UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One) | |
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the quarterly period ended June 30, 2019
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
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) | |
(Zip Code) | ||
(Address of principal executive offices) | ||
(Registrant’s telephone number, including area code) | ||
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol | Name of each exchange on which registered |
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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange act.
☒ | 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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
Number of shares of Common Stock, $1.00 par value, outstanding at July 31, 2019 was 162,250,593 .
MURPHY OIL CORPORATION
TABLE OF CONTENTS
| Page |
1
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS (unaudited)
(Thousands of dollars)
| June 30, 2019 | December 31, 2018 ¹ | ||||
ASSETS | ||||||
Current assets | ||||||
Cash and cash equivalents | $ | |||||
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2019 and 2018 | ||||||
Inventories | ||||||
Prepaid expenses | ||||||
Assets held for sale | ||||||
Total current assets | ||||||
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of 8,656,715 in 2019 and $8,070,487 in 2018 | ||||||
Operating lease assets | ||||||
Deferred income taxes | ||||||
Deferred charges and other assets | ||||||
Non-current assets held for sale | ||||||
Total assets | $ | |||||
LIABILITIES AND EQUITY | ||||||
Current liabilities | ||||||
Current maturities of long-term debt | $ | |||||
Short-term loan payable | ||||||
Accounts payable | ||||||
Income taxes payable | ||||||
Other taxes payable | ||||||
Operating lease liabilities | ||||||
Other accrued liabilities | ||||||
Liabilities associated with assets held for sale | ||||||
Total current liabilities | ||||||
Long-term debt, including capital lease obligation | ||||||
Asset retirement obligations | ||||||
Deferred credits and other liabilities | ||||||
Non-current operating lease liabilities | ||||||
Deferred income taxes | ||||||
Non-current liabilities associated with assets held for sale | ||||||
Total liabilities | ||||||
Equity | ||||||
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued | ||||||
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,083,364 shares in 2019 and 195,076,924 shares in 2018 | ||||||
Capital in excess of par value | ||||||
Retained earnings | ||||||
Accumulated other comprehensive loss | ( | ) | ( | ) | ||
Treasury stock | ( | ) | ( | ) | ||
Murphy Shareholders' Equity | ||||||
Noncontrolling interest | ||||||
Total equity | ||||||
Total liabilities and equity | $ | |||||
1 Reclassified to conform to current presentation (see Note A). See Notes to Consolidated Financial Statements, page 7.
2
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(Thousands of dollars, except per share amounts)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
| 2019 | 2018 ¹ | 2019 | 2018 ¹ | ||||||||
Revenues | ||||||||||||
Revenue from sales to customers | $ | |||||||||||
Gain (loss) on crude contracts | ( | ) | ( | ) | ||||||||
Gain on sale of assets and other income | ||||||||||||
Total revenues | ||||||||||||
Costs and expenses | ||||||||||||
Lease operating expenses | ||||||||||||
Severance and ad valorem taxes | ||||||||||||
Exploration expenses, including undeveloped lease amortization | ||||||||||||
Selling and general expenses | ||||||||||||
Depreciation, depletion and amortization | ||||||||||||
Accretion of asset retirement obligations | ||||||||||||
Other expense (benefit) | ( | ) | ||||||||||
Total costs and expenses | ||||||||||||
Operating income from continuing operations | ||||||||||||
Other income (loss) | ||||||||||||
Interest and other income (loss) | ( | ) | ( | ) | ( | ) | ||||||
Interest expense, net | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Total other loss | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Income (loss) from continuing operations before income taxes | ( | ) | ( | ) | ||||||||
Income tax expense (benefit) | ( | ) | ||||||||||
Income (loss) from continuing operations | ( | ) | ||||||||||
Income from discontinued operations, net of income taxes | ||||||||||||
Net income including noncontrolling interest | ||||||||||||
Less: Net income attributable to noncontrolling interest | ||||||||||||
NET INCOME ATTRIBUTABLE TO MURPHY | $ | |||||||||||
INCOME (LOSS) PER COMMON SHARE – BASIC | ||||||||||||
Continuing operations | $ | ( | ) | |||||||||
Discontinued operations | ||||||||||||
Net Income | $ | |||||||||||
INCOME (LOSS) PER COMMON SHARE – DILUTED | ||||||||||||
Continuing operations | $ | ( | ) | |||||||||
Discontinued operations | ||||||||||||
Net Income | $ | |||||||||||
Cash dividends per Common share | ||||||||||||
Average Common shares outstanding (thousands) | ||||||||||||
Basic | ||||||||||||
Diluted | ||||||||||||
See Notes to Consolidated Financial Statements, page 7.
3
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
(Thousands of dollars)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
| 2019 | 2018 | 2019 | 2018 | ||||||||
| ||||||||||||
Net income | $ | |||||||||||
Other comprehensive income (loss), net of tax | ||||||||||||
Net (loss) gain from foreign currency translation | ( | ) | ( | ) | ||||||||
Retirement and postretirement benefit plans | ||||||||||||
Deferred loss on interest rate hedges reclassified to interest expense | ||||||||||||
Reclassification of certain tax effects to retained earnings | ( | ) | ||||||||||
Other | ( | ) | ||||||||||
Other comprehensive income (loss) | ( | ) | ( | ) | ||||||||
COMPREHENSIVE INCOME | $ | |||||||||||
See Notes to Consolidated Financial Statements, page 7.
4
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(Thousands of dollars)
| Six Months Ended June 30, | |||||
| 2019 | 2018 ¹ | ||||
Operating Activities | ||||||
Net income including noncontrolling interest | $ | |||||
Adjustments to reconcile net income to net cash provided by continuing operations activities: | ||||||
(Income) loss from discontinued operations | ( | ) | ( | ) | ||
Depreciation, depletion and amortization | ||||||
Previously suspended exploration costs (credits) | ( | ) | ||||
Amortization of undeveloped leases | ||||||
Accretion of asset retirement obligations | ||||||
Deferred income tax charge (benefit) | ( | ) | ||||
Pretax (gain) loss from sale of assets | ( | ) | ||||
Mark to market and revaluation of contingent consideration | ||||||
Mark to market of crude contracts | ( | ) | ||||
Long-term non-cash compensation | ||||||
Net (increase) decrease in noncash operating working capital | ( | ) | ||||
Other operating activities, net | ( | ) | ( | ) | ||
Net cash provided by continuing operations activities | ||||||
Investing Activities | ||||||
Acquisition of oil and gas properties | ( | ) | ||||
Property additions and dry hole costs | ( | ) | ( | ) | ||
Proceeds from sales of property, plant and equipment | ||||||
Net cash required by investing activities | ( | ) | ( | ) | ||
Financing Activities | ||||||
Borrowings on revolving credit facility | ||||||
Proceeds from term loan | ||||||
Repurchase of common stock | ( | ) | ||||
Capital lease obligation payments | ( | ) | ||||
Withholding tax on stock-based incentive awards | ( | ) | ( | ) | ||
Distribution to noncontrolling interest | ( | ) | ||||
Cash dividends paid | ( | ) | ( | ) | ||
Net cash provided (required) by financing activities | ( | ) | ||||
Cash Flows from Discontinued Operations 2 | ||||||
Operating activities | ||||||
Investing activities | ( | ) | ( | ) | ||
Financing activities | ( | ) | ( | ) | ||
Net cash provided by discontinued operations | ||||||
Cash transferred from discontinued operations to continuing operations | ||||||
Effect of exchange rate changes on cash and cash equivalents | ||||||
Net increase (decrease) in cash and cash equivalents | ( | ) | ||||
Cash and cash equivalents at beginning of period | ||||||
Cash and cash equivalents at end of period | $ | |||||
1 Reclassified to conform to current presentation (See Note A).
2 Cash flows from discontinued operations are not part of the cash flow reconciliation.
See Notes to Consolidated Financial Statements, page 7.
5
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)
(Thousands of dollars)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
| 2019 | 2018 | 2019 | 2018 | ||||||||
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued | $ | |||||||||||
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,083,364 shares at June 30, 2019 and 195,065,341 shares at June 30, 2018 | ||||||||||||
Balance at beginning of period | ||||||||||||
Exercise of stock options | ||||||||||||
Balance at end of period | ||||||||||||
Capital in Excess of Par Value | ||||||||||||
Balance at beginning of period | ||||||||||||
Exercise of stock options, including income tax benefits | ( | ) | ( | ) | ||||||||
Restricted stock transactions and other | ( | ) | ( | ) | ( | ) | ||||||
Stock-based compensation | ||||||||||||
Adjustments to acquisition valuation | ( | ) | ||||||||||
Balance at end of period | ||||||||||||
Retained Earnings | ||||||||||||
Balance at beginning of period | ||||||||||||
Net income (loss) for the period | ||||||||||||
Reclassification of certain tax effects from accumulated other comprehensive loss | ||||||||||||
Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact | ||||||||||||
Cash dividends | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Balance at end of period | ||||||||||||
Accumulated Other Comprehensive Loss | ||||||||||||
Balance at beginning of period | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Foreign currency translation (loss) gain, net of income taxes | ( | ) | ( | ) | ||||||||
Retirement and postretirement benefit plans, net of income taxes | ||||||||||||
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes | ||||||||||||
Reclassification of certain tax effects to retained earnings | ( | ) | ||||||||||
Other | ( | ) | ||||||||||
Balance at end of period | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Treasury Stock | ||||||||||||
Balance at beginning of period | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Purchase of treasury shares | ( | ) | ( | ) | ||||||||
Awarded restricted stock, net of forfeitures | ||||||||||||
Balance at end of period – 32,832,771 shares of Common Stock in 2019 and 22,018,095 shares of Common Stock in 2018, at cost | ( | ) | ( | ) | ( | ) | ( | ) | ||||
Murphy Shareholders’ Equity | ||||||||||||
Noncontrolling Interest | ||||||||||||
Balance at beginning of period | ||||||||||||
Acquisition closing adjustments | ( | ) | ||||||||||
Net income attributable to noncontrolling interest | ||||||||||||
Distributions to noncontrolling Interest Owners | ( | ) | ( | ) | ||||||||
Balance at end of period | ||||||||||||
Total Equity | $ | |||||||||||
See Notes to Consolidated Financial Statements, page 7.
6
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 2 through 6 of this Form 10-Q report.
Note A – Nature of Business and Interim Financial Statements
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 and Canada and conducts oil and natural gas exploration activities worldwide.
Malaysia has been classified as held for sale on the accompanying balance sheets; and effective January 1, 2019 Malaysia was reported as discontinued operations as the sale represents a strategic shift that has a major effect on the Company’s operations and financial results. Prior periods have been reclassified to conform with the current presentation. See Notes E and R for more information regarding the sale of this asset.
In connection with the LLOG acquisition, further discussed in Note Q, we now hold a 0.5% interest in two variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House FPS LLC (collectively Delta House). These VIEs have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of June 30, 2019, our maximum exposure to loss was $3.7 million, which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.
INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at June 30, 2019 and December 31, 2018, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2019 and 2018, in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., 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.
Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2018 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and six-month periods ended June 30, 2019 are not necessarily indicative of future results.
Note B – New Accounting Principles and Recent Accounting Pronouncements
Accounting Principles Adopted
Leases. In February 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) 2016-02 (Topic 842) 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 main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The company adopted the standard in the first quarter of 2019 utilizing the modified retrospective transition method through a cumulative-effect adjustment at the beginning of the first quarter of 2019. The Company has elected the package of practical expedients, which allows the Company not to reassess (1) whether any expired or existing contracts as of the adoption date are or contain a lease, (2) lease classification for any expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date. The Company did not elect to apply the hindsight practical expedient when determining lease term and assessing impairment of right-of-use assets. The adoption of ASU 2016-02 resulted in the recognition of right-of-use assets of $618.1 million, current lease liabilities for operating leases of approximately $155.5 million, non-current lease liabilities of $468.4 million and a cumulative-effect adjustment to credit retained earnings of $116.8 million on its Consolidated Balance Sheets, with no material impact to its Consolidated Statements of Operations. See Note P for further information regarding the impact of the adoption of ASU 2016-02 on the Company’s financial statements.
Compensation – Stock Compensation. In June 2018, the FASB issued an 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 Company adopted this guidance during the first quarter of 2019 and it did not have material impact on its consolidated financial statements.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note B – New Accounting Principles and Recent Accounting Pronouncements (Contd.)
Recent Accounting Pronouncements
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.
Recent Accounting Pronouncements (Contd.)
Compensation-Retirement Benefits-Defined Benefit Plans-General. In August 2018, the FASB issued ASU 2018-14 which 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 two key geographic segments: the U.S. and Canada. 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.
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. Revenue recognized is largely index based with price adjustments for floating market differentials.
Canada- In Canada, contracts are primarily long-term floating commodity index priced, except for certain natural gas physical forward sales fixed-price contracts. For the Onshore business in Canada, the recorded revenue is net of transportation costs 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.
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers (Contd.)
Disaggregation of Revenue
The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.
For the three-months ended June 30, 2019 and 2018, the Company recognized $646.1 million and $426.8 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. For the six-months ended June 30, 2019 and 2018 the Company recognized $1,236.7 million and $823.1 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
(Thousands of dollars) | 2019 | 2018 | 2019 | 2018 | |||||||||
Net crude oil and condensate revenue | |||||||||||||
United States | Onshore | $ | |||||||||||
Offshore | |||||||||||||
Canada | Onshore | ||||||||||||
Offshore | |||||||||||||
Other | |||||||||||||
Total crude oil and condensate revenue | |||||||||||||
Net natural gas liquids revenue | |||||||||||||
United States | Onshore | ||||||||||||
Offshore | |||||||||||||
Canada | Onshore | ||||||||||||
Total natural gas liquids revenue | |||||||||||||
Net natural gas revenue | |||||||||||||
United States | Onshore | ||||||||||||
Offshore | |||||||||||||
Canada | Onshore | ||||||||||||
Total natural gas revenue | |||||||||||||
Total revenue from contracts with customers | |||||||||||||
Gain (loss) on crude contracts | ( | ) | ( | ) | |||||||||
Gain on sale of assets and other income | |||||||||||||
Total revenue | $ | ||||||||||||
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Revenue from Contracts with Customers (Contd.)
Contract Balances and Asset Recognition
As of June 30, 2019, and December 31, 2018, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $191.6 million and $147.6 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.
The Company has not entered into any upstream oil and gas sale contracts that have financing components as at June 30, 2019.
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. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.
For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.
The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the company’s long-term strategy. The contractually stated price for each unit of commodity transferred under these contracts represents the stand-alone selling price of the commodity.
As of June 30, 2019, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of 12 months or more starting at the inception of the contract:
Current Long-Term Contracts Outstanding at June 30, 2019 | ||||||||
Location | Commodity | End Date | Description | Approximate Volumes | ||||
U.S. | Oil | Q3 2019 | Fixed quantity delivery in Eagle Ford | |||||
U.S. | Oil | Q4 2021 | Fixed quantity delivery in Eagle Ford | |||||
U.S. | Oil, 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 | |||||
Canada | Gas | Q4 2020 | Contracts to sell natural gas at USD Index pricing | |||||
Canada | Gas | Q4 2024 | Contracts to sell natural gas at USD Index pricing | |||||
Canada | Gas | Q4 2026 | Contracts to sell natural gas at USD Index pricing | |||||
Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D – Property, Plant and Equipment
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 June 30, 2019, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $245.0 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2019 and 2018.
(Thousands of dollars) | 2019 | 2018 | ||||
Beginning balance at January 1 | $ | |||||
Additions pending the determination of proved reserves | ||||||
Capitalized exploratory well costs charged to expense | ( | ) | ||||
Balance at June 30 | $ | |||||
The capitalized well costs charged to expense during the first six months of 2019 included the CM-1X and the CT-1X wells in Vietnam Block 11-2/11. The wells were originally drilled in 2017. There were no capitalized well costs charged to expense during the first six months of 2018.
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 have been capitalized. The projects are aged based on the last well drilled in the project.
| June 30, | ||||||||||||||||||
| 2019 | 2018 | |||||||||||||||||
(Thousands of dollars) | Amount | No. of Wells | No. of Projects | Amount | No. of Wells | No. of Projects | |||||||||||||
Aging of capitalized well costs: | |||||||||||||||||||
Zero to one year | $ | $ | |||||||||||||||||
One to two years | |||||||||||||||||||
Two to three years | |||||||||||||||||||
Three years or more | |||||||||||||||||||
| $ | $ | |||||||||||||||||
Of the $211.9 million of exploratory well costs capitalized more than one year at June 30, 2019, $57.2 million is in Brunei, $66.1 million is in Vietnam, $61.3 million is in the Gulf of Mexico and $27.3 million is in the U.S. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.
Divestments
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, up to December 31, 2018, and was being recognized straight line over the life of the contract in the Canadian operating segment. The remaining deferred gain of $116.8 million, net of tax, was included as a component of Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of December 31, 2018. As required by ASC 842, effective January 1, 2019, the previously deferred gain related to the sale and leaseback transaction has been transferred to equity upon adoption, lowering liabilities but increasing retained earnings by approximately $116.8 million, net of tax. The Company amortized approximately $3.8 million of the deferred gain during the first six months of 2018.
11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D – Property, Plant and Equipment (Contd.)
Acquisitions
In 2016, a Canadian subsidiary of Murphy Oil acquired a 70 % operated working interest (WI) in Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 % non-operated WI in Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. As part of the transaction, Murphy agreed to pay an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of June 30, 2019, $126.9 million of the carried interest had been paid. The remaining carry is to be paid over a period through 2020.
Note E – Discontinued Operations and Assets Held for Sale
On March 21, 2019, Murphy Oil Corporation announced that a subsidiary had signed a sale and purchase agreement to divest the fully issued share capital of its two subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., to a subsidiary of PTT Exploration and Production Public Company Limited (PTTEP). The sale of the Malaysian business closed on July 10, 2019. See Note R for more information regarding the sale of this asset.
The Company has accounted for its Malaysian exploration and production operations, along with the former U.K., U.S. refining and marketing operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three-month and six-month period ended June 30, 2019 and 2018 were as follows:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
(Thousands of dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||
Revenues | $ | |||||||||||
Costs and expenses | ||||||||||||
Lease operating expenses | ||||||||||||
Depreciation, depletion and amortization | ||||||||||||
Other costs and expenses (benefits) | ||||||||||||
Income before taxes | ||||||||||||
Income tax expense | ||||||||||||
Income from discontinued operations | $ | |||||||||||
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note E – Discontinued Operations and Assets Held for Sale (Contd.)
The following table presents the carrying value of the major categories of assets and liabilities of the Malaysian exploration and production and the U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at June 30, 2019 and December 31, 2018.
(Thousands of dollars) | June 30, 2019 | December 31, 2018 | ||||
Current assets | ||||||
Cash | $ | |||||
Accounts receivable | ||||||
Inventories | ||||||
Prepaid expenses and other | ||||||
Property, Plant, and Equipment, net | — | |||||
Deferred income taxes and other assets | — | |||||
Operating lease asset | — | |||||
Total current assets associated with assets held for sale | ||||||
Non-current assets | ||||||
Property, Plant, and Equipment, net | ||||||
Deferred income taxes and other assets | ||||||
Operating lease asset | ||||||
Total non-current assets associated with assets held for sale | $ | |||||
Current liabilities | ||||||
Accounts payable | $ | |||||
Other accrued liabilities | ||||||
Current maturities of long-term debt | ||||||
Taxes payable | ||||||
Current operating lease liabilities | ||||||
Long-term debt | — | |||||
Asset retirement obligation | ||||||
Non-current operating lease liabilities | ||||||
Total current liabilities associated with assets held for sale | ||||||
Non-current liabilities | ||||||
Long-term debt | ||||||
Asset retirement obligation | ||||||
Total non-current liabilities associated with assets held for sale | $ | |||||
Note F – Financing Arrangements and Debt
On May 30, 2019, the Company entered into a $500 million term loan credit facility (the New Term Credit Facility). The New Term Credit Facility was a senior unsecured guaranteed facility with an original maturity date of December 2, 2019. The covenants within the New Term Credit Facility were substantially consistent with those in the Company’s revolving credit facility (see 2018 facility below), and borrowings under the New Term Credit Facility bore interest at comparable rates to those incurred under the 2018 facility. The New Term Credit Facility was prepayable at any time by the Company and had to be repaid no later than 30 days after closing of the Company’s previously announced Malaysia divestiture. Subsequent to quarter end, the Company closed the previously announced Malaysia divestiture, repaid and terminated the New Term Credit Facility.
13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F – Financing Arrangements and Debt (Contd.)
As of June 30, 2019, 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. At June 30, 2019, the Company had outstanding borrowings of $1.4 billion under the 2018 facility and $23.4 million of outstanding letters of credit, which reduce the borrowing capacity of the 2018 facility. At June 30, 2019, the interest rate in effect on borrowings under the facility was 3.905 %. At June 30, 2019, the Company was in compliance with all covenants related to the 2018 facility. Subsequent to quarter end, the Company closed the previously announced Malaysia divestiture and repaid the 2018 facility in full.
Note G – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.
| Six Months Ended June 30, | |||||
(Thousands of dollars) | 2019 | 2018 | ||||
Net (increase) decrease in operating working capital other than cash and cash equivalents: | ||||||
(Increase) decrease in accounts receivable | $ | ( | ) | ( | ) | |
(Increase) decrease in inventories | ( | ) | ||||
(Increase) decrease in prepaid expenses | ( | ) | ||||
Increase (decrease) in accounts payable and accrued liabilities | ||||||
Increase (decrease) in income taxes payable | ( | ) | ||||
Net (increase) decrease in noncash operating working capital | $ | ( | ) | |||
Supplementary disclosures: | ||||||
Cash income taxes paid, net of refunds | $ | ( | ) | |||
Interest paid, net of amounts capitalized of $0 in 2019 and 2018 | ||||||
Non-cash investing activities: | ||||||
Asset retirement costs capitalized ¹ | $ | |||||
(Increase) decrease in capital expenditure accrual | ( | ) | ||||
| ||||||
1 Includes asset retirement obligations assumed as part of the LLOG acquisition of $37.3 million. See Note Q.
Note H – Employee and Retiree Benefit 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 plan and the U.S. director’s 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.
The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2019 and 2018.
14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note H – Employee and Retiree Benefit Plans (Contd.)
| Three Months Ended June 30, | |||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||
(Thousands of dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||
Service cost | $ | |||||||||||
Interest cost | ||||||||||||
Expected return on plan assets | ( | ) | ( | ) | ||||||||
Amortization of prior service cost (credit) | ( | ) | ( | ) | ||||||||
Recognized actuarial loss | ||||||||||||
Net periodic benefit expense | $ | |||||||||||
Six Months Ended June 30, | ||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||
(Thousands of dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||
Service cost | $ | |||||||||||
Interest cost | ||||||||||||
Expected return on plan assets | ( | ) | ( | ) | ||||||||
Amortization of prior service cost (credit) | ( | ) | ( | ) | ||||||||
Recognized actuarial loss | ||||||||||||
Net periodic benefit expense | $ | |||||||||||
The components of net periodic benefit expense other than the service cost component are included in the line item “Interest and other income (loss)” in Consolidated Statements of Operations.
During the six-month period ended June 30, 2019, the Company made contributions of $14.1 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2019 for the Company’s defined benefit pension and postretirement plans is anticipated to be $18.3 million.
Note I – Incentive Plans
The costs resulting from all share-based and cash-based incentive plans payment transactions are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.
The 2017 Annual Incentive Plan (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 Incentive Plan (2018 Long-Term Plan) authorizes 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 (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2018 Long-Term Plan expires in 2028. A total of 6,750,000 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.
The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.
In the first quarter of 2019, the Committee granted 957,600 performance-based RSUs and 327,900 time-based RSUs to certain employees. The fair value of the performance-based RSUs, using a Monte Carlo valuation model, was $28.09 per unit. The fair value of the time-based RSUs was estimated based on the fair market value of the Company’s stock on the date of grant. The fair value of the time-based RSUs granted was $28.16 per unit. Additionally, in February 2019, the Committee granted 1,025,900 cash-settled RSUs (CRSU) to certain employees. The CRSUs are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards. The initial fair value of the CRSUs granted in February 2019 was $28.16 . Also in February, the Committee granted 78,716 shares of time-based RSUs to the Company’s non-employee Directors
15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note I – Incentive Plans (Contd.)
under the 2018 Stock Plan for Non-Employee Directors. These units are scheduled to vest on the third anniversary of the date of grant. The estimated fair value of these awards was $27.95 per unit on date of grant.
All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding taxes, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the six-month period ended June 30, 2019.
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:
| Six Months Ended June 30, | |||||
(Thousands of dollars) | 2019 | 2018 | ||||
Compensation charged against income before tax benefit | $ | |||||
Related income tax benefit recognized in income | ||||||
Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).
Note J – Earnings per Share
Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 2019 and 2018. The following table reconciles the weighted-average shares outstanding used for these computations.
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||
(Weighted-average shares) | 2019 | 2018 | 2019 | 2018 | |||||||
Basic method | |||||||||||
Dilutive stock options and restricted stock units | |||||||||||
Diluted method | |||||||||||
The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||
| 2019 | 2018 | 2019 | 2018 | |||||||||||
Antidilutive stock options excluded from diluted shares | |||||||||||||||
Weighted average price of these options | $ | $ | $ | $ | |||||||||||
Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income from continuing operations before income taxes. For the three-month and six-month periods ended June 30, 2019 and 2018, the Company’s effective income tax rates were as follows:
| 2019 | 2018 | |
Three months ended June 30, | ( | ||
Six months ended June 30, | |||
The effective tax rate for the three-month period ended June 30, 2019 was below the U.S. statutory tax rate of 21 % due to an enacted future change in the Alberta provincial corporate income tax rate in Canada that reduced the future deferred tax liability by $13.0 million and no tax applied to the pre-tax income of the noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).
16
The effective tax rate for the three-month period ended June 30, 2018 was below the statutory tax rate primarily due to net losses and exploration expenses in certain foreign jurisdictions for which no income tax benefits will be realized, and income generated in foreign jurisdictions which have income tax rates higher than the U.S. statutory tax rate. As a result of a reported pretax loss, these items lowered the effective tax rate.
The effective tax rate for the six-month period ended June 30, 2019 was below the U.S. statutory tax rate of 21 % due to an enacted future change in the Alberta provincial corporate income tax rate in Canada that reduced the future deferred tax liability by $13.0 million and no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
For the six-month period ended June 30, 2018 the effective tax rate is higher than the statutory tax rate of 21% because the Company reported a pre-tax loss and a tax benefit resulting from a favorable tax adjustment related to the 2017 Tax Act. The IRS’s April 2, 2018 guidance allowed for the preservation of 2017 operating loss carryforwards under the 2017 Tax Act’s taxation of unrepatriated foreign earnings. The preservation of the tax loss carryforward reduced the deferred tax expense by $156 million and resulted in a $36 million charge to taxes payable for a net $120 million tax benefit.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take multiple 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 June 30, 2019, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2015; Canada – 2013; Malaysia – 2012; and United Kingdom – 2017.
Note L – Financial Instruments and Risk Management
Murphy 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 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 Accumulated other comprehensive loss until the anticipated transactions occur.
Commodity Price Risks
At June 30, 2019, the Company had 20,000 barrels per day in WTI crude oil swap financial contracts maturing through the end of 2019 at an average price of $63.64 and 20,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2020 at an average price of $60.10 . Under these contracts, which matured monthly, the Company pays the average monthly price in effect and receives the fixed contract prices.
At June 30, 2018, the Company had 21,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018.
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 derivatives outstanding at June 30, 2019 and 2018.
At June 30, 2019 and December 31, 2018, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
| June 30, 2019 | December 31, 2018 | ||||||||||
(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 | $ | Accounts receivable | $ | ||||||||
17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
For the three-month and six-month periods ended June 30, 2019 and June 30, 2018 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) | Gain (Loss) | |||||||||||||
(Thousands of dollars) | Three Months Ended June 30, | Six months ended June 30, | |||||||||||||
Type of Derivative Contract | Statement of Operations Location | 2019 | 2018 | 2019 | 2018 | ||||||||||
Commodity | Gain (loss) on crude contracts | $ | ( | ) | ( | ) | |||||||||
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 years notes sold in May 2012 to match the payment of interest on these notes through 2022. During each of the six-month periods ended June 30, 2019 and 2018, $1.5 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss (net of tax) deferred on these matured contracts at June 30, 2019 was $6.7 million, which is recorded, net of income taxes of $1.8 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately $1.5 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remaining six months of 2019.
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. 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.
The carrying value of assets and liabilities recorded at fair value on a recurring basis at June 30, 2019 and December 31, 2018 are presented in the following table.
| June 30, 2019 | December 31, 2018 | ||||||||||||||||||||||
(Thousands of dollars) | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||
Assets: | ||||||||||||||||||||||||
Commodity derivative contracts | $ | |||||||||||||||||||||||
| $ | |||||||||||||||||||||||
| ||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||
Nonqualified employee savings plans | $ | |||||||||||||||||||||||
Contingent consideration | ||||||||||||||||||||||||
| $ | |||||||||||||||||||||||
The fair value of WTI crude oil derivative contracts in 2018 and 2019 were based on active market quotes for WTI crude oil. The income effect of changes in the fair value of crude oil derivative contracts is recorded in Gain (loss) on crude contracts in the Consolidated Statements of Operations.
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 contingent consideration, related to two recent acquisitions, is valued using a Monte Carlo simulation model. 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.
18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note L – Financial Instruments and Risk Management (Contd.)
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 June 30, 2019 and December 31, 2018.
Subsequent to the balance sheet date, the Company has entered into additional derivative instruments to manage certain risks related to commodity prices.
Note M – Accumulated Other Comprehensive Loss
The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2018 and June 30, 2019 and the changes during the six-month period ended June 30, 2019 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, 2018 | $ | ( | ) | ( | ) | ( | ) | ( | ) | |||
2019 components of other comprehensive income (loss): | ||||||||||||
Before reclassifications to income and retained earnings | ||||||||||||
Reclassifications to income | ¹ | ² | ||||||||||
Net other comprehensive income (loss) | ||||||||||||
Balance at June 30, 2019 | $ | ( | ) | ( | ) | ( | ) | ( | ) | |||
1 Reclassifications before taxes of $7,061 are included in the computation of net periodic benefit expense for the six-month period ended June 30, 2019. See Note H for additional information. Related income taxes of $1,545 are included in Income tax expense (benefit) for the six-month period ended June 30, 2019.
2 Reclassifications before taxes of $1,482 are included in Interest expense, net, for the six-month period ended June 30, 2019. Related income taxes of $311 are included in Income tax expense (benefit) for the six-month period ended June 30, 2019. See Note L for additional information.
Note N – Environmental and Other 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 changes; 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.
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
19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note N– Environmental and Other Contingencies (Contd.)
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 and operational 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. The Company has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations. 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.
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.
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 O – Business Segments
Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, 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, is shown in the tables to reconcile the business segments to consolidated totals.
(Millions of dollars) | Total Assets at June 30, 2019 | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 | |||||||||||||
External Revenues | Income (Loss) | External Revenues | Income (Loss) | |||||||||||||
Exploration and production ¹ | ||||||||||||||||
United States | $ | |||||||||||||||
Canada | ( | ) | ||||||||||||||
Other | ( | ) | ( | ) | ||||||||||||
Total exploration and production | ||||||||||||||||
Corporate | ( | ) | ( | ) | ( | ) | ||||||||||
Assets/revenue/income from continuing operations | ( | ) | ||||||||||||||
Discontinued operations, net of tax | ||||||||||||||||
Total | $ | |||||||||||||||
20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note O – Business Segments (Contd.)
(Millions of dollars) | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 | |||||||||||
External Revenues | Income (Loss) | External Revenues | Income (Loss) | ||||||||||
Exploration and production ¹ | |||||||||||||
United States | $ | ||||||||||||
Canada | |||||||||||||
Other | ( | ) | ( | ) | |||||||||
Total exploration and production | |||||||||||||
Corporate | ( | ) | ( | ) | ( | ) | |||||||
Assets/revenue/income from continuing operations | |||||||||||||
Discontinued operations, net of tax | |||||||||||||
Total | $ | ||||||||||||
1 Additional details about results of oil and gas operations are presented in the tables on pages 31 and 32.
21
Significant Accounting Policy
At inception, contracts are assessed for the presence of a lease according to criteria laid out by ASC 842. If a lease is present, further criteria is assessed to determine if the lease should be classified as an operating or finance lease. Operating leases are presented on the Consolidated Balance Sheet as Operating lease assets with the corresponding lease liabilities presented in Operating lease liabilities and Non-current operating lease liabilities. Finance lease assets are presented on the Consolidated Balance Sheet within Property, plant and equipment, net with the corresponding liabilities presented in Current maturities of long-term debt and Long-term debt.
Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term. Lease assets are then recognized based on the value of the lease liabilities. Where implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates.
Operating leases are expensed according to their nature and recognized in Lease operating expenses, Selling and general expenses or capitalized in the Consolidated Financial Statements. Finance leases are depreciated with expenses recognized in Depreciation, depletion, and amortization and Interest expense, net on the Consolidated Statement of Operations.
Nature of Leases
The Company has entered into various operating leases such as a gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines, and other oil and gas field equipment. Remaining lease terms range from 1 year to 17 years, some of which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month. Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of both at Company discretion and mutual agreement between the Company and lessor. Purchase options also exist for certain leases.
Related Expenses
Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows:
(Thousands of dollars) | Financial Statement Category | Three Months Ended June 30, 2019 | Six Months Ended June 30, 2019 | ||||||
Operating lease 1,2 | Lease operating expenses | $ | |||||||
Operating lease 2 | Selling and general expense | ||||||||
Operating lease 2 | Other operating expense | ||||||||
Operating lease 2 | Property, plant and equipment | ||||||||
Operating lease 2 | Asset retirement obligations | ||||||||
Finance lease | |||||||||
Amortization of asset | Depreciation, depletion and amortization | ||||||||
Interest on lease liabilities | Interest expense, net | ||||||||
Sublease income | Other income | ( | ) | ( | ) | ||||
Net lease expense | $ | ||||||||
1 For the three months and six months ended June 30, 2019, includes variable lease expenses of $6.6 million and $13.8 million, respectively, primarily related to additional volumes processed at a gas processing plant.
2 For the three months ended includes $10.4 million for Lease operating expense, $1.2 million for Selling and general expense, $28.7 million for Property, plant and equipment, net relating to short-term leases due within 12 months. For the six months ended includes $22.4 million for Lease operating expense, $2.3 million for Selling and general expense, $48.8 million for Property, plant and equipment, net and $3.0 million for Asset retirement obligations relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and gas field equipment.
22
Maturity of Lease Liabilities
(Thousands of dollars) | Operating Leases 1 | Finance Leases | Total | ||||||
2019 | $ | ||||||||
2020 | |||||||||
2021 | |||||||||
2022 | |||||||||
2023 | |||||||||
Remaining | |||||||||
Total future minimum lease payments | |||||||||
Less imputed interest | ( | ) | ( | ) | ( | ) | |||
Present value of lease liabilities 2 | $ | ||||||||
1 Excludes $271.8 million of minimum lease payments for leases entered but not yet commenced. These payments relate to an expansion of an existing gas processing plant and payments are anticipated to commence at the end of 2019 for 20 years.
2 Includes both the current and long-term portion of the lease liabilities.
Lease Term and Discount Rate
| June 30, 2019 | |
Weighted average remaining lease term: | ||
Operating leases | ||
Finance leases | ||
Weighted average discount rate: | ||
Operating leases | % | |
Finance leases | % | |
Other Information
(Thousands of dollars) | Six Months Ended June 30, 2019 | ||
Cash paid for amounts included in the measurement of lease liabilities: | |||
Operating cash flows from operating leases | $ | ||
Operating cash flows from finance leases | |||
Financing cash flows from finance leases | |||
Right-of-use assets obtained in exchange for lease liabilities: | |||
Operating leases | $ | ||
23
PAI Acquisition:
In December 2018, the Company announced the completion of a transaction with Petrobras Americas Inc. (PAI) which was 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 approximately 97 MMBOE (including noncontrolling interest, NCI) of proven reserves at December 31, 2018.
Under the terms of the transaction, Murphy paid cash consideration of $788.7 million and transferred a 20 % interest in MP Gulf of Mexico, LLC (MP GOM), a subsidiary of Murphy, to PAI. Murphy also has an obligation to pay 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. MP GOM is owned 80 % by Murphy and 20 % by PAI, with Murphy overseeing the operations.
LLOG Acquisition:
In June 2019, the Company announced the completion of a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired strategic deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves at May 31, 2019.
Under the terms of the transaction, Murphy paid cash consideration of $1.2 billion and has an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds are exceeded between 2019 and 2022; and $50 million following first oil from certain development projects.
The following table contains the preliminary purchase price allocation at fair value:
(Thousands of dollars) | PAI | LLOG | ||||
Cash consideration paid | $ | |||||
Fair value of net assets contributed | ||||||
Contingent consideration | ||||||
NCI in acquired assets | ||||||
Total purchase consideration | $ | |||||
(Thousands of dollars) | ||||||
Fair value of Property, plant and equipment | $ | |||||
Other assets | ||||||
Less: Asset retirement obligations | ( | ) | ( | ) | ||
Total net assets | $ | |||||
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 require significant judgments and estimates by management at the time of the valuation, are sensitive, and may be subject to change.
Certain data necessary to complete the purchase price allocations are not yet available, and includes, but is not limited to, analysis of the underlying tax basis of the acquired assets and assumed liabilities as well as the final purchase price adjustments to be settled in 2019. We expect to complete the purchase price allocations during the 12-month periods following the acquisition dates of November 30, 2018 and May 31, 2019, during which time the value of the assets and liabilities may be revised as appropriate.
24
Results of Operations
Murphy’s Consolidated Statement of Operations for the three months ended June 30, 2019 included additional revenues of $388.9 million and pre-tax income of $136.8 million attributable to the acquired PAI assets. For the six months ended June 30, 2019, additional revenues of $622.9 million and pre-tax income of $284.5 million attributable to the acquired PAI assets were included in the Consolidated Statement of Operations.
Murphy’s Consolidated Statement of Operations for the three-month and six-month periods ended June 30, 2019 included additional revenues of $43.6 million and pre-tax income of $8.0 million attributable to the acquired LLOG assets.
Pro Forma Financial Information
The following pro forma condensed combined financial information was derived from historical financial statements of Murphy PAI and LLOG and gives effect to the transaction as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable. 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, 2018; furthermore, the financial information is not intended to be a projection of future results.
(Thousands of dollars, except per share amounts) | Three Months Ended June 30, 2018 | Six Months Ended June 30, 2018 | ||||
Revenues | $ | |||||
Net Income Attributable to Murphy | ||||||
| ||||||
Net Income Attributable to Murphy per Common Share | ||||||
Basic | $ | |||||
Diluted | ||||||
Note R – Subsequent Event
25
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
Overall Review
On May 31, 2019, Murphy Oil Corporation completed a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves as of May 31, 2019 in exchange for cash of $1.2 billion paid to LLOG.
During the second quarter of 2019, the Company completed $300 million in share repurchases. Murphy purchased 11.4 million shares outstanding at an average price of $26.34 per share. The current share repurchase program for up to $500 million in share repurchases expires year-end 2020.
On March 21, 2019, Murphy Oil Corporation announced that a subsidiary has signed a sale and purchase agreement to divest the fully issued share capital of its two subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., to a subsidiary of PTT Exploration and Production Public Company Limited (PTTEP). As such the assets and liabilities of the Malaysia business have been classified as held for sale on the consolidated balance sheets and the Malaysia results of operations have been reported as discontinued operations in the statement of operations for all periods presented.
For the three months ended June 30, 2019, the Company produced 171 thousand barrels of oil equivalent per day from continuing operations which excludes Malaysia as it is held for sale. The Company invested $1.6 billion in capital expenditures, on a value of work done basis, in the second quarter of 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations (which includes income attributable to noncontrolling interest of $31.0 million) of $98.8 million for the three months ended June 30, 2019.
For the six months ended June 30, 2019, the Company produced 166 thousand barrels of oil equivalent per day from continuing operations which excludes Malaysia as it is held for sale. The Company invested $2.0 billion in capital expenditures, on a value of work done basis, in the first half of 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations (which includes income attributable to noncontrolling interest of $63.6 million) of $121.7 million for the six months ended June 30, 2019.
In the second quarter of 2018, the Company produced 122 thousand barrels of oil equivalent per day from continuing operations which excludes Malaysia as it is held for sale. The Company invested $275 million in capital expenditures, on a value of work done basis, in the second quarter of 2018. The Company reported net loss from continuing operations of $25.2 million for the three months ended June 30, 2018.
For the six months ended June 30, 2018, the Company produced 119 thousand barrels of oil equivalent per day from continuing operations which excludes Malaysia as it is held for sale. The Company invested $554 million in capital expenditures, on a value of work done basis, in the first half of 2018. The Company reported net income from continuing operations of $65.4 million for the six months ended June 30, 2018, which included an income tax gain of $120.0 million as a result of a 2018 Internal Revenue Service (IRS) interpretation of the 2017 Tax Act enacted in the fourth quarter of 2017.
During the three-month and six-month periods ended June 30, 2019, crude oil and condensate volumes were higher than the prior periods as a result of two Gulf of Mexico acquisitions. The additional income from higher volumes was off-set by lower benchmark oil prices that were below average comparable benchmark prices during 2018. The results are explained in more detail below.
Results of Operations
Murphy’s income (loss) by type of business is presented below.
| Income (Loss) | |||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
(Millions of dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||
Exploration and production | $ | 123.7 | 67.3 | 219.1 | 112.5 | |||||||
Corporate and other | (24.9 | ) | (92.5 | ) | (97.4 | ) | (47.1 | ) | ||||
Income from continuing operations | 98.8 | (25.2 | ) | 121.7 | 65.4 | |||||||
Discontinued operations | 24.4 | 70.7 | 74.3 | 148.4 | ||||||||
Net income including noncontrolling interest | $ | 123.2 | 45.5 | 196.0 | 213.8 | |||||||
26
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Results of Operations (contd.)
Exploration and Production
Results of E&P continuing operations are presented by geographic segment below.
| Income (Loss) | |||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
(Millions of dollars) | 2019 | 2018 | 2019 | 2018 | ||||||||
Exploration and production | ||||||||||||
United States | $ | 133.0 | 72.6 | 249.2 | 108.7 | |||||||
Canada | (5.9 | ) | 9.7 | 1.6 | 34.3 | |||||||
Other International | (3.4 | ) | (15.0 | ) | (31.7 | ) | (30.5 | ) | ||||
Total | $ | 123.7 | 67.3 | 219.1 | 112.5 | |||||||
Second quarter 2019 vs. 2018
United States E&P operations reported earnings of $133.0 million in the second quarter of 2019 compared to income of $72.6 million in the second quarter of 2018. Results were $60.4 million favorable in the 2019 quarter compared to the 2018 period due to higher revenues ($230.2 million) and lower income tax expense ($3.9 million), partially offset by higher depreciation, depletion and amortization ($72.9 million), lease operating expenses ($47.7 million), other operating expense ($19.9 million) other exploration costs ($12.6 million) and G&A ($2.4 million). Higher revenues were primarily due to higher volumes in the U.S. Gulf of Mexico (as a result of the MP GOM transaction in the fourth quarter of 2018 and the LLOG acquisition in the second quarter of 2019). Higher lease operating expenses and depreciation expense was due primarily to higher volumes. Higher other operating expense is due to higher business development spend relating to acquisition transaction costs and the fair market revaluation of the acquisition contingent consideration. Higher exploration charges were due to higher geological and geophysical expense principally in the Gulf of Mexico.
Canadian E&P operations reported a loss of $5.9 million in the second quarter 2019 compared to income of $9.7 million in the 2018 quarter. Results were unfavorable $15.6 million compared to the 2018 period due to lower revenue ($13.6 million) higher lease operating expense ($7.7 million). Lower revenue is principally due to lower gas, oil and condensate prices. Higher lease operating expenses and depreciation are a result of higher volumes sold at Kaybob.
Other international E&P operations reported a loss from continuing operations of $3.4 million in the second quarter of 2019 compared to a net loss of $15.0 million in the prior year quarter. The result was $11.6 million favorable in the 2019 period versus 2018 primarily due to higher revenues from Brunei and higher tax credits.
Six months 2019 vs. 2018
United States E&P operations reported earnings of $249.2 million in the first half of 2019 compared to income of $108.7 million in the first half of 2018. Results were $140.5 million favorable in the 2019 quarter compared to the 2018 period due to higher revenues ($421.3 million), partially offset by higher depreciation, depletion and amortization ($115.2 million), lease operating expenses ($81.6 million), other operating expense ($50.8 million) and G&A ($5.3 million). Higher revenues were primarily due to higher volumes in the U.S. Gulf of Mexico (as a result of the MP GOM transaction in the fourth quarter of 2018 and the LLOG acquisition in the second quarter of 2019). Higher lease operating expenses and depreciation expense was due primarily to higher volumes. Higher other operating expense is due to higher business development spend relating to acquisition transaction costs and the fair market revaluation of acquisition contingent consideration.
Canadian E&P operations reported earnings of $1.6 million in the first half of 2019 compared to income of $34.3 million in the first half of 2018. Results were unfavorable $32.7 million compared to the 2018 period primarily due to lower revenue ($13.0 million), higher lease operating expense ($16.4 million), lower other income ($11.8 million) related to the Seal insurance proceeds received in 2018; and partially off-set by lower tax charges ($11.3 million). Lower revenues are due to lower oil and condensate prices than the prior year. Higher lease operating expenses are due to higher costs at Tupper as a result of a 2018 credit relating to a gain on a sale and lease-back transaction on the disposal of a gas processing plant; in 2018 this gain was being credited to operating expenses equally over the life of the lease. In 2019 this gain was transferred to equity as a result of the implementation of ASC 842 (see Note D).
Other international E&P operations reported a loss from continuing operations of $31.7 million in the first half of 2019 compared to a net loss of $30.5 million in the prior year quarter. The 2019 result includes the write-off of previously suspended exploration
27
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Results of Operations (contd.)
costs of $13.2 million attributable to the CM-1X and the CT-1X wells (originally drilled in 2017) in Vietnam; and is partially off-set by higher revenues in Brunei ($6.0 million) and lower tax credits ($7.6 million).
Second quarter 2019 vs. 2018
Total hydrocarbon production from continuing operations averaged 170,885 barrels of oil equivalent per day in the second quarter of 2019, which represented a 40% increase from the 122,317 barrels per day produced in the 2018 quarter. The increase is principally due to the acquisition of producing Gulf of Mexico assets as part of the MP GOM transaction in the fourth quarter 2018 and the addition of further Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.
Average crude oil and condensate production from continuing operations was 107,283 barrels per day in the second quarter of 2019 compared to 61,117 barrels per day in the second quarter of 2018. The increase of 46,166 barrels per day was principally due to higher volumes in the Gulf of Mexico (45,697 barrels per day) due to the acquisition of assets as part of the MP GOM transaction and the LLOG acquisition. On a worldwide basis, the Company’s crude oil and condensate prices averaged $62.46 per barrel in the second quarter 2019 compared to $67.88 per barrel in the 2018 period, a decrease of 8% quarter to quarter.
Total production of natural gas liquids (NGL) from continuing operations was 10,168 barrels per day in the second quarter 2019 compared to 9,248 barrels per day in the 2018 period. The average sales price for U.S. NGL was $11.74 per barrel in the 2019 quarter compared to $21.28 per barrel in 2018. The average sales price for NGL in Canada was $28.37 per barrel in the 2019 quarter compared to $36.66 per barrel in 2018. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.
Natural gas sales volumes from continuing operations averaged 321 million cubic feet per day (MMCFD) in the second quarter 2019 compared to 312 MMCFD in 2018. The increase of 9 MMCFD was a result of higher volumes in the Gulf of Mexico (25 MMCFD), partially offset by lower volumes in Canada (15 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition. Lower volumes in Canada was a result of a Tupper processing plan turnaround in the 2019 quarter.
Natural gas prices for the total Company averaged $1.25 per thousand cubic feet (MCF) in the 2019 quarter, versus $1.31 per MCF average in the same quarter of 2018. Average prices in the US and Canada in the quarter were $1.88 and $1.07 respectively.
Six months 2019 vs. 2018
Total hydrocarbon production from continuing operations averaged 166,269 barrels of oil equivalent per day in the first half of 2019, which represented a 39% increase from the 119,477 barrels per day produced in the first half of 2018. The increase is principally due to the acquisition of producing Gulf of Mexico assets as part of the MP GOM transaction in the fourth quarter 2018 and the addition of further Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.
Average crude oil and condensate production from continuing operations was 104,567 barrels per day in the first half of 2019 compared to 59,219 barrels per day in the first half of 2018. The increase of 45,348 barrels per day was principally due to higher volumes in the Gulf of Mexico (46,942 barrels per day) due to the acquisition of assets as part of the MP GOM transaction and the LLOG acquisition. On a worldwide basis, the Company’s crude oil and condensate prices averaged $59.23 per barrel in the first half of 2019 compared to $64.55 per barrel in the 2018 period, a decrease of 8.25% quarter to quarter.
Total production of natural gas liquids (NGL) from continuing operations was 9,664 barrels per day in the first half of 2019 compared to 8,845 barrels per day in the 2018 period. The average sales price for U.S. NGL was $12.68 per barrel in the 2019 quarter compared to $20.97 per barrel in 2018. The average sales price for NGL in Canada was $31.78 per barrel in the 2019 quarter compared to $39.83 per barrel in 2018. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.
Natural gas sales volumes from continuing operations averaged 312 million cubic feet per day (MMCFD) in the first half quarter 2019 compared to 308 MMCFD in 2018. The increase of 4 MMCFD was a result of higher volumes in the Gulf of Mexico (16 MMCFD) partially offset by lower volumes in Canada (11 MMCFD). Lower volumes in Canada was a result of a Tupper processing plant turnaround in the second quarter of 2019. Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition.
Natural gas prices for the total Company averaged $1.59 per thousand cubic feet (MCF) in the 2019 quarter, versus $1.55 per MCF average in the same quarter of 2018. Average prices in the US and Canada in the quarter were $1.89 and $1.51 respectively.
Additional details about results of oil and gas operations are presented in the tables on pages 31 and 32.
28
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Results of Operations (contd.)
The following table contains hydrocarbons produced during the three-month and six-month periods ended June 30, 2019 and 2018.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
Barrels per day unless otherwise noted | 2019 | 2018 | 2019 | 2018 | ||||||||
Continuing operations | ||||||||||||
Net crude oil and condensate | ||||||||||||
United States | Onshore | 33,145 | 31,936 | 29,532 | 31,630 | |||||||
Gulf of Mexico 1 | 61,062 | 15,365 | 61,055 | 14,113 | ||||||||
Canada | Onshore | 5,943 | 5,254 | 6,199 | 4,809 | |||||||
Offshore | 6,685 | 7,982 | 7,304 | 8,085 | ||||||||
Other | 448 | 580 | 477 | 582 | ||||||||
Total net crude oil and condensate - continuing operations | 107,283 | 61,117 | 104,567 | 59,219 | ||||||||
Net natural gas liquids | ||||||||||||
United States | Onshore | 5,977 | 6,824 | 5,641 | 6,772 | |||||||
Gulf of Mexico 1 | 3,118 | 1,391 | 2,940 | 1,114 | ||||||||
Canada | Onshore | 1,073 | 1,033 | 1,083 | 959 | |||||||
Total net natural gas liquids - continuing operations | 10,168 | 9,248 | 9,664 | 8,845 | ||||||||
Net natural gas – thousands of cubic feet per day | ||||||||||||
United States | Onshore | 32,209 | 32,679 | 30,752 | 31,894 | |||||||
Gulf of Mexico 1 | 39,029 | 14,284 | 29,356 | 13,548 | ||||||||
Canada | Onshore | 249,367 | 264,748 | 252,120 | 263,036 | |||||||
Total net natural gas - continuing operations | 320,605 | 311,711 | 312,228 | 308,478 | ||||||||
Total net hydrocarbons - continuing operations including NCI 2,3 | 170,885 | 122,317 | 166,269 | 119,477 | ||||||||
Noncontrolling interest | ||||||||||||
Net crude oil and condensate – barrels per day | (11,160 | ) | — | (11,669 | ) | — | ||||||
Net natural gas liquids – barrels per day | (458 | ) | — | (506 | ) | — | ||||||
Net natural gas – thousands of cubic feet per day | (4,507 | ) | — | (4,203 | ) | — | ||||||
Total noncontrolling interest | (12,369 | ) | — | (12,876 | ) | — | ||||||
Total net hydrocarbons - continuing operations excluding NCI 2,3 | 158,516 | 122,317 | 153,394 | 119,477 | ||||||||
Discontinued operations | ||||||||||||
Net crude oil and condensate – barrels per day | 21,556 | 28,950 | 23,744 | 30,084 | ||||||||
Net natural gas liquids – barrels per day | 529 | 872 | 636 | 665 | ||||||||
Net natural gas – thousands of cubic feet per day 2 | 93,382 | 113,125 | 97,465 | 114,195 | ||||||||
Total discontinued operations | 37,649 | 48,676 | 40,624 | 49,782 | ||||||||
Total net hydrocarbons produced excluding NCI 2,3 | 196,165 | 170,993 | 194,018 | 169,259 | ||||||||
1 2019 includes net volumes attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).
2 Natural gas converted on an energy equivalent basis of 6:1
3 NCI – noncontrolling interest in MP GOM.
29
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Results of Operations (contd.)
The following table contains hydrocarbons sold during the three-month and six-month periods ended June 30, 2019 and 2018.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
Barrels per day unless otherwise noted | 2019 | 2018 | 2019 | 2018 | ||||||||
Continuing operations | ||||||||||||
Net crude oil and condensate | ||||||||||||
United States | Onshore | 33,145 | 31,936 | 29,532 | 31,630 | |||||||
Gulf of Mexico 1 | 58,842 | 15,365 | 61,053 | 14,113 | ||||||||
Canada | Onshore | 5,943 | 5,254 | 6,199 | 4,809 | |||||||
Offshore | 6,723 | 7,333 | 7,324 | 8,255 | ||||||||
Other | 470 | — | 468 | — | ||||||||
Total net crude oil and condensate - continuing operations | 105,123 | 59,888 | 104,576 | 58,807 | ||||||||
Net natural gas liquids | ||||||||||||
United States | Onshore | 5,977 | 6,824 | 5,641 | 6,772 | |||||||
Gulf of Mexico 1 | 3,118 | 1,391 | 2,940 | 1,114 | ||||||||
Canada | Onshore | 1,073 | 1,033 | 1,083 | 959 | |||||||
Total net natural gas liquids - continuing operations | 10,168 | 9,248 | 9,664 | 8,845 | ||||||||
Net natural gas – thousands of cubic feet per day | ||||||||||||
United States | Onshore | 32,209 | 32,679 | 30,752 | 31,894 | |||||||
Gulf of Mexico 1 | 39,029 | 14,284 | 29,356 | 13,548 | ||||||||
Canada | Onshore | 249,367 | 264,748 | 252,120 | 263,036 | |||||||
Total net natural gas - continuing operations | 320,605 | 311,711 | 312,228 | 308,478 | ||||||||
Total net hydrocarbons - continuing operations including NCI 2,3 | 168,725 | 121,088 | 166,278 | 119,065 | ||||||||
Noncontrolling interest | ||||||||||||
Net crude oil and condensate – barrels per day | (10,715 | ) | — | (11,669 | ) | — | ||||||
Net natural gas liquids – barrels per day | (458 | ) | — | (506 | ) | — | ||||||
Net natural gas – thousands of cubic feet per day 2 | (4,507 | ) | — | (4,203 | ) | — | ||||||
Total noncontrolling interest | (11,924 | ) | — | (12,876 | ) | — | ||||||
Total net hydrocarbons - continuing operations excluding NCI 2,3 | 156,801 | 121,088 | 153,403 | 119,065 | ||||||||
Discontinued operations | ||||||||||||
Net crude oil and condensate – barrels per day | 21,121 | 30,107 | 23,676 | 30,031 | ||||||||
Net natural gas liquids – barrels per day | 498 | 632 | 580 | 798 | ||||||||
Net natural gas – thousands of cubic feet per day 2 | 93,382 | 113,125 | 97,465 | 114,195 | ||||||||
Total discontinued operations | 37,183 | 49,593 | 40,500 | 49,862 | ||||||||
Total net hydrocarbons sold excluding NCI 2,3 | 193,984 | 170,681 | 193,903 | 168,927 | ||||||||
1 2019 includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1
3 NCI – noncontrolling interest in MP GOM.
30
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Results of Operations (contd.)
The following table contains the weighted average sales prices including transportation cost deduction for the three-month and six-month periods ended June 30, 2019 and 2018.
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||
| 2019 | 2018 | 2019 | 2018 | |||||||||
Weighted average Exploration and Production sales prices | |||||||||||||
Continuing operations | |||||||||||||
Crude oil and condensate – dollars per barrel | |||||||||||||
United States | Onshore | $ | 63.72 | 68.14 | 60.95 | 66.24 | |||||||
| Gulf of Mexico 1 | 62.41 | 68.11 | 58.84 | 65.81 | ||||||||
Canada 2 | Onshore | 48.94 | 59.45 | 47.97 | 57.12 | ||||||||
| Offshore | 67.86 | 72.40 | 64.39 | 68.69 | ||||||||
Other | 73.05 | — | 70.50 | — | |||||||||
Natural gas liquids – dollars per barrel | |||||||||||||
United States | Onshore | 11.73 | 21.29 | 12.29 | 20.62 | ||||||||
| Gulf of Mexico 1 | 10.53 | 23.27 | 13.46 | 23.01 | ||||||||
Canada 2 | Onshore | 28.37 | 36.66 | 31.78 | 39.83 | ||||||||
Natural gas – dollars per thousand cubic feet | |||||||||||||
United States | Onshore | 1.89 | 2.11 | 2.04 | 2.25 | ||||||||
| Gulf of Mexico 1 | 1.87 | 2.18 | 1.72 | 2.36 | ||||||||
Canada 2 | Onshore | 1.07 | 1.17 | 1.51 | 1.42 | ||||||||
Discontinued operations | |||||||||||||
Crude oil and condensate – dollars per barrel | |||||||||||||
Malaysia 3 | Sarawak | 78.25 | 69.72 | 70.32 | 67.13 | ||||||||
| Block K | 65.79 | 67.20 | 65.56 | 65.20 | ||||||||
Natural gas liquids – dollars per barrel | |||||||||||||
Malaysia 3 | Sarawak | 40.81 | 69.61 | 47.42 | 70.57 | ||||||||
Natural gas – dollars per thousand cubic feet | |||||||||||||
Malaysia 3 | Sarawak | 2.57 | 3.86 | 3.60 | 3.62 | ||||||||
| Block K | 0.24 | 0.25 | 0.24 | 0.24 | ||||||||
1 Prices include the effect of noncontrolling interest share for MP GOM.
2 U.S. dollar equivalent.
3 Prices are net of payments under the terms of the respective production sharing contracts.
31
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 30, 2019 AND 2018
(Millions of dollars) | United States 1 | Canada | Other | Total | ||||||||
Three Months Ended June 30, 2019 | ||||||||||||
Oil and gas sales and other operating revenues | $ | 549.0 | 94.8 | 3.1 | 646.9 | |||||||
Lease operating expenses | 99.7 | 36.9 | 0.6 | 137.2 | ||||||||
Severance and ad valorem taxes | 12.8 | 0.3 | — | 13.1 | ||||||||
Depreciation, depletion and amortization | 201.2 | 56.8 | 1.3 | 259.3 | ||||||||
Accretion of asset retirement obligations | 8.4 | 1.5 | — | 9.9 | ||||||||
Exploration expenses | ||||||||||||
Dry holes and previously suspended exploration costs | (0.2 | ) | — | — | (0.2 | ) | ||||||
Geological and geophysical | 15.4 | — | 2.4 | 17.8 | ||||||||
Other exploration | 2.8 | 0.1 | 3.1 | 6.0 | ||||||||
18.0 | 0.1 | 5.5 | 23.6 | |||||||||
Undeveloped lease amortization | 5.9 | 0.4 | 0.9 | 7.2 | ||||||||
Total exploration expenses | 23.9 | 0.5 | 6.4 | 30.8 | ||||||||
Selling and general expenses | 12.9 | 6.1 | 6.1 | 25.1 | ||||||||
Other | 27.9 | 0.2 | 0.1 | 28.2 | ||||||||
Results of operations before taxes | 162.2 | (7.5 | ) | (11.4 | ) | 143.3 | ||||||
Income tax provisions (benefits) | 29.2 | (1.6 | ) | (8.0 | ) | 19.6 | ||||||
Results of operations (excluding corporate overhead and interest) | $ | 133.0 | (5.9 | ) | (3.4 | ) | 123.7 | |||||
| ||||||||||||
Three Months Ended June 30, 2018 | ||||||||||||
Oil and gas sales and other operating revenues | $ | 318.8 | 108.4 | — | 427.2 | |||||||
Lease operating expenses | 52.0 | 29.2 | — | 81.2 | ||||||||
Severance and ad valorem taxes | 12.7 | 0.2 | — | 12.9 | ||||||||
Depreciation, depletion and amortization | 128.3 | 56.8 | 0.7 | 185.8 | ||||||||
Accretion of asset retirement obligations | 4.5 | 1.9 | — | 6.4 | ||||||||
Exploration expenses | ||||||||||||
Geological and geophysical | 0.2 | — | 0.7 | 0.9 | ||||||||
Other exploration | 2.4 | — | 5.9 | 8.3 | ||||||||
2.6 | — | 6.6 | 9.2 | |||||||||
Undeveloped lease amortization | 8.7 | 0.2 | 0.7 | 9.6 | ||||||||
Total exploration expenses | 11.3 | 0.2 | 7.3 | 18.8 | ||||||||
Selling and general expenses | 10.5 | 6.6 | 5.9 | 23.0 | ||||||||
Other | 6.9 | 0.3 | 1.1 | 8.3 | ||||||||
Results of operations before taxes | 92.6 | 13.2 | (15.0 | ) | 90.8 | |||||||
Income tax provisions (benefits) | 20.0 | 3.5 | — | 23.5 | ||||||||
Results of operations (excluding corporate overhead and interest) | $ | 72.6 | 9.7 | (15.0 | ) | 67.3 | ||||||
1 2019 includes results attributable to a noncontrolling interest in MP GOM.
32
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Results of Operations (contd.)
OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2019 AND 2018
(Millions of dollars) | United States 1 | Canada | Other | Total | ||||||||
Six Months Ended June 30, 2019 | ||||||||||||
Oil and gas sales and other operating revenues | $ | 1,018.2 | 213.7 | 6.0 | 1,237.9 | |||||||
Lease operating expenses | 192.1 | 75.9 | 0.9 | 268.9 | ||||||||
Severance and ad valorem taxes | 22.6 | 0.6 | — | 23.2 | ||||||||
Depreciation, depletion and amortization | 365.1 | 116.3 | 2.3 | 483.7 | ||||||||
Accretion of asset retirement obligations | 16.2 | 3.0 | — | 19.2 | ||||||||
Exploration expenses | ||||||||||||
Dry holes and previously suspended exploration costs | (0.1 | ) | — | 13.1 | 13.0 | |||||||
Geological and geophysical | 15.9 | — | 7.9 | 23.8 | ||||||||
Other exploration | 4.0 | 0.2 | 7.1 | 11.3 | ||||||||
19.8 | 0.2 | 28.1 | 48.1 | |||||||||
Undeveloped lease amortization | 12.8 | 0.7 | 1.7 | 15.2 | ||||||||
Total exploration expenses | 32.6 | 0.9 | 29.8 | 63.3 | ||||||||
Selling and general expenses | 30.2 | 13.7 | 11.7 | 55.6 | ||||||||
Other | 58.5 | 0.4 | 0.4 | 59.3 | ||||||||
Results of operations before taxes | 300.9 | 2.9 | (39.1 | ) | 264.7 | |||||||
Income tax provisions (benefits) | 51.7 | 1.3 | (7.4 | ) | 45.6 | |||||||
Results of operations (excluding corporate overhead and interest) | $ | 249.2 | 1.6 | (31.7 | ) | 219.1 | ||||||
| ||||||||||||
Six months ended June 30, 2018 | ||||||||||||
Oil and gas sales and other operating revenues | $ | 596.9 | 226.7 | — | 823.6 | |||||||
Lease operating expenses | 110.5 | 59.5 | — | 170.0 | ||||||||
Severance and ad valorem taxes | 24.5 | 0.5 | — | 25.0 | ||||||||
Depreciation, depletion and amortization | 249.9 | 112.5 | 1.5 | 363.9 | ||||||||
Accretion of asset retirement obligations | 8.9 | 3.9 | — | 12.8 | ||||||||
Exploration expenses | ||||||||||||
Geological and geophysical | 6.2 | — | 3.6 | 9.8 | ||||||||
Other exploration | 3.6 | 0.1 | 11.3 | 15.0 | ||||||||
9.8 | 0.1 | 14.9 | 24.8 | |||||||||
Undeveloped lease amortization | 21.4 | 0.4 | 1.0 | 22.8 | ||||||||
Total exploration expenses | 31.2 | 0.5 | 15.9 | 47.6 | ||||||||
Selling and general expenses | 24.9 | 14.3 | 11.9 | 51.1 | ||||||||
Other | 7.7 | (11.4 | ) | 1.0 | (2.7 | ) | ||||||
Results of operations before taxes | 139.3 | 46.9 | (30.3 | ) | 155.9 | |||||||
Income tax provisions (benefits) | 30.6 | 12.6 | 0.2 | 43.4 | ||||||||
Results of operations (excluding corporate overhead and interest) | $ | 108.7 | 34.3 | (30.5 | ) | 112.5 | ||||||
1 2019 includes results attributable to a noncontrolling interest in MP GOM.
33
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Results of Operations (contd.)
Corporate
Second quarter 2019 vs. 2018
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported a net loss of $24.9 million in the second quarter 2019 compared to net loss of $92.5 million in the 2018 quarter. The $67.6 million favorable variance is principally due to 2019 gains on forward swap commodity contracts ($57.9 million) compared to losses on forward contracts ($37.6 million) in the second quarter of 2018, and OIL insurance dividend ($4.5 million); off-set by higher taxes, foreign exchange and other ($24.0 million) and higher net interest expenses ($14.0 million).
Six months 2019 vs. 2018
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported a net loss of $97.4 million in the first half of 2019 compared to net loss of $47.1 million in the first half of 2018. The $50.3 million unfavorable variance is due to 2019 gains on forward swap commodity contracts ($57.9 million) compared to losses on forward contracts ($67.1 million) in 2018, off-set by a 2018 income tax credit ($120.0 million, related to an IRS interpretation of the Tax Act), higher general and administrative expenses ($12.0 million), higher interest charges ($10.0 million), higher tax charges ($6.8 million), foreign exchange losses ($6.1 million; versus an $8.4 million gain in 2018), and lower OIL insurance dividend income ($3.6 million).
Discontinued Operations
The Company has presented its Malaysia E&P operations and former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.
Malaysia E&P operations reported earnings of $37.2 million in the second quarter of 2019 compared to earnings of $71.1 million in the comparable 2018 period. Results for the second quarter 2019 were unfavorable by $33.9 million primarily due to lower revenues ($68.7 million), higher operating expenses ($31.4 million), partially off-set by lower depreciation ($47.5 million). Lower revenues are principally due to lower volumes sold. Higher operating expenses are due to higher lease operating expenses and commercial settlements prior to the divestiture. The lower depreciation is due to the cessation of charges as a result of the assets being classified as held for sale.
For the six months ended June 30, 2019, Malaysia E&P operations reported earnings of $94.4 million compared to $149.2 million in the 2018 period. Results for the six months ended June 30, 2019 were unfavorable by $54.8 million primarily due to lower revenues ($84.1 million), higher operating expenses ($47.1 million), partially off-set by lower depreciation ($63.8 million) and lower income taxes ($13.4 million). Lower revenues are principally due to lower volumes sold. Higher operating expenses are due to higher lease operating expenses and commercial settlement prior to the divestiture. The lower depreciation is due to the cessation of charges as a result of the assets being classified as held for sale.
Financial Condition
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $655.4 million for the first six months of 2019 compared to $331.7 million during the same period in 2018. The increased cash from operating activities is primarily attributable to higher cash revenues from the Gulf of Mexico acquisitions (see above). Changes in operating working capital from continuing operations decreased cash by $5.4 million during the first six months of 2019, compared to an increase of $22.5 million in 2018.
Cash Used in Investing Activities
Cash used for property additions and dry holes, which includes amounts expensed, were $645.2 million and $565.2 million in the six-month periods ended June 30, 2019 and 2018, respectively. Property additions in 2019 principally relate to exploration and development capital expenditures at Eagleford in the U.S., Kaybob in Canada and U.S. Gulf of Mexico. Cash used for the acquisition of oil and gas properties of $1.2 billion is attributable to acquisition of certain Gulf of Mexico assets from LLOG (see above).
34
Cash Used in Investing Activities (contd.)
Total accrual basis capital expenditures, which includes $1.2 billion for the LLOG acquisition were as follows:
| Six Months Ended June 30, | |||||
(Millions of dollars) | 2019 | 2018 | ||||
Capital Expenditures | ||||||
Exploration and production | $ | 1,966.9 | 546.4 | |||
Corporate | 5.6 | 7.9 | ||||
Total capital expenditures | $ | 1,972.5 | 554.3 | |||
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
| Six Months Ended June 30, | |||||
(Millions of dollars) | 2019 | 2018 | ||||
Property additions and dry hole costs per cash flow statements | $ | 645.2 | 565.2 | |||
Acquisition of oil and gas properties | 1,226.3 | — | ||||
Geophysical and other exploration expenses | 32.0 | 21.8 | ||||
Capital expenditure accrual changes and other | 69.0 | (32.7 | ) | |||
Total capital expenditures | $ | 1,972.5 | 554.3 | |||
The increase in capital expenditures in the exploration and production business in 2019 compared to 2018 was primarily attributable to higher development drilling activities in Eagle Ford Shale and the LLOG acquisition ($1,226.3 million).
Cash Provided by Financing Activities
Net cash provided by financing activities was $1.1 billion for the first six months of 2019 compared to net cash used by financing activities of $93.4 million during the same period. In 2019, the cash provided was principally from net borrowings on our revolver ($1,075.0 million) and a short-term loan ($500.0 million) to fund the LLOG acquisition (see above). These borrowings were repaid in July 2019 following the completion of the Malaysia divestment for net sales proceeds of $2.0 billion. In the quarter the Company used cash to buy back issued ordinary shares of $299.9 million. Total cash dividends to shareholders amounted to $85.5 million for the six months ended June 30, 2019 compared to $86.5 million in the same period of 2018.
Working Capital
Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at June 30, 2019 was a liability of $542.1 million, $688.4 million lower than December 31, 2018, with the decrease primarily attributable to a short-term loan payable ($500.0 million; subsequently repaid in July 2019 - see above); higher accounts payable ($250.4 million), higher operating lease liabilities ($128.6 million; as a result of the implementation of ASC 842, Leases), and partially offset by higher accounts receivable ($194.2 million). The increase in accounts payable and receivable is attributable to the increased operating activity from the two Gulf of Mexico acquisitions.
Capital Employed
At June 30, 2019, long-term debt of $4,185.9 million had increased by $1,076.6 million compared to December 31, 2018, as a result of funding from the revolving credit facility (subsequently repaid in July 2019) to fund the LLOG acquisition. A summary of capital employed at June 30, 2019 and December 31, 2018 follows.
Capital Employed (contd.)
35
| June 30, 2019 | December 31, 2018 | ||||||||||
(Millions of dollars) | Amount | % | Amount | % | ||||||||
Capital employed | ||||||||||||
Long-term debt | $ | 4,185.9 | 45.1 | % | 3,109.3 | 37.4 | % | |||||
Total equity | 5,098.5 | 54.9 | % | 5,197.6 | 62.6 | % | ||||||
Total capital employed | 9,284.4 | 100.0 | % | 8,307.0 | 100.0 | % | ||||||
Total capital employed excluding noncontrolling interest | $ | 8,925.9 | n/a | 7,938.6 | n/a | |||||||
Cash and invested cash are maintained in several operating locations outside the United States. At June 30, 2019, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $68.6 million in Canada and $16.3 million in Brunei. In addition, $15.9 million of cash was held in the United Kingdom and $47.8 million was held in Malaysia but was reported in current Assets held for sale on the Company’s Consolidated Balance Sheet at June 30, 2019. 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.
Accounting changes and recent accounting pronouncements – see Note B
Outlook
Average worldwide crude oil prices at the end of July 2019 have decreased from the average prices during the second quarter of 2019. The Company expects its total oil and natural gas production to average 203,600 – 207,600 barrels of oil equivalent per day in the third quarter 2019 (including noncontrolling interest of 11,700 BOEPD). The Company currently anticipates total capital expenditures for the full year 2019 to be between $1.35 and $1.45 billion (excluding noncontrolling interest of $48 million).
The Company will primarily fund its remaining capital program in 2019 using operating cash flow but will supplement funding where necessary with borrowings under available credit facilities. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings might be required during the remainder of year to maintain funding of the Company’s ongoing development projects.
As of July 31, 2019, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:
Commodities | Contract or Location | Dates | Average Volumes per Day | Average Prices | ||||
U.S. Oil | West Texas Intermediate | July 2019 | 20,000 bbls/d | $63.64 per bbl. | ||||
U.S. Oil | West Texas Intermediate | Aug. – Dec. 2019 | 23,000 bbls/d | $63.17 per bbl. | ||||
U.S. Oil | West Texas Intermediate | Jan. – Dec. 2020 | 24,000 bbls/d | $59.67 per bbl. | ||||
Canada Natural Gas | NOVA Gas Transmission Ltd. | Apr. 2019 – Dec. 2020 | 59 mmcf/d | C$2.81 per mcf | ||||
Forward-Looking Statements
This Form 10-Q 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 our forward-looking statements include, but are not limited to: the failure of the respective counterparties to perform their obligations under the relevant transaction agreements or the failure to satisfy all closing conditions, 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 Murphy’s 2018 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and page 37 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.
36
ITEM 3. 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 L to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
There were commodity transactions in place at June 30, 2019, covering certain future U.S. crude oil sales volumes in 2019 and 2020. A 10% increase in the respective benchmark price of these commodities would have decreased the net receivable associated with these derivative contracts by approximately $62.3 million, while a 10% decrease would have increased the recorded receivable by a similar amount.
There were no derivative foreign exchange contracts in place at June 30, 2019.
ITEM 4. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company 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 the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, 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) are 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.
During the quarter ended June 30, 2019, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
37
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Murphy is engaged in a number of 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 is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
ITEM 1A. RISK FACTORS
The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in its 2018 Form 10-K filed on February 27, 2019. The Company has not identified any additional risk factors not previously disclosed in its 2018 Form 10-K report.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCCEEDS
Issuer Purchase of Equity Securities:
Period | Total Number of Share Purchased | Average Price Paid Per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs1 | |||||||||
April 1 through April 30, 2019 | — | $ | — | — | $ | 500,000 | |||||||
May 1 through May 31, 2019 | 8,980,005 | $ | 26.76 | 8,980,005 | $ | 260,000 | |||||||
June 1 through June 30, 2019 | 2,396,400 | $ | 24.78 | 2,396,400 | $ | 200,000 | |||||||
1 In March 2019, the Company’s Board of Directors authorized a stock repurchase plan of up to $500 million of Murphy Common Stock. This share repurchase program expires December 31, 2020. Maximum approximate values reported represent amounts at end of month.
ITEM 6. EXHIBITS
The Exhibit Index on page 39 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.
38
SIGNATURE
Pursuant to the requirements 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 | |
| (Registrant) | |
| ||
| By | /s/ CHRISTOPHER D. HULSE |
| Christopher D. Hulse, | |
| Vice President and Controller | |
| (Chief Accounting Officer and Duly Authorized Officer) | |
August 8, 2019
(Date)
39
EXHIBIT INDEX
Exhibit No. | ||
| ||
| ||
| ||
| ||
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 | |
Exhibits other than those listed above have been omitted since they are either not required or not applicable.
40
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 quarterly report on Form 10-Q 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: August 8, 2019 |
/s/ Roger W. Jenkins |
Roger W. Jenkins |
Principal Executive Officer |
Ex. 31.1
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 quarterly report on Form 10-Q 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: August 8, 2019 |
/s/ David R. Looney |
David R. Looney |
Principal Financial Officer |
Ex. 31.2
EXHIBIT 32
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 Quarterly Report of Murphy Oil Corporation (the “Company”) on Form 10-Q for the period ended June 30, 2019 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: August 8, 2019 |
/s/ Roger W. Jenkins |
Roger W. Jenkins |
Principal Executive Officer |
/s/ David R. Looney |
David R. Looney |
Principal Financial Officer |
Ex. 32-1