20181231 10K

 



UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K





 



 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



For the fiscal year ended December 31, 2018

OR

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



For the transition period from              to             



Commission file number 1-8590

Picture 1

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)





 

 

Delaware

 

71-0361522

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification Number)



 

 

300 Peach Street, P.O. Box 7000,

 

 

El Dorado, Arkansas

 

71731-7000

(Address of principal executive offices)

 

(Zip Code)



Registrant’s telephone number, including area code:    (870) 862-6411



Securities registered pursuant to Section 12(b) of the Act:





 

 

Title of each class

 

Name of each exchange on which registered

Common Stock, $1.00 Par Value

 

New York Stock Exchange

Series A Participating Cumulative

Preferred Stock Purchase Rights

 

New York Stock Exchange



 

 



Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes     No   

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes     No   

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes     No   

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes     No   

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.





 

 

 

 

 

 



Large accelerated filer

 

Accelerated filer

 



Non-accelerated filer

 

Smaller reporting company

 



 

 

 

Emerging growth company

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes     No   

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (as of June 30, 2018) – $5,528,315,891.

Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31, 2019 was 173,058,829.

Documents incorporated by reference:

Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 8, 2019 have been incorporated by reference in Part III herein.







 


 

 



MURPHY OIL CORPORATION

2018 FORM 10-K

TABLE OF CONTENTS

 



 

 



 

Page Number



PART I

 

Item 1.

Business

Item 1A.

Risk Factors

13 

Item 1B.

Unresolved Staff Comments

20 

Item 2.

Properties

20 

Item 3.

Legal Proceedings

22 

Item 4.

Mine Safety Disclosures

22 



PART II

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

22 

Item 6.

Selected Financial Data

24 

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

25 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

46 

Item 8.

Financial Statements and Supplementary Data

46 

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

46 

Item 9A.

Controls and Procedures

46 

Item 9B.

Other Information

46 



PART III

 

Item 10.

Directors, Executive Officers and Corporate Governance

47 

Item 11.

Executive Compensation

47 

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

47 

Item 13.

Certain Relationships and Related Transactions, and Director Independence

47 

Item 14.

Principal Accounting Fees and Services

47 



PART IV

 

Item 15.

Exhibits, Financial Statement Schedules

48 



 

 

Signatures

51 





 

i

 


 

 

PART I



Item 1. BUSINESS



Summary



Murphy Oil Corporation is a global oil and gas exploration and production company.  As used in this report, the terms Murphy, Murphy Oil, we, our, its and Company may refer to Murphy Oil Corporation or any one or more of its consolidated subsidiaries.

The Company was originally incorporated in Louisiana in 1950 as Murphy Corporation.  It was reincorporated in Delaware in 1964, at which time it adopted the name Murphy Oil Corporation, and was reorganized in 1983 to operate primarily as a holding company of its various businesses.  For reporting purposes, Murphy’s exploration and production activities are subdivided into four geographic segments, including the United States, Canada, Malaysia and all other countries.  Additionally, Corporate activities include interest income, interest expense, foreign exchange effects, the impact of the Tax Cuts and Jobs Act (2017 Tax Act), corporate risk management activities and administrative costs not allocated to the segments.  The Company’s corporate headquarters are located in El Dorado, Arkansas. The Company has transitioned from an integrated oil company to an enterprise focused on oil and gas exploration and production activities. 

At December 31, 2018, Murphy had 1,108 employees

In addition to the following information about each business activity, data about Murphy’s operations, properties and business segments, including revenues by class of products and financial information by geographic area, are provided on pages 24 through 38, 71 through 73,  101 through 115 and 117 of  this Form 10-K report.

Interested parties may obtain the Company’s public disclosures filed with the Securities and Exchange Commission (SEC), including Form 10-K, Form 10-Q, Form 8-K and other documents, by accessing the Investor Relations section of Murphy Oil Corporation’s Website at www.murphyoilcorp.com.



Exploration and Production

The Company explores for and produces crude oil, natural gas and natural gas liquids worldwide.  The Company’s exploration and production management team directs the Company’s worldwide exploration and production activities.  This business maintains upstream operating offices, with the most significant of these including Houston in Texas, Calgary in Alberta, and Kuala Lumpur in Malaysia.

During 2018, Murphy’s principal exploration and production activities were conducted in the United States by wholly owned Murphy Exploration & Production Company – USA (Murphy Expro USA), in Malaysia, Australia, Brazil, Brunei, Mexico and Vietnam by wholly owned Murphy Exploration & Production Company – International (Murphy Expro International) and its subsidiaries, and in Western Canada and offshore Eastern Canada by wholly-owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries.  Murphy’s hydrocarbon production in 2018 was in the United States, Canada, Malaysia and Brunei.

Unless otherwise indicated, all references to the Company’s offshore U.S. and total oil, natural gas liquids and natural gas production and sales volumes, and proved reserves references include a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM; see further details below and in the Management’s Discussion and Analysis section).

Murphy’s worldwide 2018 production on a barrel of oil equivalent basis (six thousand cubic feet of natural gas equals one barrel of oil) was 172,172 barrels of oil equivalent per day, an increase of 5.3% compared to 2017.

See Management’s Discussion and Analysis section for further details on 2018 production and sales volume.

1

 


 

 

United States 

In the United States, Murphy primarily has production of crude oil, natural gas liquids and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico.  The Company produced approximately 58,200 barrels of crude oil and gas liquids per day and approximately 46 MMCF of natural gas per day in the U.S. in 2018.  These amounts represented 57.2% of the Company’s total worldwide oil and gas liquids and 10.9% of worldwide natural gas production volumes.

Offshore

On November 30, 2018, Murphy Expro USA and Petrobras America Inc. (PAI), a subsidiary of Petróleo Brasileiro S.A., closed a transaction among Murphy, PAI and MP Gulf of Mexico, LLC (MP GOM), a subsidiary of Murphy. The transaction had an effective date of October 1, 2018. Under the terms of the transaction, Murphy paid cash consideration of $794.6 million and transferred a 20% interest in MP GOM  to PAI.  Murphy could also owe additional contingent consideration up to $150 million if certain sales thresholds are exceeded beginning in 2019 through 2025.  PAI and Murphy contributed all of their Gulf of Mexico producing assets and Murphy contributed its interest in the Medusa Spar LLC to MP GOM. Following closing of the transaction, MP GOM is owned 80% by Murphy and 20% by PAI.  Throughout this 10K report, unless stated otherwise, financial and operational metrics relating to MP GOM include PAI’s 20% noncontrolling interest in MP GOM. 100% of revenues, costs, assets, liabilities and cash flows of MP GOM are fully consolidated in the financial statements.

During 2018, approximately 34% of total U.S. hydrocarbon production was produced at fields in the Gulf of Mexico.  Approximately 91% of Gulf of Mexico production in 2018 was derived from seven fields, including Dalmatian, Medusa, Kodiak, Front Runner, Thunder Hawk, St. Malo and Chinook.  Through MP GOM, including the noncontrolling interest, the Company now holds a 70% operated interest in Dalmatian in DeSoto Canyon Blocks 4 and 134, a 60% operated interest in Medusa in Mississippi Canyon Blocks 538/582, a 29.1% non-operated interest in Kodiak in Mississippi Canyon Blocks 727/771, a 62.5% operated interest in the Front Runner field in Green Canyon Blocks 338/339, a 62.5% operated interest in the Thunder Hawk field in Mississippi Canyon Block 734, a 100% interest in Cascade and Cottonwood, a 66.6% operated interest in Chinook Walker Ridge 425/469, a 25% non-operated interest in St Malo Walker Ridge 633/634/677/678, and a 11.5% non-operated interest in Lucius.  

Total daily production in the Gulf of Mexico in 2018 was 19,800 barrels of liquids and approximately 14 MMCF of natural gas.  At December 31, 2018, Murphy had total proved reserves for Gulf of Mexico fields of 132.9 million barrels of oil and gas liquids and 53.9 billion cubic feet of natural gas.   

Onshore

The Company holds rights to approximately 135 thousand gross acres in South Texas in the Eagle Ford Shale unconventional oil and gas play.  Total 2018 production in the Eagle Ford area was 38,200 barrels of oil and liquids per day and approximately 32 MMCF per day of natural gas.  On a barrel of oil equivalent basis, Eagle Ford production accounted for 66% of total U.S. production volumes in 2018.  At December 31, 2018, the Company’s proved reserves for the U.S. Onshore business totaled 241.2 million barrels of liquids and 255.2 billion cubic feet of natural gas. 



Canada 

In Canada, the Company holds one wholly-owned natural gas area (Tupper) in the Western Canadian Sedimentary Basin (WCSB), working interests in the Kaybob Duvernay (operated) and liquids rich Placid Montney (non-operated) lands also in the WCSB and two non-operated assets – the Hibernia and Terra Nova fields offshore Newfoundland in the Jeanne d’Arc Basin.

Onshore

The Company has approximately 94 thousand gross acres of Tupper Montney mineral rights located in northeast British Columbia.  In 2016, the Company completed its transaction to divest natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area.  Total cash consideration received by Murphy upon closing of the transaction was $414.1 million.  Connected with this sale, the Company entered into a commitment for natural gas processing capacity for minimum monthly payments through 2035.  In 2018, the Company entered into a further commitment, commencing November 2020 for an additional 200 MMCFD.

2

 


 

 

In 2016, the Company acquired a 70% operated working interest in Kaybob Duvernay lands and a 30% non-operated working interest in liquids rich Placid Montney lands, both in Alberta.  The Company has approximately 349 thousand gross acres of Kaybob and Placid mineral rights.

Also in 2016, the Company entered into an agreement to sell its wholly-owned Seal field located in the Peace River oil sands area of northwest Alberta.  This sale was completed in January 2017 and the Company received net proceeds of $48.8 million.  Finally, in 2016, MOCL completed the sale of its 5% undivided interest in Syncrude Canada Ltd. (Syncrude) for net proceeds of $739.1 million.

Daily production in 2018 in the WCSB averaged 6,800 barrels of liquids and approximately 266 MMCF of natural gas, an increase of 84.7% and 17.7% versus 2017, respectively.  Total WCSB proved liquids and natural gas reserves at December 31, 2018, were approximately 43.3 million barrels and 1.4 trillion cubic feet, respectively. 

Offshore

Murphy has a 6.5% working interest in Hibernia Main and a 4.3% working interest in Hibernia South Extension, while at Terra Nova the Company’s working interest is 10.475%.  Oil production in 2018 was approximately 6,700 barrels of oil per day for the two offshore Canada fields.  Total proved oil reserves at December 31, 2018 for the two fields were approximately 17.6 million barrels of liquids and 12.3 billion cubic feet of natural gas.



Malaysia

In Malaysia, the Company has majority interests in seven separate production sharing contracts (PSCs).  The Company serves as the operator of all these areas other than the unitized Kakap-Gumusut field.  The PSCs cover approximately 2.6 million gross acres.

Sarawak

Murphy has a 59.5% interest in oil and natural gas discoveries in two shallow-water blocks, SK 309 and SK 311, offshore Sarawak.  Approximately 12,700 barrels of liquids per day were produced in 2018 at Blocks SK 309/311.  

The Company has a gas sales contract for the Sarawak area with Petronas, the Malaysian state-owned oil company, and has an ongoing multi-phase development plan for several natural gas discoveries on these blocks.  The gas sales contract allows for gross sales volumes of 250 MMCF per day through September 2021 (with extension options), but allows the Company to deliver higher sales volumes as requested.  The Company’s net share of volumes is sold via this contract.  

Total net natural gas sales volume offshore Sarawak was approximately 104 MMCF per day during 2018.  

Total proved reserves at December 31, 2018 for Blocks SK 309/311 were 10.7 million barrels of liquids and approximately 117.7 billion cubic feet (BCF), respectively.

Other Sarawak

In November 2017, the Company acquired a 59.5% working interest in Sarawak SK405B PSC. The block SK405B is approximately 2,305 square kilometers (890 square miles) and has water depths in the range from 10 to 50 meters (33 to 164 feet).  Under the terms of the PSC, the Company will operate the block with a participating interest of 59.5%.

In February 2016, the Company acquired a 40% working interest in Block Deepwater SK2A PSC, offshore Sarawak. The Company operates the block with a commitment to acquire and process new 3D seismic. The commitment was fulfilled during 2016. This interest expired in June 2018.

In February 2015, the Company acquired a 50% interest in Block SK 2C, offshore Sarawak.  The Company operates the block that carried one well commitment during the one-year initial exploration period.  The exploration well was drilled in 2015, and the first exploration period was extended for a further eighteen months.  In 2016, the Company elected not to enter the next exploration period. The Company currently has a gas holding area for a gas field that will expire in August 2021.

3

 


 

 

In May 2013, the Company acquired an interest in shallow-water Malaysia Block SK 314A. The PSC covered a three-year exploration period.  The Company’s working interest in Block SK 314A is 59.5%. This block includes 488 thousand gross acres.  The Company has a 70% carry of a 15% partner in this concession through the minimum work program.  The first two exploration wells were drilled in 2015 and the third well in 2016.  The Company has successfully secured an annexation of an open area in Sarawak to SK 314A to complete the remaining fourth and fifth exploration commitment wells which is currently scheduled for 2019.

Block K

The Company’s working interest in the Kakap field in Block K is 6.35%, following a series of unitization and redeterminations.

In 2006, the Kakap field in Block K was unitized with the Gumusut field in an adjacent block under a Unitization and Unit Operating Agreement (UUOA) between the parties. The Gumusut-Kakap Unit is operated by another company. In the fourth quarter 2016, the owners completed the first redetermination process for a revision to the blocks’ tract participation interest, and the operator of the unitized field sought the approval of Petronas to effect the change in 2017.  In relation to this matter, in 2016, the Company recorded an estimated redetermination expense of $39.1 million ($24.1 million after taxes) related to an expected revision in the Company’s working interest covering the period from inception through year-end 2016 at Kakap, of which $17.3 million remains as a liability at the end of 2018.  In February 2017, the Company received Petronas official approval to the redetermination change that reduced the Company’s working interest in oil operations to 6.67% effective at April 1, 2017. Working interest redeterminations are required at different points within the life of the unitized field.

In 2017, following a further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia the Company has a 6.35% interest in the Kakap field in Block K Malaysia. The UFA unitized the Gumusut/Kakap (GK) and Geronggong/Jagus East fields effective November 23, 2017. The Company has recorded an estimated redetermination expense of $26.3 million ($16.3 million after taxes) related to the Company’s revised working interest, all of which remains as a liability at the end of 2018. 

The Siakap oil field was developed as a unitized area with the Petai field operated by others, and the combined development is operated by Murphy, with a tie-back to the Kikeh field with production beginning in 2014.  Oil production at Block K averaged approximately 16,700 barrels per day during 2018.  

The Company has a Block K natural gas sales contract with Petronas that calls for gross sales volumes of up to 120 MMCF per day.  Gas production in Block K will continue until the earlier of lack of available commercial quantities of associated gas reserves or expiry of the Block K production sharing contract.  Natural gas production in Block K in 2018 totaled 6 MMCF per day.  

Total proved reserves booked in Block K at the end of 2018 were 40.0 million barrels of liquids and about 26.1 billion cubic feet of natural gas.

Block H

The Company also has an interest in deepwater Block H offshore Sabah.  In early 2007, the Company announced a significant natural gas discovery at the Rotan well in Block H.  The Company followed up Rotan with several other nearby discoveries.  Murphy’s interests in Block H range between 42% and 56%.  Total gross acreage held by the Company at the end of 2018 in Block H was 679 thousand gross acres.  In early 2014, Petronas and the Company sanctioned a Floating Liquefied Natural Gas (FLNG) project for Block H, and agreed terms for sales of natural gas to be produced with prices tied to an oil index.  First production is currently expected at Block H in mid-2020.  At December 31, 2018, total natural gas proved reserves for Block H were approximately 324.4 billion cubic feet.

Block P

The Company had a 42% interest in a gas holding area covering approximately 1,854 gross acres in Block P.  This interest expired in January 2018. 





Brunei

The Company has a working interest of 8.05% in Block CA-1 and a 30% working interest in Block CA-2.  

On November 23, 2017, both the governments of Brunei and Malaysia signed a UFA (see Malaysia section above) which resulted in Jagus East discovery in Block CA-1 forming part of a unitized field with the GK Unit in Malaysia.

4

 


 

 

Following this unitization, the Company’s working interest in the Brunei section of the Kakap field was adjusted and on July 4, 2018 a participation agreement was signed which finalized the Company’s working interest of 8.05%.

The CA-1 and CA-2 blocks cover 1.44 million and 1.49 million gross acres, respectively.  Four exploration wells were drilled in Block CA-1 and six exploration wells were drilled in Block CA-2 by the end of 2018.  

The Company has a 30% non-operating working interest in Block CA-2.  In December 2014, the authority PetroleumBrunei approved a gas marketing plan which sets an eight-year gas holding period until December 2022. The consortium is presently carrying out a concept select study to assist in commercial discussions.



Australia

In Australia, the Company holds six offshore exploration permits and serves as operator of four of them.

In December 2017, Murphy signed a farm-in agreement to acquire a 40% non-operated interest in AC/P21 in the Vulcan Basin, offshore Northern Australia. Acquisition of multiclient 3D seismic commenced over the permitted area in December 2017 and was completed in December 2018. The permit covers approximately 165 thousand acres and expires in June 2019 with an option to extend.

In March 2015, Murphy was awarded the AC/P59 license, another acreage position in the Vulcan Basin with 60% interest and operatorship.  The block covers approximately 288 thousand gross acres.  The acquisition of multiclient 3D seismic commenced in 2016 and was completed in 2017.  The permit expires in 2022 with an option to renew.

In April 2014 and June 2014, Murphy was awarded licenses AC/P57 and AC/P58 in the Vulcan Basin.  The blocks cover approximately 82 thousand and 692 thousand gross acres, respectively.  These exploration permits require 3D seismic reprocessing and a gravity survey that were completed in 2017.  The permits expire in 2020 with an option to renew.

In October 2013, Murphy was awarded the EPP43 license in the Ceduna Basin, offshore South Australia, with 50% interest & operatorship. The block covers approximately 4.1 million acres. Acquisition of multiclient 3D seismic commenced over the permit in 2016 and the fully processed seismic was received in 2017. The first exploration period of the permit expires in 2021 with an option to renew.

In November 2007, Murphy signed a farm in agreement to acquire 40% of AC/P36, in the Browse Basin, offshore northern Australia in the Territory of Ashmore and Cartier Islands.  The block covers approximately 482 thousand gross acres. Murphy currently holds a non-operated 50% interest and is carried for the existing exploration commitments. The permit is in its first renewal period which currently expires in 2020 with a further option to renew.



Vietnam

The Company holds a 65% working interest in Blocks 144 and 145, a 60% interest in Block 11-2/11 and a 40% interest in Block 15-1/05.

In November 2012, the Company signed a PSC with Vietnam National Oil and Gas Group and PetroVietnam Exploration Production Company (PVEP), where it acquired a 65% interest and operatorship of Blocks 144 and 145.  The blocks cover approximately 6.56 million gross acres and are located in the outer Phu Khanh Basin.  The Company acquired 2D seismic for these blocks in 2013 and undertook seabed surveys in 2015 and 2016. The remaining commitment of the acquisition, processing and interpretation of six hundred square kilometers (600 km2) of 3D seismic is tentatively scheduled for 2020.

In June 2013, the Company acquired a 60% working interest and operatorship of Block 11-2/11 under another PSC.  The block covers 677 thousand gross acres.  The Company acquired 3D seismic and performed other geological and geophysical studies in this block in 2013.  This concession carries a three-well commitment which has been fulfilled with the first exploration well drilled in 2016 and the second and third wells drilled in 2017. 

In August 2015, the Company signed a farm-in agreement to acquire 35% of Block 15-1/05 and in 2018 became the operator and increased its working interest to 40%.  The exploration phase expired in December 2018 and is extended until December 2019.  The exploration license calls for one exploration well commitment, which is planned to be drilled in 2019.  The Lac Da Trang (LDT) 1X exploration well, the last remaining commitment of the PSC, is scheduled to commence in 2019. Effective January 11, 2019, the Declaration of Commercial Discovery of the Lac Da Vang (LDV) project was approved. First oil from LDV is currently planned by the end of 2021.

5

 


 

 

Mexico 

In December 2016, Murphy and joint venture partners were the high bidder on Block 5, which was offered as part of Mexico’s fourth phase, Round one deepwater auction.  Murphy was formally awarded the block in March 2017.   Murphy is the operator of the Block with a 30% working interest.  Block 5 is located in the deepwater Salinas basin covering approximately 640,000 gross acres (2,600 square kilometers) and water depths in this block range from 2,300 to 3,500 feet (700 to 1,100 meters).  The initial exploration period for the license is four years and includes a commitment to drill one exploration well which is planned for early 2019.



Brazil

The Company now holds an interest in 6 blocks in Brazil (SEAL-M-351, SEAL-M-428, SEAL-M-430, SEAL-M-501, SEAL-M-503 and SEAL-M-573). ExxonMobil has a 50% working interest and is the operator of the blocks, Murphy has a 20% working interest and QGEP holds a 30% working interest.  

In 2017, the Company entered into a farm-in agreement with Queiroz Galvão Exploração e Produção S.A. (QGEP) to acquire a 20% working interest in Blocks SEAL-M-351 and SEAL-M-428, located in the deepwater Sergipe-Alagoas Basin, offshore Brazil. QGEP retained a 30% working interest in the blocks and, in a separate but related transaction, ExxonMobil Exploração Brasil Ltda. (an affiliate of ExxonMobil Corporation) farmed into the remaining 50% working interest as the operator.  Subsequent to the farm-in, Murphy and its co-venturers were the high bidder in Brazil’s Round 14 lease sale, for leases which are adjacent to SEAL-M-351 and SEAL-M-428.

In 2018, the co-venturer’s were the successful bidders on blocks 430 and 573.

Murphy’s total acreage position in Brazil is 746,000 gross acres over the six blocks, offsetting several major Petrobras discoveries, with no well commitments.



Ecuador

Murphy sold its 20% working interest in Block 16, Ecuador in March 2009.  In October 2007, the government of Ecuador passed a law that increased its share of revenue for sales prices that exceed a base price (about $23.36 per barrel at December 31, 2008) from 50% to 99%.  The government had previously enacted a 50% revenue sharing rate in April 2006.  The Company initiated arbitration proceedings against the government in one arbitral body claiming that the government did not have the right under the contract to enact the revenue sharing provision.  In 2010, the arbitration panel determined that it lacked jurisdiction over the claim due to technicalities.  The arbitration was refiled in 2011 before a different arbitral body and the arbitration hearing was held in late 2014.  On February 10, 2017, the arbitration panel issued its final decision and awarded Murphy the sum of $31.3 million.  In May 2017, Ecuador instituted a proceeding in the Netherlands district court located in The Hague to set aside the award. Murphy filed an opposition and settled for $26.0 million, which was received in 2018.















6

 


 

 

Proved Reserves



Total proved reserves for crude oil, natural gas liquids and natural gas as of December 31, 2018 are presented in the following table.





 

 

 

 

 

 



 

 

 

 

 

 



 

Proved Reserves



 

Crude

 

Natural Gas

 

 



 

Oil

 

Liquids

 

Natural Gas



 

 

 

 

 

 

Proved Developed Reserves:

 

(MMBBL)

 

(BCF)

     United States

 

189.0 

 

24.9 

 

198.3 

     Canada

 

23.3 

 

1.7 

 

595.0 

     Malaysia

 

37.0 

 

0.7 

 

128.3 

              Total proved developed reserves 1

 

249.3 

 

27.3 

 

921.6 

Proved Undeveloped Reserves:

 

 

 

 

 

 

     United States

 

137.5 

 

22.7 

 

110.7 

     Canada

 

31.7 

 

4.2 

 

771.4 

     Malaysia

 

14.0 

 

 –

 

339.9 

              Total proved undeveloped reserves  2

 

183.2 

 

26.9 

 

1,222.0 

              Total proved reserves 3

 

432.5 

 

54.2 

 

2,143.6 



1 Includes proved developed reserves of 19.1 MMBBL oil, 0.8 MMBBL NGLs, and 8.2 BCF natural gas for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved undeveloped reserves of 6.4 MMBBL oil, 0.3 MMBBL NGLs, and 2.6 BCF natural gas for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes total proved reserves of 25.5 MMBBL oil, 1.1 MMBBL NGLs, and 10.8 BCF natural gas for Total and United States attributable to the noncontrolling interest in MP GOM.



Murphy Oil’s total proved reserves and proved undeveloped reserves increased during 2018 as presented in the table below:







 

 

 

 



 

 

 

 



 

Total

 

Total Proved



 

Proved 

 

Undeveloped

(Millions of oil equivalent barrels)  1

 

Reserves

 

Reserves

     Beginning of year

 

698.3 

 

351.7 

     Revisions of previous estimates

 

(21.7)

 

(43.7)

     Extensions and discoveries

 

122.5 

 

115.2 

     Improved recovery

 

0.9 

 

0.9 

     Conversions to proved developed reserves

 

 –

 

(40.9)

     Purchases of properties

 

106.8 

 

30.5 

     Production

 

(62.8)

 

 –

     End of year 2

 

844.0 

 

413.7 

1 For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of oil using a ratio of six MCF of natural gas to one barrel of oil.

2 Includes 28.4 MMBOE and 7.1 MMBOE for total proved and proved undeveloped reserves, respectively, attributable to the noncontrolling interest in MP GOM.



During 2018, Murphy’s total proved reserves increased by 145.7 million barrels of oil equivalent (mmboe).  The increase in reserves principally relates to continued development in the Eagle Ford Shale area of South Texas and the Tupper Montney gas area of Western Canada that added 42.6 MMBOE and 39.0 MMBOE, respectively, as well as improved performance in Malaysia which added 12.0 MMBOE.  In addition, Murphy added 97.0 MMBOE of total proved reserves as a result of the MP GOM transaction.

7

 


 

 

Proved Reserves (Contd.)

Murphy’s total proved undeveloped reserves at December 31, 2018 increased 62.0 MMBOE from a year earlier.  The proved undeveloped reserves reported in the table as extensions and discoveries during 2018 were predominantly attributable to three areas:  the Eagle Ford Shale area of South Texas and the Western Canada areas of Tupper Montney and Kaybob Duvernay.  Each of these areas had active development work ongoing during the year.  The majority of proved undeveloped reserves associated with revisions of previous estimates was the result of removing locations in lower performing areas of Western Canada and the Eagle Ford Shale.  The majority of the proved undeveloped reserves migration to the proved developed category are attributable to drilling in the Eagle Ford Shale, Kaybob Duvernay, and Tupper Montney. 

The Company spent approximately $824 million in 2018 to convert proved undeveloped reserves to proved developed reserves.  The Company expects to spend approximately $1,300 million in 2019, $1,200 million in 2020 and $900 million in 2021 to move currently undeveloped proved reserves to the developed category.  The anticipated level of spending in 2019 primarily includes drilling and development in the Eagle Ford Shale, Kaybob Duvernay, Tupper Montney, and Gulf of Mexico areas. 

At December 31, 2018, proved reserves are included for several development projects, including oil developments at the Eagle Ford Shale in South Texas; Kaybob Duvernay in Western Canada; deepwater Gulf of Mexico; and the Kakap and Kikeh fields, offshore Sabah in Malaysia; and natural gas developments in Tupper Montney and offshore Sabah in Block H and Kikeh in Malaysia.  Total proved undeveloped reserves associated with various development projects at December 31, 2018 were approximately 413.7 MMBOE, which represent 49% of the Company’s total proved reserves.

Certain development projects have proved undeveloped reserves that will take more than five years to bring to production.  The Company operates deepwater fields in the Gulf of Mexico that have two undeveloped locations that exceed this five-year window.  Total reserves associated with the two locations amount to less than 1% of the Company’s total proved reserves at year-end 2018.  The development of certain of these reserves stretches beyond five years due to limited well slots available, thus making it necessary to wait for depletion of other wells prior to initiating further development of these locations.

The second project that will take more than five years from initial booking to be completely developed is deepwater Block H, offshore Malaysia.   Project timing is pending timing of completion of the Floating Liquefied Natural Gas Facility (FLNG) which is ongoing and expected to be on production in 2020.  The FLNG will be operated by Malaysia’s national oil company, PETRONAS.  The Block H development project represents approximately 6% of the Company’s total proved reserves at year-end 2018.



Murphy Oil’s Reserves Processes and Policies

As per the SEC, proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The SEC has defined reasonable certainty for proved reserves, as a “high degree of confidence that the quantities will be recovered.” Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.

Murphy has established both internal and external controls for estimating proved reserves that follows the guidelines set forth by the SEC for oil and gas reporting.  Certain qualified technical personnel of Murphy from the various exploration and production offices are responsible for the preparation of proved reserve estimates and these technical representatives provide the necessary information and maintain the data as well as the documentation for all properties.

8

 


 

 

Murphy Oil’s Reserves Processes and Policies (Contd.)

The Murphy proved reserves is then consolidated and reported through the Corporate Reserves group.  Murphy’s General Manager of Corporate Reserves (Reserves Manager) leads the Corporate Reserves group that also includes Corporate reserve engineers and support staff in which all are independent of the Company’s oil and gas operational management and technical personnel.  The Reserves Manager was new to Murphy in 2018 and has over 18 years of industry experience.  He has a Bachelor of Science and a Master of Science degree in Petroleum Engineering as well as a Master of Business Administration.  The Reserves Manager is also a licensed Professional Engineer in the State of Texas. The Reserves Manager reports to the Chief Financial Officer and makes annual presentations to the Board of Directors about the Company’s reserves.  The Reserves Manager and the Corporate reserve engineers review and discuss reserves estimates directly with the Company’s technical staff in order to make every effort to ensure compliance with the rules and regulations of the SEC.  The Reserves Manager coordinates and oversees the third-party audits which are performed annually and under Company policy generally target coverage of at least one-third of the barrel oil-equivalent volume of the Company’s proved reserves.  Internal audits may also be performed by the Reserves Manager and qualified engineering staff from areas of the Company other than the area being audited by third parties. 

Each significant exploration and production office also maintains one or more Qualified Reserve Estimators (QRE) on staff.  The QRE is responsible for estimating and evaluating reserves and other reserves information for his or her assigned area.  The QRE may personally make the estimates and evaluations of reserves or may supervise and approve the estimation and evaluation thereof by others.  A QRE is professionally qualified to perform these reserves estimates as a result of having sufficient educational background, professional training, and professional experience to enable him or her to exercise prudent professional judgment.  Larger offices of the Company also employ a Regional Reserves Coordinator (RRC) who supervises the local QREs.  The RRC is usually a senior QRE who has the primary responsibility for coordinating and submitting reserves information to senior management.

QRE qualification requires a minimum of five years of practical experience in petroleum engineering or petroleum production geology, with at least three years of such experience being in the estimation and evaluation of reserves, and either a bachelors or advanced degree in petroleum engineering, geology or other discipline of engineering or physical science from a college or university of recognized stature, or the equivalent thereof from an appropriate government authority or professional organization.  Murphy provides annual training to all company reserves estimators to ensure SEC requirements associated with reserves estimation and Form 10-K reporting are fulfilled.  The training includes materials provided to each participant that outlines the latest guidance from the SEC as well as best practices for many engineering and geologic matters related to reserves estimation.

The Company’s QREs maintain files containing pertinent data regarding each significant reservoir.  Each file includes sufficient data to support the calculations or analogies used to develop the values.  Examples of data included in the file, as appropriate, include:  production histories; pertinent drilling and workover histories; bottom hole pressure data; volumetric, material balance, analogy, or other pertinent reserve estimation data; production performance curves; narrative descriptions of the methods and logic used to determine reserves values; maps and logs; and a signed copy of the documentation stating that, in their opinion, the reserves have been calculated, reviewed, documented, and reported in compliance with SEC regulations.  When reserves calculations are completed by technical personnel with the support of the QREs and appropriately reviewed by RRCs, the Corporate reserves engineers and the Reserves Manager, the conclusions are reviewed and approved with the heads of the Company’s exploration and production business units and other senior management on an annual basis.  The Company’s Controller’s department is responsible for preparing and filing reserves schedules within the Form 10-K report.



To ensure accuracy and security of reported reserves, the proved reserves estimates are coordinated in industry-standard software with access controls for approved users.  In addition, Murphy complies with audit controls concerning the various business processes related to reserves. 



The estimated proved reserves reported in this Form 10-K report are prepared by Murphy’s internal employees.  Murphy engaged both Ryder Scott Company, L.P. (Ryder Scott) and McDaniel & Associates Consultants Ltd. (McDaniel) to perform a reserves audit of 54.3% and 9.4% of the Company’s total proved reserves, respectively.  In addition, Ryder Scott provided a proved reserve report for the Petrobras GOM properties which represented 11.5% of the company total proved reserves. 

9

 


 

 

Murphy Oil’s Reserves Processes and Policies (Contd).

More information regarding Murphy’s estimated quantities of proved reserves of crude oil, natural gas liquids, and natural gas for the last three years are presented by geographic area on pages 103 through 110 of this Form 10-K report.  Also, Murphy currently has no oil and gas reserves from non-traditional sources.  Murphy has not filed and is not required to file any estimates of its total proved oil or gas reserves on a recurring basis with any federal or foreign governmental regulatory authority or agency other than the U.S. Securities and Exchange Commission.  Annually, Murphy reports gross reserves of properties operated in the United States to the U.S. Department of Energy; such reserves are derived from the same data from which estimated proved reserves of such properties are determined.

Crude oil, condensate and natural gas liquids production and sales, and natural gas sales by geographic area with weighted average sales prices for each of the three years ended December 31, 2018 are shown on pages 30 through 31 and 33 of this Form 10-K report.    

Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed beginning on page 34 of this Form 10-K report. 

Supplemental disclosures relating to oil and gas producing activities are reported on pages 101 through 116 of this Form 10-K report.



At December 31, 2018, Murphy held leases, concessions, contracts or permits on developed and undeveloped acreage as shown by geographic area in the following table.  Gross acres are those in which all or part of the working interest is owned by Murphy.  Net acres are the portions of the gross acres attributable to Murphy’s interest.









 

 

 

 

 

 

 

 

 

 

 



Developed

 

Undeveloped

 

Total

Area (Thousands of acres)

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

United States  – Onshore

105 

 

95 

 

66 

 

59 

 

171 

 

154 

                     – Gulf of Mexico

101 

 

43 

 

450 

 

250 

 

551 

 

293 

              Total United States

206 

 

138 

 

516 

 

309 

 

722 

 

447 



 

 

 

 

 

 

 

 

 

 

 

Canada – Onshore

105 

 

83 

 

482 

 

348 

 

587 

 

431 

            – Offshore

101 

 

 

43 

 

 

144 

 

10 

              Total Canada

206 

 

91 

 

525 

 

350 

 

731 

 

441 



 

 

 

 

 

 

 

 

 

 

 

Malaysia

257 

 

149 

 

2,417 

 

1,210 

 

2,674 

 

1,359 

Mexico

 –

 

 –

 

636 

 

191 

 

636 

 

191 

Brazil

 –

 

 –

 

1,120 

 

224 

 

1,120 

 

224 

Australia

 –

 

 –

 

5,792 

 

2,986 

 

5,792 

 

2,986 

Brunei

 –

 

 –

 

2,935 

 

562 

 

2,935 

 

562 

Vietnam

 –

 

 –

 

7,998 

 

4,937 

 

7,998 

 

4,937 

Spain

 –

 

 –

 

 

 

 

              Totals

669 

 

378 

 

21,947 

 

10,770 

 

22,616 

 

11,148 



Certain acreage held by the Company will expire in the next three years. 



Scheduled expirations in 2019 include 415 thousand net acres in Block AC/P58 in Australia; 125 thousand net acres in Western Canada;  9 thousand net acres in the United States; and 19 thousand net acres in the Gulf of Mexico.



Acreage currently scheduled to expire in 2020 include 93 thousand net acres in Western Canada; 37 thousand net acres in Block 351 in Brazil; 37 thousand net acres in Block 428 in Brazil;  18 thousand net acres in the United States; and 3 thousand acres in the Gulf of Mexico.

 

Scheduled expirations in 2021 include 39 thousand net acres in Western Canada; 1 thousand net acres in the United States; and 12 thousand acres in the Gulf of Mexico.

10

 


 

 

As used in the three tables that follow, “gross” wells are the total wells in which all or part of the working interest is owned by Murphy, and “net” wells are the total of the Company’s fractional working interests in gross wells expressed as the equivalent number of wholly-owned wells.  An “exploratory” well is drilled to find and produce crude oil or natural gas in an unproved area and includes delineation wells which target a new reservoir in a field known to be productive or to extend a known reservoir beyond the proved area.  A “development” well is drilled within the proved area of an oil or natural gas reservoir that is known to be productive.

The following table shows the number of oil and gas wells producing or capable of producing at December 31, 2018.











 

 

 

 

 

 

 

 



 

Oil Wells

 

Gas Wells



 

Gross

 

Net

 

Gross

 

Net

Country

 

 

 

 

 

 

 

 

United States

 

979 

 

811 

 

 

Canada

 

43 

 

24 

 

415 

 

339 

Malaysia

 

93 

 

48 

 

55 

 

33 

        Totals

 

1,115 

 

883 

 

478 

 

376 



Murphy’s net wells drilled in the last three years are shown in the following table.











 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



United States

 

Canada

 

Malaysia

 

Other

 

Totals



Pro-

 

 

 

Pro-

 

 

 

Pro-

 

 

 

Pro-

 

 

 

Pro-

 

 



ductive

 

Dry

 

ductive

 

Dry

 

ductive

 

Dry

 

ductive

 

Dry

 

ductive

 

Dry

2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploration

0.5 

 

0.4 

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

0.5 

 

0.4 

Development

46.6 

 

 -

 

28.1 

 

 -

 

 -

 

 -

 

 -

 

 -

 

74.7 

 

 -

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploration

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

 

 -

Development

68.7 

 

 -

 

27.2 

 

 -

 

 -

 

 -

 

 -

 

 -

 

95.9 

 

 -

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploration

 -

 

 -

 

 -

 

 -

 

 -

 

0.7 

 

 -

 

 -

 

 -

 

0.7 

Development

51.5 

 

 -

 

7.0 

 

 -

 

3.0 

 

 -

 

 -

 

 -

 

61.5 

 

 -



Murphy’s drilling wells in progress at December 31, 2018 are shown in the following table.  The year-end well count includes wells awaiting various completion operations.  The U.S. net wells included below are all located in the Eagle Ford Shale area of South Texas.









 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 



 

Exploration

 

Development

 

Total

Country

 

Gross

 

Net

 

    Gross

 

       Net

 

    Gross

 

       Net

United States

 

 -

 

 -

 

25.0 

 

20.6 

 

25.0 

 

20.6 

       Totals

 

 -

 

 -

 

25.0 

 

20.6 

 

25.0 

 

20.6 



11

 


 

 

Refining and Marketing – Discontinued Operations

The Company decommissioned the Milford Haven refinery units and completed the sale of its remaining downstream assets in the U.K. in 2015 for cash proceeds of $5.5 million.  The Company has accounted for and reported this U.K. downstream business as discontinued operations for all periods presented.



Environmental

Murphy’s businesses are subject to various international, national, state, provincial and local environmental laws and regulations that govern the manner in which the Company conducts its operations.  The Company anticipates that these requirements will continue to become more complex and stringent in the future.

Further information on environmental matters and their impact on Murphy are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 38 and 39.



Website Access to SEC Reports

Murphy Oil’s internet Website address is http://www.murphyoilcorp.com. The information contained on the Company’s Website is not part of this report on Form 10-K.

The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on Murphy’s Website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC.  You may also access these reports at the SEC’s Website at http://www.sec.gov.

12

 


 

 

Item 1A. RISK FACTORS



Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.

Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.

Among the most significant variable factors impacting the Company’s results of operations are the sales prices for crude oil and natural gas that it produces. The indices against which much of the Company’s production is priced were volatile in 2018. Crude oil prices in 2018 were higher than those in years 2015 to 2017, but were significantly lower than prices in 2013 and 2014. Sales prices for crude oil and natural gas can be significantly different in U.S. markets compared to other international markets.

West Texas Intermediate (WTI) crude oil prices averaged approximately $65 in 2018, compared to $51 in 2017, $43 per barrel in 2016 and $49 per barrel in 2015. The closing price for WTI at the end of 2018 was approximately $45 per barrel. Certain U.S. and Canadian crude oils and all crude oil produced in Malaysia, are generally priced from oil indices other than WTI, and these indices are influenced by different supply and demand forces than those that affect the U.S. WTI prices. The most common crude oil indices used to price the Company’s crude include Louisiana Light Sweet (LLS), Brent and the Malaysian Crude Oil Selling Price.

The average New York Mercantile Exchange (NYMEX) natural gas sales price was $3.12 in 2018, compared with $2.96 per million British Thermal Units (MMBTU) in 2017, $2.48 per MMBTU in 2016 and $2.61 per MMBTU in 2015. The closing price for NYMEX natural gas as of December 31, 2018, was $2.94 per MMBTU. In recent years, certain natural gas production offshore Sarawak have been sold at a premium to average NYMEX natural gas prices due to pricing structures built into the sales contracts.  Associated natural gas produced at fields in Block K offshore Sabah, representing approximately 6% of the Company’s 2017 natural gas sales volumes, is sold at heavily discounted prices compared to NYMEX gas prices as stipulated in the sales contract. The Company also has exposure to the Canadian benchmark natural gas price, AECO, which averaged $1.16 MMBTU in 2018.  The Company has entered into certain forward fixed price contracts as detailed in the Outlook section on page 45. 

The Company cannot predict how changes in the sales prices of oil and natural gas will affect the results of operations in future periods. In 2018, the Company hedged a portion of its exposure to the effects of changing prices of crude oil and natural gas by selling forwards, swaps and other forms of derivative contracts. The Company markets a portion of Canadian gas production to locations which sell at a premium to AECO and through physical forward sales. 



Low oil and natural gas prices may adversely affect the Company’s operations in several ways in the future.

Lower oil and natural gas prices adversely affect the Company in several ways:



·

Lower sales value for the Company’s oil and natural gas production reduces cash flows and net income.



·

Lower cash flows may cause the Company to reduce its capital expenditure program, thereby potentially restricting its ability to grow production and add proved reserves. The Company may restrict its capital expenditures to balance its cash positions going forward.



·

Lower oil and natural gas prices could lead to impairment charges in future periods.



·

Reductions in oil and natural gas prices could lead to reductions in the Company’s proved reserves in future years. Low prices could make a portion of the Company’s proved reserves uneconomic, which in turn could lead to the removal of certain of the Company’s 2018 year-end reported proved oil reserves in future periods. These reserve reductions could be significant.



13

 


 

 

·

In order to manage the potential volatility of cash flows and credit requirements, we maintain appropriate bank credit facilities.  An inability to access, renew or replace such credit facilities or access other sources of funding as they mature would negatively impact our liquidity.



·

Lower prices for oil and natural gas could lead to weaker market prices for the Company’s common stock and could cause the Company to lower its dividend.

 

Certain of these effects are further discussed in risk factors that follow.



Murphy’s commodity price risk management may limit the Company’s ability to fully benefit from potential future price increases for oil and natural gas.

The Company, from time to time, enters into various contracts to protect its cash flows against lower oil and natural gas prices. Because of these contracts, if the prices for oil and natural gas increase in future periods, the Company will not fully benefit from the price improvement on all of its production.



Murphy’s Information Technology environment may be exposed to cyber threats

In recent years the Oil and Gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, and production activities. We depend on these technologies to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, communicate with our employees and third party partners, and conduct many of our activities. 

Maintaining the security of the technology and preventing unauthorized access is critical given increasing global threats from cybercrime.  The Company’s approach focuses on cyber risk assessment, asset protection, eradicating security vulnerabilities, security education and security awareness. In the Oil and Gas industry, there are cyber intrusion attempts every day. As the sophistication of cyber attacks continues to evolve, we may be required to dedicate additional resources to continue to modify or enhance our protective measures, or to investigate and remediate any vulnerabilities to cyber attacks.



Murphy Oil’s businesses operate in highly competitive environments, which could adversely affect it in many ways, including its profitability, its ability to grow, and its ability to manage its businesses.

Murphy operates in the oil and gas industry and experiences competition from other oil and gas companies, which include state-owned foreign oil companies, major integrated oil companies, private equity investors and independent producers of oil and natural gas. Many of the state-owned and major integrated oil companies and some of the independent producers that compete with the Company have substantially greater resources than Murphy. In addition, the oil industry as a whole competes with other industries in supplying energy requirements around the world. Murphy competes, among other things, for valuable acreage positions, exploration licenses, drilling equipment and human resources.



If Murphy cannot replace its oil and natural gas reserves, it may not be able to sustain or grow its business.

Murphy continually depletes its oil and natural gas reserves as production occurs. To sustain and grow its business, the Company must successfully replace the oil and natural gas it produces with additional reserves. Therefore, it must create and maintain a portfolio of good prospects for future reserves additions and production by obtaining rights to explore for, develop and produce hydrocarbons in prospective areas. In addition, it must find, develop and produce and/or purchase reserves at a competitive cost to be successful in the long-term. Murphy’s ability to operate profitably in the exploration and production business, therefore, is dependent on its ability to find, develop and produce and/or purchase oil and natural gas reserves at costs that are less than the realized sales price for these products. In response to lower oil prices since 2014, the Company reduced its exploration program and this may reduce the rate at which it is able to replace reserves.  In 2018, the Company entered into a transaction among Murphy, PAI and MP Gulf of Mexico, LLC (MP GOM), whereby the Company through its interest in MP GOM acquired an 80% interest in PAI Gulf of Mexico producing Assets (Cascade, Chinook, Lucius, St. Malo, Cottonwood, South Marsh Island, Northwestern, and South Hadrian fields) and its interests in exploration blocks in the U.S. Gulf of Mexico to MP GOM.

14

 


 

 

Murphy’s proved reserves are based on the professional judgment of its engineers and may be subject to revision.

Proved reserves of crude oil, natural gas liquids (NGL) and natural gas included in this report on pages 101 through 110 have been prepared according to the Securities and Exchange (SEC) guidelines by qualified Company personnel or qualified independent engineers based on an unweighted average of crude oil, NGL and natural gas prices in effect at the beginning of each month of the respective year as well as other conditions and information available at the time the estimates were prepared. Estimation of reserves is a subjective process that involves professional judgment by engineers about volumes to be recovered in future periods from underground oil and natural gas reservoirs. Estimates of economically recoverable crude oil, NGL and natural gas reserves and future net cash flows depend upon a number of variable factors and assumptions, and consequently, different engineers could arrive at different estimates of reserves and future net cash flows based on the same available data and using industry accepted engineering practices and scientific methods.

Murphy’s actual future oil and natural gas production may vary substantially from its reported quantity of proved reserves due to a number of factors, including:



·

Oil and natural gas prices which are materially different from prices used to compute proved reserves



·

Operating and/or capital costs which are materially different from those assumed to compute proved reserves



·

Future reservoir performance which is materially different from models used to compute proved reserves, and



·

Governmental regulations or actions which materially impact operations of a field.


The Company’s proved undeveloped reserves represent significant portions of total proved reserves. As of December 31, 2018, and including noncontrolling interests, approximately 42% of the Company’s crude oil and condensate proved reserves, 50% of natural gas liquids proved reserves and 57% of natural gas proved reserves are undeveloped. The ability of the Company to reclassify these undeveloped proved reserves to the proved developed classification is generally dependent on the successful completion of one or more operations, which might include further development drilling, construction of facilities or pipelines, and well workovers.



The discounted future net revenues from our proved reserves as reported on pages 114 and 115 should not be considered as the market value of the reserves attributable to our properties. As required by generally accepted accounting principles (GAAP), the estimated discounted future net revenues from our proved reserves are based on an unweighted average of the oil and natural gas prices in effect at the beginning of each month during the year. Actual future prices and costs may be materially higher or lower than those used in the reserves computations.

In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on our cost of capital and the risks associated with our business and the crude oil and natural gas business in general.



Exploration drilling results can significantly affect the Company’s operating results.

The Company drills exploratory wells which subjects its exploration and production operating results to exposure to dry holes expense, which may have adverse effects on, and create volatility for, the Company’s results of operations. In response to lower oil prices in recent years, the Company has reduced its exploration program from pre-2015 levels. In 2018, two exploration wells were drilled in the US Gulf of Mexico with a 50% commercial success rate.   The Company’s 2019 planned exploratory drilling program includes four wells, two of which are in the US Gulf of Mexico, one well in Vietnam, and one well offshore Mexico.



15

 


 

 

Potential federal or state regulations could increase the Company’s costs and/or restrict operating methods, which could adversely affect its production levels.

The Company’s operations are subject to numerous environmental and occupational health and safety laws and regulations at the international, federal, provincial, state, tribal, and local levels. These laws and associated requirements can impose operational controls and/or siting constraints on our business.  These laws and regulations can result in capital and operating expenditures.



The Company’s onshore North America oil and gas production is dependent on a technique known as hydraulic fracturing whereby water, sand and certain chemicals are injected into deep oil and gas bearing reservoirs in North America. This process occurs thousands of feet below the surface and creates fractures in the rock formation within the reservoir which enhances migration of oil and natural gas to the wellbore. The Company primarily uses this technique in the Eagle Ford Shale in South Texas and in Western Canada. In June 2011, the State of Texas adopted a law requiring public disclosure of certain information regarding the components used in the hydraulic fracturing process. The Provinces of British Columbia and Alberta have also issued regulations related to various aspects of hydraulic fracturing activities under their jurisdictions. It is possible that the states, the U.S., Canadian provinces and certain municipalities adopt further laws or regulations which could render the process unlawful, less effective or drive up its costs. If any such action is taken in the future, the Company’s production levels could be adversely affected, or its costs of drilling and completion could be increased.  Once new laws and/or regulations have been enacted and adopted, the costs of compliance are appraised.

 

In April 2016, the U.S. Department of the Interior’s (DOI) Bureau of Safety and Environmental Enforcement (BSEE) enacted broad regulatory changes related to Gulf of Mexico well design, well control, casing, cementing, real-time monitoring, and subsea containment, among other items. These changes are known broadly as the Well Control Rule, and compliance is required over the next several years. However, some provisions remain for which BSEE future enforcement action and intent are unclear, so risk of impact leading to increased future cost on the Company’s Gulf of Mexico operations remains.

In July 2016, the DOI’s Bureau of Ocean Energy Management (BOEM) issued an updated Notice to Lessees and Operators (NTL) providing details on revised procedures BOEM used to determine a lessee’s ability to carry out decommissioning obligations for activities on the Outer Continental Shelf (OCS), including the Gulf of Mexico. This revised policy became effective in September 2016 and instituted new criteria by which the BOEM will evaluate the financial strength and reliability of lessees and operators active on the OCS. If the BOEM determines under the revised policy that a company does not have the financial ability to meet its decommissioning and other obligations, that company will be required to post additional financial security as assurance. In January 2017 BOEM extended the implementation timeline for the NTL by six months for properties which have co-lessees, and in February 2017 BOEM withdrew sole liability orders issued in December 2016 to allow time for the new administration to review the financial assurance program for decommissioning. Although the Company believes the new BOEM policy will likely lead to increased costs for its Gulf of Mexico operations, it does not currently believe that the impact will be material to its operations in the Gulf of Mexico.

In the future, BOEM and/or BSEE may impose new and more stringent offshore operating regulations which may adversely affect the Company’s operations.



Hydraulic fracturing exposes the Company to operational and regulatory risks and third-party claims.

Hydraulic fracturing operations subject the Company to operational risks inherent in the drilling and production of oil and natural gas. These risks include underground migration or surface spillage due to releases of oil, natural gas, formation water or well fluids, as well as any related surface or groundwater contamination, including from petroleum constituents or hydraulic fracturing chemical additives. Ineffective containment of surface spillage and surface or groundwater contamination resulting from hydraulic fracturing operations, including from petroleum constituents or hydraulic fracturing chemical additives, could result in environmental pollution, remediation expenses and third-party claims alleging damages, which could adversely affect the Company’s financial condition and results of operations. In addition, hydraulic fracturing requires significant quantities of water; the wastewater from oil and gas operations is often disposed of through underground injection. Certain increased seismic activities have been linked to underground water injection. Any diminished access to water for use in the hydraulic fracturing process, any inability to properly dispose of wastewater, or any further restrictions placed on wastewater, could curtail the Company’s operations or otherwise result in operational delays or increased costs.



16

 


 

 

Climate change initiatives and other environmental rules or regulations could reduce demand for crude oil and natural gas, which may adversely impact the Company’s business.

The issue of climate change has caused considerable attention to be directed towards initiatives to reduce global greenhouse gas emissions. An international climate agreement (the “Paris Agreement”) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016, however, after originally entering the agreement the U.S. administration, in 2017 subsequently withdrew from this agreement. The U.S. remains the only country not part of the Paris Agreement. It is possible that the Paris Agreement, if fully implemented, and other such initiatives, including environmental rules or regulations related to greenhouse gas emissions and climate change, may reduce the demand for crude oil and natural gas globally. While the magnitude of any reduction in hydrocarbon demand is difficult to predict, such a development could adversely impact the Company and other companies engaged in the exploration and production business.  The Company continually monitors the global climate change agenda initiatives and plans accordingly based on its assessment of such initiatives on its business.



Capital financing may not always be available to fund Murphy’s activities.

Murphy usually must spend and risk a significant amount of capital to find and develop reserves before revenue is generated from production.  Although most capital needs are funded from operating cash flow, the timing of cash flows from operations and capital funding needs may not always coincide, and the levels of cash flow generated by operations may not fully cover capital funding requirements, especially in periods of low commodity prices. Therefore, the Company maintains financing arrangements with lending institutions to meet certain funding needs. The Company periodically renews these financing arrangements based on foreseeable financing needs or as they expire. In November 2018, the Company entered into a $1.6 billion revolving credit facility (the “New Revolving Credit Facility”). The New Revolving Credit Facility is a senior unsecured guaranteed facility and will expire in November 2023. This replaces the previous $1.1 billion facility.

The Company’s ability to obtain additional financing is also affected by the Company’s debt credit ratings and competition for available debt financing.  A ratings downgrade could materially and adversely impact the Company’s ability to access debt markets, increase the borrowing cost under the Company’s credit facility and the cost of future debt, and potentially require the Company to post additional letters of credit or other forms of collateral for certain obligations.



See Note H for information regarding the Company's outstanding debt and other commitments as of December 31, 2018 and the terms associated therewith.



Murphy has limited or virtually no control over several factors that could adversely affect the Company.

The ability of the Company to successfully manage development and operating costs is important because virtually all of the products it sells are energy commodities such as crude oil, NGL and natural gas, for which the Company has little or no influence on the sales prices or regional and worldwide consumer demand for these products. Changes in commodity prices also impact the volume of production attributed to the Company under production sharing contracts in Malaysia. Economic slowdowns, generally reduce worldwide demand for these energy commodities, which can lead to reduced prices for oil and natural gas. An abundant recoverable supply of crude oil in recent years also led to a decline in worldwide oil prices from pre-2015 levels. Lower prices for crude oil, NGL and natural gas inevitably lead to lower earnings for the Company. The volatile, and at times low, crude oil price environment in recent years has caused the Company to reduce spending on certain discretionary drilling programs, which in turn hurts the Company’s future production levels and future cash flow generated from operations. The Company often experiences pressure on its operating and capital expenditures in periods of strong crude oil and natural gas prices because an increase in exploration and production activities due to high oil and gas sales prices generally leads to higher demand for, and consequently higher costs for, goods and services in the oil and gas industry. The increase in oil prices in 2017 and 2018 (compared to 2015 to 2016) has led to some upward inflation pressure in oil field goods and service costs during the year.

Certain of the Company’s major oil and natural gas producing properties are operated by others. Therefore, Murphy does not fully control all activities at certain of its revenue generating properties. During 2018, approximately 16% of the Company’s total production was at fields operated by others, while at December 31, 2018, approximately 14% of the Company’s total proved reserves were at fields operated by others.

17

 


 

 

Additionally, the Company relies on the availability of transportation and processing facilities that are often owned by others. These third-party systems and facilities may not always be available to the Company, and if available, may not be available at a price that is acceptable to the Company.



Failure of our partners to fund their share of development costs or obtain financing could result in delay or cancellation of future projects, thus limiting our growth and future cash flows.

Some of Murphy’s development projects entail significant capital expenditures and have long development cycle times. As a result, the Company’s partners must be able to fund their share of investment costs through the development cycle, through cash flow from operations, external credit facilities, or other sources, including financing arrangements. Murphy’s partners are also susceptible to certain of the risk factors noted herein, including, but not limited to, commodity price declines, fiscal regime changes, government project approval delays, regulatory changes, credit downgrades and regional conflict. If one or more of these factors negatively impacts a project partners’ cash flows or ability to obtain adequate financing, it could result in a delay or cancellation of a project, resulting in a reduction of the Company’s reserves and production, which negatively impacts the timing and receipt of planned cash flows and expected profitability.



Murphy’s operations and earnings have been and will continue to be affected by worldwide political developments.

Many governments, including those that are members of the Organization of Petroleum Exporting Countries (OPEC), unilaterally intervene at times in the orderly market of crude oil and natural gas produced in their countries through such actions as changing fiscal regimes (including corporate tax rates), setting prices, determining rates of production, and controlling who may buy and sell the production.

In 2018, Murphy Oil’s net income included a favorable income tax adjustment of $135.7 million related to the 2017 Tax Act enacted on December 22, 2017. The $135.7 million adjustment, primarily related to the reinstatement of a deferred tax asset for 2017 net operating losses, which in 2017, was assumed utilized against the deemed repatriation.

For the year ended December 31, 2017, Murphy recorded a tax expense of $274.0 million directly related to the impact of the 2017 Tax Act.  The charge includes the impact of a deemed repatriation of accumulated foreign earnings and the re-measurement of deferred tax assets and liabilities.

As of December 31, 2018, approximately 15% of the Company’s proved reserves, as defined by the SEC, were located in countries other than the U.S. and Canada. In addition, prices and availability of crude oil, natural gas and refined products could be influenced by political factors and by various governmental policies to restrict or increase petroleum usage and supply. Other governmental actions that could affect Murphy’s operations and earnings include expropriation, tax changes, royalty increases, redefinition of international boundaries, preferential and discriminatory awarding of oil and gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees. Governments could also initiate regulations concerning matters such as currency fluctuations, currency conversion, protection and remediation of the environment, and concerns over the possibility of global warming caused by the production and use of hydrocarbon energy.

A number of non-governmental entities routinely attempt to influence industry members and government energy policy in an effort to limit industry activities, such as hydrocarbon production, drilling and hydraulic fracturing with the desire to minimize the emission of greenhouse gases such as carbon dioxide, which may harm air quality, and to restrict hydrocarbon spills, which may harm land and/or groundwater.

Additionally, because of the numerous countries in which the Company operates, certain other risks exist, including the application of the U.S. Foreign Corrupt Practices Act, the Canada Corruption of Foreign Officials Act, the Malaysia Anti-Corruption Commission Act, the U.K. Bribery Act, the Brazil Clean Companies Act, the Mexico General Law of the National Anti-Corruption System, and other similar anti-corruption compliance statutes.

It is not possible to predict the actions of governments and hence the impact on Murphy’s future operations and earnings.



18

 


 

 

Murphy’s business is subject to operational hazards, security risks and risks normally associated with the exploration for and production of oil and natural gas.

The Company operates in urban and remote, and sometimes inhospitable, areas around the world. The occurrence of an event, including but not limited to acts of nature such as hurricanes, floods, earthquakes (and other forms of severe weather), mechanical equipment failures, industrial accidents, fires, explosions, acts of war, civil unrest, piracy and acts of terrorism could result in the loss of hydrocarbons and associated revenues, environmental pollution or contamination, personal injury, (including death), and property damages for which the Company could be deemed to be liable and which could subject the Company to substantial fines and/or claims for punitive damages.

The location of many of Murphy’s key assets causes the Company to be vulnerable to severe weather, including hurricanes and tropical storms. A number of significant oil and natural gas fields lie in offshore waters around the world. Some of the Company’s offshore fields are in the U.S. Gulf of Mexico, where hurricanes and tropical storms can lead to shutdowns and damages. The U.S. hurricane season runs from June through November. Although the Company maintains insurance for such risks as described elsewhere in this Form 10-K report, due to policy deductibles and possible coverage limits, weather-related risks are not fully insured.  The Company has in the past experienced operational delays in Malaysia due to tropical storms in the South China Sea.



Murphy’s insurance may not be adequate to offset costs associated with certain events and there can be no assurance that insurance coverage will continue to be available in the future on terms that justify its purchase.

Murphy maintains insurance against certain, but not all, hazards that could arise from its operations. The Company maintains liability insurance sufficient to cover its share of gross insured claim costs up to approximately $500 million per occurrence and in the annual aggregate. Generally, this insurance covers various types of third-party claims related to personal injury, death and property damage, including claims arising from “sudden and accidental” pollution events. The Company also maintains insurance coverage with an additional limit of $400 million per occurrence ($875 million for Gulf of Mexico claims), all or part of which could apply to certain sudden and accidental pollution events. These policies have deductibles ranging from $10 million to $25 million. The occurrence of an event that is not insured or not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future.



Lawsuits against Murphy and its subsidiaries could adversely affect its operating results.

The Company is involved in numerous lawsuits seeking cash settlements for alleged personal injuries, property damages and other business-related matters. Certain of these lawsuits will take many years to resolve through court proceedings or negotiated settlements. None of the currently pending lawsuits are considered individually material or aggregate to a material amount in the opinion of management.



The Company is exposed to credit risks associated with sales of certain of its products to third parties and associated with its operating partners.

Although Murphy limits its credit risk by selling its products to numerous entities worldwide, it still, at times, carries substantial credit risk from its customers. For certain oil and gas properties operated by the Company, other companies which own partial interests may not be able to meet their financial obligation to pay for their share of capital and operating costs as they come due. The inability of a purchaser of the Company’s oil or natural gas or a partner of the Company to meet their respective payment obligations to the Company could have an adverse effect on Murphy’s future earnings and cash flows.



19

 


 

 

Murphy’s operations could be adversely affected by changes in conversion rates.

The Company’s worldwide operational scope exposes it to risks associated with foreign currencies. Most of the Company’s business is transacted in U.S. dollars, and therefore the Company and most of its subsidiaries are U.S. dollar functional entities for accounting purposes. However, the Canadian dollar is the functional currency for all Canadian operations.

In certain countries, such as Canada and Malaysia, significant levels of transactions occur in currencies other than the functional currency. In Malaysia, such transactions include tax and other supplier payments, while in Canada, certain crude oil sales are priced in U.S. dollars. In late 2016, Malaysian authorities altered the local currency rules such that 75% of the proceeds of export oil and gas sales must be converted to local currency when received; plus, beginning in 2017, resident suppliers of goods and services to the Company must be paid in local currency.

This exposure to currencies other than the functional currency can lead to impacts on consolidated financial results from foreign currency translation. Exposures associated with current and deferred income tax liability and asset balances in Malaysia are generally not hedged. A strengthening of the Malaysian ringgit against the U.S. dollar would be expected to lead to currency gains in consolidated operations; losses would be expected if the ringgit weakens versus the dollar. On occasions, the Canadian business may hold assets or incur liabilities denominated in a currency which is not Canadian dollars which could lead to exposure to foreign exchange rate fluctuations. See also Note L in the Notes to Consolidated Financial Statements for additional information on derivative contracts.



The costs and funding requirements related to the Company’s retirement plans are affected by several factors.

A number of actuarial assumptions impact funding requirements for the Company’s retirement plans. The most significant of these assumptions include return on assets, long-term interest rates and mortality. If the actual results for the plans vary significantly from the actuarial assumptions used, or if laws regulating such retirement plans are changed, Murphy could be required to make more significant funding payments to one or more of its retirement plans in the future and/or it could be required to record a larger liability for future obligations in its Consolidated Balance Sheet.



Item 1B. UNRESOLVED STAFF COMMENTS

The Company had no unresolved comments from the staff of the U.S. Securities and Exchange Commission as of December 31, 2018.



Item 2. PROPERTIES

Descriptions of the Company’s oil and natural gas properties are included in Item 1 of this Form 10-K report beginning on page 1.  Information required by the Securities Exchange Act Industry Guide No. 2 can be found in the Supplemental Oil and Gas Information section of this Annual Report on Form 10-K on pages 101 to 115 and in Note G – Property, Plant and Equipment beginning on page 71.

20

 


 

 

Executive Officers of the Registrant



Present corporate office, length of service in office and age at February 1, 2019 of each of the Company’s executive officers are reported in the following listing.  Executive officers are elected annually, but may be removed from office at any time by the Board of Directors.



Roger W. Jenkins – Age 57; President and Chief Executive Officer since August 2013.  Mr. Jenkins served as Chief Operating Officer from June 2012 to August 2013. 

David R. Looney – Age 62; Chief Financial Officer and Executive Vice President since March 2018. Mr. Looney joined the Company following a broad range of leadership roles at both offshore deepwater Gulf of Mexico and U.S. onshore unconventional exploration and production companies.

Eugene T. Coleman – Age 60; Executive Vice President, Exploration and Business Development since September 2018.  Mr. Coleman has also served as Executive Vice President, Offshore of the Company’s exploration and production subsidiary from 2011 to 2017. As previously announced, Mr. Coleman has elected to retire from the Company effective February 28, 2019.

Michael K. McFadyen – Age 51; Executive Vice President, Offshore since September 2018.  Mr. McFadyen has also served as Executive Vice President, Onshore of the Company’s exploration and production subsidiary from 2011 to 2017.

Eric M. Hambly – Age 44; Executive Vice President, Onshore since September 2018. Mr. Hambly served as Senior Vice President, U.S. Onshore from 2016 to September 2018. 

Walter K. Compton – Age 56; Executive Vice President and General Counsel since February 2014.  Mr. Compton was Senior Vice President and General Counsel from March 2011 to February 2014.

Kelly L. Whitley – Age 53; Vice President, Investor Relations and Communications since July 2015.    

Thomas J. Mireles – Age 46; Senior Vice President, Technical Services (Health, Safety, Environment, Information Technology and Procurement) since September 2018. Mr. Mireles also served as the Senior Vice President, Eastern Hemisphere from 2016 to September 2018.

Maria A. Martinez – Age 44; Vice President, Human Resources & Administration since September 2018. Ms. Martinez was the Vice President, Human Resources from 2013 to September 2018.

E. Ted Botner – Age 54; Vice President, Law and Secretary since March 2015.  Mr. Botner was Secretary and Manager, Law from August 2013 to March 2015.

John B. Gardner – Age 50; Vice President and Treasurer since March 2015.  Mr. Gardner served as Treasurer from August 2013 to March 2015.

Kelli M. Hammock  – Age 47; Senior Vice President, Special Projects since September 2018.  Ms. Hammock served as Senior Vice President, Administration from February 2014 to September 2018.

Christopher D. Hulse – Age 40, Vice President and Controller since June 2017. Mr. Hulse was Vice President, Finance, Onshore from September 2015 to June 2017.

Barry F.R. Jeffery – Age 60; Vice President, Health, Safety, Environment and Risk Management since June 2017.  Mr. Jeffery was Vice President, Insurance, Security and Risk from July 2015 to June 2017.

Louis W. Utsch – Age 53; Vice President, Tax since January 2018. Mr. Utsch joined the Company following over 20 years of corporate tax experience at Big Four accounting firms as well as more than a decade of work experience in the oil and natural gas industry.



21

 


 

 

Item 3. LEGAL PROCEEDINGS

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income or loss, financial condition or liquidity in a future period.



Item 4. MINE SAFETY DISCLOSURES

Not applicable.



PART II



Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company’s Common Stock is traded on the New York Stock Exchange using “MUR” as the trading symbol.  There were 2,324 stockholders of record as of December 31, 2018.  Information on dividends per share by quarter for 2018 and 2017 are reported on page 116 of this Form 10-K report.

22

 


 

 

SHAREHOLDER RETURN PERFORMANCE PRESENTATION



The following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 2013 in the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index), and the Company’s peer group.  The companies in the peer group included Anadarko Petroleum Corporation, Apache Corporation, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, Cimarex Energy Co., Devon Energy Corporation, Encana Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Pioneer Natural Resources Corporation, Range Resources Corporation, Southwestern Energy Company and Whiting Petroleum Corporation.  This performance information is “furnished” by the Company and is not considered as “filed” with this Form 10-K report and it is not incorporated into any document that incorporates this Form 10-K report by reference. 



Picture 2







 

 

 

 

 

 

 

 

 

 

 

 



 

2013 

 

2014 

 

2015 

 

2016 

 

2017 

 

2018 

Murphy Oil Corporation

$

100 

 

80 

 

37 

 

54 

 

55 

 

43 

S&P 500 Index

 

100 

 

114 

 

115 

 

129 

 

157 

 

150 

Peer Group

 

100 

 

87 

 

54 

 

77 

 

68 

 

49 











23

 


 

 

Item 6. SELECTED FINANCIAL DATA













 

 

 

 

 

 

 

 

 

 

 

(Thousands of dollars except per share data)

 

 

 

 

 

 

 

 

 

 

 

Results of Operations for the Year

 

2018

 

2017

 

2016

 

2015

 

2014

 

Revenue from sales to customers

$

2,586,627 

 

2,078,548 

 

1,862,891 

 

2,787,116 

 

5,288,933 

 

Net cash provided by continuing operations

 

1,219,396 

 

1,128,075 

 

600,795 

 

1,183,369 

 

3,048,639 

 

Income (loss) from continuing operations

 

423,008 

 

(310,936)

 

(273,943)

 

(2,255,772)

 

1,024,973 

 

Net income (loss) attributable to Murphy

 

411,094 

 

(311,789)

 

(275,970)

 

(2,270,833)

 

905,611 

 

Cash dividends – diluted

 

173,044 

 

172,565 

 

206,635 

 

244,998 

 

236,371 

 

Per Common share – diluted

 

 

 

 

 

 

 

 

 

 

 

        Income (loss) from continuing operations

$

2.37 

 

(1.81)

 

(1.59)

 

(12.94)

 

5.69 

 

        Net income (loss) attributable to Murphy

 

2.36 

 

(1.81)

 

(1.60)

 

(13.03)

 

5.03 

 

Average common shares outstanding (thousands) – diluted

 

174,209 

 

172,974 

 

172,173 

 

174,351 

 

180,071 

 

Cash dividends per Common share

 

1.00 

 

1.00 

 

1.20 

 

1.40 

 

1.33 

 

Capital Expenditures for the Year 1

 

 

 

 

 

 

 

 

 

 

 

Continuing operations

 

 

 

 

 

 

 

 

 

 

 

        Exploration and production

$

1,959,400 

 

960,870 

 

789,721 

 

2,127,197 

 

3,742,541 

2

        Corporate and other

 

27,900 

 

14,821 

 

21,740 

 

59,886 

 

14,453 

 



 

1,987,300 

 

975,691 

 

811,461 

 

2,187,083 

 

3,756,994 

 

Discontinued operations

 

– 

 

– 

 

– 

 

159 

 

12,349 

 



$

1,987,300 

 

975,691 

 

811,461 

 

2,187,242 

 

3,769,343 

 

Financial Condition at December 31

 

 

 

 

 

 

 

 

 

 

 

Current ratio

 

1.04 

 

1.64 

 

1.04 

 

0.83 

 

1.02 

 

Working capital (deficit)

$

33,756 

 

537,396 

 

56,751 

 

(277,396)

 

76,155 

 

Net property, plant and equipment

 

9,757,564 

 

8,220,031 

 

8,316,188 

 

9,818,365 

 

13,331,047 

 

Total assets

 

11,052,587 

 

9,860,942 

 

10,295,860 

 

11,493,812 

 

16,742,307 

 

Long-term debt 2

 

3,227,134 

 

2,906,520 

 

2,422,750 

 

3,040,594 

 

2,536,238 

 

Murphy shareholders' equity

 

4,829,299 

 

4,620,191 

 

4,916,679 

 

5,306,728 

 

8,573,434 

 

        Per share

 

27.91 

 

26.77 

 

28.55 

 

30.85 

 

48.30 

 

Long-term debt – percent of capital employed 3  

 

40.1 

 

38.6 

 

33.0 

 

36.4 

 

22.8 

 

Stockholder and Employee Data at December 31

 

 

 

 

 

 

 

 

 

 

 

Common shares outstanding (thousands)

 

173,059 

 

172,573 

 

172,202 

 

172,035 

 

177,500 

 

Number of stockholders of record

 

2,324 

 

2,506 

 

2,588 

 

2,713 

 

2,556 

 











1 Capital expenditures include accruals for incurred but unpaid capital activities, while property additions and dry holes in the Statements of Cash Flows are cash-based capital expenditures and do not include capital accruals and geological, geophysical and certain other exploration expenses that are not eligible for capitalization under oil and gas accounting rules. 2018 includes $794.6 million capital expenditures in relation to the MP GOM transaction.

2 Long-term debt includes noncurrent capital lease obligations.

3 Long-term debt – percent of capital employed is calculated as total long-term debt at the balance sheet date divided by the sum of total long-term debt plus total Murphy shareholders’ equity at that date.

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS



Murphy Oil Corporation is a worldwide oil and gas exploration and production company.  A more detailed description of the Company’s significant assets can be found in Item 1 of this Form 10-K report.

Significant Company operating and financial highlights during 2018 were as follows:



·

Income from continuing operations before income taxes of $432.3 million (2017:  $71.8 million)



·

Entered into an oil-weighted Gulf of Mexico transaction with Petrobras (see Business Review for further details)



·

Produced 172,175 barrels of oil equivalent (BOE) per day (170,945 excluding noncontrolling interest, NCI)



·

Achieved an overall lease operating expense per BOE of $8.86 (2017:  $7.89)



·

Excluding acquisitions, replaced 166% of total proved reserves (2017:  123%)



·

Preserved balance sheet strength with approximately 35% net debt to total capital  1 (37% excluding NCI)



Throughout this section, the term, ‘excluding noncontrolling interest’ or ‘excluding NCI’ refers to amounts attributable to Murphy.

Murphy’s continuing operations generate revenue by producing crude oil, natural gas liquids (NGL) and natural gas in the United States, Canada and Malaysia and then selling these products to customers.  The Company’s revenue is affected by the prices of crude oil, natural gas and NGL.  In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products, depreciation of capital expenditures, and expenses related to exploration, administration, and for capital borrowed from lending institutions and note holders.

Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company.  In 2018 liquids represented 59% of total hydrocarbons produced on an energy equivalent basis.  In 2019, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 67%.  When oil-price linked natural gas in Malaysia is combined with oil production, the Company’s 2019 total expected production is approximately 75% linked to the price of oil.  If the prices for crude oil and natural gas are lower in 2019 or beyond, this will have an unfavorable impact on the Company’s operating profits.  The Company, from time to time, may choose to use a variety of commodity hedge instruments to reduce commodity price risk, including forward sale fixed financial swaps and long-term fixed-price physical commodity sales.

Oil prices strengthened in 2018 compared to the 2017 period.  The sales price of a barrel of West Texas Intermediate (WTI) crude oil averaged $64.77 in 2018, $50.95 in 2017, and $43.32 in 2016.  The sales price of a barrel of Platts Dated Brent crude oil increased to $71.04 in 2018, following averages of $54.28 per barrel in 2017 and $43.69 per barrel in 2016.  The WTI index increased approximately 27% over the prior year while Dated Brent experienced a 31% increase in 2018. 

During 2018 the discount for WTI crude compared to Dated Brent increased compared to the prior year.  The average WTI to Dated Brent discount was $6.27 per barrel during 2018, $3.33 per barrel during 2017 and $0.37 per barrel in 2016.  In early 2019, Dated Brent has been trading at a similar premium to WTI as 2018 average levels.  Crude oil prices in early 2019 were below the 2018 average prices. 

The NYMEX natural gas price per million British Thermal Units (MMBTU) averaged $3.12 in 2018, $2.96 in 2017 and $2.48 in 2016. The 2018 NYMEX natural gas price was approximately in line with 2017. NYMEX natural gas prices in 2017 were 19% above the average price in 2016, with the increase largely due to demand generated by LNG export growth and overland deliveries to Mexico. On an energy equivalent basis, the market continued to discount North American natural gas and NGL compared to crude oil in 2018.  Natural gas prices in North America in 2019 have thus far been below the average 2018 levels. 



1 Total capital is calculated as equity plus long-term debt less cash.

25

 


 

 

Results of Operations

Murphy Oil’s results of operations, with associated diluted earnings per share (EPS), for the last three years are presented in the following table.









 

 

 

 

 

 

 



 

 

Years Ended December 31,

(Millions of dollars, except EPS)

 

 

2018 

 

2017 

 

2016 

Income (loss) from continuing operations before income taxes

 

$

432.3 

 

71.8 

 

(493.1)



 

 

 

 

 

 

 

Net income (loss) attributable to Murphy

 

$

411.1 

 

(311.8)

 

(276.0)

           Diluted EPS

 

 

2.36 

 

(1.81)

 

(1.60)



 

 

 

 

 

 

 

Income (loss) from continuing operations attributable to Murphy

 

$

414.6 

 

(310.9)

 

(274.0)

           Diluted EPS

 

 

2.37 

 

(1.81)

 

(1.59)



 

 

 

 

 

 

 

Loss from discontinued operations

 

$

(3.5)

 

(0.9)

 

(2.0)

           Diluted EPS

 

 

(0.01)

 

-

 

(0.01)



Results of continuing operations before taxes in 2018 were improved versus 2017. In 2018, income from continuing operations attributable to Murphy of $414.6 million ($2.37 per diluted share) increased from a loss of $310.9 million ($1.81 per diluted share) in 2017. Murphy Oil’s net income in 2018 included a favorable income tax adjustment of $135.7 million related to the 2017 Tax Act enacted on December 22, 2017. The $135.7 million adjustment, primarily related to the reinstatement of a deferred tax asset for 2017 net operating losses, which in 2017, was assumed utilized against the deemed repatriation. 

The results for 2018 were also favorably impacted by higher revenues (due to higher realized oil and natural gas sales prices and volumes), higher other operating income (vs 2017 other operating expense), lower foreign exchange losses, and lower exploration expenses; partially offset by losses on crude contracts, lower gain on sale of assets, higher lease operating expenses and higher depreciation.

In 2018 the Company’s discontinued operations incurred a loss of $3.5 million.

Murphy Oil’s net loss in 2017 vs 2016 was impacted by higher revenues due to higher realized oil and natural gas sales prices, lower unrealized losses on forward sales commodity contracts, gain on sale of the Seal property in Western Canada, lower lease operating expenses, lower depreciation expense, non-recurring impairment expense in 2016, and lower selling and general expenses, but these were more than offset by higher tax charges (caused by higher pre-tax income and the impact of the 2017 Tax Act), higher exploration expenses, higher other expenses, higher foreign exchange charges, and higher interest expenses.

On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act). For the year ended December 31, 2017, Murphy recorded a tax expense of $274.0 million directly related to the impact of the 2017 Tax Act.  The charge includes the impact of a deemed repatriation of accumulated foreign earnings and the re-measurement of deferred tax assets and liabilities.

Results in 2016 included a $71.7 million after-tax gain on sale of the Company’s five percent interest in Syncrude.  In 2016, the Company’s refining and marketing operations generated a loss of $2.5 million, which led to overall losses from discontinued operations in each year.



26

 


 

 

Segment Results – In the following table, the Company’s results of operations for the three years ended December 31, 2018, are presented by segment.  More detailed reviews of operating results for the Company’s exploration and production and other activities follow the table.



A summary of Net Income is presented in the following table.









 

 

 

 

 

 

(Millions of dollars)

 

2018 

 

2017 

 

2016 

Exploration and production – continuing operations

 

 

 

 

 

 

        United States

$

242.9 

 

(8.9)

 

(164.2)

        Canada

 

51.1 

 

112.5 

 

(35.9)

        Malaysia

 

269.5 

 

224.2 

 

171.1 

        Other

 

(16.6)

 

(37.5)

 

(54.7)

             Total exploration and production – continuing operations

 

546.9 

 

290.3 

 

(83.7)

Corporate and other

 

(123.9)

 

(601.2)

 

(190.3)

Income (loss) from continuing operations

 

423.0 

 

(310.9)

 

(274.0)

Loss from discontinued operations

 

(3.5)

 

(0.9)

 

(2.0)

             Net income (loss) including noncontrolling interest

 

419.5 

 

(311.8)

 

(276.0)

Net income attributable to noncontrolling interest

 

8.4 

 

 -

 

 -

             Net income (loss) attributable to Murphy

$

411.1 

 

(311.8)

 

(276.0)



A summary of oil and gas revenues is presented in the following table.











 

 

 

 

 

 

(Millions of dollars)

 

2018

 

2017

 

2016

United States – Oil and gas liquids

$

1,245.3 

 

903.7 

 

714.1 

                       – Natural gas

 

42.9 

 

37.9 

 

35.1 

Canada – Conventional oil and gas liquids

 

291.2 

 

203.7 

 

171.7 

             – Synthetic oil

 

 –

 

 –

 

60.7 

             – Natural gas

 

147.6 

 

155.1 

 

130.0 

Malaysia – Oil and gas liquids

 

708.8 

 

639.9 

 

623.7 

                – Natural gas

 

144.7 

 

138.2 

 

127.6 

Other

 

6.1 

 

 –

 

 –

    Total oil and gas revenues

$

2,586.6 

 

2,078.5 

 

1,862.9 



Exploration and Production 

Please refer to Schedule 5 – Results of Operations for Oil and Gas Producing Activities in the Supplemental Oil and Gas Information section for supporting tables.

2018 vs 2017

Exploration and production (E&P) continuing operations recorded a profit of $546.9 million in 2018 compared to a profit of $290.3 million in 2017 and a loss of $83.7 million in 2016. The results for 2018 were favorably impacted by higher revenues due to higher realized oil and natural gas sales prices and volumes, lower gain on sale of assets, lower other exploration expenses, and lower other operating expenses, partially offset by higher lease operating expenses, higher depreciation expense, non-recurring impairment expense in 2018 and higher taxes.

Crude oil price realizations averaged $64.30 per barrel in the current year compared to $51.34 per barrel in 2017, a price increase of 25% year over year.  U.S. natural gas realized price per thousand cubic feet (MCF) averaged $2.54 in the current year compared to $2.33 per MCF in 2017, a price increase of 9% year over year. Canada natural gas realized price per MCF averaged US$1.52 in the current year compared to US$1.88 per MCF in 2016, a price decrease of 20% year over year.  Oil and gas production costs, including associated production taxes, on a per-unit basis, were $9.69 in 2018 (2017: $8.63), which together with higher oil and natural gas volumes sold, resulted in $96.2 million higher costs in 2018.

27

 


 

 

Exploration and Production (Contd.) 

2018 vs 2017(Contd.)

United States E&P operations reported earnings of $242.9 million in 2018 compared to a net loss of $8.9 million in 2017.  Results were $251.8 million favorable in the 2018 period compared to the 2017 period due to higher revenues ($345.3 million), lower depreciation ($26.6 million), and lower G&A ($12.8 million), partially offset by higher lease operating expenses ($32.0 million), higher dry hole costs ($17.9 million, primarily related to the write-off of the King Cake well in the Gulf of Mexico), an impairment charge related to select Midland properties ($20.0 million), and higher income taxes ($68.9 million).  Higher revenues were primarily due to higher realized prices and contribution from new volumes from the MP GOM transaction, while lower depreciation expense was due primarily to lower rates and lower volumes sold at Eagle Ford Shale.  Higher lease operating expenses were principally a result of higher costs at Front Runner (due to 2017 Clipper well acquisition) and Kodiak work-over costs in the U.S. Gulf of Mexico business. Higher exploration expenditures are principally a result of data acquisition costs in the U.S Gulf of Mexico business.

Canadian E&P operations reported earnings of $51.1 million in 2018 compared to earnings of $112.5 million in the 2017 period.  Results were unfavorable $61.4 million due to 2017 including a pretax gain of $132.4 million (after tax: $96.0 million) related to the sale of Seal heavy oil assets in Canada in January 2017.  Adjusting for the impact of gain on sale of assets, Canadian results of operations improved $34.6 million in the 2018 period compared to the 2017 period due to higher revenue ($85.5 million), and insurance proceeds ($21.3 million), partially offset by higher lease operating expense ($21.7 million), higher depreciation ($47.1 million) and higher taxes ($6.5 million).  Higher revenues were a result of both higher volumes at the Tupper, Kaybob and Placid assets and higher realized crude prices.  Insurance proceeds related to cash received in relation to the spill at the now divested Seal asset. Higher taxes (excluding the Seal gain in 2017) are the result of higher net earnings.  Higher lease operating expenses and depreciation are a result of higher volumes sold. 

Malaysia E&P operations reported earnings of $269.5 million in 2018, compared to earnings of $224.2 million in 2017.  Results were favorable by $45.3 million due to higher revenues ($73.1 million), lower depreciation ($6.0 million), and lower redetermination/unitization expense ($3.7 million), partially offset by higher lease operating expenses ($33.3 million), and higher taxes ($16.9 million). Higher revenues are principally due to higher realized prices, partially offset by lower volumes sold. Lower depreciation is due to lower volumes sold. Lower other expenses are due to the cost of a rig exit recorded in 2017. Higher lease operating expenses are due to higher platform, onshore facility and sub-sea maintenance costs.  The higher taxes are due to higher pre-tax profits. The redetermination/unitization charges (in both years) relates to the executed unitization agreement for the Gumusut-Kakap (GK) and Geronggong/Jagus East fields originally signed in Q4 2017. Also, in the third quarter of 2018, the Brunei working interest income was recorded as a result of signing the Brunei participation agreement (see below).

Other international E&P operations reported a loss from continuing operations of $16.6 million in 2018 compared to a loss of $37.5 million in the 2017 period.  The loss was $20.9 million lower in the 2018 period versus 2017 primarily due to the recording of past profits ($21.6 million) relating to the working interest in Block CA1 in Brunei, and lower exploration costs ($16.2 million), partially offset by lower tax benefits on investments in foreign areas ($18.2 million). The Brunei income follows the signing of the Brunei participation agreement on July 4, 2018, which enables the Company the right to claim its proportional share of revenue since inception as well as the obligation to settle the related past operating and capital expenditure costs since inception.  In addition, ongoing current Brunei revenue is now being reported.

2017 vs 2016

Exploration and production (E&P) continuing operations recorded a profit of $290.3 million in 2017 compared to a loss of $83.7 million in 2016. The results for 2017 were favorably impacted by higher revenues due to higher realized oil and natural gas liquid sales prices, lower lease operating expenses, lower depreciation expense, lower redetermination expenses, lower dry hole costs, and higher taxes, partially offset by no repeat of the impairment expense in 2016.

Crude oil price realizations averaged $51.21 per barrel in 2017 compared to $42.38 per barrel in 2016, a price increase of 21% year over year.  WTI crude oil averaged 18% more in 2017 compared to 2016. In 2017, U.S. natural gas realized price per thousand cubic feet (MCF) averaged $2.49 compared to $1.89 per MCF in 2016, a price increase of 32% year over year. Canada natural gas realized price per MCF averaged US$1.97 in 2017 compared to US$1.72 per MCF in 2016, a price increase of 15% year over year.  Oil and gas production costs, including associated production taxes, on a per-unit basis, were $8.63 in 2017 (2016:  $9.44), which together with lower oil and natural gas volumes sold, resulted in $91.3 million lower costs in 2017.

28

 


 

 

Exploration and Production (Contd.) 

2017 vs 2016 (Contd.)

United States E&P operations reported a net loss of $8.9 million in 2017 compared to a net loss of $164.2 million in 2016. Results were $155.3 million favorable in the 2017 period compared to the 2016 period due to higher revenues ($195.2 million) and lower depreciation ($54.4 million), and lower lease operating expenses ($20.1 million), partially offset by exploration costs ($23.5 million) and higher taxes ($64.9 million). Higher revenues were primarily due to higher realized prices, while lower depreciation expense was due primarily to lower rates and lower volumes sold at Eagle Ford Shale.  Lower lease operating expenses were principally a result of continued management effort to reduce costs in the Company’s U.S. Onshore business.  Higher exploration costs were due to higher lease amortization and higher taxes resulted from higher profits. 

Canadian E&P operations reported earnings of $112.5 million in 2017 compared to losses of $35.9 million in the 2016 period.  Results were favorable $148.4 million due to 2017 including a pretax gain of $132.4 million (after tax: $96.0 million) related to the sale of Seal heavy oil assets in Canada in January 2017.  Adjusting for the impact of gain on sale of assets, Canadian results of operations improved $54.2 million in the 2017 period compared to the 2016 period due to lower lease operating expense ($71.3 million), lower depreciation expense ($17.8 million), and no repeat of the 2016 impairment charge on the Company’s Terra Nova field and Seal heavy oil field in Western Canada ($95.1 million), partially offset by lower revenues ($12.2 million) and higher taxes ($142.3 million). Lower lease operating expenses and lower depreciation expense were principally the result of the disposal of the Syncrude asset in mid-2016. 

Malaysia E&P operations reported earnings of $224.2 million in 2017, compared to earnings of $171.1 million in 2016.  Results were favorable by $53.1 million due to higher revenues ($27.7 million), lower depreciation ($23.1 million), and lower redetermination/unitization expense ($24.1 million), partially offset by higher taxes ($40.5 million). Higher revenues are principally due to higher realized prices, partially offset by lower volumes sold. Lower depreciation was a result of lower volumes produced at Block K (as a result of natural field decline). 

Other international E&P operations reported a loss from continuing operations of $37.5 million in 2017 compared to a loss of $54.7 million in the 2016 period.  The loss was $17.2 million lower in the 2017 period versus 2016 primarily due to 2017 tax benefits on investments in foreign areas ($32.9 million).







29

 


 

 



The following table contains hydrocarbons produced for the three years ended December 31, 2018.















 

 

 

 

 

 

 

Barrels per day unless otherwise noted

 

2018

 

2017

 

2016

Net crude oil and condensate

 

 

 

 

 

 

United States

Onshore

 

31,787 

 

34,649 

 

35,858 



Gulf of Mexico 1

 

18,702 

 

11,551 

 

12,372 

Canada   

Onshore

 

5,690 

 

3,004 

 

1,046 



Offshore

 

6,701 

 

8,091 

 

8,737 



Heavy 2

 

– 

 

150 

 

2,766 



Synthetic 2

 

– 

 

– 

 

4,637 

Malaysia

Sarawak

 

11,942 

 

12,674 

 

13,365 



Block K

 

16,734 

 

20,312 

 

24,619 

         Brunei

 

 

558 

 

– 

 

– 

Total net crude oil and condensate

 

92,114 

 

90,431 

 

103,400 

Net natural gas liquids

 

 

 

 

 

 

 

United States

Onshore

 

6,578 

 

6,867 

 

6,929 



Gulf of Mexico 1

 

1,147 

 

947 

 

1,302 

Canada  

Onshore

 

1,073 

 

508 

 

210 

Malaysia

Sarawak

 

792 

 

829 

 

786 

Total net natural gas liquids

 

 

9,590 

 

9,151 

 

9,227 

Net natural gas sold – thousands of cubic feet per day

 

 

 

 

 

 

United States

Onshore

 

31,832 

 

32,629 

 

35,789 



Gulf of Mexico 1

 

14,356 

 

11,901 

 

17,242 

Canada  

Onshore

 

266,416 

 

226,218 

 

208,682 

Malaysia

Sarawak

 

104,457 

 

104,616 

 

106,380 



Block K

 

5,766 

 

8,358 

 

10,070 

Total net natural gas - thousands of cubic feet per day

 

422,827 

 

383,722 

 

378,163 

Total net hydrocarbons including noncontrolling interest 3

 

172,175 

 

163,536 

 

175,654 

Less noncontrolling interest

 

 

 

 

 

 

Net crude oil and condensate – barrels per day

 

1,134 

 

– 

 

– 

Net natural gas liquids – barrels per day

 

24 

 

– 

 

– 

Net natural gas – thousands of cubic feet per day

 

430 

 

– 

 

– 

Net BOE produced attributable to noncontrolling interest 3

 

1,230 

 

– 

 

– 

Total net hydrocarbons excluding noncontrolling interest 3

 

170,945 

 

163,536 

 

175,654 

Estimated net hydrocarbon reserves - million equivalent barrels 3,4

 

844.0 

 

698.3 

 

684.5 



1  2018 includes net volumes attributable to a noncontrolling interest in MP GOM.

2  The Company sold the Seal area heavy oil property in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.  Production in this table includes production for these sold interests through the date of disposition.

3 Natural gas converted on an energy equivalent basis of 6:1.

4 At December 31, 2018, includes 28.4 MMBOE relating to noncontrolling interest.



30

 


 

 

The following table contains hydrocarbons sold for the three years ended December 31, 2018.





 

 

 

 

 

 

 

Barrels per day unless otherwise noted

 

2018

 

2017

 

2016

Net crude oil and condensate

 

 

 

 

 

 

United States

Onshore

 

31,787 

 

34,649 

 

35,858 



Gulf of Mexico 1

 

17,729 

 

11,551 

 

12,372 

Canada   

Onshore

 

5,690 

 

3,004 

 

1,046 



Offshore

 

6,884 

 

7,525 

 

8,886 



Heavy 2

 

– 

 

150 

 

2,766 



Synthetic 2

 

– 

 

– 

 

4,637 

Malaysia

Sarawak

 

12,401 

 

12,454 

 

12,464 



Block K

 

17,025 

 

19,867 

 

24,376 

         Brunei

 

 

233 

 

– 

 

– 

Total net crude oil and condensate

 

91,749 

 

89,200 

 

102,405 

Net natural gas liquids

 

 

 

 

 

 

United States

Onshore

 

6,578 

 

6,867 

 

6,929 



Gulf of Mexico 1

 

1,147 

 

947 

 

1,302 

Canada  

Onshore

 

1,073 

 

508 

 

210 

Malaysia

Sarawak

 

786 

 

1,048 

 

720 

Total net natural gas liquids

 

9,584 

 

9,370 

 

9,161 

Net natural gas sold – thousands of cubic feet per day

 

 

 

 

 

 

United States

Onshore

 

31,832 

 

32,629 

 

35,789 



Gulf of Mexico 1

 

14,356 

 

11,901 

 

17,242 

Canada  

Onshore

 

266,416 

 

226,218 

 

208,682 

Malaysia

Sarawak

 

104,457 

 

104,616 

 

106,380 



Block K

 

5,766 

 

8,358 

 

10,070 

Total net natural gas - thousands of cubic feet per day

 

422,827 

 

383,722 

 

378,163 

Total net hydrocarbons including noncontrolling interest 3

 

171,804 

 

162,524 

 

174,593 

Less noncontrolling interest

 

 

 

 

 

 

 

Net crude oil and condensate – barrels per day

 

940 

 

– 

 

– 

Net natural gas liquids – barrels per day

 

24 

 

– 

 

– 

Net natural gas – thousands of cubic feet per day

 

430 

 

– 

 

– 

Net BOE sold attributable to noncontrolling interest 3

 

1,036 

 

– 

 

– 

Total net hydrocarbons excluding noncontrolling interest 3

 

170,768 

 

162,524 

 

174,593 



 

 

 

 

 

 

1  2018 includes net volumes attributable to a noncontrolling interest in MP GOM.

2  The Company sold the Seal area heavy oil property in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.  Production in this table includes production for these sold interests through the date of disposition.

3 Natural gas converted on an energy equivalent basis of 6:1.









31

 


 

 

The Company’s reported total crude oil and condensate production averaged 92,114 barrels per day in 2018, compared to 90,431 barrels per day in 2017 and 103,400 barrels per day in 2016.  The 2018 crude oil production level was 2% higher than 2017. Crude oil production in the United States totaled 50,489 barrels per day (which includes 1,134 barrels per day relating to noncontrolling interest) in 2018, up from 46,200 barrels per day in 2017.  The increase in U.S. crude oil production year over year was primarily due to new drilling and the acquisition of properties relating to the MP GOM transaction.  Crude oil volumes produced offshore Eastern Canada totaled 6,701 barrels per day in 2018, down from 8,091 barrels per day in the previous year. Crude oil production offshore Sarawak decreased from 12,674 barrels per day in 2017 to 11,942 barrels per day in 2018.  Block K in Malaysia had crude oil production of 16,734 barrels per day in 2018, down from 20,312 barrels per day in 2017.  Lower oil production in 2018 in Malaysia was primarily attributable to natural well decline at most fields.

The Company’s total crude oil and condensate production averaged 90,431 barrels per day in 2017, compared to 103,400 barrels per day in 2016 and 126,400 barrels per day in 2015.  The 2017 crude oil production level was 13% below 2016. Crude oil production in the United States totaled 46,200 barrels per day in 2017, down from 48,230 barrels per day in 2016.  The decrease in U.S. crude oil production year over year was primarily due to well decline and shut-ins due to weather events which was only partially offset by new drilling.  Heavy crude oil production in Western Canada fell from 2,766 barrels per day in 2016 to 150 barrels per day in 2017, with the reduction attributable to the sale of Seal asset in January 2017.  Crude oil volumes produced offshore Eastern Canada totaled 8,091 barrels per day in 2017, down from 8,737 barrels per day in the previous year. There was no synthetic crude oil production in Canada in 2017 compared to 4,637 barrels per day in 2016 due to the Company selling its 5% interest in Syncrude in June 2016.  Crude oil production offshore Sarawak decreased from 13,365 barrels per day in 2016 to 12,674 barrels per day in 2017.  Block K in Malaysia had crude oil production of 20,312 barrels per day in 2017, down from 24,619 barrels per day in 2016.  Lower oil production in 2017 in Malaysia was primarily attributable to natural well decline at most fields.

The Company produced natural gas liquids (NGL) of 9,590 barrels per day in 2018, largely in line with 9,151 barrels per day produced in 2017.  Eighty-one percent of the Company’s NGL production in 2018 was derived from the Gulf of Mexico and Eagle Ford Shale areas in the U.S.  

The Company’s NGL production of 9,151 barrels per day in 2017 was in line with 9,227 barrels per day produced in 2016.  Eighty-five percent of the Company’s NGL production in 2017 was derived from the Gulf of Mexico and Eagle Ford Shale areas in the U.S.  

Worldwide sales of natural gas averaged 422.8 million cubic feet (MMCF) per day in 2018 compared to 383.7 MMCF per day in 2017.  The 2018 increase in natural gas sales volumes is attributable to an 18% increase in natural gas production in Canada, primarily in Tupper and Placid areas as well as increase in gas production in the Gulf of Mexico in U.S

Worldwide sales of natural gas averaged 383.7 million cubic feet (MMCF) per day in 2017 compared to 378.2 MMCF per day in 2016.  The 2017 increase in natural gas sales volumes is attributable to 8% increase in natural gas production in Canada, primarily in Tupper and Placid areas, offset in part by lower gas production in the Gulf of Mexico and Eagle Ford Shale areas in United States. 

32

 


 

 

The following table contains the weighted average sales prices including transportation cost deduction for the three years ended December 31, 2018.







 

 

 

 

 

 

 

 



 

 

2018

 

2017

 

2016

 

Weighted average Exploration and Production sales prices 1

 

 

 

 

 

 

 

Crude oil and condensate – dollars per barrel

 

 

 

 

 

 

 

United States

Onshore

$

67.08 

 

50.49 

 

42.11 

 



Gulf of Mexico

 

62.36 

 

49.24 

 

41.63 

 

Canada 2   

Onshore

 

50.87 

 

46.68 

 

42.01 

 



Offshore

 

68.02 

 

53.39 

 

43.12 

 

Malaysia 3

Sarawak

 

62.38 

 

53.26 

 

46.02 

 



Block K

 

65.44 

 

52.72 

 

45.27 

 

          Brunei

 

 

71.48 

 

– 

 

– 

 



 

 

 

 

 

 

 

 

Natural gas liquids – dollars per barrel

 

 

 

 

 

 

 

United States

Onshore

 

22.21 

 

17.70 

 

11.51 

 



Gulf of Mexico

 

24.54 

 

19.57 

 

12.84 

 

Canada 2   

Onshore

 

37.44 

 

25.00 

 

20.63 

 

Malaysia 3

Sarawak

 

69.04 

 

51.00 

 

38.30 

 



 

 

 

 

 

 

 

 

Natural gas – dollars per thousand cubic feet

 

 

 

 

 

 

 

United States

Onshore

 

2.44 

 

2.49 

 

1.88 

 



Gulf of Mexico

 

2.77 

 

2.49 

 

1.92 

 

Canada 2 

Onshore

 

1.52 

 

1.97 

 

1.72 

 

Malaysia 3

Sarawak

 

3.78 

 

3.55 

 

3.21 

 



Block K

 

0.24 

 

0.24 

 

0.25 

 



 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 





1 U.S. dollar equivalent.

2 The Company sold the Seal area heavy oil property in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.

3 Prices are net of payments under the terms of the respective production sharing contracts.



33

 


 

 

Cost per equivalent barrel sold for these production-related expenses are shown by geographical area in the following table.











 

 

 

 

 

 

(Dollars per equivalent barrel)

 

2018 

 

2017 

 

2016 

United States – Eagle Ford Shale

 

 

 

 

 

 

    Lease operating expense

$

8.84 

 

7.35 

 

9.10 

    Severance and ad valorem taxes

 

3.20 

 

2.46 

 

2.07 

    Depreciation, depletion and amortization (DD&A) expense

 

24.54 

 

25.64 

 

25.83 

United States – Gulf of Mexico

 

 

 

 

 

 

    Lease operating expense

 

11.39 

 

13.71 

 

9.28 

    Severance and ad valorem taxes

 

 –

 

 –

 

0.02 

    DD&A expense

 

16.50 

 

20.20 

 

23.06 

Canada – Onshore

 

 

 

 

 

 

    Lease operating expense

 

4.52 

 

4.95 

 

5.26 

    Severance and ad valorem taxes

 

0.06 

 

0.10 

 

0.30 

    DD&A expense

 

10.61 

 

9.92 

 

10.61 

Canada – Offshore

 

 

 

 

 

 

    Lease operating expense

 

15.21 

 

9.61 

 

8.58 

    DD&A expense

 

13.68 

 

12.95 

 

11.08 

Malaysia – Sarawak

 

 

 

 

 

 

    Lease operating expense

 

8.12 

 

5.24 

 

5.41 

    DD&A expense

 

8.65 

 

8.09 

 

8.68 



 

 

 

 

 

 

Malaysia – Block K

 

 

 

 

 

 

    Lease operating expense

 

16.97 

 

14.13 

 

11.23 

    DD&A expense                   

 

15.52 

 

14.60 

 

13.60 



 

 

 

 

 

 

Total oil and gas operations

 

 

 

 

 

 

    Lease operating expense

 

8.86 

 

7.89 

 

8.75 

    Severance and ad valorem taxes

 

0.83 

 

0.74 

 

0.69 

    DD&A expense

 

15.50 

 

15.85 

 

16.24 



 

 

 

 

 

 

Total oil and gas operations – excluding  noncontrolling interest

 

 

 

 

 

 

     Lease operating expense

 

8.88 

 

7.89 

 

8.75 

     Severance and ad valorem taxes

 

0.83 

 

0.74 

 

0.69 

     DD&A expense

 

15.23 

 

15.85 

 

16.24 











34

 


 

 

Results of Operations (Contd.)

Corporate 

2018 vs 2017

Corporate activities, which include interest income and expense, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to operating functions, reported a net loss of $123.9 million in 2018 compared to a loss of $601.2 million in 2017. The $477.3 million favorable variance in 2018 was primarily due to a credit to income tax expense of $135.7 million primarily related to an IRS interpretation of the 2017 Tax Act (versus a charge in 2017 of $274.0 million), lower foreign exchange losses ($66.4 million), and income related to an Ecuador arbitration settlement ($26.0 million), partially offset by losses on crude contracts used to hedge price risk ($42.0 million) versus a loss in the prior period ($9.5 million), lower other tax credits ($18.2 million), and higher G&A expense ($6.9 million). Further, the 2017 period included a deferred tax charge of $65.2 million associated with the estimated tax consequence of future repatriation of Malaysian and Canadian earnings that were deemed no longer indefinitely invested. 

2017 vs 2016

Net costs of Corporate activities in 2017 were unfavorable to 2016 by $458.4 million primarily due to the impact of the 2017 Tax Act, foreign exchange losses and higher interest expense, partially offset by lower administrative expenses. The impact of the 2017 Tax Act resulted in a charge of $274.0 million principally as a result of a deemed repatriation of foreign earnings and the revaluation of deferred tax assets and liabilities. The after-tax effects of foreign currency exchange losses were $65.3 million in 2017, $117.6 million unfavorable to 2016.  These effects arose due to transactions denominated in currencies other than the respective operations’ predominant functional currency.  The foreign currency loss recognized in 2017 was mostly realized in Canada relating to an inter-company loan between foreign subsidiaries denominated in U.S. dollars. The Canadian operation’s functional currency is the Canadian dollar.  In Malaysia, net deferred tax assets and prepaid current income tax amounts reported in its balance sheet were revalued to the Malaysian operation’s functional currency of U.S. dollars. Interest expense of $181.8 million was $33.6 million higher in 2017 as a result of bonds issued in the third quarter 2017 for net proceeds of $541.0 million. Administrative expenses associated with corporate activities were lower in 2017 by $18.9 million, primarily due to a higher allocation of costs to the exploration and production businesses. 



Financial Condition

Cash Provided by Operating Activities

Net cash provided by continuing operating activities was $1,219.4 million in 2018 compared to $1,128.1 million in 2017. The $91.3 million improvement in cash provided by continuing operations activities in 2018 was primarily attributable to higher revenues from higher prices and higher volumes ($508.1 million), offset by higher cash taxes paid as a result of repatriating cash from Canada, current tax payments in Malaysia ($62.9 million), payments made on hedge (crude contracts to mitigate price risk) losses ($75.9 million).  Changes in operating working capital from continuing operations decreased cash by $169.8 million during 2018, compared to increasing cash by $136.4 million in 2017.

Cash flow provided by continuing operations was $527.3 million higher in 2017 than in 2016 due to higher realized oil and natural gas sales prices, lower lease operating expenses and lower selling and general expenses. Also, 2016 included $266.6 million relating to payments for a deepwater rig contract exit.

The total reductions of operating cash flows for interest paid during the three years ended December 31, 2018, 2017, and 2016 were $167.8 million, $147.9 million and $127.8 million, respectively.

Cash Used in Investing Activities

Cash used for property additions and dry holes, which includes amounts expensed, were $1,102.8 million and $1,009.7 million in 2018 and 2017, respectively. The increase is due to higher development drilling activities in Eagle Ford Shale and Kaybob Duvernay. Cash used for acquisition of oil properties was $794.6 million, attributable to the MP GOM acquisition.

35

 


 

 

The accrual basis of capital expenditures were as follows:





 

 

 

 

 

 

 

 



Year Ended December 31,

(Millions of dollars)

2018

 

2017

 

2016

Capital Expenditures

 

 

 

 

 

 

 

 

Exploration and production

$

1,959.4 

 

 

960.9 

 

 

789.8 

Corporate

 

27.9 

 

 

14.8 

 

 

21.7 

Total capital expenditures

$

1,987.3 

 

 

975.7 

 

 

811.5 



A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.





 

 

 

 

 

 

 

 



Year Ended December 31,

(Millions of dollars)

2018

 

2017

 

2016

Property additions and dry hole costs per cash flow statements

$

1,102.8 

 

 

1,009.7 

 

 

926.9 

Acquisition of oil properties

 

794.6 

 

 

 -

 

 

 -

Geophysical and other exploration expenses

 

43.2 

 

 

65.2 

 

 

43.4 

Capital expenditure accrual changes and other

 

46.7 

 

 

(99.2)

 

 

(158.8)

Total capital expenditures

$

1,987.3 

 

 

975.7 

 

 

811.5 



Proceeds from sales of property and equipment generated cash of $1.4 million in 2018 compared to $69.5 million in 2017 primarily relating to the proceeds from the sale of the Seal field in Western Canada and the sale of certain non-core assets of Eagle Ford Shale in South Texas in 2017.  Proceeds from sales of assets generated $1.16 billion in 2016 as a result of the sale of Syncrude and natural gas processing and sales pipeline assets that support natural gas fields in the Tupper area in Canada.

Cash Provided by and Use by Financing Activities

During 2018, the Company borrowed $325.0 million on its revolving credit facility to partially fund the MP GOM transaction.

During 2017 the Company issued $550 million notes in August 2017 that bear a rate of 5.75% and mature on August 15, 2025, for net proceeds of $541.6 million; these proceeds were used to redeem the Company’s $550 million 3.50% notes in September 2017.  The 3.50% notes had a maturity date of December 2017 and were retired early. 

During 2016, the Company borrowed $541.4 million by issuing 6.875% notes maturing in 2024. The Company used $600.0 million in cash during 2016 to repay long-term debt under its revolving credit facility. 

Total cash dividends to shareholders amounted to $173.0 million in 2018, $172.6 million in 2017, and $206.6 million in 2016.



36

 


 

 

Financial Condition (Contd.)

At the end of 2018, working capital (total current assets less total current liabilities) amounted to $33.8 million (2017:  $537.4 million).  The total working capital decrease in 2018 is primarily attributable to lower cash (due to the MP GOM transaction, $469.6 million cash impact) and inventory balances offset by higher accounts receivable and prepaid expenses.

Cash and cash equivalents at the end of 2018 totaled $387.4 million (2017:  $965.0 million). The decrease in 2018 is primarily related to the use of cash on hand to fund the MP GOM acquisition. Cash and cash equivalents at the end of 2017 totaled $965.0 million (2016:  $872.8 million). The increase in 2017 was primarily related to the conversion of Canadian government securities with maturities greater than 90 days to cash. Canadian government securities held at the end of 2016 totaled $111.5 million. These slightly longer-term Canadian investments were purchased in 2016 because of a tight supply of shorter-term securities available for purchase in Canada. 

Cash and invested cash are maintained in several operating locations outside the United States.  At December 31, 2018, Cash and cash equivalents held outside the U.S. included U.S dollar equivalents of approximately $175.1 million (2017:  $549.3 million) in Canada and $27.4 million (2017:  $334.6 million) in Malaysia.  In addition, approximately $17.2 million of cash was held in the U.K. and has been classified as part of Assets held for sale in the Consolidated Balance Sheets at year-end 2018.  In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods.  Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.  See Note J of the consolidated financial statements for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.

At December 31, 2018, long-term debt of $3,227.1 million was $320.6 million higher than year-end 2017, principally as a result of borrowing on the revolving credit facility to partially fund the MP GOM acquisition ($325.0 million). Long-term debt at year-end 2017 was $483.8 million higher than year-end 2016, principally as a result of the issuance of $550 million notes in August 2017 that bear a rate of 5.75% and mature in August 2025.  A summary of capital employed at December 31, 2018 and 2017 follows.





 

 

 

 

 

 

 

 

 

 

 



December 31, 2018

 

December 31, 2017

(Millions of dollars)

Amount

 

%

 

Amount

 

%

Capital employed

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

$

3,227.1 

 

38.3 

%

 

$

2,906.5 

 

38.6 

%

Total equity

 

5,197.6 

 

61.7 

%

 

 

4,620.2 

 

61.4 

%

Total capital employed

 

8,424.7 

 

100.0 

%

 

$

7,526.7 

 

100.0 

%

Total capital employed excluding noncontrolling
interest

$

8,056.4 

 

n/a

 

 

 

7,526.7 

 

n/a

 



Stockholders’ equity was $5.20 billion at the end of 2018 (2017:  $4.62 billion; 2016:  $4.92 billion). Stockholders’ equity increased in 2018 primarily due to net income earned and the addition of noncontrolling interest as part of the MP GOM transaction.  Stockholders’ equity declined in 2017 primarily due to the net loss incurred and cash dividends paid on common stock. A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 59 of this Form 10-K report.

Other significant changes in Murphy’s balance sheet at the end of 2018, compared to 2017 are discussed below.

Deferred income tax assets increased $148.1 million to $359.6 million (2017:  $211.5 million) principally as a result of the favorable 2018 IRS interpretation of the impact of the 2017 Tax Act which resulted in the reinstatement of deferred tax assets relating to 2017 net operating losses.

Deferred income tax liabilities decreased $29.2 million to $129.9 million (2017:  $159.1 million) principally as a result of current year Canadian taxable profits utilizing prior taxable losses and the change from a U.S. net deferred tax liability position to a net deferred tax asset position, due to the 2018 IRS interpretation of the impact of the 2017 Tax Act.

Long-term asset retirement obligations increased $318.1 million to $1,027.4 million, principally due to increased obligations associated with the MP GOM transaction.





37

 


 

 

Financial Condition (Contd.)

Murphy had commitments for capital expenditures of approximately $383.1 million at December 31, 2018 (2017: $432.3 million).  These commitments included $165.2 million for costs to develop deepwater U.S. Gulf of Mexico fields including new fields acquired as part of the MP GOM transaction, $103.0 million for field development and future work commitments in Malaysia, $60.0 million for development at Kaybob Duvernay in Canada, $31.4 million for work at Eagle Ford Shale, $14.7 million for exploration cost in Mexico, and $8.8 million for future work commitments in Vietnam.

The primary sources of the Company’s liquidity are internally generated funds, access to outside financing and working capital.  The Company generally uses its internally generated funds to finance its capital and operating expenditures, but it also maintains lines of credit with banks and will borrow as necessary to meet spending requirements. At December 31, 2018, the Company has a $1.6 billion senior unsecured guaranteed credit facility (2018 facility) with a major banking consortium, which expires in November 2023. 

At December 31, 2018, the Company had outstanding borrowings of $325.0 million under the 2018 facility and $24.7 million of outstanding letters of credit, which reduce the borrowing capacity of the 2018 facility.  Borrowings under the 2018 facility bear interest at rates, based, at the Company’s option, on the “Alternate Base Rate” of interest in effect plus the “ABR Spread” or the “Adjusted LIBOR Rate,” which is a periodic fixed rate based on LIBOR with a term equivalent to the interest period for such borrowing, plus the “Eurodollar Spread.” The “Alternate Base Rate” of interest is the highest of (i) the Wall Street Journal prime rate, (ii) the New York Federal Reserve Bank Rate plus 0.50%, and (iii) one-month LIBOR plus 1.00%. The “Eurodollar Spread” ranges from 1.075% to 2.10% per annum based upon the Corporation’s senior unsecured long-term debt securities credit ratings (the “Credit Ratings”). A facility fee accrues and is payable quarterly in arrears at a rate ranging from 0.175% to 0.40% per annum (based upon the Company’s Credit Ratings) on the aggregate commitments under the 2018 facility.  At December 31, 2018, the interest rate in effect on borrowings under the facility was 3.831%.  At December 31, 2018, the Company was in compliance with all covenants related to the 2018 facility.

Current financing arrangements are outlined in more detail in Note H to the consolidated financial statements.



Environmental Matters

Murphy faces various environmental and safety risks that are inherent in exploring for, developing and producing hydrocarbons.  To help manage these risks, the Company has established a robust health, safety and environmental governance program comprised of a worldwide policy, guiding principles, annual goals and a management system, with appropriate oversight at the business unit, senior leadership and board levels.  The Company strives to minimize these risks by continually improving its processes through design, operation and maintenance, and through emergency and oil spill response planning to address any credible and major risks it identifies through impact assessments.

Murphy and other companies in the oil and gas industry are subject to numerous international, national, state, provincial and local environmental and safety laws and regulations.  Murphy allocates a portion of its capital expenditure program, as well as its general and administrative budget, to comply with existing and anticipated environmental laws and regulations.  These requirements affect virtually all operations of the Company and increase Murphy’s overall cost of business, including its capital costs to construct, maintain and upgrade equipment and facilities, and operating costs for ongoing compliance.

The principal environmental laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials, the emission and discharge of such materials to the environment, greenhouse gas emissions, wildlife, habitat and water protection and the placement, operation and decommissioning of production equipment.  These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations.  Any violation of applicable environmental laws, regulations or permits can give rise to significant civil and criminal penalties, injunctions, construction bans and delays, and other sanctions. 

38

 


 

 

Environmental Matters (Contd.)

These laws, regulations and permits have been subject to frequent change and tend to become more stringent over time.  The change in the federal administration creates uncertainty in future changes as well as the enforcement of existing laws and regulations.  In the United States, the Environmental Protection Agency has implemented requirements to reduce sulfur dioxide, a volatile organic compound and hazardous air pollutant air emissions from oil and gas operations, including standards for wells that are hydraulically fractured.  Any current or future air emission or other environmental requirements applicable to Murphy’s businesses could curtail its operations or otherwise result in operational delays, liabilities and increased costs.

Certain jurisdictions in which the Company operates have required, or are considering requiring, more stringent permitting, chemical disclosure, transparency, water usage, disposal and well construction requirements.  Regulators are also becoming increasingly focused on air emissions from the oil and gas industry, including volatile organic compound and methane emissions.

Murphy also could be subject to strict liability for environmental contamination, in various jurisdictions where we operate, including with respect to its current or former properties, operations and waste disposal sites, or those of its predecessors.  Contamination has been identified at certain of such sites as a result of which the Company has been required and in the future may be required to remove or remediate previously disposed wastes, clean up contaminated soil, surface water and groundwater, address spills and leaks from pipelines and production equipment, and perform remedial plugging operations.  In addition to significant investigation and remediation costs, such matters can result in fines and also give rise to third-party claims for personal injury and property or other environmental damage.

In 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta.  The pipeline was immediately shut down and the Company’s emergency response plan was activated.  In cooperation with local governmental regulators, and with the assistance of qualified consultants, an investigation and remediation plan is progressing as planned and the Company’s insurers were notified.  Based on the assessments done to date, the Company recorded $43.9 million in Other expense during 2015 and a further $3.8 million in 2018 associated with the estimated costs of remediating the site.  The Company has spent $44.7 million from inception to December 31, 2018.  Further refinements in the estimated total cost to remediate the site may occur in future periods. The Company retained the responsibility for this remediation upon sale of the Seal field in 2017. As of December 31, 2018, the Company has a remaining accrued liability of $3.0 million associated with this event. In 2018, the Company received $25.0 million in respect to an insurance claim regarding this matter and the outcome of further insurance claims by the Company is pending.



Climate Change

Murphy is currently required to report greenhouse gas emissions from certain of its operations and, in British Columbia and Alberta, is subject to a carbon tax on the purchase or use of many carbon-based fuels.  Additionally, starting in 2017, a carbon tax applies to certain operations in Alberta.  The Canadian Government has announced a proposal that all other provinces and territories implement some form of carbon pricing by 2018.  Any limitation on or further regulation of, greenhouse gases (including through a cap and trade system) technology mandate, emissions tax, reporting requirement or other program, could restrict the Company’s operations, curtail demand for hydrocarbons generally and/or impose increased costs, including to operate and maintain facilities, install pollution emission controls and administer and manage emissions trading programs.



Safety Matters

The Company is subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable foreign and state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in Murphy’s operations and that this information be provided to employees, state and local government authorities and citizens.  The Company believes that its operations are in substantial compliance with applicable safety requirements, including general industry standards, record-keeping requirements and the monitoring of occupational exposure to regulated substances.

39

 


 

 

Other Matters

Impact of inflation – General inflation was moderate during the last three years in most countries where the Company operates; however, the Company’s revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas and allied industries than by changes in general inflation.  Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels and/or attitudes of traders concerning supply and demand in the future.  Prices for oil field goods and services are usually affected by the worldwide prices for crude oil. 

Following the drop in oil prices in late 2014, 2015-2016 experienced reduced demand for oil and gas materials and services, which led to downward pressure on the cost of these materials and services in 2015 and 2016. In 2017 and 2018, as oil and gas prices have moved higher, drilling activity has begun to increase, leading to upward pressure on the cost of oil and gas materials and services.

Natural gas prices are also affected by supply and demand, which are often affected by the weather and by the fact that delivery of gas is generally restricted to specific geographic areas.

As a result of the overall volatility of oil and natural gas prices, it is not possible to predict the Company’s future cost of oil field goods and services.

Accounting changes and recent accounting pronouncements – see Note B

Significant accounting policies – In preparing the Company’s consolidated financial statements in accordance with U.S. GAAP, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities.  Application of certain of the Company’s accounting policies requires significant estimates.  The most significant of these accounting policies and estimates are described below.

Oil and gas proved reserves – Oil and gas proved reserves are defined by the SEC as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire (unless evidence indicates that renewal is reasonably certain).  Proved developed reserves of oil and gas can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 

Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment.  SEC rules require the Company to use an unweighted average of the oil and gas prices in effect at the beginning of each month of the year for determining quantities of proved reserves.  These historical prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production in the future.  The Company often uses significantly different oil and natural gas price and reserve assumptions when making its own internal economic property evaluations.  Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserves quantities. 



Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.  Reserves revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligations.  Downward reserves revisions can also lead to significant impairment expense.  The Company cannot predict the type of oil and gas reserves revisions that will be required in future periods. 

40

 


 

 

Other Matters (Contd.)

Significant accounting policies (contd.)

The Company’s proved reserves of crude oil, natural gas liquids and natural gas are presented on pages 106 to 112 of this Form 10-K report.  Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data, and commercially available technologies, to establish ‘reasonable certainty’ of economic producibility.  As defined by the SEC, reasonable certainty of proved reserves describes a high-degree of confidence that the quantities will be recovered.  In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analog-based studies. 

Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves.  Reliable geologic and engineering technology is a method or combination of methods that are field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.  This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates, and was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas, and in certain reservoirs developed with the application of improved recovery techniques.  Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs.  Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.

See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2018 beginning on pages 7 and 101 of this Form 10-K report.



Property, Plant & Equipment - impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in Property, plant and equipment (PPE) in the Consolidated Balance Sheet to make sure that they are fairly presented.  The Company must evaluate its PPE for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows. 

A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events.  Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital, operating and abandonment costs, and future inflation levels. 

The need to test a long-lived asset for impairment can be based on several factors, including but not limited to a significant reduction in sales prices for oil and/or natural gas, unfavorable revisions of oil or natural gas reserves, or other changes to contracts, environmental regulations, tax laws or other regulatory changes. All of these factors must be considered when evaluating a property’s carrying value for possible impairment. 

Due to the volatility of world oil and gas markets, the actual sales prices for oil and natural gas have often been different from the Company’s projections. 

Estimates of future oil and gas production and sales volumes are based on a combination of proved and risked probable and possible reserves.  Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection.  The Company adjusts reserves and production estimates as new information becomes available. 

The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations.  Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated. 

In 2018, the Company recorded an impairment expense of $20.0 million to reduce the carrying value of select Midland properties to its net recoverable value.

The company did not record any impairment expense in 2017.

The Company recorded impairment expense of $95.1 million in 2016 to reduce the carrying value of producing heavy oil properties in Western Canada and the Terra Nova field offshore Canada to their estimated fair value due to significant declines in future oil prices in early 2016.

41

 


 

 

Other Matters (Contd.)

Significant accounting policies (contd.)

Property, Plant & Equipment – business combinations – The Company may acquire assets and assume liabilities in transactions accounted for as business combinations, such as the MP GOM transaction with PAI in 2018. In connection with a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed, based on fair values as of the acquisition date. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as goodwill. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.

Significant assumptions are involved in determining the fair value of assets acquired and liabilities assumed, such as the fair values assigned to proved and unproved crude oil and natural gas properties. In most cases, sufficient market data is not available regarding the fair values of proved and unproved properties, and the Company prepares estimates of such properties based on the fair value of associated crude oil, natural gas and NGL reserves. The primary assumptions used to arrive at estimates of future net cash flows are reserves quantities, commodity prices, and capital and operating costs. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.

Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Beginning in the fourth quarter of 2018, Murphy reports 100% of the sales volumes, revenues, costs, assets and liabilities including the 20% noncontrolling interest (NCI), of the new Gulf of Mexico transaction (MP GOM) with Petrobras Americas Inc (PAI), in accordance with accounting for noncontrolling interest as prescribed by ASC 810-10-45.



Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates.  When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company and (d) changes to regulations may be subject to different interpretations and require future clarification from issuing authorities.  The Company has deferred tax assets mostly relating to basis differences for property, equipment and inventories, and liabilities for dismantlement and retirement benefit plan obligations and net deferred tax liabilities relating to U.S. basis differences for property equipment and inventories.  The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization.

In 2018, Murphy Oil’s net income included a favorable income tax adjustment of $135.7 million related to the 2017 Tax Act enacted on December 22, 2017. The $135.7 million adjustment, primarily related to the reinstatement of a deferred tax asset for 2017 net operating losses, which in 2017, was assumed utilized against the deemed repatriation.

For the year ended December 31, 2017, Murphy recorded a tax expense of $274.0 million directly related to the impact of the 2017 Tax Act.  The charge includes the impact of a deemed repatriation of accumulated foreign earnings and the re-measurement of deferred tax assets and liabilities.



Accounting for retirement and postretirement benefit plans – Murphy Oil and certain of its subsidiaries maintain defined benefit retirement plans covering certain full-time employees.  The Company also sponsors health care and life insurance benefit plans covering most retired U.S. employees.  The expense associated with these plans is estimated by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries.  The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of return on plan assets. For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate.  Discount rates are based on the universe of high-quality corporate bonds that are available within each country.  Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans.  The discounted cash flows are used to determine an equivalent

42

 


 

 

single rate which is the basis for selecting the discount rate within each country.  Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics.  Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs.

Based on bond yields at December 31, 2018, the Company has used a weighted average discount rate of 4.4 % at year-end 2018 for the primary U.S. plans.  This weighted average discount rate is 0.7% higher than prior year, which decreased the Company’s recorded liabilities for retirement plans compared to a year ago.  Although the Company presently assumes a return on plan assets of 6.0% for the primary U.S. plan, it periodically reconsiders the appropriateness of this and other key assumptions.  The Company’s retirement and postretirement plan expenses in 2019 are expected to be $1.7 million higher than 2018 primarily due to increased amortization of the interest cost component.  Cash contributions are anticipated to be $4.8 million higher in 2019.  In 2018, the Company paid $24.5 million into various retirement plans and $3.1 million into postretirement plans.  In 2019, the Company is expecting to fund payments of approximately $27.3 million into various retirement plans and $5.1 million for postretirement plans.  The Company could be required to make additional and more significant funding payments to retirement plans in future years.  Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed return, or the health care cost trend rate increase is higher than expected. 

As described above, the Company’s retirement and postretirement expenses are sensitive to certain assumptions, primarily related to discount rates and assumed return on plan assets.  A 0.5% decline in the discount rate would increase 2019 annual retirement expenses by $2.0 million and decrease postretirement expenses by $0.3 million; and a 0.5% decline in the assumed rate of return on plan assets would increase 2018 retirement expense by $2.4 million.

Legal, environmental and other contingent matters – A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost can be reasonably estimated.  Judgment is often required to determine when expenses should be recorded for legal, environmental and other contingent matters.  In addition, the Company often must estimate the amount of such losses.  In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law.  The Company’s management closely monitors known and potential legal, environmental and other contingent matters, and makes its best estimate of the amount of losses and when they should be recorded based on information available to the Company.



Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure plans, and other long-term liabilitiesTotal payments due after 2018 under such contractual obligations and arrangements are shown in the table below.











 

 

 

 

 

 

 

 

 

 



 

Amount of Obligations

(Millions of dollars)

 

Total

 

2019

 

2020-2021

 

2022-2023

 

After 2023

Debt including current maturities

$

3,237.9 

 

10.6 

 

22.9 

 

1,445.4 

 

1,759.0 

Operating and other leases

 

401.7 

 

188.6 

 

150.8 

 

43.2 

 

19.1 

Capital expenditures, drilling rigs and other

 

2,060.2 

 

516.4 

 

314.8 

 

259.9 

 

969.1 

Other long-term liabilities, including debt
  interest

 

2,810.0 

 

162.0 

 

476.5 

 

347.6 

 

1,823.9 

       Total

$

8,509.8 

 

877.6 

 

965.0 

 

2,096.1 

 

4,571.1 



The Company has entered into agreements to lease production facilities for various producing oil fields.  In addition, the Company has other arrangements that call for future payments as described in the following section.  The Company’s share of the contractual obligations under these leases and other arrangements has been included in the table above.

In 2013, the Company entered, along with its partners, into a 25-year lease for a semi-floating production system at the Kakap field offshore Sabah, Malaysia.  The Company has included the required net lease obligations for this production system as Debt in the contractual obligation table above.

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts.  Total outstanding letters of credit were $181.2 million as of December 31, 2018.

43

 


 

 

Material off-balance sheet arrangements – The Company occasionally utilizes lease arrangements for operational or funding purposes where the commitment may not be recorded on the balance sheet.  The most significant of these arrangements at year-end 2017 included operating leases of floating, production, storage and offloading vessel (FPSO) for the Kikeh and Cascade/Chinook oil fields, drilling contracts for onshore and offshore rigs in various countries, and oil and/or natural gas transportation and processing contracts in the U.S. and Western Canada.  The leases call for future monthly net lease payments through 2022 at Kikeh.  The U.S. transportation contracts require minimum monthly payments through 2024, while Western Canada processing contracts call for minimum monthly payments through 2035.  Future required minimum annual payments under these arrangements are included in the contractual obligation table above.  In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The Company anticipates adopting this guidance in the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.





44

 


 

 

Outlook

Prices for the Company’s primary products are often quite volatile.  The price of crude oil is primarily affected by the levels of supply and demand for energy.  Anticipated future variances between the predicted demand for crude oil and the projected available supply can lead to significant movement in the price of crude oil.  In January 2019, West Texas Intermediate crude oil averaged about $51.55 for the month and averaged $54.45 in the first three weeks of February.  NYMEX natural gas averaged $3.07 during January 2019.  Both of these oil and natural gas prices are below the average prices achieved in 2018.  The Company continually monitors the prices for its main products and often alters its operations and spending plans based on these prices.

The Company’s capital expenditure budget for 2019 is expected to be between $1.25 and $1.45 billion (excluding noncontrolling interest of $48 million).  Capital and other expenditures will be routinely reviewed during 2019 and planned capital expenditures may be adjusted to reflect differences between budgeted and actual cash flow during the year.  Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared.  The Company will primarily fund its capital program in 2019 using operating cash flow and available cash, but will supplement funding where necessary using borrowings under available credit facilities. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that further capital spending reductions are required and/or borrowings might be required during the year to maintain funding of the Company’s ongoing development projects.

The Company currently expects average daily production in 2019 to be between 215,000 and 223,000 barrels of oil equivalent per day (including noncontrolling interest of 13,000 BOEPD). 

The Company has entered into natural gas forward delivery contracts to manage risk associated with certain Canadian natural gas sales prices as follows:













 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

Volumes

 

Price

 

Remaining Period

Area

 

Commodity

 

Type

 

(MMcf/d)

 

(CAD /Mcf)

 

Start Date

 

End Date

Montney

 

Natural Gas

 

Fixed price forward sales at AECO

 

59 

 

C$2.81

 

1/1/2019

 

12/31/2020



 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

Volumes

 

Price

 

Remaining Period

Area

 

Commodity

 

Type

 

(MMcf/d)

 

(USD/MMBtu)

 

Start Date

 

End Date

Montney

 

Natural Gas

 

Fixed price forward sales at AECO

 

10 

 

$             4.19

 

1/1/2019

 

3/31/2019

Montney

 

Natural Gas

 

Fixed price forward sales at AECO

 

10 

 

$             3.85

 

1/1/2019

 

3/31/2019

Montney

 

Natural Gas

 

Fixed price forward sales at Dawn

 

10 

 

$             4.20

 

1/1/2019

 

3/31/2019



In 2018 the Company observed upward pressure on the cost for oil field goods and services as commodity prices increased.  This follows price concessions from many of its vendors that supplied oil filed goods and services in prior periods of lower commodity prices.

Forward-Looking Statements

This Form 10-K contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.  These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties.  Factors that could cause actual results to differ materially from those expressed or implied in these forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of Murphy’s exploration programs, the Company’s ability to maintain production rates and replace reserves, customer demand for Murphy’s products, adverse foreign exchange movements, political and regulatory instability, adverse developments in the U.S. or global capital markets, credit markets or economies generally, and uncontrollable natural hazards.  For further discussion of risk factors, see Item 1A. Risk Factors, which begins on page 13 of this Annual Report on Form 10-K.  Murphy undertakes no duty to publicly update or revise any forward-looking statements.

45

 


 

 

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates.  As described in Note M, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

There were no commodity transactions in place at December 31, 2018 covering certain future U.S. crude oil sales volumes in 2019. 

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information required by this item appears on pages 52 through 117 of this Form 10-K report.



Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None



Item 9A. CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by Murphy to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, with the participation of the Company’s management, as of December 31, 2018, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

Murphy’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f).  Management has conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on the results of this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2018Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal controls over financial reporting during the first year of an acquisition while integrating the acquired business.  As noted in Management’s report, included on page 52 of this Form 10-K report, our assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of assets acquired in the MP GOM transaction on November 30, 2018. KPMG LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018 and their report is included on page 54 of this Form 10-K report.

Other than noted above, there were no changes in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 2018 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.



Item 9B. OTHER INFORMATION



None











46

 


 

 

PART III



Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Certain information regarding executive officers of the Company is included on page 21 of this Form 10-K report. Other information required by this item is incorporated by reference to the Registrant’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 8, 2019 under the captions “Election of Directors” and “Committees.”

Murphy Oil has adopted a Code of Ethical Conduct for Executive Management, which can be found under the Corporate Governance and Responsibility tab at www.murphyoilcorp.com.  Stockholders may also obtain, free of charge, a copy of the Code of Ethical Conduct for Executive Management by writing to the Company’s Secretary at P.O. Box 7000, El Dorado, AR 71731-7000.  Any future amendments to or waivers of the Company’s Code of Ethical Conduct for Executive Management will be posted on the Company’s Website.



Item 11. EXECUTIVE COMPENSATION

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 8, 2019 under the captions “Compensation Discussion and Analysis” and “Compensation of Directors” and in various compensation schedules.



Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 8, 2019 under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management,” and “Equity Compensation Plan Information.”



Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 8, 2019 under the caption “Election of Directors.”



Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 8, 2019 under the caption “Audit Committee Report.”













47

 


 

 



PART IV



Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES



(a)   1.   Financial Statements – The consolidated financial statements of Murphy Oil Corporation and consolidated subsidiaries are located or begin on the pages of this Form 10-K report as indicated below.





 



Page No.

Report of Management – Consolidated Financial Statements 

52

Report of Management – Internal Control Over Financial Reporting

52

Report of Independent Registered Public Accounting Firm

53

Report of Independent Registered Public Accounting Firm

54

Consolidated Balance Sheets

55

Consolidated Statements of Operations

56

Consolidated Statements of Comprehensive Income (Loss)

57

Consolidated Statements of Cash Flows

58

Consolidated Statements of Stockholders’ Equity

59

Notes to Consolidated Financial Statements

60

Supplemental Oil and Gas Information (unaudited)

101

Supplemental Quarterly Information (unaudited)

116



2.    Financial Statement Schedules





 

Schedule II – Valuation Accounts and Reserves

117



All other financial statement schedules are omitted because either they are not applicable or the required information is included in the consolidated financial statements or notes thereto.



3.   Exhibits – The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference. Exhibits other than those listed have been omitted since they either are not required or are not applicable.







 

 

Exhibit
No.

 

Incorporated by Reference to the Indicated Filing by
Murphy Oil Corporation

*2.1

Contribution Agreement dated as of October 10, 2018 among Murphy Exploration & Production Company – USA, Petrobras America Inc. and MP Gulf of Mexico, LLC

 

3.1

Certificate of Incorporation of Murphy Oil Corporation, as amended effective May 11, 2005

Exhibit 3.1 to Form 10-K for the year ended December 31, 2010

3.2

By-Laws of Murphy Oil Corporation, as amended effective February 3, 2016

Exhibit 3.2 to Form 8-K filed February 5, 2016

4.1

Indenture dated as of May 4, 1999 between Murphy Oil Corporation and Suntrust Bank, Nashville, N.A., as trustee

Exhibit 4.2 to Form 10-K for the year ended December 31, 2004

4.2

Supplemental Indenture dated as of May 4, 1999 between Murphy Oil Corporation and Suntrust Bank, Nashville, N.A., as trustee, relating to 7.05% Notes due 2029

Exhibit 4.2 to Form 10-K for the year ended December 31, 2004

4.3

Indenture dated as of May 18, 2012 between Murphy Oil Corporation and U.S. Bank National Association, as trustee

Exhibit 4.1 to Form 8-K filed May 18, 2012

4.4

First Supplemental Indenture dated as of May 18, 2012, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 4.00% Notes due 2022

Exhibit 4.2 to Form 8-K filed May 18, 2012

48

 


 

 

4.5

Second Supplemental Indenture dated as of November 30, 2012, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 3.70% Notes due 2022 and 5.125% notes due 2042

Exhibit 4.1 to Form 8-K filed November 30, 2012

4.6

Third Supplemental Indenture dated as of August 17, 2016, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 6.875% Notes due 2024

Exhibit 4.1 to Form 8-K filed August 17, 2016

4.7

Fourth Supplemental Indenture dated as of August 18, 2017, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 5.75% Notes due 2025

Exhibit 4.1 to Form 8-K filed August 18, 2017

10.1

Credit Agreement dated as of August 10, 2016 among Murphy Oil Corporation, Murphy Exploration & Production Company – International, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto 

Exhibit 10.1 to Form 8-K filed August 12, 2016

10.2

Third Amendment dated as of November 17, 2017 to Credit Agreement dated as of August 10, 2016 among Murphy Oil Corporation, Murphy Exploration & Production Company – International and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto

Exhibit 10.1 to Form 8-K filed November 20, 2017

10.3

Fourth Amendment dated as of October 10, 2018 to Credit Agreement dated as of August 10, 2016 among Murphy Oil Corporation, Murphy Exploration & Production Company – International and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto

Exhibit 10.1 to Form 8-K filed October 11, 2018

*10.4

Credit Agreement dated as of November 28, 2018 among Murphy Oil Corporation, Murphy Exploration & Production Company – International, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto

 

10.5

2007 Long-Term Incentive Plan

Exhibit 10.1 of Murphy’s Form 8-K report filed April 24, 2007

10.6

Form of employee stock option (2007 Long-Term Plan)

Exhibits 99.1 and 99.2 of Murphy’s Form 10-Q report filed August 6, 2012

10.7

Murphy Oil Corporation 2012 Long-Term Incentive Plan

Exhibit A to definitive proxy statement filed March 29, 2012

10.8

Form of employee stock option (2012 Long-Term Plan)

Exhibit 99.1 to Form 10-K for the year ended December 31, 2013

10.9

Form of employee performance-based restricted stock unit grant agreement (2012 Long-Term Plan)

Exhibit 99.2 to Form 10-K for the year ended December 31, 2014

10.10

Form of stock appreciation right (2012 Long-Term Plan)

Exhibit 99.3 to Form 10-Q filed May 7, 2014

10.11

Form of employee time-based restricted stock unit grant agreement (2012 Long-Term Plan)

Exhibit 99.1 to Form 10-Q filed May 7, 2014

10.12

Form of employee time-based restricted stock unit-cash grant agreement (2012 Long-Term Plan)

Exhibit 99.2 to Form 10-Q filed May 7, 2014

10.13

Murphy Oil Corporation 2018 Long-Term Incentive Plan

Exhibit B to definitive proxy statement filed March 23, 2018 

*10.14

Form of employee performance-based restricted stock unit – stock settled grant agreement (2018 Long-Term Plan)     

 

*10.15

Form of employee time-based restricted stock unit – stock settled 3-year grant agreement (2018 Long-Term Plan)     

 

*10.16

Form of employee time-based restricted stock unit – stock settled 5-year grant agreement (2018 Long-Term Plan)     

 

49

 


 

 

10.17

Murphy Oil Corporation 2013 Stock Plan for Non-Employee Directors

Exhibit A to definitive proxy statement filed March 22, 2013

10.18

Form of non-employee director restricted stock unit award (2013 NED Plan)

Exhibit 99.2 to Form 10-Q filed November 6, 2013

10.19

Murphy Oil Corporation 2018 Stock Plan for Non-Employee Directors

Exhibit A to definitive proxy statement filed March 23, 2018

*10.20

Form of non-employee director restricted stock unit award – stock settled grant agreement (2018 NED Plan)

 

10.21

Murphy Oil Corporation Non-Qualified Deferred Compensation Plan for Non-Employee Directors

Exhibit 10.6 to Form 10-K for the year ended December 31, 2015

10.22

Tax Matters Agreement dated as of August 30, 2013, between Murphy Oil Corporation and Murphy USA Inc.

Exhibit 10.1 to Form 8-K filed September 5, 2013

10.23

Employee Matters Agreement dated as of August 30, 2013, between Murphy Oil Corporation and Murphy USA Inc.

Exhibit 10.3 to Form 8-K filed September 5, 2013

10.24

Trademark License Agreement dated as of August 30, 2013, between Murphy Oil Corporation and Murphy USA Inc.

Exhibit 10.4 to Form 8-K filed September 5, 2013

*21.1

Subsidiaries of Murphy Oil Corporation

 

*23.1

Consent of Independent Registered Public Accounting Firm

 

*31.1

Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 

*31.2

Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 

*32.1

Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

*99.1

Ryder Scott reserves audit report for Eagle Ford Shale, Gulf of Mexico, and Malaysia

 

*99.2

Ryder Scott reserves audit report for MP GOM JV

 

*99.3

McDaniel independent audit report for Canada Onshore and Offshore proved crude oil and natural gas reserves

 

101.INS

XBRL Instance Document

 

101.SCH

XBRL Taxonomy Extension Schema Document

 

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

 

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

 

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document

 

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

 





50

 


 

 









SIGNATURES



Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



MURPHY OIL CORPORATION





 

 

 

 

 

By

/s/ ROGER W. JENKINS

 

Date:

February 27, 2019

 



Roger W. Jenkins, President

 

 

 

 





Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 27, 2019 by the following persons on behalf of the registrant and in the capacities indicated.





 

 

/s/ CLAIBORNE P. DEMING

 

/s/ R. MADISON MURPHY

Claiborne P. Deming, Chairman and Director

 

R. Madison Murphy, Director



 

 



 

 

/s/ ROGER W. JENKINS

 

/s/ WALENTIN MIROSH

Roger W. Jenkins, President and

 

Walentin Mirosh, Director

Chief Executive Officer and Director

 

 

(Principal Executive Officer)

 

 



 

 



 

 

/s/ T. JAY COLLINS

 

/s/ JEFFREY W. NOLAN

T. Jay Collins, Director

 

Jeffrey W. Nolan, Director



 

 

/s/ STEVEN A. COSSE

 

/s/ NEAL E. SCHMALE

Steven A. Cossé, Director

 

Neal E. Schmale, Director



 

 



 

 

/s/ LAWRENCE R. DICKERSON

 

/s/ LAURA A. SUGG

Lawrence R. Dickerson, Director

 

Laura A. Sugg, Director



 

 



 

 

/s/ ELISABETH W. KELLER

 

/s/ DAVID R. LOONEY

Elisabeth W. Keller, Director

 

David R. Looney, Executive Vice President



 

and Chief Financial Officer



 

(Principal Financial Officer)



 

 

/s/ JAMES V. KELLEY

 

/s/ CHRISTOPHER D. HULSE

James V. Kelley, Director

 

Christopher D. Hulse

Vice President and Controller

(Principal Accounting Officer)



 

 



 

 



 

 



 

 



 

 



 

 



 

 











51

 


 

 

REPORT OF MANAGEMENT – CONSOLIDATED FINANCIAL STATEMENTS

The management of Murphy Oil Corporation is responsible for the preparation and integrity of the accompanying consolidated financial statements and other financial data.  The financial statements were prepared in conformity with U.S. generally accepted accounting principles (GAAP) appropriate in the circumstances and include some amounts based on informed estimates and judgments, with consideration given to materiality.

An independent registered public accounting firm, KPMG LLP, has audited the Company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board and provides an objective, independent opinion about the Company’s consolidated financial statements.  The Audit Committee of the Board of Directors appoints the independent registered public accounting firm; ratification of the appointment is solicited annually from the shareholders.  KPMG LLP’s opinion covering the Company’s consolidated financial statements can be found on page 53.

The Board of Directors appoints an Audit Committee annually to implement and to support the Board’s oversight function of the Company’s financial reporting, accounting policies, internal controls and independent registered public accounting firm.  This Committee is composed solely of directors who are not employees of the Company. The Committee meets routinely with representatives of management, the Company’s audit staff and the independent registered public accounting firm to review and discuss the adequacy and effectiveness of the Company’s internal controls, the quality and clarity of its financial reporting, the scope and results of independent and internal audits, and to fulfill other responsibilities included in the Committee’s Charter.  The independent registered public accounting firm and the Company’s audit staff have unrestricted access to the Committee, without management presence, to discuss audit findings and other financial matters.

REPORT OF MANAGEMENT – INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f).  The Company’s internal controls have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements in accordance with U.S. GAAP.  All internal control systems have inherent limitations, and therefore, can provide only reasonable assurance with respect to the reliability of financial reporting and preparation of consolidated financial statements.

Management has conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013.  Based on the results of this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2018.

Our assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of assets acquired in the MP GOM transaction on November 30, 2018.  The assets acquired represent 15% of total consolidated assets and revenue from the acquired assets represent 2% of total consolidated revenue.  We are in the process of integrating process and internal controls over financial reporting.

KPMG LLP has performed an audit of the Company’s internal control over financial reporting and their opinion thereon can be found on page 54.



52

 


 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors
Murphy Oil Corporation:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and subsidiaries (the Company) as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2018, and the related notes and financial statement Schedule II (collectively, the consolidated financial statements).  In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles. 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control –Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 27, 2019 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.  We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.  Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.



/s/ KPMG LLP



We have served as the Company’s auditor since 1952.



Houston, Texas
February 27,  2019

 

53

 


 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Stockholders and Board of Directors

Murphy Oil Corporation:



Opinion on Internal Control Over Financial Reporting

We have audited Murphy Oil Corporation and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2018, and the related notes and financial statement Schedule II (collectively, the consolidated financial statements), and our report dated February 27, 2019 expressed an unqualified opinion on those consolidated financial statements.

The Company acquired assets in MP Gulf of Mexico, LLC (the Acquired Business) during 2018, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018, the Acquired Business’ internal control over financial reporting associated with total assets of $1.6 billion and total revenues of $56 million included in the consolidated financial statements of the Company as of and for the year ended December 31, 2018. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of the Acquired Business.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Report of Management – Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP
Houston, Texas

February 27, 2019

54

 


 

 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS







 

 

 

 

 

 



 

 

 

 

 

 

December 31 (Thousands of dollars)

 

2018

 

2017



 

 

 

 

 

 

Assets

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

Cash and cash equivalents

 

$

387,373 

 

 

964,988 

Accounts receivable, less allowance for doubtful accounts of $1,605 in 

     2018 and 2017

 

 

331,859 

 

 

243,472 

Inventories

 

 

87,911 

 

 

105,127 

Prepaid expenses

 

 

51,724 

 

 

35,087 

Assets held for sale

 

 

20,947 

 

 

22,929 

Total current assets

 

 

879,814 

 

 

1,371,603 

Property, plant and equipment, at cost less accumulated depreciation,

     depletion and amortization of $13,065,751 in 2018 and $12,280,741 in 2017

 

 

9,757,564 

 

 

8,220,031 

Deferred income taxes

 

 

359,644 

 

 

211,543 

Deferred charges and other assets

 

 

55,565 

 

 

57,765 

Total assets

 

$

11,052,587 

 

 

9,860,942 

Liabilities and Stockholders' Equity

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

Current maturities of long-term debt

 

$

10,583 

 

 

9,902 

Accounts payable

 

 

596,071 

 

 

595,916 

Income taxes payable

 

 

31,605 

 

 

44,604 

Other taxes payable

 

 

19,387 

 

 

23,574 

Other accrued liabilities

 

 

185,648 

 

 

156,681 

Liabilities associated with assets held for sale

 

 

2,764 

 

 

3,530 

Total current liabilities

 

 

846,058 

 

 

834,207 

Long-term debt, including capital lease obligation

 

 

3,227,134 

 

 

2,906,520 

Deferred income taxes

 

 

129,894 

 

 

159,098 

Asset retirement obligations

 

 

1,027,423 

 

 

709,299 

Deferred credits and other liabilities

 

 

624,436 

 

 

631,627 

Equity

 

 

 

 

 

 

    Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued        

 

 

– 

 

 

– 

    Common Stock, par $1.00, authorized 450,000,000 shares, issued
          195,076,924 shares in 2018 and 195,055,724 in 2017

 

 

195,077 

 

 

195,056 

    Capital in excess of par value

 

 

979,642 

 

 

917,665 

    Retained earnings

 

 

5,513,529 

 

 

5,245,242 

    Accumulated other comprehensive loss

 

 

(609,787)

 

 

(462,243)

    Treasury stock

 

 

(1,249,162)

 

 

(1,275,529)

Murphy Shareholders' Equity

 

 

4,829,299 

 

 

4,620,191 

    Noncontrolling interest

 

 

368,343 

 

 

– 

Total  equity

 

 

5,197,642 

 

 

4,620,191 

Total liabilities and stockholders’ equity

 

$

11,052,587 

 

 

9,860,942 



See Notes to Consolidated Financial Statements, page  60.



55

 


 

 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS





 

 

 

 

 

 



 

 

 

 

 

 

Years Ended December 31 (Thousands of dollars except per share amounts)

2018

 

2017  1

 

2016 1

Revenues

 

 

 

 

 

 

Revenue from sales to customers

$

2,586,627 

 

2,078,548 

 

1,862,891 

(Loss) gain on crude contracts

 

(41,975)

 

9,566 

 

(63,412)

Gain on sale of assets and other income

 

25,951 

 

137,015 

 

11,759 

 Total revenues

 

2,570,603 

 

2,225,129 

 

1,811,238 



 

 

 

 

 

 

Costs and Expenses

 

 

 

 

 

 

Lease operating expenses

 

555,894 

 

468,323 

 

559,360 

Severance and ad valorem taxes

 

52,072 

 

43,618 

 

43,826 

Exploration expenses, including undeveloped
   lease amortization

 

103,977 

 

122,834 

 

101,861 

Selling and general expenses

 

216,024 

 

203,573 

 

246,277 

Depreciation, depletion and amortization

 

971,901 

 

957,719 

 

1,054,081 

Impairment of assets

 

20,000 

 

– 

 

95,088 

Redetermination expense

 

11,332 

 

15,000 

 

39,100 

Accretion of asset retirement obligations

 

44,559 

 

42,590 

 

46,742 

Other (income) expense

 

(34,873)

 

30,706 

 

13,806 

Total costs and expenses

 

1,940,886 

 

1,884,363 

 

2,200,141 



 

 

 

 

 

 

Operating income (loss) from continuing operations

 

629,717 

 

340,766 

 

(388,903)



 

 

 

 

 

 

Other income (loss)

 

 

 

 

 

 

Interest and other income (loss)

 

(15,775)

 

(87,181)

 

43,958 

Interest expense, net

 

(181,604)

 

(181,783)

 

(148,170)

Total other loss

 

(197,379)

 

(268,964)

 

(104,212)



 

 

 

 

 

 

Income (loss) from continuing operations before income taxes

 

432,338 

 

71,802 

 

(493,115)

Income tax expense (benefit)

 

9,330 

 

382,738 

 

(219,172)

Income (loss) from continuing operations

 

423,008 

 

(310,936)

 

(273,943)

Loss from discontinued operations, net of income taxes

 

(3,522)

 

(853)

 

(2,027)



 

 

 

 

 

 

Net income (loss) including noncontrolling interest

 

419,486 

 

(311,789)

 

(275,970)

Less: Net income attributable to noncontrolling interest

 

8,392 

 

– 

 

– 

NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY

$

411,094 

 

(311,789)

 

(275,970)



 

 

 

 

 

 

INCOME (LOSS) PER COMMON SHARE – BASIC

 

 

 

 

 

 

Continuing operations

$

2.39 

 

(1.81)

 

(1.59)

Discontinued operations

 

(0.01)

 

– 

 

(0.01)

Net income (loss)

$

2.38 

 

(1.81)

 

(1.60)



 

 

 

 

 

 

INCOME (LOSS) PER COMMON SHARE – DILUTED

 

 

 

 

 

 

Continuing operations

$

2.37 

 

(1.81)

 

(1.59)

Discontinued operations

 

(0.01)

 

– 

 

(0.01)

Net income (loss)

$

2.36 

 

(1.81)

 

(1.60)



 

 

 

 

 

 

Cash dividends per Common share

 

1.00 

 

1.00 

 

1.20 



 

 

 

 

 

 

Average Common shares outstanding (thousands)

 

 

 

 

 

 

Basic

 

172,974 

 

172,524 

 

172,173 

Diluted

 

174,209 

 

172,524 

 

172,173 



See Notes to Consolidated Financial Statements, page  60.

1 Reclassified to conform to current presentation (see Note B). 

56

 


 

 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)







 

 

 

 

 

 



 

 

 

 

 

 

Years Ended December 31 (Thousands of dollars)

2018

 

2017

 

2016



 

 

 

 

 

 

Net income (loss) including noncontrolling interest

$

419,486 

 

(311,789)

 

(275,970)

Other comprehensive income (loss), net of tax

 

 

 

 

 

 

Net gain (loss) from foreign currency translation

 

(145,022)

 

171,725 

 

66,449 

Retirement and postretirement benefit plans

 

29,110 

 

(7,682)

 

7,955 

Deferred loss on interest rate hedges reclassified to
     interest expense.

 

2,342 

 

1,926 

 

1,926 

Reclassification of certain tax effects to retained earnings

 

(30,237)

 

– 

 

– 

Other

 

(3,737)

 

– 

 

– 

Other comprehensive income (loss)

 

(147,544)

 

165,969 

 

76,330 

COMPREHENSIVE INCOME (LOSS)

$

271,942 

 

(145,820)

 

(199,640)



See Notes to Consolidated Financial Statements, page 60.



57

 


 

 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS









 

 

 

 

 

 



 

 

 

 

 

 

Years Ended December 31 (Thousands of dollars)

2018

 

2017

 

2016

Operating Activities

 

 

 

 

 

 

Net income (loss) including noncontrolling interest

$

419,486 

 

(311,789)

 

(275,970)

Adjustments to reconcile net loss to net cash provided by
  continuing operations activities:

 

 

 

 

 

 

Loss from discontinued operations

 

3,522 

 

853 

 

2,027 

Depreciation, depletion and amortization

 

971,901 

 

957,719 

 

1,054,081 

Impairment of assets

 

20,000 

 

– 

 

95,088 

Amortization of deferred major repair costs

 

– 

 

– 

 

3,794 

Dry hole costs (credits)

 

20,624 

 

(4,163)

 

15,047 

Amortization of undeveloped leases

 

40,177 

 

61,776 

 

43,417 

Accretion of asset retirement obligations

 

44,559 

 

42,590 

 

46,742 

Deferred income tax expense (benefit)

 

(183,680)

 

260,420 

 

(387,843)

Pretax gains from disposition of assets

 

(54)

 

(127,434)

 

(1,663)

Net (increase) decrease in noncash operating working capital

 

(169,808)

 

136,414 

 

(38,689)

Other operating activities, net

 

52,669 

 

111,689 

 

44,764 

Net cash provided by continuing operations activities

 

1,219,396 

 

1,128,075 

 

600,795 

Investing Activities

 

 

 

 

 

 

Acquisition of oil properties

 

(794,623)

 

– 

 

– 

Property additions and dry hole costs

 

(1,102,805)

 

(1,009,667)

 

(926,948)

Proceeds from sales of property, plant and equipment

 

1,383 

 

69,506 

 

1,155,144 

Purchase of investment securities 1

 

– 

 

(212,661)

 

(695,879)

Proceeds from maturity of investment securities 1

 

– 

 

320,828 

 

761,000 

Other investing activities, net

 

– 

 

– 

 

(7,230)

Net cash provided (required) by investing activities

 

(1,896,045)

 

(831,994)

 

286,087 

Financing Activities

 

 

 

 

 

 

Borrowings of debt

 

325,000 

 

541,597 

 

541,444 

Repayments of debt

 

– 

 

(550,000)

 

(600,000)

Capital lease obligation payments

 

(9,750)

 

(17,133)

 

(10,447)

Issue cost of debt facility

 

(6,366)

 

– 

 

(14,085)

Cash dividends paid

 

(173,044)

 

(172,565)

 

(206,635)

Other financing activities, net

 

(8,076)

 

(7,116)

 

(1,158)

Net cash required by financing activities

 

127,764 

 

(205,217)

 

(290,881)

Effect of exchange rate changes on cash and cash equivalents

 

(28,730)

 

1,327 

 

(6,387)

Net increase (decrease) in cash and cash equivalents

 

(577,615)

 

92,191 

 

589,614 

Cash and cash equivalents at beginning of period

 

964,988 

 

872,797 

 

283,183 

Cash and cash equivalents at end of period

$

387,373 

 

964,988 

 

872,797 



1 Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.



See Notes to Consolidated Financial Statements, page 60.

58

 


 

 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY









 

 

 

 

 

 



 

 

 

 

 

 

Years Ended December 31 (Thousands of dollars)

2018

 

2017

 

2016

Cumulative Preferred Stock – par $100, authorized
   400,000 shares, none issued

$

– 

 

– 

 

– 

Common Stock – par $1.00, authorized 450,000,000 shares at
   December 31, 2018, 2017 and 2016, issued 195,076,924 shares
   at December 31, 2018 and 195,055,724 at December 31, 2017 and 2016.

 

 

 

 

 

 

Balance at beginning of year

 

195,056 

 

195,056 

 

195,056 

Exercise of stock options

 

21 

 

– 

 

– 

       Balance at end of period

 

195,077 

 

195,056 

 

195,056 

Capital in Excess of Par Value

 

 

 

 

 

 

Balance at beginning of year

 

917,665 

 

916,799 

 

910,074 

Exercise of stock options, including income tax benefits

 

(362)

 

– 

 

(12,017)

Restricted stock transactions and other

 

(33,920)

 

(26,553)

 

(10,078)

Stock-based compensation

 

27,920 

 

27,496 

 

29,119 

Fair value increase in common controlled assets

 

68,339 

 

– 

 

– 

Other

 

– 

 

(77)

 

(299)

      Balance at end of period

 

979,642 

 

917,665 

 

916,799 

Retained Earnings

 

 

 

 

 

 

Balance at beginning of year

 

5,245,242 

 

5,729,596 

 

6,212,201 

Net income (loss) for the year attributable to Murphy

 

411,094 

 

(311,789)

 

(275,970)

Reclassification of certain tax effects from accumulated other comprehensive loss

 

30,237 

 

– 

 

– 

Cash dividends

 

(173,044)

 

(172,565)

 

(206,635)

      Balance at end of period

 

5,513,529 

 

5,245,242 

 

5,729,596 

Accumulated Other Comprehensive Loss

 

 

 

 

 

 

Balance at beginning of year

 

(462,243)

 

(628,212)

 

(704,542)

Foreign currency translation gains (losses), net of income taxes

 

(145,022)

 

171,725 

 

66,449 

Retirement and postretirement benefit plans, net of income taxes

 

29,110 

 

(7,682)

 

7,955 

Deferred loss on interest rate hedge reclassified to interest expense,
    net of income taxes

 

2,342 

 

1,926 

 

1,926 

Reclassification of certain tax effects to retained earnings

 

(30,237)

 

– 

 

– 

Other

 

(3,737)

 

– 

 

– 

      Balance at end of year

 

(609,787)

 

(462,243)

 

(628,212)

Treasury Stock

 

 

 

 

 

 

Balance at beginning of year

 

(1,275,529)

 

(1,296,560)

 

(1,306,061)

Sale of stock under employee stock purchase plans

 

– 

 

146 

 

509 

Awarded restricted stock

 

26,367 

 

20,885 

 

8,992 

    Balance at end of year – 22,018,095 shares of Common Stock in 2018,
       22,482,851 shares of Common Stock in 2017,
       and 22,853,547 shares of Common Stock in 2016

 

(1,249,162)

 

(1,275,529)

 

(1,296,560)

Murphy Shareholders' Equity

 

4,829,299 

 

4,620,191 

 

4,916,679 

Noncontrolling Interest

 

 

 

 

 

 

Balance at beginning of year

 

– 

 

– 

 

– 

Acquisition

 

359,951 

 

– 

 

– 

Net income attributable to noncontrolling interest

 

8,392 

 

– 

 

– 

Distributions to noncontrolling Interest Owners

 

 

– 

 

– 

      Balance at end of year

 

368,343 

 

– 

 

– 

Total Equity

$

5,197,642 

 

4,620,191 

 

4,916,679 















See Notes to Consolidated Financial Statements, page 60.

59

 


 

 

 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 55-59 of the Form 10-K report.



Note A – Significant Accounting Policies



NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries.  The Company primarily produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide.  The Company sold its interest in a Canadian synthetic oil operation in 2016 and its Canadian heavy oil assets in early 2017.  See Notes E and G for more information regarding the sale of these assets.



PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries.  Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis.  Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method.  Beginning in the fourth quarter of 2018, Murphy reports 100% of the sales volume, revenues, costs, assets and liabilities including the 20% noncontrolling interest (NCI), of the new Gulf of Mexico transaction (MP GOM) with Petrobras Americas Inc (PAI), in accordance with accounting for noncontrolling interest as prescribed by ASC 810-10-45 (see Note D). Other investments are generally carried at cost.  All significant intercompany accounts and transactions have been eliminated.



Beginning in 2017, certain reclassifications in presentation have been made to the Consolidated Statements of Operations.  The Company now presents a separate “Operating income (loss) from continuing operations” subtotal on the Consolidated Statements of Operations.  Additionally, “Interest and other income (loss),” which includes foreign exchange gains and losses, has been reclassified from a component of total revenues and is now presented below Operating income (loss) from continuing operations.  “Interest expense” and “Capitalized interest” have also been combined into the “Interest expense, net” line item and are now presented below “Operating income (loss) from continuing operations.”  Previously reported periods have been reclassified to conform to the current period presentation.  These reclassifications did not impact previously reported Income (loss) from continuing operations before income taxes, Loss from continuing operations, or Net Loss.



REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities.  The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties.  Revenues from the production of oil and natural gas properties in which Murphy shares in the undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period.  Revenue is presented as the Company’s share net of certain costs associated with generation of Revenue. Examples of costs that reduce revenue include transportation, gathering, compression, and processing fees in U.S. and Canada, as well as certain required payments associated with production sharing contracts (PSCs) and export taxes in Malaysia.  Natural gas imbalances occur when the Company’s actual gas sales volumes differ from its proportional share of production from the well.  The company follows the sales method of accounting for these natural gas imbalances.  The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field.  At December 31, 2018 and 2017, the liabilities for natural gas balancing were immaterial.  Gains and losses on asset disposals or retirements are included in net income/(loss) as a component of revenues.  See Note B for further discussion on revenue recognition.



CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that are highly liquid and have a maturity of three months or less from the date of purchase are classified as cash equivalents.



60


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note A – Significant Accounting Policies (Contd.)

MARKETABLE SECURITIES – The Company classifies investments in marketable securities as available-for-sale or held-to-maturity.  The Company does not have any investments classified as trading securities.  Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive loss.  Held-to-maturity securities are recorded at amortized cost.  Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security.  Dividend and interest income is recognized when earned.  Unrealized losses considered to be other than temporary are recognized in earnings.  The cost of securities sold is based on the specific identification method.  The fair value of investment securities is determined by available market prices

ACCOUNTS RECEIVABLE – At December 31, 2018 and 2017, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas.  The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables.  The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers and historical write-off experience.  Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts.  The Company has not experienced any significant credit-related losses in the past three years.

INVENTORIES – Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and gas production operations.  Unsold crude oil production is carried in inventory at the lower of cost, generally applied on a first-in, first-out (FIFO) basis, or market, and includes costs incurred to bring the inventory to its existing condition.  Materials and supplies inventories are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment.

PROPERTY, PLANT AND EQUIPMENT – The Company uses the successful efforts method to account for exploration and development expenditures.  Leasehold acquisition costs are capitalized.  If proved reserves are found on undeveloped property, the leasehold cost is transferred to proved properties.  Costs of undeveloped leases associated with unproved properties are expensed over the life of the leases.  Exploratory well costs are capitalized pending determination about whether proved reserves have been found.  In certain cases, a determination of whether a drilled exploratory well has found proved reserves cannot be made immediately.  This is generally due to the need for major capital expenditure to produce and/or evacuate the hydrocarbon(s) found.  The determination of whether to make such capital expenditure is usually dependent on whether further exploratory or appraisal wells find a sufficient quantity of additional reserves.  The Company continues to capitalize exploratory well costs in Property, Plant and Equipment when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.  The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization.  Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred.  Development costs, including unsuccessful development wells, are capitalized.  Interest is capitalized on significant development projects that are expected to take one year or more to complete.



Oil and gas properties are evaluated by field for potential impairment.  Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable.  An impairment is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value.  If an impairment occurs, the carrying value of the impaired asset is reduced to fair value. As a result of management’s assessments during 2018, the Company recognized a pretax, noncash impairment charge of $20.0 million at select Midland properties.  There were no impairments recorded during 2017. In 2016, charges of $95.1 million at its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties were reported.  See also Note G for further discussion of impairment charges. 



The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset.  The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled or the asset is placed in service.  The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates.  When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability.  The liability is increased over time to reflect the change in its present value, and the capitalized cost is depreciated over the useful life of the related long-lived asset.  The Company reevaluates the adequacy of its recorded ARO liability at least annually.  Actual costs of asset retirements such as dismantling oil and gas production facilities and site restoration are charged against the related liability. 



61

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note A – Significant Accounting Policies (Contd.)

Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings.



Depreciation and depletion of producing oil and gas properties are recorded based on units of production.  Unit rates are computed for unamortized development drilling and completion costs using proved developed reserves and acquisition costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on the availability of additional information.  Additionally, certain natural gas processing facilities and related equipment in Malaysia are being depreciated on a straight-line basis over their estimated useful life ranging from 20 to 25 years.



Capitalized Interest – Interest associated with borrowings from third parties is capitalized on significant oil and gas development projects when the expected development period extends for one year or more.  Interest capitalized is credited in the Consolidated Statements of Operations and is added to the cost of the underlying asset for the development project in Property, plant and equipment in the Consolidated Balance Sheets.  Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs.



ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists and the cost can be reasonably estimated.  If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Related expenditures are charged against the liability.  Environmental remediation liabilities have not been discounted for the time value of future expected payments.  Environmental expenditures that have future economic benefit are capitalized.

INCOME TAXES – The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities.  Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse.  The Company routinely assesses the realizability of deferred tax assets based on available evidence including assumptions of future taxable income, tax planning strategies and other pertinent factors.  A deferred tax asset valuation allowance is recorded when evidence indicates that it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period.  

Prior to 2017, the Company did not provide U.S. deferred taxes for undistributed earnings of certain foreign subsidiaries when these earnings were considered indefinitely invested.  On December 22, 2017 the Tax Cuts and Jobs Act (2017 Tax Act) was enacted which triggered the transitional tax on a deemed repatriation of all past foreign earnings (see Note J) and a provision for this impact has been recorded.  Also, deferred tax liabilities are recorded for relevant withholding taxes when undistributed earnings of foreign subsidiaries are not considered indefinitely invested.  Under present law, the Company would incur a 5% withholding tax on any earnings repatriated from Canada to the U.S. 

The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized, and then only for the largest amount that is greater than 50% likely of being realized.  The Company includes potential penalties and interest for uncertain income tax positions in income tax expense.

FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and former refining and marketing activities in the United Kingdom.  The U.S. dollar is the functional currency used to record all other operations.  Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings.  Gains or losses from translating foreign functional currencies into U.S. dollars are included in Accumulated Other Comprehensive Loss in Consolidated Statements of Stockholders’ Equity.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheets.  Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings.  The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for the use of the hedging instrument to manage the risk.  Derivative instruments designated as fair value or cash flow hedges are linked to

62

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note A – Significant Accounting Policies (Contd.)

specific assets and liabilities or to specific firm commitments or forecasted transactions.  The Company assesses at inception and on an ongoing basis whether a derivative instrument accounted for as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item.  A derivative that is not a highly effective hedge does not qualify for hedge accounting.  The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item.  The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in Accumulated other comprehensive loss in the Consolidated Balance Sheets until the hedged item is recognized currently in earnings.  If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued and the gain or loss recorded in Accumulated other comprehensive loss is recognized immediately in earnings.

Fair Value Measurements – The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets.  Fair value is determined using various techniques depending on the availability of observable inputs.  Level 1 inputs include quoted prices in active markets for identical assets or liabilities.  Level 2 inputs include observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants. See Note Q.



STOCK-BASED COMPENSATION

Equity-Settled Awards – The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock.  The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options.  The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock price.  The Company uses both historical data and current information to support its assumptions.  Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years.  The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units that are equity settled and expense is recognized over the three-year vesting period.  The fair value of time-lapse restricted stock units is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period.  The Company estimates the number of stock options and performance-based restricted stock units that will not vest and adjusts its compensation expense accordingly.  Differences between estimated and actual vested amounts are accounted for as an adjustment to expense when known.



Cash-Settled Awards – The Company accounts for stock appreciation rights (SAR), cash-settled restricted stock units (CRSU) and phantom stock units as liability awards.  Expense associated with these awards are recognized over the vesting period based on the latest available estimate of the fair value of the awards, which is generally determined using a Black-Scholes method for SAR, a Monte Carlo method for performance-based CRSU, and the period-end price of the Company’s common stock for time-based CRSU and phantom units.  When SAR are exercised and when CRSU and phantom units settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards. See Note K.



PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS – The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets.  Changes in the funded status which have not yet been recognized in the Consolidated Statement of Operations are recorded net of tax in Accumulated other comprehensive loss.  The remaining amounts in Accumulated other comprehensive loss include net actuarial losses and prior service (cost) credit. See Note L.



NET INCOME (LOSS) PER COMMON SHARE – Basic income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period.  Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares.  Dilutive securities are not included in the computation of diluted income (loss) per share when a net loss occurs as the inclusion would have the effect of reducing the diluted loss per share.



USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles (GAAP), management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

63

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note B – New Accounting Principles and Recent Accounting Pronouncements



Accounting Principles Adopted



Revenue from Contracts with Customers.  In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, which established a comprehensive model of accounting for revenue arising from contracts with customers that superseded most revenue recognition requirements and industry-specific guidance.  Under the new standard, the Company recognizes revenue when it transfers control of the commodity to customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for the commodity.  Additional disclosures are required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers.  The Company adopted the new standard in the first quarter of 2018 using the modified retrospective method.  The Company performed a review of contracts in each of its revenue streams and implemented accounting policies and internal controls to address the requirements of the ASU.  Prior to January 1, 2018, the Company followed the sales method of revenue recognition under Accounting Standards Codification (ASC) Topic 605 and recorded revenue when deliveries occurred, and legal ownership of the commodity transferred to the customer.

There was no adjustment to the opening balance of stockholders’ equity as at January 1, 2018, resulting from the application of the new ASU promulgated in ASC Topic 606 using the modified retrospective method.  The comparative information has not been adjusted and continues to be reported under ASC Topic 605 – Revenue Recognition.  See also Note C for further discussion of Revenue Recognition. 

Statement of Cash Flows.  In August 2016, the FASB issued ASU 2016-15 to reduce diversity in practice in how certain transactions are classified in the statement of cash flows.  The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees.  The amendments in this ASU were effective for annual and interim periods beginning after December 15, 2017.  The Company adopted this guidance in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements.

Compensation – Retirement Benefits.  In March 2017, the FASB issued ASU 2017-07 requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component outside a subtotal of income from operations, if presented.  The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization.  The update is effective for annual and interim periods beginning after December 15, 2017.  The Company elected to apply the practical expedient, which allows us to reclassify amounts disclosed previously in the retirement benefits note as the basis for applying retrospective presentation for comparative periods.  The Company adopted the standard in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements.

Compensation – Stock Compensation.  In May 2017, the FASB issued ASU 2017-09 which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting.  The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period.  The Company adopted this accounting standard in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements.

Statement of Operations – Reporting Comprehensive Income.  In February 2018, the FASB issued ASU 2018-02, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act.  The Company elected to early adopt this accounting standard during the first quarter of 2018 and recorded discrete adjustments from accumulated other comprehensive income to retained earnings of $28.4 million related to retirement and postretirement obligations and $1.8 million related to the deferred loss on interest rate derivative hedges.  The adoption of this ASU will have no future impact.













64

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note B – New Accounting Principles and Recent Accounting Pronouncements (Contd).



Accounting Principles Adopted (Contd).



In August 2018, the U.S. Securities and Exchange Commission (SEC) adopted the final rule under SEC Release No. 33-10532 Disclosure Update and Simplification, to eliminate or modify certain disclosure rules that are redundant, outdated, or duplicative of U.S. GAAP or other regulatory requirements. Among other changes, the amendments eliminated the annual requirement to disclose the high and low trading prices of our common stock and the ratio of earnings to fixed charges. In addition, the amendments provide that disclosure requirements related to the analysis of shareholders' equity are expanded for interim financial statements. An analysis of the changes in each caption of shareholders' equity presented in the balance sheet must be provided in a note or separate statement, as well as the amount of dividends per share for each class of shares. This rule was effective on November 5, 2018; and the expanded interim disclosure requirements for changes in shareholders' equity will be effective for the Company for our quarterly reporting beginning March 31, 2019.



Recent Accounting Pronouncements



Leases.  In February 2016, the FASB established Topic 842 (the new standard) by issuing ASU 2016-02 to increase transparency and comparability among companies.  The new standard requires lease benefits and corresponding lease liabilities to be recorded on the balance sheet and requires disclosing key information about leasing arrangements.  The main difference between previous Generally Accepted Accounting Principles (GAAP) and the requirements of the new standard, is the recognition of right-of-use (ROU) assets and lease liabilities for certain leases.  Entities will now be required to recognize operating leases alongside finance leases (formerly referred to as capital leases), with the distinction affecting the classification of expense recognition.  The new standard also calls for disclosures regarding leasing arrangements and costs, to provide a more comprehensive insight into an entity’s leasing activities. 



The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods.  Early adoption is permitted for all entities.  The Company adopted this guidance in the first quarter of 2019 effective as of January 1, 2019.  A modified retrospective transition approach is required upon adoption, with the new standard being applied to all leases at the date of initial application.  We expect to take certain practical expedients that allow our initial date of application to coincide with the effective date, such that the new standard is applied prospectively on January 1, 2019 (relief option). Therefore, financial information and disclosures related to prior periods will neither be updated nor recast and will not reflect the new requirements.



Further, the new standard also provides other practical expedients that an entity may elect, at its option, to facilitate a more efficient transition.  We expect to elect the main ‘package of practical expedients,’ allowing entities not to reassess lease conclusions made under previous GAAP (primarily related to lease identification and classification). We currently expect to elect the short-term lease recognition exemption for all leases that qualify.



We expect the new standard will have a material effect on our financial statements.  Reviews indicate the impact will be generated primarily from ROU assets and lease liabilities related to an operating lease of a gas processing plant and floating, platform, storage, and off-take vessels.  As required by the standard, previously deferred gains related to a sale-leaseback transaction will be transferred to equity upon transition, lowering liabilities but increasing retained earnings by approximately $160 million (see Note G).  For all asset classes, preliminary estimates suggest operating leases could add approximately $800 million, representing the present value of remaining minimum lease payments.  These estimates are provisional.  Additional changes may arise due to the finalization of policies and elections made to the volume of leases recognized and revisions made to anticipated lease terms.  We do not expect the standard to have an impact on our underlying liquidity or our debt-covenant compliance under our existing agreements.





65

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note B – New Accounting Principles and Recent Accounting Pronouncements (Contd.)



Recent Accounting Pronouncements (Contd.)

Compensation – Stock Compensation.  In June 2018, the FASB issued ASU 2018-07 which supersedes existing guidance for equity-based payments to nonemployees and expands the scope of guidance for stock compensation to include all share-based payment arrangements related to the acquisition of goods and services from both nonemployees and employees.  As a result, the same guidance that provides for employee share-based payments, including most of its requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. The ASU is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods.  Early adoption is permitted.  The Company adopted this guidance for the first quarter of 2019 and it is not expected to have a material impact on its consolidated financial statements.

Fair Value Measurement.  In August 2018, the FASB issued ASU 2018-13 which modifies disclosure requirements related to fair value measurement.  The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019.  Implementation on a prospective or retrospective basis varies by specific disclosure requirement.  Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.

Compensation-Retirement Benefits-Defined Benefit Plans-General.  In August 2018, the FASB issued ASU 2018-14 that modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans.  For public companies, the amendments in this ASU are effective for fiscal years beginning after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.



Note C – Revenue from Contracts with Customers

Nature of Goods and Services

The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and gas) in select basins around the globe. The Company’s revenue from sales of oil and gas production activities are primarily subdivided into three key geographic segments: the U.S., Canada, and Malaysia.  Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.

For operated oil and gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest in MP GOM as prescribed by ASC 810-10-45.

U.S.- In the United States, the Company primarily produces oil and gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico.  Revenue is generally recognized when oil and gas are transferred to the customer at the delivery point and is net of transportation costs. Revenue recognized is largely index based with price adjustments for floating market differentials.

Canada- Primarily all long-term contracts in Canada, except for certain natural gas physical forward sales fixed-price contracts, are floating commodity index priced. For the Onshore business in Canada, the recorded revenue is net of transportation and any gain or loss on spot purchases made to meet committed volumes on sales contracts for the month. For the Offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer.

Malaysia- In Malaysia, the Company has interests in seven separate PSCs. The Company serves as the operator of all these areas except for the unitized Gumusut-Kakap field. Crude oil contracts in Malaysia share similar features of largely fixed cargo quantities and variable index-based pricing, and revenue is typically recognized as the same time of vessel load.  Malaysia also has three long term Gas Sales Agreements (GSA) with terms until the end of the field life, economic life, or PSC term.

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note C – Revenue from Contracts with Customers (Contd.)

Disaggregation of Revenue

The Company reviews performance based on three key geographical segments and between onshore and offshore sources of Revenue within these geographies.

For the years ended December 31, 2018, 2017, and 2016 the Company recognized $2.6 billion, $2.1 billion, and 1.9 billion, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. 





 

 

 

 

 

 



 

For the Year Ended



 

December 31,

(Thousands of dollars)

 

2018

 

2017

 

2016

Net crude oil and condensate revenue

 

 

 

 

 

 

United States – Onshore

$

778,198 

 

644,023 

 

508,045 

– Offshore 1

 

403,523 

 

208,984 

 

172,022 

Canada    – Onshore

 

105,651 

 

51,013 

 

92,605 

– Offshore

 

170,895 

 

147,230 

 

138,425 

Malaysia – Sarawak

 

282,370 

 

241,774 

 

209,751 

– Block K

 

406,653 

 

378,401 

 

403,912 

Other

 

6,079 

 

– 

 

– 

Total crude oil and condensate revenue

 

2,153,369 

 

1,671,425 

 

1,524,760 



 

 

 

 

 

 

Net natural gas liquids revenue

 

 

 

 

 

 

United States – Onshore

 

53,335 

 

43,804 

 

28,316 

– Offshore 1

 

10,269 

 

6,894 

 

5,781 

Canada    – Onshore

 

14,657 

 

5,450 

 

1,351 

Malaysia – Sarawak

 

19,798 

 

19,733 

 

10,001 

Total natural gas liquids revenue

 

98,059 

 

75,881 

 

45,449 



 

 

 

 

 

 

Net natural gas revenue

 

 

 

 

 

 

United States – Onshore

 

28,335 

 

27,460 

 

24,281 

– Offshore 1

 

14,525 

 

10,480 

 

10,839 

Canada    – Onshore

 

147,613 

 

155,125 

 

129,968 

Malaysia – Sarawak

 

144,222 

 

137,479 

 

126,975 

– Block K

 

504 

 

698 

 

619 

Total natural gas revenue

 

335,199 

 

331,242 

 

292,682 

Total revenue from contracts with customers

 

2,586,627 

 

2,078,548 

 

1,862,891 



 

 

 

 

 

 

Gain (loss) on crude contracts

 

(41,975)

 

9,566 

 

(63,412)

Other operating income

 

25,897 

 

9,581 

 

10,096 

Gain on sale of assets

 

54 

 

127,434 

 

1,663 

Total revenue

$

2,570,603 

 

2,225,129 

 

1,811,238 

1 2018 includes revenue attributable to noncontrolling interest in MP GOM, effective November 30, 2018.

Contract Balances and Asset Recognition

As of December 31, 2018, and December 31, 2017, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet, were $263.0 million and $203.4 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on historical collections and ability of customers to pay, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.



67

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note C – Revenue from Contracts with Customers (Contd.)

The Company has not entered into any upstream oil and gas sale contracts that have financing components as of December 31, 2018.

The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.



Performance Obligations

The Company recognizes oil and gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer and considers each unit of measure, of the specified commodity, to represent a distinct performance obligation.  The pricing for the Company’s sales contracts is typically market or index-based based. The Company has elected the direct allocation exception and therefore the variable consideration is allocated to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied performance obligations for delivery of a commodity in subsequent periods.

The Company has applied the exemption to not report any unsatisfied performance obligation related to contracts with terms of less than one year. 

As at December 31, 2018, the Company had the following sales contracts in place with terms greater than one year:
 











 

 

 

 

 

 

 

 

Current Long-Term Contracts Outstanding at December 31, 2018

Location

 

Commodity

 

End Date

 

Description

 

Approximate Volumes

U.S.

 

Oil

 

Q3 2019

 

Fixed quantity delivery in Eagle Ford

 

4,000 BOED

U.S.

 

Oil

 

Q4 2021

 

Fixed quantity delivery in Eagle Ford

 

17,000 BOED

U.S.

 

Gas and NGL

 

Q2 2026

 

Deliveries from dedicated acreage in
   Eagle Ford

 

As produced

Canada

 

Gas

 

Q4 2020

 

Contracts to sell natural gas
at Alberta AECO fixed prices

 

59 MMCFD

Canada

 

Gas

 

Q4 2020

 

Contracts to sell natural gas at USD Index
pricing

 

60 MMCFD

Canada

 

Gas

 

Q4 2024

 

Contracts to sell natural gas at USD Index
pricing

 

30 MMCFD

Canada

 

Gas

 

Q4 2026

 

Contracts to sell natural gas at USD Index
pricing

 

38 MMCFD







68

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note D – Acquisition

In December 2018, the Company announced the completion of a transaction with Petrobras Americas Inc. (PAI) which became effective October 1, 2018.  Through this transaction, Murphy acquired all PAI’s producing Gulf of Mexico assets along with certain blocks that hold deep exploration rights.  This transaction added production of approximately 50,000 BOED (including noncontrolling interest, NCI) along with approximately 97 MMBOE (including NCI) of proven reserves at December 31, 2018. See Supplemental Oil and Gas Information (Unaudited), below for discussion of proved reserves acquired.

Under the terms of the transaction, Murphy paid cash consideration of $794.6 million and transferred a 20% interest in MP Gulf of Mexico, LLC (MP GOM), a subsidiary of Murphy, to PAI.  Murphy could also owe additional contingent consideration up to $150 million if certain sales thresholds are exceeded beginning in 2019 through 2025.  Both companies contributed all of their current producing Gulf of Mexico assets into MP GOM.  Following closing of the transaction, MP GOM is owned 80% by Murphy and 20% by PAI, with Murphy overseeing the operations. 

The following tables contain the preliminary purchase price allocation at fair value:



 

 

(Thousands of dollars)

 

 

Cash consideration paid to PAI

$

794,623 

Fair value of net assets contributed

 

166,797 

Fair value of contingent consideration

 

52,540 

Noncontrolling interest in acquired assets

 

253,490 

Total purchase consideration

$

1,267,450 





 

 

(Thousands of dollars)

 

 

Fair value of Property, Plant, and Equipment

$

1,617,052 

Other assets

 

10,041 

Less:  Asset retirement obligations

 

(359,643)

Total net assets

$

1,267,450 


The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved, probable, and possible reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average discount rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change.

Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, analysis of the underlying tax basis of the PAI assets acquired and liabilities assumed and the final purchase price adjustments to be settled in 2019. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate. 

Results of Operations

The results of operations attributable to the acquired PAI assets are included in our Consolidated Statement of Operations beginning on December 1, 2018.  Murphy generated additional revenues of $56.7 million and pre-tax income of $36.5 million related to the acquired assets from the period December 1, 2018 to December 31, 2018.

69

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note D – Acquisition (Contd.)

Pro Forma Financial Information

The following pro forma condensed combined financial information was derived from historical financial statements of Murphy and PAI and gives effect to the transaction as if it had occurred on January 1, 2017.  The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including depletion of PAI fair-valued proved crude oil and natural gas properties.  The pro forma condensed combined financial information was also adjusted to exclude acquisition-related costs of $6.2 million incurred by Murphy.  The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the transaction or any estimated costs that have been or will be incurred by us to integrate the PAI assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2017; furthermore, the financial information is not intended to be a projection of future results.











 

 

 

 



 

 

 

 



Years Ended December 31,

(Thousands of dollars, except per share amounts)

 

2018

 

2017

Revenues

$

2,825,169 

 

2,816,458 

Net Income Attributable to Murphy

 

603,231 

 

(224,860)



 

 

 

 

Net Income Attributable to Murphy per Common Share

 

 

 

 

Basic

$

3.49 

 

(1.30)

Diluted

 

3.46 

 

(1.30)









Note E – Discontinued Operations and Assets Held for Sale



The Company has accounted for its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented.



The following table presents the carrying value of the major categories of assets and liabilities of U.K. discontinued refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at December 31, 2018 and 2017.



 

 

 

 

 

 



 

 

 

 

 

 

(Thousands of dollars)

 

2018

 

 

2017

Current assets

 

 

 

 

 

 

    Cash

 

$

17,219 

 

 

16,631 

    Accounts receivable

 

 

3,728 

 

 

6,298 

        Total current assets held for sale

 

$

20,947 

 

 

22,929 

Current liabilities

 

 

 

 

 

 

    Accounts payable

 

$

106 

 

 

837 

   Refinery decommissioning cost

 

 

2,658 

 

 

2,693 

        Total current liabilities associated with assets held for sale

 

$

2,764 

 

 

3,530 



The results of operations associated with discontinued operations are presented in the following table.





 

 

 

 

 

 



 

 

 

 

 

 

(Thousands of dollars)

2018

 

2017

 

2016

Revenues

$

 

854 

 

1,464 

Loss from operations before income taxes

$

(3,522)

 

(853)

 

(2,027)

Loss on sale before income taxes

 

– 

 

– 

 

– 

Total loss from discontinued operations before taxes

 

(3,522)

 

(853)

 

(2,027)

Income tax expense

 

– 

 

– 

 

– 

Loss from discontinued operations

$

(3,522)

 

(853)

 

(2,027)







70

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note F – Inventories



Inventories consisted of the following at December 31, 2018 and 2017.





 

 

 

 





December 31,



2018

 

2017

(Thousands of dollars)

 

 

 

 

Unsold crude oil

$

25,205 

 

20,153 

Materials and supplies

 

62,706 

 

84,974 



$

87,911 

 

105,127 













Note G – Property, Plant and Equipment





 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 



 

December 31, 2018

 

 

December 31, 2017

 

(Thousands of dollars)

 

Cost

 

Net

 

 

Cost

 

Net

 

Exploration and production1

 

$

22,629,844 

 

9,654,945 

 

20,329,930 

 

8,120,293 

Corporate and other

 

 

193,471 

 

102,619 

 

 

170,842 

 

99,738 

 



 

$

22,823,315 

 

9,757,564 

 

 

20,500,772 

 

8,220,031 

 

1  Includes unproved mineral rights as follows:

 

$

512,025 

 

144,912 

 

 

600,423 

 

198,349 

 

2.  Includes $32,071 in 2018 and $38,670 in 2017 related to administrative assets and support equipment.



Divestments



In 2017, a Canadian subsidiary of the Company completed its disposition of the Seal field in Western Canada.  Total cash consideration to Murphy upon closing of the transaction was $48.8 million.  Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million.  A $129.0 million pretax gain was reported in 2017 related to the sale.  Also, in 2017, a U.S. subsidiary of the Company completed its disposition of certain non-core properties in the Eagle Ford Shale area.  Total cash consideration to Murphy upon closing of the transaction was approximately $19.6 million.  There were no gains or losses recorded related to the non-core Eagle Ford Shale sales.



In 2016, a Canadian subsidiary of the Company completed the sale of its five percent, non-operated working interest in Syncrude Canada Ltd. (Syncrude) asset to Suncor Energy Inc. (Suncor).  The Company received net cash proceeds of $739.1 million and recorded an after-tax gain of $71.7 million associated with the Syncrude divestiture.



In 2016, a Canadian subsidiary of the Company completed a divestiture of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia.  Total cash consideration received upon closing was $414.1 million.  A gain on sale of approximately $187.0 million was

deferred and is being recognized over approximately the next 17 years in the Canadian operating segment.  The Company amortized approximately $7.6 million and $7.1 million of the deferred gain during 2018 and 2017, respectively.  The remaining deferred gain of $160.2 million was included as a component of Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of December 31, 2018.



Acquisition



In 2018, a wholly owned subsidiary, Murphy Exploration & Production Company - USA, entered into a definitive agreement with Petrobras America Inc. (PAI), a subsidiary of Petrobras. The transaction was comprised of all of the Gulf of Mexico producing assets from Murphy and PAI with Murphy overseeing the operations.  Both companies contributed all their current producing Gulf of Mexico assets to MP Gulf of Mexico, LLC, a subsidiary of Murphy,  which following closing of the transaction is owned 80% by Murphy and 20% by PAI. The transaction excludes exploration blocks from Murphy. However, PAI’s blocks that hold deep exploration rights were part of the transaction. Murphy paid net cash consideration of $794.6 million at closing, after adjustments provided for in the sale and purchase agreement. Additionally, PAI received a 20% interest in MP GOM and will earn an additional contingent consideration up to $150 million if certain price and production thresholds are exceeded beginning in 2019 through 2025.  Also, Murphy will carry $50 million of PAI costs in the St. Malo Field if certain enhanced oil recovery projects are undertaken.



71

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note G – Property, Plant and Equipment (Contd.)



In 2016, a Canadian subsidiary of Murphy Oil acquired a 70% operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved.  Under the terms of the joint venture, the total consideration amounts to approximately $375.0 million of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property.  As of December 31, 2018,  $102.0 million of the carried interest had been paid. The carry is to be paid over a period through 2020.

Impairments



During 2018, underperforming wells led to impairments in certain of the Company’s US Onshore properties. In 2018 the Company recorded a pretax noncash impairment charge of $20 million to reduce the carrying values to their estimated fair values at select Midland properties.    During 2016, declines in future oil and gas prices led to impairments in certain of the Company’s producing properties.  During 2016, the Company recorded pretax noncash impairment charges of $95.1 million to reduce the carrying values to their estimated fair values for the Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties.



The following table reflects the recognized impairments for the three years ended December 31, 2018.









 

 

 

 

 

 

 

 



 

December 31,

 

(Thousands of dollars)

 

 

2018

2017

 

2016

US Onshore (Midland)

 

$

20,000 

 

– 

 

– 

 

Canada

 

 

– 

 

– 

 

95,088 

 

Malaysia

 

 

– 

 

– 

 

– 

 



 

$

20,000 

 

– 

 

95,088 

 



Other



In 2006, the Kakap field in Block K was unitized with the Gumusut field in an adjacent block under a Unitization and Unit Operating Agreement (UUOA) between the owners. The Gumusut-Kakap Unit is operated by another company.  In the fourth quarter 2016, the owners completed the first redetermination process for a revision to the blocks’ tract participation interest, and the operator of the unitized field sought the approval of Petronas to effect the change in 2017.  In 2016, the Company recorded an estimated redetermination expense of $39.1 million ($24.1 million after taxes) related to an expected revision in the Company’s working interest covering the period from inception through year-end 2016 at Kakap.  In February 2017, the Company received Petronas official approval to the redetermination change that reduced the Company’s working interest in oil operations to 6.67% effective at April 1, 2017.  Working interest redeterminations are required at different points within the life of the unitized field.  Following a partial payment, the remaining redetermination liability of $17.3 million was included as a component of Other current liabilities in the Company’s Consolidated Balance Sheet as of December 30, 2018.



In 2017, following a further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia, the Company has a 6.35% interest in the Kakap field in Block K Malaysia.  The UFA unitized the Gumusut/Kakap (GK) and Geronggong/Jagus East fields effective November 23, 2017.  In the fourth quarter 2017, the Company recorded an estimated redetermination expense of $15.0 million ($9.3 million after tax) related to Company’s revised working interest, which was included as a component of Other current liabilities in the Company’s Consolidated Balance Sheet as of December 31, 2018.

72

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note G – Property, Plant and Equipment (Contd.)



Exploratory Wells



Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.



At December 31, 2018, 2017 and 2016, the Company had total capitalized drilling costs pending the determination of proved reserves of $229.1 million, $175.6 million and $148.5 million, respectively.  The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2018.







 

 

 

 

 

 



 

 

 

 

 

 

(Thousands of dollars)

2018

 

2017

 

2016

Beginning balance at January 1

$

175,640 

 

148,500 

 

130,514 

Additions pending the determination of proved reserves

 

60,179 

 

51,488 

 

17,986 

Reclassifications to proved properties based on the
     determination of proved reserves

 

(2,214)

 

(15,988)

 

– 

Capitalized exploration well costs charged to expense

 

(4,521)

 

(8,360)

 

– 

        Ending balance at December 31

$

229,084 

 

175,640 

 

148,500 



The capitalized well costs charged to expense during 2018 included the Julong East well in Block CA-1, offshore Brunei in which further development of the well has not been sanctioned by the operator and the contract term for development sanctions has now been reached.  This well was originally drilled in 2012. The capitalized well costs charged to expense in 2017 included the Marakas-01 well in Block SK314A, offshore Malaysia in which development of the well could not be justified due to noncommercial hydrocarbon quantities found. 



The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs has been capitalized.  The projects are aged based on the last well drilled in the project. 





 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



2018

 

2017

 

2016

(Thousands of dollars)

Amount

 

No. of
Wells

 

No. of
Projects

 

Amount

 

No. of
Wells

 

No. of
Projects

 

Amount

 

No. of
Wells

 

No. of
Projects

Aging of capitalized well
  costs:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     Zero to one year

$

61,096 

 

 

 

$

41,480 

 

 

 

$

20,481 

 

 

     One to two years

 

40,523 

 

 

 

 

5,812 

 

 

 

 

63,527 

 

 

     Two to three years

 

– 

 

– 

 

– 

 

 

43,200 

 

 

 

 

– 

 

– 

 

– 

     Three years or more

 

127,465 

 

 

 

 

85,148 

 

 

 

 

64,492 

 

 

– 



$

229,084 

 

10 

 

 

$

175,640 

 

13 

 

 

$

148,500 

 

12 

 



Of the $167.9 million of exploratory well costs capitalized more than one year at December 31, 2018,  $55.8 million is in Brunei, $63.5 million is in Vietnam, $27.4 million in the U.S., and $21.2 million is in Malaysia. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. 

73

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note H – Financing Arrangements and Long-Term Debt 



As of December 31, 2018, the Company has a  $1.6 billion revolving credit facility (2018 facility). The 2018 facility is a senior unsecured guaranteed facility which expires in November 2023 and it replaced the $1.1 billion senior unsecured guaranteed credit facility (2016 facility). At December 31, 2018, the Company had outstanding borrowings of $325.0 million under the 2018 facility and $24.7 million of outstanding letters of credit, which reduce the borrowing capacity of the 2018 facility. Borrowings under the 2018 facility bear interest at rates, based, at the Company’s option, on the “Alternate Base Rate” of interest in effect plus the “ABR Spread” or the “Adjusted LIBOR Rate,” which is a periodic fixed rate based on LIBOR with a term equivalent to the interest period for such borrowing, plus the “Eurodollar Spread.” The “Alternate Base Rate” of interest is the highest of (i) the Wall Street Journal prime rate, (ii) the New York Federal Reserve Bank Rate plus 0.50%, and (iii) one-month LIBOR plus 1.00%. The “Eurodollar Spread” ranges from 1.075% to 2.10% per annum based upon the Corporation’s senior unsecured long-term debt securities credit ratings (the “Credit Ratings”). A facility fee accrues and is payable quarterly in arrears at a rate ranging from 0.175% to 0.40% per annum (based upon the Company’s Credit Ratings) on the aggregate commitments under the 2016 facility.  At December 31, 2018, the interest rate in effect on borrowings under the facility was 3.831%.  At December 31, 2018, the Company was in compliance with all covenants related to the 2018 facility.



In August 2017, the Company sold $550 million of new notes that bear interest at the rate of 5.75% and mature on August 15, 2025.  The Company incurred transaction costs of $8.4 million on the issuance of these new notes.  The Company pays interest semi-annually on February 15 and August 15 of each year.  The initial interest payment was paid on February 15, 2018.  The proceeds of the $550 million notes were used to redeem the Company’s 3.50% notes in September 2017.  The 3.50% notes had an original maturity of December 2017.



The Company and its partners are parties to a 25-year lease of production equipment at the Kakap field offshore Malaysia.  The lease has been accounted for as a capital lease (finance lease under ASC 842), and payments under the agreement are to be made over a 15-year period through March 2029.  Current maturities of long-term debt and long-term debt on the Consolidated Balance Sheet included $10.6 million and $125.8 million, respectively, associated with this lease at December 31, 2018.





 

 

 

 



 

 

 

 



December 31,

(Thousands of dollars)

2018

 

2017

Notes payable

 

 

 

 

     4.00% notes, due June 2022

$

500,000 

 

500,000 

     4.45% notes, due December 20221

 

600,000 

 

600,000 

     6.875% notes, due August 2024

 

550,000 

 

550,000 

     5.75% notes, due August 2025

 

550,000 

 

550,000 

     7.05% notes, due May 2029

 

250,000 

 

250,000 

     5.875% notes, due December 20421

 

350,000 

 

350,000 

         Total notes payable

 

2,800,000 

 

2,800,000 

     Unamortized debt issuance cost and discount on notes payable

 

(23,627)

 

(27,433)

         Total notes payable, net of unamortized discount

 

2,776,373 

 

2,772,567 

Capitalized lease obligation, due through March 2029

 

136,344 

 

143,855 

         Total debt including current maturities

 

2,912,717 

 

2,916,422 

Senior Unsecured Revolving Credit Facility

 

325,000 

 

 -

Current maturities

 

(10,583)

 

(9,902)

         Total long-term debt

$

3,227,134 

 

2,906,520 

1 Due to a series of ratings changes by credit agencies, the paying interest rates on the notes due December 2022 and December 2042 decreased from 4.7% to 4.45% and 6.125% to 5.875%, respectively, in 2017 and remained through 2018.



The amount of debt repayable over each of the next five years and thereafter are as follows:  ‘$10.6 million in 2019, $11.2 million in 2020, $11.7 million in 2021, $1.1 billion in 2022, $337.9 million in 2023 and $1.76 billion thereafter.









74

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note I – Asset Retirement Obligations

The asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 2018 and 2017 are related to the estimated costs to dismantle and abandon its producing oil and gas properties and related equipment.



A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation for 2018 and 2017 is shown in the following table.







 

 

 

 



 

 

 

 

(Thousands of dollars)

2018

 

2017

Balance at beginning of year

$

722,139 

 

781,057 

         Accretion expense

 

44,559 

 

42,590 

         Liabilities incurred

 

13,886 

 

52,331 

         Liabilities assumed from PAI

 

359,643 

 

– 

         Revisions of previous estimates

 

(24,959)

 

(47,612)

         Liabilities settled

 

(23,398)

 

(29,111)

         Liabilities assumed by purchaser of oil and gas assets

 

– 

 

(87,456)

         Changes due to translation of foreign currencies

 

(8,966)

 

10,340 

                 Balance at end of year

 

1,082,904 

 

722,139 

         Current portion of liability at end of year1

 

(55,481)

 

(12,840)

                 Noncurrent portion of liability at end of year

$

1,027,423 

 

709,299 



1Included in Other accrued liabilities on the Consolidated Balance Sheet.



The estimation of future ARO is based on a number of assumptions requiring professional judgment.  The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as:  prices for oil field services, technological changes, governmental requirements and other factors.



In 2017, revisions of previous estimates primarily reflected the impact of lower rig service rates in the U.S.



Liabilities assumed from PAI in 2018 primarily represent obligations assumed as part of the MP GOM acquisition

(see Note D).







75

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note J – Income Taxes



The components of income (loss) from continuing operations before income taxes for each of the three years presented and income tax expense (benefit) attributable thereto were as follows.







 

 

 

 

 

 



 

 

 

 

 

 

(Thousands of dollars)

2018

 

2017

 

2016

Income (loss) from continuing operations before income taxes

 

 

 

 

 

 

       United States

$

14,907 

 

(299,349)

 

(595,196)

       Foreign

 

417,431 

 

371,151 

 

102,081 

                 Total

$

432,338 

 

71,802 

 

(493,115)

Income tax expense (benefit)

 

 

 

 

 

 

       Federal – Current

$

(9,765)

 

 –

 

 -

                    – Deferred

 

(131,200)

 

156,065 

 

(197,450)

              Total Federal

 

(140,965)

 

156,065 

 

(197,450)

       State

 

3,299 

 

4,230 

 

13,984 

       Foreign – Current

 

202,775 

 

122,318 

 

146,861 

                    – Deferred

 

(55,779)

 

100,125 

 

(182,567)

              Total Foreign

 

146,996 

 

222,443 

 

(35,706)

                 Total

$

9,330 

 

382,738 

 

(219,172)



The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense.







 

 

 

 

 

 

(Thousands of dollars)

2018

 

2017

 

2016

Income tax expense (benefit) based on the U.S. statutory tax rate

$

90,791 

 

25,131 

 

(172,590)

Revaluation of deferred tax (US tax reform)

 

 –

 

118,004 

 

 –

Tax impact of deemed repatriation of foreign invested
earnings (U.S. tax reform)

 

(135,700)

 

156,000 

 

 –

Deferred tax effect on Canadian earnings no longer indefinitely
invested

 

 –

 

65,000 

 

 –

Foreign income (loss) subject to foreign tax rates different than
     the U.S. statutory rate

 

72,007 

 

12,658 

 

8,582 

State income taxes, net of federal benefit

 

2,607 

 

2,438 

 

9,090 

U.S. tax benefit on certain foreign upstream investments

 

(14,702)

 

(32,926)

 

(21,336)

Tax effects on sale of Canadian assets

 

 –

 

 –

 

(89,473)

Tax effects on sale of Malaysian assets

 

 –

 

 –

 

2,080 

Increase in deferred tax asset valuation allowance related
     to other foreign exploration expenditures

 

3,283 

 

18,601 

 

25,734 

Other, net

 

(8,956)

 

17,832 

 

18,741 

            Total

$

9,330 

 

382,738 

 

(219,172)



76

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note J – Income Taxes (Contd.)



The Tax Cuts and Jobs Act

 

On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act).  For the year ended December 31, 2017, the Company recorded a provisional tax expense of $274.0 million directly related to the impacts of the 2017 Tax Act.  The charge included the impact of a deemed repatriation of foreign earnings and the re-measurement of deferred tax assets and liabilities.  During 2018, the Company completed the accounting for the income tax effects related to the 2017 Tax Act before the end of the measurement period.  The Company revised the provisional amount recorded in 2017 and recognized a favorable income tax adjustment of $135.7 million primarily related to the reinstatement of a deferred tax asset for 2017 net operating losses, which in 2017 was assumed utilized against the deemed repatriation.  This reinstatement followed April 2, 2018 Internal Revenue Service guidance related to the Section 965(n) election.  This guidance allowed the Company to preserve the 2017 tax net operating loss as a carryforward and allowed previously unused foreign tax credits to be credited against all but $26 million of current income tax on the deemed inclusion of foreign earnings.  The $26 million tax is further reduced by $16 million of post-2017 foreign tax credits allowed to be carried back as an offset, which results in a net $10.1 million tax on the deemed repatriation.  This tax is fully offset by $29.7 million of AMT credit carryforwards to 2017, with half of the $19.6 million remainder expected to be refunded in late 2019, and the balance to be refunded or available to offset future U.S. income tax obligations over the next four years.



An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2018 and 2017 showing the tax effects of significant temporary differences follows.





 

 

 

 



 

 

 

 

(Thousands of dollars)

2018

 

2017

Deferred tax assets

 

 

 

 

         Property and leasehold costs

$

491,660 

 

488,584 

         Liabilities for dismantlements

 

88,075 

 

98,444 

         Postretirement and other employee benefits

 

113,826 

 

134,444 

         Alternative minimum tax

 

9,765 

 

29,710 

         Foreign tax credit carryforwards

 

– 

 

228,159 

         U. S. net operating loss

 

496,629 

 

272,930 

         Other deferred tax assets

 

19,974 

 

13,892 

                  Total gross deferred tax assets

 

1,219,929 

 

1,266,163 

         Less valuation allowance

 

(213,815)

 

(476,256)

                  Net deferred tax assets

 

1,006,114 

 

789,907 

Deferred tax liabilities

 

 

 

 

         Deferred tax on undistributed foreign earnings

 

(5,000)

 

(65,000)

         Accumulated depreciation, depletion and amortization

 

(742,562)

 

(669,638)

         Other deferred tax liabilities

 

(28,802)

 

(2,824)

                  Total gross deferred tax liabilities

 

(776,364)

 

(737,462)

                  Net deferred tax assets

$

229,750 

 

52,445 



In management’s judgment, the net deferred tax assets in the preceding table are more likely than not to be realized based on the consideration of deferred tax liability reversals and future taxable income.  The valuation allowance for

deferred tax assets relate primarily to tax assets arising in foreign tax jurisdictions that in the judgment of management at the present time are more likely than not unexpected to be realized.  The valuation allowance decreased $262 million in 2018 primarily due to a decrease in foreign tax credit carryforwards.   Subsequent reductions of the valuation allowance are expected to be reported as reductions of tax expense assuming no offsetting change in the deferred tax asset.



The Company has an estimated U.S. net operating loss of $2.36 billion at year-end 2018 with a corresponding deferred tax asset of $496.6 million.  The Company believes the U.S. net operating loss being carried forward will be utilized in future periods prior to expirations in 2036 and 2037.

77

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note J – Income Taxes (Contd.)



Other Information



During 2018 the Company repatriated $1.2 billion to the U.S. and paid $60 million of related Canadian withholding tax.  $1.3 billion was reflected on the Company’s December 31, 2017 balance sheet as earnings not permanently reinvested, with an accompanying $65.0 million liability.  Currently the Company considers $100.0 million of Canada’s past foreign earnings not permanently reinvested, with an accompanying $5.0 million liability.  At December 31, 2018, $1.2 billion of past foreign earnings are considered permanently reinvested.  The Company closely and routinely monitors these reinvestment positions considering underlying facts and circumstances pertinent to our business and the future operation of the company.



Uncertain Income Tax Positions

The financial statement recognition of the benefit for a tax position is dependent upon the benefit being more likely than not to be sustainable upon examination.  If this threshold is met, the tax benefit is then measured and recognized at the largest amount that is greater than 50% likely of being realized upon ultimate settlement.  Liabilities associated with uncertain income tax positions are included in Deferred credits and other liabilities in the Consolidated Balance Sheets.  A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years presented is shown in the following table.









 

 

 

 

 

 



 

 

 

 

 

 

(Thousands of dollars)

2018

 

2017

 

2016

Balance at January 1

$

3,437 

 

7,417 

 

6,631 

Additions for tax positions related to current year

 

454 

 

769 

 

756 

Settlements due to lapse of time

 

(988)

 

(4,834)

 

 –

Foreign currency translation effect

 

 –

 

85 

 

30 

  Balance at December 31

$

2,903 

 

3,437 

 

7,417 



All additions or settlements to the above liability affect the Company’s effective income tax rate in the respective period of change.  The Company accounts for any applicable interest and penalties on uncertain tax positions as a component of income tax expense.  The Company also had other recorded liabilities as of December 31, 2018, 2017 and 2016 for interest and penalties of $0.2 million, $0.1 million and $0.3 million, respectively, associated with uncertain tax positions.  Income tax expense for the years ended December 31, 2018, 2017 and 2016 included net benefits for interest and penalties of $0.1 million, $0.2 million and $0.1 million, respectively, associated with uncertain tax positions.



During the next twelve months, the Company currently expects to add between $0.2 million and $1.0 million to the liability for uncertain taxes for 2019 events.  Although existing liabilities could be reduced by settlement with taxing authorities or lapse due to statute of limitations, the Company believes that the changes in its unrecognized tax benefits due to these events will not have a material impact on the Consolidated Statement of Operations during 2019.



The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities.  These audits often take years to complete and settle.  Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters.  As of December 31, 2018, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows:  United States – 2015; Canada – 2013; Malaysia – 2012; and United Kingdom – 2017.



78

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note K – Incentive Plans



Murphy utilizes cash-based and/or share-based incentive awards to supplement normal salaries as compensation for executive management and certain employees.  For share-based awards that qualify for equity accounting, costs are recognized as an expense in the Consolidated Statements of Operations using a grant date fair value-based measurement method over the periods that the awards vest.  For share-based awards that are required to be accounted for under liability accounting rules, costs are recognized as expense using a fair value-based measurement method over the vesting period, but expense is adjusted as necessary through the date the award value is finally determined.  Total expense for liability awards is ultimately adjusted to the final intrinsic value for the award.



At the Company’s annual stockholders’ meeting held on May 9, 2018, shareholders approved replacement of the 2012 Long-Term Incentive Plan (2012 Long-Term Plan) with the 2018 Long-Term Incentive Plan (2018 Long-Term Plan).  The 2018 Long-Term Plan authorizes the Committee to make grants of the Company’s Common Stock to employees in the same form as the 2012 Long-Term Plan.  The new plan can be found in the Company’s Definitive Proxy statement (Definitive 14A) dated March 23, 2018.  All awards on or after May 9, 2018 will be made under the 2018 Long-Term Plan.



The Company currently has outstanding incentive awards issued to certain employees under the 2017 Annual Incentive Plan, the 2012 Long-Term Plan and the 2018 Long-Term Plan.  The 2017 Annual Plan authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees.  Cash awards under the 2017 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. 



The 2018  Long-Term Plan and the 2012 Long-term Plan authorize the Committee to make grants of the Company’s Common Stock to employees.  These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives.  The 2018 Long-Term Plan expires in 2028.  A total of 6.75 million shares are issuable during the life of the 2018 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding; allowed shares not granted in an earlier year may be granted in future years.  Based on awards made to date, 3.4 million shares are available for grant under the 2018 Long-Term Plan at December 31, 2018In 2018, the Company’s shareholders approved the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors. 



The Company generally expects to issue treasury shares to satisfy future stock option exercises and vesting of restricted stock and restricted stock units.



Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:





 

 

 

 

 

 



 

 

 

 

 

 

(Thousands of dollars)

2018

 

2017

 

2016

Compensation charged against income (loss) before income tax benefit

$

34,467 

 

40,365 

 

46,300 

Related income tax benefit recognized in income

 

4,383 

 

5,017 

 

15,244 



As of December 31, 2018, there were $46.5 million in compensation costs to be expensed over approximately the next five years related to unvested share-based compensation arrangements granted by the Company.  Employees receive net shares, after applicable statutory withholding taxes, upon each stock option exercise and restricted stock award.  Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were immaterial for the year ended December 31, 2018.  There were no income tax benefits realized in either 2017 or 2016 due to no stock option exercises during those years.



Equity-Settled Awards



STOCK OPTIONS – The Committee fixes the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixes the option term at no more than seven years from such date.  Each option granted to date under the 2012 Long-Term Plan has been nonqualified, with a term of seven years and an option price equal to FMV at date of grant.  Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years.  For stock options, the number of shares issued upon exercise is reduced for settlement of applicable statutory income tax withholdings owed by the grantee.

79

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note K – Incentive Plans (Contd.)



The fair value of each option award is estimated on the date of grant using the Black-Scholes pricing model based on the assumptions noted in the following table.  Expected volatility is based on historical volatility of the Company’s stock and implied volatility on publicly traded at-the-money options on the Company’s stock.  The Company estimates the expected term of the options granted based on historical option exercise patterns and considers certain groups of employees exhibiting different behavior.  The risk-free interest rate for periods within the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant. In 2018, in light of a shift in the peer group compensation practices, the Company ceased the inclusion of stock options and stock appreciation rights as a part of the long-term incentive compensation mix. 







 

 

 

 

 



 

 

 

 

 



2018

 

2017

 

2016



 

 

 

 

 

Fair value per option grant

N/A

 

$7.96

 

$5.03

Assumptions

 

 

 

 

 

        Dividend yield

N/A

 

3.60%

 

4.00%

        Expected volatility

N/A

 

41.00%

 

45.00%

        Risk-free interest rate

N/A

 

1.97%

 

1.32%

        Expected life

N/A

 

5.30 yrs.

 

5.20 yrs.



Changes in stock options outstanding during the last three years are presented in the following table.







 

 

 

 



 

 

 

 



Number of
Shares

 

Average
Exercise
Price   



 

 

 

 

Outstanding at December 31, 2015

5,443,288 

 

$

52.93 

Granted at FMV

862,000 

 

 

17.57 

Exercised

– 

 

 

 -

Forfeited

(547,853)

 

 

44.23 

Outstanding at December 31, 2016

5,757,435 

 

 

48.46 

Granted at FMV

603,000 

 

 

28.51 

Exercised

– 

 

 

 –

Forfeited

(1,459,166)

 

 

49.34 

Outstanding at December 31, 2017

4,901,269 

 

 

45.74 

Granted at FMV

– 

 

 

 –

Exercised

(72,000)

 

 

17.57 

Forfeited

(834,674)

 

 

53.36 

Outstanding at December 31, 2018

3,994,595 

 

 

44.66 

Exercisable at December 31, 2015

3,542,352 

 

$

52.26 

Exercisable at December 31, 2016

3,830,535 

 

 

53.80 

Exercisable at December 31, 2017

3,197,269 

 

 

54.22 

Exercisable at December 31, 2018

3,182,345 

 

 

49.10 



Additional information about stock options outstanding at December 31, 2018 is shown below.







 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

Options Outstanding

 

Options Exercisable

Range of Exercise
Prices per Option

 

No. of
Options

 

Avg. Life
Remaining
in Years

 

Aggregate
Intrinsic
Value

 

No. of
Options

 

Avg. Life
Remaining
in Years

 

Aggregate
Intrinsic
Value

$17.00 to $30.00

 

1,131,500 

 

4.5

 

$

3,719,263 

 

319,250 

 

4

 

$

1,859,631 

$31.00 to $50.00

 

817,350 

 

2.9

 

 

 –

 

817,350 

 

2.9

 

 

 –

$51.00 to $65.00

 

2,045,745 

 

1.0

 

 

 –

 

2,045,745 

 

1.0

 

 

 –



 

3,994,595 

 

2.4

 

$

3,719,263 

 

3,182,345 

 

1.8

 

$

1,859,631 







80

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note K – Incentive Plans (Contd.)

The total intrinsic value of options exercised during 2018 was $1 million.  There were no options exercised in both 2017 and 2016 as all awards either had no intrinsic value or were not vested.  Intrinsic value is the excess of the market price of stock at date of exercise over the exercise price received by the Company upon exercise.  Aggregate intrinsic value is nil when the exercise price of the stock option exceeds the market price of the Company’s common stock.



PERFORMANCE-BASED RESTRICTED STOCK UNITS – Performance-based restricted stock units (PSUs) to be settled in Common shares were granted in each of the last three years under the 2012 Long-Term Plan.  Each grant will vest if the Company achieves specific performance objectives at the end of the designated performance period.  Additional shares may be awarded if performance objectives are exceeded.  If performance goals are not met, PSUs will not vest, but recognized compensation cost associated with the stock award would not be reversed.  For past awards, the performance conditions were based on the Company’s total shareholder return over the performance period compared to an industry peer group of companies.  During the performance period, PSUs are subject to transfer restrictions and are subject to forfeiture if a grantee terminates for reasons other than retirement, disability or death.  Termination for these three reasons will lead to a pro rata award of amounts earned.  No dividends are paid or voting rights exist on awards of PSUs prior to their settlement.





Changes in PSUs outstanding for each of the last three years are presented in the following table.





 

 

 

 

 



 

 

 

 

 

(Number of stock units)

2018

 

2017

 

2016

Outstanding at beginning of year

1,187,921 

 

992,573 

 

1,103,986 

Granted

905,500 

 

560,000 

 

394,000 

Vested and issued

(311,866)

 

(272,725)

 

(361,096)

Forfeited

(121,138)

 

(91,927)

 

(144,317)

          Outstanding at end of year

1,660,417 

 

1,187,921 

 

992,573 



The fair value of the equity-settled performance-based awards granted in each year was estimated on the date of grant using a Monte Carlo valuation model.  Expected volatility was based on daily historical volatility of the Company’s stock price compared to a peer group average over a three-year period.  The risk-free interest rate is based on the yield curve of three-year U.S. Treasury bonds and the stock beta was calculated using three years of historical averages of daily stock data for Murphy and the peer group.  The assumptions used in the valuation of the performance awards granted in 2018, 2017  and 2016 are presented in the following table.    





 

 

 

 

 



 

 

 

 

 



2018

 

2017

 

2016



 

 

 

 

 

Fair value per share at grant date

$22.99 - $30.56

 

$24.10$28.28

 

$12.21$16.34

Assumptions

 

 

 

 

 

        Expected volatility

48.00%

 

47.00%

 

33.00%

        Risk-free interest rate

2.30%

 

1.46%

 

0.93%

        Stock beta

1.103

 

1.058

 

0.863

        Expected life

3.0 yrs.

 

3.0 yrs.

 

3.0 yrs.



81

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note K – Incentive Plans (Contd.)



TIME-BASED RESTRICTED STOCK UNITS – Time-based restricted stock units (RSUs) have been granted to the Company’s Non-Employee Directors under the 2013 NED Plan and to certain employees under the 2012 Long-Term Plan and 2018 Long-Term Plan.  These awards vest on the third anniversary of the date of grant.  The fair value of these awards was estimated based on the market value of the Company’s stock on the date of grant, which were $25.69 to $28.43 per share in 2018, $28.51 per share in 2017, and $17.57 per share in 2016.



Changes in RSUs outstanding for each of the last three years are presented in the following table.







 

 

 

 

 



 

 

 

 

 

(Number of share units)

2018

 

2017

 

2016



 

 

 

 

 

Outstanding at beginning of year

1,035,980 

 

923,282 

 

477,244 

Granted

823,803 

 

419,720 

 

503,555 

Vested and issued

(233,456)

 

(217,633)

 

(32,092)

Forfeited

(87,473)

 

(89,389)

 

(25,425)

          Outstanding at end of year

1,538,854 

 

1,035,980 

 

923,282 



EMPLOYEE STOCK PURCHASE PLAN (ESPP) – The Company had an ESPP under which the Company’s Common stock could have been purchased by eligible U.S. and Canadian employees.  The plan ceased to operate in 2017. Each quarter, an eligible employee could have elected to withhold up to 10% of his or her salary to purchase shares of the Company’s stock at the end of the quarter at a price equal to 90% of the fair value of the stock as of the first day of the quarter. Employee stock purchases under the ESPP were 2,564 shares at an average price of $26.85 per share in 2017 and 8,962 shares at an average price of $23.41 per share in 2016Compensation costs related to the ESPP were estimated based on the value of the 10% discount and the fair value of the option that provided for the refund of participant withholdings, and such expenses were immaterial for all periods presented.  The fair value per share issued under the ESPP was approximately $5.34 and $2.94 for the years ended December 31, 2017 and 2016, respectively.



Cash-Settled Awards



The Company has granted stock-based incentive awards to be settled in cash to certain employees in the form of Stock Appreciation Rights (SAR), Performance-based restricted stock units (CPSU), Time-based restricted stock units (CRSU) and Phantom units.



SAR awards have terms similar to stock options. CPSU terms are similar to other performance-based restricted stock awards (PSUs). CRSUs generally settle on the third anniversary of the date of grant.  Phantom units generally settle three to five years from date of grant.  Each award granted is settled, net of applicable income tax withholdings, in cash rather than with Common shares.  Total expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $6.5 million in 2018, $12.9 million in 2017 and $17.2 million in 2016.



The Committee also administers the Company’s incentive compensation plans, which provide for annual or periodic cash awards to officers, directors and certain other employees.  These cash awards are generally determinable based on the Company achieving specific financial and/or operational objectives.  Compensation expense of $30 million, $30.5 million and $25.8 million was recorded in 2018, 2017 and 2016, respectively, for these plans.





82

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note L – Employee and Retiree Benefit Plans

PENSION AND OTHER POSTRETIREMENT PLANS – The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees.  All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan.  All U.S. tax qualified plans meet the funding requirements of federal laws and regulations.  Contributions to foreign plans are based on local laws and tax regulations.  The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees.  The health care benefits are contributory; the life insurance benefits are noncontributory.



Upon the disposal of Murphy’s former U.K. downstream assets, the Company retained all vested defined benefit pension obligations associated with former employees of this business.  No additional benefits will accrue to these former U.K. employees under the Company’s retirement plan after the date of their separation from Murphy.



GAAP requires the Company to recognize the overfunded or underfunded status of its defined benefit plans as an asset or liability in its consolidated balance sheet and to recognize changes in that funded status between periods through accumulated other comprehensive loss.



The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the years ended December 31, 2018 and 2017 and a statement of the funded status as of December 31, 2018 and 2017.





 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 



Pension
Benefits

 

Other
Postretirement
Benefits

(Thousands of dollars)

2018

 

2017

 

2018

 

2017

Change in benefit obligation

 

 

 

 

 

 

 

 

Obligation at January 1

$

881,932 

 

815,593 

 

106,276 

 

106,679 

Service cost

 

8,994 

 

8,279 

 

1,965 

 

1,601 

Interest cost

 

26,168 

 

27,047 

 

3,427 

 

3,444 

Participant contributions

 

– 

 

– 

 

2,104 

 

2,075 

Actuarial loss (gain)

 

(57,378)

 

60,855 

 

(13,778)

 

(3,077)

Medicare Part D subsidy

 

– 

 

– 

 

325 

 

318 

Exchange rate changes

 

(12,742)

 

18,751 

 

(67)

 

46 

Benefits paid

 

(41,132)

 

(39,910)

 

(5,473)

 

(4,810)

Prior Service Cost

 

737 

 

– 

 

– 

 

– 

Other

 

(28,934)

 

(8,683)

 

– 

 

– 

        Obligation at December 31

 

777,645 

 

881,932 

 

94,779 

 

106,276 

Change in plan assets

 

 

 

 

 

 

 

 

Fair value of plan assets at January 1

 

563,825 

 

519,357 

 

– 

 

– 

Actual return on plan assets

 

(18,951)

 

50,079 

 

– 

 

– 

Employer contributions

 

24,357 

 

24,918 

 

3,044 

 

2,417 

Participant contributions

 

– 

 

– 

 

2,104 

 

2,075 

Medicare Part D subsidy

 

– 

 

– 

 

325 

 

318 

Exchange rate changes

 

(12,071)

 

18,064 

 

– 

 

– 

Benefits paid

 

(41,132)

 

(39,910)

 

(5,473)

 

(4,810)

Other

 

(28,934)

 

(8,683)

 

– 

 

– 

        Fair value of plan assets at December 31

 

487,094 

 

563,825 

 

– 

 

– 

Funded status and amounts recognized in the
    Consolidated Balance Sheets at December 31

 

 

 

 

 

 

 

 

Deferred charges and other assets

 

11,039 

 

5,905 

 

– 

 

– 

Other accrued liabilities

 

(9,175)

 

(8,856)

 

(5,101)

 

(5,392)

Deferred credits and other liabilities

 

(292,415)

 

(315,156)

 

(89,678)

 

(100,884)

        Funded status and net plan liability recognized
            at December 31

$

(290,551)

 

(318,107)

 

(94,779)

 

(106,276)

83

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note L – Employee and Retiree Benefit Plans (Contd.)

At December 31, 2018, amounts included in Accumulated other comprehensive loss (AOCL) in the Consolidated Balance Sheets, before reduction for associated deferred income taxes, which have not been recognized in net periodic benefit expense are shown in the following table.





 

 

 

 



 

 

 

 

(Thousands of dollars)    

Pension
Benefits

 

Other
Postretirement
Benefits

Net actuarial loss

$

(239,030)

 

13,969 

Prior service (cost) credit

 

(5,568)

 

– 



$

(244,598)

 

13,969 



Amounts included in AOCL at December 31, 2018 that are expected to be amortized into net periodic benefit expense during 2019 are shown in the following table.





 

 

 

 



 

 

 

 

(Thousands of dollars)    

Pension
Benefits

 

Other
Postretirement
Benefits

Net actuarial loss

$

(14,117)

 

(391)

Prior service (cost) credit

 

(956)

 

– 



$

(15,073)

 

(391)



The table that follows includes projected benefit obligations, accumulated benefit obligations and fair value of plan assets for plans where the accumulated benefit obligation exceeded the fair value of plan assets.





 

 

 

 

 

 

 

 

 

 

 

 





Projected
Benefit Obligations

 

Accumulated
Benefit Obligations

 

Fair Value
of Plan Assets

(Thousands of dollars)

2018

 

2017

 

2018

 

2017

 

2018

 

2017

Funded qualified plans where
   accumulated benefit obligation
   exceeds fair value of plan assets

$

457,446 

 

691,923 

 

447,793 

 

640,230 

 

316,543 

 

540,161 

Unfunded nonqualified and directors'
   plans where accumulated benefit
   obligation exceeds fair value of
   plan assets

 

158,228 

 

172,364 

 

150,586 

 

163,319 

 

– 

 

– 

Unfunded other postretirement plans

 

94,808 

 

106,276 

 

94,808 

 

106,276 

 

– 

 

– 



The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2018.





 

 

 

 

 

 

 

 

 

 

 

 



Pension Benefits

 

Other
Postretirement Benefits

(Thousands of dollars)

 

2018

 

2017

 

2016

 

2018

 

2017

 

2016

Service cost

$

8,994 

 

8,279 

 

8,136 

 

1,965 

 

1,601 

 

1,864 

Interest cost

 

26,168 

 

27,047 

 

25,185 

 

3,427 

 

3,444 

 

3,800 

Expected return on plan assets

 

(29,236)

 

(28,941)

 

(28,154)

 

– 

 

– 

 

– 

Amortization of prior service 
   cost (credit)

 

1,021 

 

1,026 

 

1,204 

 

(38)

 

(74)

 

(75)

Amortization of transitional
   (asset) liability

 

– 

 

– 

 

– 

 

– 

 

– 

 

– 

Recognized actuarial loss

 

21,893 

 

16,691 

 

16,165 

 

– 

 

– 

 



 

28,840 

 

24,102 

 

22,536 

 

5,354 

 

4,971 

 

5,594 

Termination benefits expense

 

– 

 

– 

 

– 

 

– 

 

– 

 

– 

Curtailment expense

 

– 

 

– 

 

822 

 

– 

 

– 

 

(19)

Net periodic benefit expense

$

28,840 

 

24,102 

 

23,358 

 

5,354 

 

4,971 

 

5,575 



84

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note L – Employee and Retiree Benefit Plans (Contd.)

Termination and curtailment expenses in 2016 were primarily related to plan amendments made upon early retirement of certain employees during 2016.



The preceding tables in this note include the following amounts related to foreign benefit plans.





 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 



Pension
Benefits

 

Other
Postretirement
Benefits

(Thousands of dollars)

2018

 

2017

 

2018

 

2017

Benefit obligation at December 31

$

173,860 

 

222,483 

 

812 

 

791 

Fair value of plan assets at December 31

 

170,551 

 

212,535 

 

– 

 

– 

Net plan liabilities recognized

 

3,309 

 

9,948 

 

812 

 

791 

Net periodic benefit expense (benefit)

 

3,983 

 

194 

 

146 

 

133 



The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2018 and 2017 and net periodic benefit expense for 2018 and 2017.





 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



Benefit Obligations

 

Net Periodic Benefit Expense



Pension
Benefits

 

Other
Postretirement
Benefits

 

Pension
Benefits

 

Other
Postretirement
Benefits



December 31

 

December 31

 

Year

 

Year



2018

 

2017

 

2018

 

2017

 

2018

 

2017

 

2018

 

2017

Discount rate

4.07% 

 

3.42% 

 

3.73% 

 

3.73% 

 

3.54% 

 

3.66% 

 

4.32% 

 

4.33% 

Expected return on plan assets

5.37% 

 

5.64% 

 

– 

 

– 

 

5.37% 

 

5.64% 

 

– 

 

– 

Rate of compensation increase

3.28% 

 

3.52% 

 

– 

 

– 

 

3.52% 

 

3.52% 

 

– 

 

– 







The discount rates used for determining the plan obligations and expense are based on the universe of high-quality corporate bonds that are available within each country.  Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans.  The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country.  Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics.  Expected compensation increases are based on anticipated future averages for the Company.



Benefit payments, reflecting expected future service as appropriate, which are expected to be paid in future years from the assets of the plans or by the Company are shown in the following table.





 

 

 

 



 

 

 

 

(Thousands of dollars)

Pension
Benefits

 

Other
Postretirement
Benefits

2018

$

37,266 

 

5,754 

2019

 

37,565 

 

5,839 

2020

 

38,606 

 

5,994 

2021

 

39,660 

 

6,130 

2022

 

39,908 

 

6,171 

2023-2027

 

207,633 

 

32,109 



 

 

 

 



For purposes of measuring postretirement benefit obligations at December 31, 2018, the future annual rates of increase in the cost of health care were assumed to be 6.5% for 2018 decreasing each year to an ultimate rate of 4.5% in 2038 and thereafter.







85

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note L – Employee and Retiree Benefit Plans (Contd.)

Assumed health care cost trend rates have a significant effect on the expense and obligation reported for the postretirement benefit plan.  A one percent change in assumed health care cost trend rates would have the following effects.





 

 

 

 



 

 

 

 

(Thousands of dollars)

1% Increase

 

1% Decrease

Effect on total service and interest cost components of net periodic postretirement
    benefit expense for the year ended December 31, 2018

$

1,049 

 

(813)

Effect on the health care component of the accumulated postretirement benefit
    obligation at December 31, 2018

 

12,656 

 

(10,350)



During 2018, the Company made contributions of $23.7 million to its domestic defined benefit pension plans, $0.8 million to its foreign defined benefit pension plans and $3.0 million to its domestic postretirement benefits plan.  During 2019, Company currently expects to make contributions of $26.7 million to its domestic defined benefit pension plans, $0.6 million to its foreign defined benefit pension plans and $5.1 million to its domestic postretirement benefits plan.



Plan Investments – Murphy Oil Corporation maintains an Investment Policy Statement (Statement) that establishes investment standards related to its funded domestic qualified retirement plan.  The Statement specifies that all assets will be held in a Trust sponsored by the Company, which is administrated by a trustee appointed by the Investment Committee (Committee).  Members of the Committee are appointed by the Chief Executive Officer of Murphy.  The Committee hires Investment Managers to invest trust assets within the guidelines established by the Committee as allowed by the Statement.  The investment goals call for a portfolio of assets consisting of equity, fixed income and cash equivalent securities.  The primary consideration for investments is the preservation of capital, and investment growth should exceed the rate of inflation.  The Committee has directed the asset investment advisors of its benefit plans to maintain a portfolio consisting of both equity and fixed income securities.  The Company believes that over time a balanced to slightly heavier weighting of the portfolio in equity securities compared to fixed income securities represents the most appropriate long-term mix for future investment return on assets held by domestic plans.  The parameters for asset allocation call for the following minimum and maximum percentages: equity securities of between 40% and 70%; fixed income securities of between 30% and 60%; long/short equity of between 0% and 15%; and cash and equivalents of between 0% and 15%.  The Committee is authorized to direct investments within these parameters.  Equity investments may include common, preferred and convertible preferred stocks, emerging markets stocks and similar funds, and long/short equity funds.  Long/short equity is a strategy invested in a portfolio of long stocks hedged with short sales of stocks and/or stock index options, with the combination of investment intended to produce equity-like returns with lower volatility over the long term.  Generally, no more than 10% of an Investment Manager’s portfolio is to be held in equity securities of any one issuer, and equity securities should have a minimum market capitalization of $100 million.  Equities held in the trust should be listed on the New York or American Stock Exchanges, principal U.S. regional exchanges, major foreign exchanges or quoted in significant over-the-counter markets.  Equity or fixed income securities issued by the Company may not be held in the trust. Fixed income securities include maturities greater than one year to maturity.  The fixed income portfolio should not exceed an average maturity of 11 years.  The portfolio may include investment grade corporate bonds, issues of the U.S. government, its agencies and government sponsored entities, government agency issued collateralized mortgage backed securities, agency issued mortgage backed securities, municipal bonds, asset backed securities, commercial mortgage backed securities and international and emerging markets bond funds.  The Committee routinely reviews the investment performance of Investment Managers.



86

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note L – Employee and Retiree Benefit Plans (Contd.)

For the U.K. retirement plan, trustees have been appointed by the wholly-owned subsidiary that sponsors the plan for U.K. employees.  The trustees have hired a fiduciary investment manager to manage the assets of the plan within the parameters of the Statement of Investment Principles (Statement).  The objective of investments is to earn a reasonable return within the allocation strategy permitted in the Statement while limiting the risk for the funded position of the plan.  The Statement specifies a strategy with an allocation goal of 60% Delegated growth fund (DGF) equities and 40% Delegated liability fund (DLF).  Also, the allocation goal includes interest rate hedge ratio and inflation rate hedge ratio of 100%.  Hewitt Risk Management Services Limited (Manager) has discretion to vary the level of interest rate and inflation hedge ratios from the strategic levels.  The DGF is diversified by style, strategy and asset class by investing with underlying funds that may include equity funds, fixed income funds, debt funds, currency funds, hedge funds, fund of hedge funds and other collective investment schemes covering a broad range of asset classes and strategies.  The DLF aims to provide returns in line with the liabilities of typical pension schemes on an exposure basis in the relevant tenures and instruments (long/short, real/nominal).  The DLF holds cash as collateral for the leveraged positions.  Small working cash balances are permitted to facilitate daily management of payments and receipts within the plan.  The trustee routinely reviews the investment performance of the plan.



For the Canadian retirement plan, the wholly-owned subsidiary that sponsors the plan has a Statement of Investment Policies and Procedures (Policy) applicable to the plan assets.  A pension committee appointed by the board of directors of the subsidiary oversees the plan, selects the investment advisors and routinely reviews performance of the asset portfolio.  The Policy permits assets to be invested in various Canadian and foreign equity securities, various fixed income securities, real estate, natural resource properties or participation rights and cash.  The objective for plan investments is to achieve a total rate of return equal to the long-term interest rate assumption used for the going-concern actuarial funding valuation.  The normal allocation for 2019 includes total equity securities of 42% with a range of 37% to 47% of total assets.  Fixed income securities have a normal allocation of 56% with a range of 51% to 61%.  Cash will normally have an allocation of 2% with a range of 0% to 10%.  The Policy calls for diversification norms within the investment portfolios of both equity securities and fixed income securities.





The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 2018 and 2017 are presented in the following table.





 

 

 

 

 

 



 

 

 

 

 

 



December 31,

 

 



2018

 

 

2017

 

 

Equity securities

56.0 

%

 

60.3 

%

 

Fixed income securities

42.2 

 

 

37.2 

 

 

Cash equivalents

1.8 

 

 

2.5 

 

 



100.0 

%

 

100.0 

%

 



The Company’s weighted average expected return on plan assets was 5.42% in 2018 and the return was determined based on an assessment of actual long-term historical returns and expected future returns for a portfolio with investment characteristics similar to that maintained by the plans.  The 5.42% expected return was based on an expected average future equity securities return of 6.97% and a fixed income securities return of 3.44% and is net of average expected investment expenses of 0.60%.  Over the last 10 years, the return on funded retirement plan assets has averaged 7.71%.







87

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note L – Employee and Retiree Benefit Plans (Contd.)

At December 31, 2018, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.





 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 



 

 

 

Fair Value Measurements Using

(Thousands of dollars)

Fair Value at
December 31, 2018

 

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

 

Significant
Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

Domestic Plans

 

 

 

 

 

 

 

 

   Equity securities:

 

 

 

 

 

 

 

 

      U.S. core equity

$

62,105 

 

62,105 

 

 –

 

 –

      U.S. small/midcap

 

19,436 

 

19,436 

 

 –

 

 –

      Hedged funds and other
         alternative strategies

 

45,844 

 

 –

 

10,789 

 

35,055 

      International commingled 
        trust fund

 

63,089 

 

 –

 

63,089 

 

 –

      Emerging market commingled
        equity fund

 

15,355 

 

 –

 

15,355 

 

 –

   Fixed income securities:

 

 

 

 

 

 

 

 

      U.S. fixed income

 

87,526 

 

 –

 

87,526 

 

 –

      International commingled 
        trust fund

 

13,274 

 

 –

 

13,274 

 

 –

      Emerging market mutual fund

 

4,570 

 

 –

 

4,570 

 

 –

    Cash and equivalents

 

5,344 

 

5,344 

 

 –

 

 –

                   Total Domestic Plans

 

316,543 

 

86,885 

 

194,603 

 

35,055 

Foreign Plans

 

 

 

 

 

 

 

 

   Equity securities funds

 

67,165 

 

 –

 

67,165 

 

 –

   Fixed income securities funds

 

89,417 

 

 –

 

89,417 

 

 –

   Diversified pooled fund

 

10,762 

 

 –

 

10,762 

 

 –

   Cash and equivalents

 

3,207 

 

 –

 

3,207 

 

 –

                   Total Foreign Plans

 

170,551 

 

 –

 

170,551 

 

 –

                   Total

$

487,094 

 

86,885 

 

365,154 

 

35,055 







































88

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note L – Employee and Retiree Benefit Plans (Contd.)

At December 31, 2017, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.





 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 



 

 

 

Fair Value Measurements Using

(Thousands of dollars)

Fair Value at

December 31, 2017

 

Quoted Prices

in Active

Markets for

Identical Assets

(Level 1)

 

Significant

Other

Observable

Inputs

(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

Domestic Plans

 

 

 

 

 

 

 

 

   Equity securities:

 

 

 

 

 

 

 

 

      U.S. core equity

$

67,343 

 

67,343 

 

 –

 

 –

      U.S. small/midcap

 

24,544 

 

24,544 

 

 –

 

 –

      Hedged funds and other
         alternative strategies

 

50,522 

 

 –

 

12,572 

 

37,950 

      International commingled 
        trust fund

 

83,960 

 

 –

 

83,960 

 

 –

      Emerging market commingled
        equity fund

 

20,774 

 

 –

 

20,774 

 

 –

   Fixed income securities:

 

 

 

 

 

 

 

 

      U.S. fixed income

 

79,890 

 

 –

 

79,890 

 

 –

      International commingled 
        trust fund

 

13,122 

 

 –

 

13,122 

 

 –

      Emerging market mutual fund

 

5,266 

 

 –

 

5,266 

 

 –

    Cash and equivalents

 

5,871 

 

5,871 

 

 –

 

 –

                   Total Domestic Plans

 

351,292 

 

97,758 

 

215,584 

 

37,950 

Foreign Plans

 

 

 

 

 

 

 

 

   Equity securities funds

 

78,666 

 

 –

 

78,666 

 

 –

   Fixed income securities funds

 

103,314 

 

 –

 

103,314 

 

 –

   Diversified pooled fund

 

23,665 

 

 –

 

23,665 

 

 –

   Cash and equivalents

 

6,888 

 

 –

 

6,888 

 

 –

                   Total Foreign Plans

 

212,533 

 

 –

 

212,533 

 

 –

                   Total

$

563,825 

 

97,758 

 

428,117 

 

37,950 



The definition of levels within the fair value hierarchy in the tables above is included in Note Q.



For domestic plans, U.S. core and small/midcap equity securities are valued based on daily market prices as quoted on national stock exchanges or in the over-the-counter market.  Hedge funds and other alternative strategies funds consist of three investments.  One of these investments is valued based on daily market prices as quoted on national stock exchanges, another investment is valued monthly based on net asset value and permits withdrawals semi-annually after a 90-day notice, and the third investment is also valued monthly based on net asset values and has a two-year lock-up period and a 95-day notice following the lock-up period.  International equities held in a commingled trust are valued monthly based on prices as quoted on various international stock exchanges.  The emerging market commingled equity fund is valued monthly based on net asset value.  These commingled equity funds can be withdrawn monthly and have a 10-day notice period.  U.S. fixed income securities are valued daily based on bids for the same or similar securities or using net asset values.  International fixed income securities held in a commingled trust are valued on a monthly basis using net asset values.  The fixed income emerging market mutual fund is valued daily based on net asset value.  For foreign plans, the equity securities funds are comprised of U.K. and foreign equity funds valued daily based on fund net asset values.  Fixed income securities funds are U.K. securities valued daily at net asset values.  The diversified pooled fund is valued daily at net asset value and contains a combination of Canadian and foreign equity securities, Canadian fixed income securities and cash.

89

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note L – Employee and Retiree Benefit Plans (Contd.)

The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:



 

 

 

 



 

 

 

 

(Thousands of dollars)

Hedged Funds and Other
Alternative Strategies

Total at December 31, 2016

 

$

34,114 

 

Actual return on plan assets:

 

 

 

 

        Relating to assets held at the reporting date

 

 

3,836 

 

        Relating to assets sold during the period

 

 

– 

 

Purchases, sales and settlements

 

 

– 

 

        Total at December 31, 2017

 

 

37,950 

 

Actual return on plan assets:

 

 

 

 

        Relating to assets held at the reporting date

 

 

(2,921)

 

        Relating to assets sold during the period

 

 

– 

 

Purchases, sales and settlements

 

 

– 

 

        Total at December 31, 2018

 

$

35,029 

 



THRIFT PLANS – Most full-time U.S. employees of the Company may participate in thrift or similar savings plans by allotting up to a specified percentage of their base pay.  The Company matches contributions at a stated percentage of each employee’s allotment based on years of participation in the plans, with a maximum match of 6%.  Amounts charged to expense for the Company’s match to these plans were $5.2 million in 2018, $7.8 million in 2017 and $7.4 million in 2016.



Note M – Financial Instruments and Risk Management



DERIVATIVE INSTRUMENTS – Murphy often uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates.  The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management.  The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features.  Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX).  The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.  For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.  Certain interest rate derivative contracts were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in AOCL until the anticipated transactions occur.



Commodity Purchase Price Risks



The Company is subject to commodity price risk related to crude oil it produces and sells.  During the last three years, the Company had West Texas Intermediate (WTI) crude oil price swap financial contracts to economically hedge a portion of its United States production.  Under these contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices.

At December 31, 2018, the Company had no open WTI crude oil swap financial contracts. At December 31, 2017, the Company had 21,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018 at an average price of $54.88.    



Foreign Currency Exchange Risks



The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S.  The Company had no foreign currency exchange short-term derivative instruments outstanding as of December 31, 2018 and 2017.  



90

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note M – Financial Instruments and Risk Management (Contd.)



At December 31, 2018 and 2017, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.    



 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 



 

December 31, 2018

 

December 31, 2017

(Thousands of dollars)

 

Asset (Liability) Derivatives

 

Asset (Liability) Derivatives

Type of Derivative Contract

 

Balance Sheet Location

 

Fair Value

 

Balance Sheet Location 

 

Fair Value

Commodity

 

Accounts receivable

$

3,837 

 

Accounts payable

$

(39,093)



For the years ended December 31, 2018, 2017 and 2016, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.



 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 



 

 

 

Gain (Loss)

(Thousands of dollars)

 

 

 

 

Year Ended December 31,

Type of Derivative Contract

 

Statement of Operations Locations

 

2018

 

2017

 

2016

Commodity

 

(Loss) gain on crude contracts

 

$

(41,975)

 

9,566 

 

(63,412)

Foreign exchange

 

Interest and other income (loss)

 

 

 

 

26,714 



 

 

 

$

(41,975)

 

9,566 

 

(36,698)



Interest Rate Risks



Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022.  During each of the three years ended December 31, 2018,  $3.0 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statements of Operations.  The remaining loss (net of tax) deferred on these matured contracts at December 31, 2018 was $7.9 million, which is recorded, net of income taxes of $2.1 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheets.  The Company expects to charge approximately $3.0 million of this deferred loss to Interest expense in the Consolidated Statements of Operations during 2019.



CREDIT RISKS – The Company’s primary credit risks are associated with trade accounts receivable, cash equivalents and derivative instruments.  Trade receivables arise mainly from sales of oil and natural gas in the U.S., Canada and Malaysia, and cost sharing amounts of operating and capital costs billed to partners for oil and natural gas fields operated by Murphy.  The credit history and financial condition of potential customers are reviewed before credit is extended, security is obtained when deemed appropriate based on a potential customer’s financial condition, and routine follow-up evaluations are made.  The combination of these evaluations and the large number of customers tends to limit the risk of credit concentration to an acceptable level.  Cash equivalents are placed with several major financial institutions, which limit the Company’s exposure to credit risk.  The Company controls credit risk on derivatives through credit approvals and monitoring procedures and believes that such risks are minimal because counterparties to the majority of transactions are major financial institutions.



































91

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note N – Earnings per Share



Net income (loss) was used as the numerator in computing both basic and diluted income per Common share for each of the three years ended December 31, 2018The following table reconciles the weighted-average shares outstanding used for these computations.







 

 

 

 

 

 



 

 

 

 

 

 

(Weighted-average shares)

 

2018

 

2017

 

2016

Basic method

 

172,974,491 

 

172,524,061 

 

172,173,012 

Dilutive stock options 1 

 

1,234,274 

 

 –

 

 –

        Diluted method

 

174,208,765 

 

172,524,061 

 

172,173,012 



1 Due to a net loss recognized by the Company for the years ended December 31, 2017 and 2016, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.



The following table reflects certain options to purchase shares of common stock that were outstanding during the three years ended December 31, 2018, but were not included in the computation of dilutive earnings per share because the incremental shares from the assumed conversion were antidilutive.





 

 

 

 

 

 



 

 

 

 

 

 



 

2018

 

2017

 

2016

Antidilutive stock options excluded from diluted shares

 

3,942,296 

 

4,901,269 

 

5,757,435 

Weighted average price of these options

 

$46.77 

 

$45.74 

 

$48.46 





Note O – Other Financial Information



GAIN FROM FOREIGN CURRENCY TRANSACTIONS – Net gains (losses) from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Operations were $(7.8) million in 2018, $(75.4) million in 2017 and $59.7 million in 2016.



Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2018 as shown in the following table.







 

 

 

 

 

 



 

 

 

 

 

 

(Thousands of dollars)

2018

 

2017

 

2016

Accounts receivable

$

(89,070)

 

114,401 

 

119,671 

Inventories

 

12,216 

 

26,883 

 

(5,171)

Prepaid expenses

 

(17,341)

 

29,570 

 

149,946 

Deferred income tax assets

 

 –

 

 –

 

 -

Accounts payable and accrued liabilities

 

(51,769)

 

(51,439)

 

(328,078)

Current income tax liabilities

 

(23,844)

 

16,999 

 

24,943 

        Net (increase) decrease in noncash operating working capital

$

(169,808)

 

136,414 

 

(38,689)

Supplementary disclosures (including discontinued operations):

 

 

 

 

 

 

Cash income taxes paid, net of refunds

$

129,296 

 

68,076 

 

6,707 

Interest paid, net of amounts capitalized of $5,258 in 2018, 
   $4,488 in 2017 and $4,322 in 2016

 

167,750 

 

147,975 

 

127,798 



 

 

 

 

 

 

Noncash investing activities, related to continuing operations:

 

 

 

 

 

 

Asset retirement costs capitalized

$

353,436 

 

8,509 

 

13,690 

Decrease (increase) in capital expenditure accrual

 

(42,467)

 

99,199 

 

158,885 









92

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note O – Other Financial Information (Contd.)



DEEPWATER RIG CONTRACT EXIT COSTS – At year-end 2015, the Company had two deepwater drilling rigs in the Gulf of Mexico under contract that were scheduled to expire in February and November 2016.  In the face of low commodity prices, a significant reduction in the Company’s overall 2016 capital spending program and lack of interest by working interest partners and others to participate in drilling opportunities in 2016, the Company idled and stacked both rigs during the fourth quarter of 2015.  The Company reported a pretax charge to Other expense in 2015 totaling $282.0 million that included both the costs incurred in 2015 when the rigs were idle and stacked together with the remaining day rate commitments due under the contracts in 2016.  The contract originally scheduled to expire in November 2016 was terminated by the Company.  The Company paid approximately $266.7 million related to these contracts in 2016 and reported a pretax benefit to Other expense in 2017 and 2016 of $6.1 million and $4.3 million, respectively, for the final settlement of the contracts at less than the recorded costs.  These amounts are included in Other expense in the Consolidated Statements of Operations.











Note P – Accumulated Other Comprehensive Loss



The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2018 and December 31, 2017 and the changes during 2017 and 2016 are presented net of taxes in the following table.







 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

(Thousands of dollars)

Foreign
Currency
Translation
Gains (Losses)

 

Retirement and
Postretirement
Benefit Plan
Adjustments

 

Deferred
Loss on
Interest
Rate
Derivative
Hedges

 

Total

Balance at December 31, 2016

$

(446,555)

 

(171,305)

 

(10,352)

 

(628,212)

2017 components of other comprehensive income (loss):

 

 

 

 

 

 

 

 

Before reclassifications to income

 

171,725 

 

(17,269)

 

– 

 

154,456 

Reclassifications to income

 

– 

 

9,587 

1

1,926 

2

11,513 

                  Net other comprehensive income

 

171,725 

 

(7,682)

 

1,926 

 

165,969 

Balance at December 31, 2017

 

(274,830)

 

(178,987)

 

(8,426)

 

(462,243)

2018 components of other comprehensive income (loss):

 

 

 

 

 

 

 

 

Before reclassifications to income

 

(145,022)

 

(16,839)

 

(1,815)

 

(163,676)

Reclassifications to income

 

– 

 

13,790 

1

2,342 

2

16,132 

                  Net other comprehensive income (loss)

 

(145,022)

 

(3,049)

 

527 

 

(147,544)

Balance at December 31, 2018

$

(419,852)

 

(182,036)

 

(7,899)

 

(609,787)



1

Reclassifications before taxes of $17,313 and $14,821 are included in the computation of net periodic benefit expense in 2018 and 2017, respectively.  See Note L for additional information.  Related income taxes of $3,523 and $5,234 are included in income tax expense in 2018 and 2017, respectively.

2

Reclassifications before taxes of $2,963 are included in Interest expense in both 2018 and 2017.  Related income taxes of $622 and $1,037 are included in income tax expense in 2018 and 2017.  See Note M for additional information.

 

 

Note Q – Assets and Liabilities Measured at Fair Value





Fair Values – Recurring



The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet.  The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality.  Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.



93

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note Q – Assets and Liabilities Measured at Fair Value (Contd.)



The fair value measurements for these assets and liabilities at December 31, 2018 and 2017 are presented in the following table.









 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



December 31, 2018

 

December 31, 2017

(Thousands of dollars)

Level 1

 

Level 2

 

Level 3

 

Total

 

Level 1

 

Level 2

 

Level 3

 

Total

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     Commodity derivative contracts

$

– 

 

3,837 

 

– 

 

3,837 

 

– 

 

– 

 

– 

 

– 



$

– 

 

3,837 

 

– 

 

3,837 

 

– 

 

– 

 

– 

 

– 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     Nonqualified employee
        savings plans

$

13,845 

 

– 

 

– 

 

13,845 

 

16,158 

 

– 

 

– 

 

16,158 

     Contingent consideration

 

– 

 

– 

 

47,730 

 

47,730 

 

– 

 

– 

 

– 

 

– 

     Commodity derivative contracts

 

– 

 

– 

 

– 

 

– 

 

– 

 

39,093 

 

– 

 

39,093 



$

13,845 

 

– 

 

47,730 

 

61,575 

 

16,158 

 

39,093 

 

– 

 

55,251 



The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds.  The fair value of this liability was based on quoted prices for these equity securities and mutual funds.  The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of Operations.



The Company’s contingent consideration liability (as further described in Note D) is measured at fair value on a recurring basis and is categorized as Level 3 in the fair value hierarchy.  The contingent consideration is valued using a Monte Carlo simulation model, which used the following assumptions as of December 31, 2018: (i) the remaining expected life of 7 years, (ii) West Texas Intermediate forward strip pricing with historical volatility of 30.0%, and (iii) a risk-free interest rate of 2.752%. The income effect of changes in the fair value of the contingent consideration is recorded in Other (income) expense in the Consolidated Statements of Operations.



The fair value of West Texas Intermediate (WTI) crude oil contracts in 2018 and 2017 was based on active market quotes for WTI crude oil. The income effect of changes in fair value of crude oil derivative contracts is recorded in Gain (loss) on crude contracts in the Consolidated Statements of Operations, while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and other income (loss)



The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists.  There were no offsetting positions recorded at December 31, 2018 and 2017.



The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2018 and 2017.  The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties.  The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts.  The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities.  The Company has off-balance sheet exposures relating to certain letters of credit.  The fair value of these, which represents fees associated with obtaining the instruments, was nominal.





 

 

 

 

 

 

 

 



December 31,



2018

 

2017

(Thousands of dollars)

Carrying
Amount

 

Fair
Value

 

Carrying
Amount

 

Fair
Value

Financial assets (liabilities):

 

 

 

 

 

 

 

 

        Current and long-term debt

$

(3,237,717)

 

(3,003,388)

 

(2,916,422)

 

(2,993,003)



94

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note Q – Assets and Liabilities Measured at Fair Value (Contd.)



Fair Values – Nonrecurring



In 2018, as a result of our assessment of market value and our expected recoverable value of select Midland properties in the U.S., the Company recognized a pretax noncash impairment charge of $20.0 million.



As a result of significantly lower commodity prices during 2016, the Company recognized $95.1 million, respectively, in pretax noncash impairment charges related primarily to producing properties.



The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs and a discount rate believed to be consistent with those used by principal market participants in the applicable region.



The fair value information associated with these impaired properties is presented in the following table.







 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 



 

Year Ended December 31,



 

 

 

 

 

 

 

 

 

 

Total



 

 

 

 

 

 

 

 

Net Book

 

Pretax



 

 

 

 

 

 

 

 

Value

 

(Noncash)



 

Fair Value

 

Prior to

 

Impairment

(Thousands of dollars)

 

 

Level 1

 

Level 2

 

Level 3

 

Impairment

 

Expense

2018

 

 

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

  Impaired proved properties

 

 

 

 

 

 

 

 

 

 

 

      United States Midland

 

$

– 

 

– 

 

37,690 

 

57,690 

 

20,000 

2016

 

 

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

  Impaired proved properties

 

 

 

 

 

 

 

 

 

 

 

      Western Canada

 

$

– 

 

– 

 

71,967 

 

167,055 

 

95,088 



 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 











Note R – Commitments



The Company leases production and other facilities under operating leases.  The most significant operating leases are associated with floating, production, storage and offloading facilities at the Kikeh oil field, the West Patricia field and the Gulf of Mexico Cascade Chinook facility.  During each of the next five years, expected future net rental payments under all operating leases are approximately $188.6 million in 2019, $88.9 million in 2020, $61.9 million in 2021, $27.6 million in 2022 and $15.6 million in 2023.  Rental expense for noncancelable operating leases, including contingent payments when applicable, was $75.3 million in 2018, $72.6 million in 2017, and $77.5 million in 2016.  A lease of production equipment at the Kakap field offshore Sabah, Malaysia has been accounted for as a capital lease and is included in long-term debt discussed in Note H.



The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond December 31, 2018.  These rigs will primarily be utilized for drilling operations in onshore U.S., Canada, and the Gulf of Mexico.  Future commitments under these contracts, all of which expire by 2020, total $57.9 million.  Gulf of Mexico rig contracts are short term in nature and can be terminated within 30 days without cost.  A portion of these costs are expected to be borne by other working interest owners as partners of the Company when the wells are drilled.  These drilling costs are generally expected to be accounted for as capital expenditures as incurred during the contract periods.



95

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note R – Commitments (Contd.)



The Company has operating, production handling and transportation service agreements for oil and/or natural gas operations in the U.S. and Western Canada.  The U.S. Onshore and Gulf of Mexico transportation contracts require minimum monthly payments through 2024, while the Western Canada processing contracts call for minimum monthly payments through 2045.  Future required minimum monthly payments for the next five years are $116.8 million in 2019, $128.0 million in 2020, $145.3 million in 2021, $136.2 million in 2022 and $123.7 million in 2023.  Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement.  Total costs incurred under these service arrangements were $52.2 million in 2018, $53.8 million in 2017, and $50.3 million in 2016.



Commitments for capital expenditures were approximately $383.1 million at December 31, 2018, including $165.2 million for costs to develop deepwater U.S. Gulf of Mexico fields including new fields acquired as part of the MP GOM transaction,  $103.0 million for field development and future work commitments in Malaysia, $60.0 million for development at Kaybob Duvernay in Canada, $31.4 million for work at Eagle Ford Shale, $14.7 million for exploration cost in Mexico, and $8.8 million for future work commitments in Vietnam.



Note S – Contingencies



The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world.  Examples of such governmental action include, but are by no means limited to:  tax legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others.  Governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences or may be taken in response to actions of other governments.  It is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.



ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment.  Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays.  A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.



The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled.  Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal.  In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control.  Under existing laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.  Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses.  The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011.  The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries.  Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013.  The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.





96

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note S – Contingencies (Contd.)



In 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta.  The pipeline was immediately shut down and the Company’s emergency response plan was activated.  In cooperation with local governmental regulators, and with the assistance of qualified consultants, an investigation and remediation plan is progressing as planned and the Company’s insurers were notified.  Based on the assessments done to date, the Company recorded $43.9 million in Other expense during 2015 and a further $3.8 million in 2018 associated with the estimated costs of remediating the site.  The Company has spent $44.7 million from inception to December 31, 2018

Further refinements in the estimated total cost to remediate the site may occur in future periods. The Company retained the responsibility for this remediation upon sale of the Seal field in 2017. As of December 31, 2018, the Company has a remaining accrued liability of $3.0 million associated with this event. In 2018, the Company received $25.0 million in respect to an insurance claim regarding this matter and the outcome of further insurance claims by the Company is pending.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites.  However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.



LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.



Note T – Common Stock Issued and Outstanding



Activity in the number of shares of Common Stock issued and outstanding for the three years ended December 31, 2018 is shown below.





 

 

 

 

 



 

 

 

 

 

(Number of shares outstanding)

2018

 

2017

 

2016

Beginning of year

172,572,873 

 

172,202,177 

 

172,034,711 

Stock options exercised  1

21,200 

 

– 

 

– 

Restricted stock awards  1

464,756 

 

368,132 

 

158,504 

Employee stock purchase and thrift plans

– 

 

2,564 

 

8,962 

Treasury shares purchased

– 

 

– 

 

– 

         End of year

173,058,829 

 

172,572,873 

 

172,202,177 



1 Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note K due to withholdings for   statutory income taxes owed upon issuance of shares. 





97

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note U – Business Segments



Murphy’s reportable segments are organized into geographic areas of operations.  The Company’s exploration and production activity is subdivided into segments for the United States, Canada, Malaysia and all other countries.  Each of these segments derives revenues primarily from the sale of crude oil, condensate, natural gas liquids and/or natural gas.  The Company’s management evaluates segment performance based on income (loss) from operations, excluding interest income and interest expense. 



The Company has several customers that purchase a significant portion of its oil and natural gas production.  During 2018, 2017, and 2016, sales to Phillips 66 and affiliated companies represented approximately 12%, 14% and 17%,  respectively, of the Company’s total sales revenue.  Due to the quantity of active oil and natural gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices.



The Company completed the sale of its U.K. downstream assets during 2015.  For all years presented, assets and liabilities associated with U.K. refining and marketing operations were reported as held for sale in the Consolidated Balance Sheets.  These operations have been reported as Discontinued operations for all periods presented in these consolidated financial statements.



Information about business segments and geographic operations is reported in the following tables.  For geographic purposes, revenues are attributed to the country in which the sale occurs.  Corporate and other activities, including interest income, other gains and losses (including foreign exchange gains/losses, and realized/unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totalsAs used in the table on the following page, certain long-lived assets at December 31 exclude investments, noncurrent receivables, deferred tax assets, and other intangible assets.

98

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued





 

 

 

 

 

 

 

 

 

 

 

Segment Information

Exploration and Production

 

(Millions of dollars)

United
States

 

Canada1

 

Malaysia

 

Other

 

Total
E&P

 

Year ended December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

Segment income (loss)

$

242.9 

 

51.1 

 

269.5 

 

(16.6)

 

546.9 

 

Revenues from external customers

 

1,289.6 

 

438.6 

 

854.2 

 

22.2 

 

2,604.6 

Interest income

 

– 

 

– 

 

– 

 

– 

 

– 

 

Interest expense, net of capitalization

 

– 

 

– 

 

– 

 

0.2 

 

0.2 

 

Income tax expense (benefit)

 

68.1 

 

14.5 

 

143.3 

 

(25.3)

 

200.6 

 

Significant noncash charges (credits)

 

 

 

 

 

 

 

 

 

 

 

       Depreciation, depletion and amortization

 

519.5 

 

232.4 

 

198.6 

 

3.5 

 

954.0 

 

       Accretion of asset retirement obligations

 

19.5 

 

7.7 

 

17.4 

 

– 

 

44.6 

 

       Amortization of undeveloped leases

 

36.8 

 

0.8 

 

– 

 

2.5 

 

40.1 

 

       Impairment of assets

 

20.0 

 

– 

 

– 

 

– 

 

20.0 

 

       Deferred and noncurrent income taxes

 

68.1 

 

16.5 

 

(0.5)

 

(25.7)

 

58.4 

 

Additions to property, plant, equipment

 

1,343.5 

 

373.8 

 

138.6 

 

15.9 

 

1,871.8 

 

Total assets at year-end

 

6,342.9 

 

1,711.9 

 

1,670.2 

 

188.1 

 

9,913.1 

 

Year ended December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

Segment income (loss)

$

(8.9)

 

112.5 

 

224.2 

 

(37.5)

 

290.3 

 

Revenues from external customers

 

944.3 

 

485.5 

 

781.1 

 

– 

 

2,210.9 

 

Interest income

 

– 

 

– 

 

– 

 

– 

 

– 

 

Interest expense, net of capitalization

 

– 

 

– 

 

– 

 

– 

 

– 

 

Income tax expense (benefit)

 

(0.8)

 

44.4 

 

126.4 

 

(36.2)

 

133.8 

 

Significant noncash charges (credits)

 

 

 

 

 

 

 

 

 

 

 

       Depreciation, depletion and amortization

 

546.1 

 

185.4 

 

204.6 

 

3.8 

 

939.9 

 

       Accretion of asset retirement obligations

 

17.4 

 

7.9 

 

17.3 

 

– 

 

42.6 

 

       Amortization of undeveloped leases

 

60.2 

 

1.6 

 

– 

 

– 

 

61.8 

 

       Deferred and noncurrent income taxes

 

2.5 

 

55.3 

 

(3.7)

 

(36.2)

 

17.9 

 

Additions to property, plant, equipment

 

534.8 

 

267.6 

 

16.0 

 

37.6 

 

856.0 

 

Total assets at year-end

 

5,186.2 

 

1,725.8 

 

1,670.1 

 

154.2 

 

8,736.3 

 

Year ended December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

Segment loss

$

(164.2)

 

(35.9)

 

171.1 

 

(54.7)

 

(83.7)

 

Revenues from external customers

 

749.1 

 

365.3 

 

753.4 

 

0.2 

 

1,868.0 

 

Interest income

 

– 

 

– 

 

– 

 

– 

 

– 

 

Interest expense, net of capitalization

 

– 

 

– 

 

– 

 

– 

 

– 

 

Income tax expense (benefit)

 

(65.7)

 

(134.3)

 

85.9 

 

(18.8)

 

(132.9)

 

Significant noncash charges (credits)

 

 

 

 

 

 

 

 

 

 

 

       Depreciation, depletion and amortization

 

600.5 

 

203.2 

 

227.7 

 

5.9 

 

1,037.3 

 

       Accretion of asset retirement obligations

 

17.1 

 

13.3 

 

16.3 

 

– 

 

46.7 

 

       Amortization of undeveloped leases

 

38.4 

 

4.5 

 

– 

 

0.5 

 

43.4 

 

       Impairment of assets

 

– 

 

95.1 

 

– 

 

– 

 

95.1 

 

       Deferred and noncurrent income taxes

 

(108.4)

 

(175.8)

 

(8.5)

 

(18.3)

 

(311.0)

 

Additions to property, plant, equipment

 

269.8 

 

361.3 

 

101.4 

 

(1.3)

 

731.2 

 

Total assets at year-end

 

5,419.0 

 

1,559.5 

 

2,024.7 

 

115.7 

 

9,118.9 

 



 1 Includes Synthetic crude operations in 2016.  This business was sold in June 2016.

 2 Includes a pretax gain of $129.0 million on sale of Seal area heavy oil field sold in January 2017.



 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

Geographic Information

Certain Long-Lived Assets at December 31

(Millions of dollars)

United
States

 

Canada

 

Malaysia

 

United
Kingdom

 

Other

 

Total

2018

$

6,634.3 

 

1,644.6 

 

1,325.4 

 

– 

 

153.3 

 

9,757.6 

2017

 

5,050.5 

 

1,635.9 

 

1,392.3 

 

– 

 

141.3 

 

8,220.0 

2016

 

5,121.6 

 

1,451.4 

 

1,637.0 

 

– 

 

106.2 

 

8,316.2 



99

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued





 

 

 

 

 

 



 

 

 

 

 

 

Segment Information — Continued

 

(Millions of dollars)

Corporate
and
Other

 

Discontinued
Operations

 

Consolidated
Total

Year ended December 31, 2018

 

 

 

 

 

 

Segment income (loss)

$

(123.9)

 

(3.5)

 

419.5 

Revenues from external customers

 

(34.0)

 

– 

 

2,570.6 

Interest income

 

8.0 

 

– 

 

8.0 

Interest expense, net of capitalization

 

181.4 

 

– 

 

181.6 

Income tax expense (benefit)

 

(191.3)

 

– 

 

9.3 

Significant noncash charges (credits)

 

 

 

 

 

 

       Depreciation, depletion and amortization

 

17.9 

 

– 

 

971.9 

       Accretion of asset retirement obligations

 

– 

 

– 

 

44.6 

       Amortization of undeveloped leases

 

– 

 

– 

 

40.1 

       Deferred and noncurrent income taxes

 

(242.1)

 

– 

 

(183.7)

Additions to property, plant, equipment

 

22.7 

 

– 

 

1,894.5 

Total assets at year-end

 

1,118.5 

 

20.9 

 

11,052.5 

Year ended December 31, 2017

 

 

 

 

 

 

Segment income (loss)

$

(607.5)

 

(0.9)

 

(311.8)

Revenues from external customers

 

4.6 

 

– 

 

2,225.1 

Interest income

 

7.4 

 

– 

 

7.4 

Interest expense, net of capitalization

 

181.8 

 

– 

 

181.8 

Income tax expense (benefit)

 

245.6 

 

– 

 

382.7 

Significant noncash charges (credits)

 

 

 

 

 

 

       Depreciation, depletion and amortization

 

17.8 

 

– 

 

957.7 

       Accretion of asset retirement obligations

 

– 

 

– 

 

42.6 

       Amortization of undeveloped leases

 

– 

 

– 

 

61.8 

       Deferred and noncurrent income taxes

 

242.5 

 

– 

 

260.4 

Additions to property, plant, equipment

 

14.8 

 

– 

 

870.8 

Total assets at year-end

 

1,101.7 

 

22.9 

 

9,860.9 



 

 

 

 

 

 

Year ended December 31, 2016

 

 

 

 

 

 

Segment loss

$

(149.1)

 

(2.0)

 

(276.0)

Revenues from external customers

 

6.6 

 

– 

 

1,811.2 

Interest income

 

2.9 

 

– 

 

2.9 

Interest expense, net of capitalization

 

148.2 

 

– 

 

148.2 

Income tax expense (benefit)

 

(64.1)

 

– 

 

(219.2)

Significant noncash charges (credits)

 

 

 

 

 

 

       Depreciation, depletion and amortization

 

16.8 

 

– 

 

1,054.1 

       Accretion of asset retirement obligations

 

– 

 

– 

 

46.7 

       Amortization of undeveloped leases

 

– 

 

– 

 

43.4 

       Impairment of assets

 

– 

 

– 

 

95.1 

       Deferred and noncurrent income taxes

 

(76.8)

 

– 

 

(387.8)

Additions to property, plant, equipment

 

21.9 

 

– 

 

753.1 

Total assets at year-end

 

1,149.9 

 

27.1 

 

10,295.9 













 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

Geographic Information

Revenues from External Customers for the Year

(Millions of dollars)

United
States

 

Canada

 

Malaysia

 

Other

 

Total

2018

$

1,297.5 

 

438.5 

 

854.3 

 

(19.7)

 

2,570.6 

2017

 

958.3 

 

485.7 

 

781.1 

 

– 

 

2,225.1 

2016

 

692.3 

 

365.3 

 

753.4 

 

0.2 

 

1,811.2 









 

100

 


 

 

 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)



The following unaudited schedules are presented in accordance with required disclosures about Oil and Gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies.  Additional background information concerning some of the schedules follows:



SCHEDULE 1 – SUMMARY OF PROVED CRUDE OIL RESERVES

SCHEDULE 2 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES

SCHEDULE 3 – SUMMARY OF PROVED NATURAL GAS RESERVES



Reserves of crude oil, condensate, natural gas liquids and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year.  Many assumptions and judgmental decisions are required to estimate reserves.  Reserve estimates and future cash flows are based on the average market prices for sales of oil and gas on the first calendar day of each month during the year. The average prices used for 2018 were $65.56 per barrel for NYMEX crude oil (WTI), and $3.10 per Mcf for natural gas (Henry Hub). The average prices used for 2017 were $51.34 per barrel for NYMEX crude oil (WTI), and $2.98 per Mcf for natural gas (Henry Hub).  Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.



Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data and commercially available technologies to establish reasonable certainty”  of economic producibility.  As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered.  In estimating proved reserves, Murphy uses common industry-accepted methods for subsurface evaluations, including performance, volumetric and analog-based studies.  Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves.  Reliable geologic and engineering technology is a method or combination of methods that are field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.  This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates.  The approach was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas and in certain reservoirs developed with the application of improved recovery techniques.  Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data and commercially available seismic processing and numerical reservoir simulation programs.  Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.



Prior to its disposition in 2016, Murphy included synthetic crude oil from its five percent interest in the Syncrude project in Alberta, Canada in its proved crude oil reserves.  All synthetic oil volumes reported as proved reserves in Schedule 1 are the final synthetic crude oil product.



Production quantities shown are net volumes withdrawn from reservoirs.  These may differ from sales quantities due to inventory changes, volumes consumed for fuel and/or shrinkage from the extraction of natural gas liquids.



All crude oil and synthetic reserves, natural gas liquid reserves and natural gas reserves are from consolidated subsidiaries (including noncontrolling interest) and proportionately consolidated joint ventures.  The Company has no proved reserves attributable to investees accounted for by the equity method.



101


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



All proved reserves in Malaysia are associated with production sharing contracts for Blocks SK 309/311, K and H.  Malaysia reserves include oil and gas to be received for both cost recovery and profit provisions under the contract.  At December 31, 2018, liquids and natural gas proved reserves associated with the production sharing contracts in Malaysia totaled 51.7 million barrels and 468.2 billion cubic feet (BCF), respectively.  At December 31, 2018, approximately 26.1 BCF of natural gas proved reserves in Malaysia relate to fields in Block K for which the Company expects to receive sale proceeds of approximately $0.24 per thousand cubic feet.  Sales price for other natural gas produced in Malaysia is based on market-driven prices.



SCHEDULE 6 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES



GAAP requires calculation of future net cash flows using a 10% annual discount factor, an unweighted average of oil and natural gas prices in effect at the beginning of each month of the year, and year-end costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates.    On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act); as a result the company’s statutory U.S. tax rate was 21% in 2018, a decrease from the previous rate of 35%.



The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production.  Other logical assumptions would likely have resulted in significantly different amounts.



Schedule 6 also presents the principal reasons for change in the standardized measure of discounted future net cash flows for each of the three years ended December 31, 2018.

102

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



Schedule 1 – Summary of Proved Crude Oil Reserves Based on Average Prices for 2015 – 2018





 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 



Crude &

Synthetic

Oil

 

Crude Oil

 

Synthetic

Oil 1

(Millions of barrels)

Total

 

Total

 

United
States

 

Canada

 

Malaysia

 

Canada

Proved developed and
    undeveloped crude oil /
    synthetic oil reserves:

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

456.2 

 

341.4 

 

238.9 

 

27.9 

 

74.6 

 

114.8 

Revisions of previous estimates

(5.8)

 

(5.8)

 

(10.9)

 

2.5 

 

2.6 

 

 –

Extensions and discoveries

11.0 

 

11.0 

 

8.6 

 

 –

 

2.4 

 

 –

Purchases of properties

26.3 

 

26.3 

 

 –

 

26.3 

 

 –

 

 –

Sales of properties

(121.0)

 

(7.8)

 

(4.5)

 

(3.3)

 

 –

 

(113.2)

Production

(37.7)

 

(36.1)

 

(17.7)

 

(4.5)

 

(13.9)

 

(1.6)

December 31, 2016

329.0 

 

329.0 

 

214.4 

 

48.9 

 

65.7 

 

(0.0)

Revisions of previous estimates

(6.0)

 

(6.0)

 

(4.7)

 

2.3 

 

(3.6)

 

 –

Improved recovery

2.0 

 

2.0 

 

 –

 

 –

 

2.0 

 

 –

Extensions and discoveries

31.6 

 

31.6 

 

27.2 

 

4.4 

 

 –

 

 –

Purchases of properties

4.7 

 

4.7 

 

4.7 

 

 –

 

 –

 

 –

Production

(33.2)

 

(33.2)

 

(16.9)

 

(4.1)

 

(12.2)

 

 –

December 31, 2017

328.1 

 

328.1 

 

224.7 

 

51.5 

 

51.9 

 

 –

Revisions of previous estimates

(15.3)

 

(15.3)

 

(15.0)

 

(8.0)

 

7.7 

 

 –

Improved recovery

0.8 

 

0.8 

 

 –

 

 –

 

0.8 

 

 –

Extensions and discoveries

58.9 

 

58.9 

 

42.9 

 

16.0 

 

 –

 

 –

Purchases of properties

93.6 

 

93.6 

 

92.3 

 

 –

 

1.3 

 

 –

Production

(33.6)

 

(33.6)

 

(18.4)

 

(4.5)

 

(10.7)

 

 –

     December 31, 2018 2

432.5 

 

432.5 

 

326.5 

 

55.0 

 

51.0 

 

 –

Proved developed crude
    oil/ synthetic oil reserves:

 

 

 

 

 

 

 

 

 

 

 

        December 31, 2015

326.6 

 

211.8 

 

125.9 

 

23.8 

 

62.1 

 

114.8 

        December 31, 2016

184.9 

 

184.9 

 

113.9 

 

19.2 

 

51.8 

 

 –

        December 31, 2017

185.5 

 

185.5 

 

126.3 

 

21.9 

 

37.3 

 

 –

        December 31, 2018 3

249.3 

 

249.3 

 

189.0 

 

23.3 

 

37.0 

 

 –

Proved undeveloped crude
    oil reserves:

 

 

 

 

 

 

 

 

 

 

 

        December 31, 2015

129.6 

 

129.6 

 

113.0 

 

4.1 

 

12.5 

 

 –

        December 31, 2016

144.1 

 

144.1 

 

100.5 

 

29.7 

 

13.9 

 

 –

        December 31, 2017

142.6 

 

142.6 

 

98.4 

 

29.6 

 

14.6 

 

 –

        December 31, 2018 4

183.2 

 

183.2 

 

137.5 

 

31.7 

 

14.0 

 

 –



1 All synthetic oil operations were sold in June 2016.

2 Includes total proved reserves of 25.5 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved developed reserves of 19.1 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

4 Includes proved undeveloped reserves of 6.4 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

103

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices

for 2015 – 2018 – Continued



2018 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates – The 2018 negative crude oil revision in the U.S. was primarily attributable to revised type curves and the removal of proved undeveloped locations outside the 5-year development window.  The negative Canadian oil reserves revisions in 2018 resulted from removing locations in lower performing areas of the Kaybob Duvernay as well as locations removed in Hibernia Offshore Canada due to updated operator development plans.  The positive revisions for crude oil reserves in Malaysia were principally attributable to continued development in Kakap field and improved performance in South Acis field.



Improved recovery – The 2018 Malaysia crude oil proved reserve addition was due to favorable impacts from gas lift activity at the Kikeh field.



Extensions and discoveries – In 2018, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay.  Proved oil reserves were also added for drilling activities in the U.S. offshore.



Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and oversees operations.  In addition, the Company acquired partial ownership in the Jagus East field in Brunei.



2017 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimatesThe 2017 negative crude oil revision in the U.S. was primarily attributable to the removal of proved undeveloped locations within the 5-year development window as capital was reallocated to higher performing drilling locations within the Company’s Eagle Ford Shale fields, partially offset by improved Eagle Ford Shale costs and performance results in the Gulf of Mexico.  The positive Canadian oil reserves revisions in 2017 resulted from improved performance at Tupper Montney assets in Western Canada, and offshore Canada fields, Hibernia and Terra Nova.  The negative revisions for crude oil reserves in Malaysia were principally attributable to the redetermination of Kakap participation that lowered the Company’s entitlement, and higher government entitlement under the terms of the respective production sharing contracts due to higher oil prices, offsetting positive performance revisions at the Company’s Sarawak projects.



Improved recovery – The 2017 Malaysia crude oil proved reserve addition was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.



Extensions and discoveries – In 2017, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and in Canada for drilling activities in the Montney and Duvernay.  Proved oil reserves were also added for drilling activities in the U.S. offshore.



Purchases of properties – In 2017, the Company acquired greater working interests in two of its operated Gulf of Mexico fields.  In U.S. onshore, the Company acquired acreage in the Permian area of west Texas.  Additional Eagle Ford Shale acreage was acquired through joint venture agreements with other operators within its core acreage position. 



2016 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes

Revisions of previous estimatesThe 2016 negative crude oil revision in the U.S. was primarily attributable to impacts of lower price on Eagle Ford Shale volumes and reduced performance in a particular location, partially offset by improved Eagle Ford Shale costs and drilling results in the Gulf of Mexico.  The positive Canadian oil reserves revisions in 2016 resulted from improved Kaybob Duvernay performance and an increase at Terra Nova due to development drilling.  The positive revisions for crude oil reserves in Malaysia was attributable to improved performance and lower government entitlement under the terms of the respective production sharing contracts due to lower oil prices, which collectively more than offset a negative revision at Kikeh following updated decline curve analysis.



104

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



2016 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes (Contd.)



Extensions and discoveries – In 2016, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and deeper oil-water contacts realized at a field in Malaysia.



Purchases of properties – In 2016, the Company’s Canadian subsidiary acquired working interests in the Kaybob Duvernay and liquids rich Placid Montney areas.  The crude oil reserves are all associated with the Kaybob Duvernay area.



Sales of properties – In the U.S., proved oil reserves were reduced following the sale of certain non-core Eagle Ford Shale acreage.  In Canada, the Company sold its interests in both a heavy oil field and a synthetic oil project.









105

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices 

for 2015 – 2018







 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

(Millions of barrels)

Total

 

United
States

 

Canada

 

Malaysia

 

Proved developed and undeveloped NGL reserves:

 

 

 

 

 

 

 

 

December 31, 2015

36.4 

 

35.4 

 

0.4 

 

0.6 

 

Revisions of previous estimates

1.6 

 

1.2 

 

0.2 

 

0.2 

 

Extensions and discoveries

2.9 

 

2.8 

 

0.1 

 

 –

 

Purchase of properties

5.1 

 

 –

 

5.1 

 

 –

 

Production

(3.5)

 

(3.0)

 

(0.2)

 

(0.3)

 

December 31, 2016

42.5 

 

36.4 

 

5.6 

 

0.5 

 

Revisions of previous estimates

1.3 

 

2.0 

 

(0.6)

 

(0.1)

 

Extensions and discoveries

7.8 

 

7.0 

 

0.8 

 

 –

 

Purchases of properties

0.5 

 

0.5 

 

 –

 

 –

 

Production

(3.2)

 

(2.9)

 

(0.2)

 

(0.1)

 

December 31, 2017

48.9 

 

43.0 

 

5.6 

 

0.3 

 

Revisions of previous estimates

(6.2)

 

(5.3)

 

(1.6)

 

0.7 

 

Extensions and discoveries

12.0 

 

9.7 

 

2.3 

 

 –

 

Purchases of properties

3.0 

 

3.0 

 

 –

 

 –

 

Production

(3.5)

 

(2.8)

 

(0.4)

 

(0.3)

 

     December 31, 2018 1

54.2 

 

47.6 

 

5.9 

 

0.7 

 

Proved developed NGL reserves:

 

 

 

 

 

 

 

 

        December 31, 2015

21.6 

 

20.7 

 

0.3 

 

0.6 

 

        December 31, 2016

22.2 

 

20.8 

 

0.9 

 

0.5 

 

        December 31, 2017

24.6 

 

23.3 

 

1.0 

 

0.3 

 

        December 31, 2018 2

27.3 

 

24.9 

 

1.7 

 

0.7 

 

Proved undeveloped NGL reserves:

 

 

 

 

 

 

 

 

        December 31, 2015

14.8 

 

14.7 

 

0.1 

 

 –

 

        December 31, 2016

20.3 

 

15.6 

 

4.7 

 

 –

 

        December 31, 2017

24.3 

 

19.7 

 

4.6 

 

 –

 

        December 31, 2018 3

26.9 

 

22.7 

 

4.2 

 

 –

 



1 Includes total proved reserves of 1.1 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 0.8 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved undeveloped reserves of 0.3 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

106

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices

for 2015 – 2018 – Continued



2018 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The negative 2018 NGL proved reserves revision in the U.S. was primarily in the Company’s Eagle Ford Shale fields based on removal of proved undeveloped locations outside the 5-year development window.  The negative Canadian NGL reserves revisions in 2018 resulted from removing locations in lower performing areas of the Kaybob Duvernay.  The positive revisions for NGL reserves in Malaysia were principally attributable to improved performance for gas fields offshore Sarawak.



Extensions and discoveries – In 2018, proved NGL reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay.



Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and oversees operations.





2017 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The positive 2017 NGL proved reserves revision in the U.S. was primarily in the Company’s Eagle Ford Shale fields based on an updated shrinkage ratio of liquids rich gas production combined with improved costs, offsetting removal of proved undeveloped locations from within the 5-year development window as capital was reallocated to higher performing drilling locations within the Eagle Ford Shale.



Extensions and discoveries – Proved NGL reserves were added primarily from drilling activities in the Eagle Ford Shale area concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves.



Purchase of properties – In U.S., proved NGL reserves were added following the acquisition of acreage in both the Eagle Ford Shale and Permian areas, and increased working interest in two Gulf of Mexico fields.



2016 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The positive 2016 NGL proved reserves revision was primarily in the Eagle Ford Shale area based on an updated ratio of oil to gas production.



Extensions and discoveries – Proved NGL reserves were added primarily from drilling activities in the Eagle Ford Shale area.



Purchase of properties – In Canada, proved NGL reserves were added following the acquisition of acreage in both the Kabob Duvernay and liquids rich Placid Montney areas.







107

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2015 – 2018





 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

(Billions of cubic feet)

Total

 

United
States

 

Canada

 

Malaysia

 

Proved developed and undeveloped
    natural gas reserves:

 

 

 

 

 

 

 

 

December 31, 2015

1,688.8 

 

232.4 

 

909.6 

 

546.8 

 

Revisions of previous estimates

43.3 

 

0.1 

 

45.3 

 

(2.1)

 

Improved recovery

164.2 

 

6.4 

 

120.2 

 

37.6 

 

Extensions and discoveries

122.3 

 

 –

 

122.3 

 

 –

 

Sales of properties

(2.2)

 

(0.1)

 

(2.1)

 

 –

 

Production

(138.4)

 

(19.4)

 

(76.4)

 

(42.6)

 

December 31, 2016

1,878.0 

 

219.4 

 

1,118.9 

 

539.7 

 

Revisions of previous estimates

(5.4)

 

(16.0)

 

19.4 

 

(8.8)

 

Extensions and discoveries

190.6 

 

32.2 

 

156.7 

 

1.7 

 

Purchases of properties

4.0 

 

4.0 

 

 –

 

 –

 

Production

(140.1)

 

(16.3)

 

(82.6)

 

(41.2)

 

December 31, 2017

1,927.1 

 

223.3 

 

1,212.4 

 

491.4 

 

Revisions of previous estimates

(1.8)

 

37.6 

 

(51.2)

 

11.8 

 

Improved recovery

0.6 

 

 –

 

 –

 

0.6 

 

Extensions and discoveries

310.3 

 

44.7 

 

261.0 

 

4.6 

 

Purchases of properties

61.7 

 

20.3 

 

41.4 

 

 –

 

Production

(154.3)

 

(16.9)

 

(97.2)

 

(40.2)

 

     December 31, 2018 1

2,143.6 

 

309.0 

 

1,366.4 

 

468.2 

 

Proved developed natural gas reserves:

 

 

 

 

 

 

 

 

        December 31, 2015

783.5 

 

148.3 

 

453.5 

 

181.7 

 

        December 31, 2016

818.1 

 

138.7 

 

498.9 

 

180.5 

 

        December 31, 2017

819.3 

 

127.7 

 

547.0 

 

144.6 

 

        December 31, 2018 2

921.6 

 

198.3 

 

595.0 

 

128.3 

 

Proved undeveloped natural gas reserves:

 

 

 

 

 

 

 

 

        December 31, 2015

905.3 

 

84.1 

 

456.1 

 

365.1 

 

        December 31, 2016

1,059.9 

 

80.7 

 

620.0 

 

359.2 

 

        December 31, 2017

1,107.8 

 

95.6 

 

665.5 

 

346.7 

 

        December 31, 2018  3

1,222.0 

 

110.7 

 

771.4 

 

339.9 

 



1 Includes total proved reserves of 10.8 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 8.2 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved undeveloped reserves of 2.6 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

108

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2015 – 2018 – Continued



2018 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates –  In 2018, the U.S. positive natural gas revision was primarily due to drilling within the Eagle Ford Shale.  The 2018 negative natural gas revisions in Canada resulted from removing locations in lower performing areas of the Kaybob Duvernay asset partially offset by positive performance revisions in the Tupper Montney asset.  The positive revision for natural gas reserves in Malaysia was primarily attributable to positive performance revisions at the Company’s Sarawak projects offset somewhat by negative Block H revisions attributable to higher government entitlement under the terms of the respective production sharing contracts due to higher gas prices.



Improved recovery – The 2018 Malaysia natural gas proved reserve addition was due to favorable impacts from gas lift activity at the Kikeh field.



Extensions and discoveries – In 2018, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale.  Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Tupper Montney and Kaybob Duvernay areas in Western Canada.  In Malaysia, proved natural gas reserves were added in the Merapuh field in Sarawak from field development activities.



Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and overseas operations.  In addition, the Company acquired acreage in Tupper Montney in Western Canada.



2017 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – In the U.S., the negative natural gas revision was primarily due to shutting in a gas well located in the Gulf of Mexico due to early water break through, and in the Company’s Eagle Ford Shale fields proved undeveloped locations were removed from within the 5-year development window as capital was reallocated to higher performing drilling locations within the Eagle Ford Shale.  The negative revision for natural gas reserves in Malaysia was primarily attributable to higher government entitlement under the terms of the respective production sharing contracts due to higher gas prices, offsetting positive performance revisions at the Company’s Sarawak projects.  The 2017 positive natural gas revisions in Canada were attributable to updated well type curves and field performance at the Tupper Montney assets in Western Canada. 



Extensions and discoveries – In 2017, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and field development drilling in the Gulf of Mexico.  Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Montney and Kaybob Duvernay areas in Western Canada.  In Malaysia, proved natural gas reserves were added in Sarawak from field development activities.



Purchase of properties – In the U.S., proved natural gas reserves were added following the acquisition of acreage in both the Eagle Ford Shale and Permian areas, and increased working interest in two Gulf of Mexico fields.



2016 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – The 2016 positive natural gas revisions in Canada were attributable to updated well type curves and field development techniques in both the Montney and Duvernay areas of Western Canada.  The negative revision for natural gas reserves in Malaysia was primarily attributable to the removal of Sarawak area proved reserves resulting from the government’s decision to delay certain field development plans.



Extensions and discoveries – In 2016, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale.  Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Tupper area.  In Malaysia, proved natural gas reserves were added in Block H as the Permai field was added to the field development plan.



Purchase of properties – In Canada, proved natural gas reserves were added following the acquisition of acreage in both the Kaybob Duvernay and liquids rich Placid Montney areas.

109

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



2016 Comments for Proved Natural Gas Reserves Changes (Contd.)



Sales of properties – Proved natural gas reserves were reduced following the sale of certain non-core Eagle Ford Shale acreage in the U.S. and the associated gas related to the sale of a heavy oil field in Canada.



110

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



Schedule 4 – Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities





 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

(Millions of dollars)

United
States

 

Canada

 

Malaysia

 

Other

 

Total

Year ended December 31, 2018

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

 

 

 

 

 

 

 

 

 

 

        Unproved

$

2.8 

 

– 

 

– 

 

0.2 

 

3.0 

        Proved

 

794.3 

 

– 

 

– 

 

– 

 

794.3 

                Total acquisition costs

 

797.1 

 

– 

 

– 

 

0.2 

 

797.3 

Exploration costs 1

 

88.1 

 

0.6 

 

2.2 

 

35.1 

 

126.0 

Development costs 1

 

853.7 

 

373.8 

 

145.9 

 

16.6 

 

1,390.0 

                Total costs incurred

 

1,738.9 

 

374.4 

 

148.1 

 

51.9 

 

2,313.3 

Charged to expense

 

 

 

 

 

 

 

 

 

 

        Dry hole expense

 

16.0 

 

– 

 

0.1 

 

4.5 

 

20.6 

        Geophysical and other costs

 

13.4 

 

0.6 

 

2.1 

 

31.3 

 

47.4 

                Total charged to expense

 

29.4 

 

0.6 

 

2.2 

 

35.8 

 

68.0 

Property additions

$

1,709.5 

 

373.8 

 

145.9 

 

16.1 

 

2,245.3 

Year ended December 31, 2017

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

 

 

 

 

 

 

 

 

 

 

        Unproved

$

50.4 

 

– 

 

– 

 

13.0 

 

63.4 

        Proved

 

7.7 

 

– 

 

– 

 

– 

 

7.7 

                Total acquisition costs

 

58.1 

 

– 

 

– 

 

13.0 

 

71.1 

Exploration costs 1

 

13.7 

 

0.6 

 

(8.9)

 

73.8 

 

79.2 

Development costs 1

 

508.4 

 

273.8 

 

35.7 

 

1.1 

 

819.0 

                Total costs incurred

 

580.2 

 

274.4 

 

26.8 

 

87.9 

 

969.3 

Charged to expense

 

 

 

 

 

 

 

 

 

 

        Dry hole expense

 

(1.9)

 

– 

 

0.7 

 

(3.0)

 

(4.2)

        Geophysical and other costs

 

9.7 

 

0.5 

 

1.7 

 

53.3 

 

65.2 

                Total charged to expense

 

7.8 

 

0.5 

 

2.4 

 

50.3 

 

61.0 

Property additions

$

572.4 

 

273.9 

 

24.4 

 

37.6 

 

908.3 

Year ended December 31, 2016

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

 

 

 

 

 

 

 

 

 

 

        Unproved

$

18.6 

 

– 

 

– 

 

– 

 

18.6 

        Proved

 

– 

 

206.7 

 

– 

 

– 

 

206.7 

                Total acquisition costs

 

18.6 

 

206.7 

– 

– 

 

– 

 

225.3 

Exploration costs 1

 

18.5 

 

3.6 

 

6.0 

 

42.0 

 

70.1 

Development costs 1

 

239.7 

 

165.1 

 

102.9 

 

0.3 

 

508.0 

                Total costs incurred

 

276.8 

 

375.4 

 

108.9 

 

42.3 

 

803.4 

Charged to expense

 

 

 

 

 

 

 

 

 

 

        Dry hole expense

 

0.4 

 

– 

 

4.5 

 

10.2 

 

15.1 

        Geophysical and other costs

 

5.7 

 

3.6 

 

0.7 

 

33.4 

 

43.4 

                Total charged to expense

 

6.1 

 

3.6 

 

5.2 

 

43.6 

 

58.5 

Property additions

$

270.7 

 

371.8 

 

103.7 

 

(1.3)

 

744.9 



1 Includes noncash asset retirement costs as follows:



 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

             2018

 

 

 

 

 

 

 

 

 

 

              Exploration costs

$

– 

 

– 

 

– 

 

– 

 

– 

              Development costs

 

366.0 

 

 –

 

7.3 

 

0.2 

 

373.5 



$

366.0 

 

 –

 

7.3 

 

0.20 

 

373.5 

              2017

 

 

 

 

 

 

 

 

 

 

              Exploration costs

$

– 

 

– 

 

– 

 

– 

 

– 

              Development costs

 

37.6 

 

6.3 

 

8.4 

 

– 

 

52.3 



$

37.6 

 

6.3 

 

8.4 

 

– 

 

52.3 

              2016

 

 

 

 

 

 

 

 

 

 

              Exploration costs

$

– 

 

 –

 

 –

 

– 

 

 –

              Development costs

 

0.9 

 

10.5 

 

2.3 

 

– 

 

13.7 



$

0.9 

 

10.5 

 

2.3 

 

– 

 

13.7 





111

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



Schedule 5 – Results of Operations for Oil and Gas Producing Activities 1



 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 



United

 

 

 

 

 

 

 

 

 

(Millions of dollars)

States

 

Canada

 

 

Malaysia

 

Other

 

Total

Year ended December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

    Crude oil and natural gas liquids sales

$

1,245.3 

 

291.2 

 

 

708.8 

 

6.1 

 

2,251.4 

    Natural gas sales

 

42.9 

 

147.6 

 

 

144.7 

 

– 

 

335.2 

            Total oil and gas revenues

 

1,288.2 

 

438.8 

 

 

853.5 

 

6.1 

 

2,586.6 

    Other operating revenues

 

1.4 

 

(0.2)

 

 

0.7 

 

16.1 

 

18.0 

            Total revenues

 

1,289.6 

 

438.6 

 

 

854.2 

 

22.2 

 

2,604.6 

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

    Lease operating expenses

 

230.5 

 

122.6 

 

 

202.1 

 

0.7 

 

555.9 

    Severance and ad valorem taxes

 

50.9 

 

1.2 

 

 

– 

 

– 

 

52.1 

    Exploration costs charged to expense

 

29.4 

 

0.6 

 

 

2.2 

 

31.6 

 

63.8 

    Undeveloped lease amortization

 

36.8 

 

0.8 

 

 

– 

 

2.5 

 

40.1 

    Depreciation, depletion and amortization

 

519.5 

 

232.4 

 

 

198.6 

 

3.5 

 

954.0 

    Accretion of asset retirement obligations

 

19.5 

 

7.7 

 

 

17.4 

 

– 

 

44.6 

    Impairment of assets

 

20.0 

 

– 

 

 

– 

 

– 

 

20.0 

    Redetermination expense

 

– 

 

– 

 

 

11.3 

 

– 

 

11.3 

    Selling and general expenses

 

49.0 

 

26.8 

 

 

10.8 

 

23.5 

 

110.1 

    Other expenses (benefits)

 

23.0 

 

(19.1)

 

 

(1.0)

 

2.3 

 

5.2 

            Total costs and expenses

 

978.6 

 

373.0 

 

 

441.4 

 

64.1 

 

1,857.1 

            Results of operations before taxes

 

311.0 

 

65.6 

 

 

412.8 

 

(41.9)

 

747.5 

    Income tax expense (benefit)

 

68.1 

 

14.5 

 

 

143.3 

 

(25.3)

 

200.6 

            Results of operations

$

242.9 

 

51.1 

 

 

269.5 

 

(16.6)

 

546.9 

Year ended December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

    Crude oil and natural gas liquids sales

$

903.7 

 

203.7 

 

 

639.9 

 

– 

 

1,747.3 

    Natural gas sales

 

37.9 

 

155.1 

 

 

138.2 

 

– 

 

331.2 

            Total oil and gas revenues

 

941.6 

 

358.8 

 

 

778.1 

 

– 

 

2,078.5 

    Other operating revenues

 

2.7 

 

126.7 

 

 

3.0 

 

– 

 

132.4 

            Total revenues

 

944.3 

 

485.5 

 

 

781.1 

 

– 

 

2,210.9 

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

    Lease operating expenses

 

198.5 

 

101.1 

 

 

168.8 

 

– 

 

468.4 

    Severance and ad valorem taxes

 

42.2 

 

1.5 

 

 

– 

 

– 

 

43.7 

    Exploration costs charged to expense

 

7.8 

 

0.5 

 

 

2.4 

 

50.3 

 

61.0 

    Undeveloped lease amortization

 

60.2 

 

1.6 

 

 

– 

 

– 

 

61.8 

    Depreciation, depletion and amortization

 

546.1 

 

185.4 

 

 

204.6 

 

3.8 

 

939.9 

    Accretion of asset retirement obligations

 

17.4 

 

7.9 

 

 

17.3 

 

– 

 

42.6 

    Redetermination expense

 

– 

 

– 

 

 

15.0 

 

– 

 

15.0 

    Selling and general expenses

 

61.8 

 

28.3 

 

 

14.0 

 

19.6 

 

123.7 

    Other expenses

 

20.0 

 

2.3 

 

 

8.4 

 

– 

 

30.7 

            Total costs and expenses

 

954.0 

 

328.6 

 

 

430.5 

 

73.7 

 

1,786.8 

            Results of operations before taxes

 

(9.7)

 

156.9 

 

 

350.6 

 

(73.7)

 

424.1 

    Income tax expense (benefit)

 

(0.8)

 

44.4 

 

 

126.4 

 

(36.2)

 

133.8 

            Results of operations

$

(8.9)

 

112.5 

 

 

224.2 

 

(37.5)

 

290.3 

1 Results exclude corporate overhead, interest and discontinued operations. 2018 includes noncontrolling interest in MP GOM.















112

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



Schedule 5 – Results of Operations for Oil and Gas Producing Activities 1 – Continued







 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

Canada

 

 

 

 

 

 



United

 

Conven-

 

 

 

 

 

 

 

 

(Millions of dollars)

States

 

tional

 

Synthetic

 

Malaysia

 

Other

 

Total

Year ended December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

    Crude oil and natural gas liquids sales

$

714.1 

 

171.7 

 

60.7 

 

623.7 

 

– 

 

1,570.2 

    Natural gas sales

 

35.1 

 

130.0 

 

– 

 

127.6 

 

– 

 

292.7 

            Total oil and gas revenues

 

749.2 

 

301.7 

 

60.7 

 

751.3 

 

– 

 

1,862.9 

    Other operating revenues

 

(0.1)

 

(0.7)

 

3.6 

 

2.1 

 

0.2 

 

5.1 

            Total revenues

 

749.1 

 

301.0 

 

64.3 

 

753.4 

 

0.2 

 

1,868.0 

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

    Lease operating expenses

 

218.6 

 

102.6 

 

69.8 

 

168.4 

 

– 

 

559.4 

    Severance and ad valorem taxes

 

37.0 

 

4.3 

 

2.5 

 

– 

 

– 

 

43.8 

    Exploration costs charged to expense

 

6.1 

 

3.6 

 

– 

 

5.2 

 

43.6 

 

58.5 

    Undeveloped lease amortization

 

38.4 

 

4.5 

 

– 

 

– 

 

0.5 

 

43.4 

    Depreciation, depletion and amortization

 

600.5 

 

186.7 

 

16.5 

 

227.7 

 

5.9 

 

1,037.3 

    Accretion of asset retirement obligations

 

17.1 

 

10.9 

 

2.4 

 

16.3 

 

– 

 

46.7 

    Impairment of assets

 

– 

 

95.1 

 

– 

 

– 

 

– 

 

95.1 

    Redetermination expense

 

– 

 

– 

 

– 

 

39.1 

 

– 

 

39.1 

    Selling and general expenses

 

54.0 

 

28.2 

 

0.5 

 

15.4 

 

33.6 

 

131.7 

    Other expenses

 

7.3 

 

7.9 

 

– 

 

24.3 

 

(9.9)

 

29.6 

            Total costs and expenses

 

979.0 

 

443.8 

 

91.7 

 

496.4 

 

73.7 

 

2,084.6 

            Results of operations before taxes

 

(229.9)

 

(142.8)

 

(27.4)

 

257.0 

 

(73.5)

 

(216.6)

    Income tax expense (benefit)

 

(65.7)

 

(58.9)

 

(75.4)

 

85.9 

 

(18.8)

 

(132.9)

            Results of operations

$

(164.2)

 

(83.9)

 

48.0 

 

171.1 

 

(54.7)

 

(83.7)



1 Results exclude corporate overhead, interest and discontinued operations.

 

113

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



Schedule 6 – Standardized Measure of Discounted Future Net Cash Flows Relating to

Proved Oil and Gas Reserves 1





 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

(Millions of dollars)

United
States

 

Canada

 

Malaysia

 

Total

December 31, 2018

 

 

 

 

 

 

 

 

Future cash inflows

$

23,473.9 

 

5,437.5 

 

5,511.6 

 

34,423.0 

Future development costs

 

(3,279.1)

 

(1,362.7)

 

(517.4)

 

(5,159.2)

Future production costs

 

(7,279.5)

 

(2,693.0)

 

(2,813.4)

 

(12,785.9)

Future income taxes

 

(2,216.5)

 

(236.4)

 

(472.0)

 

(2,924.9)

        Future net cash flows

 

10,698.8 

 

1,145.4 

 

1,708.8 

 

13,553.0 

10% annual discount for estimated timing
    of cash flows

 

(4,295.4)

 

(531.4)

 

(446.3)

 

(5,273.1)

        Standardized measure of discounted
            future net cash flows

$

6,403.4 

 

614.0 

 

1,262.5 

 

8,279.9 

December 31, 2017

 

 

 

 

 

 

 

 

Future cash inflows

$

12,885.8 

 

4,714.3 

 

4,392.0 

 

21,992.1 

Future development costs

 

(2,079.5)

 

(1,081.7)

 

(632.3)

 

(3,793.5)

Future production costs

 

(4,765.3)

 

(2,507.4)

 

(2,305.0)

 

(9,577.7)

Future income taxes

 

(893.7)

 

(161.1)

 

(232.2)

 

(1,287.0)

        Future net cash flows

 

5,147.3 

 

964.1 

 

1,222.5 

 

7,333.9 

10% annual discount for estimated timing
    of cash flows

 

(2,698.2)

 

(394.6)

 

(318.2)

 

(3,411.0)

        Standardized measure of discounted
            future net cash flows

$

2,449.1 

 

569.5 

 

904.3 

 

3,922.9 

December 31, 2016

 

 

 

 

 

 

 

 

Future cash inflows

$

9,477.9 

 

3,752.7 

 

4,318.7 

 

17,549.3 

Future development costs

 

(1,691.1)

 

(1,143.6)

 

(763.8)

 

(3,598.5)

Future production costs

 

(3,981.6)

 

(2,329.7)

 

(2,661.2)

 

(8,972.5)

Future income taxes

 

(118.9)

 

(81.3)

 

(73.3)

 

(273.5)

        Future net cash flows

 

3,686.3 

 

198.1 

 

820.4 

 

4,704.8 

10% annual discount for estimated timing
    of cash flows

 

(1,799.5)

 

(95.0)

 

(230.3)

 

(2,124.8)

        Standardized measure of discounted
            future net cash flows

$

1,886.8 

 

103.1 

 

590.1 

 

2,580.0 

1  2018 includes noncontrolling interest in MP GOM.

114

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued



Schedule 6 – Standardized Measure of Discounted Future Net Cash Flows Relating to

Proved Oil and Gas Reserves – Continued 1



Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.







 

 

 

 

 

 



 

 

 

 

 

 

(Millions of dollars)

 

2018

 

2017

 

2016

Net changes in prices and production costs

$

2,972.6 

 

2,428.4 

 

(1,476.1)

Net changes in development costs

 

(1,891.1)

 

(724.4)

 

544.9 

Sales and transfers of oil and gas produced, net of production costs

 

(1,978.6)

 

(1,576.0)

 

(1,196.3)

Net change due to extensions and discoveries

 

1,930.3 

 

807.9 

 

280.5 

Net change due to purchases and sales of proved reserves

 

3,152.4 

 

85.9 

 

(583.4)

Development costs incurred 

 

1,017.3 

 

802.7 

 

479.6 

Accretion of discount

 

469.5 

 

270.9 

 

428.1 

Revisions of previous quantity estimates

 

(347.8)

 

(109.5)

 

(49.2)

Net change in income taxes

 

(967.6)

 

(643.0)

 

292.8 

       Net increase (decrease)

 

4,357.0 

 

1,342.9 

 

(1,279.1)

Standardized measure at January 1

 

3,922.9 

 

2,580.0 

 

3,859.1 

       Standardized measure at December 31

$

8,279.9 

 

3,922.9 

 

2,580.0 

1 2018 includes noncontrolling interest in MP GOM.



Schedule 7 – Capitalized Costs Relating to Oil and Gas Producing Activities





 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

(Millions of dollars)

United
States

 

Canada

 

Malaysia

 

Other

 

Total

December 31, 2018

 

 

 

 

 

 

 

 

 

 

Unproved oil and gas properties

$

394.2 

 

250.0 

 

21.2 

 

176.9 

 

842.3 

Proved oil and gas properties

 

11,678.3 

 

3,693.0 

 

6,263.5 

 

– 

 

21,634.8 

            Gross capitalized costs

 

12,072.5 

 

3,943.0 

 

6,284.7 

 

176.9 

 

22,477.1 

Accumulated depreciation,
    depletion and amortization

 

 

 

 

 

 

 

 

 

 

        Unproved oil and gas properties

 

(129.3)

 

(213.5)

 

– 

 

(25.4)

 

(368.2)

        Proved oil and gas properties

 

(5,433.7)

 

(2,088.8)

 

(4,963.5)

 

– 

 

(12,486.0)

            Net capitalized costs

$

6,509.5 

 

1,640.7 

 

1,321.2 

 

151.5 

 

9,622.9 

December 31, 2017

 

 

 

 

 

 

 

 

 

 

Unproved oil and gas properties

$

360.9 

 

286.8 

 

20.5 

 

162.1 

 

830.3 

Proved oil and gas properties

 

9,606.4 

 

3,603.4 

 

6,139.7 

 

– 

 

19,349.5 

            Gross capitalized costs

 

9,967.3 

 

3,890.2 

 

6,160.2 

 

162.1 

 

20,179.8 

Accumulated depreciation,
    depletion and amortization

 

 

 

 

 

 

 

 

 

 

        Unproved oil and gas properties

 

(149.5)

 

(230.7)

 

– 

 

(21.8)

 

(402.0)

        Proved oil and gas properties

 

(4,893.8)

 

(2,027.9)

 

(4,774.5)

 

– 

 

(11,696.2)

            Net capitalized costs

$

4,924.0 

 

1,631.6 

 

1,385.7 

 

140.3 

 

8,081.6 





Note:Unproved oil and gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells, and exploratory wells capitalized pending further evaluation.

 

115

 


 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)







 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

(Millions of dollars except per share amounts)

First
Quarter

 

Second
Quarter

 

Third
Quarter

 

Fourth
Quarter

 

Year

Year ended December 31, 2018  1

 

 

 

 

 

 

 

 

 

 

Revenue from contracts with customers

$

606.9 

 

655.2 

 

659.8 

 

664.7 

 

2,586.6 

Income (loss) from continuing operations before
    income taxes

 

97.0 

 

82.3 

 

146.8 

 

106.2 

 

432.3 

Income (loss) from continuing operations

 

168.7 

 

45.9 

 

95.8 

 

112.6 

 

423.0 

Net income including noncontrolling interest

 

168.3 

 

45.5 

 

93.9 

 

111.8 

 

419.5 

Net income attributable to Murphy

 

168.3 

 

45.5 

 

93.9 

 

103.4 

 

411.1 

Income (loss) from continuing operations per
    Common share

 

 

 

 

 

 

 

 

 

 

        Basic

 

0.98 

 

0.26 

 

0.55 

 

0.60 

 

2.39 

        Diluted

 

0.97 

 

0.26 

 

0.55 

 

0.59 

 

2.37 

Net income (loss) per Common share

 

 

 

 

 

 

 

 

 

 

        Basic

 

0.97 

 

0.26 

 

0.54 

 

0.60 

 

2.38 

        Diluted

 

0.96 

 

0.26 

 

0.54 

 

0.59 

 

2.36 

Cash dividend per Common share

 

0.25 

 

0.25 

 

0.25 

 

0.25 

 

1.00 

Year ended December 31, 2017

 

 

 

 

 

 

 

 

 

 

Revenue from contracts with customers

$

509.0 

 

477.6 

 

511.2 

 

580.5 

 

2,078.5 

Loss from continuing operations before
    income taxes

 

154.9 

 

(21.9)

 

(63.6)

 

2.4 

 

71.8 

Income (loss) from continuing operations

 

57.5 

 

(17.3)

 

(66.3)

 

(284.8)

 

(310.9)

Net income (loss) attributable to Murphy

 

58.5 

 

(17.6)

 

(65.9)

 

(286.8)

 

(311.8)

Income from continuing operations per
    Common share

 

 

 

 

 

 

 

 

 

 

        Basic

 

0.33 

 

(0.10)

 

(0.38)

 

(1.65)

 

(1.81)

        Diluted

 

0.33 

 

(0.10)

 

(0.38)

 

(1.65)

 

(1.81)

Net income (loss) per Common share

 

 

 

 

 

 

 

 

 

 

        Basic

 

0.34 

 

(0.10)

 

(0.38)

 

(1.66)

 

(1.81)

        Diluted

 

0.34 

 

(0.10)

 

(0.38)

 

(1.66)

 

(1.81)

Cash dividend per Common share

 

0.25 

 

0.25 

 

0.25 

 

0.25 

 

1.00 

1  2018 includes noncontrolling interest in MP GOM.



  

























 

116

 


 

 

 

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SCHEDULE II - VALUATION ACCOUNTS AND RESERVES







 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

(Millions of dollars)

Balance at
January 1

 

Charged
to Expense

 

Deductions

 

Other 1

 

Balance at
December 31

2018

 

 

 

 

 

 

 

 

 

 

Deducted from asset accounts:

 

 

 

 

 

 

 

 

 

 

        Allowance for doubtful accounts

$

1.6 

 

– 

 

– 

 

– 

 

1.6 

        Deferred tax asset valuation allowance

 

476.3 

 

3.3 

 

– 

 

(265.9)

 

213.7 

2017

 

 

 

 

 

 

 

 

 

 

Deducted from asset accounts:

 

 

 

 

 

 

 

 

 

 

        Allowance for doubtful accounts

$

1.6 

 

– 

 

– 

 

– 

 

1.6 

        Deferred tax asset valuation allowance

 

305.4 

 

18.6 

 

– 

 

152.3 

 

476.3 

2016

 

 

 

 

 

 

 

 

 

 

Deducted from asset accounts:

 

 

 

 

 

 

 

 

 

 

        Allowance for doubtful accounts

$

1.6 

 

– 

 

– 

 

– 

 

1.6 

        Deferred tax asset valuation allowance

 

294.4 

 

25.7 

 

– 

 

(14.7)

 

305.4 



1Amounts in 2017 and 2016 for deferred tax asset valuations are primarily associated with an increase in foreign tax credit carryforwards.  The amount in 2018 for deferred tax asset valuation allowance is primarily associated with utilization of foreign tax credit carryforwards. 

 





117


 

 



 

GLOSSARY

ABBREVIATIONS

3D seismic
three-dimensional images created by bouncing sound waves off underground rock formations that are used to determine the best places to drill for hydrocarbons

deepwater
offshore location in greater than 1,000 feet of water

downstream
refining and marketing operations

dry hole
an unsuccessful exploration well that is plugged and abandoned, with associated costs written off to expense

exploratory
wildcat and delineation, e.g., exploratory wells

hydrocarbons
organic chemical compounds of hydrogen and carbon atoms that form the basis of all petroleum products

oil sands
tar-like hydrocarbon-bearing substance that occurs naturally in certain areas at the Earth’s surface or at relatively shallow depths and which can be recovered, processed and upgraded into a light, sweet synthetic crude oil

operator
the company serving as the manager and often the decision-maker of a drilling or production project

production sharing contract
agreement between extracting company(ies) and a host country regarding each party’s share of production after stipulated exploratory and development costs are recovered

synthetic oil
a light, sweet crude oil produced by upgrading bitumen recovered from oil sands

unitization
combining of multiple mineral or leasehold interests to be able to produce from a common reservoir

upstream
oil and natural gas exploration and production operations, including synthetic oil operation

working interest
right to drill and produce oil and gas on the leased acreage, as well as the obligation to pay costs

ARO - Asset Retirement Obligation

ASU - Accounting Standards Update

BCF - Billion cubic feet

BOED - Barrel of oil equivalent per day

FASB - Financial Accounting Standards Board

FLNG - Floating Liquified Natural Gas

GAAP - U.S. Generally Accepted Accounting Principles

GK - Gumusut/Kakap

MCF - Thousand cubic feet

MMBOE - Million barrels of oil equivalent

MMCF - Million cubic feet

MMCFD – Million cubic feet per day

MOCL - Murphy Oil Company Ltd.

NCI - Noncontrolling interest

NYMEX - New York Mercantile Exchange

OSHA - Occupational Safety and Health Act

PAI – Petrobras Americas Inc., a subsidiary of Petróleo Brasileiro S.A.

QRE - Qualified Reserve Estimators

SEC - U.S. Securities and Exchange Commission

UFA - Unitization Framework Agreement

WCSB - Western Canadian Sedimentary Basin

WTI - West Texas Intermediate



 


Exhibit 21 for Q4 2018

Exhibit 2.1

 

CONTRIBUTION AGREEMENT

AMONG

MURPHY EXPLORATION & PRODUCTION COMPANY - USA

PETROBRAS AMERICA INC. AND

MP GULF OF MEXICO, LLC

Dated as of October 10, 2018.



 


 

TABLE OF CONTENTS

 



 

 



 

Page

ARTICLE 1    DEFINITIONS



 

 

Section 1.1

Certain Definitions



 

ARTICLE 2    ORGANIZATION OF JVCO LLC

18 



 

 

Section 2.1

JVCo LLC

18 

Section 2.2

Initial Transfers

18 

Section 2.3

Effective Time; Proration of Costs and Revenues

19 



 

ARTICLE 3    ADJUSTMENTS TO INITIAL PAI PAYMENT

20 



 

 

Section 3.1

MEPU Adjustments to

20 

Section 3.2

PAI Adjustments to

22 

Section 3.3

Effect of Adjustments

24 

Section 3.4

Allocation of Initial PAI Payment for Tax Purposes

24 

Section 3.5

Withholding

25 



 

ARTICLE  4    CONSENTS; PREFERENTIAL RIGHTS; AND CASUALTY LOSSES

25 



 

 

Section 4.1

Consents to Assignment and Preferential Rights to Purchase

25 

Section 4.2

Casualty or Condemnation Loss

28 



 

ARTICLE 5    REPRESENTATIONS AND WARRANTIES OF MEPU

29 



 

 

Section 5.1

Disclaimers

29 

Section 5.2

Existence and Qualification

31 

Section 5.3

Liability for Brokers’ Fees

32 

Section 5.4

Litigation

32 

Section 5.5

Taxes and Assessments

32 

Section 5.6

Title

33 

Section 5.7

Environmental

33 

Section 5.8

Outstanding Capital Commitments

34 

Section 5.9

Compliance with Laws

34 

Section 5.10

Contracts

34 

Section 5.11

Payments for Production

36 

Section 5.12

Imbalances

36 

Section 5.13

Consents and Preferential Purchase Rights

36 

Section 5.14

Permits

36 

Section 5.15

Wells; Decommissioning Activities

37 

Section 5.16

Equipment

37 

Section 5.17

Condemnation and Eminent Domain

38 

Section 5.18

Bankruptcy

38 

Section 5.19

Foreign Person

38 

Section 5.20

Payout Status

38 

Section 5.21

Operation of the MEPU Assets

38 

i

 


 

 



 

 

Section 5.22

Royalties

38 

Section 5.23

Suspense Funds

38 

Section 5.24

Bonds and Credit Support

39 

Section 5.25

Non-Consent Operations

39 

Section 5.26

Assets Complete

39 

Section 5.27

Intellectual Property

39 

Section 5.28

Ownership of Units

39 

Section 5.29

No Business Conduct

39 

Section 5.30

Ownership of JVCo

40 

Section 5.31

Anticorruption

40 

Section 5.32

Seismic Data

40 



 

ARTICLE 6    REPRESENTATIONS AND WARRANTIES OF PAI

40 



 

 

Section 6.1

Disclaimers

40 

Section 6.2

Existence and Qualification

42 

Section 6.3

Liability for Brokers’ Fees

43 

Section 6.4

Litigation

43 

Section 6.5

Taxes and Assessments

44 

Section 6.6

Title

44 

Section 6.7

Environmental

44 

Section 6.8

Outstanding Capital Commitments

45 

Section 6.9

Compliance with Laws

45 

Section 6.10

Contracts

45 

Section 6.11

Payments for Production

47 

Section 6.12

Imbalances

48 

Section 6.13

Consents and Preferential Purchase Rights

48 

Section 6.14

Permits

48 

Section 6.15

Wells; Decommissioning Activities

48 

Section 6.16

Equipment

49 

Section 6.17

Condemnation and Eminent Domain

49 

Section 6.18

Bankruptcy

49 

Section 6.19

Foreign Person

49 

Section 6.20

Payout Status

49 

Section 6.21

Operation of the PAI Assets

49 

Section 6.22

Royalties

49 

Section 6.23

Suspense Funds

50 

Section 6.24

Bonds and Credit Support

50 

Section 6.25

Non-Consent Operations

50 

Section 6.26

Assets Complete

50 

Section 6.27

Intellectual Property

50 

Section 6.28

Anticorruption

50 



 

ARTICLE 7    COVENANTS OF THE PARTIES

51 



 

 

Section 7.1

Access

51 

Section 7.2

Confidentiality; Public Announcements

52 









ii

 


 

 

Section 7.3

Operation of Business

52 

Section 7.4

HSR Filings

54 

Section 7.5

FCC Filings

55 

Section 7.6

Tax Matters

55 

Section 7.7

Further Assurances; Recording

57 

Section 7.8

Operatorship; Royalties

57 

Section 7.9

No Shop

57 

Section 7.10

Representations and Warranties

57 

Section 7.11

Closing Conditions

58 

Section 7.12

Debranding

58 

Section 7.13

NORM

58 

Section 7.14

Decommissioning

58 

Section 7.15

Amendment of Schedules

59 

Section 7.16

Transfer Orders and Letters in Lieu

59 

Section 7.17

No Business Conduct

59 

Section 7.18

Environmental Defects

60 

Section 7.19

Anticorruption

60 



 

ARTICLE 8    CONDITIONS TO CLOSING

61 



 

 

Section 8.1

Conditions of MEPU to Closing

61 

Section 8.2

Conditions of PAI to Closing

62 



 

ARTICLE 9    CLOSING

63 



 

 

Section 9.1

Time and Place of Closing

63 

Section 9.2

Obligations of MEPU at Closing

64 

Section 9.3

Obligations of PAI at Closing

65 

Section 9.4

Closing Cash and Post-Closing Adjustments

66 



 

ARTICLE 10    TERMINATION

69 



 

 

Section 10.1

Termination

69 

Section 10.2

Effect of Termination

70 



 

ARTICLE 11    INDEMNIFICATIONS; LIMITATIONS

70 



 

 

Section 11.1

Assumption of Obligations; Retained Liabilities

70 

Section 11.2

Indemnification

71 

Section 11.3

Indemnification Actions

72 

Section 11.4

Limitation on Actions

75 

Section 11.5

Non-Compensatory Damages

77 

Section 11.6

Exclusive Remedy and Release

77 

Section 11.7

Opportunity for Review

78 



 

ARTICLE 12    MISCELLANEOUS

78 



 

 

Section 12.1

Exhibits and Schedules

78 







iii

 


 

 

Section 12.2

Expenses

78 

Section 12.3

Counterparts

78 

Section 12.4

Notices

78 

Section 12.5

Sales or Use Tax, Recording Fees and Similar Taxes and Fees

79 

Section 12.6

Severability

80 

Section 12.7

Replacement of Bonds, Letters of Credit and Guarantees

80 

Section 12.8

Records

80 

Section 12.9

Governing Law; Jurisdiction; Venue; Jury Waiver

81 

Section 12.10

Dispute Resolution

82 

Section 12.11

Captions

83 

Section 12.12

Waiver; Rights Cumulative

83 

Section 12.13

Assignment

83 

Section 12.14

Entire Agreement

83 

Section 12.15

Amendment

84 

Section 12.16

No Third Party Beneficiaries

84 

Section 12.17

References

84 

Section 12.18

Construction

85 

Section 12.19

No Partnership Created

85 



 



 

 

EXHIBITS:

 

 

Exhibit A-1

-

Leases and Units; Working Interest; Net Revenue Interest

Exhibit A-2

-

Wells

Exhibit A-3

-

Easement

Exhibit A-4

-

Equipment

Exhibit A-5

-

Certain Real Property

Exhibit B

-

Form of MEPU Conveyance

Exhibit C

-

Form of PAI Conveyance

Exhibit D

-

Form of Units Conveyance

Exhibit E

-

LLC Formation Document

Exhibit F

-

Form of LLC Agreement

Exhibit G

-

Form of Master Services Agreement

Exhibit H

-

Form of PAI Parent Guarantee



 

 



 

 

SCHEDULES:

 

 

Schedule 1.1(f)(ii)

-

Contracts

Schedule 1.1(y)(xiii)

-

Certain Intellectual Property

Schedule 1.1(y)(xiv)

-

Certain Excluded Agreements

Schedule 1.1(y)(xv)

-

Certain Excluded Assets

Schedule 3.4

-

Allocation Schedule

Schedule 5.1(f)

-

MEPU Knowledge Persons

Schedule 5.2(d)

-

Conflicts

Schedule 5.4

-

Litigation

Schedule 5.5

-

Taxes

Schedule 5.7

-

Environmental

Schedule 5.8

-

Outstanding Capital Commitments

Schedule 5.9

-

Compliance with Laws









iv

 


 

 

Schedule 5.10(a)

-

MEPU Material Contracts

Schedule 5.11

-

Payments for Production

Schedule 5.12

-

Imbalances

Schedule 5.13

-

Consents and Preferential Rights

Schedule 5.15

-

Wells; Decommissioning Activities

Schedule 5.20

-

Payout Status

Schedule 5.23

-

Suspense Funds

Schedule 5.24

-

Credit Support

Schedule 5.25

-

Non-Consent Operations

Schedule 5.27

-

Intellectual Property

Schedule 5.28

-

Medusa Spar Encumbrances

Schedule 6.1(f)

-

PAI Knowledge Persons

Schedule 6.4

-

Litigation

Schedule 6.5

-

Taxes

Schedule 6.7

-

Environmental

Schedule 6.8

-

Outstanding Capital Commitments

Schedule 6.9

-

Compliance with Laws

Schedule 6.10(a)

-

PAI Material Contracts

Schedule 6.11

-

Payments for Production

Schedule 6.12

-

Imbalances

Schedule 6.13

-

Consents and Preferential Rights

Schedule 6.15

-

Wells; Decommissioning Activities

Schedule 6.20

-

Payout Status

Schedule 6.23

-

Suspense Funds

Schedule 6.24

-

Credit Support

Schedule 6.25

-

Non-Consent Operations

Schedule 6.27

-

Intellectual Property

Schedule 7.3

-

Operation of Business

Schedule 7.9

-

No Shop









































v

 


 

 



 

Index of Defined Terms

Defined Term

Section



 

AFEs

5.8 

Affiliate

1.1(a)

Agreed Allocated Value

1.1(b)

Agreement

Preamble

Allocable Amount

3.4 

Allocation Schedule

3.4 

Anticorruption Law

1.1(c)

Applicable Interest

1.1(d)

Asset Taxes

1.1(e)

Assets

1.1(f)

Assumed Obligations

11.1(a)

BOEM

1.1(g)

BSEE

1.1(h)

Business Day

1.1(i)

BW Pioneer

1.1(j)

Cascade Operating Agreement

1.1(k)

Casualty Loss

4.2(a)

Casualty Loss Threshold

4.2(b)

Chinook Operating Agreement

1.1(l)

Claim Notice

11.3(c)

Closing

9.1 

Closing Date

9.1 

Code

1.1(m)

Confidentiality Agreement

7.1 

Consent

1.1(n)

Consent Request Notice

4.1(a)

Contracts

1.1(f)(ii)

Controlled Representatives

1.1(o)

Conveyance

9.3(a)

Cottonwood Operating Agreement

1.1(p)

Customary Post-Closing Consents

1.1(q)

Decommissioning

1.1(r)

Defensible Title

1.1(s)

Dispute

12.1 

DTPA

5.1(d)

Due Inquiry

1.1(t)

Easements

1.1(f)(iii)

Effective Time

1.1(u)

Encumbrance

1.1(v)

Environmental Defect

1.1(w)

Environmental Laws

1.1(x)

Equipment

1.1(f)(iv)

Excluded Assets

1.1(y)







vi

 


 

 

Execution Date

Preamble

Final Settlement Statements

9.4(d)(ii)

Fundamental Representations

11.4(h)

GAAP

1.1(uu)(v)

Governmental Authority

1.1(z)

Hazardous Substances

1.1(aa)

HSR Act

1.1(bb)

Hydrocarbons

1.1(cc)

Imbalance

1.1(dd)

Income Taxes

1.1(ee)

Indebtedness

1.1(ff)

Indemnified Party

11.3(a)

Indemnifying Party

11.3(a)

Initial PAI Payment

Recitals

Initial Transfers

2.2 

Intellectual Property

1.1(f)(ix)

Interest Period

1.1(d)

JIB

1.1(gg)

JIB Expenses

1.1(hh)

JV Party

1.1(ii)

JVCo

Preamble

knowledge (with respect to MEPU)

5.1(f)

knowledge (with respect to PAI)

6.1(f)

Lands

1.1(f)(i)

Laws

1.1(jj)

Leases

1.1(f)(i)

Liabilities

1.1(kk)

LIBOR Reference Rate

1.1(ll)

Line Fill

1.1(mm)

LLC Agreement

2.1(d)

LLC Formation Document

2.1(a)

Longstop Date

10.1(b)

Losses Arbitrator

12.10(c)

Master Services Agreement

Recitals

Medusa Spar

Recitals

Medusa Spar Company Agreement

1.1(nn)

Medusa Spar Units

Recitals

Member

2.1(b)

MEPU

Preamble

MEPU Assets

2.2(a)

MEPU Adjustment Amount

3.1 

MEPU Cash Contribution

2.2(d)

MEPU Closing Adjustment Amount

9.4(c)(i)

MEPU Conveyance

9.2(a)

MEPU Credit Agreement

8.1(h)

MEPU Final Settlement Statement

9.4(d)(i)







vii

 


 

 

MEPU Indemnified Parties

11.2(a)

MEPU Material Adverse Effect

1.1(oo)

MEPU Material Contracts

5.10(a)

MEPU Preliminary Settlement Statement

9.4(a)(i)

MEPU Suspense Funds

5.23 

Negotiation Representatives

12.10(a)

Net Revenue Interest

1.1(pp)

NORM

1.1(qq)

Operating Expenses

2.3(c)

Organizational Documents

1.1(rr)

PAI Assets

2.2(c)

PAI Adjustment Amount

3.2 

PAI Cash Contribution

2.2(e)

PAI Closing Adjustment Amount

9.4(c)(ii)

PAI Conveyance

9.3(a)

PAI Final Settlement Statement

9.4(d)(ii)

PAI Indemnified Parties

11.2(b)

PAI Material Adverse Effect

1.1(ss)

PAI Material Contracts

6.10(a)

PAI Parent Guarantee

1.1(tt)

PAI Preliminary Settlement Statement

9.4(a)(ii)

PAI Suspense Funds

6.23 

Party

Preamble

Permits

1.1(f)(v)

Permitted Encumbrances

1.1(uu)

Person

1.1(vv)

Pipe Transfer Taxes

12.5 

Post-Closing Tax Return

7.6(c)

Pre-Closing Tax Return

7.6(c)

Pre-Interest Proportionate Adjusted Cash Consideration

3.2 

Preferential Right

1.1(ww)

Preferential Right Notice

4.1(a)

Preliminary Settlement Statements

9.4(a)(ii)

Properties

1.1(f)(iii)

Proportionate Adjusted Cash Consideration

3.2 

Real Property

1.1(f)(xii)

Records

1.1(f)(xiii)

Regardless of Fault

11.3(b)

Release

1.1(xx)

Remediate

1.1(yy)

Remediation

1.1(yy)

Remediation Amount

1.1(zz)

Representatives

1.1(aaa)

Retained Liabilities

11.1(b)

Seismic Data

1.1(f)(x)

St. Malo

1.1(bbb)







viii

 


 

 

St. Malo Operating Agreement

1.1(ccc)

Straddle Period

1.1(ddd)

Targeted Closing Date

9.1 

Tax

1.1(eee)

Tax Return

1.1(fff)

Third Party

1.1(ggg)

Third Party Acquisition

1.1(hhh)

Third Party Claim

11.3(c)

Transfer Taxes

12.5 

Transferor Taxes

1.1(iii)

Transferors

Preamble

Transition Period

1.1(jjj)

Transition Services Agreement

1.1(kkk)

Treasury Regulations

1.1(lll)

Units

1.1(e)(i)

Units Contribution

2.2(b)

Units Conveyance

9.2(g)

UTPCPL

5.1(d)

Vantage Matter

1.1(mmm)

Wells

1.1(e)(i)

Willful Breach

1.1(nnn)

Working Interest

1.1(ooo)























































ix

 

 


 

 

CONTRIBUTION AGREEMENT

This Contribution Agreement (this Agreement”), is dated as of October 10, 2018 (the Execution Date”), by and among Murphy Exploration & Production Company - USA, a Delaware corporation (“MEPU”),  Petrobras America Inc., a Delaware corporation (“PAI and, together with MEPU, “Transferors) and MP Gulf of Mexico, LLC, a Delaware limited liability company (“JVCo”) (for the limited purposes of Section 2.1(c)).  MEPU and PAI are sometimes referred to collectively as the “Parties” and individually as a “Party.”

RECITALS:

WHEREAS, MEPU is the owner of certain interests in oil and gas properties located in the U.S. parts of the Gulf of Mexico (the “Gulf of Mexico”) that are defined and described herein; 

WHEREAS, MEPU is the owner of 40% of the issued and outstanding limited liability company membership interests (the “Medusa Spar Units”) in Medusa Spar LLC, a Delaware limited liability Company (“Medusa Spar”);  

WHEREAS, MEPU desires to contribute (a) its undivided right, title and interest in and to those properties and rights and (b) the Medusa Spar Units to JVCo;  

WHEREAS, PAI is the owner of certain interests in oil and gas properties located in the Gulf of Mexico that are defined and described herein;

WHEREAS, PAI desires to transfer its undivided right, title and interest in and to those properties and rights to JVCo;  

WHEREAS, immediately prior to the Closing JVCo shall make a payment to PAI of Nine Hundred Million Dollars ($900,000,000) in cash (the “Initial PAI Payment”) (as adjusted);

WHEREAS, as a result of such transfers and such payment, MEPU shall acquire an 80% interest in JVCo and PAI shall acquire a 20% interest in JVCo;

WHEREAS, MEPU and PAI further desire that JVCo and MEPU enter into a master services agreement in form and substance substantially similar to that attached hereto as Exhibit G (the “Master Services Agreement”) for, among other things, the operation of the Assets, and the handling of the production of JVCo from the Assets; and

NOW, THEREFORE, in consideration of the premises and of the mutual promises, representations, warranties, covenants, conditions and agreements contained herein, and for other valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties agree as follows:

1


 

 

ARTICLE 1    DEFINITIONS

Section 1.1    Certain DefinitionsThe following terms have the meanings set forth below. Capitalized terms not referenced in this Section 1.1 have the meanings set forth in the Sections of this Agreement indicated in the Index of Defined Terms.

(a)    Affiliate” means, with respect to any Person, a Person that directly or indirectly controls, is controlled by or is under common control with such Person, with control in such context meaning the ability to direct the management or policies of a Person through ownership of voting shares or other securities, pursuant to a written agreement, or otherwise.

(b)    Agreed Allocated Value” means a good faith allocation of value agreed by the Parties for a Property for which a Party is required to send out a Preferential Right Notice.

(c)    “Anticorruption Law” means (i) the U.S. Foreign Corrupt Practices Act of 1977, as amended, and the rules and regulations thereunder, as amended, (ii) the Brazilian Federal Law No. 12.846/2013, as amended, (iii) the United Kingdom Bribery Act 2010, as amended and (iv) any other applicable Law of any other jurisdiction that relates to bribery or corruption.

(d)    Applicable Interest” means interest on the Pre-Interest Proportionate Adjusted Cash Consideration from, and including, the Effective Time through the Business Day immediately preceding the Closing Date (the “Interest Period”) at a rate per annum equal to the sum of (a) the LIBOR Reference Rate plus (b) one percent (1.00%).

(e)    Asset Taxes”  means ad valorem, property, excise, severance, production, sales, use, and similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons or the receipt of proceeds therefrom, but excluding, for the avoidance of doubt, any Income Taxes and Transfer Taxes.

(f)    Assets” means, with respect to each Transferor as identified on the applicable exhibit or schedule, all of such Transferor’s right, title, and interest in and to the following other than Excluded Assets: 

(i)    (A) All oil and gas leasehold interests in the oil and gas leases described on Exhibit A-1 and any ratifications, extensions and amendments thereof, whether or not the same are described on Exhibit A-1 (collectively, the “Leases”), all of the lands covered by the Leases (collectively, the “Lands”), and (B) any and all oil, gas, water, carbon dioxide, disposal or injection wells (whether producing, shut-in, temporarily abandoned, plugged and abandoned or otherwise) located on the Leases or Lands or on pooled, communitized or unitized (including any working interest units, governmental units or compulsory units) acreage that includes all or any part of the Leases (the “Wells”), including but not limited to those wells more particularly described on Exhibit A-2, together with all royalty interests, overriding royalty interests, production payments, sliding scale royalty interests, carried interests, options, farmout rights, reversionary interests, net profits interests and other rights to Hydrocarbons in place that are attributable to the Leases, Lands or Wells, together with all pools, units and other rights that arise by

2


 

 

operation of Law or otherwise in all properties and lands unitized (including any working interest units, governmental units or compulsory units), communitized or pooled with the Leases, Lands or Wells, including but not limited to those pools or units (including any working interest units, governmental units or compulsory units) more particularly described on Exhibit A-1 (the “Units”);

(ii)    To the extent assignable (subject to compliance with Section 4.1), all currently existing contracts, agreements and instruments set forth on Schedule 1.1(f)(ii) and all currently existing contracts, agreements and instruments, whether oral or in writing, applicable to the Properties, or the purchase, sale, production, handling, processing or transportation of Hydrocarbons attributable thereto, to the extent that such contracts, agreements and instruments directly relate to the other Assets and/or will be binding on JVCo after the Closing, including operating agreements, unitization, pooling and communitization agreements, balancing agreements, facilities or equipment leases, participation, exploration or development agreements, declarations and orders, joint venture agreements, farmin and farmout agreements, exchange agreements, transportation agreements, processing agreements, marketing agreements and licensing agreements (“Contracts”);

(iii)    To the extent assignable (subject to compliance with Section 4.1), all easements, licenses, servitudes, rights-of-way, surface leases and other rights or interests relating to the use or ownership of surface, subsurface or seabed property and structures that are used, or held for use, in connection with the ownership or operation of the Leases, Lands, Wells, Units or Equipment, or the production, handling, processing or transportation of Hydrocarbons attributable thereto, including but not limited to those more particularly described on Exhibit A-3 (the “Easements” and together with the Leases, Lands, Wells, Real Property, Equipment and Units, the “Properties”);

(iv)    All equipment, platforms, wells, machinery, fixtures and other tangible personal and mixed property and improvements, that is located on the Properties or used, or held for use, in connection with the ownership or operation of the Properties or the production, handling, processing or transportation of Hydrocarbons attributable thereto, including (A) all facilities, gathering and processing systems, central processing equipment, platforms and any rigs or similar equipment located on such facilities or platforms or attached thereto, buildings, utility lines, completion workover riser systems, compressors, meters, tanks, pumps, motors, casing, equipment (including spars, trees, pipeline end terminations, jumpers, risers, umbilicals, control assemblies, communication equipment, supervisory control and data acquisition (SCADA) equipment and production handling equipment), machinery and tools and gathering lines, flowlines and pipelines (whether or not in use), (B) any personal property (including all office furniture, furnishings and equipment, cell phones, mobile devices, communications software, software, computer-related hardware and other hardware, personal property and equipment owned, licensed or used by such Transferor with respect to the Assets) on or attached to such facilities or platforms (the “Equipment”), and (C)  all buildings affixed to the Real Property, in each case, including but not limited to those more particularly described on Exhibit A-4;

3


 

 

(v)    To the extent assignable (subject to compliance with Section 4.1), all environmental and other permits, licenses, orders, authorizations, registrations, consents, franchises, and related instruments or rights granted or issued by any Governmental Authority for the benefit of such Transferor and primarily relating to the ownership, operation or use of the Properties or Equipment (collectively, the “Permits”);

(vi)    All Hydrocarbons in and under and which may be produced and saved from or attributable to the Properties from and after the Effective Time, and all rents, issues, profits, proceeds, products, revenues and other income from or attributable thereto, and all liens and security interests in favor of such Transferor under any Laws or under any Contracts with respect to the sale of such Hydrocarbons, including the security interests granted under applicable Uniform Commercial Code provisions;

(vii)    All Imbalances;

(viii)    All Hydrocarbons stored in tanks for the benefit of such Transferor as of the Effective Time and all Line Fill related to the Properties;

(ix)    To the extent transferable without payment of a fee or the need to obtain consent (unless such consent is obtained in accordance with Section 4.1 or JVCo agrees to pay such fee), all domestic and foreign intellectual property and proprietary rights owned, licensed or used by such Transferor with respect to the Assets, including all: (a) inventions, patents, patent applications, and patent disclosures, (b) trademarks, service marks, trade dress, logos, brand names, trade names, domain names, and other indicia of origin, and all applications, registrations, and renewals in connection therewith, and all goodwill associated therewith, (c) works of authorship and other copyrightable works, copyrights, and applications, registrations, and renewals in connection therewith, (d) mask works and registrations and applications therefor, (e) rights in industrial and other protected designs and any registrations and applications therefore, (f) rights in trade secrets, know-how, and confidential business information (including such rights with respect to research and development, know-how, formulae, compositions, manufacturing and production processes and techniques, technical data, designs, drawings, specifications, research records, records of inventions, test information, customer and supplier lists, pricing and cost information, and business and marketing plans), (g) tapes, data and program documentation and all tangible manifestations and technical information relating thereto, and (h) all rights to sue or otherwise recover for past, present and future infringements, misappropriations, dilutions, and other violations of any of the foregoing (collectively, the “Intellectual Property”);

(x)    All geological and geophysical data (including all seismic data and reprocessed data) and all logs, in each case to the extent related to the Properties, and that are (A) owned by such Transferor or its Affiliates (whether outright or as a result of such data being prepared for the joint account under any applicable joint operating agreement, unit operating agreement or other operating agreement applicable to the Assets), or (B) transferable pursuant to the terms of the Contract giving rise to such Transferor’s rights in such data without the payment of a fee to any Third Party or the requirement of consent by

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such Third Party under such Contract (unless (I) JVCo has separately agreed to pay such fee, (II) if necessary, JVCo has a valid license from the applicable Third Party to such data, provided that the transferring Transferor shall use its commercially reasonable efforts to assist JVCo in obtaining any such license and (III) if applicable, any required Third Party consent has been obtained) (all of the foregoing data that is transferred to JVCo as part of the Assets, the “Seismic Data”);

(xi)    All rights, claims and causes of action to the extent, and only to the extent, that such rights, claims or causes of action are associated with the other Assets as of the Closing and relate to the Assumed Obligations; provided that, such Transferor shall use its reasonable efforts to enforce, for the benefit of JVCo,  if JVCo agrees to pay any costs and expenses incurred by such Transferor, any right, claim or cause of action that would otherwise be transferred hereunder but is not transferable;

(xii)    All real property set forth on Exhibit A-5 (the “Real Property”);

(xiii)    Originals (or photocopies where originals are not available) and electronic copies of all files, records, maps, information, and data of such Transferor or any Affiliate of such Transferor, whether written or electronically stored, to the extent pertaining to the ownership, operation and use of the other Assets, including: (A) land and title records (including lease files, surveys, land files, title opinions, and title curative documents); (B) well files, well logs, well information, well data bases, production records, monthly platform product and/or producer imbalance statements, division order files, abstracts; (C) contract files, operational accounting records, Tax records (other than those relating to Income Taxes or that relate to such Transferor’s business generally), operational records, environmental, health and safety records, technical records, engineering data and records and production and processing records; (D) Equipment records; and (E) all interpretive data, technical evaluations, technical outputs, reserve estimates, and economic estimates with respect to the Assets (collectively, the “Records”).

(g)    BOEM” means and refers to the U.S. Bureau of Ocean Energy Management or any successor agency thereto.

(h)    BSEE” means and refers to the U.S. Bureau of Safety and Environmental Enforcement or any successor agency thereto.

(i)    Business Day” means any day that is not a Saturday, a Sunday, or other day on which banks are required or authorized by Law to be closed in Houston, Texas or in Rio de Janeiro, Brazil.

(j)    BW Pioneer” means that certain specialized deep-water floating, production, storage and offloading vessel known as the BW Pioneer, and all its accessories, appurtenances, components and equipment.

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(k)    Cascade Operating Agreement” means that certain Joint Operating Agreement by and among BHP Billiton Petroleum (Deepwater) Inc., Petrobras America Inc. and Devon Energy Production Company, L.P., effective as of January 30, 2002.

(l)    Chinook Operating Agreement” means that certain Joint Operating Agreement by and between BHP Billiton Petroleum (Deepwater) Inc. and Total Exploration Production USA, Inc., effective as of February 1, 2000.

(m)    Code” means the Internal Revenue Code of 1986, as amended.

(n)    Consent” means any prohibitions on assignment or requirements to obtain consents, approval or waiver from, make any filings with or deliver any notices to, any Third Parties (including any Governmental Authority), in each case, that would be applicable in connection with the transfer of the Assets or the consummation of the transactions contemplated by this Agreement.

(o)    Controlled Representatives” means any Person’s Affiliates and their respective officers, directors, managers, employees, agents and other authorized representatives.

(p)    Cottonwood Operating Agreement” means that certain Offshore Operating Agreement by and between Petrobras America Inc. and Kerr-McGee Corporation, effective as of February 1, 1994.

(q)    Customary Post-Closing Consents” means the consents and approvals from Governmental Authorities for the assignment of the Assets to JVCo that are customarily obtained after the assignment of properties similar to the Assets.

(r)    Decommissioning” means all decommissioning, plugging, abandonment, dismantlement and removal activities and obligations with respect to the Properties as are required by Laws, Contracts or Easements associated with the Properties or any Governmental Authority (expressly including such activities described and defined as of the Effective Time and as may be amended thereafter, in 30 Code of Federal Regulations 250.1700 et seq.) and further including all well plugging, replugging and abandonment; dismantlement and removal of all facilities, pipelines and flowlines and other assets of any kind related to or associated with operations or activities conducted on the Properties; and site clearance, site restoration and site remediation and other activities associated therewith.

(s)    Defensible Title” means that title to the respective Assets of each Party which, subject to Permitted Encumbrances:

(i)    entitles such Party to receive throughout the duration of the productive life of any Property not less than the Net Revenue Interest shown in Exhibit A-1 for such Property except decreases in connection with those operations in which such Party may be a nonconsenting co-owner (to the extent

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permitted by this Agreement), decreases resulting from the establishment or amendment of pools or units (to the extent permitted by this Agreement), and decreases required to allow other working interest owners to make up past underproduction or pipelines to make up past underdeliveries;

(ii)    obligates such Party to bear a percentage of the costs and expenses for the maintenance and development of, and operations relating to, each Property not greater than the Working Interest shown in Exhibit A-1 for such Property without increase throughout the productive life of such Property except increases resulting from contribution requirements with respect to defaulting co-owners under applicable operating agreements and increases that are accompanied by at least a proportionate increase in such Party’s Net Revenue Interest in such Property; and

(iii)    is free and clear of all Encumbrances other than Permitted Encumbrances.

(t)    Due Inquiry” means (i) with respect to any matter relating to any Asset for which such Transferor or its Affiliates does not serve as operator thereof, reasonable inquiry of the operator of such Assets, and (ii) with respect to any other matter, reasonable inquiry by each Person listed on Schedule 5.1(f) or Schedule 6.1(f), as applicable, of such Person’s directly reporting subordinate personnel who would be reasonably expected to have knowledge of the relevant subject matter.

(u)    Effective Time” means October 1, 2018 at 00:01 a.m. Central Prevailing Time, 2018.

(v)      “Encumbrance” means any lien, mortgage, pledge, option, security interest, hypothecation, charge, encumbrance, irregularity or other defect (including a discrepancy or error in Net Revenue Interest or Working Interest as set forth in Exhibit A-1; but excluding any Environmental Defect).

(w)    Environmental Defect” means an individual existing condition of an Asset or of the soil, sub-surface, surface waters, groundwaters, sea, seafloor, atmosphere, natural resources or other environmental medium, wherever located, associated with the ownership or operation of an Asset (including the presence or release of waste, Hazardous Substances or Hydrocarbons), that, in each case (i) is not in compliance with (or causes a Party, with respect to an Asset, not to be in compliance with) Environmental Laws or with the terms of the Leases, Easements, Permits or Contracts, (ii) relates to any environmental pollution, contamination, degradation, damage or injury caused by or associated with an Asset for which Remediation or other corrective action is required, or (iii) otherwise requires or would require, if known (A) reporting to a Governmental Authority, and/or (B) investigation or Remediation in accordance with Environmental Laws or under the terms of the Leases, Easements, Permits or Contracts, provided that an “Environmental Defect” shall not include NORM or Decommissioning (except to the extent constituting a violation of Environmental Laws related to on-going or previous Decommissioning activities).

(x)    Environmental Laws” means all Laws, including common law, and relating to the protection of the environment, natural resources, or threatened or endangered species, pollution, or its impacts on human health or safety, or the

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management, manufacture, generation, labeling, registration, use, treatment, storage, transportation, handling, disposal or Release of or exposure to Hazardous Substances, including the following federal statutes (and any regulations promulgated pursuant thereto), all as amended: the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Water Act, the Clean Air Act, the Marine Mammal Protection Act, the Endangered Species Act, the Outer Continental Shelf Lands Act (to the extent related to Hazardous Substances), the Federal Water Pollution Control Act, the Clean Air Act, the Hazardous Materials Transportation Act, the Toxic Substances Control Act, the Oil Pollution Act, the Emergency Planning and Community Right-to-Know Act, the Safe Drinking Water Act and the National Environmental Policy Act and all applicable related Laws of any Governmental Authority having jurisdiction over the property in question addressing pollution or the environment and all regulations implementing the foregoing.  The term “Environmental Laws” does not include good or desirable operating practices or standards that may be employed or adopted by other oil and gas well operators or recommended by a Governmental Authority.

(y)    Excluded Assets” means, with respect to each Transferor: 

(i)    all corporate, financial, and legal records of such Transferor that relate to such Transferor’s business generally and not specifically to the Assets or that are subject to legal privilege or require a consent which has not been obtained at or prior to Closing, all Income Tax records of such Transferor, all books, records and files that do not relate to the Assets or solely relate to the Excluded Assets;

(ii)    all agreements, documents, records and correspondence relating to the transfer of the Assets to JVCo, or any other potential sale of the Assets;

(iii)    all audit rights arising under any Contracts with respect to the period prior to the Effective Time or related to any Retained Liabilities, except to the extent relating to any Assumed Obligation;

(iv)    such Transferor’s area-wide bonds, Permits and licenses or other Permits, licenses or authorizations used in the conduct of such Transferor’s business generally;

(v)    all rights, titles, claims and interests of such Transferor or any of its Affiliates of or under any policy or agreement of insurance or any insurance proceeds;

(vi)    other than any property described in sub-sections (x), (xi) or (xiii) in the definition of “Assets,” all office furniture, furnishings and equipment, cell phones, mobile devices, communications software, software, computer-related hardware and other hardware, personal property and equipment owned, licensed or used by such Transferor with respect to the Assets;

(vii)    any Contracts that constitute (A) master services agreements, blanket agreements or similar Contracts or (B) flight service agreements, drilling rig contracts, vessel agreements or similar Contracts and any contracts relating to Marketing Services (as defined in the Master Services Agreement) and G&A Services (as defined in

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the Master Services Agreement) to be provided by MEPU under the Master Services Agreement;

(viii)    all drilling rigs, aircraft, vehicles and vessels, in each case, whether owned, leased or chartered (excluding any platform rigs that are permanently attached to or affixed to any Equipment);

(ix)    all counterclaims, cross-claims, offsets or defenses and similar rights (A) to the extent relating to any matters for which such Transferor has an indemnity obligation pursuant to this Agreement that has not terminated, or (B) to the extent relating to the Retained Liabilities;

(x)    all rights and causes of action arising, occurring or existing in favor of such Transferor or any of its Affiliates (A) to the extent relating to any of the Retained Liabilities or (B) except to the extent relating to any Assumed Obligation, with respect to any period prior to the Effective Time;

(xi)    any swap, forward, future or derivative transaction or option or other similar hedge Contracts, and all software used for trading, hedging and credit analysis;

(xii)    all claims of such Transferor or its Affiliates for refunds of or loss carry forwards with respect to Transferor Taxes;

(xiii)    all corporate names and business names, and the other Intellectual Property set forth on Schedule 1.1(y)(xiii);

(xiv)    the instruments and information technology assets set forth on Schedule 1.1(y)(xiv);  

(xv)    the assets set forth on Schedule 1.1(y)(xv);  and 

(xvi)    any Assets excluded from the transactions contemplated hereby pursuant to the express terms hereof.

(z)    Governmental Authority” means any federal, national, supranational, state, provincial, local or foreign government and/or any political subdivision thereof, including departments, courts, commissions, boards, bureaus, ministries, agencies or other instrumentalities, including BOEM and BSEE, or similar government, governmental, legislative, judicial, regulatory or administrative authority, branch, agency, law enforcement body, commission or instrumentality, or any court, tribunal, or arbitral or judicial body.

(aa)    Hazardous Substances” means any pollutants, contaminants, toxic or hazardous or extremely hazardous substances, materials, wastes, constituents, compounds or chemicals that are regulated by, or may form the basis of Liability under, any Environmental Laws, including NORM, asbestos, produced water, petroleum and any released Hydrocarbons.

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(bb)    HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the rules and regulations promulgated thereunder.

(cc)    Hydrocarbons” means all crude oil, natural gas and other gas, casinghead gas, condensate, distillate, natural gas liquids and other liquid or gaseous hydrocarbons or any combination thereof and all products refined or extracted therefrom, together with all minerals produced in association with these substances. 

(dd)    Imbalance” means over-production or under-production or over-deliveries or under-deliveries with respect to Hydrocarbons produced from or allocated to the Properties, to the extent subject to an imbalance or make-up obligation, regardless of whether such over-production or under-production or over-deliveries or under-deliveries arise at a platform, wellhead, pipeline, gathering system, plant, transportation, receipt point, delivery point or other location (excluding any imbalances attributable to royalties payable in kind to BOEM or BSEE) and regardless of whether the same arises under contract, by operation of Law or otherwise; provided that “Imbalance” does not include any Excluded Assets.

(ee)    Income Taxes means any Tax measured by or imposed on the net income, profits, revenue, capital gains, or similar measure or any franchise or similar Tax imposed by a state on a person’s gross or net income and/or capital for the privilege of engaging in business in that state.

(ff)    Indebtedness” means, for a particular Person, without duplication: (a) indebtedness of such Person for borrowed money, including the face amount of any letter of credit and other obligations under letters of credit and agreements relating to the issuance of letters of credit or acceptance financing; (b) obligations of such Person evidenced by bonds, debentures, notes, mortgage or other similar instruments or securities for the repayment of money borrowed; (c) obligations of such Person to pay the deferred purchase price of property or services (including obligations that are non-recourse to the credit of such Person but are secured by the assets of such Person, but excluding trade accounts payables or accruals in the ordinary course of business consistent with past practice); (d) obligations of such Person under any currency, interest rate, materials or other hedging agreement or arrangement in the ordinary course of business; (e) obligations of such Person under direct or indirect guaranties in respect of, and obligations (contingent or otherwise) of such Person to purchase or otherwise acquire, or otherwise to assure a creditor against loss in respect of, indebtedness or obligations of others of the kinds referred to in clauses (a) through (d) above; and (f) indebtedness or obligations of others of the kinds referred to in clauses (a) through (e) secured by any Encumbrance on or in respect of any property of such Person.

(gg)    JIB” means any joint interest billing that is issued to, or by, a  Transferor, or any of its successors or assigns under any Contract that constitutes a joint operating agreement or unit operating agreement.

(hh)    JIB Expenses” means any cost or expenditure to be discharged by a  Transferor or any of its successors or assigns pursuant to any JIB; provided, however, that for the purposes of this Agreement,  Asset

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Taxes shall not be treated as JIB Expenses, and responsibility for such Taxes shall instead be allocated pursuant to Section 7.6(a) of this Agreement.

(ii)    JV Party” means each of JVCo, MEPU and PAI.

(jj)    Laws” means all laws, statutes, rules, regulations, ordinances, orders, decrees, requirements, judgments, principles of common law, policies, rules or regulations and codes promulgated, issued or enacted by Governmental Authorities.

(kk)    Liabilities” means any and all claims, demands, suits, causes of actions, regulatory action, payments, charges, judgments, assessments, liabilities, losses, damages, penalties, fines, settlements or costs and expenses (including consequential and indirect damages to the extent incurred to a Third Party), including any attorneys’ fees, costs of investigation, defense, litigation, arbitration or other expenses incurred in connection therewith and including liabilities, costs, losses and damages for personal injury or death, property damage, contractual claims (including contractual indemnity claims), torts, or otherwise.

(ll)    LIBOR Reference Rate” means the 12 Month London Interbank Offered Rate for United States Dollar deposits on October 1, 2018, as reported by the Financial Times or, if not available, by the Wall Street Journal. 

(mm)    Line Fill” means the volume of Hydrocarbons owned by a  Transferor or allocated to a  Transferor (a) which is contained in any gathering lines or pipelines owned by such Transferor and included in the Assets, to the extent attributable to the respective Property or (b) which is required to be maintained as line fill in any Third Party gathering lines or pipelines.

(nn)    Medusa Spar Company Agreement” means the Limited Liability Company Agreement of Medusa Spar LLC, adopted as of December 18, 2003.

(oo)    MEPU Material Adverse Effect” means any change, circumstance, effect, event, development, occurrence, condition or fact (for the purposes of this definition, each, an “event”) (whether foreseeable or not and whether covered by insurance or not) that has, has had or would be reasonably likely to have, individually or in the aggregate with any other event or events, a material adverse effect (i) on the ownership, operation or financial condition of the MEPU Assets, taken as a whole as currently operated as of the Execution Date or (ii) upon the ability of MEPU to consummate the transactions contemplated in this Agreement; provided, however, that Material Adverse Effect shall not include or take into account any effects arising out or resulting from, either alone or in combination,: (A) entering into this Agreement or the announcement or consummation of the transactions contemplated by this Agreement, including the identity of PAI; (B) changes generally affecting the international, national, regional or local general market, economic, financial or political conditions (including changes therein and changes in commodity prices, fuel supply or transportation markets, or interest rates) in the United States, in the area in which the Properties are located or worldwide, or in the

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energy industry, provided that such changes do not disproportionately affect the MEPU Assets relative to similar assets located in the same region as the MEPU Assets; (C) civil unrest, any outbreak or spread of disease or hostilities, terrorist activities or war or any similar disorder; (D) reclassifications or recalculations of reserves in the ordinary course of business; (E) natural declines in well performance, (F) actions taken or omitted to be taken by MEPU with the consent of PAI pursuant to this Agreement, (G) actions taken as required by this Agreement, (H) changes which are cured in full (including by the payment of money) before the earlier of the Closing or the termination of this Agreement under Article 10, in each case, without any cost to PAI except as provided in this Agreement, (I) changes in Law or the interpretation thereof or changes in GAAP or the interpretation thereof;  (J) matters to the extent an adjustment to the MEPU Adjustment Amount is provided for under Section 3.1; and (K) the failure of the MEPU Assets and Medusa Spar to meet any internal or industry business plans, estimates, expectations, forecasts, projections or budgets for any period (but not the effects underlying such failure unless such effects would otherwise be excepted under this definition).

(pp)    Net Revenue Interest” means, with respect to any Well or Lease, the interest in and to all Hydrocarbons produced, saved and sold from or allocated to such Well or Lease, after satisfaction of all royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons.

(qq)    NORM” means naturally occurring radioactive material.

(rr)    Organizational Documents” means, with respect to any corporation, its charter, by-laws and any agreements with shareholders; with respect to any partnership, its certificate of partnership and partnership agreement; with respect to any limited liability company, its certificate of formation and limited liability company or operating agreement; with respect to any trust, its declaration or agreement of trust; and with respect to each other Person, its comparable constitutional instruments or documents; together, in each case, with any and all amendments thereto and all material consents and other instruments delegating authority pursuant to such Organizational Documents.

(ss)    PAI Material Adverse Effect” means any change, circumstance, effect, event, development occurrence, condition or fact (for the purposes of this definition, each, an “event”) (whether foreseeable or not and whether covered by insurance or not) that has, has had or would be reasonably likely to have, individually or in the aggregate with any other event or events, a material adverse effect (i) on the ownership, operation or financial condition of the PAI Assets, taken as a whole as currently operated as of the Execution Date or (ii) upon the ability of PAI to consummate the transactions contemplated in this Agreement; provided, however, that Material Adverse Effect shall not include or take into account any effects resulting from or arising out, either alone or in combination: (A) entering into this Agreement or the announcement or consummation of the transactions contemplated by this Agreement, including the identity of MEPU; (B) changes generally affecting the international, national, regional or local general market, economic, financial or political conditions (including changes therein and changes in commodity prices, fuel supply or transportation markets, or interest rates) in the United States, in the area in which the Properties are located or worldwide, or in the energy industry, provided that such changes do not disproportionately affect the PAI Assets

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relative to similar assets located in the same region as the PAI Assets; (C) civil unrest, any outbreak or spread of disease or hostilities, terrorist activities or war or any similar disorder; (D) reclassifications or recalculations of reserves in the ordinary course of business; (E) natural declines in well performance, (F) actions taken or omitted to be taken by PAI with the consent of MEPU pursuant to this Agreement, (G) actions taken as required by this Agreement, (H) changes which are cured in full (including by the payment of money) before the earlier of the Closing or the termination of this Agreement under Article 10, in each case, without any cost to MEPU except as provided in this Agreement, (I) changes in Law or the interpretation thereof or changes in GAAP or the interpretation thereof;  (J) matters to the extent an adjustment to the PAI Adjustment Amount is provided for under Section 3.2;  and (K) the failure of the PAI Assets to meet any internal or industry business plans, estimates, expectations, forecasts, projections or budgets for any period (but not the effects underlying such failure unless such effects would otherwise be excepted under this definition).

(tt)    PAI Parent Guarantee” means the Guarantee provided by Petróleo Brasileiro S.A. substantially in the form attached hereto as Exhibit H.  

(uu)    Permitted Encumbrances” means any or all of the following:

(i)    Lessors’ royalties and any overriding royalties, reversionary interests and other burdens to the extent that they do not, individually or in the aggregate, (i) reduce a Party’s Net Revenue Interests in any Property below that shown in Exhibit A-1 or (ii) increase a Party’s Working Interest in any Property above that shown in Exhibit A-1 without at least a proportionate increase in the Net Revenue Interest;

(ii)    All Contracts, to the extent that they do not, individually or in the aggregate, (i) reduce a Party’s Net Revenue Interests in any Property below that shown in Exhibit A-1 or (ii) increase a Party’s Working Interest in any Property above that shown in Exhibit A-1 without at least a proportionate increase in the Net Revenue Interest;

(iii)    Preferential Rights and similar contractual provisions;

(iv)    Consents with respect to which waivers, approval or consents are obtained by a Party from the appropriate parties at or prior to the Closing Date or the appropriate time period for asserting the right has expired or which need not be satisfied prior to a transfer or any Assets subject to Consents that are transferred at Closing to JVCo pursuant to Section 4.1(h);

(v)    Liens for current Taxes or assessments not yet delinquent or, if delinquent, being contested in good faith by appropriate actions and for which adequate reserves have been established in accordance with generally accepted accounting principles (“GAAP”);

(vi)    Materialman’s, mechanic’s, repairman’s, employee’s, contractor’s, operator’s and other similar liens or charges arising in the ordinary course of business for amounts not yet delinquent (including any amounts being withheld as provided by Law);

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(vii)    All consents or waivers to assignment and Customary Post-Closing Consents;

(viii)    The terms and conditions of this Agreement or any agreement contemplated to be executed pursuant to this Agreement;

(ix)    Rights of reassignment arising upon intention to abandon or release the Leases, or any of them, to the extent that such rights have not been triggered;

(x)    Easements, rights-of-way, servitudes, equipment, pipelines, utility lines, structures and other rights in respect of surface and subsurface operations not involving the extraction of Hydrocarbons which, in each case, do not materially impair the operation or use of the Properties as currently operated and used;

(xi)    Liens created under Leases or Contracts or by operation of Law in respect of obligations that are not yet due;

(xii)    All applicable Laws and all rights reserved to or vested in any Governmental Authority: (1) to control or regulate any Property in any manner or to assess Taxes with respect to any Property; (ii) by the terms of any right, power, franchise, grant, license or permit, or by any provision of Law, to terminate such right, power, franchise, grant, license or permit or to purchase, condemn, expropriate or recapture or to designate a purchaser of any Property; (iii) to use such property; or (iv) to enforce any obligations or duties affecting the Properties to any Governmental Authority with respect to any franchise, grant, license or permit, in each case, in a manner which does not (A) individually or in the aggregate, (I) reduce a Party’s Net Revenue Interests in any Property below that shown in Exhibit A-1 or (II) increase a Party’s Working Interest in any Property above that shown in Exhibit A-1 without at least a proportionate increase in the Net Revenue Interest, or (B) materially impair the operation or use of the Properties as currently operated and used;

(xiii)    Such defects or irregularities in the Working Interests or Net Revenue Interests in the Properties resulting from the failure to file any assignment or other transfer instrument in a Party’s chain of title in the records of any adjoining county or parish, so long as the instrument in question is filed with the BOEM;

(xiv)    Any Encumbrance on or affecting the Leases which is discharged by a Party at or prior to Closing;

(xv)    Imbalances;

(xvi)    Terms and conditions of Permits affecting the Properties and any other rights reserved to or vested in a Governmental Authority having jurisdiction to control or regulate a Property in any manner whatsoever, and all Laws of such Governmental Authorities, to the extent, individually or in the aggregate, such terms, conditions and rights would not reasonably be expected to (A) (I) reduce a Party’s Net Revenue Interests in any Property below that shown in Exhibit A-1 or (II) increase a Party’s Working Interest in any Property above that shown in Exhibit A-1 without at least a

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proportionate increase in the Net Revenue Interest, or (B) materially impair the operation or use of the Properties as currently operated and used; and

(xvii)    Any matters expressly described on Exhibit A-1.

(vv)    Person” means any individual, corporation, partnership, limited liability company, limited liability partnership, joint venture, trust, syndicate, person, association, organization, estate, Governmental Authority or any other entity, and including any successor, by merger or otherwise, of any of the foregoing. 

(ww)    Preferential Right” means any (i) preferential purchase rights, rights of first refusal or similar rights or (ii) rights of first offer, tag-along rights, drag-along rights or other similar rights, in each case of clause (i) and (ii) above, that are applicable to the transfer of the Assets in connection with the transactions contemplated hereby.

(xx)    Release” means any actual or threatened release, spilling, leaking, pumping, pouring, emitting, emptying, discharging, injecting, escaping, leaching, dumping, abandonment, disposing or allowing to escape or migrate into or through the environment (including, without limitation, ambient air (indoor or outdoor), surface water, groundwater, land surface or subsurface strata.

(yy)    Remediation” or “Remediate” mean, with respect to an Environmental Defect, the implementation and completion of any remedial, removal, response, construction, closure, disposal, restoration or other corrective actions, including monitoring, required under Environmental Laws to correct or remove such Environmental Defect or under the terms of the Leases, Easements, Permits or Contracts, using the most cost-effective response that would be selected by a reasonable and prudent operator and that is reasonably expected to appropriately address such requirement.

(zz)    Remediation Amount” means, with respect to an Environmental Defect the cost of the Remediation of such Environmental Defect, net to the applicable Party’s interest. 

(aaa)    Representatives” means any Person’s Affiliates and their respective officers, directors, managers, employees, agents, accountants, attorneys, investment bankers, consultants, advisor and other authorized representatives.

(bbb)    St. Malo” means those certain leases set forth on Exhibit A to the St. Malo Operating Agreement.

(ccc)    St. Malo Operating Agreement” means that certain Unit Operating Agreement by and among Union Oil Company of California, Petrobras America Inc., Devon Energy Production Company, L.P., Chevron U.S.A. Inc., Statoil Gulf of Mexico LLC, Exxon Mobil Corporation and Eni Petroleum US LLC, effective as of June 1, 2007.

(ddd)    Straddle Period” means any Tax period beginning before and ending after the Effective Time.

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(eee)    Tax” means all taxes, assessments, duties, levies, imposts, or other similar charges imposed by a Governmental Authority, including all income, franchise, profits, capital gains, capital stock, transfer, gross receipts, sales, use, transfer, service, occupation, ad valorem, property, excise, severance, production, windfall profit, premium, stamp, license, payroll, employment, social security, unemployment, disability, environmental,  escheat or unclaimed property obligations, alternative minimum, add-on, value-added, withholding (including backup withholding) and other taxes, assessments, duties, levies, imposts or other similar charges of any kind whatsoever (whether payable directly or by withholding and whether or not requiring the filing of a Tax Return), and all estimated taxes, deficiency assessments, additions to tax, additional amounts, penalties or interest with respect to any of the foregoing, and any liability in respect of any of the foregoing that arises by reason of a contract, assumption, transferee or successor liability, operation of Law (including by reason of being a member of a consolidated, combined or unitary group) or otherwise.

(fff)    Tax Return” means return, declaration, report, election, document, correspondence, claim for refund or information return or statement relating to Taxes, including any schedule or attachment thereto and any amendment thereof.

(ggg)    Third Party” means any Person other than a Party to this Agreement or an Affiliate of a Party to this Agreement.

(hhh)    Third Party Acquisition” means the occurrence of any acquisition, directly or indirectly, in one or a series of related transactions of the Assets (or any portion thereof) by purchase, oil and gas lease, sublease, merger, tender offer, consolidation, business combination or otherwise by any Person other than JVCo.

(iii)    Transferor Taxes” means, with respect to each Transferor, (a) Asset Taxes allocable to such Transferor pursuant to Section 7.6(a) (without duplication of Asset Taxes taken into account in determining the adjustments to the MEPU Adjustment Amount or the PAI Adjustment Amount made pursuant to Section 3.1,  Section 3.2 or Section 9.4, as applicable, and taking into account the payments made from one Party to the other pursuant to Section 7.6(b)), (b) any Taxes imposed on or with respect to the ownership or operation of the Excluded Assets of such Transferor or that are attributable to any asset or business of such Transferor that is not part of the Assets, (c) Income Taxes with respect to the Transferor or the Transferor’s interest in a lower-tier subsidiary (including, without limitation and for the avoidance of doubt, in the case of MEPU, such Taxes with respect to its interest in Medusa Spar), (d) any and all Taxes (other than the Taxes described in clauses (a), (b) or (c) of this definition) imposed on or with respect to the ownership or operation of the Assets of such Transferor or the production of Hydrocarbons or the receipt of proceeds therefrom for any Tax period (or portion thereof) ending before the Effective Time, and (d) any and all liabilities of such Transferor, its respective direct or indirect owners or Affiliates, or any combined, unitary or consolidated group of which any of the foregoing is or was a member, in respect of any Taxes (other than the Taxes described in clauses (a), (b), or (c) of this definition).

(jjj)    Transition Period means the period of time that coincides with the term of the Transition Services Agreement.

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(kkk)    Transition Services Agreement” means a transition services agreement between PAI and/or certain of its Affiliates and JVCo, in  form and substance mutually agreed by MEPU and PAI and based on the underlying principles of the Master Services Agreement, pursuant to which PAI will operate, on a transitional basis certain of the PAI Assets after Closing; provided that if the Transition Services Agreement has not been agreed in form and substance prior to Closing, the principles in the Master Services Agreement (with PAI as the Service Provider (as defined in the Master Services Agreement) and applying only to the PAI Assets) shall serve as a basis for PAI to provide transition services from Closing until the earlier of (i) such time as MEPU and PAI have agreed on the form and substance of the Transition Services Agreement and (ii) six months after the Closing Date; provided further that PAI shall, in its reasonable discretion, be permitted to modify the principles in the Master Services Agreement so long as such modifications are consistent with acting as a Reasonable and Prudent Service Provider (as defined in the Master Services Agreement). 

(lll)    Treasury Regulations” means the final, temporary or proposed Treasury Regulations promulgated under the Code, as such regulations may be amended from time to time (including corresponding provisions of succeeding regulations).

(mmm)    Vantage Matter” means the award issued on June 29, 2018 in an arbitration between Vantage Deepwater Company and Vantage Deepwater Drilling, Inc., as petitioners, and PAI, Petrobras Venezuela Investments & Services, BV and Petróleo Brasileiro S.A. – Petrobras, as respondents and captioned Vantage Deepwater Co. et al. v. Petrobras America Inc., et al., No. 01-15-0004-8503.  

(nnn)    Willful Breach” means, with respect to any Party, an intentional and material breach that is a consequence of a failure to act by, or act undertaken by or caused by, the breaching Party under circumstances that objectively indicate that the breaching Party acted or failed to act with knowledge that such failure to act or taking or causing of such act would, or would reasonably be expected to, cause a material breach of any covenant applicable to such Party or that such Party willfully or intentionally causes any condition to Closing set forth in Section 7.17 applicable to such Party not to be satisfied.  For clarity, if a Party is obligated hereunder to use its commercially reasonable efforts to perform an action or to achieve a result, the failure to use such commercially reasonable efforts would constitute a willful and intentional breach of this Agreement; provided, that the requirement to use commercially reasonable efforts shall not include a requirement to pay any money or give anything of value to any Third Party.

(ooo)    Working Interest” with respect to any Property, means the interest in and to such Property that is burdened with the obligation to bear and pay costs and expenses of maintenance, development and operations on or in connection with such Property, but without regard to the effect of any royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons.

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ARTICLE 2    ORGANIZATION OF JVCO LLC

Section 2.1    JVCo LLC.

(a)    MEPU caused the formation of JVCo by filing a certificate of formation (hereinafter referred to as the “LLC Formation Document”) with the Secretary of State of Delaware pursuant to the Delaware Limited Liability Company Act on July 16, 2018. The LLC Formation Document is attached hereto as Exhibit E and is made a part hereof.

(b)    MEPU and PAI shall each be a “Member” of JVCo.  In connection with the Initial Transfers, all of MEPU’s membership interests in JVCo shall be converted into a membership interest in JVCo of 80%  and PAI shall have a membership interest in JVCo of 20%.

(c)    On the Closing Date,  PAI and JVCo shall, and MEPU and PAI shall cause JVCo to, take all steps required to effect the Initial PAI Payment (as adjusted). The Parties agree that, for U.S. federal income tax purposes, the transfer of the Initial PAI Payment by JVCo to PAI shall be characterized as a sale by PAI of a pro rata share of the PAI Assets to JVCo in exchange for the entire amount of the Initial PAI Payment.  The Parties shall (and shall cause their respective Affiliates to) file all U.S. federal income tax returns in a manner consistent with such characterization, and the Parties shall not (and shall cause their respective Affiliates not to) take any position inconsistent with such characterization without the consent of the other Parties.

(d)    At the Closing, the Members shall execute an amended and restated limited liability company agreement memorializing the affairs of JVCo and the conduct of its business (the “LLC Agreement”). The LLC Agreement shall be in the form of, and contain the terms, conditions and provisions as are more particularly set forth in, Exhibit F attached hereto and made a part hereof.

Section 2.2    Initial Transfers.  At the Closing, each of the Members shall make an initial transfer (the “Initial Transfers”) to JVCo as follows: 

(a)    MEPU shall assign and transfer to JVCo its right, title and interest in and to the Assets (the “MEPU Assets”), free and clear of any Encumbrances other than Permitted Encumbrances.

(b)    MEPU shall assign and transfer to JVCo the Medusa Spar Units (the “Units Contribution”), free and clear of any Encumbrances, other than those created by the Medusa Spar Company Agreement and those arising under applicable securities laws.  

(c)    PAI shall assign and transfer to JVCo its right, title and interest in and to the Assets (the “PAI Assets”), free and clear of any Encumbrances other than Permitted Encumbrances.

(d)    MEPU shall contribute 80% of the required initial working capital of Forty Million Dollars ($40,000,000) in cash (the “MEPU Cash Contribution”).  

(e)    PAI shall contribute 20% of the required initial working capital of Forty Million Dollars ($40,000,000) in cash (the “PAI Cash Contribution”); provided, that payment of the amount equal to such PAI Cash Contribution shall be made by MEPU to JVCo; provided

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further, that the amount of such PAI Cash Countribution shall be deducted from the Initial PAI  Payment pursuant to the last paragraph of Section 3.2. 

Section 2.3    Effective Time; Proration of Costs and Revenues.

(a)    Possession of the Assets shall be transferred from Transferors to JVCo at the Closing, but certain financial benefits and burdens in respect of the Assets shall be transferred effective as of the Effective Time, as described below.

(b)    JVCo shall be entitled to all production of Hydrocarbons from or attributable to the Assets on and after the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets on and after the Effective Time, and shall be responsible for (and entitled to any refunds with respect to) all Operating Expenses incurred on and after the Effective Time.  Transferors shall be entitled to all production of Hydrocarbons from or attributable to their respective Assets prior to the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to their respective Assets prior to the Effective Time, and shall be responsible for (and entitled to any refunds with respect to) all Operating Expenses incurred prior to the Effective Time. “Earned” and “incurred,” as used in this Agreement, shall be interpreted in accordance with United States generally accepted accounting principles (as published by the Financial Accounting Standards Board) and Council of Petroleum Accountants Societies (COPAS) standards.

(c)    Operating Expenses” means all operating expenses (excluding Taxes), including costs of insurance, capital expenditures incurred in the ownership and operation of the Assets, costs of gathering, treating, processing, compression and transportation, costs of service contracts, costs of idled equipment and overhead costs payable to Third Parties charged to the Assets under the applicable operating agreement or otherwise in the ordinary course of business.  Notwithstanding anything herein to the contrary, in no event shall any Retained Liability be considered to be an Operating Expense.  For the avoidance of doubt, Operating Expenses shall include operating expenses incurred in association with all existing contracts, agreements and instruments set forth on Schedule 1.1(f)(ii) and any employment-related costs or other Liabilities incurred in connection with the ownership and operation of the Assets (excluding such costs or other Liabilities that are related to Transferors actual overhead and other general and administrative costs attributable to the Assets).

(d)    For purposes of allocating production (and accounts receivable with respect thereto), under this Section 2.3, (i) liquid Hydrocarbons shall be deemed to be “from or attributable to” the Assets when they pass through the pipeline flange connecting into the storage facilities on the platform located on the Lands or, if there are no such storage facilities, when they pass through the lease automated custody transfer (LACT) meters or similar meters at the point of entry into the pipelines through which they are transported from the Lands, and (ii) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Assets when they pass through the delivery point sales meters or similar meters at the point of entry into the pipelines through which they are transported from the Lands.  Transferors shall utilize reasonable interpolative procedures to arrive at an allocation of production when exact meter readings are not available.  Each Transferor shall provide to the other Transferor, no later than ten (10) Business Days prior to Closing, evidence of

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all meter readings conducted on or about the Effective Time in connection with its respective Assets, together with all data necessary to support any estimated allocation, for purposes of establishing the adjustment to the MEPU Adjustment Amount or the PAI Adjustment Amount pursuant to Section 3.1 and Section 3.2.  Taxes (other than Taxes measured by gross proceeds, income, profits or capital gains), surface use fees, insurance premiums and other Operating Expenses that are paid periodically shall be prorated based on the number of days in the applicable period falling before and at or after the Effective Time, except that production, severance and similar Taxes measured by units of production shall be prorated based on the amount of Hydrocarbons actually produced, purchased or sold, as applicable, before, or at and after the Effective Time.  In each case, JVCo shall be responsible for the portion allocated to the period at and after the Effective Time and Transferors shall be responsible for the portion allocated to the period before the Effective Time.

(e)    All cash amounts attributable to Operating Expenses that are received or paid prior to Closing shall be accounted for in the Preliminary Settlement Statements or Final Settlement Statements, as applicable.  Such amounts that are received or paid after Closing but prior to the date of the Final Settlement Statement shall be accounted for in the Final Settlement Statement.  If, after Transferors’  agreement upon the Final Settlement Statement, (i) a Transferor or JVCo receives monies belonging to the other pursuant to the terms of this Agreement, including proceeds of production, then such amount shall, within ten (10) Business Days after the end of the month in which such amounts were received, be paid over to the proper JV Party, (ii) a Transferor or JVCo pays monies for Operating Expenses which are the obligation of another JV Party pursuant to the terms of this Agreement, then such other JV Party shall, within ten (10) Business Days after the end of the month in which the applicable invoice and proof of payment of such invoice were received, reimburse the JV Party which paid such Operating Expenses, (iii) a Transferor or JVCo receives an invoice of an expense or obligation which is owed by the other party pursuant to the terms of this Agreement, such JV Party receiving the invoice shall promptly forward such invoice to the party obligated to pay the same, and (iv) an invoice or other evidence of an obligation is received by a Transferor or JVCo which is partially an obligation of both such Transferor and JVCo pursuant to the terms of this Agreement, then the JV Parties shall consult with each other, and each shall promptly pay its portion of such obligation to the obligee. Transferors  agree that they shall cause JVCo to take any action required under this Section 2.3(e).  

(f)    Possession of any (i) cash call funds received and held by a  Transferor  as operator of the Assets but not expended pursuant to a joint operating agreement prior to Closing, and (ii) other Third Party funds being held by a  Transferor as operator of the Assets shall result in an adjustment to the MEPU Adjustment Amount or the PAI Adjustment Amount pursuant to Section 3.1(e) or Section 3.2(e), as applicable, at Closing.

ARTICLE  3    ADJUSTMENTS TO INITIAL PAI PAYMENT

Section 3.1    MEPU Adjustments to Initial PAI Payment.   The MEPU Adjustment Amount means the amount calculated as follows, without duplication:

(a)    The aggregate amount of proceeds received by MEPU or its Affiliates from the sale of Hydrocarbons which may be produced and saved from or attributable to the Properties from and after the Effective Time (less any (i) royalties, overriding royalties, net profits interests 

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and other similar burdens payable out of the production of Hydrocarbons from the MEPU Assets or the proceeds thereof which are not included in Operating Expenses and (ii) Asset Taxes and sales, use or similar Taxes imposed in connection therewith);

(b)    Increased by the aggregate amount of any other proceeds received by MEPU or its Affiliates attributable to the MEPU Assets with respect to the period at or after the Effective Time;

(c)    Increased by the amount of all Taxes (other than Taxes measured by gross proceeds, income, profits or capital gains) prorated to MEPU in accordance with Section 7.6(a) but paid or payable by JVCo;

(d)    To the extent that MEPU is overproduced as of the Effective Time with respect to any Imbalance, increased by an amount equal to (i) the Midpoint Price for Louisiana/Southeast Henry Hub as published by S&P Global Platts Gas Daily for the flow date of October 1, 2018, plus or minus any applicable adjustments for transportation, quality, location or other like adjustments to reflect the value of the Hydrocarbon at the point of any imbalance per mmbtu of natural gas and (ii) the NYMEX WTI Light Sweet Crude Oil Daily Settlement price for the prompt month (November) on October 1, 2018, plus or minus any applicable adjustments for transportation, quality, location or other like adjustments to reflect the value of the Hydrocarbon at the point of any imbalance per bbl of oil, or to the extent that MEPU is under produced as of the Effective Time with respect to any Imbalance, decreased by an amount equal to (i) above per mmbtu of natural gas and (ii) above per bbl of oil;

(e)    Increased by the amount of all (i) MEPU Suspense Funds, and (ii) other funds held by MEPU and its Affiliates pursuant to Section 2.3(f) as of the Closing;

(f)    Decreased by the amount of all Operating Expenses attributable to the MEPU Assets on and after the Effective Time which are incurred and paid by MEPU excluding, however, any amounts added pursuant to Section 3.1(a) above;

(g)    Decreased by the aggregate amount of proceeds from the sale of Hydrocarbons which may be produced and saved from or attributable to the Properties prior to the Effective Time to the extent received by JVCo as of or after the Closing (less any (i) royalties, overriding royalties net profits interests and other similar burdens payable out of the production of Hydrocarbons from the MEPU Assets or the proceeds thereof which are not included in Operating Expenses and (ii) Asset Taxes and sales, use or similar Taxes imposed in connection therewith);

(h)    Decreased by an amount with respect to all Hydrocarbons (a) produced, saved from or attributable to the Properties and stored in tanks as of the Effective Time (to the extent that the proceeds from the sale of such Hydrocarbons are received by JVCo as of or after the Closing) and (b) the Line Fill, if any, as of the Effective Time, valued at a price of the Midpoint Price for Louisiana/Southeast Henry Hub as published by S&P Global Platts Gas Daily for the flow date of October 1, 2018, plus or minus any applicable

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adjustments for transportation, quality, location or other like adjustments to reflect the value of the Hydrocarbon at the time and point of transfer per mmbtu of natural gas and the NYMEX WTI Light Sweet Crude Oil Daily Settlement price for the prompt month (November) on October 1, 2018, plus or minus any applicable adjustments for transportation, quality, location or other like adjustments to reflect the value of the Hydrocarbon at the time and point of transfer per bbl of oil (in each case, less any (i) royalties, overriding royalties net profits interests and other similar burdens payable out of the production of Hydrocarbons from the MEPU Assets or the proceeds thereof which are not included in Operating Expenses and (ii) Asset Taxes and sales, use or similar Taxes imposed in connection therewith);

(i)    Increased by the amount of all Operating Expenses (including JIB Expenses) attributable to the MEPU Assets prior to the Effective Time which are due and payable by MEPU to JVCo or any of its Affiliates;

(j)    Decreased by the amount of all prepaid expenses attributable to any Asset that are paid by, or on behalf of, MEPU and that are attributable to the period of time after the Effective Time, including prepaid utility charges;

(k)    Decreased by the amount of all Taxes (other than Taxes measured by gross proceeds, income, profits or capital gains) prorated to JVCo in accordance with Section 7.6(a) but paid or payable by MEPU;

(l)    Increased in accordance with Section 4.1; 

(m)    Increased in accordance with Section 4.2; and

(n)    Increased or decreased, as the case may be, by any other amount expressly provided for in this Agreement or mutually agreed to by the Parties in writing.

Section 3.2    PAI Adjustments to Initial PAI Payment.   The PAI Adjustment Amount means the amount calculated as follows, without duplication:

(a)    The aggregate amount of proceeds received by PAI or its Affiliates from the sale of Hydrocarbons which may be produced and saved from or attributable to the Properties from and after the Effective Time (less any (i) royalties, overriding royalties, net profits interests and other similar burdens payable out of the production of Hydrocarbons from the PAI Assets or the proceeds thereof which are not included in Operating Expenses and (ii) Asset Taxes and sales, use or similar Taxes imposed in connection therewith);

(b)    Increased by the aggregate amount of any other proceeds received by PAI or its Affiliates attributable to the PAI Assets with respect to the period at or after the Effective Time;

(c)    Increased by the amount of all Taxes (other than Taxes measured by gross proceeds, income, profits or capital gains) prorated to PAI in accordance with Section 7.6(a) but paid or payable by JVCo;

(d)    To the extent that PAI is overproduced as of the Effective Time with respect to any Imbalance, increased by an amount equal to (i) the Midpoint Price for Louisiana/Southeast Henry Hub as published by S&P Global Platts Gas Daily for the flow date of October 1, 2018, plus or minus any applicable adjustments for transportation, quality, location or other like adjustments to reflect the value of the Hydrocarbon at the point of any imbalance per mmbtu of natural gas and 

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(ii) the NYMEX WTI Light Sweet Crude Oil Daily Settlement price for the prompt month (November) on October 1, 2018, plus or minus any applicable adjustments for transportation, quality, location or other like adjustments to reflect the value of the Hydrocarbon at the point of any imbalance per bbl of oil, or to the extent that PAI is under produced as of the Effective Time with respect to any Imbalance, decreased by an amount equal to (i) above per mmbtu of natural gas and (ii) above per bbl of oil;

(e)    Increased by the amount of all (i) PAI Suspense Funds, and (ii) other funds held by PAI and its Affiliates pursuant to Section 2.3(f) as of the Closing;

(f)    Decreased by the amount of all Operating Expenses attributable to the PAI Assets on and after the Effective Time which are incurred and paid by PAI excluding, however, any amounts added pursuant to Section 3.2(a) above;

(g)    Decreased by the aggregate amount of proceeds from the sale of Hydrocarbons which may be produced and saved from or attributable to the Properties prior to the Effective Time to the extent received by JVCo as of or after the Closing (less any (i) royalties, overriding royalties net profits interests and other similar burdens payable out of the production of Hydrocarbons from the PAI Assets or the proceeds thereof which are not included in Operating Expenses and (ii) Asset Taxes and sales, use or similar Taxes imposed in connection therewith);

(h)    Decreased by an amount with respect to all Hydrocarbons (a) produced, saved from or attributable to the Properties and stored in tanks as of the Effective Time (to the extent that the proceeds from the sale of such Hydrocarbons are received by JVCo as of or after the Closing) and (b) the Line Fill, if any, as of the Effective Time, valued at a price of the Midpoint Price for Louisiana/Southeast Henry Hub as published by S&P Global Platts Gas Daily for the flow date of October 1, 2018, plus or minus any applicable adjustments for transportation, quality, location or other like adjustments to reflect the value of the Hydrocarbon at the time and point of transfer per mmbtu of natural gas and the NYMEX WTI Light Sweet Crude Oil Daily Settlement price for the prompt month (November) on October 1, 2018, plus or minus any applicable adjustments for transportation, quality, location or other like adjustments to reflect the value of the Hydrocarbon at the time and point of transfer per bbl of oil (in each case, less any (i) royalties, overriding royalties net profits interests and other similar burdens payable out of the production of Hydrocarbons from the PAI Assets or the proceeds thereof which are not included in Operating Expenses and (ii) Asset Taxes and sales, use or similar Taxes imposed in connection therewith);

(i)    Increased by the amount of all Operating Expenses (including JIB Expenses) attributable to the PAI Assets prior to the Effective Time which are due and payable by PAI to JVCo or any of its Affiliates;

(j)    Decreased by the amount of all prepaid expenses attributable to any Asset that are paid by, or on behalf of, PAI and that are attributable to the period of time after the Effective Time, including prepaid utility charges;

(k)    Decreased by the amount of all Taxes (other than Taxes measured by gross proceeds, income, profits or capital gains) prorated to JVCo in accordance with Section 7.6(a) but paid or payable by PAI;

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(l)    Decreased by $5 million.

(m)    Increased in accordance with Section 4.1;

(n)    Increased in accordance with Section 4.2; and

(o)    Increased or decreased, as the case may be, by any other amount expressly provided for in this Agreement or mutually agreed to by the Parties in writing.

On the Closing Date, MEPU, on behalf of JVCo, shall pay PAI in immediately available funds by wire transfer to an account designated by PAI,  the Initial PAI Payment,  less an amount equal to PAI Cash Contribution, less an amount equal to the sum of: (A)  the PAI Adjustment Amount multiplied by 0.8, minus (B) the MEPU Adjustment Amount multiplied by 0.2 (the “Pre-Interest Proportionate Adjusted Cash Consideration”) plus Applicable Interest (the “Proportionate Adjusted Cash Consideration”). 

Section 3.3    Effect of Adjustments.   The adjustments described in Section 3.1(a) and Section 3.2(a) shall serve to satisfy, up to the amount of the adjustment, JVCo’s entitlement under Section 2.3 to Hydrocarbon production from or attributable to the Assets between the Effective Time and the Closing and to other income, proceeds, receipts and credits earned with respect to the Assets between the Effective Time and the Closing, and JVCo shall not have any separate rights to receive any production or income, proceeds, receipts and credits with respect to which an adjustment has been made.  Similarly, the adjustments described in Section 3.1(f) and Section 3.2(f) shall serve to satisfy, up to the amount of the adjustment, JVCo’s obligation under Section 2.3 to pay Operating Expenses attributable to the ownership and operation of the Assets which are incurred between the Effective Time and the Closing, and JVCo shall not be separately obligated to pay for any Operating Expenses with respect to which an adjustment has been made.

Section 3.4    Allocation of Initial PAI Payment for Tax Purposes.   The Parties agree that the entire amount of the Initial PAI Payment, as adjusted, shall be allocated among each of the PAI Assets such that the portion of the Initial PAI Payment allocated to of each of the PAI Assets, in percentage terms,  is equal to the relative value, expressed in percentage terms, of each of the PAI Assets as reflected on Schedule 3.4 attached hereto (the “Allocation Schedule”).  Transferors agree not to take any position, and shall cause their Affiliates not to take any position, inconsistent with the allocations set forth in the Allocation Schedule without the consent of the other Party; provided that if on or prior to the tenth day following the Closing Date the auditing expert of MEPU objects to such Allocation Schedule as being inconsistent with the requirements of the Code or GAAP or as not reflecting a Casualty Loss, MEPU shall be permitted to replace such Allocation Schedule without the consent of PAI in order to correct such inconsistency or reflect such Casualty Loss.  Each Party shall promptly notify the other in writing upon receipt of notice of any pending or threatened Tax audit or assessment challenging the Allocation Schedule, and neither Party nor JVCo shall agree to any proposed adjustment to the allocation contained in the Allocation Schedule by any Governmental Authority without giving prior written notice to the other Party and allowing the other party the opportunity to reasonably assist with the defense of such allocation; provided, that nothing contained herein shall prevent either Party or JVCo from settling any proposed deficiency or adjustment by any Governmental Authority based upon or

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arising out of the allocation, and neither Party shall be required to litigate any proposed deficiency or adjustment by any Governmental Authority challenging such allocation.

Section 3.5    Withholding.   Except with respect to any Tax imposed with respect to bulk sales, bulk transfer or similar Laws of any jurisdiction that may be applicable with respect to the contribution or transfer of any or all of the Assets to JVCo, each Party shall be entitled to deduct and withhold from the consideration otherwise payable to another Party pursuant to this Agreement such amounts as such Party is required to deduct and withhold under the Code or any other Law respecting Taxes, in each case, with respect to the making of such payment.  To the extent that amounts are so withheld, such withheld amounts shall be treated for all purposes of this Agreement as having been paid to the Party in respect of whom such deduction and withholding was made.

ARTICLE 4    CONSENTS; PREFERENTIAL RIGHTS; AND CASUALTY LOSSES

Section 4.1    Consents to Assignment and Preferential Rights to Purchase

(a)    Promptly after the Execution Date, but in no event later than ten (10)  days after the Execution Date, each Party shall prepare and send (i) notices (each a Consent Request Notice”), to the holders of any Consents set forth on Schedule 5.13 or Schedule 6.13, as applicable, in compliance with the terms of such consents and requesting consents to the applicable Conveyance and, to the extent applicable, an express waiver of any provision that would require the assignment of the applicable Asset subject to such Consent to be delayed until after the Closing Date, and (ii) notices (each a Preferential Right Notice”), to the holders of any Preferential Rights set forth on Schedule 5.13 or Schedule 6.13, as applicable, in compliance with the terms of such rights and requesting waivers of such rights.  With respect to each Consent (other than a Customary Post-Closing Consent) or Preferential Right that is not set forth on Schedule 5.13 or Schedule 6.13, as applicable, but is discovered by a Party prior to Closing, as soon as reasonably practicable after discovery of any such Preferential Right or Consent, such Party shall prepare and send (A) a Consent Request Notice to the holders of any such Consents in compliance with the terms of such consents and requesting consents to the applicable Conveyance and, to the extent applicable, an express waiver of any provision that would require the assignment of the applicable Asset subject to such Consent to be delayed until after the Closing Date, and (B) a Preferential Right Notice to the holders of any such Preferential Rights in compliance with the terms of such rights and requesting waivers of such rights.  Each Party shall provide the other Party with a copy of all notices sent to applicable Preferential Right and Consent holders.  Each Party shall use commercially reasonable efforts to cause such Consents and waivers of Preferential Rights (or the exercise thereof) required to be requested pursuant to this Section 4.1(a) to be obtained and delivered prior to Closing.  The Parties shall cooperate with each other in seeking to obtain such Consents and waivers of Preferential Rights, including providing reasonably requested financial and other information, and for the avoidance of doubt the Parties shall not and shall cause JVCo not to (I) take any action intended to frustrate the receipt of any Consent or waiver or (II) to cause any contract or agreement to become an Excluded Asset by refusing to take assignment thereof or refusing to grant any Consent or waiver.

(b)    Any Preferential Right must be exercised subject to all terms and conditions set forth in this Agreement.  The consideration payable under this Agreement for any particular

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Asset for purposes of Preferential Right notices shall be the Agreed Allocated Value for such Asset.

(c)    (i) If any Preferential Right is exercised prior to Closing, or (ii) if prior to the Closing, the time period in which the holder of a Preferential Right has the right to exercise such Preferential Right has not yet expired and such holder has not waived such Preferential Right, then, in each case (A) the Assets subject to such Preferential Right shall be excluded from the Assets to be conveyed to JVCo  at Closing, (B) the MEPU Adjustment Amount or the PAI Adjustment Amount, as applicable, shall be adjusted upward by the Agreed Allocated Values of the Assets so excluded and (C) subject to Section 4.1(d), such Assets so excluded shall become Excluded Assets for all purposes hereunder.

(d)    With respect to any Preferential Right described in Section 4.1(c)(i) or Section 4.1(c)(ii) above (i) if for any reason (A) the purchase and sale of the Assets covered by such Preferential Right is not or cannot be consummated with the holder of such Preferential Right in accordance with the instrument under which such Preferential Right arises, or (B) the holder of the Preferential Right is unable to satisfy the conditions to closing contained therein, or (ii) the period in which to exercise such Preferential Right has expired without the exercise thereof, then, in each case, the applicable Party shall promptly notify the other Party and, if less than 180 days have elapsed since the Closing Date, then, within ten (10) Business Days after the other Party’s receipt of such notice, the Parties shall conduct an additional closing whereby the applicable Party shall sell, assign and convey to JVCo, and the Parties shall cause JVCo to purchase and accept from such Party, such previously Excluded Assets (1) for the amount by which the MEPU Adjustment Amount or the PAI Adjustment Amount, as applicable, was adjusted at the initial Closing with respect to such Excluded Assets (subject to any applicable adjustments contained in Section 3.1 or Section 3.2 with respect to such Excluded Assets and any applicable closing conditions), (2) pursuant to an instrument in substantially the same form as the Conveyances, except the “Closing Date” with respect to any such Excluded Asset shall mean the date of assignment of such Excluded Asset from such Party to JVCo, and (3) thereafter, such previously Excluded Assets shall become Assets for all purposes hereunder.

(e)    All Assets for which any applicable Preferential Right has been waived, or as to which the period to exercise the applicable Preferential Right has expired without the applicable Preferential Right having been validly exercised, in each case, prior to Closing, shall be transferred to JVCo at Closing pursuant to the provisions of this Agreement.  With respect to any Preferential Right, until the Assets subject to such Preferential Right are transferred to JVCo pursuant to the provisions of this Agreement, each Party shall control any dispute between it and a holder of a Preferential Right with respect to such Preferential Right.

(f)    If a Party fails to obtain a Consent prior to Closing and (i) the failure to obtain such Consent would cause (A) the assignment of the Assets affected thereby to JVCo  to be void or voidable, (B) the termination of (or the right to terminate) a Lease or other Asset under the express terms thereof, or (C) any material Liability to the transferee of such Asset, (ii) the Consent requested by such Party is denied in writing, or (iii) the Consent is required from a Governmental Authority (other than a Customary Post-Closing Consent), the Parties shall execute and deliver such instruments and take such other actions as the Parties may mutually agree to carry out the intent of this Agreement and the transfer of the benefits and burdens of such Assets to JVCo.  Such

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instruments and actions may include the execution of back-to-back agreements to effect the transfer to JVCo of the benefits and burdens of such Assets which the Party whose Assets are subject to such Consent is obligated to perform and/or is entitled to receive, as applicable (provided that entering into such back-to-back agreements is not impracticable or does not: (x) result in a breach of any obligations under any such Assets, (y) result in a violation of Law or (z) impose a burden on such Party or JVCo disproportionate to the benefit received by JVCo under such Asset).  In any such back-to-back agreement (whether in writing or otherwise), (i) such Party shall continue to be bound thereby and (ii) (A) such Party shall, without further consideration therefor, pay, assign and remit to JVCo promptly all monies, rights and other considerations received in respect of such Asset, (B) such Party shall continue to operate the Assets in compliance with Section 7.3, (C) such Party shall promptly exercise or exploit the beneficial rights and options of JVCo under such Asset at JVCo’s request and expense, (D) if and when any such Consent shall be obtained or such an Asset shall otherwise become assignable, such Party shall promptly assign, in a manner consistent with Section 2.2, its rights and obligations under such Asset to JVCo and the Parties shall cause JVCo, without the payment of any further consideration therefor, to assume such rights and obligations, and (E) the Parties shall cause JVCo to perform and discharge fully all of the obligations of such Party thereunder after the Effective Time and indemnify such Party for all Liabilities arising out of such performance by JVCo as if such obligations and Liabilities were Assumed Obligations hereunder; provided, however, JVCo shall not be required to indemnify such Party to the extent any such Liability arises from, or is attributable to (1) the gross negligence or willful misconduct of any MEPU Indemnified Party or PAI Indemnified Party, as applicable or (2) such Party’s breach of any provision of this Section 4.1(f).  To the extent that a Party is unable to assign an Asset with respect to which this Section 4.1(f) applies, the Parties shall use commercially reasonable efforts to continue to seek the Consent applicable to such Asset until the earlier of (I) the third anniversary of the Closing Date or (II) the date such Asset terminates in accordance with its terms or otherwise at the direction of the other Party.

(g)    Notwithstanding Section 4.1(f),  the Parties may mutually agree prior to Closing, for JVCo to receive an assignment of Assets affected by Consents (including all Assets subject to or otherwise affected by such Consent), and such Assets shall be assigned to JVCo at Closing, and the Parties shall cause JVCo to indemnify the Party whose Assets are subject to such Consent for all Liabilities arising out of such assignment as if such Liabilities were Assumed Obligations hereunder.

(h)    If a Party fails to obtain a Consent prior to Closing and (i) the failure to obtain such Consent would not cause (A) the assignment of the Asset (or portion thereof) affected thereby to JVCo to be void or voidable, (B) the termination of (or the right to terminate) a Lease or other Asset under the express terms thereof, or (C) any material Liability to the transferee of such Asset, (ii) such Consent requested by such Party is not denied in writing by the holder thereof, and (iii) such Consent is not required from a Governmental Authority (or is a Customary Post-Closing Consent) then, the Asset (or portion thereof) subject to such un-obtained Consent shall nevertheless be assigned by such Party to JVCo at Closing as part of the Assets.

(i)    Prior to Closing, the Parties shall use their commercially reasonable efforts to obtain all Consents required to be requested pursuant to this Section 4.1 and waivers of all Preferential Rights; in addition, following the Closing, the Parties agree to use their commercially

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reasonable efforts to cooperate with each other to obtain any Consents and waivers of Preferential Rights that were not obtained prior to Closing.

Section 4.2    Casualty or Condemnation Loss

(a)    From the Execution Date until Closing, each Party shall provide written notice to the other Party of any (i) physical damage to a Well or any Equipment, and any Environmental Defect resulting therefrom or arising in connection therewith, that occurs and (A) is not the result of normal wear and tear, mechanical failure or gradual structural deterioration of materials, equipment, and infrastructure, or reservoir changes or depletion due to normal production (including (1) failures arising or occurring during drilling or completing operations, (2) junked or lost holes, or (3) sidetracking or deviating a well), and (B) is a result of acts of God, fire, explosion, pipeline or gathering line failure, earthquake, hurricane, tropical storm, tropical depression, storm, windstorm or blowout or (ii) any condemnation or other taking related to any Asset that occurs (each, a Casualty Loss”) (provided that Casualty Loss shall not include any physical damage related to Decommissioning and NORM).  Such written notice shall be provided promptly upon a Party becoming aware of any Casualty Loss and shall include, to the extent known by such Party at such time, (I) a reasonably detailed description of the events leading to such Casualty Loss, (II) a description of the Equipment and/or Wells affected by such Casualty Loss and (III) such Party’s estimate of the costs to repair or replace the Equipment and/or Wells affected by such Casualty Loss.

(b)    From the Execution Date until Closing, should any Property suffer a Casualty Loss in an amount that exceeds Five Million Dollars $(5,000,000), net to the contributing or transferring Party’s interest in the applicable Property, then (subject to Section 8.1,  Section 8.2 and Section 10.1)  (the “Casualty Loss Threshold”) the other Party shall nevertheless be required to proceed to Closing and such Party may elect by written notice to the contributing or transferring Party prior to Closing to either (A) require such contributing or transferring Party, at such contributing or transferring Party’s sole cost, expense and Liability (to the extent the other Party does not otherwise own an interest in such Property), to repair or restore (or cause to be repaired or restored, including debris and wreck removal to the extent required by applicable Law) any such Property affected by such Casualty Loss to a quality and condition comparable to that existing with respect to such Property immediately before such Casualty Loss, as promptly as reasonably practicable (which work may extend after the Closing Date, so long as such contributing or transferring Party is diligently pursuing such repairs or restoration activities but not longer than one hundred eighty (180) days after the Closing Date unless mutually acceptable to the Parties) or (B) adjust the MEPU Adjustment Amount or the PAI Adjustment Amount, as applicable, by an amount that would be necessary to repair or restore (or cause to be repaired or restored, including debris and wreck removal to the extent required by applicable Law) any such Property affected by such Casualty Loss to a quality and condition comparable to that existing with respect to such Property immediately before such Casualty Loss. From the Execution Date until Closing, should any Property suffer a Casualty Loss in an amount less than the Casualty Loss Threshold, upon Closing, JVCo shall be entitled to all rights of the contributing or transferring Party to any insurance proceeds under insurance policies issued by Third Parties, to condemnation awards and to other claims against Third Parties with respect to the Casualty Loss; provided, however, that such contributing or transferring Party shall reserve and retain all rights, title, interests and claims against Third Parties for the recovery of such contributing or transferring Party’s costs and

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expenses (if any) incurred prior to Closing in pursuing or asserting any such insurance claims or other rights against Third Parties with respect to such Casualty Loss.

(c)    The Parties shall attempt to agree on the amount of the costs and expenses associated with Casualty Losses prior to Closing.  Subject, and without prejudice, to Section 8.1(f) and Section 8.2(f), if  the Parties are unable to reach an agreement by Closing, then a numerical average of each Party’s good faith estimate thereof shall be used for purposes of the Closing, and either Party may initiate binding arbitration in accordance with Section 12.10(c) within the 10-day period following the Closing Date to resolve the amount of the costs and expenses associated with Casualty Losses.

ARTICLE 5    REPRESENTATIONS AND WARRANTIES OF MEPU

Section 5.1    Disclaimers

(a)    Except as and to the extent expressly set forth in this Article 5 or in the certificate of MEPU to be delivered pursuant to Section 9.2(l) or in the MEPU Conveyance, PAI acknowledges and agrees that (i) MEPU makes no representations or warranties, express or implied, and (ii) MEPU expressly disclaims all Liability and responsibility for any representation, warranty, statement or information made or communicated (orally or in writing) to PAI or any of its Representatives (including any opinion, information, projection or advice that may have been provided to PAI by any officer, director, employee, agent, consultant, Representative or advisor of MEPU or any of its Affiliates), and PAI irrevocably waives (on behalf of itself, its Affiliates and their successors and assigns) any and all Liabilities it or they may have against MEPU or its Affiliates associated with the same.

(b)    EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN THIS Article 5 OR IN THE CERTIFICATE OF MEPU TO BE DELIVERED AT CLOSING PURSUANT TO Section 9.2(l) OR IN THE MEPU CONVEYANCE, WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, PAI ACKNOWLEDGES AND AGREES THAT MEPU EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, WITH RESPECT TO THE MEPU ASSETS, INCLUDING AS TO (I) TITLE TO ANY OF THE MEPU ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE MEPU ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF PETROLEUM SUBSTANCES IN OR FROM THE MEPU ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE MEPU ASSETS OR FUTURE REVENUES GENERATED BY THE MEPU ASSETS, (V) THE PRODUCTION OF PETROLEUM SUBSTANCES FROM THE MEPU ASSETS, OR WHETHER PRODUCTION HAS BEEN CONTINUOUS, OR IN PAYING QUANTITIES, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE MEPU ASSETS, OR (VII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO PAI OR ITS AFFILIATES, OR ITS OR THEIR REPRESENTATIVES IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, AND FURTHER DISCLAIMS ANY REPRESENTATION OR

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WARRANTY, EXPRESS OR IMPLIED, OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OR ANY EQUIPMENT, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT PAI HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS PAI DEEMS APPROPRIATE.  EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN THIS Article 5 OR IN THE CERTIFICATE OF MEPU TO BE DELIVERED AT CLOSING PURSUANT TO Section 9.2(l) OR IN THE MEPU CONVEYANCE OR AS OTHERWISE SET FORTH IN Article 11, WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, PAI ACKNOWLEDGES AND AGREES THAT THE MEPU ASSETS ARE BEING ASSIGNED AND CONVEYED TO JVCO “AS-IS, WHERE-IS,” WITH ALL FAULTS AND DEFECTS IN THEIR PRESENT CONDITION AND STATE OF REPAIR, WITHOUT RECOURSE.

(c)    PAI EXPRESSLY WAIVES THE WARRANTY OF FITNESS FOR INTENDED PURPOSES OR GUARANTEE AGAINST HIDDEN OR LATENT REDHIBITORY VICES UNDER LOUISIANA LAW, INCLUDING LOUISIANA CIVIL CODE ARTICLES 2520 THROUGH 2548, AND THE WARRANTY IMPOSED BY LOUISIANA CIVIL CODE ARTICLE 2475; WAIVES ALL RIGHTS IN REDHIBITION PURSUANT TO LOUISIANA CIVIL CODE ARTICLES 2520, ET SEQ.; OR FOR RESTITUTION OR OTHER DIMINUTION OF THE CONSIDERATION; ACKNOWLEDGES THAT THIS EXPRESS WAIVER SHALL BE CONSIDERED A MATERIAL AND INTEGRAL PART OF THIS TRANSFER AND THE CONSIDERATION THEREOF; AND ACKNOWLEDGES THAT THIS WAIVER HAS BEEN BROUGHT TO THE ATTENTION OF PAI AND EXPLAINED IN DETAIL AND THAT PAI HAS VOLUNTARILY AND KNOWINGLY CONSENTED TO THIS WAIVER.

(d)    IT IS THE INTENTION OF THE PARTIES THAT PAI’S RIGHTS AND REMEDIES WITH RESPECT TO THIS TRANSACTION AND WITH RESPECT TO ALL ACTS OR PRACTICES OF MEPU, PAST, PRESENT OR FUTURE, IN CONNECTION WITH THIS TRANSACTION SHALL BE GOVERNED BY LEGAL PRINCIPLES OTHER THAN THE TEXAS DECEPTIVE TRADE PRACTICES--CONSUMER PROTECTION ACT, TEX. BUS. & COM. CODE ANN. § 17.41 ET SEQ. (THE DTPA”) OR THE LOUISIANA UNFAIR TRADE PRACTICES AND CONSUMER PROTECTION LAW, LA. R.S. 51:1402, ET SEQ. (THE UTPCPL”).  AS SUCH, PAI HEREBY WAIVES THE APPLICABILITY OF THE DTPA AND THE UTPCPL TO THIS TRANSACTION AND ANY AND ALL DUTIES, RIGHTS OR REMEDIES THAT MIGHT BE IMPOSED BY THE DTPA AND/OR THE UTPCPL, WHETHER SUCH DUTIES, RIGHTS AND REMEDIES ARE APPLIED DIRECTLY BY THE DTPA OR THE UTPCPL ITSELF OR INDIRECTLY IN CONNECTION WITH OTHER STATUTES; PROVIDED, HOWEVER, PAI DOES NOT WAIVE § 17.555 OF THE DTPA.  PAI ACKNOWLEDGES, REPRESENTS AND WARRANTS THAT IT IS ACQUIRING THE INTEREST IN JVCO FOR COMMERCIAL OR BUSINESS USE; THAT IT HAS ASSETS OF $5 MILLION OR MORE ACCORDING TO ITS MOST RECENT FINANCIAL STATEMENT PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES; THAT IT HAS KNOWLEDGE AND EXPERIENCE IN FINANCIAL AND BUSINESS MATTERS THAT ENABLE IT TO EVALUATE THE MERITS AND RISKS OF A TRANSACTION SUCH AS THIS; AND THAT IT IS NOT IN A SIGNIFICANTLY DISPARATE BARGAINING POSITION WITH MEPU.

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(e)    The Parties hereby waive compliance with the provisions of any bulk sales, bulk transfer or similar Laws of any jurisdiction that may otherwise be applicable with respect to the contribution or transfer of any or all of the Assets to JVCo.

(f)    Any representation “to the knowledge of MEPU” or “to MEPU’s knowledge” is limited to matters within the actual knowledge (with duty of Due Inquiry) of the Persons listed on Schedule 5.1(f).

(g)    Subject to the foregoing provisions of this Section 5.1, and the other terms and conditions of this Agreement, MEPU represents and warrants to PAI the matters set out in Section 5.2 through Section 5.32.

Section 5.2    Existence and Qualification

(a)    Organization. MEPU is a corporation duly organized, validly existing and in good standing under the Laws of the State of Delaware and is duly qualified to do business as a foreign corporation in good standing in each jurisdiction in which it is required to qualify in order to conduct its business, except where the failure to be so qualified would not, individually or in the aggregate, have a MEPU Material Adverse Effect.  MEPU is qualified  under Law to own the Assets owned by MEPU, and in particular, MEPU is qualified pursuant to the rules and regulations of BOEM and BSEE to own federal oil and gas leases in the Outer Continental Shelf, Gulf of Mexico, and is in good standing with, authorized by and qualified with all Governmental Authorities with jurisdiction or cognizance over operations on the Outer Continental Shelf, Gulf of Mexico, to the extent MEPU is required by such authorities to so qualify and maintain good standing, except where failure to be so qualified or to be in good standing would not, individually or in the aggregate, have a MEPU Material Adverse Effect.

(b)    Power.   MEPU has the corporate power to enter into and perform this Agreement (and all documents required to be executed and delivered by MEPU at Closing) and to consummate the transactions contemplated by this Agreement (and such documents).

(c)    Authorizations and Enforceability.   The execution, delivery and performance of this Agreement (and all documents required to be executed and delivered by MEPU at Closing) and the consummation of the transactions contemplated hereby and thereby, have been duly and validly authorized by all necessary corporate action on the part of MEPU.  This Agreement has been duly executed and delivered by MEPU (and all documents required to be executed and delivered by MEPU at Closing shall be duly executed and delivered by MEPU) and this Agreement constitutes, and at the Closing such documents shall constitute, the valid and binding obligations of MEPU, enforceable in accordance with their terms except as such enforceability may be limited by applicable bankruptcy or other similar Laws affecting the rights and remedies of creditors generally as well as to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at Law).

(d)    No Conflicts.   Except as disclosed on Schedule 5.2(d)  the execution, delivery and performance of this Agreement by MEPU, and the consummation of the transactions contemplated by this Agreement shall not (i) violate any provision of the certificate of incorporation or bylaws of any MEPU, (ii) result in any material default (with due notice or lapse

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of time or both) or the creation of any Encumbrance (other than a Permitted Encumbrance) or give rise to any right of termination, cancellation or acceleration under any material note, bond, mortgage, indenture, license or agreement to which MEPU is a party or by which it or any of the MEPU Assets is bound, (iii) violate any judgment, order, ruling, or decree applicable to MEPU as a party in interest or the MEPU Assets, or (iv) violate any Laws applicable to MEPU or any of the MEPU Assets.

Section 5.3    Liability for Brokers’ Fees.  PAI (and each of its Affiliates) shall not directly or indirectly have any responsibility, Liability or expense, as a result of undertakings or agreements of MEPU or any of its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation to an intermediary in connection with the negotiation, execution or delivery of this Agreement or any agreement or transactions contemplated hereby.

Section 5.4    Litigation.   Except as disclosed on Schedule 5.4, there are no litigation or arbitral proceedings (a) pending or, to MEPU’s knowledge, threatened against MEPU or its Affiliates relating to MEPU’s ownership or MEPU’s operation of the MEPU Assets, (b) (i) pending or, to MEPU’s knowledge, threatened against the MEPU Assets operated by MEPU or any of its Affiliates or (ii) to MEPU’s knowledge, pending or threatened against the MEPU Assets operated by any Third Party, or (c) pending or, to MEPU’s knowledge, threatened in writing against MEPU that would prevent the consummation of the transactions contemplated by this Agreement. Except as disclosed on Schedule 5.4,  MEPU has not received any notice of any Liability for breach of contract, tort, or violation of Law with respect to MEPU’s ownership or operation of any Property.

Section 5.5    Taxes and Assessments

(a)     Except as set forth on Schedule 5.5: (i) MEPU has timely filed or caused to be timely filed all material Tax Returns required to be filed under applicable Law with respect to MEPU’s acquisition, ownership or operation of the MEPU Assets that are due on or prior to the Closing Date, and all such Tax Returns are correct and complete in all material respects; (ii) MEPU has timely paid or caused to be timely paid all material Taxes relating or applicable to MEPU’s acquisition, ownership or operation of the MEPU Assets (including ad valorem, property, production, severance and similar Taxes and assessments based on or measured by the ownership of property or the production of Hydrocarbons or the receipt of proceeds therefrom with respect to the MEPU Assets) that are or have become due (whether or not shown on any Tax Return), and MEPU is not delinquent in the payment of any such Taxes, (iii) there is not currently in effect any extension or waiver of any statute of limitations of any jurisdiction regarding the assessment or collection of any material Tax of MEPU relating to MEPU’s acquisition, ownership or operation of the MEPU Assets; and (iv) there are no administrative or judicial proceedings pending against the MEPU Assets or against MEPU relating to any material Liability for Taxes of MEPU with respect to the MEPU Assets by any Governmental Authority.

(b)    Medusa Spar is treated as a partnership for U.S. federal income tax purposes; Medusa Spar has timely filed or caused to be timely filed all material Tax Returns required to be filed by Medusa Spar under applicable Law that are due on or prior to the Closing Date, and all such Tax Returns are correct and complete in all material respects; Medusa Spar has timely paid or caused to be timely paid all material Taxes required to be paid by Medusa Spar;

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there is not currently in effect any extension or waiver of any statute of limitations of any jurisdiction regarding the assessment or collection of any material Tax of Medusa Spar, and Medusa Spar is not delinquent in the payment of any such Taxes; there are no administrative or judicial proceedings pending against Medusa Spar; and Medusa Spar has a Code Section 754 election in effect.

(c)    There are no Encumbrances on any of the MEPU Assets, assets of Medusa Spar or the Medusa Spar Units for Taxes (other than Permitted Encumbrances).

(d)    Except as set forth on Schedule 5.5, no MEPU Asset is subject to any Tax partnership agreement or provisions requiring a partnership income Tax return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code or any similar state statute. 

Section 5.6    Title.    MEPU has, and as of the Effective Time had, Defensible Title to the Properties that are MEPU Assets.

Section 5.7    Environmental.  Except as set forth on Schedule 5.7:

(a)    With respect to the ownership and operation of the Properties, MEPU has not entered into, and is not subject to, any agreements, consents, orders, decrees, judgments, license or permit conditions or other directives of any Governmental Authority based on any Environmental Laws that are reasonably expected to (i) have an adverse effect in any material respect on current or future exploration or production activities at or in connection with any of the MEPU Assets, or (ii) require any material Remediation or corrective action or impose material obligation concerning any of the MEPU Assets;

(b)    MEPU has not received written notice from any Person of any release or disposal of Hazardous Substances or Hydrocarbons, or any event, condition, circumstance, activity, practice or incident, in each case, concerning any land, facility, asset or Property included in the MEPU Assets (including any alleged violation of Law or Permit) that would be reasonably likely to: (i) interfere with or prevent compliance by MEPU or the MEPU Assets with any Environmental Law or the terms of any Permit issued pursuant thereto; or (ii) give rise to or result in any common Law or other Liability under applicable Environmental Laws (including any Permits issued pursuant to such Environmental Laws) of MEPU to any Person with respect to the MEPU Assets;

(c)    MEPU has made available to PAI true and complete copies of all (i) non-privileged, material reports and studies prepared at the request of MEPU or its Affiliates by Third Parties to the extent (A) in MEPU’s or its Affiliates’ possession and control and (B) MEPU or its applicable Affiliate is permitted to disclose such report or study (following MEPU’s use of commercially reasonable efforts to obtain such permission), and (ii) material written notices received by MEPU or its Affiliates from Governmental Authorities (including any requests for information under applicable Environmental Laws), in each case of either clause (i) or (ii) hereof, specifically addressing environmental conditions or compliance with Environmental Laws related to the ownership, operation or use of the MEPU Assets; and

(d)    Except for Decommissioning which is addressed in Section 5.15, to MEPU’s knowledge, there are no material liabilities under or uncured violations of any applicable

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Environmental Laws (including any Permits issued pursuant to such Environmental Laws) with respect to the MEPU Assets and no material obligations to Remediate conditions upon the MEPU Assets under applicable Environmental Law (and no such obligation would arise as a result of notice or lapse of time or both).

Section 5.8    Outstanding Capital Commitments.   Except as disclosed on Schedule 5.8, as of the Execution Date, there are no outstanding authorization for expenditures (“AFEs”) or other commitments to make capital expenditures which are binding on the MEPU Assets and which MEPU reasonably anticipates will individually require expenditures after the Effective Time in excess of Two Million Dollars $(2,000,000).

Section 5.9    Compliance with Laws.   Except with respect to Environmental Laws and Anticorruption Laws and except as disclosed on Schedule 5.9, (a) MEPU and each of its Affiliates have materially complied with all applicable Laws related to the ownership of the MEPU Assets and (b) the MEPU Assets have been operated, developed, maintained, and used, including the production of all Hydrocarbons attributable thereto, in material compliance with all applicable Laws, provided that subsection (b) shall be qualified by MEPU’s knowledge with respect to (i) any MEPU Assets for which MEPU or any of its Affiliates does not serve as the operator thereof, and (ii) the period prior to MEPU’s acquisition of such Assets.

Section 5.10    Contracts

(a)    Schedule 5.10(a) sets forth all Contracts of the type described below with respect to the MEPU Assets,  other than Leases (collectively, the MEPU Material Contracts”):

(i)    other than any Contract that is a Hydrocarbon purchase and sale, transportation, gathering, treating, processing, dedication or similar Contract, any Contract that can reasonably be expected to result in aggregate payments by MEPU or any Affiliate of MEPU of more than Two Million Dollars $(2,000,000)  during the current or any subsequent calendar year or Ten Million Dollars $(10,000,000)  in the aggregate over the term of such Contract;

(ii)    other than any Contract that is a Hydrocarbon purchase and sale, transportation, gathering, treating, processing, dedication or similar Contract, any Contract that can reasonably be expected to result in aggregate revenues to MEPU or any Affiliate of MEPU of more than Two Million Dollars $(2,000,000) during the current or any subsequent calendar year or Ten Million Dollars $(10,000,000) in the aggregate over the term of such Contract;

(iii)    any Contract that is a Hydrocarbon purchase and sale, transportation, gathering, treating, processing, dedication or similar Contract not terminable upon sixty (60) days or less notice;

(iv)    any Contract that is an indenture, mortgage, loan, credit or sale-leaseback, guarantee of any obligation, bonds, letters of credit or similar financial Contract;

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(v)    any Contract that constitutes a lease under which MEPU or any Affiliate of MEPU is the lessor or the lessee of any real or personal property (including Equipment and Real Property, but not including any of the other Properties) which lease (A) cannot be terminated by MEPU without penalty upon sixty (60) days or less notice and (B) involves an annual base rental of more than Two Hundred Fifty Thousand Dollars $(250,000);

(vi)    other than joint operating agreements, any Contract that constitutes a non-competition agreement or any agreement that purports to restrict, limit or prohibit the manner in which, or the locations in which, MEPU or any Affiliate of MEPU conducts business, including area of mutual interest Contracts;

(vii)    any Contract that contains calls upon or options to purchase production;

(viii)    any Contract that constitutes swap, forward, future or derivative transaction or option or other similar hedge Contracts;

(ix)    any Contract that provides for a power of attorney with respect to the  MEPU Assets that will not be terminated prior to the Closing Date;

(x)    any Contract that constitutes a development agreement, participation agreement, farmout agreement, partnership agreement, joint venture agreement or similar Contract (other than Tax partnership agreements);

(xi)    any Contracts for the use or sharing of drilling rigs or for the use of Equipment;

(xii)    any Contract (executory or otherwise) to sell, lease, farmout, or otherwise dispose of or encumber any interest in any of the MEPU Assets after the Execution Date, other than conventional rights of reassignment arising in connection with MEPU’s surrender or release of any of the MEPU Assets, to the extent such rights are not currently applicable;

(xiii)    any Contract that constitutes a joint or unit operating agreement;

(xiv)    any Contract for which the primary purpose is to provide for the indemnification of another Person;

(xv)    any Contract (other than the Properties) that would obligate JVCo to drill additional wells or conduct other material development operations after the Closing;

(xvi)    subject to Section 7.15(b), to the extent disclosable to PAI, any Contract that is related to Seismic Data described in clause (A) of the definition thereof;

(xvii)    any Contract with any Affiliate of MEPU;

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(xviii)    any purchase and sale agreements pursuant to which MEPU or its Affiliates acquired (directly or indirectly) the MEPU Assets that contain indemnity obligations that will be binding on JVCo following Closing; and

(xix)    any Contract that constitutes an amendment, supplement, or modification in respect of any of the foregoing.

(b)    With respect to the MEPU Material Contracts:

(i)    each of the MEPU Material Contracts is in full force and effect;

(ii)    there exists no material default under any MEPU Material Contract by MEPU or, to MEPU’s knowledge, by any other Person that is a party to such MEPU Material Contract or Leases;

(iii)    no event has occurred that upon receipt of notice or lapse of time or both would constitute any material default under any such Contract by MEPU or, to MEPU’s knowledge, any other Person who is a party to such MEPU Material Contract or Leases;

(iv)    to the extent material, MEPU has not given nor received any unresolved written notice of default, amendment, waiver, price redetermination, market out, curtailment or termination with respect to any MEPU Material Contract or Lease; and

(v)    prior to the execution of this Agreement, MEPU has made available to PAI true and complete copies of each MEPU Material Contract and all amendments thereto.

Section 5.11    Payments for Production.   Except as set forth on Schedule 5.11, all proceeds from the sale of Hydrocarbons attributable to MEPU’s interest in the Properties are currently being paid in full to MEPU (after Tax withholdings or similar deductions required by the terms of the Contracts or applicable Law).  Except as set forth in the MEPU Material Contracts, MEPU is not obligated by virtue of a take or pay payment, advance payment or other similar payment (other than royalties, overriding royalties and similar arrangements established in the Leases or reflected on Exhibit A-1), to deliver Hydrocarbons, or proceeds from the sale thereof, attributable to MEPU’s interest in the Properties at some future time without receiving payment therefor at or after the time of delivery.

Section 5.12    Imbalances.   Except as set forth in Schedule 5.12, there are no Imbalances associated with the MEPU Assets as of the Effective Time.

Section 5.13    Consents and Preferential Purchase Rights.   Except as set forth on Schedule 5.13, no Consents or Preferential Rights are applicable to the transfer of the MEPU Assets from MEPU to JVCo or any of the other transactions contemplated by this Agreement, except for compliance with the HSR Act and Customary Post-Closing Consents.

Section 5.14    Permits.    The Permits constitute all material permits, licenses, registrations, orders, approvals, variances, waivers and other authorizations required to be obtained from any

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Governmental Authority for conducting its business with respect to the MEPU Assets as presently conducted, including all Permits required to be obtained pursuant to Environmental Laws.  Each of the Permits is in full force and effect, there exists no material uncured violations of any Permit by MEPU or, to MEPU’s knowledge, by any other Person, and no event has occurred that upon receipt of notice or lapse of time or both would constitute a material default under any such Permit by MEPU or, to MEPU’s knowledge, any other Person.  Neither MEPU nor any Affiliate of MEPU has received any written notice from any Governmental Authority of any violation of any Permit in connection with the ownership and/or operation of the MEPU Assets that remains uncured, and there are no proceedings pending or, to MEPU’s knowledge, threatened that might result in any material modification, revocation, termination or suspension of any Permit or which would require any material corrective or remedial action by MEPU or any Affiliate of MEPU.

Section 5.15    Wells; Decommissioning Activities.   Except as set forth on Schedule 5.15,  MEPU represents as follows with respect to the MEPU Assets for which MEPU acts as operator:

(a)    There are no Wells (A) in respect of which MEPU has received an order from any Governmental Authority requiring that such Wells be plugged and abandoned within eighteen (18) months after the Execution Date, other than any such Decommissioning activities that have been completed in all material respects in accordance with applicable Law; or (B) that are neither in use for purposes of production or injection, nor suspended or temporarily abandoned in accordance with applicable Law, that, in each case, have not been plugged and abandoned and otherwise Decommissioned in all material respects in accordance with applicable Law;

(b)    MEPU has not received an order from any Governmental Authority requiring that any Decommissioning activities take place with respect to the Properties within eighteen (18) months after the Execution Date, other than any such Decommissioning activities that have been completed in all material respects in accordance with applicable Law;

(c)    To MEPU’s knowledge, all Decommissioning activities conducted with respect to the MEPU Assets have been performed in all material respects in accordance with all applicable Leases, the MEPU Material Contracts and all applicable Laws;

(d)    There is no Equipment in respect of which MEPU has received an order from any Governmental Authority requiring that such Equipment be Decommissioned within eighteen (18) months after the Execution Date, other than any such Decommissioning activities that have been completed in all material respects in accordance with applicable Law;

(e)    No Well is subject to penalties on allowables after the Effective Time because of overproduction; and

(f)    There are no Wells that were drilled and completed by MEPU, or to MEPU’s knowledge by any Third Party, outside the limits permitted by all applicable Laws, Permits, Contracts and Leases.

Section 5.16    Equipment. (i) The Wells and Equipment have been maintained in operable repair, working order and operating condition and are suitable for the purposes for which such Wells or Equipment were constructed or obtained or are currently being used, in each case, in all material respects, and (ii) MEPU has all material easements, rights of way, licenses and

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authorization from Governmental Authorities necessary to access, construct, operate, maintain and repair the Wells and Equipment in the ordinary course of business as currently conducted by MEPU and in material compliance with all applicable Laws, provided that this Section 5.16 shall be qualified by MEPU’s knowledge with respect to any MEPU Assets for which MEPU or any of its Affiliates does not serve as the operator.

Section 5.17    Condemnation and Eminent Domain.   As of the Execution Date, no action for condemnation or taking under right of eminent domain is, to MEPU’s knowledge, pending or threatened with respect to any MEPU Asset or portion thereof.

Section 5.18    Bankruptcy.   There are no bankruptcy, reorganization or receivership proceedings pending or, to MEPU’s knowledge, threatened against MEPU or any of its Affiliates.

Section 5.19    Foreign Person.   MEPU is not a “foreign person” within the meaning of Section 1445 of the Code, nor an entity disregarded as separate from any other Person within the meaning of Treasury Regulation Section 301.7701-3(a).

Section 5.20    Payout Status.   To MEPU’s knowledge, Schedule 5.20 contains a list of the status of any “payout” balance, as of the date set forth on such Schedule, for those Wells related to the MEPU Assets subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms).

Section 5.21    Operation of the MEPU Assets.   Beginning on the date on which MEPU acquired ownership of the relevant MEPU Assets, the MEPU Assets have been operated in material accordance with good oilfield practices as such are generally practiced with respect to oil and gas assets similar to the MEPU Assets, provided that the foregoing shall be qualified by MEPU’s knowledge with respect to any MEPU Assets for which MEPU or any of its Affiliates does not serve as the operator thereof.

Section 5.22    Royalties.   Except for the MEPU Suspense Funds, MEPU has paid in all material respects all royalties, overriding royalties and other burdens on production due by MEPU with respect to the MEPU Assets from January 1, 2018 through the month ended two (2) months prior to the month in which the Closing Date occurs for oil and the month ended three (3) months prior to the month in which the Closing Date occurs for gas and NGLs.  MEPU has or shall timely file any Form-2014s with respect to royalties due on or through the month in which the Closing Date occurs and shall pay any royalties due and owing on such periods, subject to the adjustment to the MEPU Adjustment Amount for any royalties pursuant to Section 3.1.

Section 5.23    Suspense Funds.  Schedule 5.23 lists all proceeds of production and associated penalties and interest in respect of any of the MEPU Assets that are payable to Third Parties and are being held in suspense by MEPU as of the Execution Date (the MEPU Suspense Funds”), a description of the source of such MEPU Suspense Funds and the reason they are being held in suspense, and, if known, the name or names of the Third Parties claiming such MEPU Suspense Funds or to whom such MEPU Suspense Funds may be owed.

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Section 5.24    Bonds and Credit Support.  Schedule 5.24 lists all bonds, letters of credit and other similar credit support instruments maintained by MEPU or any Affiliate of MEPU with any Governmental Authority or other Third Party with respect to the MEPU Assets.

Section 5.25    Non-Consent Operations.   Except as set forth on Schedule 5.25,  MEPU has neither elected nor been deemed to have elected to “non-consent,” nor failed to participate in, the drilling or reworking of a well, any seismic program or any other operation which would cause MEPU or JVCo to suffer a penalty or lose or forfeit any interests in the MEPU under any applicable operating agreement.

Section 5.26    Assets Complete. The MEPU Assets and the Medusa Spar Units constitute all of MEPU’s interests in production properties in the Gulf of Mexico, excluding the Excluded Assets.

Section 5.27    Intellectual Property.   MEPU does not own any registered Intellectual Property which would constitute Assets.  Except as set forth on Schedule 5.27, (i) MEPU owns and possesses all right, title and interest in and to, or has a valid right to use, all Intellectual Property, (ii) none of MEPU or any of its Affiliates is infringing, misappropriating, diluting, or otherwise violating any intellectual property rights of any other Person in connection with their ownership and operation of the MEPU Assets, (iii) no actions, suits, litigation, claims, causes of action, demands, or other proceedings are pending or have been threatened during the past three (3) years, alleging any such infringement, misappropriation, dilution or other violation, currently or in the past, by MEPU or any of its Affiliates, (iv) no Person is infringing, misappropriating, diluting, or otherwise violating any Intellectual Property and (v) MEPU and each of its Affiliates have taken reasonable efforts to maintain and protect all material Intellectual Property.

Section 5.28    Ownership of Units. Except as set forth in Schedule 5.28, the Medusa Spar Units are owned of record and beneficially by MEPU free and clear of all Encumbrances, except for those created by applicable securities Laws or contained in the Medusa Spar Company Agreement. The consummation of the Units Contribution will convey to JVCo good and valid title to the Medusa Spar Units, free and clear of all Encumbrances, except for those created by JVCo (if any), created by applicable securities Laws or contained in the Medusa Spar Company Agreement, and upon such assignment and transfer to JVCo, and JVCo’s execution of the Amended and Restated Medusa Spar LLC Agreement, JVCo will be the sole, lawful owner, beneficially and of record, of all of the Medusa Spar Units, free and clear of all Encumbrances, except for those created by JVCo, created by applicable securities Laws or contained in the Medusa Spar Company Agreement. MEPU is not in default under any, or in material breach of any of the terms of, the Organizational Documents of Medusa Spar, and no event, occurrence, condition or act which, with the giving of notice, the lapse of time or the happening of any other event or condition, has occurred that would become a default or event of default by MEPU under the Organizational Documents of Medusa Spar.

Section 5.29    No Business Conduct.  JVCo was formed on July 16, 2018 solely for the purposes of the transactions contemplated hereby.  From its inception through the Execution Date, JVCo has not engaged in any activity, other than such actions in connection with (i) its organization and (ii) the preparation, negotiation, and execution of this Agreement and the transactions

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contemplated hereby. JVCo has no operations, has not generated any revenues and has no liabilities other than those incurred in connection with the foregoing.

Section 5.30    Ownership of JVCo.  MEPU is the record and beneficial owner of JVCo, free and clear of all Encumbrances, except for those created by applicable securities Laws or contained in the current limited liability company agreement of JVCo.  

Section 5.31    Anticorruption. 

(a)    Neither MEPU nor any of its Controlled Representatives has made, offered, promised, or authorized nor will make, offer, promise or authorize the giving of any payment, gift, promise, entertainment or other advantage, whether directly or indirectly, to or for the direct or indirect use or benefit of any authority, public official or civil servant, any political party, political party official, or candidate for office, or any other public or private individual or entity, where such offer, promise, payment, gift or entertainment would violate any Anticorruption Laws.

(b)    Each of MEPU and its Controlled Representatives has complied and will comply with the Anticorruption Laws.

(c)    Neither MEPU nor any of its Controlled Representatives (i) has paid nor will pay, whether directly or indirectly through any Person or entity, any improper fees, commissions or rebates to the other Party or to any of such other Party’s Controlled Representatives, and (ii) has offered, promised, authorized or provided, nor will offer, promise, authorize or provide to the other Party or to any of such other Party’s Controlled Representatives any gifts or entertainment of significant cost or value in order to improperly influence or induce any actions or inactions in connection with this Agreement.

(d)    MEPU has adequate policies and procedures in place in relation to business ethics and conduct and Anticorruption Laws.

(e)    MEPU is in compliance and will comply with any applicable Laws regarding trade sanctions.

(f)    Neither MEPU nor any of its Controlled Representatives (i) has used or will use property, rights and values arising, directly or indirectly, from illicit activities nor (ii) has hidden or concealed the nature, source, location, disposition, movement or ownership of such property, rights and values. In addition, MEPU has complied and will comply with any applicable Laws relating to money-laundering.

Section 5.32    Seismic Data.  MEPU does not own any proprietary Seismic Data related to the Assets.

ARTICLE 6    REPRESENTATIONS AND WARRANTIES OF PAI

Section 6.1    Disclaimers

(a)    Except as and to the extent expressly set forth in this Article 6 or in the certificate of PAI to be delivered pursuant to Section 9.3(h) or in the PAI Conveyance, MEPU 

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acknowledges and agrees that (i) PAI makes no representations or warranties, express or implied, and (ii) PAI expressly disclaims all Liability and responsibility for any representation, warranty, statement or information made or communicated (orally or in writing) to PAI or any of its Representatives (including any opinion, information, projection or advice that may have been provided to PAI by any officer, director, employee, agent, consultant, Representative or advisor of PAI or any of its Affiliates), and PAI irrevocably waives (on behalf of itself, its Affiliates and their successors and assigns) any and all Liabilities it or they may have against PAI or its Affiliates associated with the same.

(b)    EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN THIS Article 6 OR IN THE CERTIFICATE OF PAI TO BE DELIVERED AT CLOSING PURSUANT TO Section 9.3(h) OR IN THE PAI CONVEYANCE, WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, MEPU ACKNOWLEDGES AND AGREES THAT PAI EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, WITH RESPECT TO THE PAI ASSETS, INCLUDING AS TO (I) TITLE TO ANY OF THE PAI ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE PAI ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF PETROLEUM SUBSTANCES IN OR FROM THE PAI ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE PAI ASSETS OR FUTURE REVENUES GENERATED BY THE PAI ASSETS, (V) THE PRODUCTION OF PETROLEUM SUBSTANCES FROM THE PAI ASSETS, OR WHETHER PRODUCTION HAS BEEN CONTINUOUS, OR IN PAYING QUANTITIES, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE PAI ASSETS, OR (VII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO MEPU OR ITS AFFILIATES, OR ITS OR THEIR REPRESENTATIVES IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, AND FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OR ANY EQUIPMENT, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT MEPU HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS MEPU DEEMS APPROPRIATE.  EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN THIS Article 6 OR IN THE CERTIFICATE OF PAI TO BE DELIVERED AT CLOSING PURSUANT TO Section 9.3(h) OR IN THE PAI CONVEYANCE OR AS OTHERWISE SET FORTH IN Article 11, WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, MEPU ACKNOWLEDGES AND AGREES THAT THE PAI ASSETS ARE BEING ASSIGNED AND CONVEYED TO JVCO “AS-IS, WHERE-IS,” WITH ALL FAULTS AND DEFECTS IN THEIR PRESENT CONDITION AND STATE OF REPAIR, WITHOUT RECOURSE.

(c)    MEPU EXPRESSLY WAIVES THE WARRANTY OF FITNESS FOR INTENDED PURPOSES OR GUARANTEE AGAINST HIDDEN OR LATENT REDHIBITORY VICES UNDER LOUISIANA LAW, INCLUDING LOUISIANA CIVIL CODE ARTICLES 2520 THROUGH 2548, AND THE WARRANTY IMPOSED BY LOUISIANA

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CIVIL CODE ARTICLE 2475; WAIVES ALL RIGHTS IN REDHIBITION PURSUANT TO LOUISIANA CIVIL CODE ARTICLES 2520, ET SEQ.; OR FOR RESTITUTION OR OTHER DIMINUTION OF THE CONSIDERATION; ACKNOWLEDGES THAT THIS EXPRESS WAIVER SHALL BE CONSIDERED A MATERIAL AND INTEGRAL PART OF THIS TRANSFER AND THE CONSIDERATION THEREOF; AND ACKNOWLEDGES THAT THIS WAIVER HAS BEEN BROUGHT TO THE ATTENTION OF MEPU AND EXPLAINED IN DETAIL AND THAT MEPU HAS VOLUNTARILY AND KNOWINGLY CONSENTED TO THIS WAIVER.

(d)    IT IS THE INTENTION OF THE PARTIES THAT MEPU’S RIGHTS AND REMEDIES WITH RESPECT TO THIS TRANSACTION AND WITH RESPECT TO ALL ACTS OR PRACTICES OF PAI, PAST, PRESENT OR FUTURE, IN CONNECTION WITH THIS TRANSACTION SHALL BE GOVERNED BY LEGAL PRINCIPLES OTHER THAN THE DTPA OR UTPCPL.  AS SUCH, MEPU HEREBY WAIVES THE APPLICABILITY OF THE DTPA AND THE UTPCPL TO THIS TRANSACTION AND ANY AND ALL DUTIES, RIGHTS OR REMEDIES THAT MIGHT BE IMPOSED BY THE DTPA AND/OR THE UTPCPL, WHETHER SUCH DUTIES, RIGHTS AND REMEDIES ARE APPLIED DIRECTLY BY THE DTPA OR THE UTPCPL ITSELF OR INDIRECTLY IN CONNECTION WITH OTHER STATUTES; PROVIDED, HOWEVER, MEPU DOES NOT WAIVE § 17.555 OF THE DTPA.  MEPU ACKNOWLEDGES, REPRESENTS AND WARRANTS THAT IT IS ACQUIRING THE INTEREST IN JVCO FOR COMMERCIAL OR BUSINESS USE; THAT IT HAS ASSETS OF $5 MILLION OR MORE ACCORDING TO ITS MOST RECENT FINANCIAL STATEMENT PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES; THAT IT HAS KNOWLEDGE AND EXPERIENCE IN FINANCIAL AND BUSINESS MATTERS THAT ENABLE IT TO EVALUATE THE MERITS AND RISKS OF A TRANSACTION SUCH AS THIS; AND THAT IT IS NOT IN A SIGNIFICANTLY DISPARATE BARGAINING POSITION WITH PAI.

(e)    The Parties hereby waive compliance with the provisions of any bulk sales, bulk transfer or similar Laws of any jurisdiction that may otherwise be applicable with respect to the contribution or transfer of any or all of the Assets to JVCo.

(f)    Any representation “to the knowledge of PAI” or “to PAI’s knowledge” is limited to matters within the actual knowledge (with duty of Due Inquiry) of Persons listed on Schedule 6.1(f).

Subject to the foregoing provisions of this Section 6.1, and the other terms and conditions of this Agreement, PAI represents and warrants to MEPU the matters set out in Section 6.2 through Section 6.28.

Section 6.2    Existence and Qualification

(a)    Organization. PAI is a corporation duly organized, validly existing and in good standing under the Laws of the State of Delaware and is duly qualified to do business as a foreign corporation in good standing in each jurisdiction in which it is required to qualify in order to conduct its business, except where the failure to be so qualified would not, individually or in

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the aggregate, have a PAI Material Adverse Effect.  PAI is qualified under Law to own the Assets owned by PAI, and in particular, PAI is qualified pursuant to the rules and regulations of BOEM and BSEE to own federal oil and gas leases in the Outer Continental Shelf, Gulf of Mexico, and is in good standing with, authorized by and qualified with all Governmental Authorities with jurisdiction or cognizance over operations on the Outer Continental Shelf, Gulf of Mexico, to the extent PAI is required by such authorities to so qualify and maintain good standing, except where failure to be so qualified or to be in good standing would not, individually or in the aggregate, have a PAI Material Adverse Effect.

(b)    Power.  PAI has the corporate power to enter into and perform this Agreement (and all documents required to be executed and delivered by PAI at Closing) and to consummate the transactions contemplated by this Agreement (and such documents).

(c)    Authorization sand Enforceability.  The execution, delivery and performance of this Agreement (and all documents required to be executed and delivered by PAI at Closing) and the consummation of the transactions contemplated hereby and thereby, have been duly and validly authorized by all necessary corporate action on the part of PAI.  This Agreement has been duly executed and delivered by PAI (and all documents required to be executed and delivered by PAI at Closing shall be duly executed and delivered by PAI) and this Agreement constitutes, and at the Closing such documents shall constitute, the valid and binding obligations of PAI, enforceable in accordance with their terms except as such enforceability may be limited by applicable bankruptcy or other similar Laws affecting the rights and remedies of creditors generally as well as to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at Law).

(d)    No Conflicts.  The execution, delivery and performance of this Agreement by PAI, and the consummation of the transactions contemplated by this Agreement shall not (i) violate any provision of the certificate of incorporation or bylaws of any PAI, (ii) result in any material default (with due notice or lapse of time or both) or the creation of any Encumbrance (other than a Permitted Encumbrance) or give rise to any right of termination, cancellation or acceleration under any material note, bond, mortgage, indenture, license or agreement to which PAI is a party or by which it or any of the PAI Assets is bound, (iii) violate any judgment, order, ruling, or decree applicable to PAI as a party in interest or the PAI Assets, or (iv) violate any Laws applicable to PAI or any of the PAI Assets.

Section 6.3    Liability for Brokers’ FeesMEPU (and each of its Affiliates) shall not directly or indirectly have any responsibility, Liability or expense, as a result of undertakings or agreements of PAI or any of its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation to an intermediary in connection with the negotiation, execution or delivery of this Agreement or any agreement or transactions contemplated hereby.

Section 6.4    Litigation.  Except as disclosed on Schedule 6.4, there are no litigation or arbitral proceedings (a) pending or, to PAI’s knowledge, threatened against PAI or its Affiliates relating to PAI’s ownership or PAI’s operation of the PAI Assets, (b) (i) pending or, to PAI’s knowledge, threatened against the PAI Assets operated by PAI or any of its Affiliates or (ii) to PAI’s knowledge, pending or threatened against the PAI Assets operated by any Third Party, or (c) pending or, to PAI’s knowledge, threatened in writing against PAI that would prevent the

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consummation of the transactions contemplated by this Agreement. Except as disclosed on Schedule 6.4, PAI has not received any notice of any Liability for breach of contract, tort, or violation of Law with respect to PAI’s ownership or operation of any Property.

Section 6.5    Taxes and Assessments

(a)    Except as set forth on Schedule 6.5: (i) PAI has timely filed or caused to be timely filed all material Tax Returns required to be filed under applicable Law with respect to PAI’s acquisition, ownership or operation of the PAI Assets that are due on or prior to the Closing Date, and all such Tax Returns are correct and complete in all material respects; (ii) PAI has timely paid or caused to be timely paid all material Taxes relating or applicable to PAI’s acquisition, ownership or operation of the PAI Assets (including ad valorem, property, production, severance and similar Taxes and assessments based on or measured by the ownership of property or the production of Hydrocarbons or the receipt of proceeds therefrom with respect to the PAI Assets) that are or have become due (whether or not shown on any Tax Return), and PAI is not delinquent in the payment of any such Taxes, (iii) there is not currently in effect any extension or waiver of any statute of limitations of any jurisdiction regarding the assessment or collection of any material Tax of PAI relating to PAI’s acquisition, ownership or operation of the PAI Assets; and (iv) there are no administrative or judicial proceedings pending against the PAI Assets or against PAI relating to any material Liability for Taxes of PAI with respect to the PAI Assets by any Governmental Authority.

(b)    There are no Encumbrances on any of the PAI Assets for Taxes (other than Permitted Encumbrances).

(c)    Except as set forth in Schedule 6.5, no PAI Asset is subject to any Tax partnership agreement or provisions requiring a partnership income Tax return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code or any similar state statute.

Section 6.6    Title    PAI has, and as of the Effective Time had, Defensible Title to the Properties that are PAI Assets.

Section 6.7    Environmental  Except as set forth on Schedule 6.7:

(a)    With respect to the ownership and operation of the Properties, PAI has not entered into, and is not subject to, any agreements, consents, orders, decrees, judgments, license or permit conditions or other directives of any Governmental Authority based on any Environmental Laws that are reasonably expected to (i) have an adverse effect in any material respect on current or future exploration or production activities at or in connection with any of the PAI Assets, or (ii) require any material Remediation or corrective action or impose material obligation concerning any of the PAI Assets;

(b)    PAI has not received written notice from any Person of any release or disposal of Hazardous Substances or Hydrocarbons, or any event, condition, circumstance, activity, practice or incident, in each case, concerning any land, facility, asset or Property included in the PAI Assets (including any alleged violation of Law or Permit) that would be reasonably likely to: (i) interfere with or prevent compliance by PAI or the PAI Assets with any Environmental Law or the terms of any Permit issued pursuant thereto; or (ii) give rise to or result in any common

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Law or other Liability under applicable Environmental Laws (including any Permits issued pursuant to such Environmental Laws) of PAI to any Person with respect to the PAI Assets;

(c)    PAI has made available to MEPU true and complete copies of all (i) non-privileged, material reports and studies prepared at the request of PAI or its Affiliates by Third Parties to the extent (A) in PAI’s or its Affiliates’ possession and control and (B) PAI or its applicable Affiliate is permitted to disclose such report or study (following PAI’s use of commercially reasonable efforts to obtain such permission), and (ii) material written notices received by PAI or its Affiliates from Governmental Authorities (including any requests for information under applicable Environmental Laws), in each case of either clause (i) or (ii) hereof, specifically addressing environmental conditions or compliance with Environmental Laws related to the ownership, operation or use of the PAI Assets; and

(d)    Except for Decommissioning which is addressed in Section 6.15, to PAI’s knowledge, there are no material liabilities under or uncured violations of any applicable Environmental Laws (including any Permits issued pursuant to such Environmental Laws) with respect to the PAI Assets and no material obligations to Remediate conditions upon the PAI Assets under applicable Environmental Law (and no such obligation would arise as a result of notice or lapse of time or both).

Section 6.8    Outstanding Capital Commitments.  Except as disclosed on Schedule 6.8, as of the Execution Date, there are no outstanding AFE or other commitments to make capital expenditures which are binding on the PAI Assets and which PAI reasonably anticipates will individually require expenditures after the Effective Time in excess of Two Million Dollars $(2,000,000).

Section 6.9    Compliance with Laws.  Except with respect to Environmental Laws and Anticorruption Laws and except as disclosed on Schedule 6.9, (a) PAI and each of its Affiliates have materially complied with all applicable Laws related to the ownership of the PAI Assets and (b) the PAI Assets have been operated, developed, maintained, and used, including the production of all Hydrocarbons attributable thereto, in material compliance with all applicable Laws, provided that subsection (b) shall be qualified by PAI’s knowledge with respect to (i) any PAI Assets for which PAI or any of its Affiliates does not serve as the operator thereof, and (ii) the period prior to PAI’s acquisition of such Assets.

Section 6.10    Contracts

(a)    Schedule 6.10(a) sets forth all Contracts of the type described below with respect to the PAI Assets, other than Leases (collectively, the “PAI Material Contracts”):

(i)    other than any Contract that is a Hydrocarbon purchase and sale, transportation, gathering, treating, processing, dedication or similar Contract, any Contract that can reasonably be expected to result in aggregate payments by PAI or any Affiliate of PAI of more than Two Million Dollars $(2,000,000) during the current or any subsequent calendar year or Ten Million Dollars $(10,000,000) in the aggregate over the term of such Contract;

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(ii)    other than any Contract that is a Hydrocarbon purchase and sale, transportation, gathering, treating, processing, dedication or similar Contract, any Contract that can reasonably be expected to result in aggregate revenues to PAI or any Affiliate of PAI of more than Two Million Dollars $(2,000,000) during the current or any subsequent calendar year or Ten Million Dollars $(10,000,000)  in the aggregate over the term of such Contract;

(iii)    any Contract that is a Hydrocarbon purchase and sale, transportation, gathering, treating, processing, dedication or similar Contract not terminable upon sixty (60) days or less notice;

(iv)    any Contract that is an indenture, mortgage, loan, credit or sale-leaseback, guarantee of any obligation, bonds, letters of credit or similar financial Contract;

(v)    any Contract that constitutes a lease under which PAI or any Affiliate of PAI is the lessor or the lessee of any real or personal property (including Equipment and Real Property, but not including any of the other Properties) which lease (A) cannot be terminated by PAI without penalty upon sixty (60) days or less notice and (B) involves an annual base rental of more than Two Hundred Fifty Thousand Dollars $(250,000);

(vi)    other than joint operating agreements, any Contract that constitutes a non-competition agreement or any agreement that purports to restrict, limit or prohibit the manner in which, or the locations in which, PAI or any Affiliate of PAI conducts business, including area of mutual interest Contracts;

(vii)    any Contract that contains calls upon or options to purchase production;

(viii)    any Contract that constitutes swap, forward, future or derivative transaction or option or other similar hedge Contracts;

(ix)    any Contract that provides for a power of attorney with respect to the PAI Assets that will not be terminated prior to the Closing Date;

(x)    any Contract that constitutes a development agreement, participation agreement, farmout agreement, partnership agreement, joint venture agreement or similar Contract (other than Tax partnership agreements);

(xi)    any Contracts for the use or sharing of drilling rigs or for the use of Equipment;

(xii)    any Contract (executory or otherwise) to sell, lease, farmout, or otherwise dispose of or encumber any interest in any of the PAI Assets after the Execution Date, other than conventional rights of reassignment arising in connection with PAI’s surrender or release of any of the PAI Assets, to the extent such rights are not currently applicable;

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(xiii)    any Contract that constitutes a joint or unit operating agreement;

(xiv)    any Contract for which the primary purpose is to provide for the indemnification of another Person;

(xv)    any Contract (other than the Properties) that would obligate JVCo to drill additional wells or conduct other material development operations after the Closing;

(xvi)    subject to Section 7.15(b), to the extent disclosable to PAI, any Contract that is related to Seismic Data described in clause (A) of the definition thereof;

(xvii)    any Contract with any Affiliate of PAI;

(xviii)    any purchase and sale agreements pursuant to which PAI or its Affiliates acquired (directly or indirectly) the PAI Assets that contain indemnity obligations that will be binding on JVCo following Closing; and

(xix)    any Contract that constitutes an amendment, supplement, or modification in respect of any of the foregoing.

(b)    With respect to the PAI Material Contracts:

(i)    each of the PAI Material Contracts is in full force and effect;

(ii)    there exists no material default under any PAI Material Contract by PAI or, to PAI’s knowledge, by any other Person that is a party to such PAI Material Contract or Leases;

(iii)    no event has occurred that upon receipt of notice or lapse of time or both would constitute any material default under any such Contract by PAI or, to PAI’s knowledge, any other Person who is a party to such PAI Material Contract or Leases;

(iv)    to the extent material, PAI has not given nor received any unresolved written notice of default, amendment, waiver, price redetermination, market out, curtailment or termination with respect to any PAI Material Contract or Lease; and

(v)    prior to the execution of this Agreement, PAI has made available to PAI true and complete copies of each PAI Material Contract and all amendments thereto.

Section 6.11    Payments for Production.  Except as set forth on Schedule 6.11, all proceeds from the sale of Hydrocarbons attributable to PAI’s interest in the Properties are currently being paid in full to PAI (after Tax withholdings or similar deductions required by the terms of the Contracts or applicable Law).  Except as set forth in the PAI Material Contracts, PAI is not obligated by virtue of a take or pay payment, advance payment or other similar payment (other than royalties, overriding royalties and similar arrangements established in the Leases or reflected on Exhibit A-1), to deliver Hydrocarbons, or proceeds from the sale thereof, attributable to PAI’s interest in the Properties at some future time without receiving payment therefor at or after the time of delivery.

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Section 6.12    Imbalances.  Except as set forth in Schedule 6.12, there are no Imbalances associated with the PAI Assets as of the Effective Time.

Section 6.13    Consents and Preferential Purchase Rights.  Except as set forth on Schedule 6.13, no Consents or Preferential Rights are applicable to the transfer of the PAI Assets from PAI to JVCo or any of the other transactions contemplated by this Agreement, except for compliance with the HSR Act and Customary Post-Closing Consents.

Section 6.14    Permits.    The Permits constitute all material permits, licenses, registrations, orders, approvals, variances, waivers and other authorizations required to be obtained from any Governmental Authority for conducting its business with respect to the PAI Assets as presently conducted, including all Permits required to be obtained pursuant to Environmental Laws.  Each of the Permits is in full force and effect, there exists no material uncured violations of any Permit by PAI or, to PAI’s knowledge, by any other Person, and no event has occurred that upon receipt of notice or lapse of time or both would constitute a material default under any such Permit by PAI or, to PAI’s knowledge, any other Person.  Neither PAI nor any Affiliate of PAI has received any written notice from any Governmental Authority of any violation of any Permit in connection with the ownership and/or operation of the PAI Assets that remains uncured, and there are no proceedings pending or, to PAI’s knowledge, threatened that might result in any material modification, revocation, termination or suspension of any Permit or which would require any material corrective or remedial action by PAI or any Affiliate of PAI.

Section 6.15    Wells; Decommissioning Activities.  Except as set forth on Schedule 6.15, PAI represents as follows with respect to the PAI Assets for which PAI acts as operator:

(a)    There are no Wells (A) in respect of which PAI has received an order from any Governmental Authority requiring that such Wells be plugged and abandoned within eighteen (18) months after the Execution Date, other than any such Decommissioning activities that have been completed in all material respects in accordance with applicable Law; or (B) that are neither in use for purposes of production or injection, nor suspended or temporarily abandoned in accordance with applicable Law, that, in each case, have not been plugged and abandoned and otherwise Decommissioned in all material respects in accordance with applicable Law;

(b)    PAI has not received an order from any Governmental Authority requiring that any Decommissioning activities take place with respect to the Properties within eighteen (18) months after the Execution Date, other than any such Decommissioning activities that have been completed in all material respects in accordance with applicable Law;

(c)    To PAI’s knowledge, all Decommissioning activities conducted with respect to the PAI Assets have been performed in all material respects in accordance with all applicable Leases, the PAI Material Contracts and all applicable Laws;

(d)    There is no Equipment in respect of which PAI has received an order from any Governmental Authority requiring that such Equipment be Decommissioned within eighteen (18) months after the Execution Date, other than any such Decommissioning activities that have been completed in all material respects in accordance with applicable Law;

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(e)    No Well is subject to penalties on allowables after the Effective Time because of overproduction; and

(f)    There are no Wells that were drilled and completed by PAI , or to PAI’s knowledge by any Third Party, outside the limits permitted by all applicable Laws, Permits, Contracts and Leases.

Section 6.16    Equipment.  (i) The Wells and Equipment have been maintained in operable repair, working order and operating condition and are suitable for the purposes for which such Wells or Equipment were constructed or obtained or are currently being used, in each case, in all material respects, and (ii) PAI has all material easements, rights of way, licenses and authorization from Governmental Authorities necessary to access, construct, operate, maintain and repair the Wells and Equipment in the ordinary course of business as currently conducted by PAI and in material compliance with all applicable Laws, provided that this Section 6.16 shall be qualified by PAI’s knowledge with respect to any PAI Assets for which PAI or any of its Affiliates does not serve as the operator.

Section 6.17    Condemnation and Eminent Domain.  As of the Execution Date, no action for condemnation or taking under right of eminent domain is, to PAI’s knowledge, pending or threatened with respect to any PAI Asset or portion thereof.

Section 6.18    Bankruptcy.  There are no bankruptcy, reorganization or receivership proceedings pending or, to PAI’s knowledge, threatened against PAI or any of its Affiliates.

Section 6.19    Foreign Person.  PAI is not a “foreign person” within the meaning of Section 1445 of the Code, nor an entity disregarded as separate from any other Person within the meaning of Treasury Regulation Section 301.7701-3(a).

Section 6.20    Payout Status.  To PAI’s knowledge, Schedule 6.20 contains a list of the status of any “payout” balance, as of the date set forth on such Schedule, for those Wells related to the PAI Assets subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms).

Section 6.21    Operation of the PAI Assets.  Beginning on the date on which PAI acquired ownership of the relevant PAI Assets, the PAI Assets have been operated in material accordance with good oilfield practices as such are generally practiced with respect to oil and gas assets similar to the PAI Assets, provided that the foregoing shall be qualified by PAI’s knowledge with respect to any PAI Assets for which PAI or any of its Affiliates does not serve as the operator thereof.

Section 6.22    Royalties.  Except for the PAI Suspense Funds, PAI has paid in all material respects all royalties, overriding royalties and other burdens on production due by PAI with respect to the PAI Assets from January 1, 2018 through the month ended two (2) months prior to the month in which the Closing Date occurs for oil and the month ended three (3) months prior to the month in which the Closing Date occurs for gas and NGLs.  PAI has or shall timely file any Form-2014s with respect to royalties due on or through the month in which the Closing Date occurs and shall pay any royalties due and owing on such periods, subject to the adjustment to the PAI Adjustment Amount for any royalties pursuant to Section 3.2.

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Section 6.23    Suspense FundsSchedule 6.23 lists all proceeds of production and associated penalties and interest in respect of any of the PAI Assets that are payable to Third Parties and are being held in suspense by PAI as of the Execution Date (the “PAI Suspense Funds”), a description of the source of such PAI Suspense Funds and the reason they are being held in suspense, and, if known, the name or names of the Third Parties claiming such PAI Suspense Funds or to whom such PAI Suspense Funds may be owed.

Section 6.24    Bonds and Credit SupportSchedule 6.24 lists all bonds, letters of credit and other similar credit support instruments maintained by PAI or any Affiliate of PAI with any Governmental Authority or other Third Party with respect to the PAI Assets.

Section 6.25    Non-Consent Operations.  Except as set forth on Schedule 6.25, PAI has neither elected nor been deemed to have elected to “non-consent,” nor failed to participate in, the drilling or reworking of a well, any seismic program or any other operation which would cause PAI or JVCo to suffer a penalty or lose or forfeit any interests in the PAI under any applicable operating agreement.

Section 6.26    Assets Complete.   The PAI Assets constitute all of PAI’s interests in exploration and production properties in the Gulf of Mexico, excluding the Excluded Assets.

Section 6.27    Intellectual Property.  PAI does not own any registered Intellectual Property which would constitute Assets.  Except as set forth on Schedule 6.27, (i) PAI owns and possesses all right, title and interest in and to, or has a valid right to use, all Intellectual Property, (ii) none of PAI or any of its Affiliates is infringing, misappropriating, diluting, or otherwise violating any intellectual property rights of any other Person in connection with their ownership and operation of the PAI Assets, (iii) no actions, suits, litigation, claims, causes of action, demands, or other proceedings are pending or have been threatened during the past three (3) years, alleging any such infringement, misappropriation, dilution or other violation, currently or in the past, by PAI or any of its Affiliates, (iv) no Person is infringing, misappropriating, diluting, or otherwise violating any Intellectual Property and (v) PAI and each of its Affiliates have taken reasonable efforts to maintain and protect all material Intellectual Property.

Section 6.28    Anticorruption. 

(a)    Neither PAI nor any of its Controlled Representatives has made, offered, promised, or authorized nor will make, offer, promise or authorize the giving of any payment, gift, promise, entertainment or other advantage, whether directly or indirectly, to or for the direct or indirect use or benefit of any authority, public official or civil servant, any political party, political party official, or candidate for office, or any other public or private individual or entity, where such offer, promise, payment, gift or entertainment would violate any Anticorruption Laws.

(b)    Each of PAI and its Controlled Representatives has complied and will comply with the Anticorruption Laws.

(c)    Neither PAI nor any of its Controlled Representatives (i) has paid nor will pay, whether directly or indirectly through any Person or entity, any improper fees, commissions or rebates to the other Party or to any of such other Party’s Controlled Representatives, and (ii) has offered, promised, authorized or provided, nor will offer, promise, authorize or provide to the other

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Party or to any of such other Party’s Controlled Representatives any gifts or entertainment of significant cost or value in order to improperly influence or induce any actions or inactions in connection with this Agreement.

(d)    PAI has adequate policies and procedures in place in relation to business ethics and conduct and Anticorruption Laws.

(e)    PAI is in compliance and will comply with any applicable Laws regarding trade sanctions.

(f)    Neither PAI nor any of its Controlled Representatives (i) has used or will use property, rights and values arising, directly or indirectly, from illicit activities nor (ii) has hidden or concealed the nature, source, location, disposition, movement or ownership of such property, rights and values. In addition, PAI has complied and will comply with any applicable Laws relating to money-laundering.

ARTICLE 7    COVENANTS OF THE PARTIES

Section 7.1    Access.  From the Execution Date to the earlier of (i) the Closing and (ii) termination of this Agreement pursuant to Article 10, each Party will give the other Party and its Representatives (a) reasonable access to the Assets to perform site visits of all Wells and Equipment, (b) reasonable access to and the right to copy, at the requesting Party’s expense, the Records in such Party’s possession, for the purpose of conducting an investigation of the Assets and (c) reasonable access to the appropriate officers and employees of such Party and its Affiliates having responsibility for the respective Assets to provide assistance in connection with the investigation of the Assets, but only to the extent that a Party may do so without violating any obligations to any Third Party and to the extent that such Party has authority to grant such access without breaching any restriction binding on such Party (provided that such Party shall use commercially reasonable efforts to obtain consent or waivers of such requirements from any such Third Parties).  Such access by a Party shall be limited to the other Party’s normal business hours, and such Party’s investigation shall be conducted in a manner that does not unreasonably interfere with the operation of the Assets. All such activities by the Parties shall be subject to any boarding agreements or releases or other agreements required by any operator of the Properties (provided that, with respect to any Assets operated by a Party  or any of its Affiliates, such boarding agreements shall be provided to the other Party reasonably promptly upon request), shall be solely for the purpose of evaluating the Assets in connection with consummating the transactions contemplated by this Agreement, and shall be subject to each Party’s and its Representatives’ compliance with the applicable operator’s (and/or Party’s) policies and procedures, in each case to the extent such Party and/or its Representatives were made aware of such policies and procedures prior to or upon such access.  Each Party shall be responsible for arranging, at its own cost, transportation to and from any such Properties.  All information obtained by a Party and its Representatives under this Section 7.1 shall be subject to the terms of that certain confidentiality agreement between the Parties dated November 6, 2017, as amended (the Confidentiality Agreement”).

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Section 7.2    Confidentiality; Public Announcements

(a)    From the Execution Date to the earlier of (i) the Closing and (ii) termination of this Agreement pursuant to Article 10,  neither Party shall make any press release or other public announcement regarding the existence of this Agreement, the contents hereof or the transactions contemplated hereby without the prior written consent of the other Party, which consent may not be unreasonably withheld; provided, however, the foregoing shall not restrict disclosures by a Party (i) that are required by applicable securities or other Laws or the applicable rules of any stock exchange having jurisdiction over the disclosing Party or its Affiliates, (ii) to Governmental Authorities and Third Parties holding Preferential Rights or rights of Consent that may be applicable to the transactions contemplated by this Agreement, as reasonably necessary to obtain waivers of such Preferential Rights or such Consents, (iii) to any current or potential debtholder or equityholder of either Party, (iv) to any Person owning Seismic Data that requires that a Party obtain a license to such Seismic Data or obtain consent to transfer such Seismic Data, or (v) to any insurer or potential insurer of either Party.

(b)    From the Execution Date until the termination of all confidentiality obligations under the LLC Agreement,  each Party shall use commercially reasonable efforts to protect the confidentiality of all geological and geophysical information, trade secrets and other data that is in such Party’s possession or control concerning the Assets and is neither publicly known nor required by Law or any stock exchange to be disclosed.

Section 7.3    Operation of Business.   Except (x) for the operations covered by the AFEs and other capital commitments described on Schedule 5.8 and Schedule 6.8, as applicable, set forth on Schedule 5.25 or Schedule 6.25, as applicable, or as otherwise set forth on Schedule 7.3, (y) as expressly consented to in writing by the other Party, or (z) as required by Law or for emergency operations that are advisable (in a Party’s good faith judgment) to protect life, property or the environment:

(a)    Each Party agrees that from and after the Execution Date until Closing, such Party shall (or shall use its commercially reasonable efforts to cause any Third Party operators to):

(i)    operate the Assets (A) as would a reasonable and prudent operator, (B) in the ordinary course of business consistent with past practice, and (C) in accordance with all applicable Laws and the terms of the Leases, Permits, Easements and Contracts;

(ii)    maintain all Leases, Easements, Permits, bonds, letters of credit or other similar credit support and Contracts in full force and effect and in accordance with the terms of the Leases, Easements, Permits, credit support and the Contracts relating thereto;

(iii)    pay all expenses incurred with respect to the Assets in the ordinary course of business;

(iv)    timely make any and all filings, reports and notices to any Governmental Authorities with respect to the Assets as required to be made by such Party under applicable Law, the Permits, the Easements, the Contracts or the Leases;

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(v)    maintain the books of account and records relating to the Assets (including the Records) in the ordinary course of business, in accordance with the usual accounting practices of each such Person;

(vi)    give prompt written notice to the other Party of any written notice received or given by such Party with respect to any alleged material breach by such Party or other Person of any Lease, Contract or Permit;

(vii)    give prompt written notice to the other Party of any emergency with respect to the Assets and any related emergency operations;

(viii)    give prompt notice to the other Party of (A) any written notice of any material damage to or destruction of any of the Assets and (B) any written notice received by such Party or any of its Affiliates of any material claim asserting any breach of contract, tort or violation of Law or any investigation, suit, action or litigation by or before a Governmental Authority, that, in each case, relates to the Assets;

(ix)    furnish the other Party with copies of all drilling, completion and workover AFEs or forced pooling applications within three (3) days of receipt from Third Parties or generation by such Party or any Affiliate of such Party; and

(x)    cause to be timely paid all rentals, royalties, shut-in royalties, minimum royalties and other payments and perform all other acts that are necessary to maintain such Party’s rights in and to the Leases and Contracts in full force and effect as to the entire areal extent and all depths of the Leases, and to maintain Defensible Title to the Leases until the Closing, and pay timely all costs and expenses incurred by such Party in connection with such Leases and Contracts.

(b)    Each Party agrees that from and after the Execution Date until Closing, it will not (or shall use its commercially reasonable efforts to cause any Third Party operators not to):

(i)    subject to the provisions of this Section 7.3(b)(i), propose or agree to participate, or elect not to participate in any operation with respect to the Assets anticipated to cost in excess of Two Million Dollars $(2,000,000) without the prior written consent of the other Party, provided that (A) with respect to any AFE for an operation to be conducted in connection with the Assets that is anticipated to cost in excess of Ten Million Dollars $(10,000,000) per operation, upon receipt of such AFE from such Party,  the other Party shall review and, no later than 48 hours prior to such Party’s deadline to respond to such AFE, respond to  such Party in writing with respect to whether it desires to consent or non-consent the operation covered by such AFE; provided that if the other Party does not timely respond with its election with respect to any such AFE within such 30 day period, then the other Party shall be deemed to have responded to approve such AFE; and (B) if the other Party affirmatively elects to non-consent to any such operation, such Party shall not be entitled to consent to such operation;

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(ii)    enter into a Contract that if entered into on or prior to the Execution Date, would have been a Material Contract, or amend any Contract that, if amended on or prior to the Execution Date, would have been a Material Contract, as amended;

(iii)    create (or suffer to exist as a result of any action by such Party) any material Encumbrance on any of the Assets (except for Permitted Encumbrances);

(iv)    terminate (unless such Material Contract terminates pursuant to its stated terms) or amend any material terms of any Material Contract;

(v)    settle any material suit or litigation (other than those relating to Retained Liabilities) or waive any claims or rights of value (except those attributable to periods prior to the Effective Time), in each case, attributable to the Assets;

(vi)    transfer, sell, mortgage, pledge or dispose of the Assets other than the sale and/or disposal of Hydrocarbons in the ordinary course of business and sales of equipment that is no longer necessary in the operation of the Assets or for which replacement equipment of equal or greater value has been obtained;

(vii)    with respect to the Assets, (A) make, change or revoke any Tax election or method; (B) file any amended Tax Return; (C) enter into any closing agreement; (D) settle or compromise any Tax claim or assessment; or (E) consent to any extension or waiver of the limitation period applicable to any claim or assessment with respect to Taxes;

(viii)    reduce or terminate (or cause to be reduced or terminated or allow to expire without renewal at equivalent or greater amounts of coverage) any insurance coverage now held by such Party or its Affiliates in connection with the Assets;

(ix)    abandon any Well capable of commercial production, or release or abandon all or any part of the Assets capable of commercial production, or release or abandon all or any portion of the Leases;

(x)    voluntarily waive or release any material right with respect to any Asset or relinquish its position as operator of any Asset; or

(xi)    commit to do any of the foregoing.

Section 7.4     HSR Filings.   As promptly as practicable and in any event not later than ten (10) Business Days after the Execution Date, MEPU shall file with the Federal Trade Commission and the Department of Justice, as applicable, the required notification and report forms under the HSR Act and shall as promptly as practicable furnish any supplemental information or documentary material that may be requested in connection therewith. MEPU shall request, and use its commercially reasonable efforts to obtain, early termination of any applicable waiting period under the HSR Act.  MEPU shall bear 100% of all filing fees under the HSR Act and shall bear its own costs for the preparation of any such filing and its other costs associated with compliance with the HSR Act.  PAI shall have the right to review in advance all characterizations of the information relating to this Agreement and the transactions contemplated hereby that appear in any filing made with a Governmental Authority as contemplated herein.

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 MEPU agrees to respond promptly to any inquiries from Governmental Authorities, including the Department of Justice or the Federal Trade Commission, concerning such filings and to comply in all material respects with the filing requirements of the HSR Act or other applicable Law.  The Parties shall cooperate with each other and, subject to the terms of the Confidentiality Agreement, PAI shall promptly furnish all information to MEPU that is reasonably necessary in connection with MEPU’s compliance with the HSR Act or other applicable Law.  MEPU shall keep PAI fully apprised with respect to any requests from or communications with Governmental Authorities, including the Department of Justice or the Federal Trade Commission, concerning such filings and shall consult PAI with respect to all responses thereto.  MEPU shall use its commercially reasonable efforts to take all actions reasonably necessary and appropriate in connection with any HSR Act or other applicable Law filing to consummate the transactions contemplated hereby, provided, however, that in no event will  MEPU or any of its Affiliates be required to agree to any divestiture, transfer or licensing of its properties, assets or businesses, or to the imposition of any limitation on the ability of any of the foregoing to conduct its businesses or to own or exercise control of its assets and properties.

Section 7.5    FCC Filings.   Each Party shall prepare, as soon as is practical following the Execution Date, any necessary filings in connection with the transactions contemplated by this Agreement that may be required to be filed by such Party with the Federal Communications Commission.  The Parties shall promptly furnish each other with copies of any notices, correspondence or other written communication from the Federal Communications Commission, shall promptly make any appropriate or necessary subsequent or supplemental filings and shall cooperate in the preparation of such filings as is reasonably necessary and appropriate.

Section 7.6    Tax Matters

(a)    Each of MEPU and PAI shall be allocated and bear all Asset Taxes with respect to the MEPU Assets and PAI Assets, respectively, attributable to (i) any Tax period ending prior to the Effective Time and (ii) the portion of any Straddle Period ending immediately prior to the Effective Time.  JVCo shall be allocated and bear all Asset Taxes with respect to the MEPU Assets and PAI Assets attributable to (x) any Tax period beginning at or after the Effective Time and (y) the portion of any Straddle Period beginning at the Effective Time.  For purposes of determining the allocations described in this Section 7.6(a), (A) Asset Taxes that are attributable to the severance or production of Hydrocarbons shall be allocated to the period in which the severance or production giving rise to such Asset Taxes occurred, (B) Asset Taxes that are based upon or related to income or receipts or imposed on a transactional basis (other than such Asset Taxes described in clause (A) or (C)), shall be allocated to the period in which the transaction giving rise to such Asset Taxes occurred, and (C) Asset Taxes that are ad valorem, property or other Asset Taxes imposed on a periodic basis pertaining to a Straddle Period shall be allocated between the portion of such Straddle Period ending immediately prior to the Effective Time and the portion of such Straddle Period beginning at the Effective Time by prorating each such Asset Tax based on the number of days in the applicable Straddle Period that occur before the day on which the Effective Time occurs, on the one hand, and the number of days in such Straddle Period that occur on or after the day on which the Effective Time occurs, on the other hand.

(b)    To the extent the actual amount of an Asset Tax is not known at the time an adjustment is to be made with respect to such Asset Tax pursuant to Section 3.1,  Section 3.2 or

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 Section 9.4, as applicable, the Parties shall utilize the most recent information available in estimating the amount of such Asset Tax for purposes of such adjustment.  To the extent the actual amount of an Asset Tax (or the amount thereof paid by or allocated pursuant to this Agreement to a Party) is ultimately determined to be different than the amount (if any) that was taken into account in the applicable Final Settlement Statement as finally determined pursuant to Section 9.4, timely payments will be made from one Party to the other to the extent necessary to cause each Party to bear the amount of such Asset Tax that is allocable to such Party under Section 7.6(a).

(c)    Each Transferor shall timely file any Tax Return with respect to Asset Taxes described in this Section 7.6 due on or before the Closing Date or that otherwise relates solely to periods before the Effective Time (a Pre-Closing Tax Return”) consistently with past practice and shall pay any Asset Taxes shown due and owing on such Pre-Closing Tax Return, subject to the applicable Transferor’s right to reimbursement for any Asset Taxes for which JVCo is responsible under  Section 7.6(a); provided, however, that any material Pre-Closing Tax Return shall be filed following 30 days’ notice to the other Transferor who shall be provided with a draft of the relevant Tax Return (along with any supporting schedules and other workpapers used in preparing the Tax Return, if any) and may raise reasonable objections, with any unresolved disputes settled by the accounting firm procedures set forth in Section 3.4.  From and after the Closing Date, JVCo shall timely file any Tax Returns with respect to Asset Taxes described in this Section 7.6 that are required to be filed after the Closing Date, including such Tax Returns required to be filed after the Closing Date for any Straddle Period (a Post-Closing Tax Return”), and shall pay any Asset Taxes shown due and owing on such Post-Closing Tax Return, subject to JVCo’s right to reimbursement for any Asset Taxes for which the applicable Transferor  is responsible under Section 7.6(a).  JVCo shall file any Post-Closing Tax Return in a manner consistent with past practice.  At least thirty (30) days prior to filing, JVCo shall deliver to each Transferor a draft of any such Post-Closing Tax Return (along with any supporting schedules and other workpapers used in preparing the Tax Return, if any) and each Transferor may raise reasonable objections, with any unresolved disputes settled by the accounting firm procedures set forth in Section 3.4. The Parties agree that (i) this Section 7.6(c) is intended to solely address the timing and manner in which certain Tax returns relating to Asset Taxes are filed and the Asset Taxes shown thereon are paid to the applicable Governmental Authority, and (ii) nothing in this Section 7.6(c) shall be interpreted as altering the manner in which Asset Taxes are allocated to and economically borne by the Parties.

(d)    Each Transferor shall promptly notify JVCo in writing upon receipt of notice of any pending or threatened Tax audits or assessments relating to the income, properties or operations of such Transferor (for the avoidance of doubt, other than pending or threatened Income Tax audits or assessments) that are reasonably expected to give rise to a lien or Encumbrance on the Assets after the Closing Date.  Each Transferor and JVCo shall promptly notify the other in writing upon receipt of notice of any pending or threatened Tax audit or assessment challenging the Allocation Schedule or that otherwise could give rise to a claim for indemnification hereunder.

(e)    Any payments made to any Party pursuant to Section 7.6(b) or Article 11 shall constitute an adjustment of the Initial PAI Payment first, and to any Capital Contribution thereafter, for Tax purposes and shall be treated as such by the Parties, who will cause their Affiliates to treat consistently, on their Tax returns to the extent permitted by Law.

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Section 7.7    Further Assurances; Recording.   Prior to and after Closing, each Party agrees to take such further actions, to execute, acknowledge and deliver all such further documents, and to cooperate with each other, in each case, as may be reasonably requested by the other Party for carrying out the purposes of this Agreement or of any document delivered pursuant to this Agreement or complying with any applicable Law with respect thereto, including with respect to preparation or filing of any financial statement, Tax return or other filing required to be made by any Party or any of their respective Affiliates by any Governmental Authority, stock exchange or under any applicable Law.  As soon as reasonably practicable after Closing, the Parties shall cause JVCo to record the Conveyances in the appropriate recording jurisdictions as well as with the appropriate Governmental Authorities, make all filings necessary to be made with any Governmental Authority to effectuate the transfer of the Assets and provide each Party with copies of all recorded, filed or approved instruments.

Section 7.8    Operatorship; Royalties.   With respect to all of the Assets operated by PAI or its Affiliates, PAI shall (and shall cause its Affiliates to) use its commercially reasonable efforts to support JVCo’s succession of PAI as operator for all Properties for which PAI currently serves as operator, including (a) using commercially reasonable efforts to prepare BOEM designation of operator forms to have JVCo named as the operator of such Assets, and (b) taking any other action reasonably requested by MEPU with respect to the transfer of operatorship with respect to such Assets.  The Parties shall cause JVCo to timely file any Form 2014s with respect to royalties required to be filed after the Closing Date and shall pay any royalties due and owing on such periods.  Notwithstanding anything in this Agreement and the documents to be executed hereunder and the Exhibits and Schedules attached hereto to the contrary, the Parties shall, within five (5) Business Days of the Closing Date, cause JVCo to complete and file all necessary documents for JVCo to become a designated operator for all Properties for which PAI  currently serves as operator. Pursuant to the Master Services Agreement, MEPU shall operate all Properties for which JVCo serves as operator.

Section 7.9    No Shop.   From and after the Execution Date, each Party shall immediately cease and cause to be terminated any discussions or negotiations with respect to any Third Party Acquisition.  Further, except in connection with any Preferential Rights or the contracts set forth on Schedule 7.10,  no Party shall, and no Party shall authorize or permit any of its Affiliates or any of its or their respective Controlled Representatives to, directly or indirectly, (a) encourage, solicit, participate in or initiate discussions, negotiations, inquiries, proposals or offers (including any proposal or offer to their shareholders) with or from or provide any non-public information to any Person or group of Persons concerning any Third Party Acquisition or any inquiry, proposal or offer which may lead to a Third Party Acquisition or (b) waive, terminate, modify or fail to enforce any provision of any contractual “standstill” or similar obligation of any Person.  No Party shall (and each Party shall cause its Affiliates not to) enter into any agreement, letter of intent, memorandum of understanding, agreement in principle, acquisition agreement, merger agreement, option agreement, joint venture agreement, partnership agreement or other agreement constituting or directly related to, or which is reasonably likely to lead to, a Third Party Acquisition or any proposal for a Third Party Acquisition.

Section 7.10    Representations and Warranties.   Each Party shall promptly notify the other of any fact or circumstance about which such Party has or obtains knowledge that would make any representation or warranty of such Party materially untrue or incorrect.  Except as

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otherwise provided in Section 7.15, no such notification (or failure to make any such notification) shall affect the representations or warranties of the Parties or the conditions to their respective obligations hereunder.

Section 7.11    Closing Conditions.   From the Execution Date until the Closing Date, each Party shall use commercially reasonable efforts to satisfy the conditions to the Closing set forth in Article 8.

Section 7.12    Debranding.  Unless the Parties agree otherwise, the Parties agree that no later than one hundred and eighty (180) Days after the Closing Date, they shall cause JVCo to (a) remove, obliterate, cover or replace, as appropriate, all signs, billboards, containers, drums, advertisements or other media containing any service marks, trade names, trade dress or other indicia of origin of a Transferor or any Affiliate of a Transferor located on or appurtenant to any portion of the Properties, including signs, billboards and advertisements or other media located at offices and facilities related to the Properties; and (b) return to the applicable Transferor or, at JVCo’s option, destroy all items and materials, including stationery, letterhead and purchase orders, located at or on the Properties that identify Properties of a Transferor or of any Affiliate of a Transferor or any of the Properties containing the above-described marks and have been located by a Transferor, or such items shall be destroyed upon location by JVCo, and JVCo shall agree to promptly destroy any additional materials located in the future. In addition, the Parties agree that, no later than one hundred and eighty (180) Days after the Closing Date, the Parties shall cause JVCo to replace all signs located at or on the Properties that use the above-described marks or any mark confusingly similar thereto, identify Properties of a Transferor or of any Affiliate of a Transferor, or identify a Transferor or any Affiliate of a Transferor as the operator of such Properties.

Section 7.13    NORM.   The Properties may currently or have in the past contained NORM, and special procedures associated with assessment, remediation, removal, transportation or disposal of NORM may be necessary.  Notwithstanding anything contained in any other provision of this Agreement, if Closing occurs, the Parties shall cause JVCo to expressly assume and accept sole responsibility for and pay all costs and expenses associated with assessment, remediation, removal, transportation and disposal of NORM associated with the Properties, and may not claim the fact that assessment, remediation, removal, transportation or disposal of NORM are not complete or that additional costs and expenses are required in connection with assessment, remediation, removal, transportation or disposal of NORM as an alleged Environmental Defect or a breach of a Party’s representations and warranties under this Agreement or the basis for any other redress against such Party, and each Party (on behalf of itself, its Affiliates and their successors and assigns) irrevocably waives any and all Liabilities against all MEPU Indemnified Parties and PAI Indemnified Parties associated with the same.

Section 7.14    Decommissioning.   The Properties may contain assets, wells, gathering lines, pipelines and facilities that are currently not in service or have been shut in or temporarily or permanently abandoned.  Subject to Section 5.15 and Section 6.15, but notwithstanding anything else contained in any other provision of this Agreement, if Closing occurs, the Parties shall cause JVCo to expressly assume and accept sole responsibility for and pay all costs and expenses associated with Decommissioning of the Properties, and may not claim the fact that

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Decommissioning is not complete or that additional costs and expenses are required in connection with Decommissioning as an alleged Environmental Defect or a breach of a Party’s representations and warranties under this Agreement or the basis for any other redress against any MEPU Indemnified Party or PAI Indemnified Party, and each Party (on behalf of itself, its Affiliates and their successors and assigns) irrevocably waives any and all Liabilities against the MEPU Indemnified Party and PAI Indemnified Party associated with the same.

Section 7.15    Amendment of Schedules

(a)    The Parties agree that, with respect to the representations and warranties of the Parties contained in this Agreement, each Party shall have the right, exercisable in writing no later than three Business Days prior to the Closing Date, to add, supplement or amend the Schedules to its representations and warranties with respect to any matter arising after the Effective Time and of which such Party did not have knowledge at the Execution Date, or any change in or update to any existing matter after the Execution Date.  For purposes of this Agreement, all matters disclosed pursuant to any such addition, supplement or amendment prior to Closing shall be deemed to have been included on the Schedules to such Party’s representations and warranties as of the Execution Date, provided,  however,  that except with respect to any such additions, supplements or amendments to Schedule 5.4,  Schedule 5.7,  Schedule 5.9,  Schedule 6.4,  Schedule 6.7 or Schedule 6.9,  all matters disclosed pursuant to any such addition, supplement or amendment at or prior to Closing shall be disregarded for purposes of the applicable Party’s indemnification obligations under Article 11.

(b)    With respect to any Seismic Data of a Party that is subject to any Third Party license or other Third Party agreement that prohibits disclosure of the terms of such license or agreement to JVCo,  such Party shall use its commercially reasonable efforts to obtain consent to disclose the terms of such license or agreement to the other Party and shall be required to update Schedule 5.10 or Schedule 6.10, as applicable, to the extent that any such consent to disclosure is obtained prior to the Closing Date.  Notwithstanding the foregoing, each Party acknowledges that this provision is not intended to incorporate, and that such Party will not acquire, any master license agreements or any similar agreement with any Third Parties.

Section 7.16    Transfer Orders and Letters in Lieu.   Each Party will deliver duly executed transfer orders or letters in lieu thereof on forms reasonably acceptable to the other Party directing all purchasers of production to make payment to JVCo of proceeds attributable to production from such Assets from and after the Effective Time, for delivery by JVCo to the purchasers of production.

Section 7.17    No Business Conduct. From and after the Execution Date and until Closing, MEPU shall cause JVCo not to conduct any business activities or assume or incur any liabilities other than as required or permitted by this Agreement. Without limiting the foregoing, other than as required or permitted by this Agreement, or with PAI’s prior consent, MEPU shall cause JVCo not to:

(a)    amend its Organizational Documents;

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(b)    acquire any assets, including any equity interests of another Person;

(c)    issue, split, combine or reclassify any of its equity interests;

(d)    sell or create any lien, security interest, or encumbrance on any of its membership interests;

(e)    hire any employees;

(f)    incur, assume, or guarantee any Indebtedness, other than any capital leases associated with the operations of the BW Pioneer1;

(g)    assume or incur any liabilities; or

(h)    authorize or agree, in writing or otherwise, to take any of the actions prohibited by this Section 7.17.

Section 7.18    Environmental Defects.  From and after the Execution Date until the earlier of (i) the Closing and (ii) termination of this Agreement pursuant to Article 10, each Party shall provide written notice to the other Party of any Environmental Defect that occurs in relation to its Properties.  Such written notice shall be provided promptly upon a Party becoming aware of any Environmental Defect and shall include, to the extent known by such Party at such time, (a) a reasonably detailed description of the Environmental Defect, (b) a description of the Properties affected by each Environmental Defect and (c) such Party’s estimation of the Remediation Amount for such Environmental Defect.  The Parties shall attempt to agree on all Remediation Amounts not later than three (3) Business Days prior to the Closing Date.  If the Parties are unable to agree by that date, a numerical average of each Party’s good faith estimate shall be used to determine the Remediation Amount for purposes of Section 8.1(f) and Section 8.2(f). The Remediation Amount with respect to any Property subject to an Environmental Defect shall be determined without duplication of any costs or losses (i) included in another Remediation Amount hereunder, (ii) included in any remedy for a Casualty Loss under Section 4.2, or (iii) for which a Party otherwise receives credit in the calculation of the MEPU Adjustment Amount or the PAI Adjustment Amount, as applicable.

Section 7.19    Anticorruption

(a)    Each Party shall (i) promptly notify the other Party of any investigation or proceeding initiated by any Government Authority relating to any alleged conduct not permitted under this Agreement; and (ii) respond in reasonable detail and with the adequate documentary support to any reasonable request from the other Party concerning the obligations, warranties and representations set out in Section 5.31 and Section 6.28, as applicable, provided that the Parties shall not be obliged to disclose any information considered legally privileged.

(b)      Each Party shall (i) maintain adequate internal controls concerning its compliance with all applicable Anticorruption Laws; (ii) establish, prepare and maintain its books



















_____________________________

1 Do we need to carve out any other capital leases?

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and records in accordance with GAAP; (iii) properly record and report its transactions in a manner that accurately and fairly reflects in reasonable detail its assets and liabilities; (iv) retain such books and records for a period of at least five years after expiration of this Agreement in accordance with its terms; and (v) comply with any and all applicable Laws.

ARTICLE  8    CONDITIONS TO CLOSING

Section 8.1    Conditions of MEPU to Closing.   The obligations of MEPU to consummate the transactions contemplated by this Agreement are subject, at the option of MEPU, to the satisfaction on or prior to Closing of each of the following conditions:

(a)    Representations.

(i)    The representations and warranties of PAI set forth in Article 6 (disregarding for this purpose any limitation or qualification by “materiality” or “PAI Material Adverse Effect”), other than the Fundamental Representations, shall be true and correct in all respects, as of the Execution Date and as of the Closing Date as though made on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except to the extent such failures to be true and correct, individually or in the aggregate, have not had  a PAI Material Adverse Effect; and

(ii)    the Fundamental Representations of PAI shall be true and correct in all respects, in each case, as of the Execution Date and as of the Closing Date as though made on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct in all respects on and as of such specified date);

(b)    Performance.   PAI shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by it under this Agreement prior to or on the Closing Date;

(c)    No Action.   No injunction, order (including any temporary restraining order), award, decree or judgment of any Governmental Authority having appropriate jurisdiction restraining, enjoining or otherwise prohibiting the consummation of or awarding substantial damages associated with the transactions contemplated hereby or the sale of any of the Properties related to the PAI Assets has been issued by any Governmental Authority and remains in effect, and no suit, action or other proceeding is pending with respect thereto;

(d)    Closing Deliverables.   PAI shall have delivered (or be ready, willing and able to deliver at Closing) to MEPU the documents and other items required to be delivered by PAI under Section 9.3;

(e)    HSR Act.  Any waiting period applicable to the consummation of the transactions contemplated under the terms of this Agreement under the HSR Act shall have expired or been terminated;

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(f)    Casualty Losses and Remediation Amounts.  The sum of (i) all  Remediation Amounts related to the PAI Assets, and (ii) all Casualty Losses related to the PAI Assets (provided that, if the value of any such Remediation Amount or Casualty Loss is in dispute, then for purposes of this  Section 8.1(f), such value shall be as determined by means of averaging the good faith assertions of such amounts by the Parties), shall be less than $300,000,000;

(g)    St. Malo.   No Third Party shall have exercised any preferential right to purchase (if any such right applies, or is asserted to apply, to the transaction contemplated by this Agreement) under the St. Malo Operating Agreement, and all of PAI’s right, title and interest in St. Malo is included in the PAI Conveyance;  

(h)    MEPU Credit Agreement. MEPU shall have delivered to PAI an amendment or consent under the Credit Agreement, dated as of August 19, 2016, among Murphy Oil Corporation, Murphy Exploration & Production Company-International, Murphy Oil Company Ltd., JPMorgan Chase Bank, N.A., as administrative agent, and the other parties thereto (the “MEPU Credit Agreement”), pursuant to which the relevant terms of the MEPU Credit Agreement shall be amended or otherwise modified in order to permit  the transactions contemplated by this Agreement and the LLC Agreement, including the contribution of assets to JVCo and the distributions to be made by JVCo, and the exclusion of JVCo from the collateral and guarantee requirements of the MEPU Credit Agreement or the MEPU Credit Agreement shall otherwise be terminated or refinanced such that the transactions contemplated by this Agreement and the LLC Agreement, including the contribution of assets to JVCo and the distributions to be made by JVCo are not prohibited; and

(i)    PAI Parent Guarantee. MEPU shall have received from Petróleo Brasileiro S.A. the PAI Parent Guarantee.

Section 8.2    Conditions of PAI to Closing.   The obligations of PAI to consummate the transactions contemplated by this Agreement are subject, at the option of PAI, to the satisfaction on or prior to Closing of each of the following conditions:

(a)    Representations.

(i)    The representations and warranties of MEPU set forth in Article 5 (disregarding for this purpose any limitation or qualification by “materiality” or “MEPU Material Adverse Effect”), other than the Fundamental Representations, shall be true and correct in all respects, as of the Execution Date and as of the Closing Date as though made on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except to the extent such failures to be true and correct, individually or in the aggregate, have not had a MEPU Material Adverse Effect; and

(ii)    the Fundamental Representations of MEPU shall be true and correct in all respects, in each case, as of the Execution Date and as of the Closing Date as though made on and as of the Closing Date (other than representations and warranties that refer to

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a specified date, which need only be true and correct in all respects on and as of such specified date);

(b)    Performance.   MEPU shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by it under this Agreement prior to or on the Closing Date;

(c)    No Action.   No injunction, order (including any temporary restraining order), award, decree or judgment of any Governmental Authority having appropriate jurisdiction restraining, enjoining or otherwise prohibiting the consummation of or awarding substantial damages associated with the transactions contemplated hereby or the sale of any of the Properties related to the MEPU Assets has been issued by any Governmental Authority and remains in effect, and no suit, action or other proceeding is pending with respect thereto;

(d)    Closing Deliverables.   MEPU shall have delivered (or be ready, willing and able to deliver at Closing) to PAI the documents and other items required to be delivered by MEPU under Section 9.2;

(e)    HSR Act.   Any waiting period applicable to the consummation of the transactions contemplated under the terms of this Agreement under the HSR Act shall have expired or been terminated; 

(f)    Casualty Losses and Remediation Amounts.   The sum of (i) all Remediation Amounts related to the MEPU Assets, and (ii) all Casualty Losses related to the MEPU Assets (provided that, if the value of any such Remediation Amount or Casualty Loss is in dispute, then for purposes of this Section 8.2(f), such value shall be as determined by means of averaging the good faith assertions of such amounts by the Parties), shall be less than $300,000,000;  

(g)    St. Malo.  No Third Party shall have exercised any preferential right to purchase (if any such right applies, or is asserted to apply, to the transaction contemplated by this Agreement) under the St. Malo Operating Agreement, and all of PAI’s right, title and interest in St. Malo is included in the PAI Conveyance;

(h)    MEPU Credit Agreement. MEPU shall have delivered to PAI an amendment or consent under the MEPU Credit Agreement, pursuant to which the relevant terms of the MEPU Credit Agreement shall be amended or otherwise modified in order to permit  the transactions contemplated by this Agreement and the LLC Agreement, including the contribution of assets to JVCo and the distributions to be made by JVCo, and the exclusion of JVCo from the collateral and guarantee requirements of the MEPU Credit Agreement or the MEPU Credit Agreement shall otherwise be terminated or refinanced such that the transactions contemplated by this Agreement and the LLC Agreement, including the contribution of assets to JVCo and the distributions to be made by JVCo are not prohibited.

ARTICLE  9    CLOSING

Section 9.1    Time and Place of Closing.   The consummation of the contribution and transfer of the Assets as contemplated by this Agreement (the Closing”), shall, unless otherwise agreed to in writing by the Parties, take place at the offices of MEPU located

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at 9805 Katy Freeway, Suite G-200 Houston, Texas 77024, at 10:00 a.m., local time, on the last Business Day of the calendar month during which all conditions in Article 8 have been satisfied or waived.  The date on which the closing actually occurs is referred to herein as the Closing Date.

Section 9.2    Obligations of MEPU at Closing.   At the Closing, upon the terms and subject to the conditions of this Agreement, and subject to the simultaneous performance by PAI of its obligations pursuant to Section 9.3,  MEPU shall deliver or cause to be delivered to PAI, among other things, the following: 

(a)    duly executed and acknowledged conveyances of the MEPU Assets in substantially the form attached hereto as Exhibit B (the MEPU Conveyance”), in sufficient duplicate originals to allow recording in all appropriate jurisdictions and offices, together with such other forms of assignments of record title ownership or operating rights or assignment of rights of way with respect to the Assets as may be required by BOEM, BSEE or any other applicable Governmental Authority;

(b)    duly executed signature page counterpart to any applicable government forms required by BOEM, BSEE and other Governmental Authorities with jurisdiction over the Wells and Equipment related to the MEPU Assets, including any designation of operator, designation of applicant and oil spill financial responsibility forms;

(c)    duly executed, acknowledged and witnessed signature page counterparts of all other assignments, filings or notices in such form required by federal or state agencies for the assignment of any federal or state MEPU Assets, each in sufficient duplicate originals to facilitate submission and recording in all appropriate jurisdictions;

(d)    duly executed counterparts of the Master Services Agreement;

(e)    duly executed counterparts of the  LLC Agreement;

(f)    duly executed and acknowledged conveyances of the Medusa Spar Units in substantially the form attached hereto as Exhibit D (the “Units Conveyance”);

(g)    copies of any and all Consents and waivers of Preferential Rights received by MEPU prior to the Closing Date;

(h)    evidence that JVCo is at Closing qualified with BOEM to hold oil and gas leases on the Outer Continental Shelf, and has posted (or is exempt from posting) with BOEM bonds (area-wide, supplemental and/or additional) required by BOEM;

(i)    an executed acknowledgment of the PAI Preliminary Settlement Statement;

(j)    on behalf of JVCo, a wire transfer of the Proportionate Adjusted Cash Consideration in same-day funds to PAI;

(k)    a wire transfer of the MEPU Cash Contribution in same-day funds to JVCo;

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(l)    a certificate duly executed by an authorized corporate officer of MEPU dated as of the Closing, certifying on behalf of MEPU that the conditions set forth in Section 8.2(a) and Section 8.2(b) have been fulfilled;

(m)    a certificate duly executed by the secretary or any assistant secretary of MEPU, dated as of the Closing, (i) attaching and certifying on behalf of MEPU complete and correct copies of (A) the certificate of incorporation and the bylaws of MEPU as in effect as of the Closing, (B) the resolutions of the board of directors of MEPU authorizing the execution, delivery, and performance by MEPU of this Agreement and the transactions contemplated hereby, and (C) any required approval by the stockholders of MEPU of this Agreement and the transactions contemplated hereby and (ii) certifying on behalf of MEPU the incumbency of each officer of MEPU executing this Agreement or any document delivered in connection with the Closing;

(n)    MEPU shall deliver to JVCo at the Closing a properly executed affidavit prepared in accordance with Treasury Regulations section 1.1445-2(b) and an IRS Form W-9, each certifying MEPU’s non-foreign status;

(o)    a release of any pledge or Encumbrance on the Medusa Spar Units set forth on Schedule 5.28;  

(p)    a release of any Encumbrance burdening the MEPU Assets;

(q)    a wire transfer of the PAI Cash Contribution in same-day funds to JVCo pursuant to Section 2.2(e); and

(r)    any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and/or delivered at the Closing.

In addition, MEPU shall take all action necessary to cause JVCo to execute and deliver the documents listed in clauses (a) through (f) above and the Transition Services Agreement.

Section 9.3    Obligations of PAI at Closing.   At the Closing, upon the terms and subject to the conditions of this Agreement, and subject to the simultaneous performance by MEPU of its obligations pursuant to Section 9.2,  PAI shall deliver or cause to be delivered to MEPU, among other things, the following:

(a)    duly executed and acknowledged conveyances of the PAI Assets in substantially the form attached hereto as Exhibit C (the “PAI Conveyance and, together with the MEPU Conveyance, the “Conveyances), in sufficient duplicate originals to allow recording in all appropriate jurisdictions and offices, together with such other forms of assignments of record title ownership or operating rights or assignment of rights of way with respect to the Assets as may be required by BOEM, BSEE or any other applicable Governmental Authority;

(b)    duly executed signature page counterpart to any applicable government forms required by BOEM, BSEE and other Governmental Authorities with jurisdiction over the Wells and Equipment related to the PAI Assets, including any designation of operator, designation of applicant and oil spill financial responsibility forms;

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(c)    duly executed, acknowledged and witnessed signature page counterparts of all other assignments, filings or notices in such form required by federal or state agencies for the assignment of any federal or state PAI Assets, each in sufficient duplicate originals to facilitate submission and recording in all appropriate jurisdictions;

(d)    duly executed counterparts of the Transition Services Agreement;

(e)    duly executed counterparts of the LLC Agreement;

(f)    copies of any and all Consents and waivers of Preferential Rights received by PAI prior to the Closing Date;

(g)    an executed acknowledgment of the MEPU Preliminary Settlement Statement;

(h)    a certificate duly executed by an authorized corporate officer of PAI, dated as of the Closing, certifying on behalf of PAI that the conditions set forth in Section 8.1(a)  and Section 8.1(b) have been fulfilled;

(i)    a certificate duly executed by the secretary or any assistant secretary of PAI, dated as of the Closing, (i) attaching and certifying on behalf of PAI complete and correct copies of (A) the certificate of incorporation and the bylaws of PAI, each as in effect as of the Closing, (B) the resolutions of the board of directors of PAI authorizing the execution, delivery, and performance by PAI of this Agreement and the transactions contemplated hereby, and (C) any required approval by the stockholders of PAI of this Agreement and the transactions contemplated hereby and (ii) certifying on behalf of PAI the incumbency of each officer of PAI executing this Agreement or any document delivered in connection with the Closing;

(j)    a non-exclusive license, in form and substance reasonably acceptable to MEPU, to all proprietary Seismic Data (if any) that is owned by PAI or its Affiliates after the Closing and acquired pursuant to this Agreement;

(k)    PAI shall deliver to  JVCo at the Closing a properly executed affidavit prepared in accordance with Treasury Regulations section 1.1445-2(b) and an IRS Form W-9, each certifying PAI’s non-foreign status;

(l)    a release of any Encumbrance burdening the PAI Assets;  and

(m)    any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and/or delivered at the Closing.

Section 9.4    Closing Cash and Post-Closing Adjustments

(a)    Not later than twenty (20)  days prior to the Closing Date: 

(i)    MEPU shall prepare in good faith and deliver to PAI, using and based upon the best information available to MEPU, a preliminary settlement statement (the MEPU Preliminary Settlement Statement) 

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estimating the MEPU Adjustment Amount after giving effect to all adjustments set forth in Section 3.1 and the calculation of the adjustments used to determine such amount, together with all information in MEPU’s or its Affiliates’ possession used to make such calculations.  

(ii)    PAI shall prepare in good faith and deliver to MEPU, using and based upon the best information available to PAI, a preliminary settlement statement (the “PAI Preliminary Settlement Statement” and, together with the MEPU Preliminary Settlement Statement, the “Preliminary Settlement Statements)  estimating the PAI Adjustment Amount  after giving effect to all adjustments set forth in Section 3.2 and the calculation of the adjustments used to determine such amount, together with (i) all information in PAI’s or its Affiliates’ possession used to make such calculations and (ii) the designation of PAI’s account for the wire transfer of the Proportionate Adjusted Cash Consideration

(b)    Within ten (10)  days of receipt of:    

(i)    the MEPU Preliminary Settlement Statement, PAI will deliver to MEPU a written report containing all changes with the explanation therefor that PAI proposes to be made to the MEPU Preliminary Settlement Statement provided by MEPU, if any.  

(ii)    the PAI Preliminary Settlement Statement, MEPU will deliver to PAI a written report containing all changes with the explanation therefor that MEPU proposes to be made to the PAI Preliminary Settlement Statement provided by PAI, if any.    

(c)    The Preliminary Settlement Statements, as agreed upon by the Parties, will be used to adjust the Initial PAI Payment; provided that if the Parties cannot agree on:    

(i)    the MEPU Preliminary Settlement Statement prior to the Closing the MEPU Adjustment Amount, for purposes of the Closing shall be amount equal to the average of (x) the estimate of the MEPU Adjustment Amount as set forth in MEPU’s draft of  the MEPU Preliminary Settlement Statement and (y) the estimate of the MEPU Adjustment Amount as set forth in (or imputed from) PAI’s written report delivered pursuant to Section 9.4(b)(i) (the resulting amount, the MEPU Closing Adjustment Amount”).

(ii)    the PAI Preliminary Settlement Statement prior to the Closing the PAI Adjustment Amount for purposes of the Closing shall be amount equal to the average of (x) the estimate of the PAI Adjustment Amount as set forth in PAI’s draft of the PAI Preliminary Settlement Statement and (y) the estimate of the PAI Adjustment Amount as set forth in (or imputed from) MEPU’s written report delivered pursuant to Section 9.4(b)(ii) (the resulting amount, the “PAI Closing Adjustment Amount”).

(d)    As soon as reasonably practicable after the Closing but not later than the 120th day following the Closing Date: 

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(i)    MEPU shall prepare in good faith and deliver to PAI a  final settlement statement (the MEPU Final Settlement Statement) setting forth the final calculation of the MEPU Adjustment Amount and showing the calculation of each adjustment, based, to the extent possible on actual credits, charges, receipts and other items before and after the Effective Time, together with all information in MEPU’s or its Affiliates’ possession used to make such calculations.  

(ii)    PAI shall prepare in good faith and deliver to MEPU a final settlement statement (the “PAI Final Settlement Statement and, together with the MEPU Final Settlement Statement, the “Final Settlement Statements setting forth the final calculation of the PAI Adjustment Amount and showing the calculation of each adjustment, based, to the extent possible on actual credits, charges, receipts and other items before and after the Effective Time, together with all information in PAI’s or its Affiliates’ possession used to make such calculations. 

(e)    As soon as reasonably practicable but not later than the 90th day following receipt of: 

(i)    the MEPU Final Settlement Statement, PAI shall deliver to MEPU a written report containing any changes that PAI proposes be made to the MEPU Final Settlement Statement, if any.  

(ii)    the PAI Final Settlement Statement, MEPU shall deliver to PAI a written report containing any changes that MEPU proposes be made to the PAI Final Settlement Statement, if any

(f)    The Parties shall undertake to agree on the final statement of the MEPU Adjustment Amount and PAI Adjustment Amount no later than 240 days after the Closing Date.  In the event that the parties cannot reach agreement within such period of time, either Party may refer the remaining matters in dispute to Deloitte & Touche LLP. If  Deloitte & Touche LLP is unable or unwilling to perform its obligations under this Section then each Party will select an internationally recognized independent accounting firm, who will then select a third internationally recognized independent accounting firm, who is independent of the parties, which third firm will then serve as the sole accounting firm hereunder.  The accounting firm shall conduct the arbitration proceedings in Houston, Texas in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section.  The accounting firm’s determination shall be made within thirty (30) days after submission of the matters in dispute and shall be final and binding on both Parties, without right of appeal.  In determining the proper amount of any adjustment to the MEPU Adjustment Amount or the PAI Adjustment Amount, the accounting firm shall not increase or decrease the MEPU Adjustment Amount or the PAI Adjustment Amount, as applicable, more than the increase or decrease proposed by MEPU or PAI, as applicable.  The accounting firm shall act as an expert for the limited purpose of determining the specific disputed matters submitted by either Party and may not award damages or penalties to either Party with respect to any matter.  Each Party shall bear

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its own legal fees and other costs of presenting its case.  Each Party shall bear one-half of the costs and expenses of the accounting firm.  

(g)    Within ten (10) days after the earlier of (i) the expiration of a Party’s thirty (30) day review period without delivery of any written report or (ii) the date on which the Parties or the accounting firm, as applicable, finally determine the MEPU Adjustment Amount or PAI Adjustment Amount,  as applicable, 

(i)    (x) MEPU shall pay to PAI 20% of the amount by which the MEPU Adjustment Amount exceeds the MEPU Closing Adjustment Amount or (y) PAI shall pay to MEPU 80% of the amount by which the MEPU Adjustment Amount exceeds the MEPU Closing Adjustment Amount, as applicable.

(ii)    (x) MEPU shall pay to PAI 20% of the amount by which the PAI Adjustment Amount exceeds the PAI Closing Adjustment Amount or (y) PAI shall pay to MEPU 80% of the amount by which the PAI Adjustment Amount exceeds the PAI Closing Adjustment Amount, as applicable;

provided, that, in the event payments are required under both Section 9.4(g)(i) and Section 9.4(g)(ii),  the Member with a greater obligation shall pay the other Member a net amount equal to the amount owed by the paying Member under this Section 9.4(g) reduced by the amount owed by the other Member under this Section 9.4(g).

ARTICLE 10    TERMINATION

Section 10.1    Termination.   At any time prior to the Closing, this Agreement may be terminated as follows:

(a)    by the mutual consent of the Parties as evidenced in writing signed by each Party;

(b)    by PAI, upon written notice to MEPU, if any of the conditions to Closing set forth in Section 8.2(c), Section 8.2(e) or Section 8.2(g) have not been satisfied as of July 1, 2019 (the Longstop Date”); 

(c)    by MEPU, upon written notice to PAI, if any of the conditions to Closing set forth in Section 8.1(c) or Section 8.1(e) have not been satisfied as of the Longstop Date;

(d)    by PAI, upon written notice to MEPU, if there has been a material breach by MEPU of any representation, warranty, covenant or other agreement set forth herein, in each case, that has prevented or, in PAI’s good faith estimation, will prevent the satisfaction of any of the conditions to Closing set forth in Section 8.2(a),  Section 8.2(b) or Section 8.2(d) and, if such breach is of a character that it is capable of being cured, such breach has not been cured by MEPU on the earlier of (A) the date that is twenty (20) days after receipt of notice thereof from PAI or (B) the Longstop Date;

(e)    by MEPU, upon written notice to PAI, if there has been a material breach by of any representation, warranty, covenant or other agreement set forth herein, in each case, that

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has prevented or, in MEPU’s good faith estimation, will prevent the satisfaction of any of the conditions to Closing set forth in Section 8.1(a),  Section 8.1(b) or Section 8.1(d) and, if such breach is of a character that it is capable of being cured, such breach has not been cured by PAI on the earlier of (i) the date that is twenty (20) days after receipt of notice thereof from MEPU or (ii) the Longstop Date; or

(f)    by PAI, upon written notice to MEPU, if the condition to Closing set forth in Section 8.2(f) has not been satisfied as of the Longstop Date; 

(g)    by MEPU, upon written notice to PAI, if any of the conditions to Closing set forth in Section 8.1(f),  Section 8.1(g) or Section 8.1(h) has not been satisfied as of the Longstop Date;

provided, however, that no Party shall have a right to terminate this Agreement pursuant to this Section 10.1 (other than pursuant to Section 10.1(a) or Section 10.1(f) for PAI or Section 10.1(g) for MEPU) if such Party is in material breach of any representation, warranty or covenant contained in this Agreement.

Section 10.2    Effect of Termination

(a)    If the obligation to close the transactions contemplated by this Agreement is terminated pursuant to any provision of Section 10.1 hereof, then, except for the provisions of Section 5.1, Section 6.1, Section 7.2(a), this Section 10.2,  Section 11.6,  Article 12 (other than Section 12.5,  Section 12.7, and Section 12.8) and such of the defined terms set forth herein necessary to give context to the surviving provisions, each of which shall survive the termination of this Agreement, this Agreement shall forthwith become void and the Parties shall have no Liability or obligation hereunder.

(b)    Subject to the foregoing Section 10.2(a), upon the termination of this Agreement neither Party shall have any other Liability or obligation hereunder or otherwise to the other Party with respect to this Agreement or the transactions contemplated by this Agreement; provided that no Party shall be relieved or released from any Liabilities arising out of any Willful Breach by such Party that gave rise to the failure of a condition set forth in Section 8.1 or Section 8.2.

ARTICLE 11    INDEMNIFICATIONS; LIMITATIONS

Section 11.1    Assumption of Obligations; Retained Liabilities

(a)    Subject to JVCo’s rights to indemnity under this Article 11 and Transferors’ obligations with respect to Operating Expenses incurred prior to the Effective Time pursuant to Section 2.3, from and after the Closing Date,  the Parties shall cause JVCo to assume,  fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and Liabilities of each Transferor and its Affiliates, known or unknown, with respect to the Assets, other than the Retained Liabilities, including all (i) obligations to Decommission any Properties and (ii) all Third Party Claims relating to preferential purchase rights (all of said obligations and Liabilities, less and except the

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Retained Liabilities, are referred to herein as the Assumed Obligations”).

(b)    Each Transferor shall retain and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and Liabilities of such Transferor with regard to its Assets, known or unknown, with respect to all Liabilities to the extent arising from or attributable to the following, regardless of whether such obligations or Liabilities arose prior to, on or after the Effective Time, except as otherwise specified: (i) the ownership, operation and use of the Excluded Assets of such Transferor, subject to Section 4.1(f); (ii) all matters set forth on Schedule 5.4,  Schedule 5.7 or Schedule 5.9,  or Schedule 6.4,  Schedule 6.7 or Schedule 6.9, as applicable, (iii) all Transferor Taxes of such Transferor, (iv) Liabilities arising in connection with property damage (including debris and wreck removal to the extent required by applicable Law), personal injury, illness or death, to the extent arising from or attributable to, the use, ownership or operation of the Assets of such Transferor prior to the Closing Date, (v) Hazardous Substances related or attributable to the Assets of such Transferor that, prior to the Closing Date, were disposed of off-site, (vi) to the extent not covered by any other Retained Liability or any Assumed Obligation, all of the obligations and Liabilities of such Transferor, known or unknown, with respect to the Assets of such Transferor, to the extent, and only to the extent, that such Liabilities arose prior to the Effective Time or are related to any breach, event, occurrence, matter or circumstance that occurred prior to the Effective Time, (vii) the payment of proceeds or other amounts owed to Working Interest, royalty, overriding royalty and other interest owners relating to the Properties of such Transferor (including any operational or regulatory reporting), and attributable to the period of time prior to the Effective Time, including any mispayments or allegations of mispayments of such proceeds or amounts attributable to the period of time prior to the Effective Time, (viii) disputes related to the proper billing or payment of joint interest billing accounts related to ownership or operation of the Assets of such Transferor prior to the Effective Time, and (ix) fines, penalties and other similar obligations levied by any Governmental Authority with respect to the condition, ownership, use or operation of the Assets of such Transferor prior to the Closing Date (all of said obligations and Liabilities are referred to herein as the Retained Liabilities”).

Section 11.2    Indemnification

(a)    From and after Closing, PAI shall indemnify, defend, and hold harmless MEPU and its Affiliates, and all of its and their respective Representatives, successors and assigns (collectively, MEPU Indemnified Parties”) and JVCo from and against all Liabilities sustained or incurred by any person or entity, or incurred in the investigation or defense of any of the same or in asserting, presenting or enforcing any of their respective rights hereunder arising from, based upon, related to or associated with:

(i)    PAI’s breach of any of its covenants or agreements contained this Agreement; 

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(ii)    any breach of any representation or warranty made by PAI pursuant to Article 6 or in the certificate delivered by PAI at Closing pursuant to Section 9.3(h); 

(iii)    the Retained Liabilities of PAI; and

(iv)    the Vantage Matter,

REGARDLESS OF FAULT.

(b)    From and after Closing, MEPU shall indemnify, defend, and hold harmless PAI and its Affiliates, and all of its and their respective Representatives, successors and assigns (collectively, PAI Indemnified Parties”) and JVCo from and against all Liabilities sustained or incurred by any person or entity or incurred in the investigation or defense of any of the same or in asserting, presenting or enforcing any of their respective rights hereunder arising from, based upon, related to or associated with:

(i)    MEPU’s breach of any of its covenants or agreements contained this Agreement,

(ii)    any breach of any representation or warranty made by MEPU pursuant to Article 5 or in the certificate delivered by MEPU at Closing pursuant to Section 9.2(l), and

(iii)    the Retained Liabilities of MEPU,

REGARDLESS OF FAULT.

(c)    From and after Closing, Transferors shall cause JVCo to indemnify, defend, and hold harmless each of the MEPU Indemnified Parties and the PAI Indemnified Parties from and against all Liabilities sustained or incurred by any person or entity or incurred in the investigation or defense of any of the same or in asserting, presenting or enforcing any of their respective rights hereunder arising from, based upon, related to or associated with the Assumed Obligations and the ownership of the Medusa Spar Units,

REGARDLESS OF FAULT.

(d)    No Indemnified Party other than MEPU and PAI shall have any rights against MEPU, PAI or JVCo under the terms of this Section 11.2 except as may be exercised on its behalf by PAI or MEPU.

Section 11.3    Indemnification Actions.   All claims for indemnification pursuant to this Agreement shall be asserted and resolved as follows:

(a)    The term Indemnifying Party when used in connection with particular Liabilities shall mean the JV Party having an obligation to Indemnify another JV Party or Person(s) with respect to such Liabilities pursuant to this

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Agreement, and the term Indemnified Party when used in connection with particular Liabilities shall mean the JV Party or Person(s) having the right to be indemnified with respect to such Liabilities by another JV Party pursuant to this Agreement.

(b)    The term REGARDLESS OF FAULT MEANS WITHOUT REGARD TO THE CAUSE OR CAUSES OF ANY CLAIM, INCLUDING, EVEN THOUGH A CLAIM IS CAUSED IN WHOLE OR IN PART BY:

(i)    THE NEGLIGENCE (WHETHER SOLE, JOINT, CONCURRENT, COMPARATIVE, CONTRIBUTORY, ACTIVE, PASSIVE, GROSS OR OTHERWISE), WILLFUL MISCONDUCT, STRICT LIABILITY OR OTHER FAULT OF ANY MEMBER OF THE PAI INDEMNIFIED PARTIES AND/OR THE MEPU INDEMNIFIED PARTIES, JVCO, INVITEES AND/OR THIRD PARTIES; AND/OR

(ii)    A PRE-EXISTING DEFECT, WHETHER PATENT OR LATENT, OF THE ASSETS AND/OR EQUIPMENT.

(c)    To make a claim for indemnification pursuant to this Agreement, an Indemnified Party shall notify the Indemnifying Party of its claim under this Section 11.3, including the specific details of and specific basis under this Agreement for its claim (the Claim Notice”).  In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnified Party (a Third Party Claim”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has actual knowledge of the Third Party Claim and shall enclose a copy of all papers (if any) served with respect to the Third Party Claim; provided that the failure of any Indemnified Party to give notice of a Third Party Claim as provided in this Section 11.3 shall not relieve the Indemnifying Party of its obligations under this Agreement except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Third Party Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the Third Party Claim.  In the event that the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant or agreement, the Claim Notice shall specify the representation, warranty, covenant or agreement that was inaccurate or breached.

(d)    In the case of a claim for indemnification based upon a Third Party Claim, the Indemnifying Party shall have 30 days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its liability to defend the Indemnified Party against such Third Party Claim at the sole cost and expense of the Indemnifying Party.  The Indemnified Party is authorized, prior to and during such 30 day period (or such shorter period until notification from the Indemnifying Party is received), at the expense of the Indemnifying Party, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party.

(e)    If the Indemnifying Party admits its liability to defend the Indemnified Party against a Third Party Claim, it shall have the right and obligation to diligently defend, at its sole cost and expense, such Third Party Claim.  The Indemnifying Party shall have full control of such

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defense and proceedings, including any compromise or settlement thereof.  If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate in good faith in contesting any Third Party Claim which the Indemnifying Party elects to contest (provided that in no event shall an Indemnified Party be obligated to bring any cross-complaint or counterclaim against any Person).  The Indemnified Party may participate in, but not control, at its own expense, any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section 11.3(e).   An Indemnifying Party shall not, without the written consent (which consent may not be unreasonably withheld) of the Indemnified Party, (i) settle any Third Party Claim or consent to the entry of any judgment with respect thereto which does not include an unconditional written release of the Indemnified Party from all Liability in respect of such Third Party Claim or (ii) settle any Third Party Claim or consent to the entry of any judgment with respect thereto in any manner that may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).

(f)    If the Indemnifying Party does not admit its liability or admits its liability to defend the Indemnified Party against the Third Party Claim, but fails to diligently prosecute or settle such Third Party Claim, then the Indemnified Party shall have the right to defend against the Third Party Claim at the sole cost and expense of the Indemnifying Party (to the extent the Indemnified Party is entitled to indemnification hereunder), with counsel of the Indemnified Party’s choosing, subject to the right of the Indemnifying Party to admit its liability and assume the defense of the Third Party Claim at any time prior to settlement or final determination thereof.  If the Indemnifying Party has not yet admitted its liability to defend the Indemnified Party against the Third Party Claim, the Indemnified Party shall send written notice to the Indemnifying Party of any proposed settlement and the Indemnifying Party shall have the option for ten (10) days following receipt of such notice to (i) admit in writing its liability to indemnify the Indemnified Party from and against the Liability and consent to such settlement, (ii) if liability is so admitted, reject, in its reasonable judgment, the proposed settlement, or (iii) deny liability.  If the Indemnified Party settles any Third Party Claim over the objection of the Indemnifying Party after the Indemnifying Party has timely admitted its obligation in writing and has actually assumed the defense of a Third Party Claim, the Indemnified Party shall be deemed to have waived any right to indemnity for such claim.  Any failure by the Indemnifying Party to respond to such notice shall be deemed to be an election under subsection (i) above.  Notwithstanding the other provisions of this Section 11.3, if the Indemnifying Party disputes its potential liability to the Indemnified Party under this Section 11.3 and if such dispute is resolved in favor of the Indemnifying Party, the Indemnifying Party shall not be required to bear any costs and expenses of the Third Party Claim or the Indemnified Party’s defense pursuant to this Section 11.3 and, to the extent incurred by the Indemnifying Party, such costs and expenses shall be promptly reimbursed by the Indemnified Party.

(g)    In the case of a claim for indemnification not based upon a Third Party Claim, the Indemnifying Party shall have 30 days from its receipt of the Claim Notice to (i) cure the Liabilities complained of, (ii) admit its liability for such Liability or (iii) dispute the claim for such Liabilities.  If the Indemnifying Party does not notify the Indemnified Party within such 30 day period that it has cured the Liabilities or that it disputes the claim for such Liabilities, the amount of such Liabilities shall conclusively be deemed a Liability of the Indemnifying Party hereunder.

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Section 11.4    Limitation on Actions

(a)    The representations and warranties (other than the Fundamental Representations) of Transferors  in Article 5 and Article 6 and the corresponding representations and warranties (other than the Fundamental Representations) given in the certificates delivered at the Closing pursuant to Section 9.2(l) and Section 9.3(h), as applicable, shall survive the Closing for a period of eighteen (18) months, provided,  however, that notwithstanding anything to the contrary herein, (i) the Fundamental Representations (other than the representations and warranties set forth in Section 5.5,  Section 5.19, Section 6.5, and Section 6.19) shall each survive the Closing without time limitation, (ii) the representations and warranties set forth in Section 5.5 and Section 6.5 shall survive the Closing until thirty (30) days following the expiration of the relevant statute of limitations, and (iii) the representations and warranties set forth in Section 5.15  (except to the extent related to any Wells that are not set forth on Exhibit A-2), Section 5.16Section 6.15 (except to the extent related to any Wells that are not set forth on  Exhibit A-2) and Section 6.16 shall survive the Closing for a period of thirty (30) months.  The covenants of Transferors  that are required to be performed prior to the Closing shall survive the Closing for a period of eighteen (18) months, and all other covenants of Transferors  shall survive the Closing until the expiration of the applicable statute of limitations.  The remainder of this Agreement shall survive the Closing without time limit except as may otherwise be expressly provided herein.  Representations, warranties, covenants, and agreements shall be of no further force and effect after the date of their expiration, provided that there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation, warranty, covenant, or agreement prior to its expiration date.

(b)    The indemnities in Section 11.2(a)(i),  Section 11.2(a)(ii),  Section 11.2(b)(i) and Section 11.2(b)(ii), shall terminate as of the termination date of each respective representation, warranty, covenant, or agreement that is subject to indemnification, except in each case as to matters for which a specific written claim for indemnity has been delivered to the Indemnifying Party on or before such termination date.  The indemnities in Section 11.2(a)(iii),  Section 11.2(a)(iv),  Section 11.2(b)(iii) and Section 11.2(c) shall continue without time limit, except that (A) the indemnity in Section 11.2(a)(iii) and Section 11.2(b)(iii) with respect to subsections (vi), (vii) and (viii) in the definition of Retained Liabilities in Section 11.1(b) (but only with respect to such subsections) shall survive the Closing for a period of twenty-four (24) months, following which period the Liabilities described in such subsections shall cease to be Retained Liabilities and shall become Assumed Obligations, (B) the indemnity in Section 11.2(a)(iii) and Section 11.2(b)(iii) with respect to subsection (ix) in the definition of Retained Liabilities in Section 11.1(b) (but only with respect to such subsection) shall survive the Closing for a period of thirty  (30) months, following which period the Liabilities described in such subsections shall cease to be Retained Liabilities and shall become Assumed Obligations and (C) the indemnity in Section 11.2(a)(iii) and Section 11.2(b)(iii) with respect to subsection (iii) of the definition of Retained Liabilities in Section 11.1(b) shall survive the Closing until the expiration of the relevant statute of limitations.

(c)    MEPU shall not have any liability for any indemnification under Section 11.2(b)(ii) for any Liability with a value of $350,000 or less, net to MEPU’s interest (and these types of Liabilities will not be counted in determining whether the $20,000,000 amount described below has been met), and MEPU shall have no Liability for any indemnification under Section

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11.2(b)(ii) until and unless the aggregate amount of the liability for all such Liabilities under Section 11.2(b)(ii) for which Claim Notices are delivered by PAI on behalf of any PAI Indemnified Party or JVCo (and for which MEPU is responsible) exceeds $20,000,000, and then only to the extent such the aggregate Liabilities which are above such $350,000 threshold exceed $20,000,000, provided, however, that the indemnities under Section 11.2(b)(ii) for a breach of any Fundamental Representation shall not be limited by the provisions of this Section 11.4(c). 

(d)    PAI shall not have any liability for any indemnification under Section 11.2(a)(ii) for any Liability with a value of $350,000 or less, net to PAI’s interest (and these types of Liabilities will not be counted in determining whether the $20,000,000 amount described below has been met), and PAI shall have no Liability for any indemnification under Section 11.2(a)(ii) until and unless the aggregate amount of the liability for all such Liabilities under Section 11.2(a)(ii) for which Claim Notices are delivered by MEPU on behalf of any MEPU Indemnified Party or JVCo (and for which PAI is responsible) exceeds $20,000,000, and then only to the extent such the aggregate Liabilities which are above such $350,000 threshold exceed $20,000,000, provided, however, that the indemnities under Section 11.2(a)(ii) for a breach of any Fundamental Representation shall not be limited by the provisions of this Section 11.4(d). For the avoidance of doubt, the limitations in this Section 11.4(d) shall not apply to indemnity under Section 11.2(a)(iv)

(e)    Notwithstanding anything to the contrary contained elsewhere in this Agreement, no Transferor shall be required to indemnify the other Transferor or JVCo under Section 11.2(a)(i) and Section 11.2(a)(ii), or Section 11.2(b)(i) and Section 11.2(b)(ii), as applicable, for aggregate Liabilities in excess of $1,000,000,000, provided, however, that the indemnities under Section 11.2(a)(ii) and Section 11.2(b)(ii) for a breach of any Fundamental Representation shall not be limited by the provisions of this Section 11.4(e). For the avoidance of doubt, the limitations in this Section 11.4(e) shall not apply to indemnity under Section 11.2(a)(iv).

(f)    PAI’s liability for any indemnification under Section 11.2(a)(iv) shall be limited to $622,000,000 plus the amount of any reasonable attorneys’ fees, costs of investigation, defense, litigation, arbitration or other expenses incurred by the MEPU Indemnified Parties or JVCo.  

(g)    The amount of any Liabilities for which an Indemnified Party is entitled to indemnity under this Article 11 shall be reduced by the amount of insurance proceeds realized by the Indemnified Party or its Affiliates with respect to such Liabilities (net of any collection costs, and excluding the proceeds of any insurance policy issued, reinsured or underwritten by the Indemnified Party or its Affiliates).

(h)    Fundamental Representations shall mean the representations and warranties set forth in (i) Section 5.2(a),  Section 5.2(b),  Section 5.2(c),  Section 5.3,  Section 5.5, Section 5.6,  Section 5.7, Section 5.15 (to the extent, and only to the extent, related to any Wells that are not set forth on Exhibit A-2), Section 5.18,  Section 5.19 and Section 5.26 and (ii) Section 6.2(a), Section 6.2(b),  Section 6.2(c),  Section 6.3,  Section 6.5,  Section 6.6,  Section 6.7,  Section 6.15 (to the extent, and only to the extent, related to any Wells that are not set forth on Exhibit A-2), Section 6.18,  Section 6.19 and Section 6.26.

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(i)    In no event shall any Indemnified Party be entitled to duplicate compensation with respect to the same Liability, loss, cost, expense, claim, award or judgment under more than one provision of this Agreement and the various documents delivered in connection with the Closing, or for which an Indemnified Party received the benefits of an adjustment to the MEPU Adjustment Amount or the PAI Adjustment Amount pursuant to Section 3.1 or Section 3.2, as applicable. Any Indemnified Party shall have a duty to mitigate the amount of any Liabilities for which such Indemnified Party is entitled to indemnity under this Article 11 by taking appropriate, commercially reasonable actions to reduce or limit the amount of such Liabilities.

(j)    For purposes of this Article 11, any claim of, and Liability resulting from, any breach or inaccuracy in the representations and warranties under this Agreement and the corresponding representations and warranties given in the certificates to be delivered by Transferors  at Closing pursuant to Section 9.2(l) and Section 9.3(h) shall be determined without regard to any materiality qualifiers in or affecting such representations or warranties.

Section 11.5    Non-Compensatory Damages.   NONE OF THE PAI INDEMNIFIED PARTIES, MEPU    INDEMNIFIED PARTIES OR JVCO SHALL BE ENTITLED TO RECOVER FROM THE OTHER PARTY OR SUCH OTHER PARTY’S AFFILIATES ANY INDIRECT, CONSEQUENTIAL, SPECIAL, PUNITIVE, INCIDENTAL, SPECULATIVE OR EXEMPLARY DAMAGES OR DAMAGES FOR LOST PROFITS (WHETHER DIRECT OR INDIRECT) OR LOSS OF BUSINESS OPPORTUNITY OF ANY KIND ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY, EXCEPT TO THE EXTENT ANY SUCH PARTY SUFFERS SUCH DAMAGES (INCLUDING COSTS OF DEFENSE AND REASONABLE ATTORNEYS’ FEES INCURRED IN CONNECTION WITH THE DEFENSE OF SUCH DAMAGES) TO A THIRD PARTY, WHICH DAMAGES (INCLUDING COSTS OF DEFENSE AND REASONABLE ATTORNEYS’ FEES INCURRED IN CONNECTION WITH THE DEFENSE OF SUCH DAMAGES) SHALL NOT BE EXCLUDED BY THIS PROVISION AS TO RECOVERY HEREUNDER.  SUBJECT TO THE PRECEDING SENTENCE, EACH OF MEPU, ON BEHALF OF ITSELF, THE MEPU INDEMNIFIED PARTIES AND JVCO, AND PAI, ON BEHALF OF ITSELF, THE PAI INDEMNIFIED PARTIES AND JVCO, WAIVES ANY RIGHT TO RECOVER INDIRECT, PUNITIVE, SPECIAL, INCIDENTAL, SPECULATIVE, EXEMPLARY AND CONSEQUENTIAL DAMAGES, INCLUDING DAMAGES FOR LOST PROFITS (WHETHER DIRECT OR INDIRECT) OR LOSS OF BUSINESS OPPORTUNITY, ARISING IN CONNECTION WITH OR WITH RESPECT TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

Section 11.6    Exclusive Remedy and Release.   Except for fraud, the indemnification remedies set forth in this Article 11 and the express rights of Transferors pursuant to Section 4.1,  Section 4.2  and Section 10.2 (to the extent any such rights expressly survive the Closing pursuant to their terms),  shall, from and after the Closing, constitute the sole and exclusive remedies of Transferors  (including in their capacity as Members of JVCo) with respect to any and all Liabilities relating to the subject matter of this Agreement, including statutory or other claims arising under any Law.  In furtherance of the foregoing, except for (a) claims made pursuant to the express indemnification provisions of this Article 11, (b) the express rights of Transferors pursuant to Section 4.1,  Section 4.2 and Section 10.2 (to the extent any such rights expressly survive the

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Closing pursuant to their terms) and (c) fraud, each Transferor hereby waives and releases, from and after the Closing to the fullest extent permitted by Law, any and all rights, Liabilities, and causes of action, with respect to the subject matter of this Agreement, it may have against the other  Transferor,  its respective Affiliates and their respective Representatives arising under or based upon any Law.  Except for (a) claims made pursuant to the express indemnification provisions of this Article 11, (b) the express rights of Transferors  pursuant to Section 4.1, Section 4.2 and Section 10.2 (to the extent any such rights expressly survive the Closing pursuant to their terms) and (c) fraud,  PAI, on behalf of the PAI Indemnified Parties and JVCo, and MEPU, on behalf of the MEPU Indemnified Parties and JVCo, shall be deemed to have waived, to the fullest extent permitted under applicable Law, any right of contribution against such Transferor or any of its Affiliates and any and all rights, Liabilities and causes of action it may have against such Transferor or any of its Affiliates, arising under or based on any federal, state or local Law, common Law or otherwise.  Notwithstanding the foregoing, nothing in this Section 11.6 shall prevent any Transferor from seeking injunctive or equitable relief in pursuit of its indemnification claims under this Article 11.

Section 11.7    Opportunity for Review.   Each Transferor represents that it has had an adequate opportunity to review all waiver, release, indemnity and defense provisions in this Agreement, including the opportunity to submit the same to legal counsel for review and advice.  Based upon the foregoing representation, the Parties agree to the provisions set forth above in this Article 11.

ARTICLE 12    MISCELLANEOUS

Section 12.1    Exhibits and Schedules.  All of the Exhibits and Schedules referred to in this Agreement constitute a part of this Agreement.  Each Party to this Agreement and its counsel has received a complete set of Exhibits and Schedules prior to and as of the execution of this Agreement.

Section 12.2    Expenses.   Except as provided in Section 12.5, all expenses incurred by a  Transferor in connection with or related to the authorization, preparation or execution of this Agreement, and the Exhibits and Schedules hereto and thereto, and all other matters related to the Closing, including all fees and expenses of counsel, accountants and financial advisers employed by such Transferor, shall be borne solely and entirely by such Transferor.

Section 12.3    Counterparts.   This Agreement may be executed in counterparts, each of which shall be deemed an original instrument, but all such counterparts together shall constitute but one agreement.  Any signature hereto delivered by a Party by facsimile transmission or other electronic transmission shall be deemed an original signature hereto.

Section 12.4    Notices.   All notices and communications required or permitted to be given hereunder shall be in writing and shall be delivered personally, sent by bonded overnight courier, mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid or sent by email (provided that delivery of such email is confirmed by written confirmation), addressed to the appropriate Party at the address for such Party shown below:

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If to MEPU:    Murphy Exploration & Production Company - USA
9805 Katy Freeway
Suite G200

    Houston, Texas 77024
Attention: Dan Hanchera
Email: dan_hanchera@murphyoilcorp.com

With a copies to:    Gibson, Dunn & Crutcher LLP
811 Main Street
Houston,  Texas 77002
Attention: Michael P. Darden

Gerald Spedale
Telephone: 346-718-6600
Email: MPDarden@gibsondunn.com

GSpedale@gibsondunn.com

If to PAI:    Petrobras America Inc.
10350 Richmond Ave.

Suite 1400
Houston, Texas  77042
Attention: Don Porteous 
Email: dporteous@petrobras.com 

With a copy to:    Linklaters LLP
1345 Avenue of the Americas
New York, NY 10105
Attention: Peter Cohen-Millstein
Telephone: 212-903-9000
Email: peter.cohen-millstein@linklaters.com



Any notice or communication given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier, during normal business hours, or upon actual receipt by the addressee after such notice has either been delivered to an overnight courier or deposited in the United States Mail or sent electronically via email (provided that delivery of such email is confirmed by written confirmation), as the case may be.  The Parties may change the addresses to which such notices or communications are to be addressed by giving written notice to the other Party in the manner provided in this Section 12.4.

Section 12.5    Sales or Use Tax, Recording Fees and Similar Taxes and Fees.  Each Transferor shall pay 100% of, and will reimburse JVCo for, any sales, use, excise, real property transfer or gain, gross receipts, goods and services, registration, capital, documentary, stamp or transfer Taxes, recording fees and similar Taxes and fees incurred and imposed upon, or with respect to, the property transfers or other transactions contemplated hereby (Transfer Taxes”) with respect to such Transferor’s Assets, other than any Transfer Taxes incurred and imposed upon, or with respect to a Transferor’s  transfer to JVCo of pipe (“Pipe

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Transfer Taxes”). The first $1,000,000 of any Pipe Transfer Taxes incurred by a Transferor shall be borne equally by each of the Transferors, and thereafter any additional Pipe Transfer Taxes shall be borne by the Transferor incurring such taxes; provided, that, for the avoidance of doubt, this clause only applies to Pipe Transfer Taxes. In the event that one Transferor is required to pay a portion of such Pipe Transfer Tax that it is not required to bear, the other Transferor will reimburse the paying Transferor for the portion of such Pipe Transfer Taxes that such nonpaying Transferor is required to bear. In the event that JVCo is required to pay any Pipe Transfer Taxes, each Transferor shall reimburse JVCo for the portion of such Pipe Transfer Taxes that such Transferor is required to bear.  If such transfers or transactions are exempt from any such Taxes or fees upon the filing of an appropriate certificate or other evidence of exemption, such Transferor will timely furnish to the other Transferor such certificate or evidence.  The Parties will reasonably cooperate as may be necessary to establish the applicability of any available Transfer Tax exemption (including, for the avoidance of doubt, any applicable isolated or occasional sale exemption).

Section 12.6    Severability.   If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of Law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner to any Party.  Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

Section 12.7    Replacement of Bonds, Letters of Credit and Guarantees.   The Parties understand that none of the bonds, letters of credit and guarantees, if any, posted by a  Transferor or any of its Affiliates with any Governmental Authority or Third Party and relating to the Assets are to be transferred to JVCo.  On or before Closing, Transferors  shall cause to be obtained in the name of JVCo, replacements for such bonds, letters of credit and guarantees, to the extent such replacements are necessary to permit the cancellation of the bonds, letters of credit and guarantees posted by Transferors  and such Affiliates or to consummate the transactions contemplated by this Agreement.

Section 12.8    Records Within thirty days of Closing, each Transferor, at its sole cost and expense, shall deliver or cause to be delivered to JVCo the Records.  Transferors  may retain copies of any or all of the Records, subject to their obligations under Section 7.2(b).  Transferors agree to furnish or cause to be furnished to each other, upon request, as promptly as practicable, such information and assistance relating to the Assets, including access to books and records, as is reasonably necessary for the filing of all Tax Returns by Transferors, the making of any election relating to Taxes, the preparation for any audit by any Governmental Authority with respect to Taxes and the prosecution or defense of any claim, suit or proceeding relating to any Tax.  Transferors shall, and shall cause JVCo to,  retain all Records with respect to Taxes for a period of at least seven (7) years following the Closing Date (or such longer period as the statute of limitations for assessment of such Taxes remains open).  Transferors  shall retain all books and records with respect to Taxes pertaining to the Assets not included in the Records for a period of at least seven (7) years following the Closing Date (or such longer period as the statute of limitations for assessment of such Taxes remains open).  Transferors shall cooperate fully with

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each other in the conduct of any audit, litigation or other proceeding relating to Taxes involving the Assets, Allocable Amount, or Allocation Schedule. 

Section 12.9    Governing Law; Jurisdiction; Venue; Jury Waiver

(a)    THIS AGREEMENT,  THE LEGAL RELATIONS AMONG THE PARTIES AND ALL DISPUTES OR CONTROVERSIES ARISING OUT OF, RELATING TO OR IN CONNECTION WITH THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY SHALL BE GOVERNED EXCLUSIVELY BY AND CONSTRUED IN ACCORDANCE WITH THE INTERNAL LAWS OF THE STATE OF TEXAS,  EXCLUDING ANY CONFLICTS OF LAW RULE OR PRINCIPLE THAT MIGHT REFER CONSTRUCTION OF SUCH PROVISIONS TO THE LAWS OF ANOTHER JURISDICTION.  SUBJECT TO THE REQUIREMENT THAT, UNLESS OTHERWISE PROVIDED HEREIN ALL DISPUTES UNDER THIS AGREEMENT, BE RESOLVED PURSUANT TO THE PROVISIONS SET FORTH IN Section 12.10,  IN ANY ACTION TO ENFORCE ANY RIGHTS HEREUNDER, EACH OF THE PARTIES HERETO CONSENTS TO THE EXERCISE OF JURISDICTION IN PERSONAM BY THE UNITED STATES FEDERAL DISTRICT COURTS LOCATED IN HOUSTON, TEXAS (OR, ONLY IF THE FEDERAL DISTRICT COURTS DECLINE TO ACCEPT JURISDICTION OVER A PARTICULAR MATTER, THE STATE COURTS IN HOUSTON, TEXAS) AND ANY APPELLATE COURT THEREOF FOR ANY SUCH ACTION.  ALL SUCH ACTIONS SHALL BE BROUGHT IN THE UNITED STATES FEDERAL DISTRICT COURTS HAVING SITES IN HOUSTON, TEXAS (OR, ONLY IF THE FEDERAL DISTRICT COURTS DECLINE TO ACCEPT JURISDICTION OVER A PARTICULAR MATTER, THE STATE COURTS IN HOUSTON, TEXAS) AND ANY APPELLATE COURT THEREOF.  EACH PARTY HEREBY IRREVOCABLY CONSENTS TO THE SERVICE OF ANY PAPERS, NOTICES OR PROCESS AT THE ADDRESS SET OUT IN Section 12.4 IN CONNECTION WITH ANY SUCH ACTION AND AGREES THAT NOTHING HEREIN WILL AFFECT THE RIGHT OF THE OTHER PARTY TO SERVE ANY SUCH PAPERS, NOTICES OR PROCESS IN ANY OTHER MANNER PERMITTED BY APPLICABLE LAW.  EACH PARTY HERETO WAIVES ANY OBJECTION TO LAYING VENUE IN ANY SUCH ACTION IN SUCH COURTS AND WAIVES ANY OBJECTION THAT SUCH COURTS ARE AN INCONVENIENT FORUM OR DO NOT HAVE JURISDICTION OVER SUCH PARTY.  EACH PARTY HERETO WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY SUCH ACTION.

(b)    EACH OF THE PARTIES, FOR ITSELF OR ANY OF ITS ASSETS, HEREBY WAIVES ANY IMMUNITY TO THE FULLEST EXTENT PERMITTED BY THE LAWS OF ANY APPLICABLE JURISDICTION.  THIS WAIVER INCLUDES IMMUNITY FROM:  (I) JURISDICTION; (II) SERVICE OF PROCESS; (III) ANY LITIGATION, EXPERT DETERMINATION, MEDIATION, OR ARBITRATION PROCEEDING COMMENCED UNDER THIS AGREEMENT; (IV) ANY JUDICIAL, ADMINISTRATIVE OR OTHER PROCEEDINGS THAT ARE PART OF, OR IN AID OF, THE LITIGATION, EXPERT DETERMINATION, MEDIATION, OR ARBITRATION COMMENCED UNDER THIS AGREEMENT; AND (V) ANY EFFORT TO CONFIRM, ENFORCE, OR EXECUTE ANY DECISION, SETTLEMENT, AWARD, JUDGMENT, SERVICE OF PROCESS, EXECUTION ORDER OR ATTACHMENT (INCLUDING PRE-JUDGMENT ATTACHMENT) THAT

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RESULTS FROM LITIGATION, EXPERT DETERMINATION, MEDIATION, ARBITRATION OR ANY JUDICIAL OR ADMINISTRATIVE PROCEEDINGS COMMENCED UNDER THIS AGREEMENT.  FOR THE PURPOSES OF THIS WAIVER, EACH PARTY ACKNOWLEDGES THAT ITS RIGHTS AND OBLIGATIONS UNDER THIS AGREEMENT ARE OF A COMMERCIAL AND NOT A GOVERNMENTAL NATURE.

Section 12.10    Dispute Resolution

(a)     Any dispute, controversy, cause of action or claim arising out of or in relation to or in connection with this Agreement, any documents contemplated to be executed hereunder, or the transactions contemplated hereby or thereby, whether sounding in contract, tort, statutory law, at common law, or in equity, including, any dispute as to the construction, validity, interpretation, enforceability or breach of this Agreement (each, a “Dispute”) (other than (i) a Dispute arising out of or in relation to or in connection with the calculation of the MEPU Adjustment Amount and the PAI Adjustment Amount, which shall be resolved in accordance with Section 9.4, or (ii) as set out in Section 4.2(c), which shall be resolved in accordance with Section 12.10(c)), on written request of either Transferor, shall be referred to representatives of the Transferors for decision, each Transferor being represented by a senior executive officer of the ultimate parent company of such Transferor who has no direct or operational responsibility for the matters contemplated by this Agreement (the “Negotiation Representatives”).  The Negotiation Representatives shall promptly meet in a good faith effort to resolve the Dispute.  If the Dispute is not resolved, as evidenced by the terms of a settlement reduced to writing and signed by the Transferors, within 30 calendar days after reference of the matter to them (or within such longer period of time as the Transferors may mutually agree in writing), either of the Transferors may submit the Dispute to non-binding mediation as provided in this Section 12.10.

(b)    The Transferors agree that prior to attempting to resolve the Dispute by litigation, the Transferors  may attempt to settle the Dispute by mediation in Houston, Texas under the then current International Institute for Conflict Prevention and Resolution Mediation Procedure, which procedure will be non-binding and confidential unless otherwise agreed by the parties.  Within ten days of a Transferor’s written notice to the other Transferor of its desire to mediate, the non-requesting Transferor will provide a written response indicating whether it agrees to mediate. Within ten days of the non-requesting Transferor’s written notice to the requesting Transferor of its agreement to mediate, the parties will appoint a mutually acceptable mediator from the CPR Panels of Distinguished Neutrals.

(c)    During the 10-day period following the Closing Date, the amount of costs and expenses associated with Casualty Losses in dispute shall be submitted to a consultant with at least ten (10) years’ experience in Gulf of Mexico oil and gas damage and insurance issues as selected by mutual agreement of the Parties or absent such agreement during the 10-day period, by the Houston, Texas office of the American Arbitration Association (the “Losses Arbitrator”).  The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section.  The Losses Arbitrator’s determination shall be made within thirty (30) days after submission of the matters in dispute and shall be final and binding upon both Parties, without right of appeal.  In

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making his determination, the Losses Arbitrator may consider such matters as in the opinion of the Losses Arbitrator are necessary or helpful to make a proper determination.  Additionally, the Losses Arbitrator may consult with and engage disinterested third parties to advise the arbitrator, including attorneys and engineers.  In no event shall the amount of costs and expenses associated with a Casualty Loss as determined by the Losses Arbitrator be less than the amount asserted by the Party asserting the lower amount or greater than the amount asserted by the Party asserting the higher amount.  The Losses Arbitrator shall act as an expert for the limited purpose of determining the amount of costs and expenses associated with Casualty Losses and may not award damages, interest or penalties to either Party with respect to any matter.  Each Party shall bear its own legal fees and other costs of presenting its case.  Each Party shall bear one-half of the costs and expenses of the Losses Arbitrator.

(d)    All applicable statutes of limitation and defenses based upon the passage of time will be tolled for the duration of any Dispute resolution under this Section 12.10.  All negotiations and mediations under this Section 12.10 shall be considered confidential and shall be treated as compromise and settlement negotiations for purposes of applicable rules of evidence.  The Transferors shall continue to perform this Agreement pending the final resolution of any Dispute.

Section 12.11    Captions.   The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement.

Section 12.12    Waiver; Rights Cumulative.   Any of the terms, covenants, representations, warranties or conditions hereof may be waived only by a written instrument executed by or on behalf of the Party waiving compliance.  No course of dealing on the part of any Party, or its respective Representatives, and no failure by a Party to exercise any of its rights under this Agreement shall operate as a waiver thereof or affect in any way the right of such Party at a later time to enforce the performance of such provision.  No waiver by any Party of any condition, or any breach of any term, covenant, representation or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation or warranty.  The rights of the Parties under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right.

Section 12.13    Assignment.  No Party shall assign or otherwise transfer all or any part of this Agreement, nor shall any Party delegate any of its rights or duties hereunder, without the prior written consent of the other Party and any transfer or delegation made without such consent shall be void.  Subject to the foregoing, this Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective successors and assigns.

Section 12.14    Entire Agreement.  The Confidentiality Agreement, this Agreement and the documents to be executed hereunder and the Exhibits and Schedules attached hereto constitute the entire agreement between the Parties pertaining to the subject matter hereof, and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties pertaining to the subject matter hereof.  In the event of any conflict between the provisions

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of this Agreement and any of the documents contemplated to be executed hereunder or the Exhibits or Schedules, the provisions of this Agreement shall control.

Section 12.15    Amendment.   This Agreement may be amended or modified only by an agreement in writing signed by each of MEPU and PAI and expressly identified as an amendment or modification.

Section 12.16    No Third Party Beneficiaries.   Nothing in this Agreement shall entitle any Person other than Transferors to any claim, cause of action, remedy or right of any kind, except the rights expressly provided to the Persons described in Section 11.2(a),   Section 11.2(b) or Section 11.2(c), subject to Section 11.2(d).

Section 12.17    References

In this Agreement:

(a)    References to any gender includes a reference to all other genders;

(b)    References to the singular includes the plural, and vice versa;

(c)    Reference to any Article or Section means an Article or Section of this Agreement;

(d)    Reference to any Exhibit or Schedule means an Exhibit or Schedule to this Agreement, all of which are incorporated into and made a part of this Agreement;

(e)    Titles appearing at the beginning of any Articles, Sections, subsections and other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement, and shall be disregarded in construing the language hereof;

(f)    All references to “$” or “dollars” shall be deemed references to United States dollars;

(g)    References to any Law or agreement means such Law or agreement as it may be amended from time to time;

(h)    Each accounting term not defined herein, and each accounting term partly defined herein to the extent not defined, will have the meaning given to it under GAAP;

(i)    The Parties agree that provisions in this Agreement in “bold” type and/or capital letters satisfy any requirements of the “express negligence rule” and any other requirements at Law or in equity that provisions be conspicuously marked or highlighted;

(j)    Time is of the essence in this Agreement.  If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date

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of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day;

(k)    Unless expressly provided to the contrary, “hereunder,” “hereof,” “herein” and words of similar import are references to this Agreement as a whole and not any particular Section or other provision of this Agreement; and

(l)    “Include” and “including” shall mean include or including without limiting the generality of the description preceding such term.

Section 12.18    Construction.   Each Transferor has had the opportunity to exercise business discretion in relation to the negotiation of the details of the transactions contemplated hereby.  This Agreement is the result of arm’s-length negotiations from equal bargaining positions.   In the event of any ambiguity in this Agreement, no presumption shall arise based on the identity of the draftsman of this Agreement.

Section 12.19    No Partnership Created.    It is not the purpose or intention of this Agreement to create (and it should not be construed as creating) a joint venture, partnership or any type of association, except for U.S. federal and applicable state or local Income Tax purposes, and the Parties are not authorized to act as an agent or principal for each other with respect to any matter related hereto.  Except for the obligation in Section 7.9, nothing contained in this Agreement prevents either Transferor from engaging in any business or purchasing any asset, whether or not in the vicinity of the Assets or in competition with the business of the other.

[Remainder of page intentionally blank; signature pages immediately follow]



 

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IN WITNESS WHEREOF, this Agreement has been signed by each of the Parties as of the date first above written.





 

 



 

 

MURPHY EXPLORATION & PRODUCTION COMPANY - USA



 

 



 

 

By:

 

 

Name:

 

 

Title:

 

 



[Signature Page to Contribution Agreement]


 

 





 

 



 

 

PETROBRAS AMERICA INC.

 



 

 



 

 

By:

 

 

Name:

 

 

Title:

 

 



[Signature Page to Contribution Agreement]


 

 

FOR THE LIMITED PURPOSES OF SECTION 2.1(C):





 

 

MP GULF OF MEXICO, LLC

 



 

 



 

 

By:

 

 

Name:

 

 

Title:

 

 



[Signature Page to Contribution Agreement]


Exhibit 1014 for Q4 2018

Exhibit 10.14

 

MURPHY OIL CORPORATION



PERFORMANCE-BASED RESTRICTED STOCK UNIT – STOCK SETTLED

GRANT AGREEMENT



 

 

 

Performance-Based

Restricted Stock Unit Award Number

Name of Grantee

 

 

Number of Restricted Stock Units Subject to this Grant

 

 

 

[[GRANTNUMBER]]

[[NAME]]

[[UNITSGRANTED]]

 

 

 



This Performance-Based Restricted Stock Unit Award (this  “Award”) is granted on and dated [•] (the “Grant Date”), by Murphy Oil Corporation, a Delaware corporation (the “Company”), pursuant to and for the purposes of the 2018 Long-Term Incentive Plan (the “Plan”).  Any terms used herein and not otherwise defined shall have the meanings set forth in the Plan.



This Agreement is subject to the following terms and provisions. In addition, certain terms and provisions applicable to this Award will be communicated to you in a separate brochure (the “Brochure”). By accepting this Agreement, you agree to the terms and provisions set forth below, in the Plan and in the Brochure.



1.   The Company hereby grants to the employee named above (the “Grantee”) a Performance-Based Award of Restricted Stock Units each equal in value to one share of Common Stock.



2.   This Award is subject to the following vesting and time lapse restrictions:

(a)  In the event that the Performance Measures as set forth in Section 3 below are satisfied in accordance with the Plan, the size of this Award will be determined by the Committee, and the Grantee will be paid the value of his or her units in Shares during the first quarter of the fiscal year immediately following the completion of the three-year performance measurement period;  provided that, except as set forth in Sections 2(c) and 2(d) below, the Grantee is employed by the Company on both the last day of the performance measurement period and the date that the Committee determines the size of this Award. 

(b)  In the event that the Grantee’s employment terminates any time prior to the date that the Committee determines the size of this Award, except as set forth in Sections 2(c) and 2(d) below, he or she will forfeit all units pursuant to this Award.

(c)  In the event of the Grantee’s death, disability, or retirement (as determined in accordance with the Plan), the Grantee will receive the pro-rata number of units earned for performance completed based upon the number of months worked pursuant to this Award up to the time of the death, disability, or retirement event.  In the event that the Performance Measures are satisfied in accordance with the Plan and, as set forth in Section 3 below, the size of this Award is determined by the Committee, the Grantee will be paid his or her  Shares during the first quarter of the fiscal year immediately following the completion of the three-year performance measurement period. 

(d)  If the Grantee is not an employee of the Company who is the Chief Executive Officer (“CEO’), who reports directly to the CEO, or is a Named Executive Officer of the Company at any time during the period beginning on the grant date of this Award and ending on the date on which a Change in Control occurs, this Award will fully vest and one hundred percent (100%) of the performance-based restricted stock units granted will be deemed to be earned at the target level of performance and will be paid in full, without restrictions, upon such Change in Control;  provided,  however, that no payment will be made until the first quarter of 2022 unless such Change in Control also qualifies as a “change in control event” as determined under Section 409A

 


 

 

(e)  If the Grantee is an employee of the Company who is the Chief Executive Officer (“CEO’), who reports directly to the CEO, or is a Named Executive Officer at any time during the period beginning on the grant date of this Award and ending on the date on which a Change in Control occurs, this Award will fully vest and one hundred percent (100%) of the performance-based restricted stock units granted will be deemed to be earned at the target level of performance and will be paid in full, without restrictions, upon the occurrence of a Qualifying Termination of Employment.  “Qualifying Termination of Employment” means the termination of the Grantee’s employment within the two-year period immediately following a Change in Control (x) by the Company or any of its affiliates without Cause or (y) by the Grantee for Good Reason.  Upon a Qualifying Termination of Employment, payment will be made as soon as reasonably practicable following the date of the Qualifying Termination of Employment, less any Shares or amounts deducted for applicable withholding taxes.

(f)  For purposes of this Agreement, “Cause” means the occurrence of any of the following:

(i) Any act or omission by the Grantee which constitutes a material willful breach of the Grantee’s obligations to the Company or any of its affiliates or the Grantee’s continued and willful refusal to substantially perform satisfactorily any duties reasonably required of the Grantee, which results in material injury to the interest or business reputation of the Company or any of its affiliates and which breach, failure or refusal (if susceptible to cure) is not corrected (other than failure to correct by reason of the Grantee’s incapacity due to physical or mental illness) within thirty (30) days after written notification thereof to the Grantee by the Company; provided that no act or failure to act on the Grantee’s part shall be deemed willful unless done or omitted to be done by the Grantee not in good faith and without reasonable belief that the Grantee’s action or omission was in the best interest of the Company or its affiliates;

(ii) The Grantee’s commission of any dishonest or fraudulent act, which has caused or may reasonably be expected to cause a material injury to the interest or business reputation of the Company or any of its affiliates;

(iii) The Grantee’s plea of guilty or nolo contendere to or conviction of a felony under the laws of the United States or any state thereof or any other plea or confession of a similar crime in a jurisdiction in which the Company or any of its affiliates conducts business; or

(iv) The Grantee’s commission of a fraudulent act or participation in misconduct which leads to a material restatement of the Company’s financial statements.

(g)  For purposes of this Agreement, “Good Reason” means the occurrence of any of the following:

(i) Any material diminution in the Grantee’s title, status, position, the scope of duties assigned, responsibilities or authority, including the assignment to the Grantee of any duties, responsibilities or authority in any manner adverse to the Grantee or inconsistent with the duties, responsibilities and authority assigned to the Grantee prior to a Change in Control;

(ii) Any reduction in the Grantee’s base salary, annual target cash bonus opportunity or long-term incentive award opportunity immediately prior to a Change in Control;

 


 

 

(iii) A relocation of more than fifty  (50) miles from the location of the Grantee’s principal job location or office prior to a Change in Control; or

(iv) Any other action or inaction that constitutes a material breach by the Company or any of its affiliates of any employment or similar agreement pursuant to which the Grantee provides services to the Company or any of its affiliates;

provided, that the Grantee provides the Company with a written notice of termination indicating the Grantee’s intent to terminate his or her employment for Good Reason within ninety (90) days after the Grantee becoming aware of any circumstances set forth above, that the Grantee provides the Company with at least thirty (30) days following receipt of such notice to remedy such circumstances, and, if the Company fails to remedy such circumstances during such thirty (30) day period, that the Grantee terminates his or her employment no later than sixty (60) days after the end of such thirty (30) day period.

3.   The Performance Measure for this Award is the Company’s total shareholder return (“TSR”) over the three-year performance measurement period compared to the TSR of the Company’s peer group.  The amount of this Award earned (the “Payout Percentage”) is based on the Company’s percentile ranking in TSR over the three-year performance measurement period compared to that of the peer group.  The Payout Percentage will be interpolated for points between the 25th and 90th percentiles.    



 

Percentile Rank

Payout Percentage

Below 25th Percentile

0.0%

25th Percentile

50.0%

50th Percentile

100.0%

75th Percentile

125.0%

At or Above 90th Percentile

150.0%



Notwithstanding the foregoing, if the Company’s TSR over the three-year performance measurement period is less than 0%, the Payout Percentage shall not exceed 100%.



4.   Provided that the Performance Measures as set forth in Section 3 above are satisfied and Shares are to be paid to the Grantee without restriction, such Shares paid will be the net Shares earned pursuant to Section 3 above less the number of Shares which must be withheld to satisfy the tax withholding requirements applicable to such payment of Shares.



5.   In the event of any relevant change in the capitalization of the Company prior to the issuance of Shares underlying the units, the number of units may be equitably adjusted pursuant to the Plan to reflect that change.



6.   This Award is not assignable except as provided under the Plan in the case of death and is not subject in whole or in part to attachment, execution, or levy of any kind.



7.   The Grantee shall have no voting rights with respect to Shares underlying the units unless and until such Shares are reflected as issued and outstanding shares on the Company’s stock ledger.



8.   The Grantee is eligible to receive a payment equivalent to the dividends paid on shares of Common Stock equal in number to the Restricted Stock Units granted hereunder.  These dividend equivalents will be accrued over the performance period and included in any Shares issued at the end of the period.  In the event that Shares are not earned, the accompanying accrued dividend equivalents will be forfeited.



9.   The Plan, this Agreement and the Brochure are administered by the Committee.  The Committee has the full authority and discretion to interpret and administer the Plan consistent with the terms and provisions of the Plan.





 

 

Attest:

Murphy Oil Corporation



 

 



By

 



 


Exhibit 1015 for Q4 2018

Exhibit 10.15

 

MURPHY OIL CORPORATION



TIME-BASED RESTRICTED STOCK UNIT – STOCK SETTLED

GRANT AGREEMENT





 

 

 

 

 

Time-Based

Restricted Stock Unit Award Number

Name of Grantee

 

 

Number of Restricted Stock Units Subject to this Grant

 

 

 

[[GRANTNUMBER]]

[[NAME]]

[[UNITSGRANTED]]

 

 

 



This Time-Based Restricted Stock Unit Award (this  “Award”) is granted on and dated [•] (the “Grant Date”), by Murphy Oil Corporation, a Delaware corporation (the “Company”), pursuant to and for the purposes of the 2018 Long-Term Incentive Plan (the “Plan”), subject to the provisions set forth herein and in the Plan.  Any terms used herein and not otherwise defined shall have the meanings set forth in the Plan.



1.    The Company hereby grants to the individual named above (the “Grantee”) an Award of Time-Based Restricted Stock Units each equal in value to one share of Common Stock.  This Award constitutes a right to receive Shares in the future and does not represent any current interest in the Shares subject to this Award.



2.    This Award is subject to the following vesting and time lapse restrictions:



(a)    In accordance with the Plan, this Award will fully vest on the [•] anniversary of the Grant Date (the “Vesting Date”) and Shares will be issued, less any Shares deducted for applicable withholding taxes; provided that, except as set forth in Sections 2(c) and 2(d) below, the Grantee is employed by the Company on the Vesting Date; provided further, that this Award shall not vest whenever the delivery of Shares under it would be a violation of any applicable law, rule or regulation.



(b)    In the event that the Grantee’s employment terminates any time prior to the Vesting Date, except as set forth in Sections 2(c) and 2(d) below, he or she will forfeit this Award.



(c)    In the event of the Grantee’s death, disability or retirement (as determined in accordance with the Plan) prior to the Vesting Date, any then outstanding units pursuant to this Award shall vest on the date of the Grantee’s termination of employment in a pro-rated amount determined by multiplying the number of units granted by a fraction, the numerator of which is the number of months in the period beginning on the Grant Date and ending on the last day of the month in which the Grantee terminates employment, and the denominator of which is the total number of months in the Restricted Period.  The Grantee (or his/her beneficiary) will be paid his/her Shares, less any Shares deducted for applicable withholding taxes, as soon as reasonably practicable following the date of the Grantee’s termination of employment.



(d)    If the Grantee is not an employee of the Company who is the Chief Executive Officer (“CEO’), who reports directly to the CEO, or is a Named Executive Officer at any time during the period beginning on the grant date of this Award and ending on the date on which a Change in Control occurs, this Award will fully vest and one hundred percent (100%) of the units granted will be deemed to be earned upon such Change in Control; provided,  however, that no payment will be made until the first quarter of 2022 unless such Change in Control also qualifies as a “change in control event” as determined under Section 409A.   



(e)    If the Grantee is  an employee of the Company who is the Chief Executive Officer (“CEO’), who reports directly to the CEO, or is a Named Executive Officer at any time during the period beginning on the grant date of this Award and ending on the date on which a Change in Control occurs, this Award will fully vest and one hundred percent (100%) of the units granted will be deemed to be earned as of the date of a Qualifying Termination of Employment. Qualifying Termination of Employment” means the termination of the Grantee’s employment within the two-year period immediately following a Change in Control (x) by the Company or any of its affiliates without Cause or (y) by the Grantee for Good Reason.  Shares will be issued

 


 

as soon as reasonably practicable following the date of the Qualifying Termination of Employment, less any Shares deducted for applicable withholding taxes.



(f)    For purposes of this Agreement, Cause” means the occurrence of any of the following:

(i) Any act or omission by the Grantee which constitutes a material willful breach of the Grantee’s obligations to the Company or any of its affiliates or the Grantee’s continued and willful refusal to substantially perform satisfactorily any duties reasonably required of the Grantee, which results in material injury to the interest or business reputation of the Company or any of its affiliates and which breach, failure or refusal (if susceptible to cure) is not corrected (other than failure to correct by reason of the Grantee’s incapacity due to physical or mental illness) within thirty (30) days after written notification thereof to the Grantee by the Company; provided that no act or failure to act on the Grantee’s part shall be deemed willful unless done or omitted to be done by the Grantee not in good faith and without reasonable belief that the Grantee’s action or omission was in the best interest of the Company or its affiliates;

(ii) The Grantee’s commission of any dishonest or fraudulent act, which has caused or may reasonably be expected to cause a material injury to the interest or business reputation of the Company or any of its affiliates;

(iii) The Grantee’s plea of guilty or nolo contendere to or conviction of a felony under the laws of the United States or any state thereof or any other plea or confession of a similar crime in a jurisdiction in which the Company or any of its affiliates conducts business; or

(iv) The Grantee’s commission of a fraudulent act or participation in misconduct which leads to a material restatement of the Company’s financial statements.

(g)    For purposes of this Agreement, “Good Reason” means the occurrence of any of the following:

(i) Any material diminution in the Grantee’s title, status, position, the scope of duties assigned, responsibilities or authority, including the assignment to the Grantee of any duties, responsibilities or authority in any manner adverse to the Grantee or inconsistent with the duties, responsibilities and authority assigned to the Grantee prior to a Change in Control;

(ii) Any reduction in the Grantee’s base salary, annual target cash bonus opportunity or long-term incentive award opportunity immediately prior to a Change in Control;

(iii) A relocation of more than fifty  (50) miles from the location of the Grantee’s principal job location or office prior to a Change in Control; or

(iv) Any other action or inaction that constitutes a material breach by the Company or any of its affiliates of any employment or similar agreement pursuant to which the Grantee provides services to the Company or any of its affiliates; provided, that the Grantee provides the Company with a written notice of termination indicating the Grantee’s intent to terminate his or her employment for Good Reason within ninety (90) days after the Grantee becoming aware of any circumstances set forth above, that the Grantee provides the Company with at least thirty (30) days following receipt of such notice to remedy such circumstances, and, if the Company fails to remedy such circumstances during such thirty (30) day period, that the Grantee terminates his or her employment no later than sixty  (60) days after the end of such thirty (30) day period.

3.    In the event of any relevant change in the capitalization of the Company subsequent to the Grant Date and prior to the issuance of Shares underlying the units, the number of units may be equitably adjusted pursuant to the Plan to reflect that change.



4.    This Award is not assignable except as provided under the Plan in the case of death and is not subject in whole or in part to attachment, execution or levy of any kind.

 


 

5.    The Grantee shall have no voting rights with respect to Shares underlying the units unless and until such Shares are reflected as issued and outstanding shares on the Company’s stock ledger.



6.    The Grantee shall not be eligible to receive any dividends or other distributions paid with respect to these units during the Restricted Period. An amount equivalent to these dividends and/or other distributions shall be paid to the Grantee upon the issuance of Shares and payment of this Award. Any such payment (unadjusted for interest) shall be made in whole Shares, valued as of the date that this Award vests in accordance with Section 2 above,  subject to applicable withholding taxes.



7.    The Plan and this Agreement are administered by the Committee.  The Committee has the full authority and discretion to interpret and administer the Plan consistent with the terms and provisions of the Plan.





 

 



 

 

Attest:

Murphy Oil Corporation



 

 



By

 



 


Exhibit 1016 for Q4 2018

Exhibit 10.16

 

MURPHY OIL CORPORATION



TIME-BASED RESTRICTED STOCK UNIT - STOCK SETTLED

GRANT AGREEMENT





 

 

 

 

 

Time-Based

Restricted Stock Unit Award Number

Name of Grantee

 

 

Number of Restricted Stock Units Subject to this Grant

 

 

 

[[GRANTNUMBER]]

[[FIRSTNAME]] [[MIDDLENAME]] [[LASTNAME]]

[[UNITSGRANTED]]

 

 

 



This Time-Based Restricted Stock Unit Award (the “Award”) is granted on and dated [●] (the “Grant Date”), by Murphy Oil Corporation, a Delaware corporation (the “Company”), pursuant to and for the purposes of the 2018 Long-Term Incentive Plan (the “Plan”).  Any terms used herein and not otherwise defined shall have the meanings set forth in the Plan.



This Agreement is subject to the following terms and provisions:



1.    The Company hereby grants to the individual named above (the Grantee) an Award of Time-Based Restricted Stock Units each equal in value to one share of Common Stock of the Company.  This Award constitutes a right to receive Shares in the future and does not represent any current interest in the Shares subject to the Award.



2.    This Award is subject to the following vesting and time lapse restrictions:



(a)    In accordance with the Plan, this Award will fully vest and Shares will be issued, less any Shares deducted for applicable withholding taxes, without restrictions, on the [●] anniversary of the Award (the “Vesting Date”). This award shall not vest whenever the delivery of Shares under it would be a violation of any applicable law, rule or regulation.

(b)    In the event that the Grantee’s employment terminates any time prior to the Vesting Date,  except for reason of death, disability, or retirement, or as a result of a Qualifying Termination of Employment following a Change in Control,  he/she will forfeit all units pursuant to this Award.

(c)    In the event of the Grantee’s death, disability, or retirement prior to the Vesting Date, the Grantee will receive the pro-rata number of units earned based upon the number of months worked pursuant to this Award up to the date of the death, disability, or retirement event.  The Grantee will be paid his/her Shares, less any Shares deducted for applicable withholding taxes, as soon as reasonably practicable following death, disability, or retirement.

(d)    If the Grantee is not an employee of the Company who is the Chief Executive Officer (“CEO’), who reports directly to the CEO, or is a Named Executive Officer at any time during the period beginning on the Grant Date and ending on the date on which a Change in Control occurs, this Award will fully vest and 100 percent of the Time-Based Restricted Stock Units will be deemed to be earned and Shares will be issued, less any Shares deducted for applicable withholding taxes, without restrictions, upon the occurrence of a Change in Control (as such term is defined in the Plan); provided, however, that no issuance of Shares will be made until the Vesting Date unless the Change in Control also qualifies as a change in the ownership or effective control of Murphy Oil Corporation, or in the ownership of a substantial portion of its assets, as determined under Section 409A of the Internal Revenue Code.

(e)    If the Grantee is an employee of the Company who is the Chief Executive Officer (“CEO’), who reports directly to the CEO, or is a Named Executive Officer at any time during the period beginning on the Grant Date and ending on the date on which a Change in Control occurs, this Award will fully vest and 100 percent of the Time-Based Restricted Stock Units will be deemed to be earned and Shares will be issued in full, without restriction, as of the date of the Qualifying Termination of Employment. “Qualifying Termination of Employment” means the termination of the Grantee’s employment within the two-year period immediately following a Change in Control (x) by the Company or any of its affiliates without Cause or (y) by the Grantee for Good Reason.  Upon a Qualifying Termination of Employment, Shares will be issued as soon as reasonably practicable following the date of the Qualifying Termination of Employment, less any Shares deducted for applicable withholding taxes.

 


 

 

(f)    For purposes of this Award, “Cause” means the occurrence of any of the following:



(i) Any act or omission by the Grantee which constitutes a material willful breach of the Grantee’s obligations to the Company or any of its affiliates or the Grantee’s continued and willful refusal to substantially perform satisfactorily any duties reasonably required of the Grantee, which results in material injury to the interest or business reputation of the Company or any of its affiliates and which breach, failure or refusal (if susceptible to cure) is not corrected (other than failure to correct by reason of the Grantee’s incapacity due to physical or mental illness) within thirty (30) days after written notification thereof to the Grantee by the Company; provided that no act or failure to act on the Grantee’s part shall be deemed willful unless done or omitted to be done by the Grantee not in good faith and without reasonable belief that the Grantee’s action or omission was in the best interest of the Company or its affiliates;

(ii) The Grantee’s commission of any dishonest or fraudulent act, which has caused or may reasonably be expected to cause a material injury to the interest or business reputation of the Company or any of its affiliates;

(iii) The Grantee’s plea of guilty or nolo contendere to or conviction of a felony under the laws of the United States or any state thereof or any other plea or confession of a similar crime in a jurisdiction in which the Company or any of its affiliates conducts business; or

(iv) The Grantee’s commission of a fraudulent act or participation in misconduct which leads to a material restatement of the Company’s financial statements.

(g)    For purposes of this Award, “Good Reason” means the occurrence of any of the following:

(i) Any material diminution in the Grantee’s title, status, position, the scope of duties assigned, responsibilities or authority, including the assignment to the Grantee of any duties, responsibilities or authority in any manner adverse to the Grantee or inconsistent with the duties, responsibilities and authority assigned to the Grantee prior to a Change in Control;

(ii) Any reduction in the Grantee’s base salary, annual target cash bonus opportunity or long-term incentive award opportunity immediately prior to a Change in Control;

(iii) A relocation of more than fifty  (50) miles from the location of the Grantee’s principal job location or office prior to a Change in Control; or

(iv) Any other action or inaction that constitutes a material breach by the Company or any of its affiliates of any employment or similar agreement pursuant to which the Grantee provides services to the Company or any of its affiliates; provided, that the Grantee provides the Company with a written notice of termination indicating the Grantee’s intent to terminate his or her employment for Good Reason within ninety (90) days after the Grantee becoming aware of any circumstances set forth above, that the Grantee provides the Company with at least thirty (30) days following receipt of such notice to remedy such circumstances, and, if the Company fails to remedy such circumstances during such thirty (30) day period, that the Grantee terminates his or her employment no later than sixty (60) days after the end of such thirty (30) day period.

3.    In consideration of the grant to the Grantee of this Award, the Grantee agrees that,  during the period beginning on the date of the termination of the Grantee’s employment for any reason, including retirement or any voluntary resignation (the “Termination Date”) and ending on the first anniversary of the Termination Date,  the Grantee will not, without the Company’s express written consent, (i) directly or indirectly solicit, induce or attempt to induce any employees, agents or consultants of the Company or its subsidiaries or affiliates to do anything from which the Grantee is restricted by reason of this Award; (ii) directly or indirectly solicit, induce or aid others to solicit or induce any employees, agents or consultants of the Company or any of its subsidiaries or affiliates to terminate their employment or engagement with the Company or any of its subsidiaries or affiliates and/or to enter into an employment, agency or consultancy relationship with Grantee or any other person or entity with whom Grantee is affiliated; or (iii) own, manage, operate, control, render service to, or participate in the ownership, management, operation or control of any Competitor (as defined below) anywhere in the United States or in any non U.S. jurisdiction in which the Company is engaged or plans to engage in business as of the Termination Date; provided, however, that Grantee will be entitled to own shares of stock of any corporation having a class of equity securities actively traded on a national securities exchange or the Nasdaq Stock Market which represent, in the aggregate, not more than 1% of such corporation’s fully-diluted shares.  For purposes of this Award, “Competitor” means any company, other entity or association or individual that directly or indirectly is engaged in (i) the business of oil or gas exploration or production or (ii) any other business in which the Company or any of its subsidiaries is engaged as of the Termination Date.


 

 



4.    In the event of any relevant change in the capitalization of the Company subsequent to the Grant Date and prior to the Award becoming vested, the number of units subject to the Award will be equitably adjusted pursuant to the Plan to reflect that change.



5.    This Award is not assignable except as provided under the Plan in the case of death, and is not subject in whole or in part to attachment, execution or levy of any kind.



6.    The Grantee shall have no voting rights with respect to Shares underlying the units unless and until such Shares are reflected as issued and outstanding shares on the Company’s stock ledger.



7.    The Grantee shall not be eligible to receive any dividends or other distributions paid with respect to the Award during the Restricted Period. An amount equivalent to these dividends and/or other distributions shall be paid to the Grantee upon the issuance of Shares and payment of the Award. Any such payment (unadjusted for interest) shall be made in whole Shares, valued as of the date that this Award becomes vested, subject to any Shares deducted for applicable withholding taxes.



8.    The Plan and this Agreement are administered by the Executive Compensation Committee of the Board of Directors of Murphy Oil Corporation.  The Executive Compensation Committee has the full authority to interpret and administer the Plan consistent with the terms and provisions of the plan document.





 

 

Attest:

Murphy Oil Corporation



 

 



By

 




Exhibit 1020 for Q4 2018

Exhibit 10.20

 

MURPHY OIL CORPORATION

RESTRICTED STOCK UNIT AWARD 

GRANT AGREEMENT



 

 

 

 

Restricted Stock Unit Award

Number:

 

Name of

Awardee:

 

Number of Restricted

Stock Units Subject to

this award:





This Restricted Stock Unit Award is granted on and dated [•],  by Murphy Oil Corporation, a Delaware corporation (the Company), pursuant to and for the purposes of the 2018 Stock Plan for Non-Employee Directors (the Plan) adopted by the stockholders of the Company on May 9, 2018, subject to the provisions set forth herein and in the Plan.  Any terms used herein and not otherwise defined shall have the meaning set forth in the Plan.



1.  The Company hereby grants to the individual named above (the Awardee) an award of Restricted Stock Units each equal in value to one share of Common Stock.  This award constitutes a right to receive shares in the future and does not represent any current interest in the shares subject to the award.



2.  Subject to paragraph 3 below and in accordance with the Plan, this award will fully vest on the earlier of (a) the third anniversary of the date of grant, [•], or (b) such earlier termination of service as a member of the Board (the “Vesting Date”) provided for in the Plan,  and Common Shares and any accrued dividend equivalents will be issued, without restrictions, within thirty days following the Vesting Date or, in the case of Deferred Units, the settlement date selected at the time a valid deferral election was made in accordance with the Plan (the “Settlement Date”).  This award shall not be settled whenever the delivery of shares of Common Stock under it would be a violation of any applicable law, rule or regulation.



3.  The Restricted Stock Unit Award will fully vest and 100 percent of the Restricted Stock Units will be deemed to be earned and Common Shares will be issued, without restrictions, upon the occurrence of a Change in Control (as such term is defined in the Plan) provided, however, that no issuance of shares will be made until [•] unless the Change in Control also qualifies as a change in the ownership or effective control of Murphy Oil Corporation, or in the ownership of a substantial portion of its assets, as determined under Section 409A of the Internal Revenue Code.



4.  In the event of any relevant change in the capitalization of the Company subsequent to the date of this grant and prior to its vesting, the number of Restricted Stock Units will be adjusted to reflect that change.



5.  In accordance with the Plan, settlement of the Restricted Stock Unit Award may be deferred to the extent the Company received from the holder of the Restricted Stock Units an executed valid deferral election form,  in compliance with such rules and procedures as the Committee deems advisable, no later than December 31 of the calendar year prior to the year in which the Restricted Stock Unit Award was granted. 



6.  This Restricted Stock Unit Award is not assignable except as provided in the case of death and is not subject in whole or in part to attachment, execution or levy of any kind.



7.  The holder of the Restricted Stock Units shall not be eligible to receive any dividends or other distributions paid with respect to the underlying Common Shares prior to the Settlement Date. An amount equivalent to these dividends and/or other distributions shall be paid to the holder on the Settlement Date. Any such payment (unadjusted for interest) shall be made in whole shares of the $1.00 par value Common Stock of the Company and in cash equal to the value of any fractional shares.





 

 



 

 

Attest:

MURPHY OIL CORPORATION



 

 



By

 



 


Exhibit 104 for Q4 2018

Exhibit 10.4




CREDIT AGREEMENT

dated as of November 28, 2018

among

MURPHY OIL CORPORATION,
MURPHY EXPLORATION & PRODUCTION COMPANY – INTERNATIONAL,
and
MURPHY OIL COMPANY LTD.,
as Borrowers

JPMORGAN CHASE BANK, N.A.,
as Administrative Agent

and

The Lenders Party Hereto

____________________________

BANK OF AMERICA, N.A.,
as Syndication Agent



and 



dnb bank asa, new york branch, wells fargo BANK, NATIONAL ASSOCIATION, MUFG bank, ltd., THE BANK OF NOVA SCOTIA AND REGIONS BANK,

as Co-Documentation Agents

___________________________

JPMorgan chase bank, n.a., MERRILL LYNCH, PIERCE, FENNER & Smith IncORPORATED, DnB MARKETS, INC., Wells Fargo Securities, LLC, MUFG Bank, Ltd., THE BANK OF NOVA SCOTIA and REGIONS BANK,
 as Co-Lead Arrangers and Joint Bookrunners
____________________________



 


 

Table of Contents





 

 



 

Page

Article I

Definitions

Section 1.01

Defined Terms

Section 1.02

Classification of Loans and Borrowings

38 

Section 1.03

Terms Generally

38 

Section 1.04

Accounting Terms; GAAP

38 

Section 1.05

Exchange Rates; Currency Equivalents

39 

Section 1.06

Interest Rates; LIBOR Notification

39 



 

 

Article II

The Credits

40 

Section 2.01

Commitments

40 

Section 2.02

Loans and Borrowings

40 

Section 2.03

Requests for Revolving Borrowings

41 

Section 2.04

[Reserved]

42 

Section 2.05

Letters of Credit

42 

Section 2.06

Funding of Borrowings

47 

Section 2.07

Interest Elections

48 

Section 2.08

Termination and Reduction of Commitments

49 

Section 2.09

Repayment of Loans; Evidence of Debt

50 

Section 2.10

Prepayment of Loans

50 

Section 2.11

Fees

52 

Section 2.12

Interest

53 

Section 2.13

Alternate Rate of Interest; Illegality

53 

Section 2.14

Increased Costs

55 

Section 2.15

Break Funding Payments

56 

Section 2.16

Payments Free of Taxes

57 

Section 2.17

Payments Generally; Pro Rata Treatment; Sharing of Set-offs

60 

Section 2.18

Mitigation Obligations; Replacement of Lenders

62 

Section 2.19

Defaulting Lenders

63 

Section 2.20

Commitment Increase

65 



 

 

Article III

Representations and Warranties

66 

Section 3.01

Organization; Powers

66 

Section 3.02

Authorization; Enforceability

67 

Section 3.03

Governmental Approvals; No Conflicts

67 

Section 3.04

Financial Condition; No Material Adverse Effect; No Default

67 

Section 3.05

Properties

68 

Section 3.06

Litigation and Environmental Matters

68 

Section 3.07

Compliance with Laws and Agreements

69 

Section 3.08

Investment Company Status

69 

Section 3.09

Taxes

69 

Section 3.10

ERISA

69 

Section 3.11

Disclosure

69 

Section 3.12

Insurance

70 



-i-

 


 

Table of Contents

(continued)



 

Page

Section 3.13

Restriction on Subsidiary Distributions

70 

Section 3.14

Subsidiaries

70 

Section 3.15

Solvency

71 

Section 3.16

Priority Status

71 

Section 3.17

Anti-Corruption Laws and Sanctions

71 

Section 3.18

Use of Proceeds

71 

Section 3.19

EEA Financial Institutions

72 



 

 

Article IV

Conditions

72 

Section 4.01

Effective Date

72 

Section 4.02

Each Credit Event

73 



 

 

Article V

Affirmative Covenants

74 

Section 5.01

Financial Statements, Ratings Change, and Other Information

74 

Section 5.02

Notices of Material Events

77 

Section 5.03

Existence; Conduct of Business

77 

Section 5.04

Payment of Obligations

77 

Section 5.05

Maintenance of Properties

77 

Section 5.06

Insurance

78 

Section 5.07

Books and Records; Inspection Rights

78 

Section 5.08

Compliance with Laws

78 

Section 5.09

Use of Proceeds

79 

Section 5.10

Reserve Reports

79 

Section 5.11

[Reserved]

80 

Section 5.12

Additional Guarantors

80 

Section 5.13

[Reserved]

80 

Section 5.14

Accounts

80 

Section 5.15

[Reserved]

80 

Section 5.16

More Favorable Financial Covenants

80 

Section 5.17

Commodity Exchange Act Keepwell Provisions

81 

Section 5.18

Canam Distribution Covenant

82 

Section 5.19

Permitted JV Closing

82 



 

 

Article VI

Negative Covenants

82 

Section 6.01

Indebtedness

82 

Section 6.02

Subsidiary Guarantees Prior to the Investment Grade Rating Date

86 

Section 6.03

Liens

86 

Section 6.04

Fundamental Changes

87 

Section 6.05

Hedging Agreements

88 

Section 6.06

Transactions with Affiliates

88 

Section 6.07

Restrictive Agreements; Subsidiary Distributions

88 

Section 6.08

Restricted Payments

89 

Section 6.09

Investments Prior to the Investment Grade Rating Date

89 



-ii-

 


 

Table of Contents

(continued)



 

Page

Section 6.10

Restricted Debt Payments Prior to the Investment Grade Rating Date

90 

Section 6.11

Asset Dispositions Prior to the Investment Grade Rating Date

91 

Section 6.12

Termination or Modifications of the Effective Date Canam Intercompany Obligations Prior to the Investment Grade Rating Date

92 

Section 6.13

New Accounts Prior to the Investment Grade Rating Date

92 

Section 6.14

Financial Covenants

92 

Section 6.15

Amendment to Permitted JV Agreements

92 

Section 6.16

Minimum Domestic Liquidity Prior to the Investment Grade Rating Date

92 



 

 

Article VII

Events of Default

93 

Section 7.01

Events of Default

93 

Section 7.02

Remedies

95 



 

 

Article VIII

[Reserved]

96 



 

 

Article IX

The Administrative Agent

96 



 

 

Article X

Miscellaneous

99 

Section 10.01

Notices

99 

Section 10.02

Waivers; Amendments

100 

Section 10.03

Expenses; Indemnity; Damage Waiver

102 

Section 10.04

Successors and Assigns

103 

Section 10.05

Survival

107 

Section 10.06

Counterparts; Integration; Effectiveness; Electronic Execution

107 

Section 10.07

Severability

108 

Section 10.08

Right of Setoff

108 

Section 10.09

Governing Law; Jurisdiction; Consent to Service of Process

108 

Section 10.10

Waiver of Jury Trial

109 

Section 10.11

Headings

110 

Section 10.12

Confidentiality

110 

Section 10.13

Material Non-Public Information

111 

Section 10.14

Interest Rate Limitation

111 

Section 10.15

USA Patriot Act

111 

Section 10.16

Hedging Agreements; Cash Management Agreements

112 

Section 10.17

Acknowledgement and Consent to Bail-In of EEA Financial Institutions

112 

Section 10.18

No Advisory or Fiduciary Responsibility

112 

Section 10.19

Currency Conversion; Judgment Currency

113 

Section 10.20

Release of Guarantees

114 



-iii-

 


 

Table of Contents

(continued)



 

 

Schedules:

 

Page

Schedule 2.01

Commitments

 

Schedule 2.05

Existing Letters of Credit

 

Schedule 3.14

Subsidiaries

 

Schedule 5.14

Accounts

 

Schedule 6.01

Existing Indebtedness

 

Schedule 6.03

Existing Liens

 

Schedule 6.09

Existing Investments

 



 

 

Exhibits:

 

 

Exhibit A

Form of Assignment and Assumption

 

Exhibit B-1

Form of Opinion of the Loan Parties’ Counsel

 

Exhibit B-2

Form of Opinion of MOCL’ Counsel

 

Exhibit C-1

U.S. Tax Certificate (For Non-U.S. Lenders that are not Partnerships for U.S. Federal Income Tax Purposes)

 

Exhibit C-2

U.S. Tax Certificate (For Non-U.S. Participants that are not Partnerships for U.S. Federal Income Tax Purposes)

 

Exhibit C-3

U.S. Tax Certificate (For Non-U.S. Participants that are Partnerships for U.S. Federal Income Tax Purposes)

 

Exhibit C-4

U.S. Tax Certificate (For Non-U.S. Lenders that are Partnerships for U.S. Federal Income Tax Purposes)

 

Exhibit D

Compliance Certificate

 

Exhibit E

Form of Guaranty Agreement

 

Exhibit F

Form of Subordinated Intercompany Note

 



-iv-



 

 


 

 

Credit Agreement dated as of November 28, 2018, among Murphy Oil Corporation, a Delaware corporation (the “Company”), MURPHY EXPLORATION & PRODUCTION COMPANY – INTERNATIONAL, a Delaware corporation (“Expro-Intl.”), Murphy Oil Company Ltd., a Canadian corporation (“MOCL”), the Lenders party hereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., as Syndication Agent, and DNB Bank ASA, New York Branch, Wells Fargo Bank, National Association, MUFG Bank, Ltd., The Bank of Nova Scotia and Regions Bank, as Co-Documentation Agents.

RECITALS

A.    The Company, Expro-Intl. and MOCL, as borrowers, have requested that the Lenders provide certain loans to and extensions of credit on behalf of the Borrowers.

B.    The Lenders have agreed to make such loans and extensions of credit subject to the terms and conditions of this Agreement.

C.    In consideration of the mutual covenants and agreements herein contained and of the loans, extensions of credit and commitments hereinafter referred to, the parties hereto agree as follows:

Article I
Definitions

Section 1.01    Defined Terms.  As used in this Agreement, the following terms have the meanings specified below:

1999 Indenture” means the Indenture dated as of May 4, 1999, between the Company, as issuer and SunTrust Bank, Nashville, N.A., as trustee, as amended and supplemented from time to time.

2012 Indenture” means the Indenture dated as of May 18, 2012, between the Company, as issuer and U.S. Bank National Association, as trustee, as amended and supplemented from time to time.

ABR”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, bear interest at a rate determined by reference to the Alternate Base Rate.

Additional Financial Covenant” means any affirmative or negative “maintenance” financial covenant contained in any Other Debt Agreement applicable to the Company or any Subsidiary (regardless of whether such provision is labeled or otherwise characterized as a “financial covenant”), including any defined terms as used therein.

Adjusted LIBO Rate” means, with respect to any Eurodollar Borrowing for any Interest Period, an interest rate per annum (rounded upwards, if necessary, to the next 1/16 of 1%) equal to (a) the LIBO Rate for such Interest Period multiplied by (b) the Statutory Reserve Rate.

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Credit Agreement


 

 

Administrative Agent” means JPMorgan Chase Bank, N.A., in its capacity as administrative agent for the Lenders hereunder.

Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Administrative Agent.

Affected Loan” has the meaning set forth in Section 2.17(f).

Affiliate” means, with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified.

Agent Parties” has the meaning assigned to it in Section 10.01(d).

Agreement” means this Credit Agreement, as the same may from time to time be amended, modified, supplemented or restated.

Alternate Base Rate” means, for any day, a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the NYFRB Rate in effect on such day plus ½ of 1% and (c) the Adjusted LIBO Rate for a one month Interest Period on such day (or if such day is not a Business Day, the immediately preceding Business Day) plus 1%; provided that, the Adjusted LIBO Rate for any day shall be based on the LIBO Rate at approximately 11:00 a.m. London time on such day.  Any change in the Alternate Base Rate due to a change in the Prime Rate, the NYFRB Rate or the Adjusted LIBO Rate shall be effective from and including the effective date of such change in the Prime Rate, the NYFRB Rate or the Adjusted LIBO Rate, respectively.  If the Alternate Base Rate is being used as an alternate rate of interest pursuant to Section 2.13 hereof, then the Alternate Base Rate shall be the greater of clause (a) and (b) above and shall be determined without reference to clause (c) above.

Anti-Corruption Laws” means all laws, rules, and regulations of any jurisdiction applicable to the Company, any other Borrower or any of their respective Subsidiaries from time to time concerning or relating to bribery or corruption.

Applicable Percentage” means, with respect to any Lender, the percentage of the total Commitments represented by such Lender’s Commitment; provided that in the case of Section 2.19 when a Defaulting Lender shall exist, “Applicable Percentage” shall mean the percentage of the total Commitments (disregarding any Defaulting Lender’s Commitment) represented by such Lender’s Commitment.  If the Commitments have terminated or expired, the Applicable Percentages shall be determined based upon the Commitments most recently in effect, giving effect to any assignments and to any Lender’s status as a Defaulting Lender at the time of determination.

Applicable Rate” means, for any day, with respect to any ABR Revolving Loan or Eurodollar Revolving Loan, or with respect to the facility fees payable hereunder, as the case may be, the applicable rate per annum set forth in the following grid under the caption “ABR Spread”, “Eurodollar Spread” or “Facility Fee Rate”, as the case may be, based upon the ratings by Moody’s and S&P, respectively, applicable on such date to the Index Debt:

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Credit Agreement


 

 



 

 

 

 

 

Level

Index Debt Ratings

Facility Fee Rate

Eurodollar Spread

ABR

Spread

All-In Drawn

I

BBB / Baa2 or higher

0.175%

1.075%

0.075%

1.25%

II

BBB- / Baa3

0.200%

1.30%

0.30%

1.50%

III

BB+ / Ba1

0.300%

1.45%

0.45%

1.75%

IV

BB / Ba2

0.350%

1.65%

0.65%

2.00%

V

BB- / Ba3 or lower

0.400%

2.10%

1.10%

2.50%



For purposes of the foregoing, (i) if either Moody’s or S&P shall not have in effect a rating for the Index Debt (other than by reason of the circumstances referred to in the last sentence of this paragraph), then such rating agency shall be deemed to have established a rating in Level V; (ii) if the ratings established or deemed to have been established by Moody’s and S&P for the Index Debt shall fall within different categories, the rate shall be based on the higher of the two ratings unless one of the ratings is two or more Levels lower than the other, in which case the rate shall be determined by reference to the Level one Level lower than the higher of the two ratings; and (iii) if the ratings established or deemed to have been established by Moody’s and S&P for the Index Debt shall be changed (other than as a result of a change in the rating system of Moody’s or S&P), such change shall be effective as of the date on which it is first announced by the applicable rating agency.  Each change in the rate shall apply during the period commencing on the effective date of such change and ending on the date immediately preceding the effective date of the next such change.  If the rating system of Moody’s or S&P shall change, or if either such rating agency shall cease to be in the business of rating corporate debt obligations, the Company and the Lenders shall negotiate in good faith to amend this definition to reflect such changed rating system or the unavailability of ratings from such rating agency and, pending the effectiveness of any such amendment, the rate shall be determined by reference to the rating most recently in effect prior to such change or cessation.

Approved Fund” has the meaning assigned to it in Section 10.04(b).

Approved Petroleum Engineer” means (a) Netherland, Sewell & Associates, Inc., (b) Cawley, Gillespie & Associates, Inc., (c) Ryder Scott Co. LP, (d) W.D. Von Gonten & Co. Petroleum Engineering, (e) De Golyer and MacNaughton, (f) McDaniel & Associates Consultants, or (g) any other independent petroleum engineers reasonably acceptable to the Administrative Agent.

Assignment and Assumption” means an assignment and assumption entered into by a Lender and an assignee (with the consent of any party whose consent is required by

3

Credit Agreement


 

 

Section 10.04), and accepted by the Administrative Agent, in the form of Exhibit A or any other form approved by the Administrative Agent.

Attributable Debt” means, in respect of a Sale and Leaseback Transaction, as at the time of determination, the present value of the total obligations of the lessee for rental payments during the remaining term of the lease included in such Sale and Leaseback Transaction (including any period for which such lease has been extended); provided,  however, that if such Sale and Leaseback Transaction results in a Capital Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of and will constitute “Capital Lease Obligations.” Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP.

Availability Period” means the period from and including the Effective Date to but excluding the earlier of the Maturity Date and the date of termination of the Commitments.

Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable EEA Resolution Authority in respect of any liability of an EEA Financial Institution.

Bail-In Legislation” means, with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule.

Bankruptcy Event” means, with respect to any Person, such Person becomes the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee, administrator, custodian, assignee for the benefit of creditors or similar Person charged with the reorganization or liquidation of its business appointed for it, or, in the good faith determination of the Administrative Agent, has taken any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any such proceeding or appointment; provided that a Bankruptcy Event shall not result solely by virtue of any ownership interest, or the acquisition of any ownership interest, in such Person by a Governmental Authority or instrumentality thereof, unless such ownership interest results in or provides such Person with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Person (or such Governmental Authority or instrumentality) to reject, repudiate, disavow or disaffirm any contracts or agreements made by such Person.

Beneficial Ownership Certification” means a certification regarding beneficial ownership or control as required by the Beneficial Ownership Regulation.

Beneficial Ownership Regulation” means 31 C.F.R. § 1010.230.

Board” means the Board of Governors of the Federal Reserve System of the United States of America.

4

Credit Agreement


 

 

Borrower” means each of the Company, Expro-Intl., and MOCL, and “Borrowers” means the Company, Expro-Intl. and MOCL, collectively.

Borrowing” means Revolving Loans of the same Type, made, converted or continued on the same date and, in the case of Eurodollar Loans, as to which a single Interest Period is in effect.

Borrowing Request” means a request by the Company on behalf of itself, Expro-Intl. or MOCL for a Revolving Borrowing in accordance with Section 2.03.

Business Day” means any day that is not a Saturday, Sunday or other day on which commercial banks in New York City are authorized or required by law to remain closed; provided that, when used in connection with a Eurodollar Loan, the term “Business Day” shall also exclude any day on which banks are not open for dealings in dollar deposits in the London interbank market.

Canadian Dollars” means the lawful currency of Canada.

Canadian Subsidiary” means any Subsidiary of the Company organized or incorporated under the laws of Canada or any province thereof (including, without limitation, MOCL).

Canam” means Canam Offshore Limited, a corporation organized under the laws of the Bahamas.

Canam Cash Amount” means, on the last day of any fiscal quarter of the Company, an amount equal to the aggregate amount of all cash, cash equivalents, marketable securities, treasury bonds and bills, certificates of deposit, investments in money market funds and commercial paper and Permitted Investments, in each case, held or owned by (whether directly or indirectly), credited to the account of, or otherwise reflected as an asset on the balance sheet of, the Excluded Canam Entities on such day (net of any such amounts that have been reserved since July 1 of the then current fiscal year for the purpose of funding the principal and interest payments due on or before the following June 30 in respect of the Effective Date Canam Intercompany Obligations required to be made pursuant to the terms of the Effective Date Canam Intercompany Note).

Capital Lease Obligations” of any Person means the obligations of such Person to pay rent or other amounts under any lease of (or other arrangement conveying the right to use) real or personal property, or a combination thereof, which obligations are required to be classified and accounted for as capital leases on a balance sheet of such Person under GAAP, and the amount of such obligations shall be the capitalized amount thereof determined in accordance with GAAP.

Cash Management Agreement” means any agreement to provide cash management services, including treasury, depository, overdraft, credit or debit card, electronic funds transfer and other cash management services.

Cash Receipts” means all cash received by or on behalf of the Company or any Subsidiary, including without limitation: (a) amounts payable under or in connection with any

5

Credit Agreement


 

 

Oil and Gas Properties; (b) cash representing operating revenue earned or to be earned by the Company or any Subsidiary; (c) proceeds from Loans; and (d) any other cash received by or on behalf of the Company or any Subsidiary from whatever source (including amounts received in respect of the Liquidation of any Hedging Agreement and amounts received in respect of any Disposition or Casualty Event).

Casualty Event” means any loss, casualty or other damage to, or any nationalization, taking under power of eminent domain or by condemnation or similar proceeding of, any Property of the Company or any of its Subsidiaries.

Certifying Officer” has the meaning set forth in Section 5.01(c).

Change in Control” means either: (a) any Person or group of related Persons (other than members of the Murphy Family) shall have acquired beneficial ownership of more than 35% of the outstanding voting shares of the Company (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended, and the applicable rules and regulations thereunder); or (b) during any period of 12 consecutive calendar months, individuals who were members of the Board of Directors of the Company on the first day of such period shall cease to constitute at least 66-2/3% of the members of the Board of Directors of the Company.

Change in Law” means the occurrence after the Effective Date, or with respect to any Lender, any later date on which such Lender becomes a party to this Agreement, of (a) the adoption of or taking effect of any law, rule, regulation or treaty, (b) any change in any law, rule, regulation or treaty or in the interpretation or application thereof by any Governmental Authority or (c) compliance by any Lender or any Issuing Bank (or, for purposes of Section 2.14(b), by any lending office of such Lender or by such Lender’s or such Issuing Bank’s holding company, if any) with any request, guideline or directive (whether or not having the force of law) of any Governmental Authority made or issued after the date of this Agreement; provided that, notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall be deemed to be a “Change in Law,” regardless of the date enacted, adopted or issued.

Charges” has the meaning set forth in Section 10.14.

Class” when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are Revolving Loans.

Code” means the Internal Revenue Code of 1986, as amended from time to time.

Commitment” means, with respect to each Lender, the commitment of such Lender to make Revolving Loans and to acquire participations in Letters of Credit hereunder, expressed as an amount representing the maximum aggregate amount of such Lender’s Credit Exposure hereunder, as such commitment may be (a) reduced from time to time pursuant to Section 2.08,

6

Credit Agreement


 

 

and (c) reduced or increased from time to time pursuant to assignments by or to such Lender pursuant to Section 10.04. The amount of each Lender’s Commitment on the Effective Date is set forth on Schedule 2.01, or in the Assignment and Assumption pursuant to which such Lender shall have assumed its Commitment, as applicable. The aggregate amount of the Lenders’ Commitments on the Effective Date is $1,600,000,000.

Commitment Increase” has the meaning assigned to such term in Section 2.20(a).

Commitment Increase Date” has the meaning assigned to such term in Section 2.20(a).  

Commodity Account” has the meaning assigned to such term in the UCC.

Commodity Exchange Act” means the Commodity Exchange Act (7 U.S.C. § 1 et seq.), as amended from time to time, and any successor statute, and any regulations promulgated thereunder.

Communications” has the meaning assigned to it in Section 10.01(d).

Company” has the meaning assigned to such term in the preliminary paragraph of this Agreement.

Compliance Certificate” has the meaning assigned to it in Section 5.01(d).  

Computation Date” has the meaning set forth in Section 1.05.

Connection Income Taxes” means Other Connection Taxes that are imposed on or measured by net income (however denominated) or that are franchise Taxes or branch profits Taxes.

Consolidated EBITDA” means, for any period, Consolidated Net Income for such period plus, (a) the following expenses or charges (without duplication) to the extent deducted from revenues in determining Consolidated Net Income for such period:  (i) income tax expense, (ii) Consolidated Interest Expense, (iii) depletion, depreciation and amortization expense, (iv) exploration expense for such period (including all drilling, completion, geological and geophysical costs), (v) extraordinary or non-recurring cash costs, expenses and charges, including those related to severance, cost savings, operating expense reductions, facilities closings, percentage of completion contracts, consolidations, and integration costs and other restructuring charges or reserves (provided that the aggregate amount of all amounts added back pursuant to this clause (v) shall not, in the aggregate, exceed (A) $75,000,000 during any period of four consecutive fiscal quarters of the Company or (B) $200,000,000 during the term of this Agreement), (vi) any non-cash losses or charges under Hedging Agreements resulting from the application of FASB ASC 815, (vii) noncash compensation expenses or costs related to any

7

Credit Agreement


 

 

management equity plan or stock option plan or any other management or employee benefit plan or agreement and (vii) all other non-cash charges, expenses or losses including, without limitation, accretion expenses associated with asset retirement obligations and minus, (b) to the extent included in the statement of such Consolidated Net Income for such period, the sum of (i) interest income, (ii) any extraordinary, unusual or non-recurring income or gains (including, whether or not otherwise includable as a separate item in the statement of such Consolidated Net Income for such period, gains on the sales of assets outside of the ordinary course of business), (iii) income tax credits (to the extent not netted from income tax expense), (iv) any other non-cash income and (v) any cash payments made during such period in respect of items described in clause (a)(v) above subsequent to the fiscal quarter in which the relevant non-cash expenses or losses were reflected as a charge in the statement of Consolidated Net Income, all as determined on a consolidated basis.  For the purposes of calculating Consolidated EBITDA for any period of four consecutive fiscal quarters (each, a “Reference Period”) pursuant to any determination of the Consolidated Leverage Ratio or the Consolidated Interest Coverage Ratio, (i) if at any time during such Reference Period the Company or any Subsidiary shall have made any Material Disposition, the Consolidated EBITDA for such Reference Period shall be reduced by an amount equal to the Consolidated EBITDA (if positive) attributable to the property that is the subject of such Material Disposition for such Reference Period or increased by an amount equal to the Consolidated EBITDA (if negative) attributable thereto for such Reference Period and (ii) if during such Reference Period the Company or any Subsidiary shall have made a Material Acquisition, Consolidated EBITDA for such Reference Period shall be calculated after giving pro forma effect thereto as if such Material Acquisition occurred on the first day of such Reference Period.  As used in this definition, “Material Acquisition” means any acquisition of property or series of related acquisitions of property that (x) is permitted pursuant to Section 6.09, (y) constitutes assets comprising all or substantially all of an operating unit of a business or constitutes all or substantially all of the common stock of a Person and (z) would result in an increase in Consolidated EBITDA equal to or in excess of $30,000,000; and “Material Disposition” means any Disposition of property or series of related Dispositions of property that (x) is permitted pursuant to Section 6.11 and (y) would result in a decrease in Consolidated EBITDA equal to or in excess of $30,000,000.

Consolidated EBITDA Ex-Canam” means, for any period, (a) Consolidated EBITDA minus (b) Excluded Canam EBITDA.

Consolidated EBITDA Ex-MOCL” means, for any period, (a) Consolidated EBITDA minus (b) Excluded MOCL EBITDA.

Consolidated Interest Coverage Ratio” means, for any period, the ratio of (a) Consolidated EBITDA for such period to (b) Consolidated Interest Expense for such period.

Consolidated Interest Expense” means, for any period, the sum (determined without duplication) of the aggregate gross interest expense of the Company and the Consolidated Subsidiaries for such period, whether paid or accrued, including (a) to the extent included in interest expense under GAAP:  (i) amortization of debt discount, (ii) capitalized interest, (iii) all commissions, discounts and other fees and charges owed with respect to letters of credit and bankers’ acceptance financing and net costs under Hedging Agreements in respect of interest rates to the extent such net costs are allocable to such period in accordance with GAAP, (iv) the

8

Credit Agreement


 

 

portion of any payments or accruals under capital leases (and imputed interest with respect to Sale and Leaseback Transactions) allocable to interest expense, plus the portion of any payments or accruals under Synthetic Leases allocable to interest expense whether or not the same constitutes interest expense under GAAP, and (v) financing fees (including arrangement, amendment and contract fees), debt issuance costs, commissions and expenses and, in each case, the amortization thereof); and (b) all cash dividend payments or other cash distributions in respect of any Disqualified Capital Stock or on any series of preferred equity of the Company or the Consolidated Subsidiaries.

Consolidated Leverage Ratio” means, as at the last day of any period, the ratio of (a) Consolidated Total Debt on such day to (b) Consolidated EBITDA for such period.

Consolidated Net Income” means, for any period, with respect to the Company and the Consolidated Subsidiaries, for any period, the aggregate of the net income (or loss) of the Company and the Consolidated Subsidiaries after allowances for taxes for such period determined on a consolidated basis in accordance with GAAP; provided that there shall be excluded from such net income (to the extent otherwise included therein) the following: (a) the net income of (i) any Person in which the Company or any Consolidated Subsidiary has an ownership interest (which interest does not cause the net income of such other Person to be consolidated with the net income of the Company and the Consolidated Subsidiaries in accordance with GAAP) and (ii) commencing with the fiscal quarter ending March 31, 2019, the Permitted JV, in the case of clauses (i) and (ii) above, except to the extent of the amount of dividends or distributions actually paid in cash (and including, in the case of the Permitted JV, the amount of cash distributions declared by the Permitted JV during such period but retained by the Permitted JV as an offset against capital contributions made by Expro-USA in such period in accordance with the terms of the Permitted JV LLC Agreement) during such period by such other Person or the Permitted JV, as the case may be, to the Company or to a Consolidated Subsidiary (other than the Permitted JV), as the case may be; (b) the net income (but not loss) during such period of any Consolidated Subsidiary to the extent that the declaration or payment of dividends or similar distributions or transfers or loans by that Consolidated Subsidiary is not at the time permitted by operation of the terms of its charter or any agreement, instrument or Governmental Requirement applicable to such Consolidated Subsidiary or is otherwise restricted or prohibited, in each case determined in accordance with GAAP (provided that, so long as the Permitted JV constitutes a Consolidated Subsidiary, the net income of the Permitted JV shall not be excluded pursuant to this clause (b) solely as a result of the conditions and requirements in respect of the payment of distributions pursuant to the Permitted JV LLC Agreement); (c) the net income (or deficit) of any Person accrued prior to the date it becomes a Consolidated Subsidiary or is merged into or consolidated with the Company or any of its Consolidated Subsidiaries; (d) any gains or losses attributable to writeups or writedowns of assets, including ceiling test writedowns; (e) any non-cash gains or losses or positive or negative adjustments under FASB ASC 815 as a result of changes in the fair market value of derivatives; and (f) any cancellation of debt income.

Consolidated Net Tangible Assets” means, at any date, (a) total assets of the Company and the Consolidated Subsidiaries determined on a consolidated basis in accordance with GAAP minus (b) the sum of (i) current liabilities (excluding short-term Indebtedness and the current portion of long-term Indebtedness) of the Company and the Consolidated Subsidiaries and (ii)

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Credit Agreement


 

 

goodwill and other intangible assets of the Company and the Consolidated Subsidiaries, in each case determined on a consolidated basis in accordance with GAAP, all as reflected in the consolidated financial statements of the Company most recently delivered to the Administrative Agent and the Lenders pursuant to Section 5.01(a) or 5.01(b), as applicable.  For purposes of this definition, the amount of any such assets and current liabilities of any Subsidiary that is not Wholly-Owned by the Company shall be included or deducted, as the case may be, only to the extent of the proportional Equity Interests directly or indirectly owned by the Company in such Subsidiary, provided that, in the case of any such liabilities, to the extent such liabilities are recourse to the Company or any other Subsidiary (or any of their Property), the full amount of such liabilities that are so recourse shall be deducted for purposes of this definition.

Consolidated Subsidiaries” means each Subsidiary of the Company (whether now existing or hereafter created or acquired) the financial statements of which shall be (or should have been) consolidated with the financial statements of the Company in accordance with GAAP.

Consolidated Total Assets” means, as of any date of determination, the amount that would in conformity with GAAP, be set forth opposite the caption “total assets” (or any like caption) on a consolidated balance sheet of the Company and the Consolidated Subsidiaries as of such date.

Consolidated Total Assets Ex-Canam” means, for any period, (a) Consolidated Total Assets minus (b) Excluded Canam Assets.

Consolidated Total Capitalization” means, at any date, the sum of (a) the consolidated shareholders’ equity of the Company and its Consolidated Subsidiaries at such date, determined on a consolidated basis in accordance with GAAP, plus (b) Consolidated Total Debt at such date.

Consolidated Total Debt” means, at any date, the aggregate principal amount of all Indebtedness of the Company and its Subsidiaries at such date (excluding undrawn letters of credit), determined on a consolidated basis in accordance with GAAP.

Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise.  “Controlling” and “Controlled” have meanings correlative thereto.

Credit Exposure” means, with respect to any Lender at any time, the sum of the outstanding principal amount of such Lender’s Revolving Loans and its LC Exposure at such time.

Credit Party” means the Administrative Agent, each Issuing Bank or any Lender.

Default” means any event or condition which constitutes an Event of Default or which upon notice, lapse of time or both would, unless cured or waived, become an Event of Default.

Defaulting Lender” means any Lender that (a) has failed, within two Business Days of the date required to be funded or paid, to (i) fund any portion of its Loans, (ii) fund any portion

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Credit Agreement


 

 

of its participations in Letters of Credit or (iii) pay over to any Credit Party any other amount required to be paid by it hereunder, unless, in the case of clause (i) above, such Lender notifies the Administrative Agent in writing that such failure is the result of such Lender’s good faith determination that a condition precedent to funding (specifically identified and including the particular default, if any) has not been satisfied, (b) has notified the Company or any Credit Party in writing, or has made a public statement to the effect, that it does not intend or expect to comply with any of its funding obligations under this Agreement (unless such writing or public statement indicates that such position is based on such Lender’s good faith determination that a condition precedent (specifically identified and including the particular default, if any) to funding a loan under this Agreement cannot be satisfied) or generally under other agreements in which it commits to extend credit, (c) has failed, within three Business Days after request by a Credit Party, acting in good faith, to provide a certification in writing from an authorized officer of such Lender that it will comply with its obligations (and is financially able to meet such obligations) to fund prospective Loans and participations in then outstanding Letters of Credit under this Agreement; provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (c) upon such Credit Party’s receipt of such certification in form and substance satisfactory to it and the Administrative Agent, or (d) has become the subject of (A) a Bankruptcy Event or (B) a Bail-In Action.

Deposit Account” has the meaning assigned to such term in the UCC.

Designated Currency” means Canadian Dollars, Pounds Sterling, Ringgit or any other currency agreed to by the Administrative Agent, the applicable Issuing Bank and the applicable Borrower.

Disposition” means with respect to any Property, any sale, lease, Sale and Leaseback Transaction, Casualty Event, assignment, conveyance, transfer or other disposition thereof (including by way of merger or consolidation).  The terms “Dispose” and “Disposed of” shall have correlative meanings.

Disqualified Capital Stock” means any Equity Interest that, by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) or upon the happening of any event, matures or is mandatorily redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock), pursuant to a sinking fund obligation or otherwise, or is convertible or exchangeable for Indebtedness or redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock) at the option of the holder thereof, in whole or in part, on or prior to the date that is 91 days after the earlier of (a) the Maturity Date and (b) the date on which there are no Loans, LC Exposure or other obligations hereunder outstanding and all of the Commitments are terminated.

Dividing Person” has the meaning assigned to it in the definition of “Division”.

Division” means the division of the assets, liabilities and/or obligations of a Person (the “Dividing Person”) among two or more Persons (whether pursuant to a “plan of division” or similar arrangement), which may or may not include the Dividing Person and pursuant to which the Dividing Person may or may not survive.

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Division Successor” means any Person that, upon the consummation of a Division of a Dividing Person, holds all or any portion of the assets, liabilities and/or obligations previously held by such Dividing Person immediately prior to the consummation of such Division. A Dividing Person which retains any of its assets, liabilities and/or obligations after a Division shall be deemed a Division Successor upon the occurrence of such Division.

 “Dollar Equivalent” means, as of any date of determination, with respect to any amount denominated in any Designated Currency, the equivalent amount thereof in dollars as determined by the Administrative Agent or the applicable Issuing Bank, as the case may be, on the basis of the Exchange Rate on such date for the purchase of dollars with such other Designated Currency.

dollars” or “$” refers to lawful money of the United States of America.

Domestic Liquidity” means, as of any date of determination, the sum of (a) the unused total Commitments on such date plus (b) the aggregate amount of Unrestricted Cash.

Domestic Subsidiary” means any Subsidiary that is organized under the laws of the United States of America or any state thereof or the District of Columbia.

EEA Financial Institution” means (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.

EEA Member Country” means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

EEA Resolution Authority” means any public administrative authority or any Person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

Effective Date” means the date on which the conditions specified in Section 4.01 are satisfied (or waived in accordance with Section 10.02).

Effective Date Canam Intercompany Note” means that certain Promissory Note, dated as of June 28, 2016, made by Canam and payable to the order of MOCL, in an original principal amount of $1,204,429,777.78.

Effective Date Canam Intercompany Obligations” means the outstanding “Principal Amount” under and as defined in the Effective Date Canam Intercompany Note.

Electronic Signature” means an electronic sound, symbol, or process attached to, or associated with, a contract or other record and adopted by a person with the intent to sign, authenticate or accept such contract or record.

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Electronic System” means any electronic system, including e-mail, e-fax, Intralinks®, ClearPar®, Debt Domain, Syndtrak and any other Internet or extranet-based site, whether such electronic system is owned, operated or hosted by the Administrative Agent and/or any Issuing Bank and any of its respective Related Persons or any other Person, providing for access to data protected by passcodes or other security system.

Environmental Laws” means all laws, rules, regulations, codes, ordinances, orders, decrees, judgments, injunctions, notices or binding agreements issued, promulgated or entered into by any Governmental Authority, relating in any way to the environment, preservation or reclamation of natural resources, the management, release or threatened release of any hazardous material, or to health and safety matters (solely as it relates to exposure to hazardous materials).

Environmental Liability” means any liability, contingent or otherwise (including any liability for damages, costs of environmental remediation, fines, penalties or indemnities), of the Company or any Subsidiary directly or indirectly resulting from (a) violation of any Environmental Law, (b) the generation, use, handling, transportation, storage, treatment or disposal of any Hazardous Materials, (c) exposure to any Hazardous Materials, (d) the release or threatened release of any Hazardous Materials into the environment or (e) any contract, agreement pursuant to which liability is assumed or imposed with respect to any of the foregoing.

Equity Interests” means shares of capital stock, partnership interests, membership interests in a limited liability company, beneficial interests in a trust or other equity ownership interests in a Person, and any warrants, options or other rights entitling the holder thereof to purchase or acquire any such Equity Interest.

ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time.

ERISA Affiliate” means any trade or business (whether or not incorporated) that, together with the Company, is treated as a single employer under Section 414(b) or (c) of the Code or, solely for purposes of Section 302 of ERISA and Section 412 of the Code, is treated as a single employer under Section 414 of the Code.

ERISA Event” means (a) any “reportable event”, as defined in Section 4043 of ERISA or the regulations issued thereunder with respect to a Plan (other than an event for which the 30‑day notice period is waived); (b) the failure of a Plan to meet the minimum funding standards under Section 412 of the Code or Section 302 of ERISA), whether or not waived; (c) the filing pursuant to Section 412 of the Code or Section 303 of ERISA of an application for a waiver of the minimum funding standard with respect to any Plan; (d) the incurrence by the Company or any of its ERISA Affiliates of any liability under Title IV of ERISA with respect to the termination of any Plan; (e) the receipt by the Company or any ERISA Affiliate from the PBGC or a plan administrator of any notice relating to an intention to terminate any Plan or Plans or to appoint a trustee to administer any Plan; (f) the incurrence by the Company or any of its ERISA Affiliates of any liability with respect to the withdrawal or partial withdrawal from any Plan or Multiemployer Plan; or (g) the receipt by the Company or any ERISA Affiliate of any notice, or the receipt by any Multiemployer Plan from the Company or any ERISA Affiliate of any notice,

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concerning the imposition of Withdrawal Liability or a determination that a Multiemployer Plan is, or is expected to be, insolvent or in reorganization, within the meaning of Title IV of ERISA.

EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor Person), as in effect from time to time.

Eurodollar”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Adjusted LIBO Rate.

Event of Default” has the meaning set forth in Section 7.01.

Exchange Rate” means on any day, for purposes of determining the Dollar Equivalent of any currency other than dollars, the rate at which such other currency may be exchanged into dollars at the time of determination on such day as set forth on the Reuters WRLD Page for such currency.  In the event that such rate does not appear on any Reuters WRLD Page, the Exchange Rate shall be determined by reference to such other publicly available service for displaying exchange rates as may be agreed upon by the Administrative Agent and the Company or, in the absence of such an agreement, such Exchange Rate shall instead be the arithmetic average of the spot rates of exchange of the Administrative Agent in the market where its foreign currency exchange operations in respect of such currency are then being conducted, at or about such time as the Administrative Agent shall elect after determining that such rates shall be the basis for determining the Exchange Rate, on such day for the purchase of dollars for delivery two Business Days later; provided that if at the time of any such determination, for any reason, no such spot rate is being quoted, the Administrative Agent may use any reasonable method it deems appropriate to determine such rate, and such determination shall be conclusive absent manifest error.

Excluded Canam Assets” means, for any period, the portion of the Consolidated Total Assets attributable to the Excluded Canam Entities.

Excluded Canam EBITDA” means, for any period, the portion of Consolidated EBITDA attributable to the Excluded Canam Entities.

Excluded Canam Entities” means the collective reference to (a) Canam, (b) Canam Brunei Oil Ltd., Murphy Peninsular Maylasia Oil Co., Ltd., Murphy Sabah Oil Co., Ltd., Murphy Sarawak Oil Co., Ltd. and each other direct and indirect subsidiary of Canam that is directly engaged in exploration and production and other related operations in Malaysia and (c) Murphy Cuu Long Tay Oil Co., Ltd. (formerly known as Murphy Semai Oil Co., Ltd.).

Excluded DDA” means (a) zero balance disbursement accounts and (b) segregated Deposit Accounts, the balance of which consists exclusively of (i) funds due and owing in the ordinary course of business to unaffiliated third parties in connection with Company’s and its Subsidiaries’ royalty payment obligations to such third parties, (ii) payroll, healthcare and other employee wage and benefit accounts, (iii) tax accounts, including, without limitation, sales tax accounts and (iv) escrow, defeasance and redemption accounts.

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Excluded Guaranteed Hedging Obligation” means, shall mean, with respect to any Subsidiary Guarantor, any Guaranteed Hedging Obligation if, and to the extent that, all or a portion of the liability of such Subsidiary Guarantor with respect to, or the grant by such Subsidiary Guarantor of a security interest to secure, such Guaranteed Hedging Obligation (or any Guarantee thereof or other agreement or undertaking agreeing to guarantee, repay, indemnify or otherwise be liable therefor) is or becomes illegal under the Commodity Exchange Act or any rule, regulation or order of the Commodity Futures Trading Commission (or the application or official interpretation of any thereof) (a) by virtue of such Subsidiary Guarantor’s failure for any reason to constitute an “eligible contract participant” as defined in the Commodity Exchange Act and the regulations thereunder at the time the guarantee obligation or other liability of such Subsidiary Guarantor or the grant of such security interest becomes or would become effective with respect to such Guaranteed Hedging Obligation or (b) in the case of a Guaranteed Hedging Obligation subject to a clearing requirement pursuant to section 2(h) of the Commodity Exchange Act (or any successor provision thereto), because such Subsidiary Guarantor is a “financial entity,” as defined in section 2(h)(7)(C)(i) of the Commodity Exchange Act (or any successor provision thereto), at the time the guarantee obligation or other liability of such Subsidiary Guarantor becomes or would become effective with respect to such related Guaranteed Hedging Obligation.  If a Guaranteed Hedging Obligation arises under a master agreement governing more than one swap, such exclusion shall apply only to the portion of such Guaranteed Hedging Obligation that is attributable to swaps for which such guarantee obligation or other liability or security interest is or becomes illegal.

Excluded MOCL EBITDA” means, for any period, the portion of Consolidated EBITDA attributable to the Excluded MOCL Entities.

Excluded MOCL Entities” means the collective reference to MOCL and each of its direct and indirect subsidiaries.

Excluded Taxes” means any of the following Taxes imposed on or with respect to a Recipient or required to be withheld or deducted from a payment to a Recipient, (a) Taxes imposed on or measured by net income (however denominated), franchise Taxes, and branch profits Taxes, in each case, (i) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its applicable lending office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes, (b) in the case of a Lender, U.S. federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in a Loan, Letter of Credit or Commitment pursuant to a law in effect on the date on which (i) such Lender acquires such interest in the Loan, Letter of Credit or Commitment (other than pursuant to an assignment request by the Company under Section 2.18(b)) or (ii) such Lender changes its lending office, except in each case to the extent that, pursuant to Section 2.16, amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its lending office, (c) Taxes attributable to such Recipient’s failure to comply with Section 2.16(f), and (d) any U.S. federal withholding Taxes imposed under FATCA.

Existing Credit Agreement” means that certain 5-Year Revolving Credit Agreement dated as of August 10, 2016 among the Company, Expro-Intl. and MOCL, as borrowers,

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JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and agents party thereto, as amended, amended and restated, supplemented or otherwise modified from time to time.

Existing Notes” means, collectively, (a) the 4.000% Notes due 2022, issued by the Company pursuant to the first supplement to the 2012 Indenture, (b) the 3.700% Notes due 2022, issued by the Company pursuant to the second supplement to the 2012 Indenture, (c) the 6.875% Notes due 2024, issued by the Company pursuant to the third supplement to the 2012 Indenture, (d) the 5.750% Notes due 2025, issued by the Company pursuant to the fourth supplement to the 2012 Indenture, (e) the 7.050% Notes due 2029, issued by the Company pursuant to the first supplement to the 1999 Indenture and (f) the 5.125% Notes due 2042, issued by the Company pursuant to the second supplement to the 2012 Indenture, in each case outstanding as of the Effective Date.

Expro-Intl.” has the meaning assigned to such term in the preliminary paragraph of this Agreement.

Expro-USA” means Murphy Exploration & Production Company – USA, a Delaware corporation.

Farm-In Agreement” shall mean an agreement whereby a Person agrees, among other things, to pay all or a share of the drilling, completion or other expenses of one or more wells or perform the drilling, completion or other operation on such well or wells as all or a part of the consideration provided in exchange for an ownership interest in an Oil and Gas Property.

Farm-Out Agreement” shall mean a Farm-In Agreement, viewed from the standpoint of the party that grants to another party the right to earn an ownership interest in an Oil and Gas Property.

FATCA” means Sections 1471 through 1474 of the Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof and any agreement entered into pursuant to Section 1471(b)(1) of the Code.

Federal Funds Effective Rate” means, for any day, the rate calculated by the NY FRB based on such day’s federal funds transactions by depositary institutions, as determined in such manner as the NYFRB shall set forth on its public website from time to time, and published on the next succeeding Business Day by the NYFRB as the federal funds effective rate.

Fee Letter” means each of (a) that certain Fee Letter dated as of November 1, 2018, by and among the Company and JPMorgan Chase Bank, N.A. and (b) that certain Fee Letter dated as of November 1, 2018 by and among the Company, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Bank of America, N.A., DNB Markets, Inc., DNB Capital LLC, Wells Fargo Securities, LLC, Wells Fargo Bank, National Association, MUFG Bank, Ltd. and The Bank of Nova Scotia.

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Financial Covenant” means (a) prior to the Investment Grade Rating Date, each of the Consolidated Leverage Ratio covenant set forth in Section 6.14(a)(i) and the Consolidated Interest Coverage Ratio covenant set forth in Section 6.14(a)(ii) and (b) from and after the Investment Grade Rating Date, the ratio of Consolidated Total Debt to Consolidated Total Capitalization covenant set forth in Section 6.14(b).

Financial Officer” means, with respect to any Person, the chief financial officer, principal accounting officer, treasurer or controller of such Person.  The term “Financial Officer” without reference to a Person shall mean a Financial Officer of the Company.

Fitch” means Fitch Ratings Inc.

Foreign Lender” means a Lender that is not a U.S. Person.

Foreign Subsidiary” means any Subsidiary of the Company other than a Domestic Subsidiary.

GAAP” means generally accepted accounting principles in the United States of America.

Governmental Authority” means the government of the United States of America, any other nation or any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government.

Governmental Requirement” means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, rules of common law, authorization or other directive or requirement, whether now or hereinafter in effect, of any Governmental Authority.

Guarantee” of or by any Person (the “guarantor”) means any obligation, contingent or otherwise, of the guarantor guaranteeing or having the economic effect of guaranteeing any Indebtedness or other obligation of any other Person (the “primary obligor”) in any manner, whether directly or indirectly, and including any obligation of the guarantor, direct or indirect, (a) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or other obligation or to purchase (or to advance or supply funds for the purchase of) any security for the payment thereof, (b) to purchase or lease property, securities or services for the purpose of assuring the owner of such Indebtedness or other obligation of the payment thereof, (c) to maintain working capital, equity capital or any other financial statement condition or liquidity of the primary obligor so as to enable the primary obligor to pay such Indebtedness or other obligation or (d) as an account party in respect of any letter of credit or letter of guaranty issued to support such Indebtedness or obligation; provided that the term Guarantee shall not include endorsements for collection or deposit in the ordinary course of business.  The term “Guarantee” when used as a verb to refer to the act of guaranteeing any Indebtedness or other obligations of a Person (for example, as such term is used in the phrase “no Subsidiary shall Guarantee any Indebtedness”) has a correlative meaning thereto.

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Guaranteed Cash Management Agreement” means any Cash Management Agreement between any Borrower or any Subsidiary and any Person that entered into such Cash Management Agreement prior to the time, or during the time, that such Person was, a Lender or an Affiliate of a Lender (including any such Cash Management Agreement in existence prior to the Effective Date), even if such Person subsequently ceases to be a Lender (or an Affiliate of a Lender) for any reason (any such Person, a “Guaranteed Cash Management Provider”); provided that, for the avoidance of doubt, the term “Guaranteed Cash Management Agreement” shall not include any Cash Management Agreement or transactions under any Cash Management Agreement entered into after the time that such Guaranteed Cash Management Provider ceases to be a Lender or an Affiliate of a Lender.

Guaranteed Cash Management Obligations” means any and all amounts and other obligations owing by any Borrower or any Subsidiary to any Guaranteed Cash Management Provider under any Guaranteed Cash Management Agreement (whether absolute or contingent and howsoever and whensoever created, arising, evidenced or acquired (including all renewals, extensions and modifications thereof and substitutions therefor)).

Guaranteed Cash Management Provider” has the meaning assigned to such term in the definition of Guaranteed Cash Management Agreement.

Guaranteed Hedging Agreement” means any Hedging Agreement between any Borrower or any Subsidiary and any Person that entered into such Hedging Agreement prior to the time, or during the time, that such Person was, a Lender or an Affiliate of a Lender (including any such Hedging Agreement in existence prior to the Effective Date), even if such Person subsequently ceases to be a Lender (or an Affiliate of a Lender) for any reason (any such Person, a “Guaranteed Hedging Party”); provided that, for the avoidance of doubt, the term “Guaranteed Hedging Agreement” shall not include any Hedging Agreement or transactions under any Hedging Agreement entered into after the time that such Guaranteed Hedging Party ceases to be a Lender or an Affiliate of a Lender.

Guaranteed Hedging Obligations” means any and all amounts and other obligations owing to any Guaranteed Hedging Party under any and all Guaranteed Hedging Agreement (whether absolute or contingent and howsoever and whensoever created, arising, evidenced or acquired (including all renewals, extensions and modifications thereof and substitutions therefor)); provided that the Guaranteed Hedging Obligations shall not, in any event, include any Excluded Guaranteed Hedging Obligation.

Guaranteed Hedging Party” has the meaning assigned to such term in the definition of Guaranteed Hedging Agreement.

Guaranteed Parties” means, collectively, the Administrative Agent, the Lenders, the Issuing Banks, the Guaranteed Cash Management Providers and the Guaranteed Hedging Parties, and “Guaranteed Party” means any of them individually.

Guarantors” means (a) the Company and (b) each Subsidiary that is a party to a Guaranty Agreement as a “Guarantor” (as such term is defined in such Guaranty) and guarantees the Obligations (including pursuant to Section 4.01 and Section 5.12). 

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Guaranty Agreement” means (a) in the case of the Company, each Domestic Subsidiary and each Canadian Subsidiary, the Guaranty Agreement executed by the Guarantors in substantially the form of Exhibit E, and (b) in the case of any Foreign Subsidiary other than a Canadian Subsidiary, a guaranty agreement, in form and substance satisfactory to the Administrative Agent (in each case, with such changes thereto as determined by the Administrative Agent as shall be advisable under the laws of the jurisdiction in which such Person is organized or in which its assets are located), unconditionally guarantying, on a joint and several basis, payment of the Obligations, as the same may be amended, modified or supplemented from time to time.

Hazardous Materials” means all explosive or radioactive substances or wastes and all hazardous or toxic substances, wastes or other pollutants, including petroleum or petroleum distillates, asbestos or asbestos containing materials, polychlorinated biphenyls, radon gas, infectious or medical wastes and all other substances or wastes of any nature regulated as “hazardous” or “toxic” or words of similar import pursuant to any Environmental Law.

Hedging Agreement” means any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions (including any agreement, contract or transaction that constitutes a “swap” within the meaning of section 1a(47) of the Commodity Exchange Act); provided that (i) no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of the Company or any of its Subsidiaries or (ii) no agreement for the physical purchase and sale of any commodity shall be a “Hedging Agreement”.

Hydrocarbon Interests” means all rights, titles, interests and estates now or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, including any reserved or residual interests of whatever nature.  Unless otherwise indicated herein, each reference to the term “Hydrocarbon Interests” shall mean Hydrocarbon Interests of the Company and/or its Subsidiaries, as the context requires.

Hydrocarbons” means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all products refined or separated therefrom.

Impacted Interest Period” has the meaning assigned to it in the definition of “LIBO Rate.”

Indebtedness” of any Person means, without duplication, (a) all obligations of such Person for borrowed money or with respect to deposits or advances of any kind, (b) all obligations of such Person evidenced by or pursuant to bonds, debentures, notes, bankers’ acceptances, or other similar instruments, (c) all obligations of such Person under conditional sale or other title retention agreements relating to property acquired by such Person, (d) all

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obligations of such Person to pay the deferred purchase price of property or services (excluding those from time to time incurred in the ordinary course of business which are not greater than 60 days past the date of invoice or delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP), (e) all Capital Lease Obligations of such Person, (f) all obligations of such Person under Synthetic Leases, (g) all obligations, contingent or otherwise, of such Person as account party under all letters of credit and letters of guaranty, and including, for the avoidance of doubt, all reimbursement obligations of such Person in respect of surety bonds and similar instruments issued for the account of such Person, (h) all Indebtedness of others secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien on property owned or acquired by such Person, whether or not the Indebtedness secured thereby has been assumed, but limited to the fair market value of the property securing such obligations, (i) all Guarantees by such Person of Indebtedness (as defined in other clauses of this definition) of others, (j) all obligations of such Person to deliver commodities, goods or services, including, without limitation, Hydrocarbons, in consideration of one or more advance payments, other than gas balancing arrangements in the ordinary course of business, (k) the undischarged balance of any production payment created by such Person or for the creation of which such Person directly or indirectly received payment, and (l) all obligations of such Person in respect of Disqualified Capital Stock; provided that notwithstanding the foregoing, Indebtedness shall exclude (i) the contractual carry of a portion of the development costs of Athabasca Oil Corporation’s interest in the Kaybob Duvernay lands in an aggregate amount not to exceed $171,000,000, (ii) the obligations of Expro-USA to make capital contributions to the Permitted JV under Section 4.4(e) of the Permitted JV LLC Agreement and (iii) unsecured contingent obligations under surety bonds and similar instruments issued for the account of the Company or any Subsidiary so long as (A) no Subsidiary is liable for any reimbursement or other payment obligations in respect thereof and (B) such obligations are not subject to any Guarantee or other form of credit support by any Subsidiary.

Incorporated Provision” has the meaning assigned to such term in Section 5.16(b).

Indemnified Taxes” means (a) Taxes, other than Excluded Taxes, imposed on or with respect to any payment made by or on account of any obligation of any Loan Party under this Agreement or any other Loan Document and (b) to the extent not otherwise described in (a) hereof, Other Taxes.

Indemnitee” has the meaning set forth in Section 10.03(b).

Index Debt” means senior, unsecured, long-term indebtedness for borrowed money of the Company that is not guaranteed by any other Person or subject to any other credit enhancement.

Ineligible Institution” has the meaning assigned to it in Section 10.04(b).

Information Memorandum” means the Confidential Information Memorandum dated November 1, 2018 relating to the Borrowers and the Transactions.

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Interest Election Request” means a request by the Company on behalf of itself, Expro-Intl. or MOCL to convert or continue a Revolving Borrowing in accordance with Section 2.07.

Interest Payment Date” means (a) with respect to any ABR Loan, the last day of each March, June, September and December, and (b) with respect to any Eurodollar Loan, the last day of the Interest Period applicable to the Borrowing of which such Loan is a part and, in the case of a Eurodollar Borrowing with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period.

Interest Period” means with respect to any Eurodollar Borrowing, the period commencing on the date of such Borrowing and ending on the numerically corresponding day in the calendar month that is one, two, three or six months or, to the extent that funds are available, as determined by each Lender, in its sole discretion, 12 months thereafter, as the Company may elect; provided that (a) if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless, in the case of a Eurodollar Borrowing only, such next succeeding Business Day would fall in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day and (b) any Interest Period pertaining to a Eurodollar Borrowing that commences on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the last calendar month of such Interest Period) shall end on the last Business Day of the last calendar month of such Interest Period.  For purposes hereof, the date of a Borrowing initially shall be the date on which such Borrowing is made and, in the case of a Revolving Borrowing, thereafter shall be the effective date of the most recent conversion or continuation of such Borrowing.

Interpolated Rate” means, at any time, for any Interest Period, the rate per annum (rounded to the same number of decimal places as the LIBO Screen Rate) determined by the Administrative Agent (which determination shall be conclusive and binding absent manifest error) to be equal to the rate that results from interpolating on a linear basis between: (a) the LIBO Screen Rate for the longest period for which the LIBO Screen Rate is available) that is shorter than the Impacted Interest Period; and (b) the LIBO Screen Rate for the shortest period (for which that LIBO Screen Rate is available) that exceeds the Impacted Interest Period, in each case, at such time.

Investment” means, as applied to any Person, any direct or indirect (a) acquisition (whether for cash, Property, services or securities or otherwise, and including pursuant to any merger or consolidation with any Person) by such Person of Equity Interests in any other Person, (b) capital contribution or other investment by such Person to or in any other Person, (c) loan or advance made by such Person to any other Person, (d) assumption, purchase or other acquisition by such Person of any Indebtedness of any other Person, (e) Guarantee by such Person of Indebtedness of any other Person, or (f) purchase or other acquisition (in one transaction or a series of transactions) by such Person of any assets of any other Person constituting a business unit.

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Investment Grade Rating” means (a) a rating established by S&P for the Index Debt of BBB- or higher; (b) a rating established by Moody’s for the Index Debt of Baa3 or higher; or (c) a rating established by Fitch for the Index Debt of BBB- or higher.

Investment Grade Rating Date” means the first date on which the Company obtains either (a) an Investment Grade Rating from two or more Rating Agencies; or (b) an Investment Grade Rating from one Rating Agency and a rating of One Notch Below Investment Grade from the other two Rating Agencies.

IRS” means the United States Internal Revenue Service.

Issuing Bank” means (a) each of (i) JPMorgan Chase Bank, N.A., (ii) Bank of America, N.A., (iii) DNB Bank ASA, New York Branch, (iv) Wells Fargo Bank, National Association, (v) MUFG Bank, Ltd., (vi) The Bank of Nova Scotia and (vii) Regions Bank and (b) any other Lender acceptable to the Administrative Agent and the Company that has agreed in its sole discretion to become an Issuing Bank hereunder pursuant to documentation in form and substance reasonably satisfactory to the Administrative Agent, in each case, in its capacity as an issuer of Letters of Credit hereunder, and its successors in such capacity as provided in Section 2.05(i).  Any Issuing Bank may, in its discretion, arrange for one or more Letters of Credit to be issued by Affiliates of such Issuing Bank, in which case the term “Issuing Bank” shall include any such Affiliate with respect to Letters of Credit issued by such Affiliate.  Each reference herein to the “Issuing Bank’ shall be deemed to be a reference to the relevant Issuing Bank.

Junior Indebtedness” means, collectively, (a) each of the Existing Notes, (b) any Indebtedness that is incurred in exchange for, or the proceeds of which are used to extend, refinance, replace, defease, discharge, refund or otherwise retire for value any Existing Notes and (c) any Indebtedness that is subordinated in right of payment to the Obligations.

LC Disbursement” means a payment made by an Issuing Bank pursuant to a Letter of Credit issued by such Issuing Bank.

LC Exposure” means, at any time, the sum of (a) the aggregate undrawn amount of all outstanding Letters of Credit at such time plus (b) the aggregate amount of all LC Disbursements that have not yet been reimbursed by or on behalf of the Borrowers at such time. The LC Exposure of any Lender at any time shall be its Applicable Percentage of the total LC Exposure at such time. The LC Exposure of any Issuing Bank at any time shall be the sum of (a) the aggregate undrawn amount of all outstanding Letters of Credit issued by such Issuing Bank at such time plus (b) the aggregate amount of all LC Disbursements made by such Issuing Bank that have not yet been reimbursed by or on behalf of the Borrowers at such time.  With respect to any Letter of Credit that by its terms provides for one or more automatic increases in the stated amount thereof, the amount of such Letter of Credit shall be deemed to be the maximum stated amount of such Letter of Credit after giving effect to all such increases, whether or not such maximum stated amount is in effect at such time.  Except as expressly provided in the last sentence of Section 2.11(d), for the purpose of determining LC Exposure hereunder, the undrawn amount of any Letter of Credit denominated in a Designated Currency or the amount of any unreimbursed LC Disbursement in respect of any Letter of Credit denominated in a Designated

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Currency shall, as of any date, be determined by reference to the Dollar Equivalent of such amount as of the most recent Computation Date pursuant to Section 1.05.

Lead Arrangers” means JPMorgan Chase Bank, N.A., Merrill Lynch, Pierce, Fenner & Smith Incorporated (or any other registered broker-dealer wholly-owned by Bank of America Corporation to which all or substantially all of Bank of America Corporation’s or any of its subsidiaries’ investment banking, commercial lending services or related businesses may be transferred following the Effective Date), DNB Markets, Inc., Wells Fargo Securities, LLC, MUFG Bank, Ltd., The Bank of Nova Scotia and Regions Bank, in their respective capacities as co-lead arrangers and joint bookrunners hereunder.

Lenders” means the Persons listed on Schedule 2.01 and any other Person that shall have become a party hereto pursuant to an Assignment and Assumption, other than any such Person that ceases to be a party hereto pursuant to an Assignment and Assumption.  Unless the context otherwise requires, the term “Lenders” includes the Issuing Banks.

Letter of Credit” means any letter of credit issued pursuant to this Agreement.  The term “Letter of Credit” shall also include any bank guarantee issued pursuant to this Agreement that is denominated in a Designated Currency, to the extent the applicable Issuing Bank agrees, in its sole discretion, to issue such bank guarantee.

Letter of Credit Commitment” means, with respect to each Issuing Bank, the commitment of such Issuing Bank to issue Letters of Credit hereunder. The initial amount of the Letter of Credit Commitment (a) for each of (i) JPMorgan Chase Bank, N.A., (ii) Bank of America, N.A., (iii) DNB Bank ASA, New York Branch, (iv) Wells Fargo Bank, National Association, (v) MUFG Bank, Ltd., (vi) The Bank of Nova Scotia and (vii) Regions Bank, is $30,000,000, and (b) for any other Lender that is an Issuing Bank, is the amount agreed to in writing by such Issuing Bank as its Letter of Credit Commitment hereunder; or if an Issuing Bank has entered into an Assignment and Assumption, the amount set forth for such Issuing Bank as its Letter of Credit Commitment in the Register maintained by the Administrative Agent; provided that the total Letter of Credit Commitments shall not exceed $250,000,000.

LIBO Rate” means, with respect to any Eurodollar Borrowing for any Interest Period, the London interbank offered rate as administered by ICE Benchmark Administration (or any other Person that takes over the administration of such rate for U.S. Dollars for a period equal in length to such Interest Period as displayed on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate (or, in the event such rate does not appear on a Reuters page or screen, on any successor or substitute page on such screen that displays such rate, or on the appropriate page of such other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion; in each case the “LIBO Screen Rate”) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period; provided that if the LIBO Screen Rate shall be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement; provided,  further, that if the LIBO Screen Rate shall not be available at such time for such Interest Period (an “Impacted Interest Period”) then the LIBO Rate shall be the Interpolated Rate; provided,  further, that if any Interpolated Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.

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Leverage Ratio Ex-MOCL” means, as of the last day of any fiscal quarter, the ratio of (a) Consolidated Total Debt on such day to (b) Consolidated EBITDA Ex-MOCL for the period of four consecutive fiscal quarters ending on such day.

LIBO Screen Rate” has the meaning assigned to it in the definition of “LIBO Rate.”

Lien” means, with respect to any asset, (a) any mortgage, deed of trust, lien, pledge, hypothecation, encumbrance, charge or security interest in, on or of such asset, (b) the interest of a vendor or a lessor under any conditional sale agreement, capital lease or title retention agreement (or any financing lease having substantially the same economic effect as any of the foregoing) relating to such asset and (c) in the case of securities, any purchase option, call or similar right of a third party with respect to such securities.

Liquidate” means, with respect to any Hedging Agreement, (a) the sale, assignment, novation, unwind or termination of all or any part of such Hedging Agreement or (b) the creation of an offsetting position against all or any part of such Hedging Agreement.  The terms “Liquidated” and “Liquidation” have correlative meanings thereto.

Loan Documents” means this Agreement, including schedules and exhibits hereto, each Letter of Credit and any applications or agreements relating thereto, any promissory notes issued by the Borrowers under this Agreement, each Guaranty Agreement, each Fee Letter, any certificate required to be delivered under this Agreement or any other Loan Document by or on behalf of the Company or any of the Subsidiaries, and any agreements entered into in connection herewith by any Borrower or any other Loan Party with or in favor of the Administrative Agent and/or the Lenders, including any amendments, modifications or supplements thereto or waivers thereof, and any other documents prepared in connection with the other Loan Documents, if any.

Loan Parties” means each Borrower and each Guarantor.

Loans” means the loans made by the Lenders to a Borrower pursuant to this Agreement.

Material Adverse Effect” means a material adverse effect on (a) the business, assets, operations, or condition, financial or otherwise, of the Company and its Subsidiaries taken as a whole, (b) the ability of the Loan Parties to perform any of their obligations under this Agreement or any other Loan Document or (c) the rights of or benefits available to the Lenders under this Agreement or any other Loan Document.

Material Indebtedness” means Indebtedness (other than the Loans, Letters of Credit and any Project Financing), or obligations in respect of one or more Hedging Agreements, of any one or more of the Company and its Subsidiaries in an aggregate principal amount exceeding $75,000,000.  For purposes of determining Material Indebtedness, the “principal amount” of the obligations of the Company or any Subsidiary in respect of any Hedging Agreement at any time shall be the maximum aggregate amount (giving effect to any netting agreements) that the Company or such Subsidiary would be required to pay if such Hedging Agreement were terminated at such time.

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Material Subsidiary” means, (a) Expro-USA, (b) Expro-Intl., (c) MOCL, (d) Murphy Exploration & Production Company, (e) Canam and (f) as of any date of determination, any other Subsidiary which, as of the most recent fiscal quarter of the Company, for the period of four consecutive fiscal quarters then ended for which financial statements have been delivered pursuant to Section 5.01(a) or Section 5.01(b), contributed greater than (i) five percent of Consolidated EBITDA for such period or (ii) five percent of Consolidated Total Assets as of the last day of such period; provided that, if at any time the aggregate amount of Consolidated EBITDA or Consolidated Total Assets attributable to all Subsidiaries that are not Material Subsidiaries exceeds ten percent of Consolidated EBITDA for any such period or ten percent of Consolidated Total Assets as of the last day of any such fiscal quarter, then the Company shall, pursuant to Section 5.01(d), designate in the Compliance Certificate required to be delivered for such fiscal quarter or fiscal year, as applicable, sufficient Subsidiaries as “Material Subsidiaries” to eliminate such excess, and upon the delivery of such Compliance Certificate to the Administrative Agent, such designated Subsidiaries shall for all purposes of this Agreement constitute Material Subsidiaries. In the event the Company fails to so designate sufficient additional Subsidiaries as “Material Subsidiaries” in the Compliance Certificate as aforesaid, the Administrative Agent may, by written notice to the Company, designate sufficient additional Subsidiaries as “Material Subsidiaries” on the Company’s behalf, whereupon such Subsidiaries shall constitute “Material Subsidiaries” for all purposes of this Agreement.

Maturity Date” means November 28, 2023; provided that if such date is not a Business Day, then the “Maturity Date” shall be the Business Day immediately preceding such date.

Maximum Rate” has the meaning set forth in Section 10.12.

MOCL” has the meaning assigned to such term in the preliminary paragraph of this Agreement.

MOCL Guarantee Trigger Event” means the occurrence of any of the following events: (i) the Total Credit Exposure (excluding any LC Exposure) exceeds $650,000,000 at any time (provided that no such MOCL Guarantee Trigger Event shall occur pursuant to this clause (i) to the extent that all outstanding Total Credit Exposure (excluding any LC Exposure) is attributable to Borrowings made to MOCL) or (ii) the Leverage Ratio Ex-MOCL as of the last day of any fiscal quarter exceeds 4.00 to 1.00.

Moody’s” means Moody’s Investors Service, a division of Moody’s Corporation.

Multiemployer Plan” means a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

Murphy Exploration & Production Company” means Murphy Exploration & Production Company, a Delaware corporation

Murphy Family” means (a) the C.H. Murphy Family Investments Limited Partnership, (b) the Estate of C.H. Murphy, Jr., and (c) siblings of the late C.H. Murphy, Jr. and his and their respective Immediate Family.  For purposes of this definition, “Immediate Family” of a person

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means such person’s spouse, children, siblings, mother-in-law and father-in-law, sons-in-law, daughters-in-law, brothers-in-law and sisters-in-law.

New Lender” has the meaning assigned to such term in Section 2.20(a).  

Non-Defaulting Lender” has the meaning set forth in Section 2.17(f).

Notice of Commitment Increase” has the meaning assigned to such term in Section 2.20(b).  

NYFRB” means the Federal Reserve Bank of New York.

NYFRB Rate” means, for any day, the greater of (a) the Federal Funds Effective Rate in effect on such day and (b) the Overnight Bank Funding Rate in effect on such day (or for any day that is not a Business Day, for the immediately preceding Business Day); provided that if none of such rates are published for any day that is a Business Day, the term “NYFRB Rate” means the rate for a federal funds transaction quoted at 11:00 a.m. on such day received by the Administrative Agent from a federal funds broker of recognized standing selected by it; provided,  further, that if any of the aforesaid rates shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.

Obligations” means (a) any and all amounts owing or to be owing by any Borrower, any Subsidiary or any Guarantor (whether direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising) to the Administrative Agent, the Issuing Banks, any Lender or any Related Party of any of the foregoing under any Loan Document; (b) all Guaranteed Hedging Obligations; (c) all Guaranteed Cash Management Obligations; and (d) all renewals, extensions and/or rearrangements of any of the above.  Without limitation of the foregoing, the term “Obligations” shall include the unpaid principal of and interest on the Loans and the LC Exposure (including, without limitation, interest accruing at the then applicable rate provided in this Agreement after the maturity of the Loans and LC Exposure and interest accruing at the then applicable rate provided in this Agreement after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, relating to any Borrower or any of its Subsidiaries or any Guarantor, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding), reimbursement obligations (including, without limitation, to reimburse LC Disbursements), obligations to post cash collateral in respect of Letters of Credit, payments in respect of an early termination of Guaranteed Hedging Obligations and unpaid amounts, fees, expenses, indemnities, costs, and all other obligations and liabilities of every nature of any Borrower, any Subsidiary or any Guarantor, whether absolute or contingent, due or to become due, now existing or hereafter arising under this Agreement, the other Loan Documents, any Guaranteed Hedging Agreement or any Guaranteed Cash Management Agreement; provided that the definition of Obligation shall exclude any Excluded Guaranteed Hedging Obligation.

Oil and Gas Properties” means (a) Hydrocarbon Interests; (b) the Properties now or hereafter pooled or unitized with Hydrocarbon Interests; (c) all presently existing or future unitization, pooling agreements and declarations of pooled units and the units created thereby (including without limitation all units created under orders, regulations and rules of any

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Governmental Authority) which may affect all or any portion of the Hydrocarbon Interests; (d) all operating agreements, contracts and other agreements, including production sharing contracts and agreements, which relate to any of the Hydrocarbon Interests or the production, sale, purchase, exchange or processing of Hydrocarbons from or attributable to such Hydrocarbon Interests; (e) all Hydrocarbons in and under and which may be produced and saved or attributable to the Hydrocarbon Interests, including all oil in tanks, and all rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the Hydrocarbon Interests; (f) all tenements, hereditaments, appurtenances and Properties in any manner appertaining, belonging, affixed or incidental to the Hydrocarbon Interests; and (g) all Properties, rights, titles, interests and estates described or referred to above, including any and all Property, real or personal, now owned or hereinafter acquired and situated upon, used, held for use or useful in connection with the operating, working or development of any of such Hydrocarbon Interests or Property (excluding drilling rigs, automotive equipment, rental equipment or other personal Property which may be on such premises for the purpose of drilling a well or for other similar temporary uses) and including any and all oil wells, gas wells, injection wells or other wells, buildings, structures, fuel separators, liquid extraction plants, plant compressors, pumps, pumping units, field gathering systems, tanks and tank batteries, fixtures, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, equipment, appliances, tools, implements, cables, wires, towers, casing, tubing and rods, surface leases, rights-of-way, easements and servitudes together with all additions, substitutions, replacements, accessions and attachments to any and all of the foregoing.  Unless otherwise indicated herein, each reference to the term “Oil and Gas Properties” shall mean Oil and Gas Properties of the Company and/or its Subsidiaries, as the context requires.

One Notch Below Investment Grade” means (a) a rating established by S&P for the Index Debt of BB+; (b) a rating established by Moody’s for the Index Debt of Ba1; or (c) a rating established by Fitch for the Index Debt of BB+.

Other Connection Taxes” means, with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to, enforced this Agreement or any other Loan Document, or sold or assigned an interest in any Loan, Letter of Credit or this Agreement or any other Loan Document).

Other Debt Agreement” means any agreement, instrument or other document governing any Indebtedness for borrowed money of the Company or any Subsidiary (other than intercompany Indebtedness) in an aggregate principal amount exceeding $20,000,000 (with committed but unutilized amounts under such Other Debt Agreement being deemed fully drawn for purposes of measuring such threshold).

Other Taxes” means all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, this Agreement or any other Loan Document, except

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any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment made pursuant to Section 2.18).

Overnight Bank Funding Rate” means, for any day, the rate comprised of both overnight federal funds and overnight Eurodollar borrowings by U.S.-managed banking offices of depository institutions, as such composite rate shall be determined by the NYFRB as set forth on its public website from time to time, and published on the next succeeding Business Day by the NYFRB as an overnight bank funding rate (from and after such date as the NYFRB shall commence to publish such composite rate).

Participant” has the meaning set forth in Section 10.04(c).

Participant Register” has the meaning assigned to such term in Section 10.04(c).

Patriot Act” means the USA PATRIOT Act of 2001, Title III of Pub. L. 107-56 (signed into law October 26, 2001).

PBGC” means the Pension Benefit Guaranty Corporation referred to and defined in ERISA and any successor entity performing similar functions.

Permitted Encumbrances” means:

(a)    Liens for taxes, assessments or governmental charges or claims not yet overdue for a period of more than 30 days or that are being contested in good faith and by appropriate proceedings for which appropriate reserves have been established to the extent required by and in accordance with GAAP (or in the case of any Foreign Subsidiary, the comparable accounting principles in the relevant jurisdiction), or for property taxes on property that the Company or any Subsidiary has determined to abandon if the sole recourse for such tax, assessment, charge or claim is to such property;

(b)    Liens in respect of property or assets of the Company or any of the Subsidiaries imposed by law, such as landlords’, sublandlords’, vendors’, suppliers’, carriers’, warehousemen’s, repairmen’s, construction contractors’, workers’ and mechanics’ Liens and other similar Liens arising in the ordinary course of business or incident to the exploration, development, operation or maintenance of Oil and Gas Properties, in each case so long as such Liens arise in the ordinary course of business and secure obligations that are not overdue by more than 60 days or which are being contested in good faith by appropriate proceedings;

(c)    pledges and deposits made in the ordinary course of business in compliance with workers’ compensation, unemployment insurance and other social security laws or regulations;

(d)    deposits to secure the performance of bids, trade contracts, leases, statutory obligations, surety and appeal bonds, performance bonds and other obligations of a like nature, in each case in the ordinary course of business;

(e)    easements, rights-of-way, restrictive covenants, licenses, restrictions (including zoning restrictions), minor title defects, exceptions, deficiencies or irregularities in title, encroachments, protrusions, servitudes, permits, conditions and covenants and other similar

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charges or encumbrances (including in any rights-of-way or other property of the Company or its Subsidiaries for the purpose of roads, pipelines, transmission lines, transportation lines, distribution lines for the removal of gas, oil or other minerals or timber, and other like purposes, or for joint or common use of real estate, rights of way, facilities and equipment) not interfering in any material respect with the business of the Company and its Subsidiaries, taken as a whole;

(f)    Liens in favor of a banking or other financial institution arising as a matter of law or in the ordinary course of business under customary general terms and conditions encumbering deposits or other funds maintained with a financial institution (including the right of set-off) and that are within the general parameters customary in the banking industry or arising pursuant to such banking institution’s general terms and conditions;

(g)    Liens on specific items of inventory or other goods (other than fixed or capital assets) and proceeds thereof of any Person securing such Person’s obligations in respect of bankers’ acceptances or letters of credit issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods in the ordinary course of business;

(h)    Liens encumbering reasonable customary initial deposits and margin deposits and similar Liens attaching to commodity trading accounts or other brokerage accounts incurred in the ordinary course of business and not for speculative purposes;

(i)    judgment liens in respect of judgments that to do not constitute an Event of Default under Section 7.01(k);  

(j)    (i) any interest or title of a lessor, sublessor, licensor or sublicensor under any lease, liens reserved in oil, gas or other Hydrocarbons, minerals, leases for bonus, royalty or rental payments and for compliance with the terms of such lease and (ii) any interest or title of a lessor, sublessor, licensor or sublicensor or secured by a lessor’s, sublessor’s, licensor’s or sublicensor’s interest under any lease, sublease, license or sublicense entered into by the Company or any Subsidiary in the ordinary course of business or otherwise permitted by this Agreement and not securing Indebtedness;

(k)    Liens which arise in the ordinary course of business under operating agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, Farm-Out Agreements, Farm-In Agreements, division orders, contracts for the sale, gathering, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, overriding royalty agreements, marketing agreements, processing agreements, net profits agreements, development agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or other geophysical permits or agreements, and other agreements that are usual or customary in the Oil and Gas Business and are for claims which are not delinquent or that are being contested in good faith and by appropriate proceedings for which appropriate reserves have been established to the extent required by and in accordance with GAAP; provided that any such Lien referred to in this clause does not materially impair the use of the property covered by such Lien for the purposes for which such property is held by any Borrower or any Subsidiary;

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(l)    Liens on pipelines, pipeline facilities and other midstream assets or facilities that arise by operation of law or other like Liens arising by operation of law in the ordinary course of business and incidental to the exploration, development, operation and maintenance of Oil and Gas Properties;

(m)    Liens on equipment of the Company or any Subsidiary granted in the ordinary course of business to the Company’s or such Subsidiary’s client at which such equipment is located;

(n)    security given to a public utility or any municipality or governmental authority when required by such utility or authority in connection with the operations of that Person in the ordinary course of business;

(o)    Liens solely on any cash earnest money deposits made by the Borrower or any Subsidiary in connection with any letter of intent or purchase agreement permitted hereunder;

(p)    Liens created in the ordinary course of business on deposits to secure liability for premiums to insurance carriers or securing insurance premium financing arrangements;

(q)    Liens arising in connection with conditional sale, title retention, consignment or similar arrangements for the sale of goods entered into by the Company and the Subsidiaries in the ordinary course of business permitted by this Agreement, purchase orders and other agreements entered into with customers of the Company or any Subsidiary in the ordinary course of business;

(r)    purported Liens evidenced by the filing of precautionary financing statements relating solely to operating leases of personal property entered into in the ordinary course of business;

(s)    trustees’ Liens granted pursuant to any indenture governing any Indebtedness not otherwise prohibited by this Agreement in favor of the trustee under such indenture and securing only obligations to pay compensation to such trustee, to reimburse such trustee of its expenses and to indemnify such trustee under the terms of such indenture; and

(t)    Liens on property or assets of the Company or any Subsidiary consisting of marine Liens provided for in Title XI of the Merchant Marine Act of 1936 or foreign equivalents;

(u)    operating leases, licenses, subleases or sublicenses granted to others not (i) interfering in any material respect with the business of the Company and its Subsidiaries, taken as a whole, or (ii) securing any indebtedness;

(v)    (i) zoning, building, entitlement and other land use regulations by Governmental Authorities with which the normal operation of the business complies and (ii) any zoning or similar law or right reserved to or vested in any Governmental Authority to control or regulate the use of any real property that does not materially interfere with the ordinary conduct of the business of the Company and its Subsidiaries, taken as a whole; and

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(w)    any encumbrance or restriction, including any options, put and call arrangements, rights of first refusal and similar rights, set forth in the Permitted JV LLC Agreement;

provided that the term “Permitted Encumbrances” shall not, in any event, include any Lien securing Indebtedness.

Permitted Investments” means: (a) direct obligations of, or obligations the principal of and interest on which are unconditionally guaranteed by, the United States of America (or by any agency thereof to the extent such obligations are backed by the full faith and credit of the United States of America), in each case maturing within one year from the date of acquisition thereof; (b) investments in commercial paper maturing within 270 days from the date of acquisition thereof and having, at such date of acquisition, the highest credit rating obtainable from S&P or from Moody’s; (c) investments in certificates of deposit, bankers’ acceptances and time deposits maturing within 270 days from the date of acquisition thereof issued or guaranteed by or placed with, and money market deposit accounts issued or offered by, any domestic office of any commercial bank organized under the laws of the United States of America or any State thereof which has a combined capital and surplus and undivided profits of not less than $500,000,000; (d) any evidence of Indebtedness issued, guaranteed or insured by the government of Canada or any province or territory thereof, and having terms to maturity of not more than three hundred sixty (360) days from the date of acquisition; (e) fully collateralized repurchase agreements with a term of not more than 30 days for securities described in clause (a) above and entered into with a financial institution satisfying the criteria described in clause (c) above; and (f) money market funds that (i) comply with the criteria set forth in SEC Rule 2a-7 under the Investment Company Act of 1940, (ii) are rated AAA by S&P and Aaa by Moody’s and (iii) have portfolio assets of at least $5,000,000,000.

Permitted JV” means Murphy Gulf of Mexico, LLC, a Delaware limited liability company.

Permitted JV Agreements” means (i) the Permitted JV Contribution Agreement, (ii) the Permitted JV MEPU Conveyance, (iii) the Permitted JV Units Conveyance, (iv) the Permitted JV LLC Agreement, (v) the Permitted JV LLC Formation Document and (vi) the Permitted JV MSA.

Permitted JV Closing Date” means the date on which the Closing (as defined in the Permitted JV Contribution Agreement) shall have occurred in accordance with the terms of the Permitted JV Contribution Agreement.

Permitted JV Contribution Agreement” means that certain Contribution and Acquisition Agreement, dated as of October 10, 2018, by and among Expro-USA, Petrobras America Inc. and the Permitted JV.

Permitted JV LLC Agreement” means that certain Amended and Restated Limited Liability Company Agreement of the Permitted JV, to be dated as of the Permitted JV Closing Date, in the form attached as Exhibit F to the Permitted JV Contribution Agreement.

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Permitted JV LLC Formation Document” means the “LLC Formation Document” as defined in the Permitted JV Contribution Agreement.

Permitted JV MEPU Conveyance” means the “MEPU Conveyance” as defined in the Contribution Agreement.

Permitted JV MSA” means the “Master Services Agreement” as defined in the  Permitted JV Contribution Agreement.

Permitted JV Units Conveyance” means the “Units Conveyance” as defined in the Contribution Agreement.

Permitted Liens” means any Lien permitted to remain outstanding pursuant to Section 6.03.

Person” means any natural person, corporation, limited liability company, trust, joint venture, association, company, partnership, Governmental Authority or other entity.

Plan” means any employee pension benefit plan (other than a Multiemployer Plan) subject to the provisions of Title IV of ERISA or Section 412 of the Code or Section 302 of ERISA, and in respect of which the Company or any ERISA Affiliate is (or, if such plan were terminated, would under Section 4069 of ERISA be deemed to be) an “employer” as defined in Section 3(5) of ERISA.

Platform” means Debt Domain, Intralinks, Syndtrak or a substantially similar electronic transmission system.

Pounds Sterling” means the lawful currency of the United Kingdom.

Prime Rate”  means the rate of interest per annum last quoted by The Wall Street Journal as the “Prime Rate” in the U.S. or, if The Wall Street Journal ceases to quote such rate, the highest per annum interest rate published by the Federal Reserve Board in Federal Reserve Statistical Release H.15 (519) (Selected Interest Rates) as the “bank prime loan” rate or, if such rate is no longer quoted therein, any similar rate quoted therein (as determined by the Administrative Agent) or any similar release by the Federal Reserve Board (as determined by the Administrative Agent). Each change in the Prime Rate shall be effective from and including the date such change is publicly announced or quoted as being effective.

Project Financing” means any Indebtedness that is incurred to finance or refinance the acquisition, improvement, installation, design, engineering, construction, development, completion, maintenance, operation, securitization or monetization, in respect of all or any portion of any project, any group of projects, or any asset related thereto, and any guaranty with respect thereto, other than such portion of such Indebtedness or guaranty that expressly provides for direct recourse to the Company or any of its Subsidiaries (other than a Project Financing Subsidiary) or any of their respective property other than recourse to the equity in, Indebtedness or other obligations of, or properties of, one or more Project Financing Subsidiaries; provided however, that support such as limited guaranties or obligations to provide or guaranty equity

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contributions or to make subordinated loans shall not be considered direct recourse for the purpose of this definition.

Project Financing Subsidiary” means any Subsidiary of the Company whose principal purpose is to incur Project Financing or to become a direct or indirect partner, member or other equity participant or owner in a Person so created, and substantially all the assets of such Subsidiary are limited to (i) those assets for which the acquisition, improvement, installation, design, engineering, construction, development, completion, maintenance, operation, securitization or monetization is being financed in whole or in part by one or more Project Financings, or (ii) the equity in, Indebtedness or other obligations of, one or more other such Subsidiaries or Persons.

Property” means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including, without limitation, cash, securities, accounts and contract rights.

Proved Non-Producing Oil and Gas Properties” means all Oil and Gas Properties which constitute proved developed non-producing reserves as defined in the Definitions for Oil and Gas Reserves promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

Proved Oil and Gas Properties” means, collectively, Proved Producing Oil and Gas Properties, Proved Non-Producing Oil and Gas Properties and Proved Undeveloped Oil and Gas Properties.

Proved Producing Oil and Gas Properties” means all Oil and Gas Properties which constitute proved developed producing reserves as defined in the Definitions for Oil and Gas Reserves promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

Proved Undeveloped Oil and Gas Properties” means all Oil and Gas Properties which constitute proved undeveloped reserves as defined in the Definitions for Oil and Gas Reserves promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

Rating Agencies” shall mean each of Moody’s, S&P and Fitch.

Recipient” means (a) the Administrative Agent, (b) any Lender and (c) any Issuing Bank, as applicable.

Redemption” means, with respect to any Indebtedness, the redemption, purchase, defeasance, prepayment or other acquisition or retirement for value of such Indebtedness. The term “Redeem” has a meaning correlative thereto.

Register” has the meaning set forth in Section 10.04(b)(iv).

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Related Parties” means, with respect to any specified Person, such Person’s Affiliates and the respective directors, officers, employees, agents and advisors of such Person and such Person’s Affiliates.

Required Lenders” means, at any time, Lenders having Credit Exposures and unused Commitments representing more than 50% of the sum of the total Credit Exposures and unused Commitments at such time.

Required Subsidiary Guarantor” means, as of any date of determination, each Domestic Subsidiary which, as of the most recent fiscal quarter of the Company, for the period of four consecutive fiscal quarters then ended for which financial statements have been delivered pursuant to Section 5.01(a) or Section 5.01(b), contributed greater than (a) ten percent of Consolidated EBITDA Ex-Canam for such period or (b) ten percent of Consolidated Total Assets Ex-Canam as of the last day of such period; provided that, if at any time the aggregate amount of Consolidated EBITDA Ex-Canam or Consolidated Total Assets Ex-Canam attributable to all Subsidiaries that are not Guarantors exceeds fifteen percent of Consolidated EBITDA Ex-Canam for any such period or fifteen percent of Consolidated Total Assets Ex-Canam as of the last day of any such fiscal quarter, then the Company shall, pursuant to Section 5.01(d), designate in the Compliance Certificate required to be delivered for such fiscal quarter or fiscal year, as applicable, sufficient Subsidiaries, whether Domestic Subsidiaries, Foreign Subsidiaries or a combination thereof, as “Required Subsidiary Guarantors” to eliminate such excess, and upon the delivery of such Compliance Certificate to the Administrative Agent, such designated Subsidiaries shall for all purposes of this Agreement constitute Required Subsidiary Guarantors and each shall be required to become a Guarantor pursuant to Section 5.12In the event that the Company fails to designate sufficient additional Subsidiaries as “Required Subsidiary Guarantors” in the Compliance Certificate as aforesaid, the Administrative Agent may, by written notice to the Company, designate sufficient Subsidiaries, whether Domestic Subsidiaries, Foreign Subsidiaries or a combination thereof, as “Required Subsidiary Guarantors” on the Company’s behalf, to eliminate such excess, and upon delivery of such written notice to the Company, such designated Subsidiaries shall for all purposes of this Agreement constitute Required Subsidiary Guarantors and each shall be required to become a Guarantor pursuant to Section 5.12.  Notwithstanding the foregoing, the Permitted JV shall not constitute a “Required Subsidiary Guarantor” for any purposes hereunder or any other Loan Documents.

Reserve Report” means each report, in form and substance reasonably satisfactory to the Administrative Agent, setting forth, as of each January 1st or, to the extent required by Section 5.10, July 1st, the Proved Oil and Gas Properties of the Company and the Subsidiaries, together with a projection of the rate of production and future net income, Taxes, operating expenses and capital expenditures with respect thereto as of such date, based upon the pricing assumptions and discount rate consistent with the Administrative Agent’s lending requirements at the time.

Responsible Officer” means, as to any Person, the Chief Executive Officer, the President, any Financial Officer or any Vice President of such Person.  Unless otherwise specified, all references to a Responsible Officer herein shall mean a Responsible Officer of the Company.

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Restricted Payment” means any dividend or other distribution (whether in cash, securities or other property) with respect to any Equity Interests in the Company or any Subsidiary, or any payment (whether in cash, securities or other property), including any sinking fund or similar deposit, on account of the purchase, redemption, retirement, acquisition, cancellation or termination of any such Equity Interests in the Company or any Subsidiary or any option, warrant or other right to acquire any such Equity Interests in the Company or any Subsidiary.

Revolving Loan” means a Loan made pursuant to Section 2.01.

Ringgit” means the lawful currency of Malaysia.

S&P” means S&P Global Ratings, a division of S&P Global Inc.

Sale and Leaseback Transaction” means any sale or other transfer of any Property or asset by any Person with the intent to lease such property or asset as lessee.

Sanctioned Country” means, at any time, a country, region or territory which is itself the subject or target of any Sanctions (at the time of this Agreement, Crimea, Cuba, Iran, North Korea and Syria).

Sanctioned Person” means, at any time, (a) any Person  listed in any Sanctions-related list of designated Persons maintained by the Office of Foreign Assets Control of the U.S. Department of the Treasury, the U.S. Department of State, the Government of Canada, the United Nations Security Council, the European Union or Her Majesty’s Treasury of the United Kingdom, (b) any Person located, organized or resident in a Sanctioned Country, (c) any Person owned 50% or more by any Person or Persons described in the foregoing clauses (a) or (b), or (d) any Person otherwise the subject of any Sanctions.

Sanctions” means all economic or financial sanctions or trade embargoes imposed, administered or enforced from time to time by (a) the U.S. government, including those administered by the Office of Foreign Assets Control of the U.S. Department of the Treasury or the U.S. Department of State or (b) the Government of Canada, the United Nations Security Council, the European Union, Her Majesty’s Treasury of the United Kingdom or any other jurisdiction applicable to the Company, any other Borrower or any of their respective Subsidiaries from time to time.

Securities Account” has the meaning assigned to such term in the UCC.

SEC” means the Securities and Exchange Commission or any successor Governmental Authority.

Solvent” means, in reference to any Person, (a) the fair value of the assets of such Person, at a fair valuation, will exceed its debts and liabilities (subordinated, contingent or otherwise); (b) the present fair saleable value of the property of such Person will be greater than the amount that will be required to pay the probable liability of its debts and other liabilities (subordinated, contingent or otherwise), as such debts and other liabilities become absolute and matured; (c) such Person will be able to pay its debts and liabilities (subordinated, contingent or

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otherwise), as such debts and liabilities become absolute and matured; and (d) such Person will not have unreasonably small capital with which to conduct the business in which it is engaged as such business is now conducted and is proposed to be conducted after the Effective Date.

Statutory Reserve Rate” means a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentage (including any marginal, special, emergency or supplemental reserves) expressed as a decimal established by the Board to which the Administrative Agent is subject with respect to the Adjusted LIBO Rate, for eurocurrency funding (currently referred to as “Eurocurrency Liabilities” in Regulation D of the Board).  Such reserve percentage shall include those imposed pursuant to such Regulation D.  Eurodollar Loans shall be deemed to constitute eurocurrency funding and to be subject to such reserve requirements without benefit of or credit for proration, exemptions or offsets that may be available from time to time to any Lender under such Regulation D or any comparable regulation.  The Statutory Reserve Rate shall be adjusted automatically on and as of the effective date of any change in any reserve percentage.

Subordinated Intercompany Note” means a Subordinated Intercompany Note substantially in the form of Exhibit F pursuant to which intercompany obligations and advances owed by any Loan Party are subordinated to the Obligations.

subsidiary” means, with respect to any Person (the “parent”) at any date, any corporation, limited liability company, partnership, association or other entity the accounts of which would be consolidated with those of the parent in the parent’s consolidated financial statements if such financial statements were prepared in accordance with GAAP as of such date, as well as any other corporation, limited liability company, partnership, association or other entity (a) of which securities or other ownership interests representing more than 50% of the equity or more than 50% of the ordinary voting power or, in the case of a partnership, more than 50% of the general partnership interests are, as of such date, owned, controlled or held, or (b) that is, as of such date, otherwise Controlled, by the parent or one or more subsidiaries of the parent or by the parent and one or more subsidiaries of the parent.

Subsidiary” means any subsidiary of the Company.

Subsidiary Guarantor” means any Subsidiary that is a Guarantor.

Surplus Inventory” means equipment of the Company or any Subsidiary, which the Company has determined in good faith (a) represents surplus equipment that is not necessary in the conduct of the exploration and production business of the Company and its Subsidiaries or (b) is obsolete or worn‑out and no longer used or usable in its business.

Synthetic Leases” means, in respect of any Person, all leases which shall have been, or should have been, in accordance with GAAP, treated as operating leases on the financial statements of the Person liable (whether contingently or otherwise) for the payment of rent thereunder and which were properly treated as indebtedness for borrowed money for purposes of U.S. federal income Taxes, if the lessee in respect thereof is obligated to either purchase for an amount in excess of, or pay upon early termination, an amount in excess of, 80% of the residual

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value of the Property subject to such operating lease upon expiration or early termination of such lease.

Taxes” means all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

Total Credit Exposure” means, the sum of the outstanding principal amount of all Lenders’ Revolving Loans and their LC Exposure at such time.

Transactions” means (a) the execution, delivery and performance by each Borrower of this Agreement and each other Loan Document to which it is a party, the borrowing of Loans, the use of the proceeds thereof, and the issuance of Letters of Credit hereunder and (b) with respect to each Guarantor, the execution, delivery and performance by such Guarantor of the Guaranty Agreement to which it is a party and each other Loan Document to which it is a party, and its Guarantee of the Obligations.

Type”, when used in reference to any Loan or Borrowing, refers to whether the rate of interest on such Loan, or on the Loans comprising such Borrowing, is determined by reference to the Adjusted LIBO Rate or the Alternate Base Rate.

UCC” means the Uniform Commercial Code as in effect in the State of New York.

Unrestricted Cash” means, as of any date of determination, cash or Permitted Investments of the Company or any of the Guarantors that are (i) Domestic Subsidiaries or (ii) Canadian Subsidiaries that would not appear as “restricted” on a consolidated balance sheet of the Company or any of such Guarantors on such date (it being understood that cash or Permitted Investments subject to a control agreement in favor of any Person other than the Administrative Agent or any Lender shall be deemed “restricted”, and cash or Permitted Investments restricted in favor of the Administrative Agent or any Lender shall be deemed not “restricted”), but only to the extent that such cash and Permitted Investments are held in accounts with financial institutions in any jurisdiction located within the United States of America or Canada.

U.S. Person” means a “United States person” within the meaning of Section 7701(a)(30) of the Code.

U.S. Tax Compliance Certificate” has the meaning assigned to such term in Section 2.16(f)(ii)(B)(iii).

Voting Stock” shall mean, with respect to any Person, any class or classes of Equity Interests pursuant to which the holders thereof have the general voting power under ordinary circumstances to elect at least a majority of the Board of Directors (or similar relevant governing body) of such Person.

Wholly-Owned” means, with respect to a subsidiary of any Person, that all of the Equity Interests of such subsidiary are, directly or indirectly, owned or controlled by such Person and/or one or more of its Wholly-Owned subsidiaries (except for directors’ qualifying shares or other

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shares required by applicable law to be owned by a Person other than such Person and/or one or more of its Wholly‑Owned subsidiaries).

Withdrawal Liability” means liability to a Multiemployer Plan as a result of a complete or partial withdrawal from such Multiemployer Plan, as such terms are defined in Part I of Subtitle E of Title IV of ERISA.

Write-Down and Conversion Powers” means, with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule.

Section 1.02    Classification of Loans and Borrowings.  For purposes of this Agreement, Loans may be classified and referred to by Class (e.g., a “Revolving Loan”) or by Type (e.g., a “Eurodollar Loan”) or by Class and Type (e.g., a “Eurodollar Revolving Loan”).  Borrowings also may be classified and referred to by Class (e.g., a “Revolving Borrowing”) or by Type (e.g., a “Eurodollar Borrowing”) or by Class and Type (e.g., a “Eurodollar Revolving Borrowing”).

Section 1.03    Terms Generally.  The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined.  Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms.  The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”.  The word “will” shall be construed to have the same meaning and effect as the word “shall”.  Unless the context requires otherwise (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein), (b) any reference herein to any Person shall be construed to include such Person’s successors and assigns, (c) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (d) all references herein to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and Schedules to, this Agreement, (e) any reference to any law, rule or regulation herein shall, unless otherwise specified, refer to such law, rule or regulation as amended, modified or supplemented from time to time and (f) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights. 

Section 1.04    Accounting Terms; GAAP.  Except as otherwise expressly provided herein, all terms of an accounting or financial nature shall be construed in accordance with GAAP, as in effect from time to time; provided that, if the Company notifies the Administrative Agent that the Company, on behalf of the Borrowers, requests an amendment to any provision hereof to eliminate the effect of any change occurring after the Effective Date in GAAP or in the application thereof on the operation of such provision (or if the Administrative Agent notifies the Company that the Required Lenders request an amendment to any provision hereof for such purpose), regardless of whether any such notice is given before or after such change in GAAP or

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in the application thereof, then such provision shall be interpreted on the basis of GAAP as in effect and applied immediately before such change shall have become effective until such notice shall have been withdrawn or such provision amended in accordance herewith.  Notwithstanding any other provision contained herein, (i) any lease that would have been characterized as an operating lease in accordance with GAAP prior to the date of the Company’s adoption of ASC 842 (whether or not such lease was in effect on such date) shall not be a Capital Lease, and any such lease shall be, for all purposes of this Agreement, treated as though it were reflected on the Company’s consolidated financial statements in the same manner as an operating lease would have been reflected prior to Borrower’s adoption of ASC 842 and (ii) all terms of an accounting or financial nature used herein shall be construed, and all computations of amounts and ratios referred to herein shall be made, without giving effect to any election under Financial Accounting Standards Board Accounting Standards Codification 825 (or any other Financial Accounting Standard having a similar result or effect) to value any Indebtedness or other liabilities of the Company or any Subsidiary at “fair value”, as defined therein. 

Section 1.05    Exchange Rates; Currency Equivalents.

(a)    The Administrative Agent shall determine the Dollar Equivalent of the LC Exposure (and including any proposed Letter of Credit to be issued, amended, extended or renewed as of such date, as applicable, in the case of the following clauses (i) and (ii)): (i) as of the date of the commencement of the initial Interest Period of any Borrowing and as of the date of the commencement of each subsequent Interest Period therefor (including on the date of conversion or continuation of any Borrowing); (ii) as of the date any Borrowing Request is submitted hereunder; (iii) as of the date of any Borrowing or the date that any Letter of Credit is issued, amended, extended or renewed; (iv) as of the date of any termination or reduction of the Commitments or any Letter of Credit Commitment; (v) as of the first Business Day of each calendar month; and (vi) during the continuation of an Event of Default, on any Business Day elected by the Administrative Agent in its discretion or upon instruction by the Required Lenders.  Except as expressly provided in the last sentence of Section 2.11(d), each such amount shall be the Dollar Equivalent of the LC Exposure until the next required calculation thereof pursuant to this Section 1.05(a).  Each day upon or as of which the Administrative Agent determines the Dollar Equivalent of any amount as described in this Section 1.05(a) is herein referred to as a “Computation Date”.

(b)    Each provision of this Agreement shall be subject to such reasonable changes of construction as the Administrative Agent may from time to time specify with the Company’s consent to appropriately reflect a change in currency of any country and any relevant market convention or practice relating to such change in currency.

Section 1.06    Interest Rates; LIBOR NotificationThe interest rate on Eurodollar Loans is determined by reference to the LIBO Rate, which is derived from the London interbank offered rate.  The London interbank offered rate is intended to represent the rate at which contributing banks may obtain short-term borrowings from each other in the London interbank market.  In July 2017, the U.K. Financial Conduct Authority announced that, after the end of 2021, it would no longer persuade or compel contributing banks to make rate submissions to the ICE Benchmark Administration (together with any successor to the ICE Benchmark Administrator, the “IBA”) for purposes of the IBA setting the London interbank offered rate. As

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a result, it is possible that commencing in 2022, the London interbank offered rate may no longer be available or may no longer be deemed an appropriate reference rate upon which to determine the interest rate on Eurodollar Loans. In light of this eventuality, public and private sector industry initiatives are currently underway to identify new or alternative reference rates to be used in place of the London interbank offered rate. In the event that the London interbank offered rate is no longer available or in certain other circumstances as set forth in Section 2.13(b) of this Agreement, such Section 2.13(b) provides a mechanism for determining an alternative rate of interest.  The Administrative Agent will notify the Borrower, pursuant to Section 2.13, in advance of any change to the reference rate upon which the interest rate on Eurodollar Loans is based. However, the Administrative Agent does not warrant or accept any responsibility for, and shall not have any liability with respect to, the administration, submission or any other matter related to the London interbank offered rate or other rates in the definition of “LIBO Rate” or with respect to any alternative or successor rate thereto, or replacement rate thereof, including without limitation, whether the composition or characteristics of any such alternative, successor or replacement reference rate, as it may or may not be adjusted pursuant to Section 2.13(b), will be similar to, or produce the same value or economic equivalence of, the LIBO Rate or have the same volume or liquidity as did the London interbank offered rate prior to its discontinuance or unavailability.

Article II
The Credits

Section 2.01    Commitments.  Subject to the terms and conditions set forth herein, each Lender agrees to make Revolving Loans to the Borrowers from time to time during the Availability Period in an aggregate principal amount that will not result in (i) such Lender’s Credit Exposure exceeding such Lender’s Commitment or (ii) the Total Credit Exposure exceeding the total Commitments.  Within the foregoing limits and subject to the terms and conditions set forth herein, any Borrower may borrow, prepay and re-borrow Revolving Loans.

Section 2.02    Loans and Borrowings.  (a) Each Revolving Loan shall be made as part of a Borrowing consisting of Revolving Loans made by the Lenders ratably in accordance with their respective Commitments.  The failure of any Lender to make any Loan required to be made by it shall not relieve any other Lender of its obligations hereunder; provided that the Commitments of the Lenders are several and no Lender shall be responsible for any other Lender’s failure to make Loans as required.

(b)    Subject to Section 2.13, each Revolving Borrowing shall be comprised entirely of ABR Loans or Eurodollar Loans as the Company, on behalf of itself, Expro-Intl. or MOCL, may request in accordance herewith, and each Lender at its option may make any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan; provided that any exercise of such option shall not affect the obligation of the Borrowers to repay such Loan in accordance with the terms of this Agreement.

(c)    At the commencement of each Interest Period for any Eurodollar Revolving Borrowing, such Borrowing shall be in an aggregate amount that is an integral multiple of $1,000,000 and not less than $5,000,000.  At the time that each ABR Revolving Borrowing is made, such Borrowing shall be in an aggregate amount that is an integral multiple

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of $1,000,000 and not less than $5,000,000; provided that an ABR Revolving Borrowing may be in an aggregate amount that is equal to the entire unused balance of the total Commitments or that is required to finance the reimbursement of an LC Disbursement as contemplated by Section 2.05(e).  Borrowings of more than one Type and Class may be outstanding at the same time; provided that there shall not at any time be more than a total of six Eurodollar Revolving Borrowings outstanding.

(d)    Notwithstanding any other provision of this Agreement, the Company, on behalf of itself, Expro-Intl. or MOCL, shall not be entitled to request, or to elect to convert or continue, any Borrowing if the Interest Period requested with respect thereto would end after the Maturity Date.

Section 2.03    Requests for Revolving Borrowings.  To request a Revolving Borrowing, the Company shall notify the Administrative Agent of such request by telephone (a) in the case of a Eurodollar Borrowing, not later than 11:00 a.m., New York City time, three Business Days before the date of the proposed Borrowing and (b) in the case of an ABR Borrowing, not later than 11:00 a.m., New York City time, one Business Day before the date of the proposed Borrowing; provided that any such notice of an ABR Revolving Borrowing to finance the reimbursement of an LC Disbursement as contemplated by Section 2.05(e) may be given not later than 10:00 a.m., New York City time, on the date of the proposed Borrowing.  Each such telephonic Borrowing Request shall be irrevocable and shall be confirmed promptly by hand delivery or telecopy to the Administrative Agent of a written Borrowing Request in a form approved by the Administrative Agent and signed by the Company.  Each such telephonic and written Borrowing Request shall specify the following information in compliance with Section 2.02:

(i)    the applicable Borrower and the aggregate amount of the requested Borrowing;

(ii)    the date of such Borrowing, which shall be a Business Day;

(iii)    whether such Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing;

(iv)    in the case of a Eurodollar Borrowing, the initial Interest Period to be applicable thereto, which shall be a period contemplated by the definition of the term “Interest Period”; and

(v)    the location and number of the applicable Borrower’s account to which funds are to be disbursed, which shall comply with the requirements of Section 2.06.

If no election as to the Type of Revolving Borrowing is specified, then the requested Revolving Borrowing shall be an ABR Borrowing.  If no Interest Period is specified with respect to any requested Eurodollar Revolving Borrowing, then the applicable Borrower shall be deemed to have selected an Interest Period of one month’s duration.  If no Borrower is specified, the Company shall be the applicable Borrower.  Promptly following receipt of a Borrowing Request

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in accordance with this Section, the Administrative Agent shall advise each Lender of the details thereof and of the amount of such Lender’s Loan to be made as part of the requested Borrowing.

Section 2.04    [Reserved].    

Section 2.05    Letters of Credit.

(a)    General.  Subject to the terms and conditions set forth herein, the Company may request the issuance of Letters of Credit denominated in dollars or in any Designated Currency from any Issuing Bank, with any Borrower as the applicant thereof for the support of its or its Subsidiaries’ obligations, in a form reasonably acceptable to the Administrative Agent and such Issuing Bank, at any time and from time to time during the Availability Period. In the event of any inconsistency between the terms and conditions of this Agreement and the terms and conditions of any form of letter of credit application or other agreement submitted by the Company (on behalf of itself, Expro-Intl. or MOCL) to, or entered into by a Borrower with, an Issuing Bank relating to any Letter of Credit, the terms and conditions of this Agreement shall control. Notwithstanding anything herein to the contrary, no Issuing Bank shall have any obligation hereunder to issue, and shall not issue, any Letter of Credit the proceeds of which would be made available to any Person (i) in furtherance of an offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of any Anti-Corruption Laws, (ii) to fund any activity or business of or with any Sanctioned Person, or in any country or territory that, at the time of such funding, is the subject of any Sanctions or (iii) in any manner that would result in a violation of any Sanctions by any party to this Agreement.

(b)    Notice of Issuance, Amendment, Renewal, Extension; Certain ConditionsTo request the issuance of a Letter of Credit by any Issuing Bank (or the amendment, renewal or extension of an outstanding Letter of Credit), the Company shall hand deliver or telecopy (or transmit by electronic communication, if arrangements for doing so have been approved by such Issuing Bank) to such Issuing Bank and the Administrative Agent (reasonably in advance of the requested date of issuance, amendment, renewal or extension, but in any event no less than three Business Days) a notice requesting the issuance of a Letter of Credit, or identifying the Letter of Credit to be amended, renewed or extended, and specifying the date of issuance, amendment, renewal or extension (which shall be a Business Day), the date on which such Letter of Credit is to expire (which shall comply with paragraph (c) of this Section 2.05), the amount of such Letter of Credit, whether such Letter of Credit is to be dollar-denominated or denominated in a Designated Currency (it being understood that if no denomination is specified, the Letter of Credit shall be dollar-denominated) the name and address of the beneficiary thereof and such other information as shall be necessary to prepare, amend, renew or extend such Letter of Credit. If requested by the applicable Issuing Bank, the Company, Expro-Intl. or MOCL, as applicable, also shall submit a letter of credit application on such Issuing Bank’s standard form in connection with any request for a Letter of Credit. A Letter of Credit shall be issued, amended, renewed or extended only if (and upon issuance, amendment, renewal or extension of each Letter of Credit the Company shall be deemed to represent and warrant that), after giving effect to such issuance, amendment, renewal or extension (determined by reference to the Dollar Equivalent of Letters of Credit denominated in a Designated Currency on the date of such issuance, amendment, renewal or extension of such Letter of Credit): (i) the LC Exposure shall not exceed

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$250,000,000, (ii) no Lender’s Credit Exposure shall exceed its Commitment, (iii) the Total Credit Exposure shall not exceed the total Commitments, and (iv) the LC Exposure of any Issuing Bank shall not exceed its Letter of Credit Commitment.  The Company may, at any time and from time to time, reduce the Letter of Credit Commitment of any Issuing Bank with the consent of such Issuing Bank; provided that the Company shall not reduce the Letter of Credit Commitment of any Issuing Bank if, after giving effect of such reduction, the conditions set forth in clauses (i) through (iv) above shall not be satisfied.

Notwithstanding anything herein to the contrary, no Issuing Bank shall be under any obligation to issue any Letter of Credit in any Designated Currency if (x) any order, judgment or decree of any Governmental Authority or arbitrator shall by its terms purport to enjoin or restrain the Issuing Bank from issuing such Letter of Credit, or any law applicable to the Issuing Bank or any request or directive (whether or not having the force of law) from any Governmental Authority with jurisdiction over the Issuing Bank shall prohibit, or request that the Issuing Bank refrain from the issuance of letters of credit generally or such Letter of Credit in particular, or shall impose upon the Issuing Bank with respect to such Letter of Credit any restriction, reserve or capital requirement (for which the Issuing Bank is not otherwise compensated hereunder) not in effect on the Effective Date, or shall impose upon the Issuing Bank any unreimbursed loss, cost or expense which was not applicable on the Effective Date and which the Issuing Bank in good faith deems material to it; (y) the issuance of such Letter of Credit would violate one or more policies of the Issuing Bank generally applicable to the issuance of letters of credit or (z) such Issuing Bank does not generally issue, or is otherwise incapable of issuing, Letters of Credit in the Designated Currency requested by the applicable Borrower.

(c)    Expiration DateEach Letter of Credit shall expire (or be subject to termination by notice from the applicable Issuing Bank to the beneficiary thereof) at or prior to the close of business on the earlier of (i) the date one year after the date of the issuance of such Letter of Credit (or, in the case of any renewal or extension thereof, one year after such renewal or extension; provided that, to the extent such date would extend beyond the date referred to in the immediately succeeding clause (c)(ii), such Letter of Credit shall, concurrently with, or prior to, the effectiveness of such renewal or extension (as applicable), be cash collateralized in a manner (and in such amount) acceptable to the applicable Issuing Bank in its sole discretion) and (ii) subject to the parenthetical in the immediately preceding clause (i), the date that is five Business Days prior to the Maturity Date.

(d)    Participations.  By the issuance of a Letter of Credit (or an amendment to a Letter of Credit increasing the amount thereof) and without any further action on the part of the Issuing Bank that issues such Letter of Credit or the Lenders, such Issuing Bank hereby grants to each Lender, and each Lender hereby acquires from such Issuing Bank, a participation in such Letter of Credit equal to such Lender’s Applicable Percentage of the aggregate amount available to be drawn under such Letter of Credit.  In consideration and in furtherance of the foregoing, each Lender hereby absolutely and unconditionally agrees to pay to the Administrative Agent, for the account of each Issuing Bank that issues a Letter of Credit hereunder, such Lender’s Applicable Percentage of each LC Disbursement made by such Issuing Bank and not reimbursed by the applicable Borrower on the date due as provided in paragraph (e) of this Section 2.05, or of any reimbursement payment required to be refunded to the Company for any reason.  Each

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Lender acknowledges and agrees that its obligation to acquire participations pursuant to this paragraph in respect of Letters of Credit is absolute and unconditional and shall not be affected by any circumstance whatsoever, including any amendment, renewal or extension of any Letter of Credit or the occurrence and continuance of a Default or reduction or termination of the Commitments, and that each such payment shall be made without any offset, abatement, withholding or reduction whatsoever.

(e)    Reimbursement.  If any Issuing Bank shall make any LC Disbursement in respect of a Letter of Credit issued by such Issuing Bank, the applicable Borrower shall reimburse such LC Disbursement by paying to the Administrative Agent, in the currency in which such Letter of Credit is denominated (except as specified below), an amount equal to such LC Disbursement not later than 12:00 noon, New York City time, on the date that such LC Disbursement is made, if the Company shall have received notice of such LC Disbursement prior to 10:00 a.m., New York City time, on such date, or, if such notice has not been received by the Company prior to such time on such date, then not later than 12:00 noon, New York City time, on the Business Day immediately following the day that the Company receives such notice, if such notice is not received prior to such time on the day of receipt; provided that the Company may, subject to the conditions to borrowing set forth herein, request in accordance with Section 2.03 that such payment be financed with an ABR Revolving Borrowing in an equivalent amount (with respect to Letters of Credit denominated in dollars) or in the Dollar Equivalent on such date (as determined by the applicable Issuing Bank) of the amount of the LC Disbursement (with respect to Letters of Credit denominated in any Designated Currency), as applicable, and to the extent so financed, the applicable Borrower’s obligation to make such payment shall be discharged and replaced by the resulting ABR Revolving Borrowing.  Notwithstanding the foregoing, any Issuing Bank may, at its option, specify in the applicable notice of LC Disbursement that such Issuing Bank will require reimbursements in dollars, in which case the applicable Borrower agrees to reimburse such Issuing Bank in dollars; provided that the applicable Issuing Bank shall notify the Company of the Dollar Equivalent of the amount of the drawing promptly following the determination thereof.  If the applicable Borrower fails to make such payment when due, the Administrative Agent shall notify each Lender of the applicable LC Disbursement (and the Dollar Equivalent thereof), the payment then due from the applicable Borrower (and the Dollar Equivalent thereof) in respect thereof and such Lender’s Applicable Percentage thereof.  Promptly following receipt of such notice, each Lender shall pay to the Administrative Agent in dollars its Applicable Percentage of the Dollar Equivalent of the payment then due from the applicable Borrower, in the same manner as provided in Section 2.06 with respect to Loans made by such Lender (and Section 2.06 shall apply, mutatis mutandis, to the payment obligations of the Lenders), and the Administrative Agent shall promptly pay to the Issuing Bank that issued such Letter of Credit the amounts so received by it from the Lenders. Promptly following receipt by the Administrative Agent of any payment from the applicable Borrower pursuant to this paragraph, the Administrative Agent shall distribute such payment to the Issuing Bank that issued such Letter of Credit or, to the extent that Lenders have made payments pursuant to this paragraph to reimburse such Issuing Bank, then to such Lenders and such Issuing Bank as their interests may appear.  Any payment made by a Lender pursuant to this paragraph to reimburse an Issuing Bank for any LC Disbursement (other than the funding of ABR Revolving Loans as contemplated above) shall not constitute a Loan and shall not relieve the applicable Borrower of its obligation to reimburse such LC Disbursement.

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(f)    Obligations Absolute.  The applicable Borrower’s obligation to reimburse LC Disbursements as provided in paragraph (e) of this Section 2.05 shall be absolute, unconditional and irrevocable, and shall be performed strictly in accordance with the terms of this Agreement under any and all circumstances whatsoever and irrespective of (i) any lack of validity or enforceability of any Letter of Credit or this Agreement, or any term or provision therein, (ii) any draft or other document presented under a Letter of Credit proving to be forged, fraudulent or invalid in any respect or any statement therein being untrue or inaccurate in any respect, (iii) payment by the applicable Issuing Bank under a Letter of Credit against presentation of a draft or other document that does not comply with the terms of such Letter of Credit, (iv) any adverse change in the relevant exchange rates or in the availability of the relevant Designated Currency to the applicable Borrower or the other Loan Parties or in the relevant currency markets generally; or (v) any other event or circumstance whatsoever, whether or not similar to any of the foregoing, that might, but for the provisions of this Section 2.05, constitute a legal or equitable discharge of, or provide a right of setoff against, the applicable Borrower’s obligations hereunder.  Neither the Administrative Agent, the Lenders nor any Issuing Bank, nor any of their Related Parties, shall have any liability or responsibility by reason of or in connection with the issuance or transfer of any Letter of Credit or any payment or failure to make any payment thereunder (irrespective of any of the circumstances referred to in the preceding sentence), or any error, omission, interruption, loss or delay in transmission or delivery of any draft, notice or other communication under or relating to any Letter of Credit (including any document required to make a drawing thereunder), any error in interpretation of technical terms or any consequence arising from causes beyond the control of any Issuing Bank; provided that the foregoing shall not be construed to excuse any Issuing Bank from liability to the applicable Borrower to the extent of any direct damages (as opposed to special, indirect, consequential or punitive damages, claims in respect of which are hereby waived by the Borrowers to the extent permitted by applicable law) suffered by a Borrower that are caused by such Issuing Bank’s failure to exercise care when determining whether drafts and other documents presented under a Letter of Credit comply with the terms thereof.  The parties hereto expressly agree that, in the absence of gross negligence or willful misconduct on the part of an Issuing Bank (as finally determined by a court of competent jurisdiction), such Issuing Bank shall be deemed to have exercised care in each such determination.  In furtherance of the foregoing and without limiting the generality thereof, the parties agree that, with respect to documents presented which appear on their face to be in substantial compliance with the terms of a Letter of Credit, the applicable Issuing Bank may, in its sole discretion, either accept and make payment upon such documents without responsibility for further investigation, regardless of any notice or information to the contrary, or refuse to accept and make payment upon such documents if such documents are not in strict compliance with the terms of such Letter of Credit.

(g)    Disbursement Procedures.  An Issuing Bank shall, promptly following its receipt thereof, examine all documents purporting to represent a demand for payment under a Letter of Credit issued by such Issuing Bank.  Such Issuing Bank shall promptly notify the Administrative Agent and the Company by telephone (confirmed by telecopy) of such demand for payment and whether such Issuing Bank has made or will make an LC Disbursement thereunder; provided that any failure to give or delay in giving such notice shall not relieve the applicable Borrower of its obligation to reimburse such Issuing Bank and the Lenders with respect to any such LC Disbursement. 

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(h)    Interim Interest.  If an Issuing Bank shall make any LC Disbursement, then, unless the applicable Borrower shall reimburse such LC Disbursement in full on the date such LC Disbursement is made, the unpaid amount thereof shall bear interest, for each day from and including the date such LC Disbursement is made to but excluding the date that the reimbursement is due and payable at the rate per annum then applicable to ABR Revolving Loans (or in the case such LC Disbursement is denominated in any Designated Currency, a rate per annum determined by such Issuing Bank (which determination will be conclusive absent manifest error) to represent its cost of funds plus the Applicable Margin at such time used to determine interest applicable to Eurodollar Revolving Loans) and such interest shall be due and payable on the date when such reimbursement is payable; provided that, if the applicable Borrower fails to reimburse such LC Disbursement when due pursuant to paragraph (e) of this Section 2.05, then Section 2.12(c) shall apply.  Interest accrued pursuant to this paragraph shall be for the account of the applicable Issuing Bank, except that interest accrued on and after the date of payment by any Lender pursuant paragraph (e) of this Section 2.05 to reimburse such Issuing Bank shall be for the account of such Lender to the extent of such payment.

(i)    Replacement of Issuing Bank

(i)    Any Issuing Bank may be replaced at any time by written agreement among the Company, the Administrative Agent, the replaced Issuing Bank and the successor Issuing Bank.  The Administrative Agent shall notify the Lenders of any such replacement of an Issuing Bank.  At the time any such replacement shall become effective, the Company shall pay all unpaid fees accrued for the account of the replaced Issuing Bank pursuant to Section 2.11(b).  From and after the effective date of any such replacement, (A) the successor Issuing Bank shall have all the rights and obligations of an Issuing Bank under this Agreement with respect to Letters of Credit to be issued thereafter and (B) references herein to the term “Issuing Bank” shall be deemed to refer to such successor or to any previous Issuing Bank, or to such successor and all previous Issuing Banks, as the context shall require.  After the replacement of an Issuing Bank hereunder, the replaced Issuing Bank shall remain a party hereto and shall continue to have all the rights and obligations of an Issuing Bank under this Agreement with respect to Letters of Credit issued by it prior to such replacement, but shall not be required to issue additional Letters of Credit.

(ii)    Subject to the appointment and acceptance of a successor Issuing Bank, any Issuing Bank may resign as an Issuing Bank at any time upon 30 days’ prior written notice to the Administrative Agent, the Company and the Lenders, in which case, such Issuing Bank shall be replaced in accordance with Section 2.05(i)(i).

(j)    Cash Collateralization.  If (i) any Event of Default shall occur and be continuing, on the Business Day that the Company receives notice from the Administrative Agent or the Required Lenders (or, if the maturity of the Loans has been accelerated, Lenders with LC Exposure representing greater than 50% of the total LC Exposure) demanding that the Borrowers cash collateralize the outstanding LC Exposure pursuant to this paragraph, (ii) any Borrower is required to cash collateralize the excess attributable to an LC Exposure in connection with any prepayment pursuant to Section 2.10(c) or cash collateralize outstanding Letters of Credit pursuant to Section 2.10(d), or (iii) any Borrower is required to cash collateralize a Defaulting Lender’s LC Exposure pursuant to Section 2.19, then the applicable

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Credit Agreement


 

 

Borrower shall deposit in an account with the Administrative Agent, in the name of the Administrative Agent and for the benefit of the Lenders, an amount in cash (in the applicable currency) equal to such LC Exposure or the excess attributable to such LC Exposure, as the case may be, as of such date, in each case, plus any accrued and unpaid interest thereon; provided that the obligation to deposit such cash collateral shall become effective immediately, and such deposit shall become immediately due and payable, without demand or other notice of any kind, upon the occurrence of any Event of Default with respect to any Borrower described in clause (h) or (i) of Section 7.01.  Such deposit shall be held by the Administrative Agent as collateral for the payment and performance of the obligations of the Borrowers under this Agreement.  The Administrative Agent shall have exclusive dominion and control, including the exclusive right of withdrawal, over such account.  Other than any interest earned on the investment of such deposits, which investments shall be made at the option and sole discretion of the Administrative Agent and at the applicable Borrower’s risk and expense, such deposits shall not bear interest.  Interest or profits, if any, on such investments shall accumulate in such account.  Moneys in such account shall be applied by the Administrative Agent to reimburse each Issuing Bank for LC Disbursements for which it has not been reimbursed and, to the extent not so applied, shall be held for the satisfaction of the reimbursement obligations of the applicable Borrower for the LC Exposure at such time or, if the maturity of the Loans has been accelerated (but subject to the consent of Lenders with LC Exposure representing greater than 50% of the total LC Exposure), be applied to satisfy other obligations of the applicable Borrower under this Agreement.  If the applicable Borrower is required to provide an amount of cash collateral hereunder as a result of the occurrence of an Event of Default or pursuant to Section 2.19 as the result of a Defaulting Lender, and the Borrowers are not otherwise required to pay to the Administrative Agent the excess attributable to an LC Exposure in connection with any prepayment pursuant to Section 2.10(c), then such amount (to the extent not applied as aforesaid) shall be returned to the applicable Borrower within three Business Days after all Events of Default have been cured or waived or the events giving rise to such cash collateralization pursuant to Section 2.19 have been satisfied or resolved.

(k)    Existing Letters of Credit.  On the Effective Date, each of the letters of credit listed on Schedule 2.05 shall be deemed to have been issued as Letters of Credit under this Agreement by the Issuing Bank specified for such Letter of Credit on Schedule 2.05, without payment of any fees otherwise due upon the issuance of a Letter of Credit, and such Issuing Bank shall be deemed, without further action by any party hereto, to have sold to each Lender, and each Lender shall be deemed, without further action by any party hereto, to have purchased from such Issuing Bank, a participation, to the extent of such Lender’s Applicable Percentage, in such Letter of Credit.

Section 2.06    Funding of Borrowings.  (a) Each Lender shall make each Loan to be made by it hereunder on the proposed date thereof solely by wire transfer of immediately available funds by 12:00 noon, New York City time, to the account of the Administrative Agent most recently designated by it for such purpose by notice to the Lenders.  The Administrative Agent will make such Loans available to the applicable Borrower by promptly crediting the funds so received, in like funds, to an account of the applicable Borrower maintained with the Administrative Agent in New York City and designated by the Company in the applicable Borrowing Request; provided that ABR Revolving Loans made to finance the reimbursement of

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Credit Agreement


 

 

an LC Disbursement as provided in Section 2.05(e) shall be remitted by the Administrative Agent to the Issuing Bank.

(b)    Unless the Administrative Agent shall have received notice from a Lender prior to the proposed date of any Borrowing that such Lender will not make available to the Administrative Agent such Lender’s share of such Borrowing, the Administrative Agent may assume that such Lender has made such share available on such date in accordance with clause (a) of this Section 2.06 and may, in reliance upon such assumption, make available to the applicable Borrower a corresponding amount.  In such event, if a Lender has not in fact made its share of the applicable Borrowing available to the Administrative Agent, then the applicable Lender and the applicable Borrower severally agree to pay to the Administrative Agent forthwith on demand such corresponding amount with interest thereon, for each day from and including the date such amount is made available to the applicable Borrower to but excluding the date of payment to the Administrative Agent, at (i) in the case of such Lender, the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation or (ii) in the case of the applicable Borrower, the interest rate applicable to ABR Loans.  If such Lender pays such amount to the Administrative Agent, then such amount shall constitute such Lender’s Loan included in such Borrowing.

Section 2.07    Interest Elections.  (a) Each Revolving Borrowing initially shall be of the Type specified in the applicable Borrowing Request and, in the case of a Eurodollar Revolving Borrowing, shall have an initial Interest Period as specified in such Borrowing Request.  Thereafter, the Company may elect to convert such Borrowing to a different Type or to continue such Borrowing and, in the case of a Eurodollar Revolving Borrowing, may elect Interest Periods therefor, all as provided in this Section 2.07.  The Company may elect different options with respect to different portions of the affected Borrowing, in which case each such portion shall be allocated ratably among the Lenders holding the Loans comprising such Borrowing, and the Loans comprising each such portion shall be considered a separate Borrowing.    

(b)    To make an election pursuant to this Section 2.07, the Company shall notify the Administrative Agent of such election by telephone by the time that a Borrowing Request would be required under Section 2.03 if the Company were requesting a Revolving Borrowing of the Type resulting from such election to be made on the effective date of such election.  Each such telephonic Interest Election Request shall be irrevocable and shall be confirmed promptly by hand delivery or telecopy to the Administrative Agent of a written Interest Election Request in a form approved by the Administrative Agent and signed by the Company.

(c)    Each telephonic and written Interest Election Request shall specify the following information in compliance with Section 2.02:

(i)    the Borrowing to which such Interest Election Request applies and, if different options are being elected with respect to different portions thereof, the portions thereof to be allocated to each resulting Borrowing (in which case the information to be specified pursuant to clauses (iii) and (iv) below shall be specified for each resulting Borrowing);

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(ii)    the effective date of the election made pursuant to such Interest Election Request, which shall be a Business Day;

(iii)    whether the resulting Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing; and

(iv)    if the resulting Borrowing is a Eurodollar Borrowing, the Interest Period to be applicable thereto after giving effect to such election, which shall be a period contemplated by the definition of the term “Interest Period”.

(v)    If any such Interest Election Request requests a Eurodollar Borrowing but does not specify an Interest Period, then the Company shall be deemed to have selected an Interest Period of one month’s duration.

(d)    Promptly following receipt of an Interest Election Request, the Administrative Agent shall advise each Lender of the details thereof and of such Lender’s portion of each resulting Borrowing.

(e)    If the Company fails to deliver a timely Interest Election Request with respect to a Eurodollar Revolving Borrowing prior to the end of the Interest Period applicable thereto, then, unless such Borrowing is repaid as provided herein, at the end of such Interest Period such Borrowing shall be converted to an ABR Borrowing.  Notwithstanding any contrary provision hereof, if an Event of Default has occurred and is continuing and the Administrative Agent, at the request of the Required Lenders, so notifies the Company, then, so long as an Event of Default is continuing (i) no outstanding Revolving Borrowing may be converted to or continued as a Eurodollar Borrowing and (ii) unless repaid, each Eurodollar Revolving Borrowing shall be converted to an ABR Borrowing at the end of the Interest Period applicable thereto.

Section 2.08    Termination and Reduction of Commitments.  (a) Unless previously terminated, the Commitments shall terminate on the Maturity Date.

(b)    The Company may at any time terminate, or from time to time reduce, the Commitments; provided that (i) each reduction of the Commitments shall be in an amount that is an integral multiple of $1,000,000 and not less than $5,000,000 and (ii) the Company shall not terminate or reduce the Commitments if, after giving effect to any concurrent prepayment of the Loans in accordance with Section 2.10, the Total Credit Exposure would exceed the total Commitments.

(c)    The Company shall notify the Administrative Agent of any election to terminate or reduce the Commitments under paragraph (b) of this Section 2.08 at least three Business Days prior to the effective date of such termination or reduction, specifying such election and the effective date thereof.  Promptly following receipt of any notice, the Administrative Agent shall advise the Lenders of the contents thereof.  Each notice delivered by the Company pursuant to this Section 2.08 shall be irrevocable; provided that a notice of termination of the Commitments delivered by the Company may state that such notice is conditioned upon the effectiveness of other credit facilities, in which case such notice may be

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revoked by the Company (by notice to the Administrative Agent on or prior to the specified effective date) if such condition is not satisfied.  Any termination or reduction of the Commitments shall be permanent.  Each reduction of the Commitments shall be made ratably among the Lenders in accordance with their respective Commitments.

Section 2.09    Repayment of Loans; Evidence of Debt.  (a) Each Borrower hereby unconditionally promises to pay to the Administrative Agent for the account of each Lender the then unpaid principal amount of each Loan on the Maturity Date.

(b)    Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of each Borrower to such Lender resulting from each Loan made by such Lender to such Borrower, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder.

(c)    The Administrative Agent shall maintain accounts in which it shall record (i) the amount of each Loan made hereunder, the Class and Type thereof and the Interest Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from each Borrower to each Lender hereunder and (iii) the amount of any sum received by the Administrative Agent hereunder from a Borrower for the account of the Lenders and each Lender’s share thereof.

(d)    The entries made in the accounts maintained pursuant to paragraph (b) or (c) of this Section 2.09 shall be prima facie evidence of the existence and amounts of the obligations recorded therein; provided that the failure of any Lender or the Administrative Agent to maintain such accounts or any error therein shall not in any manner affect the obligation of each Borrower to repay the Loans in accordance with the terms of this Agreement.

(e)    Any Lender may request that Loans made by it be evidenced by a promissory note.  In such event, the applicable Borrower shall prepare, execute and deliver to such Lender a promissory note payable to such Lender (or, if requested by such Lender, to such Lender and its registered assigns) and in a form approved by the Administrative Agent.  Thereafter, the Loans evidenced by such promissory note and interest thereon shall at all times (including after assignment pursuant to Section 10.04) be represented by one or more promissory notes in such form payable to the order of the payee named therein (or, if such promissory note is a registered not, to such payee and its registered assigns).

Section 2.10    Prepayment of Loans.  (a) Subject to any breakage costs payable pursuant to Section 2.15, each Borrower shall have the right at any time and from time to time to prepay any Borrowing made to it in whole or in part, subject to prior notice in accordance with paragraph (b) of this Section 2.10.

(b)    The Company, on behalf of itself, Expro-Intl. or MOCL, shall notify the Administrative Agent by telephone (confirmed by telecopy) of any prepayment pursuant to Section 2.10(a), (i) in the case of prepayment of a Eurodollar Revolving Borrowing, not later than 11:00 a.m., New York City time, three Business Days before the date of prepayment or (ii) in the case of prepayment of an ABR Revolving Borrowing, not later than 11:00 a.m., New York City time, one Business Day before the date of prepayment.  Each such notice shall be

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Credit Agreement


 

 

irrevocable and shall specify the prepayment date and the principal amount of each Borrowing or portion thereof to be prepaid and, in the case of a mandatory prepayment, a reasonably detailed calculation of the amount of such prepayment.  Promptly following receipt of any such notice, the Administrative Agent shall advise the Lenders of the contents thereof; provided that, if a notice of prepayment is given in connection with a conditional notice of termination of the Commitments as contemplated by Section 2.08, then such notice of prepayment may be revoked if such notice of termination is revoked in accordance with Section 2.08.  Promptly following receipt of any such notice relating to a Revolving Borrowing, the Administrative Agent shall advise the Lenders of the contents thereof.  Each partial prepayment of any Revolving Borrowing shall be in an amount that would be permitted in the case of an advance of a Revolving Borrowing of the same Type as provided in Section 2.02.  Each prepayment of a Revolving Borrowing shall be applied ratably to the Loans included in the prepaid Borrowing.  Prepayments shall be accompanied by accrued interest to the extent required by Section 2.12 and breakage costs to the extent required by Section 2.15.

(c)    If at any time (including, without limitation, on any Computation Date) the Total Credit Exposure exceeds the total Commitments, then, the Borrowers shall, without notice or demand, immediately (i) prepay the Borrowings in an aggregate principal amount equal to such excess, and (ii) if any excess remains (or would remain) after prepaying all of the Borrowings as a result of an LC Exposure, cash collateralize such excess as provided in Section 2.05(j).  Each prepayment of Borrowings pursuant to this Section 2.10(c) shall be applied ratably to the Loans included in the prepaid Borrowings.  Prepayments made pursuant to this Section 2.10(c) shall be accompanied by accrued interest to the extent required by Section 2.12 and breakage costs to the extent required by Section 2.15.

(d)    If at any time (including, without limitation, on any Computation Date) the aggregate LC Exposure exceeds the sum of all Letter of Credit Commitments then in effect, the Borrowers shall, without notice or demand, immediately replace outstanding Letters of Credit or cash collateralize outstanding Letters of Credit in accordance with the procedures set forth in Section 2.05(j), in an aggregate amount sufficient to eliminate such excess.

(e)    Prior to the Investment Grade Rating Date, if upon the consummation of any Disposition pursuant to Section 6.11(c)(to the extent the fair market value of the Property subject to the Casualty Event exceeds $25,000,000) or (e), the Consolidated Leverage Ratio exceeds 2.75 to 1.00 (calculated on  pro forma basis using (i) Consolidated Total Debt as of such day and (ii) Consolidated EBITDA for the period of four consecutive fiscal quarters most recently ended for which financial statements have been delivered pursuant to Section 5.01(a) or Section 5.01(b)), then, the Borrowers shall, without notice or demand, prepay the Borrowings in an aggregate amount necessary so that after giving effect to such prepayment, the Consolidated Leverage Ratio is less than or equal to 2.75 to 1.00 (calculated on pro forma basis as set forth above).  Such prepayment shall be due on the date that is three Business Days after the date of the realization or receipt of the cash proceeds of such Disposition.  Each prepayment of Borrowings pursuant to this Section 2.10(e) shall be applied ratably to the Loans included in the prepaid Borrowings.  Prepayments made pursuant to this Section 2.10(e) shall be accompanied by accrued interest to the extent required by Section 2.12 and breakage costs to the extent required by Section 2.15 Notwithstanding the foregoing, if any prepayment of Eurodollar Borrowings is required to be made under this Section 2.05(e), prior to the last day of the Interest

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Period therefor, the Borrowers may, in their sole discretion, deposit the amount of any such prepayment otherwise required to be made thereunder with the Administrative Agent until the last day of such Interest Period, at which time the Administrative Agent shall be authorized (without any further action by or notice to or from the Borrowers or any other Loan Party) to apply such amount to the prepayment of such Loans in accordance with this Section 2.05(e).

Section 2.11    Fees.  (a) The Company agrees to pay to the Administrative Agent for the account of each Lender a facility fee, which shall accrue at the Applicable Rate on the daily amount of the Commitment of such Lender (whether used or unused) during the period from and including the Effective Date to but excluding the date on which such Commitment terminates; provided that, if such Lender continues to have any Credit Exposure after its Commitment terminates, then such facility fee shall continue to accrue on the daily amount of such Lender’s Credit Exposure from and including the date on which its Commitment terminates to but excluding the date on which such Lender ceases to have any Credit Exposure.

(b)    The Company agrees to pay (i) to the Administrative Agent for the account of each Lender a participation fee with respect to its participations in Letters of Credit, which shall accrue at the same Applicable Rate used to determine the interest rate applicable to Eurodollar Revolving Loans on the average daily amount of such Lender’s LC Exposure (excluding any portion thereof attributable to unreimbursed LC Disbursements) during the period from and including the Effective Date to but excluding the later of the date on which such Lender’s Commitment terminates and the date on which such Lender ceases to have any LC Exposure, and (ii) to each Issuing Bank a fronting fee, which shall accrue at the rate of 0.20% per annum on the average daily amount of the LC Exposure of such Issuing Bank (excluding any portion thereof attributable to unreimbursed LC Disbursements) during the period from and including the Effective Date to but excluding the later of the date of termination of the Commitments and the date on which there ceases to be any LC Exposure of such Issuing Bank, as well as such Issuing Bank’s standard fees with respect to the issuance, amendment, renewal or extension of any Letter of Credit or processing of drawings thereunder.    

(c)    The Company agrees to pay to the Administrative Agent, for its own account, fees payable in the amounts and at the times separately agreed upon between the Company and the Administrative Agent.

(d)    Participation fees and fronting fees accrued through and including the last day of March, June, September and December of each year shall be payable on the third Business Day following such last day, commencing on the first such date to occur after the Effective Date; provided that all such fees shall be payable on the date on which the Commitments terminate and any such fees accruing after the date on which the Commitments terminate shall be payable on demand.  Any other fees payable to an Issuing Bank pursuant to paragraph (b) above shall be payable within ten days after demand.  Accrued facility fees shall be payable in arrears on the last day of March, June, September and December of each year and on the date on which the Commitments terminate, commencing on the first such date to occur after the Effective Date; provided that any fees accruing after the date on which the Commitments terminate shall be payable on demand.  All fees payable hereunder shall be computed on the basis of a year of 365 days (or 366 days in a leap year) and shall be payable for the actual number of days elapsed (including the first day but excluding the last day).  All fees

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payable hereunder shall be paid on the dates due, in immediately available funds, to the Administrative Agent (or to the applicable Issuing Bank, in the case of fees payable to it) for distribution, in the case of facility fees and participation fees, to the Lenders.  Fees paid hereunder shall not be refundable under any circumstances.  For purposes of calculating participation fees and fronting fees pursuant to Section 2.11(b), the amount of LC Exposure on any day shall be the Dollar Equivalent thereof on such day, determined using the Exchange Rate on the first Business Day of the calendar month in which such day falls.

Section 2.12    Interest.  (a) The Loans comprising each ABR Borrowing shall bear interest at the Alternate Base Rate plus the Applicable Rate.

(b)    The Loans comprising each Eurodollar Borrowing shall bear interest at the Adjusted LIBO Rate for the Interest Period in effect for such Borrowing plus the Applicable Rate.

(c)    Notwithstanding the foregoing, if any principal of or interest on any Loan or any fee or other amount payable by the applicable Borrower hereunder is not paid when due, whether at stated maturity, upon acceleration or otherwise, such overdue amount shall bear interest, after as well as before judgment, at a rate per annum equal to (i) in the case of overdue principal of any Loan, 2% plus the rate otherwise applicable to such Loan as provided in the preceding paragraphs of this Section 2.12 or (ii) in the case of any other amount, 2% plus the rate applicable to ABR Loans as provided in paragraph (a) of this Section 2.12.

(d)    Accrued interest on each Loan shall be payable in arrears on each Interest Payment Date for such Loan and, in the case of Revolving Loans, upon termination of the Commitments; provided that (i) interest accrued pursuant to paragraph (c) of this Section 2.12 shall be payable on demand, (ii) in the event of any repayment or prepayment of any Loan (other than a prepayment of an ABR Revolving Loan prior to the end of the Availability Period), accrued interest on the principal amount repaid or prepaid shall be payable on the date of such repayment or prepayment and (iii) in the event of any conversion of any Eurodollar Revolving Loan prior to the end of the current Interest Period therefor, accrued interest on such Loan shall be payable on the effective date of such conversion.

(e)    All interest hereunder shall be computed on the basis of a year of 360 days, except that interest computed by reference to the Alternate Base Rate at times when the Alternate Base Rate is based on the Prime Rate shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and in each case shall be payable for the actual number of days elapsed (including the first day but excluding the last day).  The applicable Alternate Base Rate, Adjusted LIBO Rate or LIBO Rate shall be determined by the Administrative Agent, and such determination shall be conclusive absent manifest error.

Section 2.13    Alternate Rate of Interest; IllegalityIf prior to the commencement of any Interest Period for a Eurodollar Borrowing:

(a)    If prior to the commencement of any Interest Period for a Eurodollar Borrowing:

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(i)    the Administrative Agent determines (which determination shall be conclusive absent manifest error) that adequate and reasonable means do not exist for ascertaining the Adjusted LIBO Rate or the LIBO Rate, as applicable, for such Interest Period; or

(ii)    the Administrative Agent is advised by the Required Lenders that the Adjusted LIBO Rate or the LIBO Rate, as applicable, for such Interest Period will not adequately and fairly reflect the cost to such Lenders (or Lender) of making or maintaining their Loans (or its Loan) included in such Borrowing for such Interest Period;

then the Administrative Agent shall give notice thereof to the Company and the Lenders by telephone or telecopy as promptly as practicable thereafter and, until the Administrative Agent notifies the Company and the Lenders that the circumstances giving rise to such notice no longer exist, (A) any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective, and (B) if any Borrowing Request requests a Eurodollar Borrowing, such Borrowing shall be made as an ABR Borrowing.

(b)    If at any time the Administrative Agent determines (which determination shall be conclusive absent manifest error) that (i) the circumstances set forth in clause (a)(i) have arisen and such circumstances are unlikely to be temporary or (ii) the circumstances set forth in clause (a)(i) have not arisen but the supervisor for the administrator of the LIBO Screen Rate or a Governmental Authority having jurisdiction over the Administrative Agent has made a public statement identifying a specific date after which the LIBO Screen Rate shall no longer be used for determining interest rates for loans, then the Administrative Agent and the Company shall endeavor to establish an alternate rate of interest to the LIBO Rate that gives due consideration to the then prevailing market convention for determining a rate of interest for syndicated loans in the United States at such time, and shall enter into an amendment to this Agreement to reflect such alternate rate of interest and such other related changes to this Agreement as may be applicable.  Notwithstanding anything to the contrary in Section 10.02, such amendment shall become effective without any further action or consent of any other party to this Agreement so long as the Administrative Agent shall not have received, within five Business Days of the date notice of such alternate rate of interest is provided to the Lenders, a written notice from the Required Lenders stating that such Required Lenders object to such amendment.  Until an alternate rate of interest shall be determined in accordance with this clause (b) (but, in the case of the circumstances described in clause (ii) of the first sentence of this Section 2.13(b), only to the extent the LIBO Screen Rate for such Interest Period is not available or published at such time on a current basis), (x) any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective and (y) if any Borrowing Request requests a Eurodollar Borrowing, such Borrowing shall be made as an ABR Borrowing; provided that, if such alternate rate of interest shall be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement.

(c)    If any Lender determines that any Governmental Requirement has made it unlawful, or that any Governmental Authority has asserted that it is unlawful, for any Lender or its applicable lending office to make, maintain, or fund Loans whose interest is determined by reference to the LIBO Rate, or to determine or charge interest rates based upon the LIBO Rate, or any Governmental Authority has imposed material restrictions on the authority of such Lender

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to purchase or sell, or to take deposits of, Dollars in the London interbank market, then, upon notice thereof by such Lender to the Company (through the Administrative Agent), (a) any obligation of such Lender to make or continue Eurodollar Loans or to convert ABR Loans to Eurodollar Loans shall be suspended, and (b) if such notice asserts the illegality of such Lender making or maintaining ABR Loans the interest rate on which is determined by reference to the LIBO Rate component of the ABR, the interest rate on which ABR Loans of such Lender shall, if necessary to avoid such illegality, be determined by the Administrative Agent without reference to the LIBO Rate component of the ABR, in each case until such Lender notifies the Administrative Agent and the Borrower that the circumstances giving rise to such determination no longer exist.  Upon receipt of such notice, (i) the Borrower shall, upon demand from such Lender (with a copy to the Administrative Agent), prepay or, if applicable, convert all Eurodollar Loans of such Lender to ABR Loans (the interest rate on which ABR Loans of such Lender shall, if necessary to avoid such illegality, be determined by the Administrative Agent without reference to the LIBO Rate component of the ABR), either on the last day of the Interest Period therefor, if such Lender may lawfully continue to maintain such Eurodollar Loans to such day, or immediately, if such Lender may not lawfully continue to maintain such Eurodollar Loans and (ii) if such notice asserts the illegality of such Lender determining or charging interest rates based upon the LIBO Rate, the Administrative Agent shall during the period of such suspension compute the ABR applicable to such Lender without reference to the LIBO Rate component thereof until the Administrative Agent is advised in writing by such Lender that it is no longer illegal for such Lender to determine or charge interest rates based upon the LIBO Rate.  Upon any such prepayment or conversion, the Borrower shall also pay accrued interest on the amount so prepaid or converted, together with any additional amounts required pursuant to Section 2.15.

Section 2.14    Increased Costs.  (a) If any Change in Law shall:

(i)    impose, modify or deem applicable any reserve, special deposit, liquidity or similar requirement (including any compulsory loan requirement, insurance charge or other assessment) against assets of, deposits with or for the account of, or credit extended by, any Lender (except any such reserve requirement reflected in the Adjusted LIBO Rate) or any Issuing Bank; or

(ii)    impose on any Lender or any Issuing Bank or the London interbank market any other condition, cost or expense (other than Taxes) affecting this Agreement or Loans made by such Lender or any Letter of Credit or participation therein; or

(iii)    subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (b) through (d) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its loans, loan principal, letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto;

and the result of any of the foregoing shall be to increase the cost to such Lender or such other Recipient of making, continuing, converting or maintaining any Loan (or of maintaining its obligation to make any such Loan) or to increase the cost to such Lender, such Issuing Bank or such other Recipient of participating in, issuing or maintaining any Letter of Credit or to reduce the amount of any sum received or receivable by such Lender, such Issuing Bank or such other Recipient hereunder (whether of principal, interest or otherwise), then the applicable Borrower

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will pay to such Lender, such Issuing Bank or such other Recipient, as the case may be, such additional amount or amounts as will compensate such Lender, such Issuing Bank or such other Recipient, as the case may be, for such additional costs incurred or reduction suffered.

(b)    If any Lender or any Issuing Bank determines that any Change in Law regarding capital or liquidity requirements has or would have the effect of reducing the rate of return on such Lender’s or such Issuing Bank’s capital or on the capital of such Lender’s or such Issuing Bank’s holding company, if any, as a consequence of this Agreement or the Loans made by, or participations in Letters of Credit held by, such Lender, or the Letters of Credit issued by such Issuing Bank, to a level below that which such Lender or such Issuing Bank or such Lender’s or such Issuing Bank’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s or such Issuing Bank’s policies and the policies of such Lender’s or such Issuing Bank’s holding company with respect to capital adequacy and liquidity), then from time to time the applicable Borrower will pay to such Lender or such Issuing Bank, as the case may be, such additional amount or amounts as will compensate such Lender or such Issuing Bank or such Lender’s or such Issuing Bank’s holding company for any such reduction suffered.

(c)    A certificate of a Lender or an Issuing Bank setting forth the amount or amounts necessary to compensate such Lender or such Issuing Bank or its holding company, as the case may be, as specified in paragraph (a) or (b) of this Section 2.14 shall be delivered to the Company and shall be conclusive absent manifest error.  The applicable Borrower shall pay such Lender or the applicable Issuing Bank, as the case may be, the amount shown as due on any such certificate within ten days after receipt thereof. 

(d)    Failure or delay on the part of any Lender or any Issuing Bank to demand compensation pursuant to this Section 2.14 shall not constitute a waiver of such Lender’s or such Issuing Bank’s right to demand such compensation; provided that the applicable Borrower shall not be required to compensate a Lender or any Issuing Bank pursuant to this Section 2.14 for any increased costs or reductions incurred more than 270 days prior to the date that such Lender or such Issuing Bank, as the case may be, notifies the Company of the Change in Law giving rise to such increased costs or reductions and of such Lender’s or such Issuing Bank’s intention to claim compensation therefor; provided,  further, that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the 270-day period referred to above shall be extended to include the period of retroactive effect thereof.

Section 2.15    Break Funding Payments.  In the event of (a) the payment of any principal of any Eurodollar Loan other than on the last day of an Interest Period applicable thereto (including as a result of an Event of Default), (b) the conversion of any Eurodollar Loan other than on the last day of the Interest Period applicable thereto, (c) the failure to borrow, convert, continue or prepay any Eurodollar Loan on the date specified in any notice delivered pursuant hereto (regardless of whether such notice may be revoked under Section 2.10(b) and is revoked in accordance therewith), or (d) the assignment of any Eurodollar Loan other than on the last day of the Interest Period applicable thereto as a result of a request by the Company pursuant to Section 2.18, then, in any such event, the applicable Borrower shall compensate each Lender for the loss, cost and expense attributable to such event.  In the case of a Eurodollar Loan, such loss, cost or expense to any Lender shall be deemed to include an amount determined by such

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Lender to be the excess, if any, of (i) the amount of interest which would have accrued on the principal amount of such Loan had such event not occurred, at the Adjusted LIBO Rate that would have been applicable to such Loan, for the period from the date of such event to the last day of the then current Interest Period therefor (or, in the case of a failure to borrow, convert or continue, for the period that would have been the Interest Period for such Loan), over (ii) the amount of interest which would accrue on such principal amount for such period at the interest rate which such Lender would bid were it to bid, at the commencement of such period, for dollar deposits of a comparable amount and period from other banks in the eurodollar market.  A certificate of any Lender setting forth any amount or amounts that such Lender is entitled to receive pursuant to this Section 2.15 shall be delivered to the Company and shall be conclusive absent manifest error.  The applicable Borrower shall pay such Lender the amount shown as due on any such certificate within ten days after receipt thereof.

Section 2.16    Payments Free of Taxes.  (a) Any and all payments by or on account of any obligation of any Loan Party under this Agreement or any other Loan Document shall be made without deduction or withholding for any Taxes, except as required by applicable law.  If any applicable law (as determined in the good faith discretion of an applicable withholding agent) requires the deduction or withholding of any Tax from any such payment by a withholding agent, then the applicable withholding agent shall be entitled to make such deduction or withholding and shall timely pay the full amount deducted or withheld to the relevant Governmental Authority in accordance with applicable law and, if such Tax is an Indemnified Tax, then the sum payable by the applicable Loan Party shall be increased as necessary so that after such deduction or withholding has been made (including such deductions and withholdings applicable to additional sums payable under this Section 2.16) the applicable Recipient receives an amount equal to the sum it would have received had no such deduction or withholding been made.

(b)    Payment of Other Taxes by the Loan Parties.  Each Loan Party shall timely pay to the relevant Governmental Authority in accordance with applicable law, or at the option of the Administrative Agent timely reimburse it for, Other Taxes.

(c)    Evidence of Payments.  As soon as practicable after any payment of Taxes by any Loan Party to a Governmental Authority pursuant to this Section 2.16, the Company shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(d)    Indemnification by the Loan Parties.  The Loan Parties shall jointly and severally indemnify each Recipient, within ten days after demand therefor, for the full amount of any Indemnified Taxes (including Indemnified Taxes imposed or asserted on or attributable to amounts payable under this Section 2.16) payable or paid by such Recipient or required to be withheld or deducted from a payment to such Recipient and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority.  A certificate as to the amount of such payment or liability delivered to the Company by a Lender (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.

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(e)    Indemnification by the Lenders.  Each Lender shall severally indemnify the Administrative Agent, within ten days after demand therefor, for (i) any Indemnified Taxes attributable to such Lender (but only to the extent that the Loan Parties have not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of any Loan Party to do so), (ii) any Taxes attributable to such Lender’s failure to comply with the provisions of Section 10.04(c) relating to the maintenance of a Participant Register and (iii) any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Administrative Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority.  A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error.  Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender under this Agreement or any other Loan Document or otherwise payable by the Administrative Agent to the Lender from any other source against any amount due to the Administrative Agent under this clause (e).

(f)    Status of Lenders.  (i) Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under this Agreement or any other Loan Document shall deliver to the Company and the Administrative Agent, at the time or times reasonably requested by the Company, on behalf of itself, Expro-Intl. or MOCL, or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Company or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding.  In addition, any Lender, if reasonably requested by the Company or the Administrative Agent, shall deliver such other documentation prescribed by applicable law or reasonably requested by the Company or the Administrative Agent as will enable the Company or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements.  Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Section 2.16(f)(ii)(A),  (ii)(B) and (ii)(D) below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

(ii)    Without limiting the generality of the foregoing, in the event that the Company is a U.S. Person,

(A)    any Lender that is a U.S. Person shall deliver to the Company and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Company or the Administrative Agent), an executed IRS Form W-9 certifying that such Lender is exempt from U.S. Federal backup withholding tax;

(B)    any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Company and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender

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becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Company or the Administrative Agent), whichever of the following is applicable:

(1)    in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under this Agreement or any other Loan Document, an executed IRS Form W-8BEN E or IRS Form W-8BEN establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “interest” article of such tax treaty and (y) with respect to any other applicable payments under this Agreement or any other Loan Document, IRS Form W-8BEN E or IRS Form W-8BEN establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

(2)    in the case of a Foreign Lender claiming that its extension of credit will generate U.S. effectively connected income, an executed IRS Form W-8ECI;

(3)    in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code, (x) a certificate substantially in the form of Exhibit C-1 to the effect that such Foreign Lender is not a “bank” within the meaning of Section 881(c)(3)(A) of the Code, a “ten percent shareholder” of any Borrower within the meaning of Section 881(c)(3)(B) of the Code, or a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code (a “U.S. Tax Compliance Certificate”) and (y) an executed IRS Form W-8BEN E or IRS Form W-8BEN; or

(4)    to the extent a Foreign Lender is not the beneficial owner, an executed IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W‑8BEN E, IRS Form W-8BEN, a U.S. Tax Compliance Certificate substantially in the form of Exhibit C-2 or Exhibit C-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit C-4 on behalf of each such direct and indirect partner;

(C)    any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Company and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Company or the Administrative Agent), executed originals of any other form prescribed by applicable law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be prescribed by applicable law to permit the Company or the Administrative Agent to determine the withholding or deduction required to be made; and

(D)    if a payment made to a Lender under this Agreement or any other Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such

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Lender shall deliver to the Company and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Company or the Administrative Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by the Company or the Administrative Agent as may be necessary for any Borrower and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment.  Solely for purposes of this clause (D), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.

Each Lender agrees that if any form or certification it previously delivered expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or promptly notify the Company and the Administrative Agent in writing of its legal inability to do so.

(g)    Treatment of Certain Refunds.  If any party determines, in its sole discretion exercised in good faith, that it has received a refund of any Taxes as to which it has been indemnified pursuant to this Section 2.16 (including by the payment of additional amounts pursuant to this Section 2.16), it shall pay to the indemnifying party an amount equal to such refund (but only to the extent of indemnity payments made under this Section 2.16 with respect to the Taxes giving rise to such refund), net of all out-of-pocket expenses (including Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund).  Such indemnifying party, upon the request of such indemnified party, shall repay to such indemnified party the amount paid over pursuant to this clause (g) (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) in the event that such indemnified party is required to repay such refund to such Governmental Authority.  Notwithstanding anything to the contrary in this clause (g), in no event will the indemnified party be required to pay any amount to an indemnifying party pursuant to this clause (g) the payment of which would place the indemnified party in a less favorable net after-Tax position than the indemnified party would have been in if the Tax subject to indemnification and giving rise to such refund had not been deducted, withheld or otherwise imposed and the indemnification payments or additional amounts with respect to such Tax had never been paid.  This paragraph shall not be construed to require any indemnified party to make available its Tax returns (or any other information relating to its Taxes that it deems confidential) to the indemnifying party or any other Person.

(h)    Survival.  Each party’s obligations under this Section 2.16 shall survive the resignation or replacement of the Administrative Agent or any assignment of rights by, or the replacement of, a Lender, the termination of the Commitments and the repayment, satisfaction or discharge of all obligations under any Loan Document.

(i)    Defined Terms.  For purposes of this Section 2.16, the term “Lender” includes any Issuing Bank and the term “applicable law” includes FATCA.

Section 2.17    Payments Generally; Pro Rata Treatment; Sharing of Set-offs.  (a) Each Borrower shall make each payment required to be made by it hereunder (whether of principal, interest, fees or reimbursement of LC Disbursements, or of amounts payable under

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Sections 2.14,  2.15 or 2.16, or otherwise) prior to 12:00 noon, New York City time, on the date when due, in immediately available funds, without set-off or counterclaim.  Any amounts received after such time on any date may, in the discretion of the Administrative Agent, be deemed to have been received on the next succeeding Business Day for purposes of calculating interest thereon.  All such payments shall be made to the Administrative Agent at its offices at 270 Park Avenue, New York, New York, except payments to be made directly to an Issuing Bank as expressly provided herein and except that payments pursuant to Sections 2.14,  2.15 or 2.16 and 10.03 shall be made directly to the Persons entitled thereto.  The Administrative Agent shall distribute in like funds as those received any such payments received by it for the account of any other Person to the appropriate recipient promptly following receipt thereof.  If any payment hereunder shall be due on a day that is not a Business Day, the date for payment shall be extended to the next succeeding Business Day, and, in the case of any payment accruing interest, interest thereon shall be payable for the period of such extension.  Except as set forth in Section 2.05, all payments hereunder shall be made in dollars.

(b)    If at any time insufficient funds are received by and available to the Administrative Agent to pay fully all amounts of principal, unreimbursed LC Disbursements, interest and fees then due hereunder, such funds shall be applied (i) first, towards payment of interest and fees then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of interest and fees then due to such parties, and (ii) second, towards payment of principal and unreimbursed LC Disbursements then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of principal and unreimbursed LC Disbursements then due to such parties.

(c)    If any Lender shall, by exercising any right of set-off or counterclaim or otherwise, obtain payment in respect of any principal of or interest on any of its Revolving Loans or participations in LC Disbursements resulting in such Lender receiving payment of a greater proportion of the aggregate amount of its Revolving Loans and participations in LC Disbursements and accrued interest thereon than the proportion received by any other Lender, then the Lender receiving such greater proportion shall purchase (for cash at face value) participations in the Revolving Loans and participations in LC Disbursements of other Lenders to the extent necessary so that the benefit of all such payments shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and accrued interest on their respective Revolving Loans and participations in LC Disbursements; provided that (i) if any such participations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations shall be rescinded and the purchase price restored to the extent of such recovery, without interest, and (ii) the provisions of this paragraph shall not be construed to apply to any payment made by any Borrower pursuant to and in accordance with the express terms of this Agreement or any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans or participations in LC Disbursements to any assignee or participant, other than to a Borrower or any Subsidiary or Affiliate thereof (as to which the provisions of this paragraph shall apply).  Each Borrower consents to the foregoing and agrees, to the extent it may effectively do so under applicable law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against such Borrower rights of set-off and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of such Borrower in the amount of such participation.

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(d)    Unless the Administrative Agent shall have received notice from the Company prior to the date on which any payment is due to the Administrative Agent for the account of the Lenders or any Issuing Bank hereunder that the applicable Borrower will not make such payment, the Administrative Agent may assume that the applicable Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Lenders or such Issuing Bank, as the case may be, the amount due.  In such event, if the applicable Borrower has not in fact made such payment, then each of the Lenders or such Issuing Bank, as the case may be, severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Lender or such Issuing Bank with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Administrative Agent, at the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation.

(e)    If any Lender shall fail to make any payment required to be made by it pursuant to Sections 2.05(d) or (e),  2.06(b),  2.17(d) or 10.03(c) then the Administrative Agent may, in its discretion (notwithstanding any contrary provision hereof), (i) apply any amounts thereafter received by the Administrative Agent for the account of such Lender to satisfy such Lender’s obligations to it under such Sections until all such unsatisfied obligations are fully paid, and/or (ii) hold such amounts in a segregated account over which the Administrative Agent shall have exclusive control as cash collateral for, and application to, any future funding obligations of such Lender under any such Section, in the case of each of clauses (i) and (ii) above, in any order as determined by the Administrative Agent in its discretion.

(f)    Notwithstanding the foregoing or anything to the contrary contained herein, (i) if any Defaulting Lender shall have failed to fund all or any portion of any Loan (each such Loan, an “Affected Loan”), each prepayment of Loans by any Borrower under Section 2.10 shall be applied first to such Affected Loan and the principal amount and interest with respect to such payment shall be distributed (x) to each Lender that is not a Defaulting Lender (each, a “Non-Defaulting Lender”) pro rata based on the outstanding principal amount of Affected Loans owing to all Non-Defaulting Lenders, until the principal amount of all Affected Loans has been repaid in full and (y) to the extent of any remaining amount of such prepayment, to each Lender pro rata in accordance with such Lender’s Applicable Percentage, and (ii) each payment made by the applicable Borrower on account of the interest on any Affected Loans shall be distributed to each Non-Defaulting Lender pro rata based on the outstanding principal amount of Affected Loans owing to all Non-Defaulting Lenders.

Section 2.18    Mitigation Obligations; Replacement of Lenders.

(a)    If any Lender requests compensation under Section 2.14, or if any Borrower is required to pay any Indemnified Taxes or additional amounts to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.16, then such Lender shall use reasonable efforts to designate a different lending office for funding or booking its Loans hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Sections 2.14 or 2.16, as the case may be, in the future and (ii) would not subject such Lender to any unreimbursed cost or expense and

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would not otherwise be materially disadvantageous to such Lender.  Each Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in connection with any such designation or assignment.

(b)    If (i) any Lender requests compensation under Section 2.14, (ii) any Borrower is required to pay any Indemnified Taxes or additional amounts to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.16, or (iii) any Lender becomes a Defaulting Lender, then the Company may, at its sole expense and effort, upon notice to such Lender and the Administrative Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject to the restrictions contained in Section 10.04), all its interests, rights (other than its existing rights to payments pursuant to Section 2.14 or Section 2.16) and obligations under this Agreement to an assignee that shall assume such obligations (which assignee may be another Lender, if a Lender accepts such assignment); provided that (i) the Company shall have received the prior written consent of the Administrative Agent (and if a Commitment is being assigned, each Issuing Bank) which consent shall not unreasonably be withheld, (ii) such Lender shall have received payment of an amount equal to the outstanding principal of its Loans and participations in LC Disbursements, accrued interest thereon, accrued fees and all other amounts payable to it hereunder, from the assignee (to the extent of such outstanding principal and accrued interest and fees) or the Company (in the case of all other amounts) and (iii) in the case of any such assignment resulting from a claim for compensation under Section 2.14 or payments required to be made pursuant to Section 2.16, such assignment will result in a reduction in such compensation or payments.  A Lender shall not be required to make any such assignment and delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Company to require such assignment and delegation cease to apply.

Section 2.19    Defaulting Lenders.

Notwithstanding any provision of this Agreement to the contrary, if any Lender becomes a Defaulting Lender, then the following provisions shall apply for so long as such Lender is a Defaulting Lender:

(a)    fees shall cease to accrue on the Commitment of such Defaulting Lender pursuant to Section 2.11(a).

(b)    the Commitment and Credit Exposure of such Defaulting Lender shall not be included in determining whether the Required Lenders have taken or may take any action hereunder (including any consent to any amendment, waiver or other modification pursuant to Section 10.02); provided that this clause (b) shall not apply to the vote of a Defaulting Lender in the case of an amendment, waiver or other modification requiring the consent of such Lender or each Lender affected thereby.

(c)    if any LC Exposure exists at the time such Lender becomes a Defaulting Lender then:

(i)    all or any part of the LC Exposure of such Defaulting Lender shall be reallocated among the non-Defaulting Lenders in accordance with their respective Applicable

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Percentages but only (x) to the extent that such reallocation does not, as to any non-Defaulting Lender, cause such non-Defaulting Lender’s Credit Exposure to exceed its Commitment and (y) the conditions set forth in Section 4.02 are satisfied at such time;

(ii)    if the reallocation described in clause (i) above cannot, or can only partially, be effected, the Borrowers shall within one Business Day following notice by the Administrative Agent, cash collateralize for the benefit of the Issuing Banks only the Borrowers’ obligations corresponding to such Defaulting Lender’s LC Exposure (after giving effect to any partial reallocation pursuant to clause (i) above) in accordance with the procedures set forth in Section 2.05(j) for so long as such LC Exposure is outstanding;

(iii)    if the Borrowers cash collateralize any portion of such Defaulting Lender’s LC Exposure pursuant to clause (ii) above, the Borrowers shall not be required to pay any fees to such Defaulting Lender pursuant to Section 2.11(b) with respect to such Defaulting Lender’s LC Exposure during the period such Defaulting Lender’s LC Exposure is cash collateralized;

(iv)    if the LC Exposure of the non-Defaulting Lenders is reallocated pursuant to clause (i) above, then the fees payable to the Lenders pursuant to Section 2.11(b) shall be adjusted in accordance with such non-Defaulting Lenders’ Applicable Percentages;

(v)    if all or any portion of such Defaulting Lender’s LC Exposure is neither reallocated nor cash collateralized pursuant to clause (i) or (ii) above, then, without prejudice to any rights or remedies of any Issuing Bank or any other Lender hereunder, all facility fees that otherwise would have been payable to such Defaulting Lender (solely with respect to the portion of such Defaulting Lender’s Commitment that was utilized by such LC Exposure) and letter of credit fees payable under Section 2.11(b) with respect to such Defaulting Lender’s LC Exposure shall be payable to the applicable Issuing Banks and to the extent that such LC Exposure is reallocated and/or cash collateralized; and

(vi)    subject to Section 10.17, no reallocation pursuant to clause (i) shall constitute a waiver or release of any claim of any party hereunder against a Defaulting Lender arising from that Lender having become a Defaulting Lender, including any claim of a non-Defaulting Lender as a result of such non-Defaulting Lender’s increase exposure following such reallocation; and

(d)    so long as such Lender is a Defaulting Lender, no Issuing Bank shall be required to issue, amend or increase any Letter of Credit, unless it is satisfied that the related exposure and the Defaulting Lender’s then outstanding LC Exposure will be 100% covered by the Commitments of the non-Defaulting Lenders and/or cash collateral will be provided by the Borrowers in accordance with Section 2.19(c), and LC Exposure related to any newly issued or increased Letter of Credit shall be allocated among non-Defaulting Lenders in a manner consistent with Section 2.19(c)(i) (and such Defaulting Lender shall not participate therein).

If (i) a Bankruptcy Event or a Bail-In Action with respect to a Lender Parent shall occur following the Effective Date and for so long as such event shall continue or (ii) any Issuing Bank has a good faith belief that any Lender has defaulted in fulfilling its obligations under one or

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more other agreements in which such Lender commits to extend credit, such Issuing Bank shall not be required to issue, amend or increase any Letter of Credit, unless such Issuing Bank shall have entered into arrangements with the Borrowers or such Lender, satisfactory to such Issuing Bank, as the case may be, to defease any risk to it in respect of such Lender hereunder.

In the event that the Administrative Agent, the Company, the Issuing Banks each agrees that a Defaulting Lender has adequately remedied all matters that caused such Lender to be a Defaulting Lender, then the LC Exposure of the Lenders shall be readjusted to reflect the inclusion of such Lender’s Commitment and on such date such Lender shall purchase at par such of the Loans of the other Lenders as the Administrative Agent shall determine may be necessary in order for such Lender to hold such Loans in accordance with its Applicable Percentage.

Section 2.20    Commitment Increase.

(a)    Subject to the terms and conditions set forth herein, the Company shall have the right from time to time to cause an increase in the total Commitments of the Lenders (a “Commitment Increase”) by adding to this Agreement one or more additional financial institutions that are not already Lenders hereunder (each, a “New Lender”) or by allowing one or more existing Lenders to increase their respective Commitments; provided that (i) both before and immediately after giving effect to such Commitment Increase, no Default or Event of Default shall have occurred and be continuing as of the effective date of such Commitment Increase (such date, the “Commitment Increase Date”), (ii) no such Commitment Increase shall be in an amount less than $10,000,000, (iii) the aggregate amount of all such Commitment Increases shall not exceed $300,000,000, and after giving effect to all such Commitment Increases, the total Commitments shall not exceed $1,800,000,000, (iv) no Lender’s Commitment shall be increased without such Lender’s prior written consent (which consent may be given or withheld in such Lender’s sole and absolute discretion) and (v) each New Lender and any increase in the Commitment of an existing Lender pursuant to any Commitment Increase shall be subject to the prior written consent of the Administrative Agent and each Issuing Bank (each such consent not to be unreasonably withheld or delayed).

(b)    The Company shall provide the Administrative Agent with written notice (a “Notice of Commitment Increase”) of its intention to increase the total Commitments pursuant to this Section 2.20.  Each such Notice of Commitment Increase shall specify (i) the proposed Commitment Increase Date, which date shall be no earlier than five (5) Business Days after receipt by the Administrative Agent of such Notice of Commitment Increase, (ii) the amount of the requested Commitment Increase, (iii) as applicable, the identity of each New Lender and/or existing Lender that has agreed in writing to increase its Commitment hereunder, and (iv) the amount of the respective Commitments of the then existing Lenders and the New Lenders from and after the Commitment Increase Date.

(c)    On any Commitment Increase Date, the Lenders shall purchase and assume (without recourse or warranty) from the other Lenders (i) Loans, to the extent that there are any Loans then outstanding, and (ii) undivided participation interests in any outstanding LC Exposure, in each case, to the extent necessary to ensure that after giving effect to the Commitment Increase, each Lender has outstanding Loans and participation interests in outstanding LC Exposure equal to its Applicable Percentage of the total Commitments.  Each

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Lender shall make any payment required to be made by it pursuant to the preceding sentence via wire transfer to the Administrative Agent on the Commitment Increase Date.  Each existing Lender shall be automatically deemed to have assigned any outstanding Loans on the Commitment Increase Date and the existing Lenders, each New Lender and the Borrowers each agree to take any further steps reasonably requested by the Administrative Agent, in each case to the extent deemed necessary by the Administrative Agent to effectuate the provisions of the preceding sentences, including, without limitation, the execution and delivery of one or more joinder or similar agreements.  If, on such Commitment Increase Date, any Loans that are Eurodollar Loans have been funded, then the Borrower shall be obligated to pay any breakage fees or costs that are payable pursuant to Section 2.15 in connection with the reallocation of such outstanding Loans to effectuate the provisions of this paragraph.

(d)    Each Commitment Increase shall become effective on the respective Commitment Increase Date and upon such effectiveness: (i) to the extent applicable, the Administrative Agent shall record in the Register each New Lender’s information as provided in the applicable Notice of Commitment Increase and pursuant to an Administrative Questionnaire that shall be executed and delivered by each New Lender to the Administrative Agent on or before such Commitment Increase Date, (ii) Schedule 2.01 shall be amended and restated to set forth all Lenders (including any New Lenders) that will be Lenders hereunder after giving effect to such Commitment Increase (which amended and restated Schedule 2.01 shall be set forth in Annex I to the applicable Notice of Commitment Increase) and the Administrative Agent shall distribute to each Lender (including each New Lender) a copy of such amended and restated Schedule 2.01, and (iii) each New Lender identified on the Notice of Commitment Increase for such Commitment Increase shall be a “Lender” for all purposes under this Agreement.

(e)    As a condition precedent to any Commitment Increase, the Company shall deliver to the Administrative Agent (i) a certificate of a Responsible Officer of the Company dated as of the Commitment Increase Date certifying and attaching the resolutions adopted by the Borrowers approving or consenting to such Commitment Increase and certifying that, before and after giving effect to such Commitment Increase, (A) the representations and warranties contained in this Agreement made by the Borrowers are true and correct on and as of the Commitment Increase Date (unless such representations and warranties are stated to relate to a specific earlier date, in which case such representations and warranties shall be true and correct as of such earlier date) and (B) no Default or Event of Default exists or will exist as of the Commitment Increase Date, and (ii) any legal opinions, certificates and/or other documents reasonably requested by the Administrative Agent in connection with the Commitment Increase.

Article III
Representations and Warranties



Each Borrower represents and warrants to the Lenders that:

Section 3.01    Organization; Powers.  Each of the Company and its Material Subsidiaries is duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, has all requisite power and authority to carry on its business as now conducted and, except where the failure to do so, individually or in the aggregate, could not

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reasonably be expected to result in a Material Adverse Effect, is qualified to do business in, and is in good standing in, every jurisdiction where such qualification is required. 

Section 3.02    Authorization; Enforceability.  The Transactions are within each Loan Party’s corporate or equivalent powers and have been duly authorized by all necessary corporate and, if required, stockholder action.  Each Loan Document to which each Loan Party is a party has been duly executed and delivered by such Loan Party and constitutes a legal, valid and binding obligation of such Loan Party, enforceable in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

Section 3.03    Governmental Approvals; No Conflicts.  The Transactions (a) do not require any consent or approval of, registration or filing with, or any other action by, any Governmental Authority or any third Person (including holders of its Equity Interests or any class of directors, managers or supervisors, as applicable, whether interested or disinterested, of any Borrower or any other Person), except such as have been obtained or made and are in full force and effect, (b) will not violate any applicable law or regulation or the charter, by-laws or other organizational documents of the Company or any of its Material Subsidiaries or any order of any Governmental Authority, nor is any such consent, approval, registration, filing or other action necessary for the validity or enforceability of any Loan Document or the consummation of the Transactions, except such as have been obtained or made and are in full force and effect other than those third party approvals or consents which, if not made or obtained would not cause a Default hereunder, could not reasonably be expected to have a Material Adverse Effect or do not have an adverse effect on the enforceability of the Loan Documents, (c) will not violate or result in a default under the Existing Notes, any indenture pursuant to which any Existing Notes are issued or any other indenture, agreement or other instrument binding upon the Company or any of its Material Subsidiaries or its assets, or give rise to a right thereunder to require any payment to be made by the Company or any of its Material Subsidiaries, and (d) will not result in the creation or imposition of any Lien on any asset of the Company or any of its Material Subsidiaries.

Section 3.04    Financial Condition; No Material Adverse Effect; No Default.  (a) The Company has heretofore furnished to the Lenders its consolidated balance sheet and statements of income, stockholders equity and cash flows (i) as of and for the fiscal year ended December 31, 2017, reported on by KPMG LLP, independent public accountants, and (ii) as of and for the fiscal quarter and the portion of the fiscal year ended September 30, 2018, certified by its chief financial officer.  Such financial statements present fairly, in all material respects, the financial position and results of operations and cash flows of the Company and its consolidated Subsidiaries as of such dates and for such periods in accordance with GAAP, subject to year-end audit adjustments and the absence of footnotes in the case of the statements referred to in clause (ii) above.

(b)    Since December 31, 2017, there has been no change in the business, assets, operations, prospects or condition, financial or otherwise, of the Company and its Subsidiaries that, taken as a whole, has had or could reasonably be expected to have, a Material Adverse Effect.

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(c)    No Default or Event of Default has occurred and is continuing.

Section 3.05    Properties.  (a) Each of the Company and its Material Subsidiaries has good title to, or valid leasehold interests in, all its real and personal property material to its business, except for (i) Liens permitted by Section 6.03 and (ii) minor defects in title that do not interfere with its ability to conduct its business as currently conducted or to utilize such properties for their intended purposes. 

(b)    Each of the Company and its Subsidiaries owns, or is licensed to use, all trademarks, tradenames, copyrights, patents and other intellectual property material to its business, and the use thereof by the Company and its Subsidiaries does not infringe upon the rights of any other Person, except for any such infringements that, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.

(c)    Prior the Investment Grade Rating Date, except for such acts or failures to act as could not be reasonably expected to have a Material Adverse Effect, the Oil and Gas Properties (and Properties unitized therewith) of the Company and its Subsidiaries have been maintained, operated and developed in conformity with all Governmental Requirements and in conformity with the provisions of all leases, subleases or other contracts comprising a part of the Hydrocarbon Interests and other contracts and agreements forming a part of the Oil and Gas Properties of the Company and its Subsidiaries. Specifically in connection with the foregoing, except for those as could not be reasonably expected to have a Material Adverse Effect, (i) no Oil and Gas Property of the Company or any Subsidiary is subject to having allowable production reduced below the full and regular allowable (including the maximum permissible tolerance) because of any overproduction (whether or not the same was permissible at the time) and (ii) none of the wells comprising a part of the Oil and Gas Properties (or Properties unitized therewith) of the Company or any Subsidiary is deviated from the vertical more than the maximum permitted by Governmental Requirements, and such wells are, in fact, bottomed under and are producing from, and the well bores are wholly within, the Oil and Gas Properties (or in the case of wells located on Properties unitized therewith, such unitized Properties) of the Company or such Subsidiary.  Prior the Investment Grade Rating Date, all pipelines, wells, gas processing plants, platforms and other material improvements, fixtures and equipment owned in whole or in part by the Company or any of its Subsidiaries that are necessary to conduct normal operations are being maintained in a state adequate to conduct normal operations, and with respect to such of the foregoing which are operated by the Company or any of its Subsidiaries, in a manner consistent with the Company’s or its Subsidiaries’ past practices (other than those the failure of which to maintain in accordance with this Section 3.05(c) could not reasonably be expected to have a Material Adverse Effect).

Section 3.06    Litigation and Environmental Matters.  (a) There are no actions, suits or proceedings by or before any arbitrator or Governmental Authority pending against or, to the knowledge of the Company, threatened against the Company or any of its Subsidiaries (i) as to which there is a reasonable possibility of an adverse determination and that, if adversely determined, could reasonably be expected, individually or in the aggregate, to result in a Material Adverse Effect or (ii) that involve this Agreement, any other Loan Document or the Transactions.

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(b)    Except with respect to any other matters that, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect, neither the Company nor any of its Subsidiaries (i) has failed to comply with any Environmental Law or to obtain, maintain or comply with any permit, license or other approval required under any Environmental Law, (ii) has become subject to any Environmental Liability, (iii) has received written notice of any claim with respect to any Environmental Liability or (iv) knows of any basis for any Environmental Liability.

Section 3.07    Compliance with Laws and Agreements.  Each of the Company and its Subsidiaries is in compliance with all laws, regulations and orders of any Governmental Authority applicable to it or its property and all indentures, agreements and other instruments binding upon it or its property, except where the failure to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.  No Default has occurred and is continuing or will result from the execution and delivery of this Agreement or any of the other Loan Documents, or the making of the Loans hereunder.

Section 3.08    Investment Company Status.  Neither the Company nor any of its Subsidiaries is an “investment company” as defined in, or subject to regulation under, the Investment Company Act of 1940.

Section 3.09    Taxes.  Each of the Company and its Subsidiaries has timely filed or caused to be filed all Tax returns and reports required to have been filed and has paid or caused to be paid all Taxes required to have been paid by it, except (a) Taxes that are being contested in good faith by appropriate proceedings and for which the Company or such Subsidiary, as applicable, has set aside on its books adequate reserves or (b) to the extent that the failure to do so could not reasonably be expected to result in a Material Adverse Effect.

Section 3.10    ERISA.  No ERISA Event has occurred or is reasonably expected to occur that, when taken together with all other such ERISA Events for which liability is reasonably expected to occur, could reasonably be expected to result in a Material Adverse Effect.  The Company and each ERISA Affiliate has fulfilled its obligations under the minimum funding standards of ERISA and the Code with respect to each Plan and is in compliance in all material respects with the presently applicable provisions of ERISA and the Code with respect to each Plan.  Neither the Company nor any ERISA Affiliate has (a) sought a waiver of the minimum funding standard under Section 412 of the Code in respect of any Plan, (b) failed to make any contribution or payment to any Plan or Multiemployer Plan, or made any amendment to any Plan that has resulted or could result in the imposition of a Lien or the posting of a bond or other security under ERISA or the Code, or (c) incurred any liability under Title IV of ERISA other than a liability to the PBGC for premiums under Section 4007 of ERISA that are not past due.

Section 3.11    Disclosure

(a)    The Company has disclosed to the Lenders all agreements, instruments and corporate or other restrictions to which it or any of its Subsidiaries is subject, and all other matters known to it, that, individually or in the aggregate, could reasonably be expected to result in a Material Adverse Effect.  Neither the Information Memorandum nor any of the other reports, financial statements, certificates or other information furnished by or on behalf of the Company

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to the Administrative Agent or any Lender in connection with the negotiation of this Agreement or delivered hereunder (as modified or supplemented by other information so furnished) contains any material misstatement of fact or omits to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that, with respect to projected financial information, the Company represents only that such information was prepared in good faith based upon assumptions believed to be reasonable at the time.  There are no statements or conclusions in any Reserve Report which are based upon or include misleading information or fail to take into account material information regarding the matters reported therein, it being understood that projections concerning volumes attributable to the Oil and Gas Properties of the Company and the Subsidiaries and production and cost estimates contained in each Reserve Report are necessarily based upon professional opinions, estimates and projections and that the Company and the Subsidiaries do not warrant that such opinions, estimates and projections will ultimately prove to have been accurate.

(b)    As of the Effective Date, to the best knowledge of the Borrower, the information included in the Beneficial Ownership Certification provided on or prior to the Effective Date to any Lender in connection with this Agreement is true and correct in all respects.

Section 3.12    Insurance.  The Company has, and has caused all of its Subsidiaries to have, (a) all insurance policies sufficient for the compliance by each of them with all material Governmental Requirements and all material agreements and (b) insurance coverage in at least amounts and against such risk (including, without limitation, public liability) that are usually insured against by companies similarly situated and engaged in the same or a similar business for the assets and operations of the Company and its Subsidiaries.

Section 3.13    Restriction on Subsidiary Distributions.  Prior to the Investment Grade Rating Date, neither the Company nor any Subsidiary is a party to any agreement or arrangement, or subject to any order, judgment, writ or decree, which either restricts or purports to restrict any Subsidiary from paying dividends or making any other distributions in respect of its Equity Interests to the Company or any Subsidiary, or restricts any Subsidiary from making loans or advances or transferring any Property to the Company or any Subsidiary, or which requires the consent of or notice to other Persons in connection therewith, except, in each case, for such restrictions permitted under Section 6.07.

Section 3.14    SubsidiariesExcept as disclosed to the Administrative Agent by the Company in writing from time to time after the Effective Date, which shall be a supplement to Schedule 3.14, (a) Schedule 3.14 sets forth (i) each Subsidiary’s name as listed in the public records of its jurisdiction of organization and jurisdiction of organization, and the location of its principal place of business and chief executive office and, as to each such Subsidiary, the percentage of each class of Equity Interests issued by such Subsidiary and, if such percentage is not 100% (excluding directors’ qualifying shares as required by law), a description of each class issued and outstanding and (ii) the identity of each (A) Material Subsidiary, (B) Subsidiary Guarantor, (C) Required Subsidiary Guarantor (and specifying the basis for such Person being a Required Subsidiary Guarantor, including whether such Required Subsidiary Guarantor has been designated as such pursuant to the proviso to the definition of Required Subsidiary Guarantor)

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and (D) Excluded Canam Entity.  All of the outstanding shares or other Equity Interests of each such Subsidiary owned by the Company or any other Subsidiary are validly issued and outstanding and, to the extent applicable, fully paid and not assessable, and all such shares or other Equity Interests are owned, beneficially and of record, free and clear of all Liens other than restrictions on transfer imposed by applicable law (or, in respect of the Permitted JV, pursuant to the Permitted JV LLC Agreement).  There are no outstanding subscriptions, options, warrants, calls, rights or other agreements or commitments (other than stock options granted to employees or directors and directors’ qualifying shares) of any nature relating to any Equity Interests of the Company or any Subsidiary, except as created by the Loan Documents and securities laws and other Liens permitted hereunder that arise by operation of law, or, in respect of the Permitted JV, pursuant to the Permitted JV Agreements.

Section 3.15    Solvency.  (a) Each Borrower and each of their respective Subsidiaries is (in each case), and after giving effect to any extension of credit hereunder, will be (in each case), Solvent and (b) no Borrower nor any of their respective Subsidiaries intend to (i) be or become subject to a voluntary or involuntary case under any debtor relief law, (ii) make a general assignment for the benefit of creditors, or (iii) have a custodian, conservator, receiver or similar official appointed for any Borrower, any of their respective Subsidiaries or a substantial part of any Borrower’s assets, in each case within the next ten Business Days. 

Section 3.16    Priority Status.  None of the Company or any Subsidiary has taken any action which would cause the claims of unsecured creditors of the Company or of any other Subsidiary, as the case may be (other than claims of such creditors to the extent that they are statutorily preferred or Permitted Liens), to have priority over any of the Obligations.

Section 3.17    Anti-Corruption Laws and Sanctions

(a)    Each Borrower has implemented and maintains in effect policies and procedures reasonably designed to ensure compliance by such Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions, and each Borrower and its Subsidiaries and to the knowledge of such Borrower its and its Subsidiaries’ officers, directors, employees and agents, are in compliance with Anti-Corruption Laws and applicable Sanctions in all material respects and are not knowingly engaged in any activity that would reasonably be expected to result in such Borrower being designated as a Sanctioned Person. 

(b)    None of (a) the Borrowers or any of their Subsidiaries, or to the knowledge of the Borrower or such Subsidiary, any of their respective directors, officers or employees, or (b) to the knowledge of any Borrower, any agent of any Borrower or any of its Subsidiaries that will act in any capacity in connection with or benefit from the credit facility established hereby, is a Sanctioned Person.

Section 3.18    Use of Proceeds.  The proceeds of the Loans and the Letters of Credit will be used as permitted by Section 5.09.  The Borrowers and the Subsidiaries are not engaged principally, or as one of their important activities, in the business of extending credit for the purpose, whether immediate, incidental or ultimate, of buying or carrying margin stock (within the meaning Regulation T, U or X of the Board).

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Section 3.19    EEA Financial Institutions.  No Loan Party is an EEA Financial Institution.

Article IV
Conditions

Section 4.01    Effective Date.  This Agreement shall not become effective until the date on which each of the following conditions precedent is satisfied (or waived in accordance with Section 10.02):

(a)    The Administrative Agent (or its counsel) shall have received (i) either (A) a counterpart of this Agreement signed on behalf of each Person party hereto or (B) written evidence satisfactory to the Administrative Agent (which may include telecopy or email transmission of a signed signature page or signed signature pages with respect to this Agreement) that each such Person has signed a counterpart of this Agreement and (ii) either (A) a counterpart of the Guaranty Agreement signed on behalf of the Borrowers and each Required Subsidiary Guarantor or (B) written evidence satisfactory to the Administrative Agent (which may include telecopy or email transmission of a signed signature page or signed signature pages with respect to this Agreement) that each such Person has signed a counterpart of the Guaranty Agreement.

(b)    The Administrative Agent shall have received favorable written opinions (addressed to the Administrative Agent and the Lenders and dated the Effective Date) of (i) Davis Polk & Wardwell LLP, as counsel for the Loan Parties, substantially in the form of Exhibit B‑1 and (ii) Osler, Hosking & Harcourt LLP, as counsel for MOCL, substantially in the form of Exhibit B‑2.  The Company hereby requests such counsel to deliver such opinions.

(c)    Since December 31, 2017, there has been no change in the business, assets, operations, prospects or condition, financial or otherwise, of the Company and its Subsidiaries that, taken as a whole, has had or could reasonably be expected to have, a Material Adverse Effect.

(d)    The Administrative Agent shall have received financial projections and forecasts with respect to the Company and its Consolidated Subsidiaries, in each case, in form and substance reasonably satisfactory to it.

(e)    The Administrative Agent and the Lenders shall have received (at least three Business Days prior to the Effective Date), and shall be reasonably satisfied in form and substance with, (i) all documentation and other information required by bank regulatory authorities under applicable “know-your-customer” and anti-money laundering rules and regulations, including but not limited to the Patriot Act, to the extent such documentation or other information was requested by the Administrative Agent or any such applicable Lender at least seven days prior to the Effective Date and (ii) to the extent the Borrower qualifies as a “legal entity customer” under the Beneficial Ownership Regulation, a Beneficial Ownership Certification in relation to the Borrowers (provided that, upon the execution and delivery by such Lender of its signature page to this Agreement, the condition set forth in this clause (ii) shall be deemed to be satisfied).

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(f)    The Administrative Agent shall have received such documents and certificates as the Administrative Agent or its counsel may reasonably request relating to the organization, existence and good standing of each Loan Party, the authorization of the Transactions and any other legal matters relating to the Loan Parties, this Agreement, the other Loan Documents or the Transactions, all in form and substance satisfactory to the Administrative Agent and its counsel.

(g)    The Administrative Agent shall have received a certificate, dated as of the Effective Date and signed by a Responsible Officer of the Company, confirming compliance with the conditions set forth in paragraphs (a) and (b) of Section 4.02.

(h)    The Administrative Agent, Lenders and Lead Arrangers shall have received all fees and other amounts due and payable to each such Person (including, without limitation, the fees and expenses of Paul Hastings LLP, as counsel to the Administrative Agent) on or prior to the Effective Date, including, to the extent invoiced, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrowers hereunder.

(i)    All principal, interest, fees and other amounts due or outstanding under the Existing Credit Agreement shall have been paid in full and the commitments thereunder shall have been terminated, and the Administrative Agent shall have received reasonably satisfactory evidence thereof.

(j)    The Lenders shall have received such documents and other instruments as are customary for transactions of this type or as they or their counsel may reasonably request.

The Administrative Agent shall notify the Company and the Lenders of the occurrence of the Effective Date, and such notice shall be conclusive and binding.  Notwithstanding the foregoing, the Effective Date shall not occur unless each of the foregoing conditions is satisfied (or waived pursuant to Section 10.02) at or prior to 11:59 p.m., New York City time, on November 28, 2018 (and, in the event such conditions are not so satisfied, extended or waived, the Commitments shall terminate at such time).  For purposes of determining compliance with the conditions specified in this Section 4.01, each Lender shall be deemed to have consented to, approved or accepted or to be satisfied with, each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to a Lender unless the Administrative Agent shall have received written notice from such Lender prior to the proposed Effective Date specifying its objection thereto.

Section 4.02    Each Credit Event.  The obligation of each Lender to make, convert or continue a Loan on the occasion of any Borrowing, and of the Issuing Banks to issue, amend, renew or extend any Letter of Credit, is subject to the satisfaction of the following conditions:

(a)    The representations and warranties of the Loan Parties set forth in this Agreement and each other Loan Documents shall be true and correct on and as of the date of such Borrowing or the date of the issuance, amendment, renewal or extension of such Letter of Credit, as applicable (unless such representations and warranties are stated to relate to a specific earlier date, in which case such representations and warranties shall be true and correct as of such earlier date).

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(b)    At the time of and immediately after giving effect to such Borrowing or the issuance, amendment, renewal or extension of such Letter of Credit, as applicable, no Default shall have occurred and be continuing.

(c)    The Administrative Agent shall have received a Borrowing Request (or any request for the issuance, amendment, renewal or extension of a Letter of Credit) as required by Section 2.03 in respect of a Borrowing, or in the case of the issuance, amendment, extension or renewal of a Letter of Credit, the applicable Issuing Bank and the Administrative Agent shall have received a request as required by Section 2.05(b).

(d)    In the case of the issuance, amendment, extension or increase of a Letter of Credit to be denominated in a Designated Currency, (i) there shall not have occurred any change in national or international financial, political or economic conditions or currency exchange rates or exchange controls that in the reasonable opinion of the Administrative Agent or the applicable Issuing Bank would make it impracticable for such issuance, amendment, extension or increase to be denominated in the relevant Designated Currency or (ii) the issuance of such Letter of Credit would not violate one or more policies of the Issuing Bank applicable to letters of credit generally (including, without limitation, country exposure limitations).

Each Borrowing and each issuance, amendment, renewal or extension of a Letter of Credit shall be deemed to constitute a representation and warranty by each Borrower on the date thereof as to the matters specified in paragraphs (a) and (b) of this Section 4.02.

Article V
Affirmative Covenants

During the period commencing on and including the Effective Date and until the Commitments have expired or been terminated and the principal of and interest on each Loan and all fees payable hereunder shall have been paid in full and all Letters of Credit shall have expired or terminated, in each case, without any pending draw, and all LC Disbursements shall have been reimbursed, the Company (and each Borrower, in the case of Section 5.08 and Section 5.09) covenants and agrees with the Lenders that:

Section 5.01    Financial Statements, Ratings Change, and Other Information.  The Company will furnish to the Administrative Agent and each Lender:

(a)    no later than 30 days following the date required by applicable SEC rules (without giving effect to any extensions available thereunder) for the filing of such financial statements after the end of each fiscal year of the Company, its audited consolidated balance sheet and related statements of operations, stockholders’ equity and cash flows as of the end of and for such year, setting forth in each case in comparative form the figures for the previous fiscal year, all reported on by KPMG LLP or other independent public accountants of recognized national standing (without a “going concern” or like qualification or exception and without any qualification or exception as to the scope of such audit) to the effect that such consolidated financial statements present fairly in all material respects the financial condition and results of operations of the Company and its consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied;

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(b)    no later than 30 days following the date required by applicable SEC rules (without giving effect to any extensions available thereunder) for the filing of such financial statements after the end of each of the first three fiscal quarters of each fiscal year of the Company, its consolidated balance sheet and related statements of operations, stockholders’ equity and cash flows as of the end of and for such fiscal quarter and the then elapsed portion of the fiscal year, setting forth in each case in comparative form the figures for the corresponding period or periods of (or, in the case of the balance sheet, as of the end of) the previous fiscal year, all certified by one of its Financial Officers as presenting fairly in all material respects the financial condition and results of operations of the Company and its consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied, subject to normal year-end audit adjustments and the absence of footnotes;

(c)    simultaneously with the delivery of the financial statements referred to in subsections (a) or (b) above, a copy of the certification signed by the principal executive officer and the principal financial officer of the Company (each, a “Certifying Officer”) as required by Rule 13A-14 under the Securities Exchange Act of 1934 and a copy of the internal controls disclosure statement by such Certifying Officers as required by Rule 13A-15 under the Securities Exchange Act of 1934, each as included in the Company’s Annual Report on Form 10-K or Quarterly Report on Form 10-Q, for the applicable fiscal period;

(d)    concurrently with any delivery of financial statements under Section 5.01(a) and Section 5.01(b), a certificate of a Financial Officer of the Company, substantially in the form attached hereto as Exhibit D (a “Compliance Certificate”), (i) certifying as to whether a Default has occurred and, if a Default has occurred, specifying the details thereof and any action taken or proposed to be taken with respect thereto, (ii) setting forth reasonably detailed calculations demonstrating compliance with each of the Financial Covenants set forth in Section 6.14, (iii) stating whether any change in GAAP or in the application thereof has occurred since the date of the audited financial statements referred to in Section 3.04 and, if any such change has occurred, specifying the effect of such change on the financial statements accompanying such certificate and (iv) with respect to any Compliance Certificate delivered prior to the Investment Grade Rating Date, (A) setting forth reasonably detailed calculations demonstrating the Leverage Ratio Ex-MOCL as of the last day of the fiscal quarter for such financial statements, and stating whether a MOCL Guarantee Trigger Event has occurred (and attaching thereto consolidating financial statements, in form and substance reasonably satisfactory to the Administrative Agent, demonstrating the portion of Consolidated EBITDA attributable to the Excluded MOCL Entities), (B) specifying the identity of each Required Subsidiary Guarantor, Material Subsidiary, Guarantor and Excluded Canam Entity as of the end of such fiscal quarter or fiscal year, as applicable (and including reasonable detail, in form and substance satisfactory to the Administrative Agent, with respect thereto), as the case may be, (C) to the extent necessary pursuant to the definition of “Required Subsidiary Guarantor” and/or “Material Subsidiary”, as applicable, designating sufficient additional Subsidiaries as Required Subsidiary Guarantors or Material Subsidiaries, respectively, so as to comply with the definition of “Required Subsidiary Guarantor” or “Material Subsidiary”, respectively and (D) specifying the amount of cash dividends declared and paid by Canam to the Loan Parties pursuant to Section 5.18 for each fiscal quarter or fiscal year, as applicable (and including reasonably detailed backup information, in form and substance satisfactory to the Administrative Agent, with respect thereto);

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(e)    prior to the Investment Grade Rating Date, as soon as available, and in any event within 60 days after the beginning of each fiscal year of the Company, an annual forecast with respect to such fiscal year and the immediately succeeding fiscal year;

(f)    concurrently with any delivery of financial statements under Section 5.01(a), a certificate of insurance coverage from each insurer with respect to the insurance required by Section 5.06, in form and substance satisfactory to the Administrative Agent, and, if requested by the Administrative Agent or any Lender, all copies of the applicable policies;

(g)    prior to the Investment Grade Rating Date, concurrently with any delivery of financial statements under Section 5.01(a) or, solely for each fiscal quarter of the Company ending on June 30 of each year, Section 5.01(b), a certificate of a Financial Officer, in form and substance satisfactory to the Administrative Agent, setting forth as of a recent date, a true and complete list of all Hedging Agreements of the Company and each Subsidiary, the material terms thereof (including the type, term effective date, termination date and notional amounts or volumes), the net mark-to-market value therefor, any new credit support agreements relating thereto not otherwise previously disclosed pursuant to this Section 5.01(g), any margin required or supplied under any credit support document, and the counterparty to each such agreement; provided that, to the extent all information required to be delivered pursuant to this this Section 5.01(g) has otherwise been made available for review by the Lenders on the Company’s website at http://www.murphyoilcorp.com or at http://www.sec.gov, the requirements of this Section 5.01(g) shall be satisfied upon delivery of a certificate of a Financial Officer (i) notifying the Administrative Agent and the Lenders that such information has been made available on one or both of the above websites and (ii) certifying that such information constitutes a true and complete list of all Hedging Agreements of the Company and each Subsidiary;

(h)    promptly after the same become publicly available, copies of all periodic and other reports, proxy statements and other materials filed by the Company or any Subsidiary with the SEC, or any Governmental Authority succeeding to any or all of the functions of said Commission, or with any national securities exchange, or distributed by the Company to its shareholders generally, as the case may be; 

(i)    prior to the Investment Grade Rating Date, prompt written notice, and in any event within five Business Days, of the occurrence of any Casualty Event having a fair market value in excess of $25,000,000 or the commencement of any action or proceeding that could reasonably be expected to result in a Casualty Event having a fair market value in excess of $25,000,000;

(j)    promptly after the Rating Agencies shall have announced a change in the rating established or deemed to have been established for the Index Debt, written notice of such rating change; and

(k)    promptly following any request therefor, (i) such other information regarding the operations, business affairs and financial condition of the Company or any Subsidiary, or compliance with the terms of this Agreement, as the Administrative Agent or any Lender may reasonably request and (ii) information and documentation reasonably requested by

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the Administrative Agent or any Lender for purposes of compliance with applicable “know your customer” and anti-money laundering rules and regulations, including the Patriot Act and the Beneficial Ownership Regulation.

Information required to be delivered pursuant to Section 5.01(a),  (b),  (c), or (e) shall be deemed to have been delivered on the date on which (i) such information is actually available for review by the Lenders on the Company’s website at http://www.murphyoilcorp.com or at http://www.sec.gov, and (ii) the Company provides notice to the Lenders that such information is available and designates one or both of the above websites on which such information is located.

Section 5.02    Notices of Material Events.  The Company will furnish to the Administrative Agent and each Lender prompt written notice of the following:

(a)    the occurrence of any Default;

(b)    the filing or commencement of any action, suit or proceeding by or before any arbitrator or Governmental Authority against or affecting the Company or any Affiliate thereof that, if adversely determined, could reasonably be expected to result in a Material Adverse Effect;

(c)    the occurrence of any ERISA Event that, alone or together with any other ERISA Events that have occurred, could reasonably be expected to result in liability of the Company and its Subsidiaries in an aggregate amount exceeding $75,000,000; and

(d)    any other development that results in, or could reasonably be expected to result in, a Material Adverse Effect.

Each notice delivered under this Section 5.02 shall be accompanied by a statement of a Financial Officer or other executive officer of the Company setting forth the details of the event or development requiring such notice and any action taken or proposed to be taken with respect thereto.

Section 5.03    Existence; Conduct of Business.  The Company will, and will cause each of its Material Subsidiaries to, do or cause to be done all things necessary to preserve, renew and keep in full force and effect its legal existence and the rights, licenses, permits, privileges and franchises material to the conduct of its business; provided that the foregoing shall not prohibit any merger, consolidation, liquidation or dissolution permitted under Section 6.04.

Section 5.04    Payment of Obligations.  The Company will, and will cause each of its Subsidiaries to, pay its obligations, including Tax liabilities, that, if not paid, could result in a Material Adverse Effect before the same shall become delinquent or in default, except where (a) the validity or amount thereof is being contested in good faith by appropriate proceedings, (b) the Company or such Subsidiary has set aside on its books adequate reserves with respect thereto in accordance with GAAP and (c) the failure to make payment pending such contest could not reasonably be expected to result in a Material Adverse Effect.

Section 5.05    Maintenance of Properties.  The Company will, and will cause each of its Material Subsidiaries to, (a) keep and maintain all property material to the conduct of its

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business in good working order and condition, ordinary wear and tear excepted and (b) operate its Oil and Gas Properties and other material Properties or cause such Oil and Gas Properties and other material Properties to be operated in a careful and efficient manner in accordance with the practices of the industry and in compliance with all applicable contracts and agreements and in compliance with all Governmental Requirements, including, without limitation, applicable pro ration requirements and Environmental Laws, and all applicable laws, rules and regulations of every other Governmental Authority from time to time constituted to regulate the development and operation of its Oil and Gas Properties and the production and sale of Hydrocarbons and other minerals therefrom.

Section 5.06    Insurance.  The Company will, and will cause each Subsidiary to, maintain, with financially sound and reputable insurance companies, insurance in such amounts and against such risks as are customarily maintained by companies engaged in the same or similar businesses operating in the same or similar locations.  Upon the reasonable request of the Administrative Agent from time to time, the Company shall deliver to the Administrative Agent information in reasonable detail as to the Company’s and its Subsidiaries’ insurance then in effect, stating the names of the insurance companies, the amounts of insurance, the dates of the expiration thereof and the properties and risks covered thereby. In the event the Company or any Subsidiary at any time shall fail to obtain or maintain any of the insurance required herein, then the Administrative Agent, without waiving or releasing any obligations or resulting Default hereunder, may at any time or times thereafter (but shall be under no obligation to do so) obtain and maintain such policies of insurance and pay premiums and take any other action with respect thereto which the Administrative Agent deems advisable. All sums so disbursed by the Administrative Agent shall constitute part of the Obligations, payable as provided in this Agreement.

Section 5.07    Books and Records; Inspection Rights.  The Company will, and will cause each of its Material Subsidiaries to, keep proper books of record and account in which full, true and correct entries are made of all dealings and transactions in relation to its business and activities.  The Company will, and will cause each of its Material Subsidiaries to, permit any representatives designated by the Administrative Agent or any Lender, upon reasonable prior notice, to visit and inspect its properties, to examine and make extracts from its books and records, and to discuss its affairs, finances and condition with its officers and independent accountants, all at such reasonable times and as often as reasonably requested.

Section 5.08    Compliance with Laws

(a)    The Company will, and will cause each of its Subsidiaries to, comply with all laws, rules, regulations and orders of any Governmental Authority applicable to it or its property, except where the failure to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect. 

(b)    Each Borrower will maintain in effect policies and procedures reasonably designed to ensure compliance by such Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions.    

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Section 5.09    Use of Proceeds.    

(a)    The proceeds of the Loans will be used only (i) to refinance all of the outstanding Indebtedness and other obligations under the Existing Credit Agreement and (ii) for general corporate purposes or as liquidity support for commercial paper issued by or on behalf of the Company or a Subsidiary of the Company. 

(b)    No part of the proceeds of any Loan will be used, whether directly or indirectly, for any purpose that entails a violation of any of the Regulations of the Board, including Regulations T, U and X.  No Borrower will request any Borrowing or Letter of Credit, and no Borrower shall directly or, to the knowledge of such Borrower, indirectly use the proceeds of any Borrowing or Letter of Credit (A) in furtherance of an offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of any Anti-Corruption Laws, (B) for the purpose of funding, financing or facilitating any activities, business or transaction of or with any Sanctioned Person, or in any Sanctioned Country, except to the extent permitted for a Person required to comply with Sanctions, or (C) in any manner that would result in the violation of any Sanctions applicable to any party hereto.

Section 5.10    Reserve Reports.  Prior to the Investment Grade Rating Date:

(a)    On or before March 1st of each year, commencing March 1, 2019, the Company shall furnish to the Administrative Agent and the Lenders a Reserve Report, in form and substance consistent with the requirements set forth in the definition thereof, evaluating the Proved Oil and Gas Properties of the Company and its Subsidiaries as of the immediately preceding January 1st; provided that if as of the last day of the fiscal quarter ending June 30th of such year, the Consolidated Leverage Ratio for the period of four consecutive fiscal quarters ending on such day exceeds 3.00 to 1.00, then, if requested by the Administrative Agent, the Company shall furnish to the Administrative Agent and the Lenders, on or before September 1st of such year, a Reserve Report, in form and substance consistent with the requirements set forth in the definition thereof, evaluating the Proved Oil and Gas Properties of the Company and its Subsidiaries as of the immediately preceding July 1st of such year.  Each Reserve Report shall be either prepared by one or more Approved Petroleum Engineers, or by or under the supervision of the chief engineer of the Company, who shall certify such Reserve Report to be true and accurate and to have been prepared in accordance with the procedures used in the immediately preceding January 1 Reserve Report.

(b)    With the delivery of each Reserve Report, the Company shall provide to the Administrative Agent and the Lenders a certificate from a Responsible Officer certifying that in all material respects:  (i) the information contained in the Reserve Report, as applicable, and any other information delivered in connection therewith is true and correct, (ii) the Company or its Subsidiaries owns good and defensible title to the Oil and Gas Properties evaluated in such Reserve Report, and such Properties are free of all Liens except for Liens permitted by Section 6.03 and (iii) none of their Oil and Gas Properties have been sold (other than Hydrocarbons sold in the ordinary course of business) since the date of the most recently delivered Reserve Report hereunder except as set forth on an exhibit to the certificate, which certificate shall list all of its

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Oil and Gas Properties sold (other than Hydrocarbons sold in the ordinary course of business) and in such detail as required by the Administrative Agent.

Section 5.11    [Reserved].

Section 5.12    Additional Guarantors.  Prior to the Investment Grade Rating Date, with respect to any Person that after the Effective Date is or becomes a Required Subsidiary Guarantor (other than MOCL), or with respect to MOCL, upon any MOCL Guarantee Trigger Event, the Company shall, or shall cause its Subsidiaries to, promptly (and in any event within ten days of the delivery of the Compliance Certificate for any fiscal quarter or fiscal year, as applicable, pursuant to Section 5.01(d) (or with respect to clause (i) of the definition of MOCL Guarantee Trigger Event, within ten days of the date on which the Total Credit Exposure (excluding any LC Exposure) exceeds $500,000,000)) cause such Person to (i) become a Guarantor by executing and delivering to the Administrative Agent a duly executed Guaranty Agreement (or supplement to a Guaranty Agreement or such other document as the Administrative Agent shall deem appropriate for such purpose), (ii) execute and deliver to the Administrative Agent such legal opinions, organizational and authorization documents and certificates of the type referred to in Section 4.01(b) and Section 4.01(g), and (iii) deliver to the Administrative Agent such other documents as may be reasonably requested by the Administrative Agent, all in form, content and scope reasonably satisfactory to the Administrative Agent.

Section 5.13    [Reserved].

Section 5.14    Accounts.  Prior to the Investment Grade Rating Date, the Company shall, and shall cause each Subsidiary to: (i) deposit or cause to be deposited directly, all Cash Receipts into one or more Deposit Accounts listed on Schedule 5.14, (ii) deposit or credit or cause to be deposited or credited directly, all securities and financial assets held or owned by (whether directly or indirectly), credited to the account of, or otherwise reflected as an asset on the balance sheet of, the Company and its Subsidiaries (including, without limitation, all marketable securities, treasury bonds and bills, certificates of deposit, investments in money market funds and commercial paper) into one or more Securities Accounts listed on Schedule 5.14 and (iii) cause all commodity contracts held or owned by (whether directly or indirectly), credited to the account of, or otherwise reflected as an asset on the balance sheet of, the Company and its Subsidiaries, to be carried or held in one or more Commodity Accounts listed on Schedule 5.14.

Section 5.15    [Reserved].

Section 5.16    More Favorable Financial Covenants.  Prior to the Investment Grade Rating Date:

(a)    If, at any time after the Effective Date, any Other Debt Agreement includes one or more Additional Financial Covenants (including, for the avoidance of doubt, as a result of any amendment, supplement, waiver or other modification to any Other Debt Agreement causing it to contain one or more Additional Financial Covenants), then (i) on or prior to the third Business Day following the effectiveness of any such Additional Financial Covenants, as applicable, the Company shall notify the Administrative Agent thereof, and (ii)

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whether or not the Company provides such notice, the terms of this Agreement shall, without any further action on the part of any Borrower, the Administrative Agent or any Lender, be deemed to be amended automatically to include each Additional Financial Covenant in this Agreement, mutatis mutandis effective as of the date when such Additional Financial Covenant became effective under such Other Debt Agreement. The Company further covenants to promptly execute and deliver at its expense an amendment to this Agreement in form and substance reasonably satisfactory to the Required Lenders evidencing the amendment of this Agreement to include such Additional Financial Covenants in this Agreement; provided that the execution and delivery of such amendment shall not be a precondition to the effectiveness of such amendment as provided for this Section 5.16(a), but shall merely be for the convenience of the parties hereto.

(b)    If at any time after this Agreement is amended pursuant to Section 5.16(a) to include any Additional Financial Covenant contained in any Other Debt Agreement (each, an “Incorporated Provision”), such Incorporated Provision ceases to be in effect under, or is deleted from, such Other Debt Agreement, or is amended or modified for the purposes of such Other Debt Agreement, so as to become less restrictive with respect to the Borrowers or any of their respective Subsidiaries, then (i) on or prior to the third Business Day following the effectiveness of any such cessation, deletion, amendment or modification, the Company shall notify the Administrative Agent thereof, and (ii) whether or not the Company provides such notice, so long as no Default or Event of Default in respect of such Incorporated Provision shall be in existence, the terms of this Agreement shall, without any further action on the part of the Company, the Administrative Agent or any Lender, be deemed to be amended automatically to delete such Incorporated Provision or incorporate the same amendments or modifications to such Incorporated Provision, as applicable, mutatis mutandis effective as of the date when such Incorporated Provision ceased to be in effect under, or was deleted from, or was amended or modified in such Other Debt Agreement. Upon the request of the Company, the Required Lenders will execute and deliver an amendment to this Agreement to delete or similarly amend or modify, as the case may be, such Incorporated Provision as in effect in this Agreement.  Notwithstanding the foregoing, no amendment to this Agreement pursuant to this Section 5.16(b) as the result of any Incorporated Provision ceasing to be in effect or being deleted, amended or otherwise modified shall cause any covenant or Event of Default in this Agreement to be less restrictive as to the Company or any Subsidiary than such covenant or Event of Default as contained in this Agreement as in effect on the Effective Date, and as amended, supplemented or otherwise modified thereafter (other than as the result of the application of Section 5.16(a)).

Section 5.17    Commodity Exchange Act Keepwell Provisions.  Prior to the Investment Grade Rating Date, the Company hereby guarantees the payment and performance of all Obligations of each Loan Party (other than the Company) and absolutely, unconditionally and irrevocably undertakes to provide such funds or other support as may be needed from time to time by each Loan Party (other than the Company) in order for such Loan Party to honor its obligations under its respective Guaranty Agreement including obligations with respect to Hedging Agreements (provided,  however, that the Company shall only be liable under this Section 5.17 for the maximum amount of such liability that can be hereby incurred without rendering its obligations under this Section 5.17, or otherwise under this Agreement or any Loan Document, as it relates to such other Loan Parties, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer, and not for any greater amount).  The obligations of the Company under this Section 5.17 shall remain in full force and effect until all amounts

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owing to the Guaranteed Parties on account of the Obligations are irrevocably and indefeasibly paid in full in cash, no Letter of Credit is outstanding and all of the Commitments are terminated.  The Company intends that this Section 5.17 shall constitute, and this Section 5.17 shall be deemed to constitute, a “keepwell, support, or other agreement” for the benefit of each other Loan Party for all purposes of Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.

Section 5.18    Canam Distribution CovenantPrior to the Investment Grade Rating Date, the Company shall cause Canam to directly or indirectly transfer to one or more Loan Parties, by way of dividend, prepayment of the Effective Date Canam Intercompany Obligations or other distribution, within 30 days after (a) the last day of each of the fiscal quarters of the Company ending June 30 and December 31, an amount not less than the positive difference of (i) the Canam Cash Amount as of the last day of such fiscal quarter minus (ii) $150,000,000 and (b) the last day of each of the fiscal quarters of the Company ending March 31 and September 30, an amount not less than the positive difference of (i) the Canam Cash Amount as of the last day of such fiscal quarter minus (ii) $200,000,000.  Concurrently with the consummation of each such transfer, the Company shall deliver a certificate of a Financial Officer of the Company certifying the calculation of the Canam Cash Amount (and attaching thereto reasonably detailed back-up documentation with respect thereto) for such applicable fiscal quarter.

Section 5.19    Permitted JV Closing.  On the Permitted JV Closing Date, the Company shall deliver to the Administrative Agent a certificate of a Responsible Officer certifying that (a) the Permitted JV Contribution Agreement (including the exhibits and schedules attached thereto) shall not have been modified, amended, supplemented or waived, and no consent shall have been granted thereunder, in each case in a manner that is materially adverse to the Lender, (b) attached thereto is a true, complete and correct copy of each of the Permitted JV Agreements, (c) each of such Permitted JV Agreements is in full force and effect and (d) except as attached thereto, no such Permitted JV Agreement has not been amended, modified or supplemented.

Article VI
Negative Covenants

During the period commencing on and including the Effective Date and until the Commitments have expired or terminated and the principal of and interest on each Loan and all fees payable hereunder have been paid in full and all Letters of Credit have expired or terminated and all LC Disbursements shall have been reimbursed, the Company covenants and agrees with the Lenders that:

Section 6.01    Indebtedness

(a)    Prior to the Investment Grade Rating Date, the Company will not, and will not permit any Subsidiary to create, incur, assume or permit to exist, any Indebtedness, except:

(i)    the Obligations;

(ii)    Indebtedness (other than (A) any such Indebtedness referred to in clause (a)(iii) below and (B) Indebtedness constituting Guarantees by any Subsidiary of Indebtedness of any Person) (x) existing on the Effective Date and set forth on Schedule 6.01 

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hereto and (y) any Indebtedness that is incurred in exchange for, or the proceeds of which are used to extend, refinance, replace, defease, discharge, refund or otherwise retire for value any such Indebtedness; provided that, (1) the aggregate principal amount (or accreted value, in the case of Indebtedness issued with original issue discount) of any such Indebtedness incurred pursuant to this clause (a)(ii)(y) (including undrawn or available committed amounts) does not exceed the sum of (I) the aggregate principal amount (or accreted value, in the case of Indebtedness issued with original issue discount) of the Indebtedness being refinanced, plus (II) an amount necessary to pay all accrued (including, for purposes of defeasance, future accrued) and unpaid interest on the Indebtedness being refinanced and any fees (including original issue discount and upfront fees), premiums and expenses related to such exchange or refinancing, (2) any such Indebtedness incurred pursuant to this clause (a)(ii)(y) has a stated maturity that is no earlier than the later of (I) the date that is 180 days after the Maturity Date and (II) the maturity date of the Indebtedness being refinanced, (3) the Indebtedness incurred pursuant to this clause (a)(ii)(y) does not provide for any mandatory redemptions or repayments prior to the date that is 180 days after the Maturity Date, (4) any such Indebtedness incurred pursuant to this clause (a)(ii)(y) has terms (including with respect to the priority thereof) that are substantially similar to (and, in any event, no less favorable to the lenders) than those that were applicable to the Indebtedness being refinanced and (5) any such Indebtedness incurred pursuant to this clause (a)(ii)(y) is incurred solely by the Company and is not Guaranteed by any Subsidiary;



(iii)    (A) the Existing Notes, in each case, to the extent outstanding on the Effective Date; (B) any Indebtedness that is incurred in exchange for, or the proceeds of which are used to extend, refinance, replace, defease, discharge, refund or otherwise retire for value any Existing Notes; provided that, (1) the aggregate principal amount (or accreted value, in the case of Indebtedness issued with original issue discount) of any such Indebtedness incurred pursuant to this clause (a)(iii)(B) (including undrawn or available committed amounts) does not exceed the sum of (x) the aggregate principal amount (or accreted value, in the case of Indebtedness issued with original issue discount) of the Existing Notes being refinanced, plus (y) an amount necessary to pay all accrued (including, for purposes of defeasance, future accrued) and unpaid interest on the Existing Notes being refinanced and any fees, premiums and expenses related to such exchange or refinancing, (2) any such Indebtedness incurred pursuant to this clause (a)(iii)(B) has a stated maturity that is no earlier than the later of (x) the date that is 180 days after the Maturity Date and (y) the maturity date of the Existing Notes being refinanced, (3) the Indebtedness incurred pursuant to this clause (a)(iii)(B) does not provide for any mandatory redemptions or repayments prior to the date that is 180 days after the Maturity Date except as a result of a customary change of control tender offer, (4) any such Indebtedness incurred pursuant to this clause (a)(iii)(B) has terms (including with respect to the priority thereof) that are either (x) substantially similar to (and, in any event, no less favorable to the Lenders) than those that were applicable to the Existing Notes being refinanced or (y) otherwise on customary market terms as determined in good faith by the Company in its reasonable judgment and (5) any such Indebtedness incurred pursuant to this clause (a)(iii)(B) is incurred solely by the Company and is not Guaranteed by any Subsidiary; and (C) senior unsecured or senior subordinated unsecured Indebtedness; provided that, (1) both before and immediately after giving effect to the incurrence of any such Indebtedness, (I) no Default has occurred and is continuing or would result therefrom, (II) the Consolidated Leverage Ratio (calculated on  pro forma basis using (i) Consolidated Total Debt as of such day and (ii) Consolidated EBITDA for

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the period of four consecutive fiscal quarters most recently ended for which financial statements have been delivered pursuant to Section 5.01(a) or Section 5.01(b)) does not exceed 3.00 to 1.00 and (III) the Administrative Agent shall have received a certificate of a Financial Officer of the Company, in form and substance satisfactory to the Administrative Agent, certifying as to each of the requirements set forth in the foregoing clauses (I) and (II), (2) any such Indebtedness incurred pursuant to this clause (a)(iii)(C) has a stated maturity that is no earlier than 90 days after the Maturity Date, (3) such Indebtedness incurred pursuant to this clause (a)(iii)(C) does not provide for any mandatory redemptions or repayments prior to the date that is 90 days after the Maturity Date except as a result of a customary change of control tender offer, (4) any such Indebtedness incurred pursuant to this clause (a)(iii)(C) has customary market terms as determined in good faith by the Company in its reasonable judgment and (5) any such Indebtedness incurred pursuant to this clause (a)(iii)(C) is incurred solely by the Company and is not Guaranteed by any Subsidiary;



(iv)    (A) Indebtedness of any Loan Party that is due and owing to the Company or any Subsidiary of the Company; provided that any such Indebtedness shall be unsecured and subordinated to the Obligations pursuant to the Subordinated Intercompany Note or (B) to the extent permitted by Section 6.09, Indebtedness of any Subsidiary that is not a Loan Party that is due and owing to the Company or any Subsidiary of the Company;

(v)    Indebtedness of any Subsidiary that is not a Loan Party that is due and owing to any other Subsidiary that is not a Loan Party;

(vi)    Indebtedness incurred to finance insurance premiums in the ordinary course of business in an aggregate principal amount not to exceed the amount of such insurance premiums;

(vii)    Indebtedness of the Company or any Subsidiary incurred to finance the acquisition, construction or improvement of any fixed or capital assets, including Capital Lease Obligations, and extensions, renewals and replacements of any such Indebtedness that do not increase the outstanding principal amount thereof or change the priority or security (if any) with respect thereto; provided that (A) such Indebtedness is incurred prior to or within 90 days after such acquisition or the completion of such construction or improvement, (B) after giving effect to the incurrence of such Indebtedness, the Company shall be in pro forma compliance with each of the Financial Covenants and (C) the aggregate principal amount of Indebtedness permitted by this clause (a)(vii) shall not exceed $200,000,000 at any time outstanding;

(viii)    Guarantees permitted by Section 6.02; and

(ix)    Indebtedness solely in the form of letters of credit and/or letters of guaranty, including letters of credit and/or letters of guaranty issued for the benefit of counterparties under Hedging Agreements permitted pursuant to Section 6.05;

provided that, notwithstanding anything herein to the contrary, no Indebtedness permitted to be incurred and remain outstanding pursuant to the foregoing clauses (a)(i) through (ix) shall

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be permitted to be in the form of Guarantees (with any Indebtedness in the form a Guarantee being required to comply with the requirements set forth in Section 6.02).

(b)    From and after the Investment Grade Rating Date:

(i)    the Company will not, and will not permit any Subsidiary to create, incur, assume or permit to exist any Indebtedness to the extent that as a result of such Indebtedness the Company would be, or could reasonably be expected to be, in breach of the covenant set forth in Section 6.14(b);  

(ii)    the Company will not permit any Subsidiary to create, incur, assume or permit to exist, any Indebtedness, except:

(A)    Indebtedness of any Subsidiary that is due and owing to the Company or any Subsidiary of the Company;

(B)    Indebtedness of any Subsidiary incurred to finance the acquisition, construction or improvement of any fixed or capital assets, including Capital Lease Obligations, and extensions, renewals and replacements of any such Indebtedness that do not increase the outstanding principal amount thereof or change the priority or security (if any) with respect thereto; provided that such Indebtedness is incurred prior to or within 90 days after such acquisition or the completion of such construction or improvement;

(C)    Indebtedness solely in the form of letters of credit and/or letters of guaranty, in each case incurred in the ordinary course of business, including letters of credit and/or letters of guaranty issued for the benefit of counterparties under Hedging Agreements permitted pursuant to Section 6.05 and any Guaranties of such Indebtedness; and

(D)    other Indebtedness; provided that the sum, without duplication, of (1) the outstanding aggregate principal amount of all such Indebtedness, plus (2) the Attributable Debt under all Sale and Leaseback Transactions of the Company and its Subsidiaries, plus (3) the outstanding aggregate principal amount of all Indebtedness or other obligations secured by Liens permitted under Section 6.03(b)(v), shall not exceed 15% of Consolidated Net Tangible Assets at the time of creation, incurrence or assumption thereof.

(iii)    The Company will not, and will not permit any Subsidiary to, enter into any Sale and Leaseback Transaction if, after giving effect to such Sale and Leaseback Transaction, the sum, without duplication, of (A) the aggregate amount of the Attributable Debt under all Sale and Leaseback Transactions of the Company and its Subsidiaries, plus (B) the outstanding aggregate principal amount of all Indebtedness permitted under Section 6.01(b)(ii)(D), plus (C) the outstanding aggregate principal amount of all Indebtedness or other obligations secured by Liens permitted under Section 6.03(b)(v), shall exceed 15% of Consolidated Net Tangible Assets at the time of consummation of such Sale and Leaseback Transaction.

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Section 6.02    Subsidiary Guarantees Prior to the Investment Grade Rating Date.  Prior to the Investment Grade Rating Date, the Company will not, at any time, permit any Subsidiary to Guarantee any Indebtedness or other obligations of any Person, except:

(a)    Guarantees by Subsidiaries constituting Obligations;

(b)    Performance guarantees in the ordinary course of business (excluding, for the avoidance of doubt, Guarantees of surety bonds or similar instruments or any other Indebtedness); and

(c)    Guarantees by Subsidiaries of any Indebtedness permitted pursuant to Section 6.01(a)(ix).

Section 6.03    Liens.  The Company will not, and will not permit any Subsidiary to, create, assume or suffer to exist any Lien on any asset now owned or hereafter acquired by it, except:

(a)    Prior to the Investment Grade Rating Date:

(i)    Liens in favor of the Administrative Agent securing the Obligations described in clause (a) of the definition thereof;

(ii)    any Lien on any property or asset of the Company or any Subsidiary existing on the Effective Date and set forth in Schedule 6.03;  provided that (i) such Lien shall not apply to any other Property or asset of the Company or any Subsidiary and (ii) such Lien shall secure only those obligations which it secures on the date hereof and extensions, renewals and replacements thereof that do not increase the outstanding principal amount thereof;

(iii)    Permitted Encumbrances;

(iv)    Liens on fixed or capital assets acquired, constructed or improved by the Company or any Subsidiary; provided that (i) such security interests secure Indebtedness permitted by Section 6.01(a)(vii), (ii) such Lien and the Indebtedness secured thereby are incurred prior to or within 90 days after such acquisition or the completion of such construction or improvement, (iii) the Indebtedness secured thereby does not exceed the cost of acquiring, constructing or improving such fixed or capital assets and (iv) such Lien shall not apply to any other property or assets of the Company or any Subsidiary;  

(v)    Liens securing any Indebtedness that constitutes Project Financing;

(vi)    Liens securing Indebtedness permitted by Section 6.01(a)(ix);  provided that the aggregate principal amount of the Indebtedness secured thereby does not exceed $100,000,000 at any time; and

(vii)    other Liens securing Indebtedness or other obligations in an aggregate principal amount not exceeding $50,000,000 at any time.

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(b)    From and after the Investment Grade Rating Date, the Company will not, and will not permit any Subsidiary to create, assume or suffer to exist any Lien on any asset now owned or hereafter acquired by it, except:

(i)    Liens in favor of the Administrative Agent securing the Obligations;

(ii)    any Lien on any property or asset of the Company or any Subsidiary existing on the Effective Date and set forth in Schedule 6.03;  provided that (i) such Lien shall not apply to any other Property or asset of the Company or any Subsidiary and (ii) such Lien shall secure only those obligations which it secures on the date hereof and extensions, renewals and replacements thereof that do not increase the outstanding principal amount thereof;

(iii)    Permitted Encumbrances;

(iv)    Liens on fixed or capital assets acquired, constructed or improved by the Company or any Subsidiary; provided that (i) such security interests secure Indebtedness permitted by Section 6.01(b)(ii)(B), (ii) such Lien and the Indebtedness secured thereby are incurred prior to or within 90 days after such acquisition or the completion of such construction or improvement, (iii) the Indebtedness secured thereby does not exceed the cost of acquiring, constructing or improving such fixed or capital assets and (iv) such Lien shall not apply to any other property or assets of the Company or any Subsidiary; and

(v)    other Liens; provided that the sum, without duplication, of (1) the outstanding aggregate principal amount of all Indebtedness permitted under Section 6.01(b)(ii)(D), plus (2) the Attributable Debt under all Sale and Leaseback Transactions of the Company and its Subsidiaries, plus (3) the outstanding aggregate principal amount of all Indebtedness or other obligations secured by such Liens, shall not exceed 15% of Consolidated Net Tangible Assets at the time of creation, incurrence or assumption thereof.

Section 6.04    Fundamental Changes.  (a) The Company will not, and will not permit any other Borrower to, merge into or consolidate with any other Person, or permit any other Person to merge into or consolidate with it, or consummate a Division as the Dividing Person, or sell, transfer, lease or otherwise dispose of (in one transaction or in a series of transactions) all or substantially all of its assets, or all or substantially all of the stock of any of its Material Subsidiaries (in each case, whether now owned or hereafter acquired), or liquidate or dissolve, except that if at the time thereof and immediately after giving effect thereto, no Default shall have occurred and be continuing, any Person may merge into the Company in a transaction in which the Company is the surviving corporation.

(b)    Prior to the Investment Grade Rating Date, the Company will not permit any Material Subsidiary to merge into or consolidate with any other Person, or permit any other Person to merge into or consolidate with any Material Subsidiary, or consummate a Division as the Dividing Person, or permit any Material Subsidiary to sell, transfer, lease or otherwise dispose of (in one transaction or in a series of transactions) all or substantially all of its assets, or all or substantially all of the stock of any of its Material Subsidiaries (in each case, whether now

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owned or hereafter acquired), or liquidate or dissolve, except that if at the time thereof and immediately after giving effect thereto no Default shall have occurred and be continuing (i) any Person (other than any Borrower) may merge into any Subsidiary in a transaction in which the surviving entity is a Subsidiary; provided that (A) if any Borrower (other than the Company) is a party to such transaction, such Borrower shall be the surviving entity and (B) if any Guarantor (other than a Borrower) is a party to such transaction, such Guarantor shall be the surviving entity, (ii) any such Subsidiary (other than a Borrower) may sell, transfer, lease or otherwise dispose of its assets to the Company or to another Subsidiary; provided that if such transferor is a Guarantor, the acquirer shall be a Loan Party; and (iii) any such Subsidiary (other than a Borrower) may liquidate or dissolve if the Company determines in good faith that such liquidation or dissolution is in the best interests of the Company and is not materially disadvantageous to the Lenders; provided that if such Subsidiary is a Guarantor, the assets shall be distributed to or otherwise received by a Loan Party.  

(c)    The Company will not, and will not permit any of its Subsidiaries to, engage to any material extent in any business other than businesses of the type conducted by the Company and its Subsidiaries on the date of execution of this Agreement and businesses reasonably related thereto.

(d)    No Borrower will reorganize or otherwise change its jurisdiction of organization or incorporation, or otherwise become organized or incorporated in any jurisdiction, other than in any State of the United States, or in the case of MOCL, any province of Canada or under the Canada Business Corporations Act.

Section 6.05    Hedging Agreements.  The Company will not, and will not permit any of its Subsidiaries to, enter into any Hedging Agreement, other than Hedging Agreements that are entered into in the ordinary course of business to hedge or mitigate risks to which the Company or any Subsidiary is exposed in the conduct of its business or the management of its liabilities, and not for speculative purposes; provided that the counterparty to each such Hedging Agreement shall, at the time such Hedging Agreement is entered into, be a Lender or an Affiliate of a Lender except where consented to by the Administrative Agent.

Section 6.06    Transactions with Affiliates.  The Company will not, and will not permit any of its Subsidiaries to, sell, lease or otherwise transfer any property or assets to, or purchase, lease or otherwise acquire any property or assets from, or otherwise engage in any other transactions with, any of its Affiliates, except (a) in the ordinary course of business at prices and on terms and conditions not less favorable to the Company or such Subsidiary than could be obtained on an arm’s-length basis from unrelated third parties, (b) transactions between or among the Company and its Subsidiaries not involving any other Affiliate and (c) transactions pursuant to the Permitted JV Agreements.

Section 6.07    Restrictive Agreements; Subsidiary Distributions.  Until the Investment Grade Rating Date has occurred, the Company will not, and will not permit any of its Subsidiaries to, directly or indirectly, enter into, incur or permit to exist any agreement or other arrangement that prohibits, restricts or imposes any condition upon the ability of any Subsidiary to pay dividends or other distributions with respect to any shares of its capital stock or to make or repay loans or advances to the Company or any other Subsidiary or to Guarantee Indebtedness of

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the Company or any other Subsidiary; provided that (i) the foregoing shall not apply to restrictions and conditions imposed by (A) law or by this Agreement, (B) the Permitted JV LLC Agreement in respect of the Permitted JV or Equity Interests in the Permitted JV or (C) the Permitted JV Contribution Agreement in respect of the Permitted JV or the “Assets” (as defined in the Permitted JV Contribution Agreement) and (ii) the foregoing shall not apply to customary restrictions and conditions contained in agreements relating to the sale of a Subsidiary pending such sale; provided such restrictions and conditions apply only to the Subsidiary that is to be sold and such sale is permitted hereunder.

Section 6.08    Restricted Payments.  The Company will not, and will not permit any of its Subsidiaries to, declare or make, or agree to pay or make, directly or indirectly, any Restricted Payment, except:

(a)    any Wholly‑Owned Subsidiaries of the Company may declare and pay dividends and other distributions ratably with respect to their Equity Interests;

(b)    the Company may declare and pay dividends with respect to its Equity Interests payable solely in additional shares of its Equity Interests (other than Disqualified Capital Stock);

(c)    the Company may make Restricted Payments pursuant to and in accordance with stock option plans or other benefit plans for management or employees of the Company and its Subsidiaries;

(d)    the Permitted JV may declare and pay dividends or other distributions in accordance with the Permitted JV LLC Agreement and the Permitted JV Contribution Agreement (including any non-ratable distributions to the extent expressly provided therein);

(e)    prior to the Investment Grade Rating Date, the Company and any Subsidiary may make Restricted Payments so long as (i) both before and immediately after giving effect to any such Restricted Payment, (x) no Default has occurred and is continuing or would result therefrom and (y) the Company shall be in pro forma compliance with each of the Financial Covenants and (ii) the Administrative Agent shall have received a certificate of a Financial Officer of the Company, in form and substance satisfactory to the Administrative Agent, certifying as to each of the requirements set forth in this clause (d); and

(f)    from and after the Investment Grade Rating Date, the Company and any Subsidiary may make Restricted Payments so long as both before and immediately after giving effect to any such Restricted Payment, no Default has occurred and is continuing or would result therefrom.

Section 6.09    Investments Prior to the Investment Grade Rating Date.  Prior to the Investment Grade Rating Date, the Company will not, and will not permit any of its Subsidiaries to, make or permit to remain outstanding any Investment in or to any Person, except:

(a)    (i) Investments made prior to the Effective Date in Subsidiaries in existence on the Effective Date and (ii) other Investments in existence on the Effective Date and

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described on Schedule 6.09 and any renewal or extension of any such Investments referred to in this clause (a)(ii), so long so long as such renewal or extension does not increase the amount of the Investment being renewed or extended (as determined as of such date of renewal or extension);

(b)    Investments made by any Borrower or any other Loan Party in any Person that, prior to such Investment, is a Loan Party;

(c)    Investments made by any Subsidiary that is not a Loan Party in the Company or any Subsidiary of the Company; provided that any such Investment that is the form of a loan or advance from a non-Loan Party to a Loan Party shall be unsecured and subordinated to the Obligations pursuant to the Subordinated Intercompany Note;

(d)    accounts receivable arising in the ordinary course of business, and Investments received in connection with the bankruptcy or reorganization of suppliers and customers or in settlement of delinquent obligations of, and other disputes with, customers and suppliers to the extent reasonably necessary in order to prevent or limit loss;

(e)    Permitted Investments;

(f)    Investments consisting of Hedging Agreements permitted under Section 6.05;

(g)    to the extent constituting Investments, Guarantees of Indebtedness permitted by Section 6.02;  

(h)    Investments received in connection with a Disposition permitted by Section 6.11; and

(i)    Investments so long as (i) both before and immediately after giving effect to any such Investment, no Default has occurred and is continuing or would result therefrom, (ii) immediately before and after giving effect to such Investment, the Company shall be in pro forma compliance with each of the Financial Covenants and (iii) the Administrative Agent shall have received a certificate of a Financial Officer of the Company, in form and substance satisfactory to the Administrative Agent, certifying as to each of the requirements set forth in this clause (i); and

(j)    Investments in the Permitted JV (i) in existence on the Permitted JV Closing Date pursuant to the terms of the Permitted JV Contribution Agreement, the Permitted JV MEPU Conveyance and the Permitted JV Units Conveyance and (ii) made after the Permitted JV Closing Date pursuant to and in accordance with the Permitted JV LLC Agreement.

Section 6.10    Restricted Debt Payments Prior to the Investment Grade Rating Date.  Prior to the Investment Grade Rating Date, the Company will not, and will not permit any of its Subsidiaries to, voluntarily Redeem any Junior Indebtedness prior to its stated maturity, except the Company and any Subsidiary may Redeem Junior Indebtedness so long as (i) both before and immediately after giving effect to such Redemption, no Default has occurred and is continuing or would result therefrom, (ii) immediately before and after giving effect to such Redemption, the

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Company shall be in pro forma compliance with each of the Financial Covenants and (iii) the Administrative Agent shall have received a certificate of a Financial Officer of the Company, in form and substance satisfactory to the Administrative Agent, certifying as to each of the requirements set forth in this clause (b).

Section 6.11    Asset Dispositions Prior to the Investment Grade Rating Date.  Prior to the Investment Grade Rating Date, the Company will not, and will not permit any of its Subsidiaries to, Dispose of any Property, except:

(a)    Dispositions of Surplus Inventory;

(b)    Dispositions of Hydrocarbons and seismic data in the ordinary course of business and consistent with past practices;

(c)    any Disposition of Property resulting from a Casualty Event;

(d)    Dispositions of accounts receivable in connection with the collection or compromise thereof (other than in connection with any financing transaction);

(e)    so long as such Disposition would not result in a violation of the limitations and agreements set forth in Section 6.04, additional Dispositions to any Person (other than the Company or any Affiliate thereof); provided that (i) both before and immediately after giving effect to such Disposition, no Default has occurred and is continuing or would result therefrom, (ii) after giving to such Disposition, the Company shall be pro forma compliance with each of the Financial Covenants, (iii) the consideration received in respect of such Disposition shall be equal to or greater than the fair market value of the assets subject to such Disposition and (iv) the Administrative Agent shall have received, at least three Business Days prior to the consummation of such Disposition (or such shorter period as to which the Administrative Agent may agree), a certificate of a Financial Officer of the Company, in form and substance satisfactory to the Administrative Agent, certifying as to the matters set forth in this clause (f);

(f)    other Dispositions for fair market value in an aggregate amount since the Effective Date not to exceed $25,000,000 (determined at the time of any such Disposition); and

(g)    the Disposition of the “MEPU Assets”, the “Medusa Spar Units” and the “MEPU Cash Contribution” (as each such term is defined in the Permitted JV Contribution Agreement) by Expro-USA to the Permitted JV pursuant to and in accordance with the terms of the Permitted JV Contribution Agreement, and Dispositions of Property by the Permitted JV permitted to be made without “Mutual Consent of the Board” (as defined in the Permitted JV LLC Agreement) pursuant to Section 5.6(b) of the Permitted JV LLC Agreement;

provided that if after giving effect to any Disposition pursuant to Section 6.11(c) (to the extent the fair market value of the Property subject to the Casualty Event exceeds $25,000,000) or (e), the Consolidated Leverage Ratio exceeds 2.75 to 1.00 (calculated on  pro forma basis using (i) Consolidated Total Debt as of such day and (ii) Consolidated EBITDA for the period of four consecutive fiscal quarters most recently ended for which financial statements have been

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delivered pursuant to Section 5.01(a) or Section 5.01(b)), the Borrowers shall prepay the Loans to the extent required by Section 2.10(d).

Section 6.12    Termination or Modifications of the Effective Date Canam Intercompany Obligations Prior to the Investment Grade Rating Date.  Prior to the Investment Grade Rating Date, the Company will not, and will not permit any of its Subsidiaries to, (a) reduce, forgive, terminate, Dispose of, cancel or otherwise similarly modify, the Effective Date Canam Intercompany Obligations or (b) amend, modify, waive or otherwise change any term or condition relating to the Effective Date Canam Intercompany Obligation in any manner that is, or would be, taken as a whole, adverse to the interests of the Administrative Agent or any other Guaranteed Party.

Section 6.13    New Accounts Prior to the Investment Grade Rating Date.  Prior to the Investment Grade Rating Date, the Company will not, and will not permit any Subsidiary to, open or otherwise establish or maintain, or deposit, credit or otherwise transfer any Cash Receipts, securities, financial assets or any other property into, any Deposit Account, Securities Account or Commodity Account (other than any Excluded DDA) other than a Deposit Account, Securities Account or Commodity Account listed on Schedule 5.14, which is maintained with the Administrative Agent or a Lender or another financial institution reasonably acceptable to the Administrative Agent.

Section 6.14    Financial Covenants.

(a)    Prior to the Investment Grade Rating Date:

(i)    Consolidated Leverage RatioThe Company will not, as of the last day of any fiscal quarter of the Company, permit the Consolidated Leverage Ratio for the period of four consecutive fiscal quarters ending on such day, to exceed 4.00 to 1.00.

(ii)    Consolidated Interest Coverage Ratio.  The Company will not, as of the last day of any fiscal quarter of the Company, permit the Consolidated Interest Coverage Ratio for the period of four consecutive fiscal quarters ending on such day, to be less than 2.50 to 1.00.

(b)    Ratio of Consolidated Recourse Debt to Adjusted Consolidated Capitalization.  From and after the Investment Grade Rating Date, the Company will not, as of the last day of any fiscal quarter of the Company, permit the ratio of (a) Consolidated Total Debt as of such day to (b) Consolidated Total Capitalization as of such day, to exceed 60%.

Section 6.15    Amendment to Permitted JV Agreements.  From and after the Permitted JV Closing Date, the Company will not, and will not permit any of its Subsidiaries to, amend, modify or supplement (or permit to be amended, modified or supplemented), or enter into any agreement that has the effect of amending, modifying or supplementing any Permitted JV Agreement in a manner that would be adverse to the Lenders in any material respect.

Section 6.16    Minimum Domestic Liquidity Prior to the Investment Grade Rating Date.  If on March 31, 2022, (i) the Investment Grade Rating Date has not occurred and (ii) the

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outstanding principal balance of the Company’s 4.00% Notes due 2022 and 3.70% Notes due 2022 exceeds $550,000,000 in the aggregate, then the Company shall maintain Domestic Liquidity of at least $550,000,000 at all times thereafter until such notes are redeemed in whole or the Investment Grade Rating Date occurs.

Article VII
Events of Default

Section 7.01    Events of Default.  If any of the following events (“Events of Default”) shall occur at any time on or after the Effective Date:

(a)    any Borrower shall fail to pay any principal of any Loan or any reimbursement obligation in respect of any LC Disbursement when and as the same shall become due and payable, whether at the due date thereof or at a date fixed for prepayment thereof or otherwise; 

(b)    any Borrower shall fail to pay any interest on any Loan or any fee or any other amount (other than an amount referred to in clause (a) of this Section 7.01) payable under this Agreement, when and as the same shall become due and payable, and such failure shall continue unremedied for a period of five days;

(c)    any representation or warranty made or deemed made by or on behalf of the Company or any Subsidiary in or in connection with this Agreement (or any amendment or modification hereof or waiver or consent hereunder), in or in connection with any other Loan Document (or any amendment or modification thereof or waiver or consent thereunder) or in any report, certificate, financial statement or other document furnished pursuant to or in connection with this Agreement (or any amendment or modification hereof or waiver or consent hereunder) or pursuant to or in connection with any other Loan Document (or any amendment or modification thereof or waiver or consent thereunder), shall, in any such case, prove to have been incorrect in any material respect when made or deemed made;

(d)    any Borrower or any Subsidiary shall fail to observe or perform any covenant, condition or agreement contained in Section 5.02, Section 5.03 (with respect to such Borrower’s existence), Section 5.09, Section 5.10,  Section 5.12,  Section 5.14,  Section 5.16,  Section 5.18 or Article VI;

(e)    any Borrower or any Subsidiary shall fail to observe or perform any covenant, condition or agreement contained in this Agreement (other than those specified in clause (a), (b) or (d) of this Section 7.01) or in any other Loan Document, and such failure shall continue unremedied for a period of ten days after notice thereof from the Administrative Agent to the Company (which notice will be given at the request of any Lender);

(f)    the Company or any Subsidiary shall fail to make any payment (whether of principal or interest and regardless of amount) in respect of any Material Indebtedness, when and as the same shall become due and payable;

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(g)    any event or condition occurs that results in any Material Indebtedness becoming due prior to its scheduled maturity or that enables or permits (with or without the giving of notice, the lapse of time or both) the holder or holders of any Material Indebtedness or any trustee or agent on its or their behalf to cause any Material Indebtedness to become due, or to require the prepayment, repurchase, redemption or defeasance thereof, prior to its scheduled maturity; provided that this clause (g) shall not apply to secured Indebtedness that becomes due as a result of the voluntary sale or transfer of the property or assets securing such Indebtedness;

(h)    an involuntary proceeding shall be commenced or an involuntary petition shall be filed seeking (i) liquidation, reorganization or other relief in respect of the Company or any Material Subsidiary or its debts, or of a substantial part of its assets, under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect or (ii) the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Company or any Material Subsidiary or for a substantial part of its assets, and, in any such case, such proceeding or petition shall continue undismissed for 45 days or an order or decree approving or ordering any of the foregoing shall be entered;

(i)    the Company or any Material Subsidiary shall (i) voluntarily commence any proceeding or file any petition seeking liquidation, reorganization or other relief under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect, (ii) consent to the institution of, or fail to contest in a timely and appropriate manner, any proceeding or petition described in clause (h) of this Section 7.01, (iii) apply for or consent to the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Company or any Material Subsidiary or for a substantial part of its assets, (iv) file an answer admitting the material allegations of a petition filed against it in any such proceeding, (v) make a general assignment for the benefit of creditors or (vi) take any action for the purpose of effecting any of the foregoing;

(j)    the Company or any Material Subsidiary shall become unable, admit in writing its inability or fail generally to pay its debts as they become due;

(k)    one or more judgments for the payment of money in an aggregate amount in excess of $75,000,000 shall be rendered against the Company, any Subsidiary or any combination thereof and the same shall remain undischarged for a period of 30 consecutive days during which execution shall not be effectively stayed, or any action shall be legally taken by a judgment creditor to attach or levy upon any assets of the Company or any Subsidiary to enforce any such judgment;

(l)    an ERISA Event shall have occurred that, in the opinion of the Required Lenders, when taken together with all other ERISA Events that have occurred, could reasonably be expected to result in a Material Adverse Effect;

(m)    the Loan Documents after delivery thereof shall for any reason, except to the extent permitted by the terms thereof, cease to be in full force and effect and valid, binding and enforceable in accordance with their terms against any Borrower or any Guarantor party thereto or shall be repudiated by any of them, or any Borrower or any Guarantor or any of their respective Affiliates shall so state in writing; or

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(n)    a Change in Control shall occur;

then, and in every such event (other than an event with respect to any Borrower described in clause (h) or (i) of this Section 7.01), and at any time thereafter during the continuance of such event, the Administrative Agent may, and at the request of the Required Lenders shall, by notice to the Company, take either or both of the following actions, at the same or different times:  (i) terminate the Commitments, and thereupon the Commitments shall terminate immediately, and (ii) declare the Loans then outstanding to be due and payable in whole (or in part, in which case any principal not so declared to be due and payable may thereafter be declared to be due and payable), and thereupon the principal of the Loans so declared to be due and payable, together with accrued interest thereon and all fees and other obligations of the Borrowers accrued hereunder, shall become due and payable immediately, without presentment, demand, protest or other notice of any kind, all of which are hereby waived by each Borrower; and in case of any event with respect to any Borrower described in clause (h) or (i) of this Section 7.01, the Commitments shall automatically terminate and the principal of the Loans then outstanding, together with accrued interest thereon and all fees and other obligations of the Borrowers accrued hereunder, shall automatically become due and payable, without presentment, demand, protest or other notice of any kind, all of which are hereby waived by each Borrower.

Section 7.02    Remedies.

(a)    In the case of an Event of Default other than one described in Section 7.01(h) or Section 7.01(i), at any time thereafter during the continuance of such Event of Default, the Administrative Agent may, and at the request of the Required Lenders, shall, by notice to the Borrowers, take either or both of the following actions, at the same or different times:  (i) terminate the Commitments, and thereupon the Commitments shall terminate immediately, and (ii) declare the Notes and the Loans then outstanding to be due and payable in whole (or in part, in which case any principal not so declared to be due and payable may thereafter be declared to be due and payable), and thereupon the principal of the Loans so declared to be due and payable, together with accrued interest thereon and all fees and other obligations of the Borrowers and the Guarantors accrued hereunder and under the Notes and the other Loan Documents (including, without limitation, the payment of cash collateral to secure the LC Exposure as provided in Section 2.05(j)), shall become due and payable immediately, without presentment, demand, protest, notice of intent to accelerate, notice of acceleration or other notice of any kind, all of which are hereby waived by each Borrower and each Guarantor; and in case of an Event of Default described in Section 7.01(h) or Section 7.01(i), the Commitments shall automatically terminate and the Notes and the principal of the Loans then outstanding, together with accrued interest thereon and all fees and the other obligations of the Borrowers and the Guarantors accrued hereunder and under the Notes and the other Loan Documents (including, without limitation, the payment of cash collateral to secure the LC Exposure as provided in Section 2.05(j)), shall automatically become due and payable, without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrowers and each Guarantor.

(b)    In the case of the occurrence of an Event of Default, the Administrative Agent and the Lenders will have all other rights and remedies available at law and equity.

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(c)    Notwithstanding anything herein to the contrary, following the occurrence and during the continuance of an Event of Default, and notice thereof to the Administrative Agent by the Borrower or the Required Lenders, all payments received on account of the Obligations shall, subject to Section 2.19, be applied by the Administrative Agent as follows:

(i)    first, to payment or reimbursement of that portion of the Obligations constituting fees, expenses and indemnities payable to the Administrative Agent in its capacity as such;

(ii)    second, pro rata to payment or reimbursement of that portion of the Obligations constituting fees, expenses and indemnities payable to the Lenders;

(iii)    third, pro rata to payment of accrued interest on the Loans; 

(iv)    fourth, pro rata to payment of (A) principal outstanding on the Loans, (B) reimbursement obligations in respect of Letters of Credit pursuant to Section 2.05(e) (and cash collateralization of LC Exposure hereunder) and (C) Guaranteed Cash Management Obligations owing to Guaranteed Cash Management Providers;

(v)    fifth, pro rata to Guaranteed Hedging Obligations owing to Guaranteed Hedging Parties;

(vi)    sixth, pro rata to any other Obligations; and

(vii)    seventh, any excess, after all of the Obligations shall have been indefeasibly paid in full in cash, shall be paid to the Borrowers or as otherwise required by any Governmental Requirement;

provided that, for the avoidance of doubt, Excluded Guaranteed Hedging Obligations with respect to any Subsidiary Guarantor shall not be paid with amounts received from such Subsidiary Guarantor or its assets, but appropriate adjustments shall be made with respect to payments from the Borrowers and any other Guarantors to preserve the allocation to Obligations otherwise set forth above in this Section 7.02(c).

Article VIII
[Reserved]

Article IX
The Administrative Agent

Each of the Lenders and the Issuing Banks hereby irrevocably appoints the Administrative Agent as its agent and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof, together with such actions and powers as are reasonably incidental thereto.

The bank serving as the Administrative Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not the Administrative Agent, and such bank and its Affiliates may accept deposits from,

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lend money to and generally engage in any kind of business with each Borrower or any Subsidiary or other Affiliate thereof as if it were not the Administrative Agent hereunder.  In addition to and not in limitation of the foregoing, each Borrower and each Lender acknowledges that the Administrative Agent is or may be an agent, arranger and/or lender under other loans or other securities and waives any existing or future conflicts of interest associated with its role hereunder and in such other transactions.

The Administrative Agent shall not have any duties or obligations except those expressly set forth herein.  Without limiting the generality of the foregoing, (a) the Administrative Agent shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing, (b) the Administrative Agent shall not have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby that the Administrative Agent is required to exercise as directed in writing by the Required Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 10.02), and (c) except as expressly set forth herein, the Administrative Agent shall not have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to any Borrower or any of its Subsidiaries that is communicated to or obtained by the bank serving as Administrative Agent or any of its Affiliates in any capacity.  The Administrative Agent shall not be liable for any action taken or not taken by it with the consent or at the request of the Required Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 10.02) or in the absence of its own gross negligence or willful misconduct.  The Administrative Agent shall be deemed not to have knowledge of any Default unless and until written notice thereof is given to the Administrative Agent by any Borrower or a Lender, and the Administrative Agent shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement, (ii) the contents of any certificate, report or other document delivered hereunder or in connection herewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement or any other agreement, instrument or document, or (v) the satisfaction of any condition set forth in Article IV or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to the Administrative Agent. 

The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing believed by it to be genuine and to have been signed or sent by the proper Person.  The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to be made by the proper Person, and shall not incur any liability for relying thereon.  The Administrative Agent may consult with legal counsel (who may be counsel for the Borrowers), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.

The Administrative Agent may perform any and all its duties and exercise its rights and powers by or through any one or more sub-agents appointed by the Administrative Agent.  The Administrative Agent and any such sub-agent may perform any and all its duties and exercise its rights and powers through their respective Related Parties.  The exculpatory provisions of the

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preceding paragraphs shall apply to any such sub-agent and to the Related Parties of the Administrative Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent.

Subject to the appointment and acceptance of a successor Administrative Agent as provided in this paragraph, the Administrative Agent may resign at any time by notifying the Lenders, the Issuing Banks and the Company.  Upon any such resignation, the Required Lenders shall have the right, in consultation with the Company, to appoint a successor.  If no successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days after the retiring Administrative Agent gives notice of its resignation, then the retiring Administrative Agent may, on behalf of the Lenders and the Issuing Banks, appoint a successor Administrative Agent which shall be a bank with an office in New York, New York, or an Affiliate of any such bank.  Upon the acceptance of its appointment as Administrative Agent hereunder by a successor, such successor shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations hereunder.  The fees payable by the Company to a successor Administrative Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Company and such successor.  After the Administrative Agent’s resignation hereunder, the provisions of this Article IX and Section 10.03 shall continue in effect for the benefit of such retiring Administrative Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them (i) while it was acting as Administrative Agent and (ii) after such resignation or removal for as long as any of them continues to act in any capacity hereunder or under any agreement or instrument contemplated hereby, including in respect of any actions taken in connection with transferring the agency to any successor Administrative Agent.

Each Lender acknowledges and agrees that the extensions of credit made hereunder are commercial loans and letters of credit and not investments in a business enterprise or securities.  Each Lender further represents that it is engaged in making, acquiring or holding commercial loans in the ordinary course of its business and has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement as a Lender, and to make, acquire or hold Loans hereunder.  Each Lender shall, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information (which may contain material, non-public information within the meaning of the United States securities laws concerning the Borrowers and their respective Affiliates) as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any related agreement or any document furnished hereunder or thereunder and in deciding whether or to the extent to which it will continue as a Lender or assign or otherwise transfer its rights, interests and obligations hereunder.

Each Lender and each Issuing Bank hereby authorizes the Administrative Agent to release any Guarantor from the Guaranty Agreement to which it is a party (i) pursuant to the terms thereof or (ii) with respect to any Subsidiary Guarantor at such time, on the Investment Grade Rating Date pursuant to Section 10.20.

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No Lead Arranger or Lender identified on the cover page of this Agreement (other than the Administrative Agent) shall have any right, power, obligation, liability, responsibility or duty under this Agreement other than those applicable to all Lenders in their capacity as such.  Without limiting the foregoing, no Lead Arranger or Lender identified on the cover page as a “syndication agent” or “co-documentation agent” (or any similar title) shall have or be deemed to have any fiduciary relationship with any Lead Arranger or any Lender.  Each Lender acknowledges that it has not relied, and will not rely, on the Administrative Agent, any Lead Arranger or any other Lender so identified in deciding to enter into this Agreement or in taking or not taking any action hereunder.

Article X
Miscellaneous

Section 10.01    Notices.

(a)    Except in the case of notices and other communications expressly permitted to be given by telephone (and subject to paragraph (b) below), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopy, as follows:

(i)    if to a Borrower, to the Company at 300 Peach Street, P.O. Box 7000, El Dorado, Arkansas 71731-7000, Attention of Treasurer (Telecopy No. (870) 864-6274);

(ii)    if to the Administrative Agent, to JPMorgan Chase Bank, N.A., JPMorgan Loan and Agency Services Group, 500 Stanton Christiana Road, Ops 2, 3rd Floor Newark, DE 19713, Attention of Loan and Agency Services Group (Telecopy No. (302) 634-3301); and

(iii)    if to JPMorgan Chase Bank, N.A., in its capacity as Issuing Bank, to it at JPMorgan Chase Bank, N.A., Letter of Credit Group, Global Trade Services, 10420 Highland Manor Dr., Tampa, Florida 33610, Attention of James Alonzo (Telecopy No. (813) 432-5161);

(iv)    if to any other Lender, to it at its address (or telecopy number) set forth in its Administrative Questionnaire.

Notices sent by hand or overnight courier service, or mailed by certified or registered mail, shall be deemed to have been given when received; notices sent by telecopy shall be deemed to have been given when sent (except that, if not given during normal business hours for the recipient, shall be deemed to have been given at the opening of business on the next business day for the recipient).  Notices delivered through Electronic Systems, to the extent provided in paragraph (b) below, shall be effective as provided in said paragraph (b).

(b)    Notices and other communications to the Lenders and the Issuing Banks hereunder may be delivered or furnished using Electronic Systems pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices pursuant to Article II unless otherwise agreed by the Administrative Agent and the applicable

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Lender.  The Administrative Agent or the Company may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

Unless the Administrative Agent otherwise prescribes, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement), and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient, at its e-mail address as described in the foregoing clause (i), of notification that such notice or communication is available and identifying the website address therefor; provided that, for both clauses (i) and (ii) above, if such notice, email or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next business day for the recipient.

(c)    Any party hereto may change its address or telecopy number for notices and other communications hereunder by notice to the other parties hereto.

(d)    Electronic Systems.

(i)    Each Borrower agrees that the Administrative Agent may, but shall not be obligated to, make Communications (as defined below) available to the Issuing Banks and the other Lenders by posting the Communications on Debt Domain, Intralinks, Syndtrak, ClearPar or a substantially similar Electronic System.

(ii)    Any Electronic System used by the Administrative Agent is provided “as is” and “as available.”  The Agent Parties (as defined below) do not warrant the adequacy of such Electronic Systems and expressly disclaim liability for errors or omissions in the Communications.  No warranty of any kind, express, implied or statutory, including any warranty of merchantability, fitness for a particular purpose, non-infringement of third-party rights or freedom from viruses or other code defects, is made by any Agent Party in connection with the Communications or any Electronic System.  In no event shall the Administrative Agent or any of its Related Parties (collectively, the “Agent Parties”) have any liability to any Borrower or the other Loan Parties, any Lender, any Issuing Bank or any other Person or entity for damages of any kind, including direct or indirect, special, incidental or consequential damages, losses or expenses (whether in tort, contract or otherwise) arising out of any Borrower’s, any other Loan Party’s or the Administrative Agent’s transmission of communications through an Electronic System.  “Communications” means, collectively, any notice, demand, communication, information, document or other material provided by or on behalf of any Borrower or any other Loan Party pursuant to this Agreement, the other Loan Documents or the transactions contemplated therein which is distributed by the Administrative Agent, any Lender or any Issuing Bank by means of electronic communications pursuant to this Section 10.01, including through an Electronic System.

Section 10.02    Waivers; Amendments.  (a) No failure or delay by the Administrative Agent, any Issuing Bank or any Lender in exercising any right or power hereunder shall operate

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as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power.  The rights and remedies of the Administrative Agent, the Issuing Banks and the Lenders hereunder are cumulative and are not exclusive of any rights or remedies that they would otherwise have.  No waiver of any provision of this Agreement or consent to any departure by any Borrower therefrom shall in any event be effective unless the same shall be permitted by paragraph (b) of this Section 10.02, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given.  Without limiting the generality of the foregoing, the making of a Loan or issuance of a Letter of Credit shall not be construed as a waiver of any Default, regardless of whether the Administrative Agent, any Lender or any Issuing Bank may have had notice or knowledge of such Default at the time.

(b)    Subject to Section 2.13(b) and Section 10.02(c), neither this Agreement nor any provision hereof nor any other Loan Document nor any provision thereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by each Borrower and the Required Lenders or by each Borrower and the Administrative Agent with the consent of the Required Lenders; provided that no such agreement shall (i) increase the Commitment of any Lender without the written consent of such Lender, (ii) reduce the principal amount of any Loan or LC Disbursement or reduce the rate of interest thereon, or reduce any fees payable hereunder, without the written consent of each Lender affected thereby, (iii) postpone the scheduled date of payment of the principal amount of any Loan or LC Disbursement, or any interest thereon, or any fees payable hereunder, or reduce the amount of, waive or excuse any such payment, or postpone the scheduled date of expiration of any Commitment, without the written consent of each Lender affected thereby, (iv) change Section 2.17(b) or (c) in a manner that would alter the pro rata sharing of payments required thereby, without the written consent of each Lender, (v) waive or amend Section 7.02(c) or Section 10.16 without the written consent of each Lender; provided that any waiver or amendment of Section 10.16, this proviso in this Section 10.02(b)(v),  Section 10.02(b)(vi) or Section 10.02(b)(viii), shall also require the written consent of each Guaranteed Hedging Party and each Guaranteed Cash Management Provider, (vi) modify the terms of Section 7.02(c) without the written consent of each Lender, Guaranteed Hedging Party and Guaranteed Cash Management Provider adversely affected thereby, or amend or otherwise change the definition of “Guaranteed Hedging Agreement,” “Guaranteed Hedging Obligations” or “Guaranteed Hedging Party,” without the written consent of each Guaranteed Hedging Party adversely affected thereby or the definition of “Guaranteed Cash Management Agreement,” “Guaranteed Cash Management Obligations” or “Guaranteed Cash Management Provider,” without the written consent of each Guaranteed Cash Management Provider adversely affected thereby), (vii) release any Guarantor from any Guaranty Agreement (except as set forth in such Guaranty Agreement or pursuant to Section 10.20) or limit its liability in respect thereof, without the written consent of each Lender or (viii) change any of the provisions of this Section 10.02 or the definition of “Required Lenders” or any other provision hereof specifying the number or percentage of Lenders required to waive, amend or modify any rights hereunder or make any determination or grant any consent hereunder, without the written consent of each Lender; provided,  further, that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent or any Issuing Bank hereunder or under any other Loan Document without the prior written consent of

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the Administrative Agent or such Issuing Bank, as the case may be.  Notwithstanding the foregoing, any supplement to Schedule 3.14 shall be effective simply by delivering to the Administrative Agent a supplemental schedule clearly marked as such and, upon receipt, the Administrative Agent will promptly deliver a copy thereof to the Lenders.

(c)    if the Administrative Agent and the Company acting together identify any ambiguity, omission, mistake, typographical error or other defect in any provision of this Agreement or any other Loan Document, then the Administrative Agent and the Company shall be permitted to amend, modify or supplement such provision to cure such ambiguity, omission, mistake, typographical error or other defect, and such amendment shall become effective without any further action or consent of any other party to this Agreement.

Section 10.03    Expenses; Indemnity; Damage Waiver.  (a) Each Borrower is jointly and severally obligated to pay (i) all reasonable out-of-pocket expenses incurred by the Administrative Agent and its Affiliates, including the reasonable fees, charges and disbursements of counsel for the Administrative Agent, in connection with the syndication of the credit facilities provided for herein, the preparation and administration of this Agreement or any amendments, modifications or waivers of the provisions hereof (whether or not the transactions contemplated hereby or thereby shall be consummated), (ii) all reasonable out-of-pocket expenses incurred by any Issuing Bank in connection with the issuance, amendment, renewal or extension of any Letter of Credit or any demand for payment thereunder and (iii) all reasonable out-of-pocket expenses incurred by the Administrative Agent, any Issuing Bank or any Lender, including the reasonable fees, charges and disbursements of any counsel for the Administrative Agent, any Issuing Bank or any Lender, in connection with the enforcement or protection of its rights in connection with this Agreement, including its rights under this Section 10.03, or in connection with the Loans made or Letters of Credit issued hereunder, including all such reasonable out-of-pocket expenses incurred during any workout, restructuring or negotiations in respect of such Loans or Letters of Credit. 

(b)    Each Borrower shall indemnify the Administrative Agent, each Issuing Bank and each Lender, and each Related Party of any of the foregoing Persons (each such Person being called an “Indemnitee”) against, and hold each Indemnitee harmless from, any and all losses, claims, damages, liabilities and related expenses, including the reasonable fees, charges and disbursements of any counsel for any Indemnitee, incurred by or asserted against any Indemnitee arising out of, in connection with, or as a result of (i) the execution or delivery of this Agreement, any other Loan Document, or any agreement or instrument contemplated hereby, the performance by the parties hereto of their respective obligations hereunder or thereunder or the consummation of the Transactions or any other transactions contemplated hereby, (ii) any Loan or Letter of Credit or the use of the proceeds therefrom (including any refusal by any Issuing Bank to honor a demand for payment under a Letter of Credit issued by it if the documents presented in connection with such demand do not strictly comply with the terms of such Letter of Credit), (iii) any actual or alleged release of Hazardous Materials on or from any property owned or operated by the Company or any of its Subsidiaries, or any Environmental Liability related in any way to the Company or any of its Subsidiaries, or (iv) any actual or prospective claim, litigation, investigation or proceeding relating to any of the foregoing, whether or not such claim, litigation, investigation or proceeding is brought by any Borrower or any other Loan Party or its or their respective equity holders, Affiliates, creditors or any other third Person and whether

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based on contract, tort or any other theory and regardless of whether any Indemnitee is a party thereto; provided that such indemnity shall not, as to any Indemnitee, be available to the extent that such losses, claims, damages, liabilities or related expenses are determined by a court of competent jurisdiction by final and non-appealable judgment to have resulted from the gross negligence or willful misconduct of such Indemnitee.  This Section 10.03(b) shall not apply with respect to Taxes other than any Taxes that represent losses, claims or damages arising from any non-Tax claim.

(c)    To the extent that any Borrower fails to pay any amount required to be paid by it to the Administrative Agent or any Issuing Bank under paragraph (a) or (b) of this Section 10.03, each Lender severally agrees to pay to the Administrative Agent or such Issuing Bank, as the case may be, such Lender’s Applicable Percentage (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount; provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Administrative Agent or such Issuing Bank in its capacity as such.

(d)    To the extent permitted by applicable law, no Borrower shall assert, and each Borrower hereby waives, any claim against any Indemnitee, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement, any other Loan Document, or any agreement or instrument contemplated hereby or thereby, the Transactions, any Loan or Letter of Credit or the use of the proceeds thereof.

(e)    All amounts due under this Section 10.03 shall be payable promptly after written demand therefor.

Section 10.04    Successors and Assigns.  (a) The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby (including any Affiliate of any Issuing Bank that issues any Letter of Credit), except that (i) a Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by a Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section 10.04.  Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby (including any Affiliate of any Issuing Bank that issues any Letter of Credit), Participants (to the extent provided in paragraph (c) of this Section 10.04) and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent, the Issuing Banks and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b)    (i) Subject to the conditions set forth in paragraph (b)(ii) below, any Lender may assign to one or more Persons (other than an Ineligible Institution) all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment, participations in Letters of Credit and the Loans at the time owing to it) with the prior written consent (such consent not to be unreasonably withheld) of:

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(A)    each Borrower; provided that each Borrower shall be deemed to have consented to an assignment unless it shall have objected thereto by written notice to the Administrative Agent within five Business Days after having received notice thereof; provided,  further, that no consent of any Borrower shall be required for an assignment to a Lender, an Affiliate of a Lender, an Approved Fund or, if an Event of Default has occurred and is continuing, any other assignee;

(B)    the Administrative Agent; provided that no consent of the Administrative Agent shall be required for an assignment of any Commitment to an assignee that is a Lender (other than a Defaulting Lender) with a Commitment immediately prior to giving effect to such assignment; and

(C)    each Issuing Bank.

(ii)    Assignments shall be subject to the following additional conditions: 

(A)    except in the case of an assignment to a Lender or an Affiliate of a Lender or an assignment of the entire remaining amount of the assigning Lender’s Commitment or Loans of any Class, the amount of the Commitment or Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall not be less than $5,000,000 unless each of the Borrowers and the Administrative Agent otherwise consent; provided that no such consent of the Borrowers shall be required if an Event of Default has occurred and is continuing;

(B)    each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement; provided that this clause shall not be construed to prohibit the assignment of a proportionate part of all the assigning Lender’s rights and obligations in respect of one Class of Commitments or Loans;

(C)    the parties to each assignment shall execute and deliver to the Administrative Agent (x) an Assignment and Assumption or (y) to the extent applicable, an agreement incorporating an Assignment and Assumption by reference pursuant to a Platform as to which the Administrative Agent and the parties to the Assignment and Assumption are participants), together with a processing and recordation fee of $3,500; and

(D)    the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire in which the assignee designates one or more Credit Contacts to whom all syndicate-level information (which may contain material non-public information about the Loan Parties and their related parties or their respective securities) will be made available and who may receive such information in accordance with the assignee’s compliance procedures and applicable laws, including Federal and state securities laws.

For the purposes of this Section 10.04(b), the term “Approved Fund” and “Ineligible Institution” have the following meanings:

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Approved Fund” means any Person (other than a natural person) that is engaged in making, purchasing, holding or investing in bank loans and similar extensions of credit in the ordinary course of its business and that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

Ineligible Institution” means (a) a natural person, (b) a Defaulting Lender or its Lender Parent, (c) a company, investment vehicle or trust for, or owned and operated for the primary benefit of, a natural person or relative(s) thereof or (d) the Company or any of its Affiliates; provided that, such company, investment vehicle or trust shall not constitute an Ineligible Institution if it (x) has not been established for the primary purpose of acquiring any Loans or Commitments, (y) is managed by a professional advisor, who is not such natural person or a relative thereof, having significant experience in the business of making or purchasing commercial loans, and (z) has assets greater than $25,000,000 and a significant part of its activities consist of making or purchasing commercial loans and similar extensions of credit in the ordinary course of its business.

(iii)    Subject to acceptance and recording thereof pursuant to paragraph (b)(iv) of this Section 10.04, from and after the effective date specified in each Assignment and Assumption the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Section 2.14,  Section 2.15,  Section 2.16,  Section 10.03 and Article IX).  Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 10.04 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with paragraph (c) of this Section 10.04.

(iv)    The Administrative Agent, acting for this purpose as a non‑fiduciary agent of the Borrowers, shall maintain at one of its offices a copy of each Assignment and Assumption delivered to it and a register (which register may be in electronic form) for the recordation of the names and addresses of the Lenders, and the Commitment of, and principal amount (and stated interest) of the Loans and LC Disbursements owing to, each Lender pursuant to the terms hereof from time to time (the “Register”).  The entries in the Register shall be conclusive absent manifest error, and each Borrower, the Administrative Agent, the Issuing Banks and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary.  The Register shall be available for inspection by any Borrower, the Issuing Banks and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(v)    Upon its receipt of (x) a duly completed Assignment and Assumption executed by an assigning Lender and an assignee or (y) to the extent applicable, an

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agreement incorporating an Assignment and Assumption by reference pursuant to a Platform as to which the Administrative Agent and the parties to the Assignment and Assumption are participants), the assignee’s completed Administrative Questionnaire (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in paragraph (b) of this Section 10.04 and any written consent to such assignment required by paragraph (b) of this Section 10.04, the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register; provided that if either the assigning Lender or the assignee shall have failed to make any payment required to be made by it pursuant to Section 2.05(d),  Section 2.05(e),  Section 2.06(b),  Section 2.17(d) or Section 10.03(c), the Administrative Agent shall have no obligation to accept such Assignment and Assumption and record the information therein in the Register unless and until such payment shall have been made in full, together with all accrued interest thereon.  No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this paragraph.

(c)    Any Lender may, without the consent of any Borrower, the Administrative Agent or any Issuing Bank, sell participations to one or more banks or other entities (a “Participant”), other than an Ineligible Institution, in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans owing to it); provided that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (iii) each Borrower, the Administrative Agent, the Issuing Banks and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement.  Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in the first proviso to Section 10.02(b) that affects such Participant.  Each Borrower agrees that each Participant shall be entitled to the benefits of Section 2.14,  Section 2.15 and Section 2.16 (subject to the requirements and limitations therein, including the requirements under Section 2.16(f), it being understood that the documentation required under Section 2.16(f) shall be delivered to the participating Lender) to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to paragraph (b) of this Section 10.04;  provided that such Participant (A) agrees to be subject to the provisions of Section 2.18 as if it were an assignee under paragraph (b) of this Section 10.04; and (B) shall not be entitled to receive any greater payment under Section 2.14 or Section 2.16, with respect to any participation, than its participating Lender would have been entitled to receive, except to the extent such entitlement to receive a greater payment results from a Change in Law that occurs after the Participant acquired the applicable participation.  Each Lender that sells a participation agrees, at the Company’s request and expense, to use reasonable efforts to cooperate with the Company to effectuate the provisions of Section 2.18(b) with respect to any Participant.  To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 10.08 as though it were a Lender; provided that such Participant agrees to be subject to Section 2.17(c) as though it were a Lender.  Each Lender that sells a participation shall, acting solely for this purpose as an non-fiduciary agent of the Borrowers, maintain a register on which it enters the

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name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loans or other obligations under the Loan Documents (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant’s interest in any Commitments, Loans, Letters of Credit or its other obligations under any Loan Document) to any Person except to the extent that such disclosure is necessary to establish that such Commitment, Loan, Letter of Credit or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations.  The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary.  For the avoidance of doubt, the Administrative Agent (in its capacity as Administrative Agent) shall have no responsibility for maintaining a Participant Register.

(d)    Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including without limitation any pledge or assignment to secure obligations to a Federal Reserve Bank or an central bank, and this Section 10.04 shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto. 

Section 10.05    Survival.  All covenants, agreements, representations and warranties made by any Borrower herein and in the certificates or other instruments delivered in connection with or pursuant to this Agreement shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of this Agreement and the making of any Loans and issuance of any Letters of Credit, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the Administrative Agent, any Issuing Bank or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as long as the principal of or any accrued interest on any Loan or any fee or any other amount payable under this Agreement is outstanding and unpaid or a Letter of Credit is outstanding and so long as the Commitments have not expired or terminated.  The provisions of Section 2.14,  Section 2.15,  Section 2.16,  Section 10.03 and Article IX shall survive and remain in full force and effect regardless of the consummation of the transactions contemplated hereby, the repayment of the Loans, the expiration or termination of the Letters of Credit and the Commitments or the termination of this Agreement or any provision hereof.    

Section 10.06    Counterparts; Integration; Effectiveness; Electronic Execution

(a)    This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract.  This Agreement, the other Loan Documents and any separate letter agreements with respect to (i) fees payable to the Administrative Agent and (ii) the reductions of the Letter of Credit Commitment of any Issuing Bank constitute the entire contract among the parties relating to the

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subject matter hereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof.  Except as provided in Section 4.01, this Agreement shall become effective when it shall have been executed by the Administrative Agent and when the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto, and thereafter shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. 

(b)    Delivery of an executed counterpart of a signature page of this Agreement by telecopy, emailed pdf. or any other electronic means that reproduces an image of the actual executed signature page shall be effective as delivery of a manually executed counterpart of this Agreement.  The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to any document to be signed in connection with this Agreement and the transactions contemplated hereby shall be deemed to include Electronic Signatures, deliveries or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act; provided that nothing herein shall require the Administrative Agent to accept electronic signatures in any form or format without its prior written consent.

Section 10.07    Severability.  Any provision of this Agreement held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction. 

Section 10.08    Right of Setoff.  If an Event of Default shall have occurred and be continuing, each Lender and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other obligations at any time owing by such Lender or Affiliate to or for the credit or the account of any Borrower against any of and all the obligations of such Borrower now or hereafter existing under this Agreement held by such Lender, irrespective of whether or not such Lender shall have made any demand under this Agreement and although such obligations may be unmatured.  The rights of each Lender under this Section 10.08 are in addition to other rights and remedies (including other rights of setoff) which such Lender may have.

Section 10.09    Governing Law; Jurisdiction; Consent to Service of Process.  (a) This Agreement shall be construed in accordance with and governed by the law of the State of New York.

(b)    Each Borrower hereby irrevocably and unconditionally submits, for itself and its property, to the nonexclusive jurisdiction of the Supreme Court of the State of New York sitting in the Borough of Manhattan, and of the United States District Court for the Southern District of New York sitting in the Borough of Manhattan, and any appellate court from any thereof, in any action or proceeding arising out of or relating to this Agreement, or for

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recognition or enforcement of any judgment, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such New York State or, to the extent permitted by law, in such Federal court.  Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law.  Nothing in this Agreement shall affect any right that the Administrative Agent, any Issuing Bank or any Lender may otherwise have to bring any action or proceeding relating to this Agreement against any Borrower or its properties in the courts of any jurisdiction.

(c)    Each Borrower hereby irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection which it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement in any court referred to in paragraph (b) of this Section 10.09.  Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

(d)    Each party to this Agreement irrevocably consents to service of process in the manner provided for notices in Section 10.01.  Nothing in this Agreement will affect the right of any party to this Agreement to serve process in any other manner permitted by law.

(e)    In furtherance of the foregoing, MOCL hereby irrevocably appoints the Company, with an office on the date hereof at the address specified in Section 10.01, as its authorized agent with all powers necessary to receive on its behalf service of copies of the summons and complaint and any other process which may be served in any action or proceeding arising out of or relating to the Loan Documents in any of the courts in and of the State of New York.  Such service may be made by mailing or delivering a copy of such process to MOCL in care of the Company at the Company’s above address and MOCL hereby irrevocably authorizes and directs the Company to accept such service on its behalf and agrees that the failure of the Company to give any notice of any such service to MOCL shall not impair or affect the validity of such service or of any judgment rendered in any action or proceeding based thereon.  If for any reason the Company shall cease to act as process agent, MOCL shall appoint forthwith, in the manner provided for herein, a single successor process agent qualified to act as an agent for service of process with respect to all courts in and of the State of New York and acceptable to the Administrative Agent.  Nothing in this paragraph shall affect the right of the Administrative Agent or any Lender to serve legal process in any other manner permitted by law or limit the right of the Administrative Agent or any Lender to bring any action or proceeding against MOCL or its property in the courts of other jurisdictions. To the extent that MOCL has or hereafter may acquire any right of immunity from jurisdiction of any court on the grounds of sovereignty or otherwise with respect to itself or its property, MOCL hereby irrevocably waives such immunity for itself and for its property in respect of all of its Obligations under the Loan Documents.

Section 10.10    Waiver of Jury Trial.  Each party hereto hereby waives, to the fullest extent permitted by applicable law, any right it may have to a trial by jury in any legal proceeding directly or indirectly arising out of or relating to this

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Agreement or the Transactions contemplated hereby (whether based on contract, tort or any other theory).  Each party hereto (a) certifies that no representative, agent or attorney of any other party has represented, expressly or otherwise, that such other party would not, in the event of litigation, seek to enforce the foregoing waiver and (b) acknowledges that it and the other parties hereto have been induced to enter into this Agreement by, among other things, the mutual waivers and certifications in this Section 10.10.

Section 10.11    Headings.  Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

Section 10.12    Confidentiality.  Each of the Administrative Agent, the Issuing Banks and the Lenders agrees to maintain the confidentiality of the Information (as defined below), except that Information may be disclosed (a) to its and its Affiliates’ directors, officers, employees and agents, including accountants, legal counsel and other advisors (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to the extent requested by any Governmental Authority (including any self-regulatory authority or self-regulatory body) such as the National Association of Insurance Commissioners, (c) to the extent required by applicable laws or regulations or by any subpoena or similar legal process, (d) to any other party to this Agreement, (e) in connection with the exercise of any remedies hereunder or any suit, action or proceeding relating to this Agreement or the enforcement of rights hereunder, (f) subject to an agreement containing provisions substantially the same as those of this Section 10.12, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement or (ii) any actual or prospective counterparty (or its advisors) to any swap or derivative transaction relating to any Borrower and its obligations, (g) with the consent of the Company, (h) to the extent such Information (i) becomes publicly available other than as a result of a breach of this Section 10.12 or (ii) becomes available to the Administrative Agent, any Issuing Bank or any Lender on a nonconfidential basis from a source other than the Borrowers, or (i) on a confidential basis to (i) any rating agency in connection with rating the Borrowers or their Subsidiaries or the credit facility established hereby, (ii) the CUSIP Service Bureau or any similar agency in connection with the issuance and monitoring of CUSIP numbers with respect to the credit facility established hereby or (iii) to any provider of credit insurance.  For the purposes of this Section 10.12, “Information” means all information received from any Borrower relating to such Borrower or its business, other than any such information that is available to the Administrative Agent, the Issuing Banks or any Lender on a nonconfidential basis prior to disclosure by such Borrower and other than information pertaining to this Agreement routinely provided by arrangers to data service providers, including league table providers, that serve the lending industry; provided that, in the case of information received from a Borrower after the Effective Date, such information is clearly identified at the time of delivery as confidential.  Any Person required to maintain the confidentiality of Information as provided in this Section 10.12 shall be considered to have complied with its obligation to do so if such Person has exercised the same

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degree of care to maintain the confidentiality of such Information as such Person would accord to its own confidential information.    

Section 10.13    Material Non-Public Information.

(a)    EACH LENDER ACKNOWLEDGES THAT INFORMATION AS DEFINED IN Section 10.12 FURNISHED TO IT PURSUANT TO THIS AGREEMENT MAY INCLUDE MATERIAL NON-PUBLIC INFORMATION CONCERNING THE BORROWERS AND THEIR RELATED PARTIES OR THEIR RESPECTIVE SECURITIES, AND CONFIRMS THAT IT HAS DEVELOPED COMPLIANCE PROCEDURES REGARDING THE USE OF MATERIAL NON-PUBLIC INFORMATION AND THAT IT WILL HANDLE SUCH MATERIAL NON-PUBLIC INFORMATION IN ACCORDANCE WITH THOSE PROCEDURES AND APPLICABLE LAW, INCLUDING FEDERAL AND STATE SECURITIES LAWS.

(b)    ALL INFORMATION, INCLUDING REQUESTS FOR WAIVERS AND AMENDMENTS, FURNISHED BY ANY BORROWER OR THE ADMINISTRATIVE AGENT PURSUANT TO, OR IN THE COURSE OF ADMINISTERING, THIS AGREEMENT WILL BE SYNDICATE-LEVEL INFORMATION, WHICH MAY CONTAIN MATERIAL NON-PUBLIC INFORMATION ABOUT THE LOAN PARTIES AND THEIR RELATED PARTIES OR THEIR RESPECTIVE SECURITIES.  ACCORDINGLY, EACH LENDER REPRESENTS TO EACH BORROWER AND THE ADMINISTRATIVE AGENT THAT IT HAS IDENTIFIED IN ITS ADMINISTRATIVE QUESTIONNAIRE A CREDIT CONTACT WHO MAY RECEIVE INFORMATION THAT MAY CONTAIN MATERIAL NON-PUBLIC INFORMATION IN ACCORDANCE WITH ITS COMPLIANCE PROCEDURES AND APPLICABLE LAW.

Section 10.14    Interest Rate Limitation.  Notwithstanding anything herein to the contrary, if at any time the interest rate applicable to any Loan, together with all fees, charges and other amounts which are treated as interest on such Loan under applicable law (collectively the “Charges”), shall exceed the maximum lawful rate (the “Maximum Rate”) which may be contracted for, charged, taken, received or reserved by the Lender holding such Loan in accordance with applicable law, the rate of interest payable in respect of such Loan hereunder, together with all Charges payable in respect thereof, shall be limited to the Maximum Rate and, to the extent lawful, the interest and Charges that would have been payable in respect of such Loan but were not payable as a result of the operation of this Section 10.14 shall be cumulated and the interest and Charges payable to such Lender in respect of other Loans or periods shall be increased (but not above the Maximum Rate therefor) until such cumulated amount, together with interest thereon at the Federal Funds Effective Rate to the date of repayment, shall have been received by such Lender.

Section 10.15    USA Patriot Act.  Each Lender that is subject to the requirements of the Patriot Act hereby notifies each Borrower and the Guarantors that pursuant to the requirements of the Act, it is required to obtain, verify and record information that identifies each Borrower and the Guarantors, which information includes the name and address of each Borrower and other information that will allow such Lender to identify each Borrower and the Guarantors in accordance with the Act.

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Section 10.16    Hedging Agreements; Cash Management Agreements.

(a)    Except as provided in Section 10.02(b), no Guaranteed Hedging Provider or Guaranteed Cash Management Provider shall have any voting rights under any Loan Document as a result of the existence of any Guaranteed Hedging Obligation or Guaranteed Cash Management Obligation owed to it.

(b)    If any Lender determines, acting reasonably, that any applicable law has made it unlawful, or that any Governmental Authority has asserted that it is unlawful, for such Lender to hold or benefit from a Lien over real property pursuant to any law of the United States or any State thereof, such Lender may notify the Administrative Agent and disclaim any benefit of such Lien to the extent of such illegality; provided, that such determination or disclaimer by such Lender shall not invalidate or render unenforceable such Lien for the benefit of any other Lender.

Section 10.17    Acknowledgement and Consent to Bail-In of EEA Financial Institutions.  Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any EEA Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the write-down and conversion powers of an EEA Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)    the application of any Write-Down and Conversion Powers by an EEA Resolution Authority to any such liabilities arising hereunder which may be payable to it by any party hereto that is an EEA Financial Institution; and

(b)    the effects of any Bail-In Action on any such liability, including, if applicable:

(i)    a reduction in full or in part or cancellation of any such liability;

(ii)    a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such EEA Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

(iii)    the variation of the terms of such liability in connection with the exercise of the write-down and conversion powers of any EEA Resolution Authority.

Section 10.18    No Advisory or Fiduciary Responsibility.  In connection with all aspects of each transaction contemplated hereby (including in connection with any amendment, waiver or other modification hereof or of any other Loan Document), the Borrowers acknowledge and agree, and acknowledge its Subsidiaries’ understanding, that: (a) (i) no fiduciary, advisory or agency relationship (except solely with respect to the Administrative Agent or the applicable Lender maintaining a Register or Participant Register, as applicable, as expressly provided in

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Section 10.04) between the Borrowers and the Subsidiaries, on the one hand, and the Administrative Agent or any Lender, on the other hand, is intended to be or has been created in respect of the transactions contemplated hereby or by the other Loan Documents, irrespective of whether the Administrative Agent or any Lender has advised or is advising the Borrower or any Subsidiary on other matters; (ii) the arranging and other services regarding this Agreement provided by the Administrative Agent and the Lenders are arm’s-length commercial transactions between the Borrowers and the Subsidiaries, on the one hand, and the Administrative Agent and the Lenders, on the other hand; (iii) the Borrowers have consulted their own legal, accounting, regulatory and tax advisors to the extent that it has deemed appropriate; and (iv) the Borrowers are capable of evaluating, and understand and accept, the terms, risks and conditions of the transactions contemplated hereby and by the other Loan Documents; and (b) (i) the Administrative Agent and the Lenders each is and has been acting solely as a principal and, except as expressly agreed in writing by the relevant parties, has not been, is not, and will not be acting as an advisor, agent or fiduciary for the Borrowers or any of the Subsidiaries, or any other Person; (ii) neither the Administrative Agent nor the Lenders has any obligation to the Borrowers or any of the Subsidiaries with respect to the transactions contemplated hereby except those obligations expressly set forth herein and in the other Loan Documents; and (iii) the Administrative Agent and the Lenders and their respective Affiliates may be engaged, for their own accounts or the accounts of customers, in a broad range of transactions that involve interests that differ from those of the Borrowers and the Subsidiaries, and neither the Administrative Agent nor the Lenders has any obligation to disclose any of such interests to the Borrowers or the Subsidiaries. To the fullest extent permitted by Law, the Borrowers hereby waive and release any claims that they may have against the Administrative Agent and the Lenders with respect to any breach or alleged breach of agency or fiduciary duty in connection with any aspect of any transaction contemplated hereby.

Section 10.19    Currency Conversion; Judgment Currency.

(a)    Notwithstanding anything to the contrary contained herein, if any payment of any obligation shall be made in a currency other than the currency required hereunder, such amount shall be converted into the currency required hereunder at the rate determined by the Administrative Agent, as the rate quoted by it in accordance with methods customarily used by the Administrative Agent for such or similar purposes as the spot rate for the purchase by the Administrative Agent of the required currency with the currency of actual payment through its principal foreign exchange trading office at approximately 11:00 a.m. (local time at such office) two Business Days prior to the effective date of such conversion; provided that the Administrative Agent may obtain such spot rate from another financial institution actively engaged in foreign currency exchange if the Administrative Agent does not then have a spot rate for the required currency.

(b)    The obligations of each party hereto in respect of any sum due to any other party hereto or any holder of the obligations owing hereunder (the “Applicable Creditor”) shall, notwithstanding any judgment in a currency (the “Judgment Currency”) other than dollars, be discharged only to the extent that, on the Business Day following receipt by the Applicable Creditor of any sum adjudged to be so due in the Judgment Currency, the Applicable Creditor may in accordance with normal banking procedures in the relevant jurisdiction purchase dollars with the Judgment Currency; and if the amount of dollars so purchased is less than the sum

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originally due to the Applicable Creditor in dollars, such party agrees, as a separate obligation and notwithstanding any such judgment, to indemnify the Applicable Creditor against such deficiency.  The obligations of the parties contained in this Section shall survive the termination of this Agreement and the payment of all other amounts owing hereunder.

Section 10.20    Release of Guarantees.  On the Investment Grade Rating Date, so long as no Default has occurred and is continuing, then, promptly following the Company’s written request therefor, the Administrative Agent shall execute a release of each Subsidiary Guarantor from its surety and guarantee liabilities and obligations as a Guarantor under the Guaranty Agreement (and each such Person shall cease to constitute a “Guarantor” thereunder and hereunder), other than those obligations which are expressly stated to survive termination of the Guaranty Agreement.  For the avoidance of doubt, any such release shall in no way impair or affect the liabilities and obligations of the Company (including in its capacity as a Guarantor) under the Credit Agreement and the other Loan Documents, or any other Borrower under the Credit Agreement and the other Loan Documents (other than the Guaranty Agreement), all of which liabilities and obligations shall continue in full force and effect on and after the Investment Grade Rating Date.

[SIGNATURE PAGES BEGIN NEXT PAGE]



 

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and delivered by their respective authorized officers as of the day and year first above written.



 

 



 

 



MURPHY OIL CORPORATION



 

 



By:

/s/ John B. Gardner



Name:

John B. Gardner



Title:

Vice President and Treasurer







 

 



 

 



MURPHY EXPLORATION & PRODUCTION COMPANY – INTERNATIONAL



 

 



By:

/s/ John B. Gardner



Name:

John B. Gardner



Title:

Vice President and Treasurer







 

 



 

 



MURPHY OIL COMPANY LTD.



 

 



By:

/s/ John B. Gardner



Name:

John B. Gardner



Title:

Vice President and Treasurer





Signature Page

Credit Agreement


 

 





 

 

 

 

Administrative Agent, Issuing Bank, & Lender:

JPMORGAN CHASE BANK, N.A.

 

 

 

 

By:

/s/ Jeffery C. Miller

 

Name:

Jeffery C. Miller

 

Title:

Executive Director

 

Signature Page

Credit Agreement


 

 





 

 

 

 

Syndication Agent, Issuing Bank, & Lender:

BANK OF AMERICA, N.A.

 

 

 

 

By:

/s/ Pace Doherty

 

Name:

Pace Doherty

 

Title:

Vice President



Signature Page

Credit Agreement


 

 





 

 

 

 

Co-Documentation Agent, Issuing Bank, & Lender:

WELLS FARGO BANK, NATIONAL ASSOCIATION

 

 

 

 

By:

/s/ Borden Tennant

 

Name:

Borden Tennant

 

Title:

Vice President

 

Signature Page

Credit Agreement


 

 





 

 

Lender:

DNB CAPITAL LLC



 

 



By:

/s/ James Grubb



Name:

James Grubb



Title:

Vice President



 

 



By:

/s/ Robert Dupree



Name:

Robert Dupree



Title:

Senior Vice President







 

 

Co-Documentation Agent and Issuing Bank:

DNB BANK ASA, NEW YORK BRANCH



 

 



By:

/s/ Evan W. Uhlick



Name:

Evan W. Uhlick



Title:

Senior Vice President



 

 



By:

/s/ Philip F. Kurpiewski



Name:

Philip F. Kurpiewski



Title:

Senior Vice President

 

Signature Page

Credit Agreement


 

 





 

 

Co-Documentation Agent, Issuing Bank & Lender:

MUFG BANK, LTD.



 

 



By:

Stephen W. Warfel



Name:

Stephen W. Warfel



Title:

Managing Director

 

Signature Page

Credit Agreement


 

 





 

 

Co-Documentation Agent, Issuing Bank & Lender:

THE BANK OF NOVA SCOTIA, HOUSTON BRANCH



 

 



By:

/s/ Donovan Crandall



Name:

Donovan Crandall



Title:

Managing Director

 

Signature Page

Credit Agreement


 

 





 

 

Co-Documentation Agent, Issuing Bank & Lender:

REGIONS BANK



 

 



By:

/s/ Kelly L. Elmore III



Name:

Kelly L. Elmore III



Title:

Managing Director

 

Signature Page

Credit Agreement


 

 





 

 

Lender:

EXPORT DEVELOPMENT CANADA



 

 



By:

/s/ Trevor Mulligan



Name:

Trevor Mulligan



Title:

Financing Manager



 

 



By:

/s/ Michael Lambe



Name:

Michael Lambe



Title:

Financing Manager

 

Signature Page

Credit Agreement


 

 





 

 

Lender:

CAPITAL ONE, NATIONAL ASSOCIATION



 

 



By:

/s/ Christopher Kuna



Name:

Christopher Kuna



Title:

Director

 

Signature Page

Credit Agreement


 

 





 

 

Lender:

BMO HARRIS BANK N.A.



 

 



By:

/s/ Gumaro Tijerina



Name:

Gumaro Tijerina



Title:

Managing Director

 

Signature Page

Credit Agreement


 

 





 

 

Lender:

HSBC BANK USA, N.A.



 

 



By:

/s/ John Robinson



Name:

John Robinson



Title:

Managing Director

 

Signature Page

Credit Agreement


 

 



c

 

 

Lender:

SUMITOMO MITSUI BANKING CORPORATION



 

 



By:

/s/ James D. Weinstein



Name:

James D. Weinstein



Title:

Managing Director

 

Signature Page

Credit Agreement


 

 





 

 

Lender:

BANCORPSOUTH BANK



 

 



By:

/s/ Ronald L. Hendrix



Name:

Ronald L. Hendrix



Title:

Executive Vice President

 

Signature Page

Credit Agreement


 

 





 

 

Lender:

HANCOCK WHITNEY BANK



 

 



By:

/s/ Nancy Moragas



Name:

Nancy Moragas



Title:

Senior Vice President

 

Signature Page

Credit Agreement


 

 





 

 

Lender:

STANDARD CHARTERED BANK



 

 



By:

/s/ Daniel Mattern



Name:

Daniel Mattern



Title:

Associate Director

 

Signature Page

Credit Agreement


 

 





 

 

Lender:

SOCIETE GENERALE



 

 



By:

/s/ Diego Medina



Name:

Diego Medina



Title:

Director

 

Signature Page

Credit Agreement


 

 





 

 

Lender:

SIMMONS BANK



 

 



By:

/s/ Robert L. Robinson, IV



Name:

Robert L. Robinson, IV



Title:

Community President

 



 

Signature Page

Credit Agreement


 

Schedule 2.01

to Credit Agreement

COMMITMENTS



 

 


Lender

Amount of Commitment

Percentage of Commitment

JPMorgan Chase Bank, N.A.

$130,000,000.00  8.125000000% 

Bank of America, N.A.

$130,000,000.00  8.125000000% 

Wells Fargo Bank, National Association

$130,000,000.00  8.125000000% 

DNB Capital LLC

$130,000,000.00  8.125000000% 

MUFG Bank, Ltd.

$130,000,000.00  8.125000000% 

The Bank of Nova Scotia

$130,000,000.00  8.125000000% 

Regions Bank

$130,000,000.00  8.125000000% 

Export Development Canada

$100,000,000.00  6.250000000% 

Capital One, National Association

$100,000,000.00  6.250000000% 

BMO Harris Bank N.A.

$100,000,000.00  6.250000000% 

HSBC Bank USA, N.A.

$70,000,000.00  4.375000000% 

Sumitomo Mitsui Banking Corporation

$70,000,000.00  4.375000000% 

BancorpSouth Bank

$65,000,000.00  4.062500000% 

Hancock Whitney Bank

$50,000,000.00  3.125000000% 

Standard Chartered Bank

$50,000,000.00  3.125000000% 

Societe Generale

$50,000,000.00  3.125000000% 

Simmons Bank

$35,000,000.00  2.187500000% 

Total:

$1,600,000,000  100.000000000% 



 

 


 

 



Schedule 2.05
to Credit Agreement

EXISTING LETTERS OF CREDIT



 

 

 

 

 

 

 

Alias

Pricing Option

Facility/Borrowers

Current Amount

Original Amount

CCY

Effective Date

Adjusted Expiry

BOA 68134815

Standby Letter of Credit

R/C COMM / MURPHY EXPLOR & PROD CO - INT

12,850.00 

USD

16-Aug-17

30-Oct-18

GT110035/17

Standby Letter of Credit

R/C COMM / MURPHY EXPLOR & PROD CO - INT

2,975,609.76 

USD

5-Oct-17

20-Nov-18

GT110121/18

Standby Letter of Credit

R/C COMM / MURPHY EXPLOR & PROD CO - INT

632,511.07  632,511.07 

USD

13-Mar-18

12-Jun-19

GT110129/18

Standby Letter of Credit

R/C COMM / MURPHY EXPLOR & PROD CO - INT

126,502.00  126,502.00 

USD

13-Mar-18

12-Jun-19

GT110130/18

Standby Letter of Credit

R/C COMM / MURPHY EXPLOR & PROD CO - INT

126,502.00  126,502.00 

USD

3-Apr-18

2-Jul-19

GT110136/18

Standby Letter of Credit

R/C COMM / MURPHY EXPLOR & PROD CO - INT

5,060.00  5,060.00 

USD

6-Jun-18

7-Mar-19

TFTS-952327

Standby Letter of Credit

R/C COMM / MURPHY EXPLOR & PROD CO - INT

669,200.00  631,911.53 

USD

22-Mar-17

19-May-19

OSB48621GWS CAD

Standby Letter of Credit

R/C COMM / MURPHY OIL COMPANY LTD.

14,477,296.79  14,181,238.78 

USD

20-Jun-18

19-Jun-19

BOA 68133139

Standby Letter of Credit

R/C COMM / MURPHY OIL CORP

2,575,000.00  2,900,000.00 

USD

24-May-17

24-May-19

IS0010871

Standby Letter of Credit

R/C COMM / MURPHY OIL CORP

102,071.00  102,071.00 

USD

1-Feb-17

3-Feb-20

OSB31299GWS CAD

Standby Letter of Credit

R/C COMM / MURPHY OIL CORP

1,151,277.92  1,119,778.50 

USD

9-Nov-16

18-Oct-19

OSB46464GWS CAD

Standby Letter of Credit

R/C COMM / MURPHY OIL CORP

381,303.25  387,852.29 

USD

5-Apr-18

31-Dec-19

GT110153/18

Standby Letter of Credit

R/C COMM / MURPHY EXPLOR & PROD CO - INT

4,843.79  4,843.79 

USD

25-Sep-18

24-Sep-19

GT110154/18

Standby Letter of Credit

R/C COMM / MURPHY EXPLOR & PROD CO - INT

4,843.79  4,843.79 

USD

25-Sep-18

24-Sep-19

GT110155/18

Standby Letter of Credit

R/C COMM / MURPHY EXPLOR & PROD CO - INT

4,843,787.84  4,843,787.84 

USD

25-Sep-18

24-Sep-19



2


 

 

Schedule 3.14
to Credit Agreement

SUBSIDIARIES



 

 

 

 

 

 

 

 

Name of Subsidiary

Type of Entity

Jurisdiction

Principal Place of Business

Chief Executive Office

Equity Interests Issued

Material Subsidiary

Guarantor/Required Subsidiary Guarantor

Excluded Canam Entity

Arkansas Oil Company

Corporation1

Delaware

Arkansas

El Dorado

100 %
Common Stock2

No

No

No

Caledonia Land Company

Corporation

Delaware

Arkansas

El Dorado

100 %
Common Stock

No

No

No

El Dorado Engineering Inc.

Corporation

Delaware

Arkansas

El Dorado

100 %
Common Stock

No

No

No

El Dorado Contractors

Corporation

Delaware

Arkansas

El Dorado

100 %
Common Stock

No

No

No

Marine Land Company

Corporation

Delaware

Arkansas

El Dorado

100 %
Common Stock

No

No

No

Murphy Eastern Oil Company

Corporation

Delaware

Inactive

El Dorado

100 %
Common Stock

No

No

No

Murphy Exploration & Production Company

Corporation

Delaware

Holding Company

Houston

100 %
Common Stock

Yes

Guarantor

No

________________________

1 All Subsidiaries are “C” corporations or the equivalent in other jurisdictions.

2 All Subsidiaries have issued common stock. There are no other classes of equity except see notes below pertaining to certain Australian entities.

3


 

 

Name of Subsidiary

Type of Entity

Jurisdiction

Principal Place of Business

Chief Executive Office

Equity Interests Issued

Material Subsidiary

Guarantor/Required Subsidiary Guarantor

Excluded Canam Entity

Mentor Holding Corporation

Corporation

Delaware

Inactive

El Dorado

100 %
Common Stock

No

No

No

Mentor Excess and Surplus Lines Insurance Company

Corporation

Delaware

Inactive

El Dorado

100 %
Common Stock

No

No

No

MIRC
Corporation

Corporation

Louisiana

Inactive

El Dorado

100 %
Common Stock

No

No

No

Murphy Building Corporation

Corporation

Delaware

Arkansas

El Dorado

100 %
Common Stock

No

No

No

Murphy Exploration & Production Company – International

Corporation

Delaware

Worldwide

Houston

100 %
Common Stock

Yes

Guarantor

No

Canam Offshore Limited

Corporation

Bahamas

Holding Company

Nassau

100 %
Common Stock

Yes

No

Yes

Canam Brunei Oil Ltd.

Corporation

Bahamas

Brunei

Kuala Lumpur

100 %
Common Stock

No

No

Yes

Murphy Peninsular Malaysia Oil Co., Ltd.

Corporation

Bahamas

Malaysia

Kuala Lumpur

100 %
Common Stock

No

No

Yes

Murphy Sabah Oil Co., Ltd.

Corporation

Bahamas

Malaysia

Kuala Lumpur

100 %
Common Stock

No

No

Yes

Murphy Sarawak Oil Co., Ltd.

Corporation

Bahamas

Malaysia

Kuala Lumpur

100 %
Common Stock

No

No

Yes

4


 

 

Name of Subsidiary

Type of Entity

Jurisdiction

Principal Place of Business

Chief Executive Office

Equity Interests Issued

Material Subsidiary

Guarantor/Required Subsidiary Guarantor

Excluded Canam Entity

El Dorado Exploration, S.A.

Corporation

Delaware

Inactive

N/A

100 %
Common Stock

No

No

No

Murphy Asia Oil Co., Ltd.

Corporation

Bahamas

SE Asia

Kuala Lumpur

100 %
Common Stock

No

No

No

Murphy Australia Holdings Pty.
Ltd

Corporation

Western Australia

Australia

Perth

100%
Preferred3

No

No

No

Murphy Australia AC/P 57 Oil Pty. Ltd.

Corporation

Western Australia

Australia

Perth

100 %
Common Stock

No

No

No

Murphy Australia AC/P 58 Oil Pty. Ltd.

Corporation

Western Australia

Australia

Perth

100 %
Common Stock

No

No

No

Murphy Australia EPP43 Oil
Pty. Ltd.

Corporation

Western Australia

Australia

Perth

100 %
Common Stock

No

No

No

Murphy Australia NT/P80 Oil Pty. Ltd

Corporation

Western Australia

Australia

Perth

100 %
Common Stock

No

No

No

Murphy Australia Oil Pty. Ltd

Corporation

Western Australia

Australia

Perth

100%
Preferred4

No

No

No

Murphy Australia AC/P 36 Oil Pty. Limited

Corporation

Western Australia

Australia

Perth

100 %
Common Stock

No

No

No

________________________

3 Redeemable preferred shares issued which are treated as common shares for U.S. purposes.

4 See note no. 3 above.

5


 

 

Name of Subsidiary

Type of Entity

Jurisdiction

Principal Place of Business

Chief Executive Office

Equity Interests Issued

Material Subsidiary

Guarantor/Required Subsidiary Guarantor

Excluded Canam Entity

Murphy Australia WA-408-P
Oil Pty. Ltd.

Corporation

Western Australia

Australia

Perth

100%
Preferred5

No

No

No

Murphy Australia WA-423-P
Oil Pty. Ltd.

Corporation

Western Australia

Australia

Perth

100 %
Common Stock

No

No

No

Murphy Australia WA-476-P
Oil Pty. Ltd.

Corporation

Western Australia

Australia

Perth

100 %
Common Stock

No

No

No

Murphy Australia WA-481-P
Oil Pty. Ltd.

Corporation

Western Australia

Australia

Perth

100%
Preferred6

No

No

No

Murphy Australia AC/P 59 Oil Pty. Ltd.

Corporation

Western Australia

Australia

Perth

100 %
Common Stock

No

No

No

Murphy Brazil Exploracao e Producao de Petroleo e Gas Ltda.

Corporation

Brazil

Brazil

N/A7

100 %
Common Stock

No

No

No

Murphy Cameroon Elombo Oil Co., Ltd.

Corporation

Bahamas

Cameroon8

 

100 %
Common Stock

No

No

No

Murphy Cuu Long Bac Oil Co., Ltd.

Corporation

Bahamas

Vietnam

Ho Chi Minh City

100 %
Common Stock

No

No

No

________________________

5 See note no. 3 above.

6 See note no. 3 above.

7 No office has been established.

8 Murphy has exited Cameroon.

6


 

 

Name of Subsidiary

Type of Entity

Jurisdiction

Principal Place of Business

Chief Executive Office

Equity Interests Issued

Material Subsidiary

Guarantor/Required Subsidiary Guarantor

Excluded Canam Entity

Murphy Dai Nam Oil Co., Ltd.

Corporation

Bahamas

Vietnam

Ho Chi Minh City

100 %
Common Stock

No

No

No

Murphy Equatorial Guinea Oil Co., Ltd.

Corporation

Bahamas

Equatorial Guinea9

N/A

100 %
Common Stock

No

No

No

Murphy Exploration (Alaska), Inc.

Corporation

Delaware

Alaska

Houston

100 %
Common Stock

No

No

No

Murphy International Marketing & Trading Company

Corporation

Delaware

Worldwide

Houston

100 %
Common Stock

No

No

No

Murphy Italy Oil Company

Corporation

Delaware

Inactive

Houston

100 %
Common Stock

No

No

No

Murphy Luderitz Oil Co., Ltd.

Corporation

Bahamas

Namibia

Windhoek

100 %
Common Stock

No

No

No

Murphy Nha Trang Oil Co., Ltd.

Corporation

Bahamas

Vietnam

Ho Chi Minh City

100 %
Common Stock

No

No

No

Murphy Overseas Ventures Inc.

Corporation

Delaware

Worldwide

Houston

100 %
Common Stock

No

No

No

________________________

9 Murphy has exited Equatorial Guinea.

7


 

 

Name of Subsidiary

Type of Entity

Jurisdiction

Principal Place of Business

Chief Executive Office

Equity Interests Issued

Material Subsidiary

Guarantor/Required Subsidiary Guarantor

Excluded Canam Entity

Murphy Phuong Nam Oil Co., Ltd.

Corporation

Bahamas

Vietnam

Ho Chi Minh City

100 %
Common Stock

No

No

No

Murphy Semai IV Ltd.

Corporation

Bahamas

Indonesia10

N/A

100 %
Common Stock

No

No

No

Murphy Semai Oil Co., Ltd. Note: Name changed to Murphy Cuu Long Tay Oil Co., Ltd.

Corporation

Bahamas

Vietnam

Ho Chi Minh City

100 %
Common Stock

No

No

Yes11

Murphy Somali Oil Company

Corporation

Delaware

Somalia12

N/A

100 %
Common Stock

No

No

No

Murphy South Barito, Ltd.

Corporation

Bahamas

Indonesia

N/A

100 %
Common Stock

No

No

No

Murphy Spain Oil Company

Corporation

Delaware

Spain

Madrid13

100 %
Common Stock

No

No

No

Murphy West Africa, Ltd.

Corporation

Bahamas

Republic of Congo14

N/A

100 %
Common Stock

No

No

No

________________________

10 Murphy has exited Indonesia.

11 Moved under Canam Offshore Ltd. effective June 2016 for Vietnam operations.

12 No activity.

13 Branch office in process of winding down.

14 Murphy has exited Congo.

8


 

 

Name of Subsidiary

Type of Entity

Jurisdiction

Principal Place of Business

Chief Executive Office

Equity Interests Issued

Material Subsidiary

Guarantor/Required Subsidiary Guarantor

Excluded Canam Entity

Murphy Wokam Oil Company, Ltd.

Corporation

Bahamas

Indonesia

N/A

100 %
Common Stock

No

No

No

Murphy Worldwide, Inc.

Corporation

Delaware

Worldwide

Houston

100 %
Common Stock

No

No

No

Ocean Exploration Company

Corporation

Delaware

Holding Company

Houston

100 %
Common Stock

No

No

No

Odeco Italy Oil Company

Corporation

Delaware

Inactive

N/A

100 %
Common Stock

No

No

No

Murphy Offshore Oil Co. Ltd.

Corporation

Bahamas

Worldwide

Nassau

100 %
Common Stock

No

No

No

Murphy Netherlands Holdings B.V.

Corporation

Netherlands

Netherlands

N/A15

100 %
Common Stock

No

No

No

Murphy Netherlands Holdings II B.V.

Corporation

Netherlands

Netherlands

N/A

100 %
Common Stock

No

No

No

Murphy Sur,
S. de R. L. de C.V.

Corporation

Mexico

Mexico

N/A16

100 %
Common Stock

No

No

No

Murphy Exploration & Production Company – USA

Corporation

Delaware

United States

Houston

100 %
Common Stock

Yes

Guarantor

No

_____________________________

15 No offices have been established in the Netherlands.

16 No offices have been established in the Netherlands.

9


 

 

Name of Subsidiary

Type of Entity

Jurisdiction

Principal Place of Business

Chief Executive Office

Equity Interests Issued

Material Subsidiary

Guarantor/Required Subsidiary Guarantor

Excluded Canam Entity

Murphy Crude Oil Marketing, Inc.

Corporation

Delaware

United States

Houston

100 %
Common Stock

No

No

No

Murphy Gas Gathering Inc.

Corporation

Delaware

United States

Houston

100 %
Common Stock

No

No

No

Murphy Oil Company Ltd.

Corporation

Canada

Canada

Calgary

100 %
Common Stock

Yes

No

No

Murphy Canada Exploration Company

Corporation

Nova Scotia

Canada

Calgary

100 %
Common Stock

No

No

No

Murphy Canada Holding ULC

Corporation

Alberta

Canada

Calgary

100 %
Common Stock

No

No

No

Murphy Canada, Ltd.

Corporation

Canada

Canada

Calgary

100 %
Common Stock

No

No

No

Murphy Finance Company

Corporation

Nova Scotia

N/A17

N/A

100 %
Common Stock

No

No

No

Murphy Realty Inc.

Corporation

Delaware

Arkansas

El Dorado

100 %
Common Stock

No

No

No

New Murphy Oil (UK)Corporation

Corporation

Delaware

Holding Company

El Dorado

100 %
Common Stock

No

No

No

_____________________________

17 Inactive.

10


 

 

Name of Subsidiary

Type of Entity

Jurisdiction

Principal Place of Business

Chief Executive Office

Equity Interests Issued

Material Subsidiary

Guarantor/Required Subsidiary Guarantor

Excluded Canam Entity

Murphy Petroleum Limited

Corporation

England

U.K.

N/A18

100 %
Common Stock

No

No

No

Alnery No. 166 Ltd.

Corporation

England

U.K.

N/A

100 %
Common Stock

No

No

No

Murphy Retail Acquisition Limited

Corporation

England

U.K.

N/A

100 %
Common Stock

No

No

No

Murco Petroleum Limited

Corporation

England

U.K.

N/A

100 %
Common Stock

No

No

No

European Petroleum Distributors Ltd.

Corporation

England

U.K.

N/A

100 %
Common Stock

No

No

No

________________________

18 Murphy no longer has continuing operations in the U.K.

11


 

 



Schedule 5.14
to Credit Agreement

ACCOUNTS



Account

Financial Institution

or Intermediary

Account

Number

Account Type

Excluded

DDA (Y/N)

Murphy Oil Corporation - General (Wires)

Bank of America, N. A., New York, NY

USD A/C # 004451259985

Depository Account

Y

Murphy Oil Corporation - CDA (ACH/Check)

Bank of America, N. A., New York, NY

USD A/C # 003359985473

Depository Account

Y

Murphy Oil Corporation - Lease Rental

Bank of America, N. A., New York, NY

USD A/C # 003359985481

Depository Account

Y

Murphy Exploration & Production Company

Bank of America, N. A., New York, NY

USD A/C # 004451259862

Depository Account

Y

Canam Offshore Limited

Bank of America, N. A., New York, NY

USD A/C # 004451259859

Depository Account

Y

Murphy Oil Corporation

BancorpSouth, El Dorado, AR

USD A/C # 6400074412/ 6400074404

Marine Land Co/ Caledonia Land Co

N

Murphy Brazil Exploracao E. Producao De Petroleo E Gas

Banco J P Morgan S. A.

BRL A/C #01.102947-7

Depository Account

N

Murphy Brasil Exploracao E. Producao De Petroleo E Gas Ltda.

Bank of America, Sao Paulo, Brazil

BRL A/C #11057015

Depository Account

N

Canam Brunei Oil Ltd.

Bank of America, Malaysia Berhad

USD A/C # 0076953752

Depository Account

N

Murphy Oil Corporation

Capital One Bank N. A.

USD A/C # 4670140461

Money Market Cash Account

N

12


 

 



Account

Financial Institution

or Intermediary

Account

Number

Account Type

Excluded

DDA (Y/N)

Murphy Oil Corporation

J. P. Morgan Chase Bank, New York, New York

USD A/C # 325-008361

Depository Account

N

New Murphy Oil (UK) Corporation

Bank of America, N. A., New York, NY

USD A/C # 004451259901

Depository Account

Y

Murphy Sur S de RL de CV

Bank of America Mexico, S. A., Mexico

USD A/C# 14633028

Depository Account

N

Murphy Sur S de RL de CV

Bank of America Mexico, S. A., Mexico

MXN A/C# 14633010

Depository Account

N

Murphy Sur S de RL de CV

J. P. Morgan Chase Bank, New York, New York

USD A/C # 780180639

Depository Account

N

Murphy Oil Corporation

Whitney Bank

USD A/C # 60071102

Depository Account

N

Murphy Sur S de RL de CV

Banco J P Morgan S. A.

MXN A/C # 77644593

Depository Account

N

Murphy Netherlands Holdings BV

Bank of America Merrill Lynch Intl Ltd., Amsterdam

USD A/C # 20451013

Depository Account

N

Murphy Netherlands Holdings II BV

Bank of America Merrill Lynch Intl Ltd., Amsterdam

USD A/C # 20452011

Depository Account

N

Murphy Netherlands Holdings BV

J. P. Morgan Chase Bank, Amsterdam

USD A/C # NL68CHAS0626000578

Depository Account

N

Murphy Netherlands Holdings II BV

J. P. Morgan Chase Bank, Amsterdam

USD A/C # NL71CHAS0626000330

Depository Account

N

Murphy Nha Trang Oil Co., Ltd.

J. P. Morgan Chase Bank

USD A/C # 0076958206

Depository Account

N



13


 

 

Account

Financial Institution

or Intermediary

Account

Number

Account Type

Excluded

DDA (Y/N)



Ho Chi Minh Branch, Vietnam

VND A/C # 0076958205

 

 

Murphy Phuong Nam Oil Co., Ltd.

J. P. Morgan Chase Bank

USD A/C # 0076958246

Depository Account

N

Ho Chi Minh Branch, Vietnam

VND A/C # 0076958245

Murphy Cuu Long Bac Oil Co., Ltd.

J. P. Morgan Chase Bank

USD A/C # 0076958288

Depository Account

N

Ho Chi Minh Branch, Vietnam

VND A/C # 0076958301

Murphy Sarawak Oil Co., Ltd

J. P. Morgan Chase Bank Berhad

USD A/C # 0076953295

Depository Account

N

Kuala Lumpur, Malaysia

 

 

MYR A/C # 0076953294

USD A/C # 0076953458

 

Murphy Sarawak Oil Co., Ltd

J.P. Morgan Chase Bank Berhad            Kuala Lumpur, Malaysia

USD A/C # 0076953492

Payroll Account

N

Murphy Sarawak Oil Co., Ltd

J.P. Morgan Chase Bank Berhad            Kuala Lumpur, Malaysia

USD A/C # 0076953669

Depository Account

N

Murphy Sarawak Oil Co., Ltd

J. P. Morgan Chase, Labuan Branch Labuan, Malaysia

Master USD A/C # 3440000137

Depository Account

N

Murphy Sabah Oil Co., Ltd

Bank of America N. A., New York, NY

USD A/C # 004451259875

Depository Account

Y



14


 

 

Account

Financial Institution

or Intermediary

Account

Number

Account Type

Excluded

DDA (Y/N)

Murphy Sabah Oil Co., Ltd

J. P. Morgan Chase Bank Berhad

USD A/C # 0076953293

Depository Account

N

Kuala Lumpur, Malaysia

MYR A/C # 0076953292

 

USD A/C # 0076953457

Murphy Sabah Oil Co., Ltd

J. P. Morgan Chase Bank Berhad

Kuala Lumpur, Malaysia

 

 

MYR A/C # 0076953570

 

Depository Account

N

Murphy Sarawak Oil Co., Ltd

J. P. Morgan Chase Bank Berhad

Kuala Lumpur, Malaysia

 

 

 

MYR A/C # 0076953569

 

 

Depository Account

N

Murphy Sabah Oil Co., Ltd

 

Standard Chartered Bank Malaysia Berhad

 

 

MYR A/C # 312193490119

 

Depository Account

N

Murphy Sarawak Oil Co., Ltd

 

Standard Chartered Bank Malaysia Berhad

 

 

MYR A/C # 312193489870

 

Depository Account

N

Murphy Oil Corporation

Bank of Tokyo-Mitsubishi UFJ, Ltd.

USD A/C # 820000973

Depository Account

Y

15


 

 



Account

Financial Institution

or Intermediary

Account

Number

Account Type

Excluded

DDA (Y/N)

Murphy Oil Corporation

J. P. Morgan Chase Bank, New York, NY

USD A/C # 5029438

Money Market Cash Account

N

Murphy Oil Corporation

Wells Fargo Bank

USD A/C # 793-3000992336

Money Market Cash Account

N

Murphy Oil Corporation

Bank of America, New York, NY

USD A/C # 5S4-04P36-1-7 EJE

Money Market Cash Account

N

Murphy Sabah Oil Co. Ltd.

J. P. Morgan Chase Bank, New York, NY

USD A/C # ILF0004459

Money Market Cash Account

N

Murphy Sabah Oil Co. Ltd.

Wells Fargo Bank, New York, NY

USD A/C # 3722-3000992404

Money Market Cash Account

N

Murphy Australia Oil Pty. Ltd.

J. P. Morgan Chase Bank, Sydney, Australia

AUD A/C # 083602700

Depository Account

N

USD A/C # 0083602735

Murphy Australia Holdings Pty Ltd.

J. P. Morgan Chase Bank, Sydney, Australia

USD A/C # 0083602671

 

Depository Account

N

Murphy Australia EPP43 Oil Pty Ltd.

J. P. Morgan Chase Bank, Sydney, Australia

USD A/C # 0083602794

 

Depository Account

N

Murphy Australia AC/P57 Oil Pty Ltd.

J. P. Morgan Chase Bank, Sydney, Australia

USD A/C # 0083602874

 

Depository Account

N

Murphy Australia AC/P58 Oil Pty Ltd.

J. P. Morgan Chase Bank, Sydney, Australia

USD A/C # 0083602882

 

 

Depository Account

N

Murphy Australia AC/P59 Oil Pty Ltd.

J. P. Morgan Chase Bank, Sydney, Australia

USD A/C # 0083602890

Depository Account

N



16


 

 

Account

Financial Institution

or Intermediary

Account

Number

Account Type

Excluded

DDA (Y/N)

Murphy Petroleum Ltd.

Bank of America NA

London, UK

GBP A/C # 80451017

Depository Account

N

USD A/C # 80451025

MURCO Petroleum Ltd.

Bank of America NA

London, UK

GBP A/C # 80449020                     USD A/C # 80449012

Depository Account

N

Murphy Eastern Oil Company

Bank of America NA, London, UK

USD A/C # 80450019

Depository Account

N

MURCO Petroleum Ltd.

JP Morgan Chase Bank NA

London, UK

USD A/C # 20543702

Depository Account

N

MURCO Petroleum Ltd.

National Westminster Bank

GBP A/C # 04426886

Depository Account

N

GBP A/C # 20579381

Murphy Oil Corporation

MUFG / Union Bank

General USD A/C # 0021420914

Depository Account

N

Murphy Oil Corporation

MUFG / Union Bank

Controlled Disb USD A/C #  9081002454

Controlled Disbursement Account

N

Murphy Spain Oil Company

Bank of America Merrill Lynch Intl Ltd.

EUR A/C # ES79 1485 0001 0900 3663 1014

Depository Account

N

Murphy Exploration & Production Company – USA/Y Bar Ranch Ltd.

JP Morgan Chase Bank, N.A.

USD A/C # 528207496

Escrow Account

Y

Murphy Oil Corporation

Scotiabank, Ontario, Canada

CDN A/C # 129890008818

Depository Account

N

Murphy Oil Company Ltd.

Scotiabank, Ontario, Canada

CDN A/C # 10009 0439118

Depository Account

 

N

 

 

USD A/C # 129898926913 

 

Murphy Oil Company Ltd.

Scotiabank, Ontario, Canada

CDN A/C # 129890007013

Pool Accounts

N

17


 

 



Account

Financial Institution

or Intermediary

Account

Number

Account Type

Excluded

DDA (Y/N)



 

USD A/C # 129890349518

 

 

Murphy Canada Ltd.

Scotiabank, Ontario, Canada

CDN A/C # 12989 0003816
USD A/C # 12989 0350311

Depository Account

N

Murphy Oil Canada

Scotiabank, Ontario, Canada

CDN A/C # 12989 0005010

Depository Account

N

Murphy Oil Company Ltd.

CIBC

CDN A/C # 00009-5814812  (Terra Nova)

 

Depository Account

N

USD A/C # 00009-0274216  (Terra Nova)

 

Murphy Oil Company Ltd.

CIBC

CDN A/C # 894-18540

T-Bill Investment Account

N

Murphy Oil Company Ltd.

Scotiabank, Ontario, Canada

USD A/C # 800-50673

Investment Account

N

Murphy Oil Company Ltd.

MUFG Bank, Ltd.

USD A/C #0820001619

Investment Account

N

Murphy Oil Company Ltd.

Scotiabank, Ontario, Canada

CDN A/C # 78047309-14

Trust Accounts

N

CDN A/C # 78047311-10

CDN A/C # 78047312-19

CDN A/C # 78047308-15

CDN A/C # 78049077-10

Murphy Overseas Ventures Inc.

Deutsche Bank

USD A/C # 002-0677-051

Depositary Accounts

N

IDR A/C # 002-0677-001

Murphy Overseas Ventures Inc.

Citibank Bank

USD A/C # 010-6185.506

Depositary Accounts

N

IDR A/C # 010-6185.018



18


 

 

Schedule 6.01
to Credit Agreement

EXISTING INDEBTEDNESS

1.    Promissory Note, dated as of June 28, 2016, made by Canam Offshore Limited, a corporation organized under the laws of the Bahamas, and payable to the order of Murphy Oil Company Ltd., a Canadian corporation, in an original principal amount of $1,204,429,777.78.

2.    SEMI-FPS Lease Agreement, dated as of November 9, 2012 between Sabah Shell Petroleum Company Limited and Gumusut-Kakap Semi-Floating Production System (Labuan Limited) (as amended prior to the date hereof).



 

19


 

 

Schedule 6.03
to Credit Agreement

EXISTING LIENS

None.

20


 

 



Schedule 6.09
to Credit Agreement

EXISTING INVESTMENTS

None.



 

21


 

 

EXHIBIT A

FORM OF

ASSIGNMENT AND ASSUMPTION

This Assignment and Assumption (the “Assignment and Assumption”) is dated as of the Effective Date set forth below and is entered into by and between [Insert name of Assignor] (the “Assignor”) and [Insert name of Assignee] (the “Assignee”).  Capitalized terms used but not defined herein shall have the meanings given to them in the Credit Agreement identified below (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), receipt of a copy of which is hereby acknowledged by the Assignee.  The Standard Terms and Conditions set forth in Annex 1 attached hereto are hereby agreed to and incorporated herein by reference and made a part of this Assignment and Assumption as if set forth herein in full.

For an agreed consideration, the Assignor hereby irrevocably sells and assigns to the Assignee, and the Assignee hereby irrevocably purchases and assumes from the Assignor, subject to and in accordance with the Standard Terms and Conditions and the Credit Agreement, as of the Effective Date inserted by the Administrative Agent as contemplated below (i) all of the Assignor’s rights and obligations in its capacity as a Lender under the Credit Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest identified below of all of such outstanding rights and obligations of the Assignor under the respective facilities identified below (including any letters of credit and guarantees included in such facilities) and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of the Assignor (in its capacity as a Lender) against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned pursuant to clauses (i) and (ii) above being referred to herein collectively as the “Assigned Interest”).  Such sale and assignment is without recourse to the Assignor and, except as expressly provided in this Assignment and Assumption, without representation or warranty by the Assignor.

1.    Assignor:    ______________________________

2.    Assignee:    ______________________________
                                   [and is an Affiliate/Approved Fund of [identify Lender]]

3.    Borrowers:  Murphy Oil Corporation, Murphy Exploration & Production Company − International and Murphy Oil Company Ltd.

4.    Administrative Agent:    JPMorgan Chase Bank, N.A., as the administrative agent under the Credit Agreement

5.    Credit Agreement:    Credit Agreement dated as of November [  ], 2018, among Murphy Oil Corporation, Murphy Exploration & Production Company International, and

Exhibit A (Page 1)

Credit Agreement

 


 

 

Murphy Oil Company Ltd., as Borrowers, the Lenders parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents parties thereto

6.    Assigned Interest:



 

 

 

Facility Assigned

Aggregate Amount of Commitment / Loans for all Lenders

Amount of Commitment /

Loans Assigned

Percentage Assigned of Commitment / Loans19



$

$

%



$

$

%



$

$

%



Effective Date:  :  _____________ ___, 20___ [TO BE INSERTED BY ADMINISTRATIVE AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER IN THE REGISTER THEREFOR.]

The Assignee agrees to deliver to the Administrative Agent a completed Administrative Questionnaire in which the Assignee designates one or more Credit Contacts to whom all syndicate-level information (which may contain material non-public information about the Borrowers and their Related Parties or their respective securities) will be made available and who may receive such information in accordance with the Assignee’s compliance procedures and applicable laws, including Federal and state securities laws.

The terms set forth in this Assignment and Assumption are hereby agreed to:



 

 



ASSIGNOR



 

 



[NAME OF ASSIGNOR]



 

 



 

 



By:

 



 

Name:



 

Title:





 

 



ASSIGNEE



 

 



[NAME OF ASSIGNEE]



 

 



 

 



By:

 



 

Name:



 

Title:

________________________

19 Set forth, to at least 9 decimals, as a percentage of the Commitments/Loans of all Lenders thereunder

Exhibit A (Page 2)

Credit Agreement

 


 

 





 

 

Consented to and Accepted:

 



 

 

JPMORGAN CHASE BANK, N.A.,

 

 

as Administrative Agent

 

 



 

 



 

 

By:

 

 



 

Name:



 

Title:







 

 

[Consented to:] 20

 



 

 

MURPHY OIL CORPORATION,

 

 

as Borrower

 

 



 

 



 

 

By:

 

 



 

Name:



 

Title:





MURPHY EXPLORATION & PRODUCTION COMPANY INTERNATIONAL,

as Borrower

 

 



 

 



 

 

By:

 

 



 

Name:



 

Title:



________________________

20 To be added only if the consent of the Borrowers and/or other parties (e.g. Issuing Banks) is required by the terms of the Credit Agreement.

Exhibit A (Page 3)

Credit Agreement

 


 

 









 

 

MURPHY OIL COMPANY LTD.,

as Borrower

 

 



 

 



 

 

By:

 

 



 

Name:



 

Title:



 

 



 

 

[NAME OF RELEVANT PARTY]

 

 



 

 



 

 

By:

 

 



 

Name:



 

Title:

Exhibit A (Page 4)

Credit Agreement

 


 

 

ANNEX 1

STANDARD TERMS AND CONDITIONS FOR
ASSIGNMENT AND ASSUMPTION

1.    Representations and Warranties. 

1.1    Assignor.  The Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of the Assigned Interest, (ii) the Assigned Interest is free and clear of any lien, encumbrance or other adverse claim, (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and (iv) it is not a Defaulting Lender; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with the Credit Agreement or any other documents or instruments delivered pursuant thereto, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Credit Agreement or any collateral thereunder, (iii) the financial condition of the Company, any of its Subsidiaries or Affiliates or any other Person obligated in respect of the Credit Agreement or (iv) the performance or observance by the Company, any of its Subsidiaries or Affiliates or any other Person of any of their respective obligations under the Credit Agreement or any other documents or instruments delivered pursuant thereto.

1.2.    Assignee.  The Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and to become a Lender under the Credit Agreement, (ii) it is not an Ineligible Institution and it satisfies the requirements, if any, specified in the Credit Agreement that are required to be satisfied by it in order to acquire the Assigned Interest and become a Lender, (iii) from and after the Effective Date, it shall be bound by the provisions of the Credit Agreement as a Lender thereunder and, to the extent of the Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it is sophisticated with respect to decisions to acquire assets of the type represented by the Assigned Interest and either it, or the Person exercising discretion in making its decision to acquire the Assigned Interest, is experienced in acquiring assets of such type, (v) it has received a copy of the Credit Agreement, together with copies of the most recent financial statements delivered pursuant to Section 5.01 thereof, as applicable, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assignment and Assumption and to purchase the Assigned Interest on the basis of which it has made such analysis and decision independently and without reliance on the Administrative Agent or any other Lender, and (vi) attached to the Assignment and Assumption is any documentation required to be delivered by it pursuant to the terms of the Credit Agreement, duly completed and executed by the Assignee; and (b) agrees that (i) it will, independently and without reliance on the Administrative Agent, the Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

2.    Payments.  From and after the Effective Date, the Administrative Agent shall make all payments in respect of the Assigned Interest (including payments of principal, interest, fees and

Exhibit A (Page 5)

Credit Agreement

 


 

 

other amounts) to the Assignor for amounts which have accrued to but excluding the Effective Date and to the Assignee for amounts which have accrued from and after the Effective Date.

3.    General Provisions.  This Assignment and Assumption shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns.  This Assignment and Assumption may be executed in any number of counterparts, which together shall constitute one instrument.  Acceptance and adoption of the terms of this Assignment and Assumption by the Assignee and the Assignor by Electronic Signature or delivery of an executed counterpart of a signature page of this Assignment and Assumption by any Electronic System shall be effective as delivery of a manually executed counterpart of this Assignment and Assumption.  This Assignment and Assumption shall be governed by, and construed in accordance with, the law of the State of New York.



 

Exhibit A (Page 6)

Credit Agreement

 


 

 

EXHIBIT B-1

FORM OF OPINION OF DAVIS POLK & WARDWELL LLP

 

Exhibit B-1

Credit Agreement


 

 

EXHIBIT B-2

FORM OF OPINION OF OSLER, HOSKIN & HARCOURT LLP

 

Exhibit B-2

Credit Agreement

 


 

EXHIBIT C-1



[FORM OF]

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Not Partnerships For U.S. Federal Income Tax Purposes)



Reference is hereby made to the Credit Agreement dated as of November [  ], 2018 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among Murphy Oil Corporation (the “Company”), Murphy Exploration & Production Company- International, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, and each lender from time to time party thereto. 

Pursuant to the provisions of Section 2.16 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the Loan(s) (as well as any Note(s) evidencing such Loan(s)) in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Code, (iii) it is not a ten percent shareholder of the Company within the meaning of Section 871(h)(3)(B) of the Code and (iv) it is not a controlled foreign corporation related to the Company as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished the Administrative Agent and the Company with a certificate of its non-U.S. Person status on IRS Form W-8BEN.  By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Company and the Administrative Agent, and (2) the undersigned shall have at all times furnished the Company and the Administrative Agent with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.



 

 

[NAME OF LENDER]

 



 

 



By:

 



Name:

 



Title:

 



 

 



Date:

          ,     , 20[  ]



 

Exhibit C-1

Credit Agreement


 

EXHIBIT C-2



[FORM OF]

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Not Partnerships For U.S. Federal Income Tax Purposes)



Reference is hereby made to the Credit Agreement dated as of November [ ], 2018 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among Murphy Oil Corporation (the “Company”), Murphy Exploration & Production Company- International, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, and each lender from time to time party thereto

Pursuant to the provisions of Section 2.16 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the participation in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Code, (iii) it is not a ten percent shareholder of the Company within the meaning of Section 871(h)(3)(B) of the Code, and (iv) it is not a controlled foreign corporation related to the Company as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished its participating Lender with a certificate of its non-U.S. Person status on IRS Form W-8BEN.  By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender in writing, and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.



 

 

[NAME OF PARTICIPANT]

 



 

 



By:

 



Name:

 



Title:

 



 

 



Date:

          ,     , 20[  ]



 

Exhibit C-2

Credit Agreement


 

EXHIBIT C-3



[FORM OF]

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Partnerships For U.S. Federal Income Tax Purposes)



Reference is hereby made to the Credit Agreement dated as of November [  ], 2018 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among Murphy Oil Corporation (the “Company”), Murphy Exploration & Production Company- International, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, and each lender from time to time party thereto

Pursuant to the provisions of Section 2.16 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the participation in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such participation, (iii) with respect such participation, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of the Company within the meaning of Section 871(h)(3)(B) of the Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to the Company as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished its participating Lender with IRS Form W-8IMY accompanied by one of the following forms from each of its partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption.  By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.



 

 

[NAME OF PARTICIPANT]

 



 

 



By:

 



Name:

 



Title:

 



 

 



Date:

          ,     , 20[  ]

 

Exhibit C-3

Credit Agreement


 

EXHIBIT C-4



[FORM OF]

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Partnerships For U.S. Federal Income Tax Purposes)



Reference is hereby made to the Credit Agreement dated as of November [  ], 2018 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among Murphy Oil Corporation (the “Company”), Murphy Exploration & Production Company- International, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, and each lender from time to time party thereto. 

Pursuant to the provisions of Section 2.16 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the Loan(s) (as well as any Note(s) evidencing such Loan(s)) in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such Loan(s) (as well as any Note(s) evidencing such Loan(s)), (iii) with respect to the extension of credit pursuant to this Credit Agreement, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of the Company within the meaning of Section 871(h)(3)(B) of the Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to the Company as described in Section 881(c)(3)(C) of the Code.

The undersigned has furnished the Administrative Agent and the Company with IRS Form W-8IMY accompanied by one of the following forms from each of its partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption.  By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Company and the Administrative Agent, and (2) the undersigned shall have at all times furnished the Company and the Administrative Agent with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.



 

 

[NAME OF LENDER]

 



 

 



By:

 



Name:

 



Title:

 



 

 



Date:

          ,     , 20[  ]



 

Exhibit C-4

Credit Agreement


 

EXHIBIT D



[FORM OF]

COMPLIANCE CERTIFICATE



Reference is hereby made to the Credit Agreement dated as of November [  ], 2018 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among Murphy Oil Corporation (the “Company”), Murphy Exploration & Production Company International, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, and each lender from time to time party thereto.  This certificate is delivered to you pursuant to Section 5.01(d) of the Credit Agreement.

1.    I, [_______________], a Responsible Officer of the Borrower, have reviewed the financial statements of the Borrower and its Subsidiaries for the [fiscal year][fiscal quarter] ended [__________] and such statements fairly present in all material respects the financial condition and results of operations of the Company and its consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied[, subject to normal year-end audit adjustments and the absence of footnotes] 21.

2.    As of the date hereof, no Default or Event of Default has occurred and is continuing [or specify Default and describe any actions taken or proposed to be taken with respect thereto].

3.    (a) The Borrower is in compliance with the financial covenants contained in Section 6.14 of the Credit Agreement as shown on Schedule 1 attached hereto.

    (b) Attached hereto as Schedule 2 are consolidating financial statements demonstrating the portion of Consolidated EBITDA attributable to the Excluded MOCL Entities.  The Leverage Ratio Ex-MOCL as of the last day of the [fiscal year][fiscal quarter] ended [__________] is as shown on Schedule 2 attached hereto, and a MOCL Guarantee Trigger Event [has][has not] occurred.

4.    No change in GAAP or in the application thereof has occurred since the date of the audited financial statements referred to in Section 3.04 [or, if any such change has occurred, specifying the effect of such change on the financial statements accompanying such certificate].

5.     The identity of each Required Subsidiary Guarantor, Material Subsidiary, Guarantor and Excluded Canam Entity as of the end of such [fiscal quarter][fiscal year] (and calculations with respect thereto) are as set forth on Schedule 3 attached hereto and  to the extent necessary pursuant to the definition of “Required Subsidiary Guarantor” and/or “Material Subsidiary”, as applicable, Schedule 3 designates sufficient additional Subsidiaries as Required Subsidiary Guarantors or Material Subsidiaries, respectively, so as to comply with the definition of “Required Subsidiary Guarantor” or “Material Subsidiary”, respectively.

6.    The amount of cash dividends declared and paid by Canam to the Loan Parties pursuant to Section 5.18 for such [fiscal quarter][fiscal year], is $[___________], and evidence thereof is attached hereto as Schedule 4.  

 [Signature Page Follows]



________________________

21 [To be included in compliance certificates for quarterly financials]

Exhibit D

Credit Agreement


 

EXHIBIT D



Executed and delivered this [___] day of [________].



 

 



MURPHY OIL CORPORATION,



a Delaware corporation



 

 



By:

 



Name:

 



Title:

 



 

Exhibit D

Credit Agreement


 

 



EXHIBIT E



FORM OF GUARANTY AGREEMENT



[see attached]

 

Exhibit E-1

Credit Agreement


 

 

Execution Version





GUARANTY



dated as of



November 28, 2018



Among



MURPHY OIL CORPORATION,



MURPHY EXPLORATION & PRODUCTION COMPANY – INTERNATIONAL,



THE OTHER GUARANTORS PARTY HERETO FROM TIME TO TIME,



and



JPMORGAN CHASE BANK, N.A.,

as Administrative Agent







 

 


 

 



This GUARANTY, dated as of November 28, 2018 is among MURPHY OIL CORPORATION, a Delaware corporation (the “Company”), MURPHY EXPLORATION & PRODUCTION COMPANY – INTERNATIONAL, a Delaware corporation (“Expro-Intl.”), each of the Subsidiaries of the Company that is a signatory hereto, and each other Person that may become a party hereto as provided herein, and JPMORGAN CHASE BANK, N.A., as Administrative Agent for the Guaranteed Parties (together, with its successors and assigns, the “Administrative Agent”).



Reference is made to the Credit Agreement, dated as of November 28, 2018 (as amended, restated, amended and restated, modified or supplemented from time to time, the “Credit Agreement”), by and among the Company, Expro-Intl., Murphy Oil Company Ltd., a Canadian corporation, the Administrative Agent, the Lenders and Issuing Banks from time to time party thereto and the other agents and arrangers party thereto.



The Lenders have agreed to extend credit to the Borrowers and the Issuing Banks have indicated their willingness to issue Letters of Credit on the terms and conditions set forth in the Credit Agreement.  The obligations of the Lenders and Issuing Banks to extend such credit are, in each case, conditioned upon, among other things, the execution and delivery of this Agreement by each Guarantor (as defined below).  The Guarantors are Affiliates of one another and will derive substantial direct and indirect benefits from the extensions of credit to the Borrowers pursuant to the Credit Agreement, and are willing to execute and deliver this Agreement in order to induce the Lenders and Issuing Banks to extend such credit.  Accordingly, the parties hereto agree as follows:



ARTICLE I



Definitions.  

Section 1.01      Credit Agreement Definitions.  



Capitalized terms used in this Agreement, including the preamble and introductory paragraphs hereto, and not otherwise defined herein have the meanings specified in Section 1.01 of the Credit Agreement.



The rules of construction specified in Sections 1.02 through 1.04 of the Credit Agreement also apply to this Agreement.



Section 1.02     Other Defined Terms.  As used in this Agreement, the following terms have the meanings specified below:



Accommodation Payment” has the meaning assigned to such term in Article III.  



Agreement” means this Guaranty (as amended, restated, amended and restated, supplemented or otherwise modified from time to time).



Allocable Amount” has the meaning assigned to such term in Article III.  



Credit Agreement” has the meaning assigned to such term in the preliminary statement of this Agreement.



Debtor Relief Laws” means the Bankruptcy Code of the United States, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium,

 


 

 

rearrangement, receivership, insolvency, reorganization, or similar debtor relief Laws of the United States or other applicable jurisdictions from time to time in effect and affecting the rights of creditors generally.



Law” has the same meaning as the defined term “Governmental Requirement” in the Credit Agreement.



Guaranteed Obligations” mean the “Obligations” as defined in the Credit Agreement.



Guaranteed Parties” means, collectively, the Administrative Agent, the Issuing Banks, the Lenders, the Guaranteed Cash Management Providers, the Guaranteed Hedging Parties, any Affiliate of a Lender to which Obligations are owed and each co-agent or sub-agent appointed by the Administrative Agent pursuant to Article IX of the Credit Agreement.



Guarantors” means, collectively, (a) the Company, (b) Expro-Intl., (c) Murphy Exploration & Production Company, a Delaware corporation, (d) Murphy Exploration & Production Company – USA, a Delaware corporation and (e) any other Subsidiary of the Company that becomes a party to this Agreement after the Effective Date pursuant to Section 5.13;  provided that if any Guarantor is released from its obligations hereunder as provided in Section 5.12(b) or Section 5.12(c), such Person shall cease to be a Guarantor hereunder and for all purposes effective upon such release.



Guaranty Supplement” means an instrument substantially in the form of Exhibit I hereto.



Termination Conditions” means (i) all Obligations (including, without limitation, all principal, interest (including interest accruing during the pendency of an insolvency or liquidation proceeding, regardless of whether allowed or allowable in such insolvency or liquidation proceeding) and premium, if any, on all Loans, and all fees, costs, expenses and other amounts payable under the Credit Agreement and the other Loan Documents) shall have been paid in full in cash (other than contingent indemnification obligations and obligations under or in respect of Guaranteed Hedging Agreements and Guaranteed Cash Management Agreements), (ii) no Letter of Credit is outstanding (other than Letters of Credit that have been cash collateralized or otherwise secured to the satisfaction of the applicable Issuing Bank), (iii) all of the Commitments have been terminated, (iv) no Guaranteed Hedging Agreement is outstanding and all amounts payable by any Borrower or any Subsidiary to any Guaranteed Hedging Party shall have been paid in full (other than contingent indemnification obligations), or if any Guaranteed Hedging Agreement is outstanding, credit support arrangements acceptable in the sole discretion of the Guaranteed Hedging Party party thereto have been made to secure any Borrower’s or any Subsidiary’s obligations thereunder to such Guaranteed Hedging Party or other arrangements mutually agreed upon including, without limitation, upon the refinancing of the Credit Agreement, the granting of pari passu guarantees with such refinancing Indebtedness to the Guaranteed Hedging Party which guarantees the Guaranteed Hedging Agreements on a pro rata basis with such refinancing Indebtedness, and otherwise on terms no less favorable to the Guaranteed Hedging Party than those contained in the Loan Documents, or such Guaranteed Hedging Agreement has been novated or assigned to one or more third parties and all amounts required to be paid by any Borrower or any Subsidiary in respect of any such novation shall have been paid in full (other than contingent indemnification obligations) and (v) the payment in full in cash of all amounts owed under and the termination of all obligations under each Guaranteed Cash Management Agreement has occurred (other than contingent indemnification obligations and obligations under Guaranteed Cash Management Agreements as to which arrangements satisfactory to the applicable Guaranteed Cash Management Provider shall have been made, including, without limitation, upon the refinancing of the Credit Agreement, the granting of pari passu guarantees with such refinancing Indebtedness to the Guaranteed Cash Management Provider which guarantees the Guaranteed Cash Management Agreements on a pro rata basis with such refinancing Indebtedness, and

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otherwise on terms no less favorable to the Guaranteed Cash Management Provider than those contained in the Loan Documents).



UFCA” has the meaning assigned to such term in Article III.  



UFTA” has the meaning assigned to such term in Article III.  

ARTICLE II

Guarantee

Section 2.01     Guarantee.  Each Guarantor hereby irrevocably, absolutely and unconditionally, guarantees, jointly with the other Guarantors and severally, as a primary obligor and not merely as a surety, to the Administrative Agent, for the ratable benefit of the Guaranteed Parties and their respective successors, indorsees, transferees and assigns, the prompt and complete payment and performance when due (whether at the stated maturity, by acceleration or otherwise and whether such Guaranteed Obligations are now existing or hereafter incurred) of the Guaranteed Obligations.  Each of the Guarantors further agrees that the Guaranteed Obligations may be extended, increased or renewed, amended or modified, in whole or in part, without notice to, or further assent from, such Guarantor and that such Guarantor will remain bound upon its guarantee hereunder notwithstanding any such extension, increase, renewal, amendment or modification of any Guaranteed Obligation.  Each Guarantor waives any and all notice of the creation, renewal, extension or accrual of any of the Guaranteed Obligations and notice of or proof of reliance by the Administrative Agent or any Guaranteed Parties upon the guarantee contained in this Section 2.01 or acceptance of the guarantee contained in this Section 2.01; the Guaranteed Obligations, and any of them, shall conclusively be deemed to have been created, contracted or incurred, or renewed, extended, amended or waived, in reliance upon the guarantee contained in this Section 2.01; and all dealings between any Borrower and any of the Guarantors, on the one hand, and the Administrative Agent and the Guaranteed Parties, on the other hand, likewise shall be conclusively presumed to have been had or consummated in reliance upon the guarantee contained in this Section 2.01.  Each Guarantor waives diligence, promptness, presentment, protest, demand for payment and notice of default or nonpayment to or upon any Borrower or any of the Guarantors with respect to the Guaranteed Obligations.  Each Guarantor agrees that the Obligations may at any time and from time to time exceed the amount of the liability of such Guarantor hereunder without impairing the guarantee contained in this Section 2.01 or affecting the rights and remedies of the Administrative Agent or any other Guaranteed Party.



Section 2.02    Guarantee of Payment.  Each Guarantor understands and agrees that the guarantee contained in Section 2.01 shall be construed as a continuing, absolute and unconditional guarantee of payment (whether or not any proceeding under any Debtor Relief Law shall have stayed the accrual of collection of any of the Guaranteed Obligations or operated as a discharge thereof) and not of collection, and waives any right to require that any resort be had by the Administrative Agent or any other Guaranteed Party to any security held for the payment of any of the Guaranteed Obligations, or to any balance of any deposit account or credit on the books of the Administrative Agent or any other Guaranteed Party in favor of any other Guarantor or any other Person.  The obligations of each Guarantor hereunder are independent of the obligations of any other Guarantor or any Borrower, and a separate action or actions may be brought and prosecuted against each Guarantor whether or not action is brought against any other Guarantor or the Borrowers and whether or not any other Guarantor or the Borrowers be joined in any such action or actions.  Any payment required to be made by a Guarantor hereunder may be required by the Administrative Agent or any other Guaranteed Party on any number of occasions.  No payment made by any Borrower, any of the Guarantors, any other guarantor or any other Person or received or collected by the Administrative Agent or any Guaranteed Party from any Borrower, any of the

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Guarantors, any other guarantor or any other Person by virtue of any action or proceeding or any set-off or appropriation or application at any time or from time to time in reduction of or in payment of the Guaranteed Obligations shall be deemed to modify, reduce, release or otherwise affect the liability of any Guarantor hereunder which shall, notwithstanding any such payment, remain liable for the Guaranteed Obligations up to the maximum liability of such Guarantor hereunder until the Termination Conditions are satisfied.  When making any demand hereunder or otherwise pursuing its rights and remedies hereunder against any Guarantor, the Administrative Agent or any Guaranteed Party may, but shall be under no obligation to, make a similar demand on or otherwise pursue such rights and remedies as it may have against any Borrower, any other Guarantor or any other Person or against any collateral security or guarantee for the Guaranteed Obligations or any right of offset with respect thereto, and any failure by the Administrative Agent or any Guaranteed Party to make any such demand, to pursue such other rights or remedies or to collect any payments from any Borrower, any other Guarantor or any other Person or to realize upon any such collateral security or guarantee or to exercise any such right of offset, or any release of any Borrower, any other Guarantor or any other Person or any such collateral security, guarantee or right of offset, shall not relieve any Guarantor of any obligation or liability hereunder, and shall not impair or affect the rights and remedies, whether express, implied or available as a matter of law, of the Administrative Agent or any Guaranteed Party against any Guarantor.  For the purposes hereof “demand” shall include the commencement and continuance of any legal proceedings.



Section 2.03     No Limitations.  (a)  Except for termination or release of a Guarantor’s obligations hereunder as expressly provided in Section 5.12, to the fullest extent permitted by applicable Law, the obligations of each Guarantor hereunder shall not be subject to any reduction, limitation, impairment or termination for any reason, including any claim of waiver, release, surrender, alteration or compromise, and shall not be subject to any defense or set-off, counterclaim, recoupment or termination whatsoever by reason of the invalidity, illegality or unenforceability of any of the Guaranteed Obligations, any impossibility in the performance of any of the Guaranteed Obligations, or otherwise.  Without limiting the generality of the foregoing, to the fullest extent permitted by applicable Law and except for termination or release of a Guarantor’s obligations hereunder in accordance with the terms of Section 5.12 (but without prejudice to Section 2.04), the obligations of each Guarantor hereunder shall not be discharged, impaired or otherwise affected by, and to the fullest extent permitted by applicable law, each Guarantor waives any defense arising out of, (i) the failure of the Administrative Agent, any other Guaranteed Party or any other Person to assert any claim or demand or to enforce any right or remedy under the provisions of any Loan Document or otherwise; (ii) any rescission, waiver, amendment or modification of, or any release from any of the terms or provisions of, any Loan Document or any other agreement, including with respect to any other Guarantor under this Agreement; (iii) the release of, or any impairment of any security held by the Administrative Agent or any other Guaranteed Party for the Guaranteed Obligations; (iv) any default, failure or delay, willful or otherwise, in the performance of the Guaranteed Obligations; (v) the failure to perfect any security interest in, or the release of, any security held by or on behalf of the Administrative Agent or any other Guaranteed Party; (vi) any change in the corporate existence, structure or ownership of any Loan Party, the lack of legal existence of any Borrower or any other Guarantor or legal obligation to discharge any of the Guaranteed Obligations by any Borrower or any other Guarantor for any reason whatsoever, including, without limitation, in any insolvency, bankruptcy or reorganization of any Loan Party; (vii) the existence of any claim, set-off or other rights that any Guarantor may have at any time against any Borrower, the Administrative Agent, any other Guaranteed Party or any other Person, whether in connection with the Agreement, the other Loan Documents or any unrelated transaction; (viii) this Agreement having been determined (on whatsoever grounds) to be invalid, non-binding or unenforceable against any other Guarantor ab initio or at any time after the Effective Date or (ix) any other circumstance whatsoever, any act or omission that may or might in any manner or to any extent vary the risk of any Guarantor or otherwise operate as a defense to, or discharge of, any Borrower, any Guarantor or any other guarantor or surety as a matter of law or equity, in bankruptcy or in any other instance (in each case, other than the satisfaction of the

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Termination Conditions).  Anything contained in this Agreement to the contrary notwithstanding, the obligations of each Guarantor under this Agreement shall be limited to an aggregate amount equal to the largest amount that would not render its obligations under this Agreement subject to avoidance as a fraudulent transfer or conveyance under Section 548 of the Bankruptcy Code of the United States or any comparable provisions of any similar federal or state law.



(b)    To the fullest extent permitted by applicable Law and except for termination orrelease of a Guarantor’s obligations hereunder in accordance with the terms of Section 5.12 (but without prejudice to Section 2.04), each Guarantor waives any defense based on or arising out of any defense of any Borrower or any other Guarantor or the unenforceability of the Guaranteed Obligations or any part thereof from any cause, or the cessation from any cause of the liability of any Borrower or any other Guarantor.  The Administrative Agent and the other Guaranteed Parties may in accordance with the terms of the Loan Documents, at their election, foreclose on any security held by one or more of them by one or more judicial or nonjudicial sales, accept an assignment of any such security in lieu of foreclosure, compromise or adjust any part of the Guaranteed Obligations, make any other accommodation with any Borrower or any other Guarantor or exercise any other right or remedy available to them against any Guarantor, without affecting or impairing in any way the liability of any Guarantor hereunder except to the extent the Termination Conditions have been satisfied.  To the fullest extent permitted by applicable Law, each Guarantor waives any defense arising out of any such election even though such election operates, pursuant to applicable Law, to impair or to extinguish any right of reimbursement or subrogation or other right or remedy of such Guarantor against any Borrower or any other Guarantor, as the case may be, or any security.  To the fullest extent permitted by applicable Law, each Guarantor waives any and all suretyship defenses.



Section 2.04    Reinstatement.  Notwithstanding anything to the contrary contained in this Agreement, each of the Guarantors agrees that (a) its guarantee hereunder shall continue to be effective or be reinstated, as the case may be, if at any time payment, or any part thereof, of any Guaranteed Obligation is rescinded or must otherwise be restored by the Administrative Agent or any other Guaranteed Party upon the insolvency, bankruptcy, dissolution, liquidation or reorganization (or any analogous proceeding in any jurisdiction) of any Borrower or any Guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, any Borrower or any Guarantor or any substantial part of its property, or otherwise, all as though such payments had not been made and (b) the provisions of this Section 2.04 shall survive the termination of this Agreement.



Section 2.05    Agreement To Pay; Subrogation.  In furtherance of the foregoing and not in limitation of any other right that the Administrative Agent or any other Guaranteed Party has at law or in equity against any Guarantor by virtue hereof, upon the failure of any Borrower or any other Guarantor to pay any Guaranteed Obligation when and as the same shall become due, whether at maturity, by acceleration, after notice of prepayment or otherwise, each Guarantor hereby promises to and will forthwith pay, or cause to be paid, to the Administrative Agent for distribution to the applicable Guaranteed Parties in cash the amount of such unpaid Guaranteed Obligation.  Upon payment by any Guarantor of any sums to the Administrative Agent as provided above, all rights of such Guarantor against any Borrower or any other Guarantor arising as a result thereof by way of right of subrogation, contribution, reimbursement, indemnity or otherwise shall in all respects be subject to Article III.  



Section 2.06    Information.  Each Guarantor assumes all responsibility for being and keeping itself informed of each Borrower’s and each other Guarantor’s financial condition and assets, and of all other circumstances bearing upon the risk of nonpayment of the Guaranteed Obligations and the nature, scope and extent of the risks that such Guarantor assumes and incurs hereunder, and agrees that none of the Administrative Agent or the other Guaranteed Parties will have any duty to advise such Guarantor of information known to it or any of them regarding such circumstances or risks.

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ARTICLE III



Indemnity, Subrogation and Subordination.



Upon payment by any Guarantor of any Guaranteed Obligations, all rights of such Guarantor against any Borrower or any other Guarantor arising as a result thereof by way of right of subrogation, contribution, reimbursement, indemnity or otherwise shall in all respects be subordinate and junior in right of payment to the payments that must be made in order for the Termination Conditions to be satisfied.  If any amount shall be paid to any Borrower or any other Guarantor in violation of the foregoing restrictions on account of (i) such subrogation, contribution, reimbursement, indemnity or similar right or (ii) any such indebtedness of any Borrower or any other Guarantor, such amount shall be held in trust for the benefit of the Guaranteed Parties and shall forthwith be paid to the Administrative Agent to be credited against the payment of the Guaranteed Obligations, whether matured or unmatured, in accordance with the terms of the Credit Agreement and the other Loan Documents.  Subject to the foregoing, to the extent that any Guarantor shall, under this Agreement or the Credit Agreement as a joint and several obligor, repay any of the Guaranteed Obligations constituting Loans or other advances made to another Loan Party under the Credit Agreement (an “Accommodation Payment”), then the Guarantor making such Accommodation Payment shall be entitled to contribution and indemnification from, and be reimbursed by, each of the other Guarantors in an amount equal to a fraction of such Accommodation Payment, the numerator of which fraction is such other Guarantor’s Allocable Amount and the denominator of which is the sum of the Allocable Amounts of all of the Guarantors; provided that such rights of contribution and indemnification shall be subordinated to the prior payment of the payments that must be made in order for the Termination Conditions to be satisfied.  As of any date of determination, the “Allocable Amount” of each Guarantor shall be equal to the maximum amount of liability for Accommodation Payments which could be asserted against such Guarantor hereunder and under the Credit Agreement without (a) rendering such Guarantor “insolvent” within the meaning of Section 101 (31) of the Bankruptcy Code of the United States, Section 2 of the Uniform Fraudulent Transfer Act (“UFTA”) or Section 2 of the Uniform Fraudulent Conveyance Act (“UFCA”), (b) leaving such Guarantor with unreasonably small capital or assets, within the meaning of Section 548 of the Bankruptcy Code of the United States, Section 4 of the UFTA, or Section 5 of the UFCA, or (c) leaving such Guarantor unable to pay its debts as they become due within the meaning of Section 548 of the Bankruptcy Code of the United States or Section 4 of the UFTA, or Section 5 of the UFCA.



ARTICLE IV



Subordination of Guarantor Claims.



Section 4.01 Subordination of Guarantor Claims.  As used herein, the term “Guarantor Claims” shall mean all debts and obligations of any Guarantor to any other Guarantor, whether such debts and obligations now exist or are hereafter incurred or arise, or whether the obligation of the debtor thereon be direct, contingent, primary, secondary, several, joint and several, or otherwise, and irrespective of whether such debts or obligations be evidenced by note, contract, open account, or otherwise, and irrespective of the Person or Persons in whose favor such debts or obligations may, at their inception, have been, or may hereafter be created, or the manner in which they have been or may hereafter be acquired by.  After the occurrence and during the continuation of an Event of Default, no Guarantor shall receive or collect, directly or indirectly, from any obligor in respect thereof any amount upon the Guarantor Claims.



Section 4.02     Claims in Bankruptcy.  In the event of receivership, bankruptcy, reorganization, arrangement, debtor’s relief, or other insolvency proceedings involving any Guarantor, the Administrative Agent, on behalf of the Administrative Agent and the Guaranteed Parties, shall have the

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right to prove its claim in any proceeding, so as to establish its rights hereunder and receive directly from the receiver, trustee or other court custodian, dividends and payments which would otherwise be payable upon Guarantor Claims.  Each Guarantor hereby assigns such dividends and payments to the Administrative Agent, for the benefit of the Administrative Agent and the Guaranteed Parties, for application against the Obligations as provided under Section 7.02(c) of the Credit Agreement.  Should the Administrative Agent or any Guaranteed Party receive, for application upon the Guaranteed Obligations, any such dividend or payment which is otherwise payable to any Guarantor, and which, as between such Guarantors, shall constitute a credit upon the Guarantor Claims, then upon the satisfaction of the Termination Conditions, the intended recipient shall become subrogated to the rights of the Administrative Agent and the Guaranteed Parties to the extent that such payments to the Administrative Agent and the Guaranteed Parties on the Guarantor Claims have contributed toward the liquidation of the Guaranteed Obligations, and such subrogation shall be with respect to that proportion of the Guaranteed Obligations which would have been unpaid if the Administrative Agent and the Guaranteed Parties had not received dividends or payments upon the Guarantor Claims.



Section 4.03     Payments Held in Trust.  In the event that, notwithstanding Section 4.01 and Section 4.02, any Guarantor should receive any funds, payments, claims or distributions which is prohibited by such Sections, then it agrees: (a) to hold in trust for the Administrative Agent and the other Guaranteed Parties an amount equal to the amount of all funds, payments, claims or distributions so received and (b) that it shall have absolutely no dominion over the amount of such funds, payments, claims or distributions except to pay them promptly to the Administrative Agent, for the benefit of the Guaranteed Parties; and each Guarantor covenants promptly to pay the same to the Administrative Agent.



Section 4.04 Liens Subordinate.  Each Guarantor agrees that, until the Termination Conditions are satisfied, any Liens securing payment of the Guarantor Claims shall be and remain inferior and subordinate to any Liens securing payment of the Guaranteed Obligations, regardless of whether such encumbrances in favor of such Guarantor, the Administrative Agent or any other Guaranteed Party presently exist or are hereafter created or attach.  Without the prior written consent of the Administrative Agent, no Guarantor shall, until Termination Conditions are satisfied, (a) exercise or enforce any creditor’s right it may have against any debtor in respect of the Guarantor Claims or (b) foreclose, repossess, sequester or otherwise take steps or institute any action or proceeding (judicial or otherwise, including without limitation the commencement of or joinder in any liquidation, bankruptcy, rearrangement, debtor’s relief or insolvency proceeding) to enforce any Lien held by it.



ARTICLE V



Miscellaneous.



Section 5.01     Notices.  All communications and notices hereunder shall (except as otherwise expressly permitted herein) be in writing and given as provided in Section 10.01 of the Credit Agreement.  All communications and notices hereunder to a Guarantor shall be given in care of the Borrowers.



Section 5.02     Waivers; Amendment.  



(a) No failure by any Guaranteed Party to exercise, and no delay by any such Personin exercising, any right, remedy, power or privilege hereunder or under any other Loan Document shall operate as a waiver thereof; nor shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege.  The rights, remedies, powers and privileges herein provided, and provided under each other Loan Document, are cumulative and not exclusive of any rights, remedies, powers and

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privileges provided by Law.  No waiver of any provision of any Loan Document or consent to any departure by any Loan Party therefrom shall in any event be effective unless the same shall be permitted by this Section 5.02, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given.



(b)    Neither this Agreement nor any provision hereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by the Administrative Agent and the Loan Party or Loan Parties with respect to which such waiver, amendment or modification is to apply, subject to any consent required in accordance with Section 10.02(b) of the Credit Agreement.



Section 5.03    Administrative Agent’s Fees and Expenses; Indemnification.  Each Guarantor, jointly with the other Guarantors and severally, agrees to (a) pay or reimburse the Administrative Agent, any Issuing Bank and the Lenders for their fees and expenses incurred hereunder to the extent provided in Section 10.03(a) of the Credit Agreement and (b) indemnify and hold harmless the Administrative Agent, each Issuing Bank, the Lenders and their respective Related Parties from any and all losses, claims, damages, liabilities and related expenses to the extent provided in Section 10.03(b) of the Credit Agreement; provided that in each case of clauses (a) and (b) each reference therein to each “Borrower” shall be deemed to be a reference to “each Guarantor.”



Section 5.04    Successors and Assigns.  Whenever in this Agreement any of the parties hereto is referred to, such reference shall be deemed to include the successors and assigns of such party permitted under the Credit Agreement; and the provisions of this Agreement shall bind and inure to the benefit of the Guarantors and the Guaranteed Parties and their respective permitted successors and assigns.  Except in a transaction expressly permitted under the Credit Agreement, no Guarantor may assign any of its rights or obligations hereunder without the written consent of the Administrative Agent.



Section 5.05    Survival of Agreement.  All covenants, agreements, indemnities, representations and warranties made by the Guarantors in the Loan Documents and in the certificates or other instruments delivered in connection with or pursuant to this Agreement or any other Loan Document shall be considered to have been relied upon by the Guaranteed Parties and shall survive the execution and delivery of the Loan Documents and the making of any Loans and issuance of any Letters of Credit, regardless of any investigation made by any Guaranteed Party or on its behalf and notwithstanding that any Guaranteed Party may have had notice or knowledge of any Default or Event of Default or incorrect representation or warranty at the time any credit is extended under the Credit Agreement or any other Loan Document, and shall continue in full force and effect until this Agreement is terminated as provided in Section 5.12 hereof, or with respect to any individual Guarantor until such Guarantor is otherwise released from its obligations under this Agreement in accordance with the terms hereof.



Section 5.06    Counterparts; Effectiveness; Several Agreement.  This Agreement may be executed in counterparts (and by different parties hereto in different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract.  This Agreement shall become effective when it shall have been executed by the Guarantors and the Administrative Agent and thereafter shall be binding upon and inure to the benefit of each Guarantor, the Administrative Agent, the other Guaranteed Parties and their respective permitted successors and assigns, subject to Section 5.04 hereof.  Delivery of an executed counterpart of a signature page of this Agreement by telecopy or other electronic imaging means (including in.pdf or .tif format via electronic mail) shall be effective as delivery of a manually executed counterpart of this Agreement.  This Agreement shall be construed as a separate agreement with respect to each Guarantor and may be amended, restated, amended and restated, modified, supplemented, waived or released with respect to any Guarantor without

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the approval of any other Guarantor and without affecting the obligations of any other Guarantor hereunder.



Section 5.07     Severability.  If any provision of this Agreement is held to be illegal, invalid or unenforceable, (a) the legality, validity and enforceability of the remaining provisions of this Agreement shall not be affected or impaired thereby and (b) the parties shall endeavor in good faith negotiations to replace the illegal, invalid or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the illegal, invalid or unenforceable provisions.  The invalidity of a provision in a particular jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.



Section 5.08     GOVERNING LAW, ETC.  



(a)    THIS AGREEMENT SHALL BE GOVERNED BY, AND SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.



(b)    BY EXECUTING AND DELIVERING THIS AGREEMENT, EACH GUARANTOR IRREVOCABLY AND UNCONDITIONALLY SUBMITS, FOR ITSELF AND ITS PROPERTY, TO THE NONEXCLUSIVE JURISDICTION OF THE COURTS OF THE STATE OF NEW YORK SITTING IN NEW YORK CITY IN THE BOROUGH OF MANHATTAN AND OF ANY UNITED STATES DISTRICT COURT OF THE SOUTHERN DISTRICT OF NEW YORK SITTING IN NEW YORK CITY IN THE BOROUGH OF MANHATTAN, AND ANY APPELLATE COURT FROM ANY THEREOF, IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, OR FOR RECOGNITION OR ENFORCEMENT OF ANY JUDGMENT, AND EACH OF THE PARTIES HERETO IRREVOCABLY AND UNCONDITIONALLY AGREES THAT ALL CLAIMS IN RESPECT OF ANY SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN SUCH NEW YORK STATE COURT OR, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, IN SUCH FEDERAL COURT.  EACH OF THE PARTIES HERETO AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW.  EACH PARTY HERETO AGREES THAT THE ADMINISTRATIVE AGENT AND THE OTHER GUARANTEED PARTIES RETAIN THE RIGHT TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW OR TO BRING PROCEEDINGS AGAINST ANY GUARANTOR IN THE COURTS OF ANY OTHER JURISDICTION IN CONNECTION WITH THE EXERCISE OF ANY RIGHTS UNDER THIS AGREEMENT OR THE ENFORCEMENT OF ANY JUDGMENT.



(c)    EACH GUARANTOR IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT IN ANY COURT REFERRED TO IN PARAGRAPH (b) OF THIS SECTION 5.08.  EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF SUCH ACTION OR PROCEEDING IN ANY SUCH COURT.



(d)    EACH PARTY TO THIS AGREEMENT IRREVOCABLY CONSENTS TO SERVICE OF PROCESS IN THE MANNER PROVIDED FOR NOTICES IN SECTION 10.01 OF THE CREDIT AGREEMENT.  NOTHING IN THIS AGREEMENT WILL AFFECT THE RIGHT OF ANY

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PARTY TO THIS AGREEMENT TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW.



Section 5.09     WAIVER OF RIGHT TO TRIAL BY JURY.  EACH PARTY HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY).   EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PERSON HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PERSON WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION 5.09.



Section 5.10    Headings.  Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and are not to affect the construction of, or to be taken into consideration in interpreting, this Agreement.



Section 5.11    Obligations Absolute.  To the extent permitted by Law, all rights of the Administrative Agent and the other Guaranteed Parties hereunder and all obligations of each Guarantor hereunder shall be absolute and unconditional irrespective of (a) any lack of validity or enforceability of the Credit Agreement, any other Loan Document, any agreement with respect to any of the Guaranteed Obligations or any other agreement or instrument relating to any of the foregoing, (b) any change in the time, manner or place of payment of, or in any other term of, all or any of the Guaranteed Obligations, or any other amendment or waiver of or any consent to any departure from the Credit Agreement, any other Loan Document, or any other agreement or instrument, (c) any release or amendment or waiver of or consent under or departure from any guarantee guaranteeing all or any of the Guaranteed Obligations or (d) subject only to termination or release of a Guarantor’s obligations hereunder in accordance with the terms of Section 5.12, but without prejudice to reinstatement rights under Section 2.04, any other circumstance that might otherwise constitute a defense available to, or a discharge of, any Guarantor in respect of the Guaranteed Obligations or this Agreement.



Section 5.12     Termination or Release.  (a)  This Agreement and the Guarantees made herein shall terminate with respect to all Guaranteed Obligations when the Termination Conditions have been satisfied.



(b)    A Guarantor (other than a Borrower) shall automatically be released from its obligations hereunder to the extent all of its Equity Interests are Disposed of in a transaction permitted by Section 6.11 of the Credit Agreement, or otherwise to the extent such release is consented to by the requisite Lenders pursuant to Section 10.02(b) of the Credit Agreement.



(c)    On the Investment Grade Rating Date, each Guarantor (other than the Company) shall, in accordance with the terms of Section 10.20 of the Credit Agreement, be released from its surety and guarantee liabilities and obligations as a Guarantor hereunder (and each such Person shall cease to constitute a “Guarantor” hereunder), other than those liabilities and obligations which are expressly stated to survive termination of this Agreement.  For the avoidance of doubt, any release pursuant to this Section 5.12(c) shall in no way impair or affect the liabilities and obligations of the Company under the Credit Agreement, any other Loan Documents or in its capacity as a Guarantor hereunder, or any other Borrower under the Credit Agreement and the other Loan Documents (other than this Agreement), all of which

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liabilities and obligations shall continue in full force and effect on and after the Investment Grade Rating Date.



(d)    In connection with any termination or release pursuant to paragraph (a), (b) or (c) above, the Administrative Agent shall promptly execute and deliver to any Guarantor, at such Guarantor’s expense, all documents that such Guarantor shall reasonably request to evidence such termination or release.  Any execution and delivery of documents pursuant to this Section 5.12 shall be without recourse, representation or warranty of any kind (whether express or implied) by the Administrative Agent.



(e)    At any time that the respective Guarantor desires that the Administrative Agenttake any of the actions described in immediately preceding paragraph (c), it shall, upon request of the Administrative Agent, deliver to the Administrative Agent an officer’s certificate certifying that the release of the respective Guarantor is permitted pursuant to paragraph (a) or (b) above.  The Administrative Agent shall have no liability whatsoever to any Guaranteed Party as a result of any release of any Guarantor by it as permitted (or which the Administrative Agent in good faith believes to be permitted) by this Section 5.12.  



Section 5.13     Additional Guarantors.  Each Subsidiary of the Company that is required to become a party to this Agreement pursuant to Section 5.12 of the Credit Agreement shall become a Guarantor for all purposes of this Agreement upon execution and delivery by such Subsidiary of a Guaranty Supplement. Upon the execution and delivery by a Subsidiary of a Guaranty Supplement, such Subsidiary shall become a Guarantor hereunder with the same force and effect as if originally named as a Guarantor herein.  The execution and delivery of any such instrument shall not require the consent of any other Guarantor hereunder.  The rights and obligations of each Guarantor hereunder shall remain in full force and effect notwithstanding the addition of any new Guarantor as a party to this Agreement.



Section 5.14     Set-Off.  In addition to any rights and remedies of the Guaranteed Parties provided by law, upon the occurrence and during the continuance of an Event of Default, each Guaranteed Party shall have the right, without notice to any Guarantor, any such notice being expressly waived by each Guarantor to the extent permitted by applicable law, upon any Guaranteed Obligations becoming due and payable by any Guarantor (whether at the stated maturity, by acceleration or otherwise), to apply to the payment of such Guaranteed Obligations, by setoff or otherwise, any and all deposits (general or special, time or demand, provisional or final), in any currency, and any other credits, indebtedness or claims, in any currency, in each case whether direct or indirect, absolute or contingent, matured or unmatured, at any time held or owing by such Guaranteed Party, any affiliate thereof or any of their respective branches or agencies to or for the credit or the account of such Guarantor.  Each Guaranteed Party agrees promptly to notify the relevant Guarantor and the Administrative Agent after any such application made by such Guaranteed Party; provided that the failure to give such notice shall not affect the validity of such application.



Section 5.15     Recourse.  This Agreement is made with full recourse to each Guarantor and pursuant to and upon all the warranties, representations, covenants and agreements on the part of such Guarantor contained herein, in the Credit Agreement and the other Loan Documents and otherwise in writing in connection herewith or therewith.  It is the desire and intent of each Guarantor and each applicable Guaranteed Party that this Agreement shall be enforced against each Guarantor to the fullest extent permissible under applicable Law applied in each jurisdiction in which enforcement is sought.



[Signature Pages Follow]

 

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly

executed by their respective authorized officers as of the day and year first above written.



 

 

 



GUARANTORS:



 



MURPHY OIL CORPORATION, as a Guarantor



 

 



By:

 



Name:

John Gardner



Title:

Vice President and Treasurer





 

 



MURPHY EXPLORATION & PRODUCTION COMPANY – INTERNATIONAL, as a Guarantor



 

 



By:

 



Name:

John Gardner



Title:

Vice President and Treasurer





 

 



MURPHY EXPLORATION & PRODUCTION COMPANY, as a Guarantor



 

 



By:

 



Name:

 



Title:

 





 

 



MURPHY EXPLORATION & PRODUCTION COMPANY – USA, as a Guarantor



 

 



By:

 



Name:

 



Title:

 



 

[SIGNATURE PAGE TO GUARANTY]


 

 





 

 



ACCEPTED AND AGREED:



 



ADMINISTRATIVE AGENT:



 

 



JPMORGAN CHASE BANK, N.A., as Administrative Agent



 

 



By:

 



Name:

Jeffrey C. Miller



Title:

Vice President

 


 

 

EXHIBIT I TO GUARANTY



FORM OF GUARANTY SUPPLEMENT



THIS SUPPLEMENT NO.    (this “Guaranty Supplement”) dated as of                 , 20    , to the Guaranty dated as of November 28, 2018, among MURPHY OIL CORPORATION, a Delaware corporation (the “Company”), MURPHY EXPLORATION & PRODUCTION COMPANY – INTERNATIONAL, a Delaware corporation (“Expro-Intl.”), the other Guarantors party thereto from time to time and JPMorgan Chase Bank, N.A., as Administrative Agent on behalf of the Guaranteed Parties (together, with its successors and assigns, the “Administrative Agent”) (as amended, restated, modified or supplemented from time to time, the “Guaranty”), is made by [                    ], a [               ] (the “New Guarantor”) in favor of JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders from time to time party to the Credit Agreement referred to below.



A.    Reference is made to the Credit Agreement, dated as of November 28, 2018 (as amended, restated, amended and restated, modified or supplemented from time to time, the “Credit Agreement”), by the Company, Expro-Intl., Murphy Oil Company Ltd., a Canadian corporation, the Lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders, each Lender and Issuing Bank from time to time party thereto and the other agents and arrangers party thereto.



B.    Capitalized terms used herein and not otherwise defined herein shall have the meanings assigned to such terms in the Credit Agreement and the Guaranty, as applicable.



C.    The Guarantors have entered into the Guaranty in order to induce the Lender

and Issuing Banks to make extensions of credit to the Borrowers under the Credit Agreement.  Section 5.13 of the Guaranty provides that additional Subsidiaries may become Guarantors under the Guaranty by execution and delivery of an instrument in the form of this Guaranty Supplement.  The New Guarantor is executing this Guaranty Supplement in accordance with the requirements of the Credit Agreement to become a Guarantor under the Guaranty as consideration for Loans and Letters of Credit previously made and hereafter to be made.



Accordingly, the Administrative Agent and the New Guarantor agree as follows:



Section 1.  In accordance with Section 5.13 of the Guaranty, by executing and delivering this Guaranty Supplement, the New Guarantor hereby becomes a Guarantor under the Guaranty with the same force and effect as if originally named therein as a Guarantor and the New Guarantor hereby agrees to all the terms and provisions of the Guaranty applicable to it as a Guarantor thereunder.  Each reference to a “Guarantor” in the Guaranty shall be deemed to include the New Guarantor as if originally named therein as a Guarantor.  The Guaranty is hereby incorporated herein by reference.



Section 2.  The New Guarantor represents and warrants to the Administrative Agent and the other Guaranteed Parties that this Guaranty Supplement has been duly authorized, executed and delivered by it and constitutes its legal, valid and binding obligation, enforceable against it in accordance with its terms, except as such enforceability may be limited by Debtor Relief Laws and by general principles of equity and principles of good faith and fair dealing.



Section 3.  This Guaranty Supplement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract.  This Guaranty Supplement shall become effective when the Administrative Agent shall have received a counterpart of this Guaranty Supplement that bears the

 

 


 

 

signature of the New Guarantor and the Administrative Agent has executed a counterpart hereof.  Delivery of an executed counterpart of a signature page of this Guaranty Supplement by telecopy or other electronic imaging means (including in .pdf or .tif format via electronic mail) shall be effective as delivery of a manually executed counterpart of this Guaranty Supplement.



Section 4.  Except as expressly supplemented hereby, the Guaranty shall remain in full force and effect, subject to the termination of the Guaranty pursuant to Section 5.12 thereof.



Section 5.  



(a)    THIS GUARANTY SUPPLEMENT SHALL BE GOVERNED BY, AND SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.



(b)    BY EXECUTING AND DELIVERING THIS GUARANTY SUPPLEMENT,THE NEW GUARANTOR IRREVOCABLY AND UNCONDITIONALLY SUBMITS, FOR ITSELF AND ITS PROPERTY, TO THE NONEXCLUSIVE JURISDICTION OF THE COURTS OF THE STATE OF NEW YORK SITTING IN NEW YORK CITY IN THE BOROUGH OF MANHATTAN AND OF ANY UNITED STATES DISTRICT COURT OF THE SOUTHERN DISTRICT OF NEW YORK SITTING IN NEW YORK CITY IN THE BOROUGH OF MANHATTAN, AND ANY APPELLATE COURT FROM ANY THEREOF, IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS GUARANTY SUPPLEMENT, OR FOR RECOGNITION OR ENFORCEMENT OF ANY JUDGMENT, AND EACH OF THE PARTIES HERETO IRREVOCABLY AND UNCONDITIONALLY AGREES THAT ALL CLAIMS IN RESPECT OF ANY SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN SUCH NEW YORK STATE COURT OR, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, IN SUCH FEDERAL COURT.  EACH OF THE PARTIES HERETO AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW.  EACH PARTY HERETO AGREES THAT THE ADMINISTRATIVE AGENT AND THE OTHER GUARANTEED PARTIES RETAIN THE RIGHT TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW OR TO BRING PROCEEDINGS AGAINST THE NEW GUARANTOR IN THE COURTS OF ANY OTHER JURISDICTION IN CONNECTION WITH THE EXERCISE OF ANY RIGHTS UNDER THIS GUARANTY SUPPLEMENT OR THE ENFORCEMENT OF ANY JUDGMENT.



(c)    THE NEW GUARANTOR IRREVOCABLY AND UNCONDITIONALLYWAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS GUARANTY SUPPLEMENT IN ANY COURT REFERRED TO IN PARAGRAPH (b) OF THIS SECTION.  EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF SUCH ACTION OR PROCEEDING IN ANY SUCH COURT.



(d)    EACH PARTY HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS GUARANTY SUPPLEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY).  EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR

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ATTORNEY OF ANY OTHER PERSON HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PERSON WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS GUARANTY SUPPLEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.



Section 6.  If any provision of this Guaranty Supplement is held to be illegal, invalid or unenforceable, (a) the legality, validity and enforceability of the remaining provisions of this Guaranty Supplement shall not be affected or impaired thereby and (b) the parties shall endeavor in good faith negotiations to replace the illegal, invalid or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the illegal, invalid or unenforceable provisions.  The invalidity of a provision in a particular jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.



Section 7.  All communications and notices hereunder shall be in writing and given as provided in Section 5.01 of the Guaranty.



Section 8.  The New Guarantor agrees to reimburse the Administrative Agent for its reasonable out-of-pocket expenses in connection with this Guaranty Supplement, as provided in Section 5.03 of the Guaranty.



Section 9.  For purposes of New York General Obligations Law §5-1105, the parties hereto agree that the promise by the New Guarantor contained herein is a Guarantee (as defined in the Credit Agreement) and that (i) the consideration for this Guarantee, which is hereby expressed in writing, is the making of the Loans to the applicable Borrowers on the Effective Date and from time to time thereafter, the making of Commitments with respect to the Loans on the Effective Date and from time to time thereafter and the other extensions of credit that constitute Obligations under the Credit Agreement from time to time outstanding, and (ii) such Loans, Commitments and other extensions of credit have been given and/or performed and would be valid consideration for this Guaranty Supplement but for the time that they were given (i.e., would have been valid consideration for this Guaranty if the New Guarantor had entered into this Guaranty contemporaneously with the initial making of the Loans, Commitments and other extensions of credit on the Effective Date).



Section 10. The New Guarantor hereby expressly waives notice of acceptance of this Guaranty Supplement, acceptance on the part of the Administrative Agent and the other Guaranteed Parties being conclusively presumed by their request for this Guaranty Supplement and delivery of the same to the Administrative Agent.

 

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IN WITNESS WHEREOF, the New Guarantor has duly executed this Guaranty Supplement as of the day and year first above written.







 

 



[NAME OF NEW GUARANTOR]



 

 



By:

 



Name:

 



Title:

 









 

 



JPMORGAN CHASE BANK, N.A., as Administrative Agent



 

 



By:

 



Name:

 



Title:

 



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EXHIBIT F

FORM OF

SUBORDINATED INTERCOMPANY NOTE

[see attached]

Exhibit F 

CREDIT AGREEMENT 


 

 

Exhibit F

INTERCOMPANY SUBORDINATION AGREEMENT 

This INTERCOMPANY SUBORDINATION AGREEMENT (this “Agreement”), dated as of [ ], 20[ ], is entered into by and among the Obligors (as defined below) listed on the signature pages hereof and those additional entities that hereafter become parties hereto in such capacity by joinder, the Subordinated Creditors (as defined below) listed on the signature pages hereof and those additional entities that hereafter become parties hereto in such capacity by joinder and JPMORGAN CHASE BANK, N.A., in its capacity as administrative agent for each of the Guaranteed Parties (in such capacity, together with its successors and assigns in such capacity, “Administrative Agent”) pursuant to the Credit Agreement referred to below.  



WHEREAS, the Administrative Agent is a party to that certain Credit Agreement dated as of November 28, 2018 (as amended, amended and restated, extended, supplemented or otherwise modified in writing from time to time, the “Credit Agreement”), among Murphy Oil Corporation (the “Company”), Murphy Exploration & Production Company – International (“Expro-Intl.”) and Murphy Oil Company Ltd., as Borrowers (collectively, the “Borrowers” and each, a “Borrower”), the Administrative Agent and the lenders from time to time party thereto;

WHEREAS, the Administrative Agent, the Company, Expro-Intl. and the other Guarantors are party to that certain Guaranty Agreement dated as of November 28, 2018 (as amended, amended and restated, extended, supplemented or otherwise modified in writing from time to time, the “Guaranty”), pursuant to which the Guarantors have jointly and severally guaranteed, among other obligations, the obligations of each Borrower under the Credit Agreement; and

WHEREAS, the Lenders have agreed to extend credit to the Borrowers and the Issuing Banks have indicated their willingness to issue Letters of Credit on the terms and conditions set forth in the Credit Agreement and the obligations of the Lenders and Issuing Banks to extend such credit are, in each case, conditioned upon, among other things, the execution and delivery of this Agreement by each Obligor and Subordinated Creditor.



NOW THEREFORE, the parties hereto agree as follows:

SECTION 1. Defined Terms.  Unless otherwise specified herein, capitalized terms used but not otherwise defined herein have the meanings assigned to such terms in the Credit Agreement.  As used in this Agreement, the following terms have the meanings specified below:  

(a)    “Discharge of Senior Obligations” means (i) all Senior Obligations (including, without limitation, all principal, interest (including interest accruing during the pendency of an insolvency or liquidation proceeding, regardless of whether allowed or allowable in such insolvency or liquidation proceeding) and premium, if any, on all Loans, and all fees, costs, expenses and other amounts payable under the Credit Agreement and the other Loan Documents) shall have been paid in full in cash (other than contingent indemnification obligations and obligations under or in respect of Guaranteed Hedging Agreements and Guaranteed Cash Management Agreements), (ii) no Letter of Credit is outstanding (other than Letters of Credit that have been cash collateralized or otherwise secured to the satisfaction of the applicable Issuing Bank), (iii) all of the Commitments have been terminated, (iv) no Guaranteed Hedging Agreement is outstanding and all amounts payable by any Borrower or any Subsidiary to any Guaranteed Hedging Party shall have been paid in full (other than contingent indemnification obligations), or if any Guaranteed Hedging Agreement is outstanding, credit support arrangements acceptable in the sole discretion of the Guaranteed Hedging Party party thereto have been made to secure any Borrower’s or any Subsidiary’s obligations thereunder to such Guaranteed Hedging Party or other arrangements mutually agreed upon including, without limitation, upon the refinancing of the Credit Agreement, the granting of

 


 

 

pari passu guarantees and liens with such refinancing Indebtedness to the Guaranteed Hedging Party which secures and guarantees the Guaranteed Hedging Agreements on a pro rata basis with such refinancing Indebtedness, and otherwise on terms no less favorable to the Guaranteed Hedging Party than those contained in the Loan Documents, or such Guaranteed Hedging Agreement has been novated or assigned to one or more third parties and all amounts required to be paid by any Borrower or any Subsidiary in respect of any such novation shall have been paid in full (other than contingent indemnification obligations) and (v) the payment in full in cash of all amounts owed under and the termination of all obligations under each Guaranteed Cash Management Agreement has occurred (other than contingent indemnification obligations and obligations under Guaranteed Cash Management Agreements as to which arrangements satisfactory to the applicable Guaranteed Cash Management Provider shall have been made, including, without limitation, upon the refinancing of the Credit Agreement, the granting of pari passu guarantees and liens with such refinancing Indebtedness to the Guaranteed Cash Management Provider which secures the Guaranteed Cash Management Agreements on a pro rata basis with such refinancing Indebtedness, and otherwise on terms no less favorable to the Guaranteed Cash Management Provider than those contained in the Loan Documents).  The term “Discharged” with respect to the Senior Obligations has a correlative meaning to the foregoing.

(b)    “Obligor” means each Loan Party under the Credit Agreement or the other Loan Documents.

(c)    “Insolvency or Liquidation Proceeding” means (a) any voluntary or involuntary case or proceeding under any bankruptcy law with respect to the Company or any of its Subsidiaries, (b) any other voluntary or involuntary insolvency, reorganization or bankruptcy case or proceeding, or any receivership, liquidation, reorganization or other similar case or proceeding with respect to the Company or any of its Subsidiaries or with respect to any of their respective assets, (c) any liquidation, dissolution, reorganization or winding up of the Company or any of its Subsidiaries whether voluntary or involuntary and whether or not involving insolvency or (d) any assignment for the benefit of creditors or any other marshalling of assets and liabilities of the Company or any of its Subsidiaries.

(d)    “Senior Obligations” means the “Obligations” as such term is defined in the Credit Agreement.

(e)    “Subordinated Creditor” means the Company and each Subsidiary of the Company, whether now existing or hereafter formed or acquired. 

(f)    “Subordinated Obligations” means, collectively, all debts and obligations of any Obligor to any Subordinated Creditor, whether such debts and obligations now exist or are hereafter incurred or arise, or whether the obligation of the debtor thereon be direct, contingent, primary, secondary, several, joint and several, or otherwise, and irrespective of whether such debts or obligations be evidenced by note, contract, open account, or otherwise, and irrespective of the Person or Persons in whose favor such debts or obligations may, at their inception, have been, or may hereafter be created, or the manner in which they have been or may hereafter be acquired (and including, for the avoidance of doubt, any and all interest, premiums, costs, expenses or indemnification amounts thereof or payable in respect thereof or in connection therewith).

SECTION 2. Subordination.  Each Subordinated Creditor and each Obligor agrees, and whether or not any Insolvency or Liquidation Proceeding has been commenced by or against the Company or any of its Subsidiaries, that the Subordinated Obligations are and shall be subordinate and junior in right of payment, to the extent and in the manner hereinafter set forth, to the prior Discharge of Senior Obligations.  Such subordination is for the benefit of each present and future Guaranteed Party, each of whom shall be entitled to enforce this Agreement as party hereto or as a third party beneficiary

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hereof.  Each Guaranteed Party shall be deemed to have acquired Senior Obligations, whether now outstanding or hereafter created, incurred, assumed or guaranteed, in reliance upon the provisions contained in this Agreement.  Each Subordinated Creditor hereby waives, to the maximum extent permitted by law, notice of the existence or creation of all or any of the Senior Obligations. 

SECTION 3.     Events of Subordination.  

(a)    In the event of any dissolution, winding up, liquidation, arrangement, reorganization, adjustment, protection, relief or composition of any Obligor or its debts, whether voluntary or involuntary, in any bankruptcy, insolvency, arrangement, reorganization, receivership, relief or other similar case or proceeding relating to a Bankruptcy Event or upon an assignment for the benefit of creditors or any other marshalling of the assets and liabilities of any Obligor or otherwise, then the Guaranteed Parties shall be entitled to receive payment in full of the Senior Obligations until the Discharge of Senior Obligations before any Subordinated Creditor is entitled to receive any payment from or on behalf of any Obligor of all or any of the Subordinated Obligations, and any payment or distribution of any kind (whether in cash, property or securities) that otherwise would be payable or deliverable upon or with respect to the Subordinated Obligations in any such case, proceeding, assignment, marshalling or otherwise (including any payment that may be payable by reason of any other indebtedness of such Obligor being subordinated to payment of the Subordinated Obligations) shall be paid or delivered directly to the Administrative Agent for the account of the Guaranteed Parties for application (in the case of cash) to, or as collateral (in the case of non-cash property or securities) for, the payment or prepayment of the Senior Obligations until the Discharge of Senior Obligations has occurred.

(b)    In the event that any Event of Default under the Credit Agreement shall have occurred and be continuing, then no payment (including any payment that may be payable by reason of any other Indebtedness of any Obligor being subordinated to payment of the Subordinated Obligations) shall be made by or on behalf of any Obligor for or on account of any Subordinated Obligations, and no Subordinated Creditor shall take or receive from any Obligor, directly or indirectly, in cash or other property or by set-off or in any other manner, including, without limitation, from or by way of collateral, payment of all or any of the Subordinated Obligations, unless and until (i) the Discharge of Senior Obligations has occurred or (ii) such Event of Default shall have been cured or waived.

(c)    Except as otherwise set forth in Sections 3(a) and (b) above, any Obligor is permitted to pay or have paid on its behalf, and any Subordinated Creditor is entitled to receive, any payment or prepayment of principal and interest on the Subordinated Obligations as permitted by the Credit Agreement.

SECTION 4.     In Furtherance of Subordination.  Each Subordinated Creditor agrees as follows:

(a)      If any proceeding referred to in Section 3(a) above is commenced by or against any Obligor:

(i)    the Administrative Agent is hereby irrevocably authorized and empowered (in its own name or in the name of each Subordinated Creditor or otherwise), but shall have no obligation, to demand, sue for, collect and receive every payment or distribution referred to in Section 3(a) and give acquittance therefor and to file claims and proofs of claim and take such other action (including, without limitation, voting the Subordinated Obligations or enforcing any security interest or other lien securing payment of the Subordinated Obligations) as it may deem necessary or advisable for the exercise or enforcement of any of the rights or interests of the Administrative Agent or the Guaranteed Parties; and

3


 

 

(ii)    each Subordinated Creditor shall duly and promptly take such action as the Administrative Agent may request (x) to collect the Subordinated Obligations for the account of the Guaranteed Parties and to file appropriate claims or proofs or claim in respect of the Subordinated Obligations, (y) to execute and deliver to the Administrative Agent such powers of attorney, assignments, or other instruments as the Administrative Agent may request in order to enable the Administrative Agent to enforce any and all claims with respect to, and any security interests and other liens securing payment of, the Subordinated Obligations, and (z) to collect and receive any and all payments or distributions which may be payable or deliverable upon or with respect to the Subordinated Obligations.

(b)    All payments or distributions upon or with respect to the Subordinated Obligations which are received by each Subordinated Creditor from or on behalf of any Obligor contrary to the provisions of this Agreement shall be received and thereafter held in trust for the benefit of the Guaranteed Parties, shall be segregated from other funds and property held by such Subordinated Creditor and shall be forthwith paid over to the Administrative Agent for the account of the Guaranteed Parties in the same form as so received (with any necessary indorsement) to be applied (in the case of cash) to, or held as collateral (in the case of non-cash property or securities) for, the payment or prepayment of the Senior Obligations in accordance with the terms of the Credit Agreement.

(c)    The Administrative Agent is hereby authorized to demand specific performance of this Agreement, whether or not any Obligor shall have complied with any of the provisions hereof applicable to it, at any time when any Subordinated Creditor shall have failed to comply with any of the provisions of this Agreement applicable to it.  Each Subordinated Creditor hereby irrevocably waives any defense based on the adequacy of a remedy at law, which might be asserted as a bar to such remedy of specific performance.

(d)    In any case commenced by or against any Borrower or any other Loan Party in

connection with the occurrence of a Bankruptcy Event (a “Reorganization Proceeding”), to the extent not prohibited by applicable Law, the Administrative Agent shall have the exclusive right to exercise any voting rights in respect of the claims of such Subordinated Creditor in respect of the Subordinated Obligations against any Borrower and/or any such other Loan Party.

(e)    If, at any time, all or part of any payment with respect to Senior Obligations theretofore made (whether by a Borrower, any other Loan Party or any other Person or enforcement of any right of setoff or otherwise) is rescinded, avoided or must otherwise be returned by the holders of Senior Obligations for any reason whatsoever (including, without limitation, the insolvency, bankruptcy or reorganization of a Borrower, any other Loan Party or such other Persons or as the result of any avoidance or other actions commenced therein), the provisions set forth herein shall continue to be effective or be reinstated, as the case may be, all as though such payment had not been made.

(f)    Each Subordinated Creditor agrees that it shall not object to the entry of any order or orders approving any cash collateral stipulations, adequate protection stipulations or similar stipulations relating to the Subordinated Obligations executed by the Administrative Agent or any other Guaranteed Party in any Reorganization Proceeding.

SECTION 5. Rights of Subrogation.  Each Subordinated Creditor agrees that no payment or distribution to the Administrative Agent or the other Guaranteed Parties pursuant to the provisions of this Agreement shall entitle such Subordinated Creditor to exercise any right of subrogation in respect thereof until the Discharge of Senior Obligations shall has occurred.

SECTION 6.     Further Assurances.  Each Subordinated Creditor and each Obligor will, at its

4


 

 

expense and at any time and from time to time, promptly execute and deliver all further instruments and documents, and take all further action, that may be necessary or desirable, or that the Administrative Agent may reasonably request in writing, in order to protect any right or interest granted or purported to be granted hereby or to enable the Administrative Agent or any Guaranteed Parties to exercise and enforce its rights and remedies hereunder.

SECTION 7. Agreements in Respect of Subordinated Obligations.  No Subordinated Creditor will sell, assign, pledge, encumber or otherwise dispose of any of the Subordinated Obligations unless such sale, assignment, pledge, encumbrance or disposition is made subject to this Agreement.

SECTION 8. Agreement by the Obligors.  Each Obligor hereby agrees that it will not make any payment in respect of any Subordinated Obligations, or take any other action in respect thereof, in each case, if such payment or other action would be in contravention of the provisions of this Agreement.

SECTION 9. Obligations Hereunder Not Affected.  All rights, interests, agreements and obligations of the Administrative Agent, the other Guaranteed Parties, each Subordinated Creditor and each Obligor under this Agreement, shall remain in full force and effect irrespective of:

(i)    any amendment, extension, renewal, compromise, discharge, acceleration or other change in the time for payment or the terms of the Senior Obligations or any part thereof;

(ii)    any taking, holding, exchange, enforcement, waiver, release, failure to perfect, sell or otherwise dispose of any security for payment of any Guaranty or any Senior Obligations;

(iii)    the application of security and directing the order or manner of sale thereof as the Administrative Agent and the Guaranteed Parties in their sole discretion may determine;

(iv)    the release or substitution of one or more of any endorsers or other guarantors of any of the Senior Obligations;

(v)    the taking of, or failure to take any action which might in any manner or to any extent vary the risks of any Guarantor or which, but for this Section 9 might operate as a discharge of such Guarantor;

(vi)    any defense arising by reason of any disability, change in corporate existence or structure or other defense of any Obligor, any other Guarantor or a Subordinated Creditor, the cessation from any cause whatsoever (including any act or omission of any Guaranteed Party) of the liability of such Obligor, any other Guarantor or a Subordinated Creditor;

(vii)    any defense based on any claim that such Guarantor’s or Subordinated Creditor’s obligations exceed or are more burdensome than those of any Obligor, any other Guarantor or any other subordinated creditor, as applicable;

(viii)    the benefit of any statute of limitations affecting such Guarantor’s or

Subordinated Creditor’s liability hereunder;

5


 

 

(ix)    any right to proceed against any Obligor, proceed against or exhaust any security for the Senior Obligations, or pursue any other remedy in the power of any Guaranteed Party, whatsoever;

(x)    the occurrence of any Insolvency or Liquidation Proceeding;

(xi)    any benefit of and any right to participate in any security now or hereafter held by any Guaranteed Party, and

(xii)    to the fullest extent permitted by law, any and all other defenses or benefits that may be derived from or afforded by applicable Law limiting the liability of or exonerating guarantors or sureties.



This Agreement shall continue to be effective or be reinstated, as the case may be, if at any time any payment of any of the Senior Obligations is rescinded, avoided, or must otherwise be returned by the Administrative Agent or any Guaranteed Party upon the insolvency, bankruptcy or reorganization of any Obligor or otherwise, all as though such payment had not been made.

SECTION 10. Treatment of Guaranty and Security of Subordinated Obligations.  Any payments or distributions of any kind or character made to, or received by, any Subordinated Creditor in respect of any guaranty or security in support of the Subordinated Obligations shall be subject to the terms of this Agreement and applied on the same basis as payments or distributions made directly by the Obligor under such Subordinated Obligations.  To the extent that a Borrower or any of its Subsidiaries that is a Loan Party (other than the respective Obligor or Obligors which are already parties hereto) provide a guarantee or any security in support of any Subordinated Obligations, the party which is the lender of the respective Subordinated Obligations will cause each such Person to become a party hereto (if such Person is not already a party hereto) not later than five days after the execution and delivery of the respective guarantee or security documentation (or such later date as the Administrative Agent shall reasonably agree); provided that any failure to comply with the foregoing requirements of this Section 10 will have no effect whatsoever on the subordination provisions contained herein (which shall apply to all payments or distributions received with respect to any guarantee or security for any Subordinated Obligations, whether or not the Person furnishings such guarantee or security is a party hereto).

SECTION 11. Waiver.  Each Subordinated Creditor and each Obligor hereby waives promptness, diligence, notice of acceptance and any other notice with respect to any of the Senior Obligations and this Agreement and any requirement that the Administrative Agent or any other Guaranteed Party protect, secure, perfect or insure any security interest or lien or any property subject thereto or exhaust any right or take any action against any Obligor or any other person or entity or any collateral.

SECTION 12. Amendments, Etc.  No amendment or waiver of any provision of this Agreement, and no consent to any departure by any Subordinated Creditor or any Obligor herefrom, shall in any event be effective unless the same shall be in writing and signed by the Administrative Agent, such Obligor and each Subordinated Creditor, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given.

SECTION 13.     Addresses for Notices

(a)    Except as provided in clause (b) below, all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by facsimile or other electronic transmission as follows, and all notices

6


 

 

and other communications expressly permitted hereunder to be given by telephone shall be made to the applicable telephone number, as follows:

(i)    if to any Obligor, any Subordinated Creditor or the Administrative Agent, to the address, facsimile number, electronic mail address or telephone number specified for such Person on Schedule I hereto; and

(ii)    if to any other Lender, to the address, facsimile number, electronic mail address or telephone number specified in its Administrative Questionnaire.

(b)    Notices and other communications sent by hand or overnight courier service, or mailed by certified or registered mail, shall be deemed to have been given when received; notices and other communications sent by facsimile shall be deemed to have been given when sent (except that, if not given during normal business hours for the recipient, shall be deemed to have been given at the opening of business on the next business day for the recipient).  Notices and other communications delivered through electronic communications to the extent provided in clause (c) below shall be effective as provided in such clause (c).  

(c)    Notices and other communications provided for hereunder may be delivered or furnished by electronic communication (including e-mail and Internet or intranet websites) pursuant to procedures approved by the Administrative Agent.  The Administrative Agent or any Obligor or Subordinated Creditor may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

(d)    Unless the Administrative Agent otherwise prescribes, (i) notices and other communications sent to an electronic mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return electronic mail or other written acknowledgement); provided that if such notice or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next business day for the recipient, and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient at its electronic mail address as described in the foregoing clause (i) of notification that such notice or communication is available and identifying the website address therefor.



SECTION 14. No Waiver; Remedies; Conflict of Terms.  No failure on the part of the Administrative Agent or any Guaranteed Party to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any right hereunder preclude any other or further exercise thereof or the exercise of any other right.  The remedies herein provided are cumulative and not exclusive of any remedies provided by law.  

SECTION 15. Joinder.  Upon execution and delivery after the date hereof by any Subsidiary of a joinder agreement in substantially the form of Exhibit A hereto, each such Subsidiary shall become an Obligor and/or a Subordinated Creditor, as applicable, hereunder with the same force and effect as if originally named as an Obligor or a Subordinated Creditor, as applicable, hereunder.  The rights and obligations of each Obligor and each Subordinated Creditor hereunder shall remain in full force and effect notwithstanding the addition of any new Obligor or Subordinated Creditor as a party to this Agreement.



SECTION 16. Each Subordinated Creditor and each Obligor hereby expressly waives notice of acceptance of this Agreement, acceptance on the part of the Administrative Agent and the other

7


 

 

Guaranteed Parties being conclusively presumed by their request for this Agreement and delivery of the same to the Administrative Agent.

SECTION 17.     Governing Law; Jurisdiction; Etc.  

(a)    THIS AGREEMENT SHALL BE GOVERNED BY, AND SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK. 

(b)    BY EXECUTING AND DELIVERING THIS AGREEMENT, EACH OBLIGOR AND EACH SUBORDINATED CREDITOR IRREVOCABLY AND UNCONDITIONALLY SUBMITS, FOR ITSELF AND ITS PROPERTY, TO THE NONEXCLUSIVE JURISDICTION OF THE COURTS OF THE STATE OF NEW YORK SITTING IN NEW YORK CITY IN THE BOROUGH OF MANHATTAN AND OF ANY UNITED STATES DISTRICT COURT OF THE SOUTHERN DISTRICT OF NEW YORK SITTING IN NEW YORK CITY IN THE BOROUGH OF MANHATTAN, AND ANY APPELLATE COURT FROM ANY THEREOF, IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, OR FOR RECOGNITION OR ENFORCEMENT OF ANY JUDGMENT, AND EACH OF THE PARTIES HERETO IRREVOCABLY AND UNCONDITIONALLY AGREES THAT ALL CLAIMS IN RESPECT OF ANY SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN SUCH NEW YORK STATE COURT OR, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, IN SUCH FEDERAL COURT.  EACH OF THE PARTIES HERETO AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW.  EACH PARTY HERETO AGREES THAT THE ADMINISTRATIVE AGENT AND THE OTHER GUARANTEED PARTIES RETAIN THE RIGHT TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW OR TO BRING PROCEEDINGS AGAINST ANY GUARANTOR IN THE COURTS OF ANY OTHER JURISDICTION IN CONNECTION WITH THE EXERCISE OF ANY RIGHTS UNDER THIS AGREEMENT OR THE ENFORCEMENT OF ANY JUDGMENT. 

(c)    EACH OBLIGOR AND EACH SUBORDINATED CREDITOR IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT IN ANY COURT REFERRED TO IN PARAGRAPH (b) OF THIS SECTION 5.08.  EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF SUCH ACTION OR PROCEEDING IN ANY SUCH COURT. 



(d)    EACH PARTY HERETO IRREVOCABLY CONSENTS TO SERVICE OF PROCESS IN THE MANNER PROVIDED FOR NOTICES IN SECTION 13 OF THIS AGREEMENT.  NOTHING IN THIS AGREEMENT WILL AFFECT THE RIGHT OF ANY PARTY HERETO TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY APPLICABLE LAW. 

(e)    EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY

8


 

 

ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY).  EACH PARTY HERETO (I) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (II) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION 17(e).  

[Remainder of page left intentionally blank] 

 

9


 

 

IN WITNESS WHEREOF, each Subordinated Creditor, each Obligor and the Borrowers

have caused this Intercompany Subordination Agreement to be duly executed and delivered by its officer thereunto duly authorized as of the date first above written.





 

 

 



OBLIGORS AND SUBORDINATED CREDITORS:



 



MURPHY OIL CORPORATION



 

 



By:

 



Name:

 



Title:

 





 

 



MURPHY EXPLORATION & PRODUCTION COMPANY – INTERNATIONAL



 

 



By:

 



Name:

 



Title:

 





 

 



MURPHY OIL COMPANY LTD.



 

 



By:

 



Name:

 



Title:

 





 

 



MURPHY EXPLORATION & PRODUCTION COMPANY



 

 



By:

 



Name:

 



Title:

 





 

 



MURPHY EXPLORATION & PRODUCTION COMPANY - USA



 

 



By:

 



Name:

 



Title:

 

Signature Page to Intercompany Subordination Agreement


 

 





 

 



OTHER SUBORDINATED CREDITORS:



 



[SUBORDINATED CREDITORS]



 

 



By:

 



Name:

 



Title:

 



Signature Page to Intercompany Subordination Agreement


 

 

Agreed and acknowledged as of the date above written:







 

 



JPMORGAN CHASE BANK, N.A., as Administrative Agent



 

 



By:

 



Name:

Jeffrey C. Miller



Title:

Vice President



 

Signature Page to Intercompany Subordination Agreement


 

 

Schedule I to the Intercompany Subordination Agreement 

ADDRESSES FOR NOTICES 

1.    All notices sent to any Obligor or Subordinated Creditor should be sent to the address specified in Section 10.01 of the Credit Agreement.

2.    All notices sent to the Administrative Agent should be sent to the address specified in Section 10.01 of the Credit Agreement.

I-1


 

 

Exhibit A to the Intercompany Subordination Agreement 



FORM OF JOINDER AGREEMENT 

This JOINDER AGREEMENT dated as of ___________, 20__ (this “Joinder”), is delivered pursuant to the Intercompany Subordination Agreement dated as of [ ], 20[ ] (as amended, amended and restated, supplemented or otherwise modified from time to time, the “Intercompany Subordination Agreement”), among the Subordinated Creditors and Obligors from time to time party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.  All capitalized terms not defined herein shall have the meaning ascribed to them in the Intercompany Subordination Agreement.

1.    Joinder in the Intercompany Subordination.  The undersigned hereby agrees that on and after the date hereof, it shall be [an “Obligor”] [and] [a “Subordinated Creditor”] under and as defined in the Intercompany Subordination Agreement, hereby assumes and agrees to perform all of the obligations of [an Obligor] [and] [a Subordinated Creditor] thereunder and agrees that it shall comply with and be fully bound by the terms of the Intercompany Subordination Agreement as if it had been a signatory thereto as of the date thereof; provided that the representations and warranties made by the undersigned thereunder shall be deemed true and correct as of the date of this Joinder.

2.    Unconditional Joinder.  The undersigned acknowledges that the undersigned’s obligations as a party to this Joinder are unconditional and are not subject to the execution of one or more Joinders by other parties.  The undersigned further agrees that it has joined and is fully obligated as [an Obligor] [and] [a Subordinated Creditor] under the Intercompany Subordination Agreement.

3.    Waiver of Notice of Acceptance.  The undersigned hereby expressly waives notice of acceptance of this Joinder and the Intercompany Subordination Agreement, acceptance on the part of the Administrative Agent and the other Guaranteed Parties being conclusively presumed by their request for this Joinder and the Intercompany Subordination Agreement and delivery of the same to the Administrative Agent.

4.    Incorporation by Reference.  All terms and conditions of the Intercompany Subordination Agreement are hereby incorporated by reference in this Joinder as if set forth in full.

IN WITNESS WHEREOF, the undersigned has duly executed and delivered this Joinder as of the day and year first above written.

[REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]

 


 

 



IN WITNESS WHEREOF, the undersigned has caused this Joinder Agreement to be duly executed and delivered by its officer thereunto duly authorized as of the date first above written.





 

 



 



 

 



 

 



By:

 



Name:

 



Title:

 



 


Exhibit 211 for 2018

MURPHY OIL CORPORATION

SUBSIDIARIES OF THE REGISTRANT AS OF DECEMBER 31, 2018

Exhibit 21.1

 

 





 

 

 

 



 

 

 

Percentage



 

 

 

of Voting



 

 

 

Securities



 

State or Other

 

Owned by



 

Jurisdiction

 

Immediate

Name of Company

 

of Incorporation

 

Parent

Murphy Oil Corporation (REGISTRANT)

 

 

 

 

A.   Arkansas Oil Company

 

Delaware

 

100.0 

B.   Caledonia Land Company

 

Delaware

 

100.0 

C.   El Dorado Engineering Inc.

 

Delaware

 

100.0 

1.   El Dorado Contractors

 

Delaware

 

100.0 

2.   El Dorado Exploracion y Produccion, S. de. R.L. de C.V.

       (see company F.3.b(1) below)

 

 

Mexico

 

10.0 

D.   Marine Land Company

 

Delaware

 

100.0 

E.   Murphy Eastern Oil Company

 

Delaware

 

100.0 

F.   Murphy Exploration & Production Company

 

Delaware

 

100.0 

 1.   Mentor Holding Corporation

 

Delaware

 

100.0 

a.   Mentor Excess and Surplus Lines Insurance Company

 

Delaware

 

100.0 

b.   MIRC Corporation

 

Louisiana

 

100.0 

2.   Murphy Building Corporation

 

Delaware

 

100.0 

 3.   Murphy Exploration & Production Company – International

 

Delaware

 

100.0 

a.   Canam Offshore Limited

 

Bahamas

 

100.0 

(1)  Canam Brunei Oil Ltd.

 

Bahamas

 

100.0 

(2)  Murphy Peninsular Malaysia Oil Co., Ltd.

 

Bahamas

 

100.0 

(3)  Murphy Sabah Oil Co., Ltd.

 

Bahamas

 

100.0 

(4)  Murphy Sarawak Oil Co., Ltd.

 

Bahamas

 

100.0 

(5)  Murphy Cuu Long Tay Oil Co., Ltd.

 

Bahamas

 

100.0 

b.   El Dorado Exploration, S.A.

 

Delaware

 

100.0 

(1)

El Dorado Exploracion y Produccion, S. de. R.L. de C.V.

 

Mexico

 

90 

c.   Murphy Asia Oil Co., Ltd.

 

Bahamas

 

100.0 

d.   Murphy Australia Holdings Pty. Ltd

 

Western Australia

 

100.0 

(1)  Murphy Australia AC/P 57 Oil Pty. Ltd.

 

Western Australia

 

100.0 

(2)  Murphy Australia AC/P 58 Oil Pty. Ltd.

 

Western Australia

 

100.0 

(3)  Murphy Australia EPP43 Oil Pty. Ltd.

 

Western Australia

 

100.0 

(4)  Murphy Australia NT/P80 Oil Pty. Ltd

 

Western Australia

 

100.0 

(5)  Murphy Australia Oil Pty. Ltd.

 

Western Australia

 

100.0 

(i)   Murphy Australia AC/P 36 Oil Pty. Limited

 

Western Australia

 

100.0 

(6)   Murphy Australia WA-408-P Oil Pty. Ltd.

 

Western Australia

 

100.0 

(7)   Murphy Australia WA-476-P Oil Pty. Ltd.

 

Western Australia

 

100.0 

(8)   Murphy Australia WA-481-P Oil Pty. Ltd.

 

Western Australia

 

100.0 

(9)   Murphy Australia AC/P 59 Oil Pty. Ltd.

 

Western Australia

 

100.00 

e.   Murphy Brasil Exploracao e Producao de Petroleo e Gas Ltda.
      (see company l.(1) below)

 

Brazil

 

90.0 

f.    Murphy Cuu Long Bac Oil Co., Ltd.

 

Bahamas

 

100.0 

g.   Murphy Dai Nam Oil Co., Ltd.

 

Bahamas

 

100.0 

h.   Murphy Equatorial Guinea Oil Co., Ltd.

 

Bahamas

 

100.0 

i.    Murphy Exploration (Alaska), Inc.

 

Delaware

 

100.0 

j.    Murphy Luderitz Oil Co., Ltd.

 

Bahamas

 

100.0 

k.   Murphy Nha Trang Oil Co., Ltd.

 

Bahamas

 

100.0 

l.    Murphy Overseas Ventures Inc.

 

Delaware

 

100.0 

(1)  Murphy Brasil Exploracao e Producao de Petroleo e Gas Ltda.
                                    (see company e. above)

 

Brazil

 

10.0 

m.  Murphy Phuong Nam Oil Co., Ltd.

 

Bahamas

 

100.0 

n.   Murphy Semai IV Ltd.

 

Bahamas

 

100.0 

o.   Murphy South Barito, Ltd.

 

Bahamas

 

100.0 

p.   Murphy-Spain Oil Company

 

Delaware

 

100.0 

q.   Murphy West Africa, Ltd.

 

Bahamas

 

100.0 



 

 

 

 


 

 

MURPHY OIL CORPORATION

SUBSIDIARIES OF THE REGISTRANT AS OF DECEMBER 31, 2018 (Contd.)

Exhibit 21.1

 



 

 

 

 



 

 

 

 



 

 

 

Percentage



 

 

 

of Voting



 

 

 

Securities



 

State or Other

 

Owned by



 

Jurisdiction

 

Immediate

Name of Company

 

of Incorporation

 

Parent

r.   Murphy Worldwide, Inc.

 

Delaware

 

100.0 

s.   Murphy Offshore Oil Co. Ltd.

 

Bahamas

 

100.0 

t.   Murphy Netherlands Holdings B.V.

 

Netherlands

 

100.0 

(1)  Murphy Netherlands Holdings II B.V.

 

Netherlands

 

100.0 

(1)  Murphy Sur, S. de R. L. de C.V.

 

Mexico

 

100.0 

 4.   Murphy Exploration & Production Company – USA

 

Delaware

 

100.0 

a.

MP Gulf of Mexico, LLC

 

Delaware

 

80.0 

G.   Murphy Oil Company Ltd.

 

Canada

 

100.0 

 1.   Murphy Canada Exploration Company

 

NSULCo.

 

100.0 

 2.   Murphy Canada Holding ULC

 

AULC

 

100.0 

 3.   Murphy Canada, Ltd.

 

Canada

 

100.0 

 4.   Murphy Finance Company

 

NSULCo.

 

100.0 

H.   New Murphy Oil (UK) Corporation

 

Delaware

 

100.0 

 1.   Murphy Petroleum Limited

 

England

 

100.0 

a.   Murco Petroleum Limited

 

England

 

100.0 



 


Exhibit 231 for Q4 2018

EXHIBIT 23.1













Consent of Independent Registered Public Accounting Firm





The Board of Directors

Murphy Oil Corporation:


We consent to the incorporation by reference in the registration statement (No. 333-226494) on Form S-8 and in the registration statement (No. 333-227875) on Form S-3 of Murphy Oil Corporation of our reports dated February 27, 2019, with respect to the consolidated balance sheets of Murphy Oil Corporation and subsidiaries as of December 31, 2018 and 2017, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2018, and the related notes and financial statement Schedule II  (collectively, the consolidated financial statements), and the effectiveness of internal control over financial reporting as of December 31, 2018, which reports appear in the December 31, 2018 annual report on Form 10‑K of Murphy Oil Corporation.

Our report dated February 27, 2019, on the effectiveness of internal control over financial reporting as of December 31, 2018, contains an explanatory paragraph that states the Company acquired assets in MP Gulf of Mexico, LLC (the Acquired Business) during 2018, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018, the Acquired Business’ internal control over financial reporting associated with total assets of $1.6 billion and total revenues of $56 million included in the consolidated financial statements of the Company as of and for the year ended December 31, 2018. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of the Acquired Business.





/s/ KPMG LLP



Houston, Texas
February 27, 2019








































Exhibit 311 for Q4 2018

EXHIBIT 31.1





CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002



I, Roger W. Jenkins, certify that:



1.

I have reviewed this annual report on Form 10-K of Murphy Oil Corporation;



2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;



4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:



a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



c)

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controls over financial reporting; and



5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):



a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and



b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.





Date:  February 27, 2019







/s/ Roger W. Jenkins

Roger W. Jenkins

Principal Executive Officer










Exhibit 312 for Q4 2018

EXHIBIT 31.2





CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002



I, David R. Looney, certify that:



1.

I have reviewed this annual report on Form 10-K of Murphy Oil Corporation;



2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;



4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:



a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



c)

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controls over financial reporting; and



5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):



a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and



b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.





Date:  February 27, 2019





/s/ David R. Looney

David R. Looney

Principal Financial Officer












Exhibit 32 for Q4 2018



EXHIBIT 32.1



CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002





In connection with the Annual Report of Murphy Oil Corporation (the “Company”) on Form 10-K for the year ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, Roger W. Jenkins and David R. Looney,  Principal Executive Officer and Principal Financial Officer, respectively, of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to our knowledge:



(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and



(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.





Date:  February 27, 2019







/s/ Roger W. Jenkins

Roger W. Jenkins

Principal Executive Officer









/s/ David R. Looney

David R. Looney

Principal Financial Officer










































Exhibit 991 for Q4 2018

Exhibit 99.1

 



















MURPHY OIL CORPORATION











Estimated



Future Reserves



Attributable to Certain



Leasehold Interests



and



Derived Through Certain Production Sharing Contracts











SEC Parameters











As of



December 31, 2018











 

 

/s/ Eric T. Nelson

 

/s/ Val Rick Robinson

Eric T. Nelson, P.E.

 

Val Rick Robinson, P.E.

TBPE License No. 102286

 

TBPE License No. 105137

Managing Senior Vice President

 

Managing Senior Vice President



 

[SEAL]

[SEAL]



RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

 

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

 

Picture 4Picture 1





 

 

                           TBPE REGISTERED ENGINEERING FIRM F-1580

 

FAX (713) 651-0849

                           1100 LOUISIANA STREET    SUITE 4600

HOUSTON,  TEXAS 77002-5294

TELEPHONE (713) 651-9191







January 18, 2019







Trond Mathisen

General Manager - Corporate Reserves Group

Murphy Oil Corporation

9805 Katy Freeway, Suite G-200

Houston, TX 77024





Gentlemen:



At the request of Murphy Oil Corporation  (Murphy), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2018 prepared by Murphy’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).    Our reserves audit, completed on December 28, 2018 and presented herein, was prepared for public disclosure by Murphy in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.  For the Eagle Ford shale properties and Malaysia, the estimated reserves shown herein represent Murphy’s estimated net reserves attributable to the leasehold interests and derived through certain production sharing contracts in certain properties owned by Murphy and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2018.  For the Gulf of Mexico properties, the estimated reserves shown herein represent the Murphy and Petrobras GOM JV (MPGOM) estimated net reserves attributable to the leasehold interests in certain legacy Murphy properties now owned by MPGOM.    The properties reviewed by Ryder Scott incorporate Murphy reserves determinations and are located onshore in the state of Texas, in the federal waters offshore Louisiana and Alabama, and in the countries of Malaysia and Brunei. 



The properties reviewed by Ryder Scott account for a portion of Murphy’s total net proved reserves as of December 31, 2018.  Based on the estimates of total net proved reserves prepared by Murphy, the reserves audit conducted by Ryder Scott addresses 54.0 percent of the total proved developed net reserves on a barrel of oil equivalent, BOE basis and 54.6 percent of the total proved undeveloped net reserves on a barrel of oil equivalent, BOE basis of Murphy.  The net reserves figures provided by Murphy includes the 20 percent non-controlling interest of Petrobras in MPGOM.    



As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or Reserves Information.”  Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.

 

 

 

 

 

 

 

 

 

SUITE  800,  350  7TH  AVENUE, S.W

     CALGARY, ALBERTA T2P 3N9

TEL (403) 262-2799

FAX (403) 262-2790

     621  17TH STREET, SUITE 1550

DENVER, COLORADO 80293-1501

TEL (303) 623-9147

FAX (303) 623-4258

 


 

Murphy Oil Corporation

January 18, 2019

Page 2

 

 

Based on our review, including the data, technical processes and interpretations presented by Murphy, it is our opinion that the overall procedures and methodologies utilized by Murphy in preparing their estimates of the proved reserves as of December 31, 2018 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Murphy are, in the aggregate and within each geographic area, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.



The estimated reserves presented in this report are related to hydrocarbon prices.  Murphy has informed us that in the preparation of their reserves and income projections, as of December 31, 2018, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulationsActual future prices may vary considerably from the prices required by SEC regulationsThe recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The net reserves as estimated by Murphy attributable to Murphy's interest and entitlement in properties that we reviewed are summarized by region as follows





SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold Interests and

Derived Through Certain Production Sharing Contracts of

Murphy Oil Corporation

As of December 31,  2018





 

 

 

 

 

 

 

 



 

Proved



 

Developed

 

 

 

Total



 

Producing

 

Non-Producing

 

Undeveloped

 

Proved

Audited by Ryder Scott

 

Eagle Ford Shale (EFS)

 

Net Reserves

 

 

 

 

 

 

 

 

  Oil/Condensate – MBarrels

 

92,724 

 

797 

 

105,459 

 

198,980 

  Plant Products – MBarrels

 

20,501 

 

257 

 

21,430 

 

42,188 

  Gas – MMcf

 

156,146 

 

1,147 

 

97,858 

 

255,151 

  MBOE

 

139,249 

 

1,245 

 

143,199 

 

283,693 







 

Proved



 

Developed

 

 

 

Total



 

Producing

 

Non-Producing

 

Undeveloped

 

Proved

Malaysia

 

Net Reserves

 

 

 

 

 

 

 

 

  Oil/Condensate – MBarrels

 

36,960 

 

72 

 

14,010 

 

51,042 

  Plant Products – MBarrels

 

662 

 

 

38 

 

700 

  Gas – MMcf

 

113,106 

 

15,225 

 

339,889 

 

468,220 

  MBOE

 

56,473 

 

2,610 

 

70,696 

 

129,779 



RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 3

 

 

For the Gulf of Mexico region, the net reserves below represent 100 percent of the Murphy and Petrobras GOM JV (MPGOM) and include the 20 percent non-controlling interest (NCI) of Petrobras:





SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold Interests and

Murphy Petrobras GOM JV (MPGOM)

As of December 31, 2018





 

 

 

 

 

 

 

 



 

Proved



 

Developed

 

 

 

Total



 

Producing

 

Non-Producing

 

Undeveloped

 

Proved

Gulf of Mexico (GOM)

 

Net Reserves to MPGOM

 

 

 

 

 

 

 

 

  Oil/Condensate – MBarrels

 

20,828 

 

5,680 

 

10,256 

 

36,764 

  Plant Products – MBarrels

 

1,418 

 

302 

 

666 

 

2,386 

  Sales Gas – MMcf

 

23,989 

 

3,523 

 

6,430 

 

33,942 

  MBOE

 

26,244 

 

6,569 

 

11,994 

 

44,807 





Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (MBarrels).  All gas volumes are reported on an as sold basis expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located.  Certain gas volumes that are consumed as fuel in operations are also included as net gas reserves; these volumes represent 2.5% of the total GOM net MBOE, 3.5% of the total EFS net MBOE, and 1%  of the total Malaysia net MBOE.  The net reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.  MBOE means thousand barrels of oil equivalent.





Reserves Included in This Report



In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.



The various proved reserves status categories are defined under the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report.  The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.



 Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”  All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 4

 

 

progressively increasing uncertainty in their recoverability.  At Murphy’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.



Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.  The proved reserves included herein were estimated using deterministic methods.  The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”    



Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.  For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”  Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.  Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.    





Audit Data, Methodology, Procedure and Assumptions



The estimation of reserves involves two distinct determinations.  The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures.  These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy.  These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves.  Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.



In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator.  When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves.  If the reserves  quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator.  Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported.  For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.”  The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.”  The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.”  All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 5

 

 

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available.  Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.



The proved reserves, prepared by Murphy,  for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods.  The proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were primarily estimated by performance methods or a combination of methods.  These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through October, 2018, in those cases where such data were considered to be definitive.  The data utilized in this analysis were furnished to Ryder Scott by Murphy or obtained from public data sources and were considered sufficient for the purpose thereof.  Certain proved producing reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods.  These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserves estimates was considered to be inappropriate. 



Most of the proved developed non-producing and undeveloped reserves that we reviewed were estimated by performance methods, analogy, or a combination of methods.  Certain proved non-developed and undeveloped reserves  that we reviewed were estimated by the volumetric method or a combination of methods. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Murphy for our review or which we have obtained from public data sources that were available through December, 2018.  The data utilized from the analogues in conjunction with well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof. 



To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.  Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.



As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Murphy relating to hydrocarbon prices and costs as noted herein.

 

The hydrocarbon prices furnished by Murphy for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements.  For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract.  Upon contract

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 6

 

 

expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.    



The initial SEC hydrocarbon prices in effect on December 31, 2018 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold.  These benchmark prices are prior to the adjustments for differentials as described herein.  The table below summarizes the “benchmark prices” and “price reference” used by Murphy for the geographic areas reviewed by us.  In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements. 



The product prices which were actually used by Murphy to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.”  The differentials used by Murphy were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Murphy.



The table below summarizes Murphy’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Murphy’s “average realized prices.”  The average realized prices shown in the table below were determined from Murphy’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Murphy’s estimate of the total net reserves for the properties reviewed by us for the geographic area.  The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.







 

 

 

 

 

 

Geographic Area

Product

Price

Reference

Average

Benchmark

Prices

Average Realized

Prices

North America

 

 

 

 

   United States - Offshore

Oil/Condensate

WTI Cushing

$65.56/Bbl

$66.76/Bbl

  

NGLs

WTI Cushing

$65.56/Bbl

$23.83/Bbl



Gas

Henry Hub

$3.10/MMBTU

$2.12/Mcf



 

 

 

 

   United States - Onshore

Oil/Condensate

WTI Cushing

$65.56/Bbl

$67.93/Bbl

  

NGLs

WTI Cushing

$65.56/Bbl

$22.14/Bbl



Gas

Henry Hub

$3.10/MMBTU

$1.99/Mcf



 

 

 

 

Malaysia / Brunei

 

 

 

 

    Sarawak

Oil/Condensate

Brent

$71.56/Bbl

$74.85/Bbl



Gas

Contract

-

$3.60/Mcf



 

 

 

 

    Block H

Oil/Condensate

Brent

$71.56/Bbl

$77.05/Bbl



Gas

Japan Customs-Cleared Crude

$9.12/MMBTU

$3.46/Mcf



 

 

 

 

   Block K

Oil/Condensate

Brent

$71.56/Bbl

$77.05/Bbl



Gas (Kikeh)

Contract

N/A

$0.31/Mcf



Gas (Siakap No.)

Contract

N/A

$0.24/Mcf



RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 7

 

 

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Murphy’s individual property evaluations. 



Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserves estimates reviewed. 



Operating costs furnished by Murphy are based on the operating expense reports of Murphy and include only those costs directly applicable to the leases or wells for the properties reviewed by us.   The operating costs include a portion of general and administrative costs allocated directly to the leases and wells.    For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs.  The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements.    The operating costs furnished by Murphy were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Murphy.  No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.



Development costs furnished by Murphy are based on authorizations for expenditure for the proposed work or actual costs for similar projects.  The development costs furnished by Murphy were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by MurphyThe estimated net cost of abandonment after salvage was included by Murphy for properties where abandonment costs net of salvage were materialMurphy’s estimates of the net abandonment costs were accepted without independent verification.    



The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Murphy’s plans to develop these reserves as of December 31, 2018.  The implementation of Murphy’s development plans as presented to us is subject to the approval process adopted by Murphy’s management.  As the result of our inquiries during the course of our review, Murphy has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Murphy’s management at the appropriate local, regional and/or corporate level.  In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Murphy.  Where appropriate, Murphy has provided written documentation supporting their commitment to proceed with the development activities as presented to us.   Additionally, Murphy has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans.    While these plans could change from those under existing economic conditions as of December 31,  2018, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. 



According to Item 1203 (d) of the SEC Regulations, an explanation should be included for the reasons “…why material amounts of proved undeveloped reserves … remain undeveloped for five years or more after disclosure as proved undeveloped reserves.”  A material amount of proved undeveloped reserves, estimated by Murphy for certain properties reviewed by us, in this report are forecast to be converted to developed beyond the five-year time frame.  A five-year time frame for converting undeveloped to developed was adopted by the SEC, “unless specific circumstances justify a longer time frame.”  In this report, certain undeveloped reserves within the Malaysian properties are scheduled to be developed beyond 5 years due to the platform facility and production rate constraints. It is our opinion that although these reserves are scheduled to be developed beyond 5 years they are compliant with SEC regulations and reasonable for a prudent operator whose development schedule is constrained by the country’s regulations.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 8

 

 

Current costs used by Murphy were held constant throughout the life of the properties.



Murphy’s forecasts of future production rates are based on historical performance from wells currently on production.  If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated.  An estimated rate of decline was then applied to depletion of the reserves.  If a decline trend has been established, this trend was used as the basis for estimating future production rates. 



Test data and other related information were used by Murphy to estimate the anticipated initial production rates for those wells or locations that are not currently producing.  For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Murphy.  Wells or locations that are not currently producing may start producing earlier or later than anticipated in Murphy’s estimates due to unforeseen factors causing a change in the timing to initiate production.  Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. 



The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. 



The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal right to produce or a revenue interest in such production unless evidence indicates that contract renewal is reasonably certain.  Furthermore, properties in the different countries may be subjected to substantially varying contractual fiscal terms that affect the net revenue to Murphy for the production of these volumes.  The prices and economic return received for these net volumes can vary materially based on the terms of these contracts.  Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Murphy the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof.  Ryder Scott has not conducted an exhaustive audit or verification of such contractual information.  Neither our review of such contractual information nor our acceptance of Murphy’s representations regarding such contractual information should be construed as a legal opinion on this matter.



Ryder Scott did not evaluate the country and geopolitical risks in the countries where Murphy operates or has interests.    Murphy’s operations may be subject to various levels of governmental controls and regulations.  These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time.  Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.



The estimates of proved reserves presented herein were based upon a review of the properties in which Murphy owns and derives an interest; however, we have not made any field examination of the properties.  No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Murphy for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 9

 

 

Certain technical personnel of Murphy are responsible for the preparation of reserves estimates on new properties and for the preparation of revised estimates, when necessary, on old properties.  These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner.  We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.



Murphy has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.  In performing our audit of Murphy’s forecast of future proved production, we have relied upon data furnished by Murphy with respect to property interests owned or derived, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, excess profits taxes, export taxes, unrecovered cost balances,  recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements.  Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Murphy.  We consider the factual data furnished to us by Murphy to be appropriate and sufficient for the purpose of our review of Murphy’s estimates of reserves.  In summary, we consider the assumptions, data, methods and analytical procedures used by Murphy and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.





Audit Opinion



Based on our review, including the data, technical processes and interpretations presented by Murphy, it is our opinion that the overall procedures and methodologies utilized by Murphy in preparing their estimates of the proved reserves as of December 31, 2018 comply with the current SEC regulations  and that the overall proved reserves for the reviewed properties as estimated by Murphy are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.  Ryder Scott found the processes and controls used by Murphy in their estimation of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in estimates for these properties.



We were in reasonable agreement with Murphy's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Murphy's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Murphy when its reserves estimates were prepared.  In these cases, Murphy revised its estimates to better conform to our estimates.  As a consequence, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Murphy and the Murphy and Petrobras GOM JV (MPGOM).





Other Properties



Other properties, as used herein, are those properties of Murphy which we did not review.    The proved net reserves attributable to the other properties account for 45.6 percent of the total proved net reserves on an equivalent barrel, BOE, basis based on estimates prepared by Murphy as of December 31, 2018

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 10

 

 

The same technical personnel of Murphy were responsible for the preparation of the reserves  estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.





Standards of Independence and Professional Qualification



Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937.  Ryder Scott is employee-owned and maintains offices in Houston,  Texas;  Denver,  Colorado; and Calgary,  Alberta,  Canada.  We have approximately eighty engineers and geoscientists on our permanent staff.  By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue.  We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients.  This allows us to bring the highest level of independence and objectivity to each engagement for our services.



Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations.  Many of our staff have authored or co-authored technical papers on the subject of reserves related topics.    We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.



Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.    Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training.  Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.



We are independent petroleum engineers with respect to Murphy.  Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.



The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott.  The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.





Terms of Usage



The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Murphy.  



We have provided Murphy with a digital version of the original signed copy of this report letter.  In the event there are any differences between the digital version included in filings made by Murphy and the original signed report letter, the original signed report letter shall control and supersede the digital version.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 11

 

 

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.





 

 

 

Very truly yours,

 

 

 

 

 

RYDER SCOTT COMPANY, L.P.

 

 

TBPE Firm Registration No. F-1580

 

 

 

 

 

 

 

 

/s/ Eric T. Nelson

 

 

 

 

 

Eric T. Nelson, P.E.

 

 

TBPE License No. 102286

 

 

Managing Senior Vice President

[SEAL]

 

 

 

 

 

 

 

/s/ Val Rick Robinson

 

 

 

 

 

Val Rick Robisnon, P.E.

 

 

TBPE License No. 105137

 

 

Managing Senior Vice President

[SEAL]



ETN-VRR (DPR)/pl





 

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

 

















Professional Qualifications of Primary Technical Person



The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Mr. Eric T. Nelson is the primary technical person responsible for the estimate of the reserves, future production and income.



Mr. Nelson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2005, is a Managing Senior Vice President and a member of the Board of Directors.  He is responsible for ongoing reservoir evaluation studies worldwide.  Before joining Ryder Scott, Mr. Nelson served in a number of engineering positions with Exxon Mobil Corporation.  For more information regarding Mr. Nelson’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.



Mr. Nelson earned a Bachelor of Science degree in Chemical Engineering from the University of Tulsa in 2002 (summa cum laude) and a Master of Business Administration from the University of Texas in 2007 (Dean’s Award).  He is a licensed Professional Engineer in the State of Texas.  Mr. Nelson is also a member of the Society of Petroleum Engineers.

 

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Nelson fulfills.  As part of his 2018 continuing education hours, Mr. Nelson attended over 17 hours of training during 2018 covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, evaluations of resource play reserves, evaluation of simulation models, procedures and software, and ethics training.

 

Based on his educational background, professional training and more than 13 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Nelson has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.







 

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

 









PETROLEUM RESERVES DEFINITIONS



As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)





PREAMBLE



On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA).  The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K.  The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”.  The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.  Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).



Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.    All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC.  The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.



Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.



Reserves may be attributed to either natural energy or improved recovery methods.  Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.  Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids.  Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.



Reserves may be attributed to either conventional or unconventional petroleum accumulations.  Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

PETROLEUM RESERVES DEFINITIONS

Page 2

 

 

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.  These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. 

Reserves do not include quantities of petroleum being held in inventory. 



Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.





RESERVES (SEC DEFINITIONS)



Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:



Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.



Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results).  Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).





PROVED RESERVES (SEC DEFINITIONS)



Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:



Proved oil and gas reserves.    Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.



(i) The area of the reservoir considered as proved includes:



(A) The area identified by drilling and limited by fluid contacts, if any, and



(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

PETROLEUM RESERVES DEFINITIONS

Page 3

 

 

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.



(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.



(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and



(B) The project has been approved for development by all necessary parties and entities, including governmental entities.



(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.



 

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

 







PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES



As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)



and



2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)





Reserves status categories define the development and producing status of wells and reservoirs.  Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).





DEVELOPED RESERVES (SEC DEFINITIONS)



Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:



Developed oil and gas reserves are reserves of any category that can be expected to be recovered:



(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and



(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.



Developed Producing (SPE-PRMS Definitions)



While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.



Developed Producing Reserves 

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

 

 

Improved recovery reserves are considered producing only after the improved recovery project is in operation.



Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.



Shut-In

Shut-in Reserves are expected to be recovered from:

(1)

completion intervals that are open at the time of the estimate but which have not  yet started producing;

(2)

wells which were shut-in for market conditions or pipeline connections; or

(3)

wells not capable of production for mechanical reasons.



Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves



In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.





UNDEVELOPED RESERVES (SEC DEFINITIONS)



Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:



Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.



(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.



(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.



(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.





RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


Exhibit 992 for Q4 2018

Exhibit 99.2

 



















MURPHY OIL CORPORATION











Estimated



Future Reserves and Income



Attributable to Certain



Leasehold Interests











SEC Parameters











As of



December 31, 2018





















 

 

/s/ Eric T. Nelson

 

/s/ Christine E. Neylon

Eric T. Nelson, P.E.

 

Christine E. Neylon, P.E.

TBPE License No. 102286

 

TBPE License No. 122128

Managing Senior Vice President

 

Vice President



 

[SEAL]

[SEAL]



RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

 

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Picture 4Picture 1





 

 

                           TBPE REGISTERED ENGINEERING FIRM F-1580

 

FAX (713) 651-0849

                           1100 LOUISIANA STREET    SUITE 4600

HOUSTON,  TEXAS 77002-5294

TELEPHONE (713) 651-9191



January 18, 2019







Trond Mathisen

General Manager - Corporate Reserves Group

Murphy Oil Corporation

9805 Katy Freeway, Suite G-200

Houston, TX 77024





Gentlemen:



At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of the Murphy and Petrobras GOM JV (MPGOM) as of December 31, 2018.  The subject legacy Petrobras properties, now owned by MPGOM, are located in the federal waters offshore LouisianaThe reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).  Our third party study, completed on January 4, 2019 and presented herein, was prepared for public disclosure by Murphy Oil Corporation (Murphy) in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. 



The properties evaluated by Ryder Scott account for a portion of Murphy’s total net proved reserves as of December 31, 2018.  Based on information provided by Murphy,  the third party estimate conducted by Ryder Scott addresses 17.1 percent of the total proved developed net reserves on a barrel of oil equivalent, BOE basis,  and 5.7 percent of the total proved undeveloped net reserves on a barrel of oil equivalent, BOE basis.



The estimated reserves and future net income amounts presented in this report, as of December 31,  2018 are related to hydrocarbon prices.  The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations.  Actual future prices may vary considerably from the prices required by SEC regulationsThe recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The results of this study, which are summarized in the following table, represent 100% of the Murphy and Petrobras GOM JV (MPGOM) and include the 20% non-controlling interest (NCI) of Petrobras.  At Murphy’s request, this report contains the proved reserves attributable to MPGOM but not the associated future income.





 

 

 

 

 

 

 

 

SUITE  800,  350  7TH  AVENUE, S.W

     CALGARY, ALBERTA T2P 3N9

TEL (403) 262-2799

FAX (403) 262-2790

     621  17TH STREET, SUITE 1550

DENVER, COLORADO 80293-1501

TEL (303) 623-9147

FAX (303) 623-4258

 


 

Murphy Oil Corporation

January 18, 2019

Page 2

 

 

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Murphy and Petrobras GOM JV (MPGOM)

As of December 31, 2018





 

 

 

 

 

 

 

 



 

Proved



 

Developed

 

 

 

Total



 

Producing

 

Non-Producing

 

Undeveloped

 

Proved

Net Remaining Reserves

 

 

 

 

 

 

 

 

 Oil/Condensate – MBarrels

 

65,263 

 

3,685 

 

21,775 

 

90,723 

 Plant Products – MBarrels

 

2,284 

 

159 

 

540 

 

2,983 

 Gas – MMcf

 

11,620 

 

1,913 

 

6,420 

 

19,953 

 MBOE

 

69,484 

 

4,163 

 

23,385 

 

97,032 





Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (MBarrels).  All gas volumes are reported on an as sold basis expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are locatedCertain gas volumes that are consumed as fuel in operations are also included as net gas reserves; these volumes represent 0.5 percent of the total net MBOE.  The net reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.  MBOE means thousand barrels of oil equivalent.



The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIESTM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton.  The program was used at the request of Murphy.  Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized.  Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding.  The rounding differences are not material.



The deductions incorporate the normal direct costs of operating the wells, recompletion costs, development costs, and certain abandonment costs net of salvage.  The “Other” costs shown include variable costs and certain transportation costs.  The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. 



Liquid hydrocarbon reserves account for approximately 99 percent and gas reserves account for the remaining one percent of total future gross revenue from proved reserves.





Reserves Included in This Report



The proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 2

 

 

The various reserves status categories are defined under the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report.  The proved developed non-producing reserves included herein consist of the behind pipe category.

 

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist.



Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”  All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  At Murphy’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.



Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.”  The proved reserves included herein were estimated using deterministic methods.  The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” 



Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.  For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”  Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.  Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts. 



Murphy’s operations may be subject to various levels of governmental controls and regulations.  These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time.  Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.



The estimates of reserves presented herein were based upon a detailed study of the properties in which Murphy owns an interest; however, we have not made any field examination of the properties.  No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.



RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 2

 

 

Estimates of Reserves



The estimation of reserves involves two distinct determinations.  The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures.  These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy.  These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves.  Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property. 



In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator.  When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves.  If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator.  Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported.  For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.”  The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.”  The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.”  All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.



Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available.  Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.



The proved reserves for the properties included herein were estimated by performance methods or the volumetric method.  Nearly all of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by the volumetric methodThese methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserves estimates was considered to be inappropriate.  The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Murphy or which we have obtained from public data sources that were available through September, 2018.  The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.  Certain proved producing reserves were estimated by performance methodsThese performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through September, 2018 in those cases where such data were considered to be definitive. 

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 2

 

 

The data utilized in this analysis were furnished to Ryder Scott by Murphy or obtained from public data sources and were considered sufficient for the purpose thereof. 



Most of the proved non-producing and undeveloped reserves included herein were estimated by the volumetric method.  The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Murphy or which we have obtained from public data sources that were available through September, 2018.  The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.  Certain proved non-producing and undeveloped reserves were estimated by performance methods



To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.  Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.



Murphy has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.  In preparing our forecast of future proved production and income, we have relied upon data furnished by Murphy with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as processing fees, recompletion and development costs, development plans,  abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements.  Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Murphy.    We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.



In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein.  The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.”  In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.



Future Production Rates



For wells currently on production, our forecasts of future production rates are based on historical performance data.  If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated.  An estimated rate of decline was then applied to depletion of the reserves.  If a decline trend has been established, this trend was used as the basis for estimating future production rates. 

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 2

 

 

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing.  For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Murphy.  Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production.  Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. 



The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. 



Hydrocarbon Prices



The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements.  For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract.  Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described. 



Murphy furnished us with the above mentioned average prices in effect on December 31, 2018.   These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold.  These benchmark prices are prior to the adjustments for differentials as described herein.  The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.  In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.  



The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.”  The differentials used in the preparation of this report were furnished to us by Murphy



In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.





Geographic Area

Product

Price

Reference

Average

Benchmark

Prices

Average Realized

Prices

   North America

 

 

 

 



Oil/Condensate

WTI Cushing

$65.56/Bbl

$64.01Bbl

  United States

NGLs

WTI Cushing

$65.56/Bbl

$27.70/Bbl



Gas

Henry Hub

$3.101/MMBTU

$2.16/Mcf

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 2

 

 

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations. 



Costs



Operating costs for the leases and wells in this report are based on the operating expense reports of Murphy and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs.  The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements.    The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by MurphyNo deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.



Development costs were furnished to us by Murphy and are based on authorizations for expenditure for the proposed work or actual costs for similar projects.  The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs.  The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material.  The estimates of the net abandonment costs furnished by Murphy were accepted without independent verification. 



The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Murphy’s plans to develop these reserves as of December 31, 2018.  The implementation of Murphy’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Murphy’s management.  As the result of our inquiries during the course of preparing this report, Murphy has informed us that the development activities included herein have been subjected to and received the internal approvals required by Murphy’s management at the appropriate local, regional and/or corporate level.  In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Murphy.  Additionally, Murphy has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans.  While these plans could change from those under existing economic conditions as of December 31, 2018, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. 



Current costs used by Murphy were held constant throughout the life of the properties.



Standards of Independence and Professional Qualification



Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937.  Ryder Scott is employee-owned and maintains offices in Houston,  Texas;  Denver,  Colorado; and Calgary,  Alberta,  Canada.  We have approximately eighty engineers and geoscientists on our permanent staff.  By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue.  We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients.  This allows us to bring the highest level of independence and objectivity to each engagement for our services.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 3

 

 

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations.  Many of our staff have authored or co-authored technical papers on the subject of reserves related topics.    We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.



Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.    Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training.  Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.



We are independent petroleum engineers with respect to Murphy.  Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.



The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott.  The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.



Terms of Usage



The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Murphy.    



We have provided Murphy with a digital version of the original signed copy of this report letter.  In the event there are any differences between the digital version included in filings made by Murphy and the original signed report letter, the original signed report letter shall control and supersede the digital version.



RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

Murphy Oil Corporation

January 18, 2019

Page 3

 

 

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.





 

 

 

Very truly yours,

 

 

 

 

 

RYDER SCOTT COMPANY, L.P.

 

 

TBPE Firm Registration No. F-1580

 

 

 

 

 

 

 

/s/ Eric T. Nelson

 

 

 

 

 

Eric T. Nelson, P.E.

 

 

TBPE License No. 102286

 

 

Managing Senior Vice President

[SEAL]

 

 

 

 

 

 

 

/s/ Christine E. Neyon

 

 

 

 

 

Christine E. Neylon, P.E.

 

 

TBPE License No. 122128

 

 

Vice President

[SEAL]





ETN-CEN  (DPR)/pl



 

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

 

















Professional Qualifications of Primary Technical Person



The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Mr. Eric T. Nelson is the primary technical person responsible for the estimate of the reserves, future production and income.



Mr. Nelson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2005, is a Managing Senior Vice President and a member of the Board of Directors.  He is responsible for ongoing reservoir evaluation studies worldwide.  Before joining Ryder Scott, Mr. Nelson served in a number of engineering positions with Exxon Mobil Corporation.  For more information regarding Mr. Nelson’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.



Mr. Nelson earned a Bachelor of Science degree in Chemical Engineering from the University of Tulsa in 2002 (summa cum laude) and a Master of Business Administration from the University of Texas in 2007 (Dean’s Award).  He is a licensed Professional Engineer in the State of Texas.  Mr. Nelson is also a member of the Society of Petroleum Engineers.

 

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Nelson fulfills.  As part of his 2018 continuing education hours, Mr. Nelson attended over 17 hours of training during 2018 covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, evaluations of resource play reserves, evaluation of simulation models, procedures and software, and ethics training.

 

Based on his educational background, professional training and more than 13 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Nelson has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.







 

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

 









PETROLEUM RESERVES DEFINITIONS



As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)





PREAMBLE



On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA).  The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K.  The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”.  The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.  Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).



Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.    All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC.  The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.



Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.



Reserves may be attributed to either natural energy or improved recovery methods.  Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.  Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids.  Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.



Reserves may be attributed to either conventional or unconventional petroleum accumulations.  Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. 

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PETROLEUM RESERVES DEFINITIONS

Page 2

 

 

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.  These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. 



Reserves do not include quantities of petroleum being held in inventory. 



Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.





RESERVES (SEC DEFINITIONS)



Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:



Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.



Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results).  Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).





PROVED RESERVES (SEC DEFINITIONS)



Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:



Proved oil and gas reserves.    Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.



(i) The area of the reservoir considered as proved includes:



(A) The area identified by drilling and limited by fluid contacts, if any, and



(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

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PETROLEUM RESERVES DEFINITIONS

Page 2

 

 

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.



(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.



(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and



(B) The project has been approved for development by all necessary parties and entities, including governmental entities.



(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.









 

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

 







PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES



As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)



and



2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)





Reserves status categories define the development and producing status of wells and reservoirs.  Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).





DEVELOPED RESERVES (SEC DEFINITIONS)



Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:



Developed oil and gas reserves are reserves of any category that can be expected to be recovered:



(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and



(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.



Developed Producing (SPE-PRMS Definitions)



While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.



Developed Producing Reserves 

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


 

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

 

 

Improved recovery reserves are considered producing only after the improved recovery project is in operation.



Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.



Shut-In

Shut-in Reserves are expected to be recovered from:

(1)

completion intervals that are open at the time of the estimate but which have not  yet started producing;

(2)

wells which were shut-in for market conditions or pipeline connections; or

(3)

wells not capable of production for mechanical reasons.



Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves



In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.





UNDEVELOPED RESERVES (SEC DEFINITIONS)



Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:



Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.



(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.



(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.



(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.





RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


Exhibit 993 for Q4 2018

Exhibit 99.3

 

Picture 1

February 5, 2019





Murphy Oil Corporation

4000, 520 – 3rd Avenue SW

Calgary, Alberta

T2P 0R3





Attention:          Mr. Trond Mathisen, Corporate Reserves Group Manager





Reference:        Murphy Oil Corporation

Evaluation of the Canadian Oil and Gas Properties as of December 31, 2018



Dear Sir:

Pursuant to your request, McDaniel & Associates Consultants Ltd. (“McDaniel”) has conducted an independent audit of Murphy Oil Corporation’s (“Murphy”) proved crude oil, natural gas and natural gas liquids reserves for Murphy’s interests in the Greater Kaybob Project located within the Province of Alberta, Canada, and the Hibernia Main, Hibernia Southern Extension, and Terra Nova projects (the “East Coast Canada properties”) located within the Province of Newfoundland and Labrador, Canada.  Murphy holds a 70 percent working interest in the Greater Kaybob Project, and a 6.5 percent working interest in the Hibernia Main Project, 4.3791 percent working interest in the Hibernia Southern Extension Project and 10.475 percent working interest in the Terra Nova Project.  Murphy has represented that these properties account for approximately nine percent of its total company proved reserves on an equivalent barrel basis as of December 31, 2018, and that its reserves estimates have been prepared in accordance with the United States Securities and Exchange Commission (SEC) definitionsWe have reviewed information provided to us by Murphy that it represents to be its estimates of the reserves, as of December 31, 2018, for the same properties as those which we auditedThe completion date of our report is January 15, 2019This report was prepared in accordance with guidelines specified in Item 1202(a)(8) of Regulation S-K and is to be used for inclusion in certain filings of the SEC.

 

2200, Bow Valley Square 3, 255 - 5 Avenue SW, Calgary AB  T2P 3G6     Tel: (403) 262-5506     Fax: (403) 233-2744     www.mcdan.com

 


 

 

 

Murphy Oil Corporation

February 5, 2019

Report of Third Party for certain Canadian Oil & Gas Properties owned by Murphy Limited  Page

2

 

Reserves included herein are expressed as reserves as represented by MurphyGross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2018Working interest reserves are defined as that portion of the gross reserves attributable to the interests owned by Murphy after deducting all working interests owned by othersNet reserves are defined as working interest reserves after the deduction of royalties.

Estimates of crude oil, natural gas and natural gas liquids reserves should be regarded only as estimates that may change as further production history and additional information become availableNot only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Murphy personnel, Murphy files, from records on file with the appropriate regulatory agencies, and from public sourcesIn the preparation of this report we have relied, without independent verification, upon such information furnished by Murphy with respect to property interests, production from such properties, current costs of operation and development, prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented.  Furthermore, if in the course of our examination something came to our attention, which brought into question the validity or sufficiency of any of such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or dataA field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

The process of estimating reserves requires complex judgments and decision-making based on available geological, geophysical, engineering and economic dataTo estimate the economically recoverable oil, synthetic crude oil and natural gas reserves, and related future net cash flows, we consider many factors and make assumptions including:

·

expected reservoir characteristics based on geological, geophysical and engineering assessments;

·

future production rates based on historical performance and expected future operating and investment activities;

·

future oil and gas prices and quality differentials;

·

assumed effects of regulation by governmental agencies; and

·

future development and operating costs

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Murphy Oil Corporation

February 5, 2019

Report of Third Party for certain Canadian Oil & Gas Properties owned by Murphy Limited  Page

3

 

Estimates of reserves were prepared using standard geological and engineering methods generally accepted by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).”  Generally accepted methods for estimating reserves include volumetric calculations, material balance techniques, production decline curves, pressure transient analysis, analogy with similar reservoirs, and reservoir simulationThe method or combination of methods used is based on professional judgment and experience.

Discovered oil and natural gas reserves are generally only produced when they are economically recoverableAs such, oil and gas prices, and capital and operating costs have an impact on whether reserves will ultimately be producedAs required by SEC rules, reserves represent the quantities that are expected to be economically recoverable using existing prices and costsEstimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.

The proved reserves estimates in this report were based upon 2018 first-of-the month fiscal average pricing using benchmark pricingOil prices were primarily based upon West Texas Intermediate at Cushing crude oil benchmark of USD$65.56 per barrel and a Brent crude oil benchmark of USD$71.43 per barrel.  Specific pricing for each field was adjusted for historical quality and transportation cost differentials, and for currency exchange ratesThe resulting adjusted price is referred to as the “realized price.”  For total proved reserves in the Greater Kaybob Project, the estimated realized prices were CAD$67.81 per barrel of crude oil, CAD$1.47 per Mcf of natural gas, and CAD$43.34 per barrel of natural gas liquids.  For total proved reserves in the Hibernia Main and Hibernia South East Extension projects, the estimated realized price was CAD$92.57, while in the Terra Nova Project, the estimated realized price was CAD$91.69 per barrel of crude oil.

Generally, operations are subject to various levels of government controls and regulations.  These laws and regulations may include matters relating to land tenure, drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment, that are subject to change from time to time.  Current legislation is generally a matter of public record, and additional legislation or amendments that will affect reserves or when any such proposals, if enacted, might become effective generally cannot be predicted.  Changes in government regulations could affect reserves or related economics.  In the regions that are currently being evaluated we believe we have applied existing regulations appropriately.

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Murphy Oil Corporation

February 5, 2019

Report of Third Party for certain Canadian Oil & Gas Properties owned by Murphy Limited  Page

4

 

Murphy Estimates

Murphy has represented that estimated proved reserves attributable to the audited properties are based on SEC definitionsMurphy represents that its estimates of the reserves attributable to these properties represents approximately seven,  seven and nine percent of its total company proved developed producing, proved developed and total proved reserves after royalties on an equivalent basis and are as follows, expressed in thousands of barrels (Mbbl), and thousands of barrels of oil equivalent (Mboe):

Murphy’s estimate of Reserves as of December 31, 2018

Certain Canadian Fields Audited by McDaniel & Associates



 

 

 

 

Business Unit

Crude Oil

(Mbbl)

Natural Gas (Mboe)

Natural Gas Liquids (Mboe)

Oil Equivalent (Mboe)

Working Interest Reserves (after royalties)

Proved Developed Producing

Greater Kaybob

5,760

4,550

1,016

11,326

East Coast Canada

15,713

1,995

-

17,708

Proved Developed Non-Producing

Greater Kaybob

735

361

83

1,179

East Coast Canada

93

-

-

93

Proved Developed

Greater Kaybob

6,495

4,911

1,099

12,505

East Coast Canada

15,806

1,995

-

17,801

Proved Undeveloped

Greater Kaybob

28,619

14,841

3,659

47,119

East Coast Canada

1,817

61

-

1,878

Total Proved

Greater Kaybob

35,114

19,752

4,758

59,624

East Coast Canada

17,623

2,056

-

19,679

Note: Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent based on an energy equivalent basis.  Of the Total Proved Natural Gas reserves estimated by Murphy above, 2,076 Mboe are attributed to fuel gas reserves in the East Coast Canada Business Unit.

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Murphy Oil Corporation

February 5, 2019

Report of Third Party for certain Canadian Oil & Gas Properties owned by Murphy Limited  Page

5

 

Reserves Audit Opinion

McDaniel has used all data, assumptions, procedures and methods that it considers necessary to prepare this report.

In our opinion, the information relating to estimated proved reserves of bitumen and synthetic crude oil contained in this opinion has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7 and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (5), (8) of Regulation S-K of the Securities and Exchange Commission.

We have examined the assumptions, data, methods procedures and proved reserves estimates prepared by MurphyIn our opinion, the proved reserves for the reviewed properties as estimated by Murphy are, in aggregate on the basis of equivalent barrels, reasonable because when compared to our estimates, or if we were to perform our own detailed estimates, reflect a difference of not more than plus or minus 10 percent.

The analyses of these properties, as reported herein, was conducted within the context of an audit of a distinct group of properties in aggregate as part of the total corporate level reserves.  Extraction and use of these analyses outside of this context may not be appropriate without supplementary due diligence.

McDaniel is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 60 years.  McDaniel does not have any financial interest, including stock ownership, in MurphyOur fees were not contingent on the results of our evaluationThis letter report has been prepared at the request of Murphy.  

This report was prepared by McDaniel & Associates Consultants Ltd. for the exclusive use of Murphy.  It is not to be reproduced, distributed, or made available, in whole or in part to any person, company, or organization other than Murphy without the knowledge and consent of McDaniel & Associates Consultants Ltd.  We reserve the right to revise any of the estimates provided herein if any relevant data existing prior to preparation of this report was not made available or if any data provided was found to be erroneous.

If there are any questions, please contact Cam Boulton at (403) 218-8965 or Jared Wynveen directly at (403) 218-1397.

Sincerely,

McDANIEL & ASSOCIATES CONSULTANTS LTD.

APEGA PERMIT NUMBER:  P3145







 

 

 

“signed by C. T. Boulton”

 

 

“signed by J. W. B. Wynveen”



 

 

 

C. T. Boulton, P. Eng.

 

 

J. W. B. Wynveen, P. Eng.

Executive Vice President

 

 

Executive Vice President



CTB/JWBW:jep

[18-0224]

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