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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended DECEMBER 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ________________ to ________________
Commission file number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 71-0361522
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification Number)
200 Peach Street, P. O. Box 7000, El Dorado, Arkansas 71731-7000
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (501) 862-6411
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Stock, $1.00 Par Value New York Stock Exchange
The Toronto Stock Exchange
Series A Participating Cumulative New York Stock Exchange
Preferred Stock Purchase Rights The Toronto Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
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, and (2) has been subject to such filing requirements
for the past 90 days. Yes X No .
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of the voting stock held by non-affiliates of the
registrant, based on average price at February 29, 1996 as quoted by the New
York Stock Exchange, was approximately $1,398,815,000.
Number of shares of Common Stock, $1.00 Par Value, outstanding at February 29,
1996, was 44,851,962.
Documents incorporated by reference:
The Registrant's definitive Proxy Statement relating to the Annual Meeting of
Stockholders on May 8, 1996 (Part III)
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TABLE OF CONTENTS - 1995 FORM 10-K REPORT
Page
Numbers
-------
PART I
Item 1. Business 3
Item 2. Properties 3
Item 3. Legal Proceedings 9
Item 4. Submission of Matters to a Vote of Security Holders 9
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 10
Item 6. Selected Financial Data 10
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operation 10
Item 8. Financial Statements and Supplementary Data 10
Item 9. Changes in and Disagreements With Accountants
on Accounting and Financial Disclosure 10
PART III
Item 10. Directors and Executive Officers of the Registrant 10
Item 11. Executive Compensation 10
Item 12. Security Ownership of Certain Beneficial Owners 10
and Management
Item 13. Certain Relationships and Related Transactions 10
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 11
Signatures 12
Exhibit Index 13
2
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES.
Murphy Oil Corporation is a natural resources company that operates through
subsidiaries in the United States and internationally to conduct the
various business activities of the enterprise. As used in this report, the
terms Murphy, we, our, its, and Company may refer to any one or more of the
consolidated subsidiaries as well as to Murphy Oil Corporation.
The Company was originally incorporated in Louisiana in 1950 as Murphy
Corporation; reincorporated in Delaware in 1964, at which time it adopted
the name Murphy Oil Corporation; and reorganized in 1983 to operate solely
as a holding company of its various businesses. Its activities are
classified into two business segments: (1) "Petroleum," which comprises
its international integrated oil and gas operations and is further
subdivided into "Exploration and Production" and "Refining, Marketing, and
Transportation," and (2) "Farm, Timber, and Real Estate," which has
operations primarily in Arkansas and North Louisiana. Additionally,
"Corporate and Other" activities include interest income, interest expense,
and overhead not allocated to either of the business segments.
The information appearing on pages 4 through 50 of the 1995 Annual Report
to Security Holders (1995 Annual Report) is incorporated in this Annual
Report on Form 10-K as Exhibit 13 and is deemed to be filed as part of this
10-K report as indicated under Items 1, 2, 3, 5, 6, 7, 8, and 14. A
narrative of the graphic and image information that appears in the paper
format version of Exhibit 13 on pages 4 through 50 is included in the
electronic Form 10-K document as an appendix to Exhibit 13 (pages A-1
through A-8).
In addition to the following information about each business segment, data
relative to Murphy's operations, properties, and industry segments,
including revenues by class of products and financial information by
geographic areas, are described on pages 20 through 28, 40, 41, 46, and 47
of the 1995 Annual Report, which is filed in this 10-K report as Exhibit
13.
PETROLEUM - EXPLORATION AND PRODUCTION
During 1995, Murphy's principal exploration and/or production activities
were conducted in the United States, Ecuador, Spain, China, Pakistan, Peru,
the Falkland Islands, and Ireland by wholly owned Murphy Exploration &
Production Company (Murphy Expro) and its subsidiaries; in Canada by wholly
owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries; and in the U.K.
North Sea by wholly owned Murphy Petroleum Limited. Murphy's crude oil and
natural gas liquids production is primarily in the United States, Canada,
the U.K. North Sea, and Ecuador; its natural gas is produced and sold in
the United States, Canada, the United Kingdom, and Spain. MOCL also has a
five-percent interest in Syncrude Canada Ltd., which extracts synthetic
crude oil from oil sand deposits in northern Alberta.
Murphy's estimated net quantities of proved oil and gas reserves and proved
developed oil and gas reserves at January 1, 1993 and at December 31, 1993,
1994, and 1995 by geographic area are reported on pages 43 and 44 of the
1995 Annual Report, which is filed in this 10-K report as Exhibit 13.
Murphy has not filed, and is not required to file, any estimates of its
total proved net oil or gas reserves on a recurring basis with any federal
or foreign governmental regulatory authority or agency other than the SEC.
Annually, Murphy reports gross reserves of properties operated in the
United States to the U.S. Department of Energy; such reserves are derived
from the same data from which estimated total net proved reserves of such
properties are determined.
In 1995, essentially all of Murphy's crude oil, condensate, and natural gas
liquids production in the United States was delivered, either directly or
indirectly through exchanges, to its own refineries. Net crude oil,
condensate, and gas liquids production and net natural gas sales by
geographic area with weighted average sales prices for each of the five
years ended December 31, 1995 appear on page 48 of the 1995 Annual Report,
which is filed in this 10-K report as Exhibit 13.
Production costs in U.S. dollars per equivalent barrel produced, including
natural gas volumes converted to equivalent barrels of crude oil on the
basis of approximate relative energy content, are shown on page 23 of the
1995 Annual Report, which is filed in this 10-K report as Exhibit 13.
3
PETROLEUM - EXPLORATION AND PRODUCTION (Contd.)
Supplemental disclosures about oil and gas producing activities are
reported on pages 42 through 47 of the 1995 Annual Report, which is filed
in this 10-K report as Exhibit 13.
At December 31, 1995, Murphy held leases, concessions, contracts, or
permits on nonproducing and producing acreage in the following countries
(thousands of acres).
Nonproducing Producing Total
-------------- ------------- ---------------
Country Gross Net Gross Net Gross Net
------- ----- --- ----- --- ----- ---
United States - Onshore 20 11 186 58 206 69
- Gulf of Mexico 614 360 415 152 1,029 512
- Frontier 127 89 - - 127 89
------ ------ ----- --- ------ ------
Total United States 761 460 601 210 1,362 670
------ ------ ----- --- ------ ------
Canada - Onshore 756 378 517 196 1,273 574
- Offshore 138 17 - - 138 17
- Oil sands 157 41 14 5 171 46
------ ------ ----- --- ------ ------
Total Canada 1,051 436 531 201 1,582 637
------ ------ ----- --- ------ ------
United Kingdom 715 164 81 13 796 177
Ecuador - - 494 99 494 99
Spain 28 5 61 11 89 16
China 563 254 - - 563 254
Ireland 650 162 - - 650 162
Pakistan 11,100 8,472 - - 11,100 8,472
Peru 3,112 3,112 - - 3,112 3,112
Tunisia 165 42 - - 165 42
------ ------ ----- --- ------ ------
Totals 18,145 13,107 1,768 534 19,913 13,641
====== ====== ===== === ====== ======
Oil and gas wells producing or capable of producing at December 31, 1995
are summarized as follows.
Oil Wells Gas Wells
-------------- --------------
Country Gross Net Gross Net
------- ----- ------- ------ ------
United States 1,278 528.4 408 141.6
Canada 4,084 734.0 765 231.0
United Kingdom 79 10.7 20 1.5
Ecuador 26 5.2 - -
Spain - - 1 .2
----- ------- ----- -----
Totals 5,467 1,278.3 1,194 374.3
===== ======= ===== =====
Wells included above with multiple
completions and counted as one well each 119 51.9 112 65.5
===== ======= ===== =====
Gross wells are those in which all or part of the working interest is owned
by Murphy. Net wells are the portions of the gross wells applicable to
Murphy's working interest.
4
PETROLEUM - EXPLORATION AND PRODUCTION (Contd.)
Murphy's net wells drilled in the last three years are summarized in the
following table.
United United
States Canada Kingdom Ecuador Other Totals
------------ ------------ ------------ -------------- ------------ -------------
Pro- Pro- Pro- Pro- Pro- Pro-
ductive Dry ductive Dry ductive Dry ductive Dry ductive Dry ductive Dry
------- --- ------- --- ------- --- ------- ----- ------- --- ------- ----
1995
----
Exploratory 4.6 1.9 6.0 4.3 .3 .1 - - - .5 10.9 6.8
Development 2.0 - 25.9 1.6 .8 - 2.8 - - - 31.5 1.6
1994
----
Exploratory 6.1 4.0 5.4 5.0 .5 .5 - - - - 12.0 9.5
Development .5 .1 29.8 1.5 .6 - 2.0 - - - 32.9 1.6
1993
----
Exploratory 7.4 6.5 3.9 4.2 .1 - - - - .5 11.4 11.2
Development 4.1 - 24.5 2.7 .7 .1 1.2 - - - 30.5 2.8
The wells being drilled by Murphy at December 31, 1995 are summarized as
follows.
Exploratory Development Totals
----------- -------------- --------------
Country Gross Net Gross Net Gross Net
------- ----- --- ----- --- ----- ---
United States 11 5.1 - - 11 5.1
Canada - - 1 .2 1 .2
United Kingdom 1 .3 3 .3 4 .6
Ecuador - - 1 .2 1 .2
--- --- -- --- --- ---
Totals 12 5.4 5 .7 17 6.1
=== === == === === ===
Additional information about current exploration and production activities
is reported on pages 4 through 12 of the 1995 Annual Report, which is filed
in this 10-K report as Exhibit 13.
PETROLEUM - REFINING, MARKETING, AND TRANSPORTATION
Murphy Oil USA, Inc. (Murphy USA), a wholly owned subsidiary, owns and
operates two refineries in the United States. The refinery at Superior,
Wisconsin, is located on fee land. The Meraux, Louisiana, refinery is
located on both fee and leased land; these leases expire at varying times
from 2010 to 2022, and at such times the Company has options to purchase
all leased acreage at fixed prices. Murco Petroleum Limited (Murco), a
wholly owned U.K. subsidiary serviced by Murphy Eastern Oil Company, has an
effective 30-percent interest in a 108,000-barrel-a-day refinery at Milford
Haven, Wales. Refinery capacities at December 31, 1995 are shown in the
following table.
5
PETROLEUM - REFINING, MARKETING, AND TRANSPORTATION (Contd.)
Milford Haven,
Meraux, Superior, Wales
Louisiana Wisconsin (Murco's 30%) Totals
-------------- --------- -------------- ---------
Crude capacity - b/sd* 100,000 35,000 32,400 167,400
Process capacities - b/sd*
Vacuum distillation 50,000 20,000 16,500 86,500
Catalytic cracking - fresh feed 40,000 11,000 9,960 60,960
Pretreating cat-reforming feeds 26,000 9,000 5,490 40,490
Catalytic reforming 18,500 8,000 5,490 31,990
Distillate hydrotreating 15,000 5,800 9,000 29,800
Gas oil hydrotreating 33,000 - - 33,000
Solvent deasphalting 18,000 - - 18,000
Isomerization - 2,000 2,250 4,250
Production capacities - b/sd*
Alkylation 9,500 1,600 1,680 12,780
Asphalt - 13,500 - 13,500
Crude oil and product storage
capacities - bbls. 4,453,000 2,852,000 2,638,000 9,943,000
*Barrels per stream day.
Murphy distributes refined products from 47 terminals in the United States
to retail and wholesale accounts in the United States (Murphy USA) and
Canada (MOCL) under the brand name SPUR and to unbranded wholesale
accounts. Four of these are marine terminals, two are supplied by truck,
two are adjacent to the refineries, and 39 are supplied by pipeline. Nine
terminals are wholly owned and operated by Murphy USA, 16 are jointly owned
and operated by others, and the remaining 22 are owned by others. Murphy
USA receives products at the terminals owned by others in exchange for
deliveries from the Company's wholly owned and jointly owned terminals. At
the end of 1995, refined products were marketed at wholesale and/or retail
through 514 branded outlets in 15 southeastern and upper midwestern states
and seven branded outlets in the Thunder Bay area of Ontario, Canada.
At the end of 1995, Murco distributed refined products in the United
Kingdom from the Milford Haven refinery; three wholly owned, rail-fed
terminals; eight terminals owned by others where products are received in
exchange for deliveries from the Company's wholly owned terminals; and 465
branded outlets under the brand names MURCO and EP.
Murphy owns a 20-percent interest in a 120-mile, 165,000-barrel-a-day
refined products pipeline that transports products from the Meraux refinery
to two common carrier pipelines serving Murphy's marketing area in the
southeastern United States. The Company also owns a 22-percent interest in
a 312-mile crude oil pipeline in Montana and Wyoming with a capacity of
120,000 barrels a day and a 3.2-percent interest in LOOP Inc., which
provides deep-water off-loading accommodations off the Louisiana coast for
oil tankers and onshore facilities for storage of crude oil. In addition,
Murphy owns 29.4 percent of a 22-mile, 300,000-barrel-a-day crude oil
pipeline between LOOP storage at Clovelly, Louisiana, and Alliance,
Louisiana, and 100 percent of a 24-mile, 200,000-barrel-a-day crude oil
pipeline from Alliance to the Meraux refinery. The pipeline from Alliance
to Meraux is also connected to another company's pipeline system, allowing
crude oil from wells serviced by that system to be shipped to the refinery.
As of December 31, 1995, MOCL had a 52.5-percent interest in a 114-mile
dual pipeline in Canada that transports heavy crude oil from Blackfoot,
Alberta, to Kerrobert, Saskatchewan, where access to a major crude oil
trunk line is available. In connection with this pipeline, which has a
throughput capacity of 50,000 barrels a day, MOCL owns interests in two
dual crude oil pipelines--100 percent of a two-mile, 2,500-barrel-a-day
lateral line at Winter, Saskatchewan, and 52.5 percent of a 4.5-mile,
5,000-barrel-a-day lateral line at Neilburg, Saskatchewan. MOCL also owns
13.1 percent of a 40-mile, 38,000-barrel-a-day dual heavy crude oil
pipeline from Cactus Lake, Saskatchewan, to Kerrobert; 41 percent of a
15-mile, 9,000-barrel-a-day dual crude oil pipeline from Bodo, Alberta, to
Cactus Lake; 100 percent of a 10.5-mile, 82,500-barrel-a-day dual crude oil
pipeline from
6
PETROLEUM - REFINING, MARKETING, AND TRANSPORTATION (Contd.)
Milk River, Alberta, to the U.S. border; 100 percent of a 108-mile, 45,000-
barrel-a-day crude oil pipeline from Regina, Saskatchewan, to the U.S.
border; and 100 percent of a 28-mile, 15,000-barrel-a-day heavy crude oil
pipeline from Eyehill, Saskatchewan, to Unity, Saskatchewan. MOCL is
operator of these pipelines.
Additional information about current refining, marketing, and
transportation activities and a statistical summary of key operating and
financial indicators for each of the five years ended December 31, 1995 are
reported on pages 13 through 17 and 49 of the 1995 Annual Report, which is
filed in this 10-K report as Exhibit 13.
FARM, TIMBER, AND REAL ESTATE
Deltic Farm & Timber Co. Inc. (Deltic), a wholly owned subsidiary, is
engaged in farming and timber and land management in Arkansas and North
Louisiana, lumber manufacturing and marketing in Arkansas, and real estate
development in Little Rock, Arkansas.
Deltic owns sawmills at Ola in central Arkansas and at Waldo in southern
Arkansas. The mills have a combined annual capacity to produce 165 million
board feet of lumber. The Ola mill is equipped for maximum utilization of
small stem timber, while the Waldo mill can process both small and large
diameter timber.
Deltic owned 341,000 acres of timberland at year-end 1995. Its estimated
standing timber inventories on this acreage are calculated for each tract
by utilizing growth formulas based on representative sample tracts and tree
counts for various diameter classifications. The calculations of pine
inventories are subject to periodic adjustments based on sample cruises or
actual volumes harvested from related tracts. The hardwood inventories
shown in the following table are only approximations, so physical
quantities of such timber may vary significantly from these approximations.
Estimated inventories of standing timber at year-end for each of the last
three years were as follows.
1995 1994 1993
--------- ------- -------
Pine sawtimber - MBF* 765,000 812,000 810,000
Hardwood sawtimber - MBF* 97,000 105,000 113,000
Pine pulpwood - cords 1,180,000 991,000 963,000
Hardwood pulpwood - cords 360,000 396,000 417,000
========= ======= =======
*Thousand board feet - Doyle scale.
At Deltic's farms, which comprise 36,000 acres in northeastern Louisiana
and southeastern Arkansas, the primary crops grown and harvested are
cotton, soybeans, corn, wheat, and rice. In western Little Rock, Arkansas,
Deltic has been developing Chenal Valley, a 4,300-acre planned community
centered around one of Arkansas's top-ranked golf courses, in stages over
recent years and has been selling real estate, primarily residential lots
thus far, in Chenal Valley.
Additional information about current farm, timber, and real estate
activities and a statistical summary of key operating and financial
indicators for each of the five years ended December 31, 1995 are reported
on pages 18, 19, and 50 of the 1995 Annual Report, which is filed in this
10-K report as Exhibit 13.
EMPLOYEES
Murphy had 1,794 full-time employees at December 31, 1995.
7
COMPETITION AND OTHER CONDITIONS WHICH MAY AFFECT BUSINESS
Murphy operates principally in the oil industry, in which it experiences
intense competition from other oil and gas companies, many of which have
substantially greater resources. In addition, the oil industry as a whole
competes with other industries in supplying energy requirements around the
world. Murphy is a net purchaser of crude oil and other refinery
feedstocks and occasionally purchases refined products and may therefore be
required to respond to operating and pricing policies of others, including
producing country governments from whom it makes purchases. Additional
information concerning current conditions of the Company's business is
reported under the caption "Outlook" on page 27 of the 1995 Annual Report,
which is filed in this 10-K report as Exhibit 13.
The operations and earnings of Murphy have been and continue to be affected
by worldwide political developments. Many governments, including those
that are members of the Organization of Petroleum Exporting Countries
(OPEC), unilaterally intervene at times in the orderly market of crude oil
and natural gas produced in their countries through such actions as fixing
prices and determining rates of production and who may sell and buy the
production. Until 1993, the United States also regulated prices for
certain natural gas production. In addition, prices and availability of
crude oil, natural gas, and refined products could be influenced by
political unrest and by various governmental policies to restrict or
increase petroleum usage and supply. Other governmental actions that could
affect Murphy's operations and earnings include tax changes and regulations
concerning: currency fluctuations, protection and/or remediation of the
environment (See the caption "Environmental" on page 26 of the 1995 Annual
Report, which is filed in this 10-K report as Exhibit 13.), preferential
and discriminatory awarding of oil and gas leases, restraints and controls
on imports and exports, safety, and relationships between employers and
employees. Because these and other government-influenced factors too
numerous to list are subject to constant changes dictated by political
considerations and are often made in great haste in response to changing
internal and worldwide economic conditions and to actions of other
governments or specific events, it is not practical to attempt to predict
the effects of such factors on Murphy's future operations and earnings.
Murphy's policy is to insure against known risks when insurance is
available at costs and terms Murphy considers reasonable. Certain existing
risks are insured by Murphy only through Oil Insurance Limited (OIL), which
is operated as a mutual insurance company by certain participating oil
companies including Murphy and was organized to insure against risks for
which commercial insurance is unavailable or for which the cost of
commercial insurance is prohibitive.
EXECUTIVE OFFICERS OF THE REGISTRANT
The age (at January 1, 1996), present corporate office, and length of
service in office of each of the Company's executive officers and persons
chosen to become officers are reported in the following listing. Executive
officers are elected annually but may be removed from office at any time by
the Board of Directors.
R. Madison Murphy - Age 38; Chairman of the Board since October 1994. Mr.
Murphy had been Executive Vice President and Chief Financial and
Administrative Officer, Director, and Member of the Executive Committee
since 1993. Prior to that, he was Executive Vice President and Chief
Financial Officer from 1992 to 1993; Vice President, Planning/Treasury,
from 1991 to 1992; and Vice President, Planning, from 1988 to 1991, with
additional duties as Treasurer from 1990 until August 1991.
Claiborne P. Deming - Age 41; President and Chief Executive Officer since
October 1994 and Director and Member of the Executive Committee since
1993. In 1992, he became Executive Vice President and Chief Operating
Officer. Mr. Deming was President of Murphy USA from 1989 to 1992 and
Vice President, Petroleum Operations, for Murphy from 1988 to 1989.
Steven A. Cosse - Age 48; Senior Vice President since October 1994 and
General Counsel since August 1991. Mr. Cosse was elected Vice President
in 1993. For the eight years prior to August 1991, he was General
Counsel for Murphy Expro, at that time named Ocean Drilling &
Exploration Company (ODECO), a majority-owned subsidiary of Murphy.
8
EXECUTIVE OFFICERS OF THE REGISTRANT (Contd.)
Herbert A. Fox Jr. - Age 61; Vice President since October 1994. Mr. Fox
has also been President of Murphy USA since 1992. He served with Murphy
USA as Vice President, Manufacturing, from 1990 to 1992 and as Manager
of Crude Supply from 1973 to 1990.
Bill H. Stobaugh - Age 44; Vice President since May 1995, when he joined
the Company. Prior to that, he had held various engineering, planning,
and managerial positions, the most recent being with an engineering
consulting firm.
Clefton D. Vaughan - Age 54; Vice President since October 1994. He has
also been Vice President of Murphy Expro since 1992. Mr. Vaughan was
Vice President of Murphy from 1989 to 1992 and held various other
positions with the Company prior to that.
Odie F. Vaughan - Age 59; Treasurer since August 1991. From 1975 through
July 1991, he was with ODECO as Vice President of Taxes and Treasurer.
Ronald W. Herman - Age 58; Controller since August 1991. He was
Controller of ODECO from 1977 through July 1991.
W. Bayless Rowe - Age 43; Secretary since 1988 and Manager of Law
Department since October 1994. He was General Attorney from 1988 to
October 1994.
ITEM 3. LEGAL PROCEEDINGS.
Information related to legal proceedings contained in Note P, page 40 of
the 1995 Annual Report, which is filed in this 10-K report as Exhibit 13,
is incorporated herein. Also, Murphy Oil USA, Inc., in connection with its
ownership and operation of two oil refineries in the United States, is a
defendant in two governmental actions that: (1) seek monetary sanctions of
$100,000 or more, and (2) arise under enacted provisions that regulate the
discharge of materials into the environment or have the purpose of
protecting the environment. These actions individually or in the aggregate
are not material to the financial condition of the Company. In addition,
Murphy and its subsidiaries are engaged in a number of other legal
proceedings, all of which Murphy considers routine and incidental to its
business and none of which is material as defined by the rules and
regulations of the U.S. Securities and Exchange Commission.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to a vote of security holders during the fourth
quarter of 1995.
9
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
The Company's Common Stock is traded on the New York Stock Exchange and the
Toronto Stock Exchange. Other information required by this item is
reported on page 28 of the 1995 Annual Report, which is filed in this 10-K
report as Exhibit 13.
ITEM 6. SELECTED FINANCIAL DATA.
Information required by this item appears on page 20 of the 1995 Annual
Report, which is filed in this 10-K report as Exhibit 13.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATION.
Information required by this item appears on pages 21 through 28 of the
1995 Annual Report, which is filed in this 10-K report as Exhibit 13.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Information required by this item appears on pages 28 through 47 of the
1995 Annual Report, which is filed in this 10-K report as Exhibit 13.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Certain information regarding executive officers of the Company is included
in Part I, pages 8 and 9, of this 10-K report. Other information required
by this item is incorporated by reference to the Registrant's definitive
proxy statement for the annual meeting of stockholders on May 8, 1996,
under the caption "Election of Directors."
ITEM 11. EXECUTIVE COMPENSATION.
Information required by this item is incorporated by reference to the
Registrant's definitive proxy statement for the annual meeting of
stockholders on May 8, 1996, under the captions "Compensation of
Directors," "Executive Compensation," "Option Exercises and Fiscal Year-End
Values," "Option Grants," "Compensation Committee Report for 1995,"
"Shareholder Return Performance Presentation," and "Retirement Plans."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information required by this item is incorporated by reference to the
Registrant's definitive proxy statement for the annual meeting of
stockholders on May 8, 1996, under the caption "Certain Stock Ownerships."
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information required by this item is incorporated by reference to the
Registrant's definitive proxy statement for the annual meeting of
stockholders on May 8, 1996, under the caption "Compensation Committee
Interlocks and Insider Participation."
10
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) 1. FINANCIAL STATEMENTS
The following consolidated financial statements of Murphy Oil Corporation
and consolidated subsidiaries are included on the pages indicated of
Exhibit 13 to this 10-K report.
Exhibit 13
Page Nos.
---------
Independent Auditors' Report 29
Consolidated Statements of Income 30
Consolidated Balance Sheets 31
Consolidated Statements of Cash Flows 32
Consolidated Statements of Stockholders' Equity 33
Notes to Consolidated Financial Statements 34 through 41
(a) 2. FINANCIAL STATEMENT SCHEDULES
Financial statement schedules are omitted because either they are not
applicable or the required information is included in the consolidated
financial statements or notes thereto.
(a) 3. EXHIBITS
The Exhibit Index on page 13 of this 10-K report lists the exhibits that
are hereby filed.
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the quarter ended December 31,
1995.
11
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
MURPHY OIL CORPORATION
By CLAIBORNE P. DEMING Date: March 26, 1996
---------------------------------- ----------------------
Claiborne P. Deming, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below on March 26, 1996 by the following persons on behalf of
the registrant and in the capacities indicated.
R. MADISON MURPHY MICHAEL W. MURPHY
---------------------------------- ------------------------------
R. Madison Murphy, Chairman Michael W. Murphy, Director
and Director
CLAIBORNE P. DEMING WILLIAM C. NOLAN JR.
---------------------------------- ------------------------------
Claiborne P. Deming, President and William C. Nolan Jr.,
Chief Executive Officer Director
and Director
(Principal Executive Officer)
B. R. R. BUTLER CAROLINE G. THEUS
---------------------------------- ------------------------------
B. R. R. Butler, Director Caroline G. Theus, Director
GEORGE S. DEMBROSKI LORNE C. WEBSTER
---------------------------------- ------------------------------
George S. Dembroski, Director Lorne C. Webster, Director
H. RODES HART STEVEN A. COSSE
---------------------------------- ------------------------------
H. Rodes Hart, Director Steven A. Cosse, Senior
Vice President and
General Counsel
(Principal Financial Officer)
VESTER T. HUGHES JR. RONALD W. HERMAN
---------------------------------- ------------------------------
Vester T. Hughes Jr., Director Ronald W. Herman, Controller
(Principal Accounting Officer)
C. H. MURPHY JR.
----------------------------------
C. H. Murphy Jr., Director
12
EXHIBIT INDEX
Exhibit Page Number or
No. Incorporation by Reference to
- ------- ------------------------------------------------------------------
3.1 Certificate of Incorporation of Murphy Oil Exhibit 3.1, Page Ex. 3.1-0, of Murphy's Annual Report on Form
Corporation as of September 25, 1986 10-K for the year ended December 31, 1991
3.2 Bylaws of Murphy Oil Corporation at February 1, 1995 Exhibit 3.3, Page Ex. 3.3-1, of Murphy's Annual Report on Form
10-K for the year ended December 31, 1994
3.3 Bylaws of Murphy Oil Corporation at October 4, 1995 Page Ex. 3.3-1
4 Instruments Defining the Rights of Security Holders.
Murphy Oil Corporation is party to several long-term
debt instruments, none of which authorizes securities
that exceed 10 percent of the total assets of Murphy
Oil Corporation and its subsidiaries on a consolidated
basis. Pursuant to Regulation S-K, item 601(b),
paragraph 4(iii)(A), Murphy agrees to furnish a copy
of each such instrument to the Securities and Exchange
Commission upon request.
4.1 Rights Agreement dated as of December 6, 1989 between Exhibit 4.1, Page Ex. 4.1-0, of Murphy's Annual Report on
Murphy Oil Corporation and Harris Trust Company of New Form 10-K for the year ended December 31, 1994
York, as Rights Agent
10.1 1982 Management Incentive Plan Exhibit 10.2, Page Ex. 10.2-0, of Murphy's Annual Report on
Form 10-K for the year ended December 31, 1991
10.2 1987 Management Incentive Plan (adopted May 13, 1987, Exhibit 10.2, Page Ex. 10.2-0, of Murphy's Annual Report
amended February 7, 1990 retroactive to February 3, on Form 10-K for the year ended December 31, 1994
1988)
10.3 1992 Stock Incentive Plan Exhibit 10.3, Page Ex. 10.3-0, of Murphy's Annual Report
on Form 10-K for the year ended December 31, 1992
13 1995 Annual Report to Security Holders Page Ex. 13-0, report pp. 4 through 50
Appendix - Narrative to Graphic and Image Material (Page A-1 for electronic filing only)
21 Subsidiaries of the Registrant Page Ex. 21-1
23 Independent Auditors' Consent Page Ex. 23-1
27.1 Financial Data Schedule for 1995 (Electronic filing only)
27.2 Restated Financial Data Schedule for 1994 (Electronic filing only)
99.1 Undertakings Page Ex. 99.1-1
99.2 Form 11-K, Annual Report for the fiscal year ended To be filed as an amendent of this Annual Report on Form
December 31, 1995 covering Combined Thrift Plans for 10-K not later than 180 days after December 31, 1995
Employees of Murphy Oil Corporation, Murphy Oil USA,
Inc., and Deltic Farm & Timber Co., Inc.
Exhibits other than those listed above have been omitted since they either are
not required or are not applicable.
13
EXHIBIT 3.3
BYLAWS (AS AMENDED OCTOBER 4, 1995)
OF
MURPHY OIL CORPORATION
(A Delaware corporation)
ARTICLE I.
Offices.
Section 1. Offices. Murphy Oil Corporation (hereinafter called the
Company) may have, in addition to its principal office in Delaware, a principal
or other office or offices at such place or places, either within or without the
State of Delaware, as the board of directors may from time to time determine or
as shall be necessary or appropriate for the conduct of the business of the
Company.
ARTICLE II.
Meetings of Stockholders.
Section 1. Place of Meetings. The annual meeting of the stockholders
shall be held at the place therein determined by the board of directors and
stated in the notice thereof, and other meetings of the stockholders may be held
at such place or places, within or without the State of Delaware, as shall be
fixed by the board of directors and stated in the notice thereof.
Section 2. Annual Meetings. The annual meeting of stockholders for the
election of directors and the transaction of such other business as may come
before the meeting shall be held in each year on the second Wednesday in May.
If this date shall fall upon a legal holiday, the meeting shall be held on the
next succeeding business day. At each annual meeting the stockholders entitled
to vote shall elect a board of directors and they may transact such other
corporate business as shall be stated in the notice of the meeting.
Section 3. Special Meetings. Special meetings of the stockholders for any
purpose or purposes may be called by the Chairman of the Board or by order of
the board of directors and shall be called by the Chairman of the Board or the
Secretary upon the written request of stockholders holding of record at least a
majority of the outstanding shares of stock of the Company entitled to vote at
such meeting. Such written request shall state the purpose or purposes for
which such meeting is to be called.
Section 4. Notice of Meetings. Except as otherwise expressly required by
law, notice of each meeting of stockholders, whether annual or special, shall be
given at least 10 days before the date on which the meeting is to be held to
each stockholder of record entitled to
Ex. 3.3-1
vote thereat by delivering a notice thereof to him personally, or by mailing
such notice in a postage prepaid envelope directed to him at his address as it
appears on the books of the Company, unless he shall have filed with the
Secretary of the Company a written request that notices intended for him be
directed to another address, in which case such notice shall be directed to him
at the address designated in such request. Notice of any meeting of
stockholders shall not be required to be given to any stockholder who shall
attend such meeting in person or by proxy; and if any stockholder shall in
person or by attorney thereunto authorized, in writing or by telegraph, cable,
radio or wireless and confirmed in writing, waive notice of any meeting of the
stockholders, whether prior to or after such meeting, notice thereof need not be
given to him. Notice of any adjourned meeting of the stockholders shall not be
required to be given except where expressly required by law.
Section 5. Quorum. At each meeting of the stockholders the holders of
record of a majority of the issued and outstanding stock of the Company entitled
to vote at such meeting, present in person or by proxy, shall constitute a
quorum for the transaction of business except where otherwise provided by law,
the certificate of incorporation or these bylaws. In the absence of a quorum,
any officer entitled to preside at or act as secretary of such meeting shall
have the power to adjourn the meeting from time to time until a quorum shall be
constituted. At any such adjourned meeting at which a quorum shall be present
any business may be transacted which might have been transacted at the meeting
as originally called.
Section 6. Voting. At every meeting of stockholders each holder of record
of the issued and outstanding stock of the Company entitled to vote at such
meeting shall be entitled to one vote in person or by proxy, but no proxy shall
be voted after three years from its date unless the proxy provides for a longer
period, and, except where the transfer books of the Company have been closed or
a date has been fixed as the record date for the determination of stockholders
entitled to vote, no share of stock shall be voted directly or indirectly. At
all meetings of the stockholders, a quorum being present, all matters shall be
decided by majority vote of those present in person or by proxy, except as
otherwise required by the laws of the State of Delaware or the certificate of
incorporation. The vote thereat on any question need not be by ballot unless
required by the laws of the State of Delaware.
ARTICLE III.
Board of Directors.
Section 1. General Powers. The property, business and affairs of the
Company shall be managed by the board of directors.
Section 2. Number and Term of Office. The number of directors shall be
eleven, but may from time to time be increased or diminished to not less than
three by amendment of these bylaws. Directors need not be stockholders. Each
director shall hold office until the annual meeting of the stockholders next
following his election and until his successor shall have been elected and shall
qualify, or until his death, resignation or removal.
Section 3. Quorum and Manner of Acting. Unless otherwise provided by law
the presence of six members of the board of directors shall be necessary to
constitute a quorum
Ex. 3.3-2
for the transaction of business. In the absence of a quorum, a majority of the
directors present may adjourn the meeting from time to time until a quorum shall
be present. Notice of any adjourned meeting need not be given. At all meetings
of directors, a quorum being present, all matters shall be decided by the
affirmative vote of a majority of the directors present, except as otherwise
required by the laws of the State of Delaware.
Section 4. Place of Meetings, etc. The board of directors may hold its
meetings and keep the books and records of the Company at such place or places
within or without the State of Delaware as the board may from time to time
determine.
Section 5. Annual Meeting. Promptly after each annual meeting of
stockholders for the election of directors and on the same day the board of
directors shall meet for the purpose of organization, the election of officers
and the transaction of other business. Notice of such meeting need not be
given. Such meeting may be held at any other time or place as shall be
specified in a notice given as hereinafter provided for special meetings of the
board of directors or in a consent and waiver of notice thereof signed by all
the directors.
Section 6. Regular Meetings. Regular meetings of the board of directors
may be held at such time and place, within or without the State of Delaware, as
shall from time to time be determined by the board of directors. After there
has been such determination and notice thereof has been once given to each
member of the board of directors, regular meetings may be held without further
notice being given.
Section 7. Special Meetings; Notice. Special meetings of the board of
directors shall be held whenever called by the Chairman of the Board or by a
majority of the directors. Notice of each such meeting shall be mailed to each
director, addressed to him at his residence or usual place of business, at least
10 days before the day on which the meeting is to be held, or shall be sent to
him at such place by telegraph, cable, radio or wireless, or be delivered
personally or by telephone, not later than the day before the day on which such
meeting is to be held. Each such notice shall state the time and place of the
meeting but need not state the purposes thereof. Notice of any meeting of the
board of directors need not be given to any director, however, if waived by him
in writing or by telegraph, cable, radio or wireless and confirmed in writing,
whether before or after such meeting, or if he shall be present at such meeting.
Any meeting of the board of directors shall be a legal meeting without any
notice thereof having been given if all the directors then in office shall be
present thereat.
Section 8. Resignation. Any director of the Company may resign at any
time by giving written notice to the Chairman of the Board or the Secretary of
the Company. The resignation of any director shall take effect upon receipt of
notice thereof or at such later time as shall be specified in such notice; and,
unless otherwise specified therein, the acceptance of such resignation shall not
be necessary to make it effective.
Section 9. Removal. Any director may be removed at any time, either with
or without cause, by the affirmative vote of the holders of record of a majority
of the issued and outstanding class of stock of the Company entitled to vote for
the election of such director, given at a special meeting of the stockholders
called for that purpose. The vacancy in the board of directors caused by any
such removal may be filled by the stockholders at such meeting.
Ex. 3.3-3
Section 10. Vacancies. Any vacancy that shall occur in the board of
directors by reason of death, resignation, disqualification or removal or any
other cause whatever, unless filled as provided in Section 9 hereof, shall be
filled by the majority (even if that be only a single director) of the remaining
directors theretofore elected by the holders of the class of capital stock which
elected the directors whose office shall have become vacant. If any new
directorship is created by increase in the number of directors, a majority of
the directors then in office may fill such new directorship. The term of office
of any director so chosen to fill a vacancy or a new directorship shall
terminate upon the election and qualification of directors at any meeting of
stockholders called for the purpose of electing directors.
Section 11. Compensation of Directors. Directors may receive a fee, as
fixed by the Chairman of the Board, for their services, together with expenses
for attendance at regular or special meeting of the board. Members of
committees of the board of directors may be allowed compensation for attending
committee meetings. Nothing herein contained shall be construed to preclude any
director from serving the Company or any subsidiary thereof in any other
capacity and receiving compensation therefor.
ARTICLE IV.
Committees of the Board.
Section 1. Executive Committee. The board of directors shall elect from
the directors an executive committee.
The board of directors shall fill vacancies in the executive committee by
election from the directors.
Ex. 3.3-4
The executive committee shall fix its own rules of procedure and shall meet
where and as provided by such rules or by resolution of the board of directors,
but in every case the presence of at least three members of the committee shall
be necessary to constitute a quorum for the transaction of business.
In every case the affirmative vote of a majority of all of the members of
the committee present at the meeting shall be necessary for the adoption of any
resolution.
Section 2. Membership and Powers. The executive committee shall consist
of five members in addition to the Chairman of the Board, who by virtue of his
office shall be a member of the executive committee and chairman thereof.
Unless otherwise ordered by the board of directors, each elected member of the
executive committee shall continue to be a member thereof until the expiration
of his term of office as a director.
The executive committee, subject to any limitations prescribed by the board
of directors, shall have special charge of all financial accounting, legal and
general administrative affairs of the Company. During the intervals between the
meetings of the board of directors the executive committee shall have all the
powers of the board in the management of the business and affairs of the
Company, including the power to authorize the seal of the Company to be affixed
to all papers which require it, except that said committee shall not have the
power of the board (i) to fill vacancies in the board, (ii) to amend the bylaws,
(iii) to adopt a plan of merger or consolidation, (iv) to recommend to the
stockholders the sale, lease, exchange, mortgage, pledge or other disposition of
all or substantially all of the property and assets of the Company otherwise
than in the usual and regular course of its business, or (v) to recommend to the
stockholders a voluntary dissolution of the Company or a revocation thereof.
Section 3. Other Committees. The board of directors may, by resolution or
resolutions passed by a majority of the whole board, designate one or more other
committees, each committee to consist of two or more of the directors of the
Company, which, to the extent provided in said resolution or resolutions, shall
have and may exercise the powers of the board of directors in the management of
the business and affairs of the Company, and may have power to authorize the
seal of the Company to be affixed to all papers which may require it. Such
committee or committees shall have such name or names as may be determined from
time to time by resolution adopted by the board of directors.
ARTICLE V.
Officers.
Section 1. Number. The principal officers of the Company shall be a
Chairman of the Board, President, one or more Vice Presidents (which may be
designated as Executive or Senior Vice President(s)), a Secretary, a Treasurer,
and a Controller. No officers except the Chairman of the Board and President
need be directors. One person may hold the offices and perform the duties of
any two or more of said offices.
Section 2. Election and Term of Office. The principal officers of the
Company shall
Ex. 3.3-5
be chosen annually by the board of directors at the annual meeting thereof.
Each such officer shall hold office until his successor shall have been chosen
and shall qualify, or until his death or until he shall resign or shall have
been removed in the manner hereinafter provided.
Section 3. Subordinate Officers. In addition to the principal officers
enumerated in Section 1 of this Article V, the Company may have one or more
Assistant Vice Presidents, one or more Assistant Treasurers, one or more
Assistant Secretaries and such other officers, agents and employees as the board
of directors may deem necessary, each of whom shall hold office for such period,
have such authority, and perform such duties as the board or the President may
from time to time determine. The board of directors may delegate to any
principal officer the power to appoint and to remove any such subordinate
officers, agents or employees.
Section 4. Compensation of Principal Officers. The salaries of the
principal officers shall be fixed from time to time either by the board of
directors or by a committee of the board to which such power may be delegated.
The salaries of any other officers shall be fixed by the President or by a
committee or committees to which he may delegate such power.
Section 5. Removal. Any officer may be removed, either with or without
cause, at any time, by resolution adopted by the board of directors at any
regular meeting of the board or at any special meeting of the board called for
the purpose at which a quorum is present.
Section 6. Vacancies. A vacancy in any office may be filled for the
unexpired portion of the term in the manner prescribed in these bylaws for
election or appointment to such office for such term.
Section 7. Chairman of the Board. The Chairman of the Board shall preside
at all meetings of the stockholders and directors at which he may be present.
He shall have such other authority and responsibility and perform such other
duties as may be determined by the board of directors.
Section 8. President. The President shall be the chief executive officer
of the Company and as such shall have general supervision and management of the
affairs of the Company subject to the control of the board of directors. He may
enter into any contract or execute any deeds, mortgages, bonds, contracts or
other instruments in the name and on behalf of the Company except in cases in
which the authority to enter into such contract or execute and deliver such
instrument, as the case may be, shall be otherwise expressly delegated. In
general he shall perform all duties incident to the office of President as
herein defined and all such other duties as from time to time may be assigned to
him by the board of directors. In the absence of the Chairman of the Board, the
President shall preside at meetings of the stockholders and directors.
Section 9. Vice Presidents. The Vice Presidents, in order of their
seniority unless otherwise determined by the board of directors, shall in the
absence or disability of the President perform the duties and exercise the
powers of such offices. The Vice Presidents shall perform such other duties and
have such other powers as the President or the board of directors may from time
to time prescribe.
Ex. 3.3-6
Section 10. Secretary. The Secretary shall attend all sessions of the
board and all meetings of the stockholders, and record all votes and the minutes
of all proceedings in a book to be kept for that purpose, and shall perform like
duties for the committees of the board of directors when required. He shall
give or cause to be given, notice of all meetings of the stockholders and of
special meetings of the board of directors, and shall perform such other duties
as may be prescribed by the board of directors, or the President, under whose
supervision he shall be. He shall keep in safe custody the seal of the Company
and, when authorized by the board of directors, affix the same to any instrument
requiring it, and when so affixed it shall be attested by his signature or by
the signature of the Treasurer or an Assistant Secretary.
Section 11. Treasurer. The Treasurer shall have custody of the corporate
funds and securities and shall keep full and accurate accounts of receipts and
disbursements in the books belonging to the Company, and shall deposit all
moneys and other valuable effects in the name and to the credit of the Company
in such depositories as may be designated from time to time by the Board of
Directors.
He shall disburse the funds of the Company as may be ordered by the board,
taking proper vouchers for such disbursements, and shall render to the President
and board of directors at the regular meetings of the board, or whenever they
may require it, an account of the financial condition of the Company.
If required by the board of directors, he shall give the Company a bond, in
such sum and with such surety or sureties as shall be satisfactory to the board,
for the faithful performance of the duties of his office, and for the
restoration to the Company, in case of his death, resignation, retirement or
removal from office, of all books, papers, vouchers, money and other property of
whatever kind in his possession or under his control belonging to the Company.
Section 12. Controller. The Controller shall be in charge of the accounts
of the Company and shall perform such duties as from time to time may be
assigned to him by the President or by the board of directors.
Ex. 3.3-7
ARTICLE VI.
Shares and Their Transfer.
Section 1. Certificates for Stock. Certificates for shares of capital
stock of the Company shall be numbered, and shall be entered in the books of the
Company, in the order in which they are issued.
Section 2. Regulations. The board of directors may make such rules and
regulations as it may deem expedient, not inconsistent with the certificate of
incorporation or these bylaws, concerning the issue, transfer and registration
of certificates for shares of capital stock of the Company. It may appoint, or
authorize any principal officer or officers to appoint, one or more transfer
clerks or one or more transfer agents and one or more registrars, and may
require all such certificates to bear the signature or signatures of any of
them.
Section 3. Stock Certificate Signature. The certificates for shares of
the respective classes of such stock shall be signed by, or in the name of the
Company by, the Chairman of the Board, the President or any Vice President and
the Treasurer or an Assistant Treasurer, or the Secretary or an Assistant
Secretary, and where signed (a) by a transfer agent or an assistant transfer
agent or (b) by a transfer clerk acting on behalf of the Company and a
registrar, the signature of any such Chairman of the Board, President, Vice
President, Treasurer, Assistant Treasurer, Secretary or Assistant Secretary may
be facsimile. Each such certificate shall exhibit the name of the holder
thereof and number of shares represented thereby and shall not be valid until
countersigned by a transfer agent.
The board of directors may, if it so determines, direct that certificates
for shares of any class or classes of capital stock of the Company be registered
by a registrar, in which case such certificates will not be valid until so
registered.
In case any officer of the Company who shall have signed, or whose
facsimile signature shall have been used on, any certificate for shares of
capital stock of the Company shall cease to be such officer, whether because of
death, resignation or otherwise, before such certificate shall have been
delivered by the Company, such certificate shall nevertheless be deemed to have
been adopted by the Company and may be issued and delivered as though the person
who signed such certificate or whose facsimile signature shall have been used
thereon had not ceased to be such officer.
Section 4. Designations, Preferences, etc. on Certificates for Stock.
Certificates for shares of capital stock of the Company shall state on the face
or back thereof that the Company will furnish without charge to each stockholder
who so requests (which request may be addressed to the Secretary of the Company
or to a transfer agent) a statement of the designations, preferences and
relative, participating, optional or other special rights of each class of stock
or series thereof which the Company is authorized to issue and the
qualifications, limitations or restrictions of such preferences and/or rights.
Section 5. Stock Ledger. A record shall be kept by the Secretary or by
any other officer, employee or agent designated by the board of directors of the
name of the person, firm, or corporation holding the stock represented by such
certificates, the number of shares
Ex. 3.3-8
represented by such certificates, respectively, and the respective dates
thereof, and in case of cancellation the respective dates of cancellation.
Section 6. Cancellation. Every certificate surrendered to the Company for
exchange or transfer shall be canceled, and no new certificate or certificates
shall be issued in exchange for any existing certificate until such existing
certificate shall have been so canceled.
Section 7. Transfers of Stock. Transfers of shares of the capital stock
of the Company shall be made only on the books of the Company by the registered
holder thereof or by his attorney thereunto authorized on surrender of the
certificate or certificates for such shares properly endorsed and the payment of
all taxes thereon. The person in whose name shares of stock stand on the books
of the Company shall be deemed the owner thereof for all purposes as regards the
Company; provided, however, that whenever any transfer of shares shall be made
for collateral security, and not absolutely, such fact, if known to the
Secretary or the transfer agent making such transfer, shall be so expressed in
the entry of transfer.
Section 8. Closing of Transfer Books. The board of directors may by
resolution direct that the stock transfer books of the Company be closed for a
period not exceeding 60 days preceding the date of any meeting of the
stockholders, or the date for the payment of any dividend, or the date for the
allotment of any rights, or the date when any change or conversion or exchange
of capital stock of the company shall go into effect, or for a period not
exceeding 60 days in connection with obtaining the consent of stockholders for
any purpose. In lieu of such closing of the stock transfer books, the board may
fix in advance a date, not exceeding 60 days preceding the date of any meeting
of stockholders, or the date for the payment of any dividend, or the date for
the allotment of rights, or the date when any change or conversion or exchange
of capital stock shall go into effect or a date in connection with obtaining
such consent, as a record date for the determination of the stockholders
entitled to notice of, and to vote at, such meeting, and any adjournment
thereof, or to receive payment of any such dividend, or to receive any such
allotment of rights, or to exercise the rights in respect of any such change,
conversion, or exchange of capital stock or to give such consent, as the case
may be, notwithstanding any transfer of any stock on the books of the Company
after any record date so fixed.
ARTICLE VII.
Miscellaneous Provisions.
Section 1. Corporate Seal. The board of directors shall provide a
corporate seal which shall be in the form of a circle and shall bear the name of
the Company and words and figures showing that it was incorporated in the State
of Delaware in the year 1964. The Secretary shall be the custodian of the seal.
The board of directors may authorize a duplicate seal to be kept and used by any
other officer.
Section 2. Fiscal Year. The fiscal year of the Company shall be fixed by
resolution of the board of directors.
Section 3. Voting of Stocks Owned by the Company. The board of directors
may authorize any person in behalf of the Company to attend, vote and grant
proxies to be used at
Ex. 3.3-9
any meeting of stockholders of any corporation in which the Company may hold
stock.
Section 4. Dividends. Subject to the provisions of the certificate of
incorporation, the board of directors may, out of funds legally available
therefor, at any regular or special meeting declare dividends upon the capital
stock of the Company as and when they deem expedient. Dividends may be paid in
cash, in property, or in shares of capital stock of the Company, subject to the
provisions of the certificate of incorporation. Before declaring any dividend
there may be set apart out of any funds of the Company available for dividends
such sum or sums as the directors from time to time in their discretion deem
proper for working capital or as a reserve fund to meet contingencies or for
equalizing dividends or for such other purposes as the directors shall deem
conducive to the interests of the Company.
ARTICLE VIII.
Indemnification of Officers, Directors,
Employees and Agents; Insurance.
Section 1. Indemnification.
(a) The Company may indemnify any person who was or is a party or is
threatened to be made a party to any threatened, pending or completed action,
suit or proceeding, whether civil, criminal, administrative or investigative
(including an action by or in the right of the Company) by reason of the fact
that he is or was a director, officer, employee or agent of the Company, or is
or was serving at the request of the Company as a director, officer, employee or
agent of another corporation, partnership, joint venture, trust or other
enterprise, against expenses (including attorneys' fees) and, except for an
action by or in the right of the Company, judgments, fines and amounts paid in
settlement, actually and reasonably incurred by him in connection with such
action, suit or proceeding, if he acted in good faith and in a manner he
reasonably believed to be in or not opposed to the best interests of the
Company, and, with respect to any criminal action or proceeding, had no
reasonable cause to believe his conduct was unlawful. Except for an action by
or in the right of the Company, the termination of any action, suit or
proceeding by judgment, order, settlement, conviction, or upon a plea of nolo
contendere or its equivalent, shall not, of itself, create a presumption that
the person did not act in good faith and in a manner which he reasonably
believed to be in or not opposed to the best interests of the Company, and, with
respect to any criminal action or proceeding, had reasonable cause to believe
that his conduct was unlawful. With respect to an action by or in the right of
the Company, no indemnification shall be made in respect of any claim, issue or
matter as to which such person shall have been adjudged to be liable for
negligence or misconduct in the performance of his duty to the Company unless
and only to the extent that the Delaware Court of Chancery or the court in which
such action or suit was brought shall determine upon application that, despite
the adjudication of liability but in view of all the circumstances of the case,
such person is fairly and reasonably entitled to indemnity for such expenses
which such court shall deem proper.
(b) To the extent that a director, officer, employee or agent of the
Company has been successful on the merits or otherwise in defense of any action,
suit or proceeding referred to
Ex. 3.3-10
in subsection (a) or in defense of any claim, issue or matter therein, he shall
be indemnified against expenses (including attorneys' fees) actually and
reasonably incurred by him in connection therewith.
(c) Any indemnification under subsection (a) (unless ordered by a court)
shall be made by the Company only as authorized in the specific case upon a
determination that indemnification of the director, officer, employee or agent
is proper in the circumstances because he has met the applicable standard of
conduct set forth in subsection (a). Such determination shall be made (i) by
the board of directors by a majority vote of a quorum consisting of directors
who were not parties to such action, suit or proceeding, or (ii) if such a
quorum is not obtainable, or, even if obtainable a quorum of disinterested
directors so directs, by independent legal counsel in a written opinion, or
(iii) by the stockholders.
(d) Expenses incurred in defending a civil or criminal action, suit or
proceeding may be paid by the Company in advance of the final disposition of
such action, suit or proceeding as authorized by the board of directors in the
manner provided in subsection (c) upon receipt of an undertaking by or on behalf
of the director, officer, employee or agent to repay such amount unless it shall
ultimately be determined that he is entitled to be indemnified by the Company as
authorized in this section.
(e) The indemnification provided by this Article shall not be deemed
exclusive of any other rights to which those seeking indemnification may be
entitled under any agreement, vote of stockholders or disinterested directors or
otherwise, both as to action in their official capacities and as to action in
other capacities while holding such offices, and shall continue as to a person
who has ceased to be a director, officer, employee or agent and shall inure to
the benefit of the heirs, executors and administrators of such a person.
Section 2. Insurance. The Company may purchase and maintain insurance on
behalf of any person who is or was a director, officer, employee or agent of the
Company, or is or was serving at the request of the Company as a director,
officer, employee or agent of another corporation, partnership, joint venture,
trust or other enterprise against any liability asserted against him and
incurred by him in any such capacity, or arising out of his status as such,
whether or not the Company would have the power to indemnify him against such
liability under the provisions of either the General Corporation Law of the
State of Delaware or of these bylaws.
ARTICLE IX.
Amendments.
The bylaws of the Company may be altered, amended or repealed either by the
affirmative vote of a majority of the stock issued and outstanding and entitled
to vote in respect thereof and represented in person or by proxy at any annual
or special meeting of the stockholders, or by the affirmative vote of a majority
of the directors then in office given at any regular or special meeting of the
board of directors. Bylaws, whether made or altered by the stockholders or by
the board of directors, shall be subject to alteration or repeal by the
stockholders as in this Article provided.
Ex. 3.3-11
EXHIBIT 13
PETROLEUM
================================================================================
[GRAPH--INCOME CONTRIBUTION*--EXPLORATION AND PRODUCTION]
[GRAPH--CAPITAL EXPENDITURES--EXPLORATION AND PRODUCTION]
[GRAPH--NET HYDROCARBONS PRODUCTION]
EXPLORATION AND PRODUCTION
================================================================================
(Thousands of dollars) 1995 1994
================================================================================
Income contribution(1) ................... $ 29,506 45,253
United States ........................ 4,841 18,128
International ........................ 24,665 27,125
Total assets ............................. 1,149,433 1,292,402
United States ........................ 317,422 386,830
International ........................ 832,011 905,572
Capital expenditures(2) .................. 231,718 286,348
United States ........................ 71,186 79,451
International ........................ 160,532 206,897
================================================================================
Crude oil and liquids produced -
barrels a day .......................... 57,015 51,328
United States ........................ 13,736 13,355
International ........................ 43,279 37,973
Natural gas sold - MCF a day ............. 251,726 256,258
United States ........................ 189,250 195,555
International ........................ 62,476 60,703
================================================================================
1 Before unusual or infrequently occurring items.
2 Prior year amounts reclassified to conform to 1995 presentation.
================================================================================
WORLDWIDE OVERVIEW
Murphy is engaged in exploration and production operations throughout the
world. In the U.S., the Company is one of the largest operators in the Gulf of
Mexico and has interests onshore, primarily in Louisiana, Texas, and South
Arkansas. The Company also explores for and produces light oil, heavy oil, and
natural gas in western Canada, where a substantial ownership of heavy oil
reserves is providing a growing source of the Company's crude oil production.
Murphy's Canadian activities also include an interest in the world's largest
synthetic crude oil operation and interests in two oil fields offshore eastern
Canada--Hibernia, which is under development, and Terra Nova, where development
plans are being prepared. The Company has long been active in the U.K. sector of
the North Sea, where an ownership in the giant Ninian oil field has provided an
important source of crude oil production for a number of years. This field has
now been joined by three other oil properties in various stages of production or
development--"T" Block, where Tiffany and Toni fields were placed on stream in
late 1993 and where the Thelma and Southeast Thelma fields are expected to
commence production in late 1996; the Mungo and Monan fields, where development
was approved in 1995; and the Schiehallion field, an important discovery west of
the Shetland Islands on Block 204/25a. Development of the Schiehallion field is
expected to be approved early in 1996. The Company also has producing properties
in Spain and Ecuador and conducts an ongoing exploration program in other parts
of the world, with Peru, offshore China, and Pakistan currently among areas of
particular interest.
The exploration and production function represents the Company's best
opportunity for extraordinary growth. Murphy's exploration programs emphasize
those areas where we have established production and the related data base and
high-risk prospects that have potential for significant reserve additions. The
Company also has the technical expertise to identify frontier prospects, along
with the resources to acquire significant ownership positions therein, and
attempts to do so early in the exploration cycle of emerging basins. Leveraging
that ownership position to fund exploratory drilling is an available option.
Earnings from the Company's exploration and production activities,
excluding unusual or infrequently occurring items, totaled $29.5 million in 1995
compared to $45.2 million a year ago. The decrease was due primarily to lower
sales prices for natural gas in the U.S. and higher exploration expenses, offset
in part by higher crude oil production and sales prices. Production of crude oil
and liquids increased 11 percent to 57,015 barrels a day, with all major
oil-producing areas experiencing increases. Total natural gas sales were 251.7
million cubic feet a day, down two percent. On an energy equivalent basis, the
Company's 1995 production was up five percent to a
4
[GULF OF MEXICO MAP]
record 98,969 barrels a day.
Capital expenditures for exploration and production totaled $231.7 million
in 1995 compared to $286.3 million in 1994. The 1996 budget provides for a
40-percent increase in capital expenditures for exploration and production
activities, primarily due to higher levels of spending on development projects
that will contribute significant new production commencing in 1997.
As shown in the schedules on pages 43 and 44, proved reserves of crude oil
and liquids increased 6.4 million barrels, while natural gas reserves were
essentially unchanged. Reserve additions in the U.S. totaled 5.1 million barrels
of oil and 70.7 billion cubic feet of natural gas. Additions from discoveries
included Viosca Knoll Block 783 and West Cameron Blocks 521 and 631. In the
U.K., the decision to develop the Mungo, Monan, Thelma, and Southeast Thelma
fields added 20.3 million barrels of oil and 19.8 billion cubic feet of natural
gas. Other changes included a 3.5-million-barrel downward revision in Ecuador.
On an energy equivalent basis, Murphy's reserves totaled 333.8 million barrels
at the end of 1995 compared to 327.6 million barrels at year-end 1994.
A review geographically of the Company's principal exploration and
production activities is presented in the sections that follow. The Company's
working interest percentage is shown, generally following the name of each field
or block, and unless otherwise indicated, average daily production rates are
net to the Company after deduction for royalty interests. The terms crude oil
production and oil production include natural gas liquids where applicable.
UNITED STATES
Average U.S. crude oil production totaled 13,736 barrels a day in 1995, up
three percent from 1994, and natural gas production totaled 189.3 million cubic
feet a day, a decrease of three percent from a year ago. Additions to production
were primarily provided by workovers and new drilling in existing fields,
essentially offset by normal production declines in several of the Company's
older fields.
Gulf of Mexico - The Gulf of Mexico is the Company's principal area of
interest in the U.S. and offers significant growth potential. In 1995, the Gulf
accounted for 69 percent and 89 percent, respectively, of our U.S. oil and
natural gas production.
The Ship Shoal Block 113 field (50-70%) is our largest single source of oil
production in the U.S. A successful oil well was completed during 1995, and a
successful gas well was completed shortly after year-end. While a slower pace of
drilling in 1995 resulted in normal decline more than offsetting new production,
additional wells are planned in 1996 for this field. Oil production averaged
3,850 barrels a day in 1995 compared to 4,239 in 1994, and natural gas
production averaged 16.6 million cubic feet a day compared to 16.3 million a
year ago.
An interpretation of a 3-D seismic survey over the Ship Shoal Block 222
field (40-44.4%) led to drilling three successful wells during 1995, and
additional drilling is planned for 1996. Oil production averaged 734 barrels a
day in 1995 compared to 554 in 1994. Natural gas production averaged 3.4 million
cubic feet a day in 1995, up from one million in 1994.
Workover activities in the South Timbalier Block 63 field (100%) resulted in
substantial production increases during 1995. Average oil production increased
from
5
[GRAPH--CRUDE OIL AND NGL PRODUCTION]
[GRAPH--NATURAL GAS SALES]
[PICTURE APPEARS HERE]
197 barrels a day in 1994 to 506 in 1995, and natural gas production increased
from 10.1 million cubic feet a day to 16.2 million in 1995. A drilling program
based on 3-D seismic data also commenced on this block in the last quarter of
1995, and initial results are encouraging. A successful natural gas well was
placed on stream in December 1995, and another natural gas well was completed
and placed on stream shortly after year-end. Additional drilling is planned for
1996. Oil production from the adjacent South Timbalier Block 86 field (86.9%)
averaged 376 barrels a day in 1995 compared to 430 in 1994. Natural gas
production averaged 5.8 million cubic feet in 1995 compared to 2.7 million in
1994, with a gas discovery placed on stream in April 1994 providing the
increase.
Operations to sidetrack an oil well in the South Pelto Block 20 field (50%)
were successfully completed during 1995, and average oil production from the
field increased to 1,700 barrels a day in 1995 compared to 1,457 in 1994.
Average natural gas production declined from 5.4 million cubic feet a day in
1994 to 3.9 million.
Reflecting the nature of the business, production from three of the
Company's largest natural gas fields in
6
the U.S. continued to decline in 1995. Production from the Ship Shoal Block 113A
field (100%), which was placed on stream in 1982, averaged 27.8 million cubic
feet a day compared to 38.5 million in 1994. At the Matagorda Island Block
604/589 area (62.7%), production averaged 16.2 million cubic feet a day, down
from 23.6 million in 1994, and production from Viosca Knoll Blocks 203 and 204
(66.7%) declined from 17.4 million cubic feet a day in 1994 to 15.7 million in
1995.
While field declines are never welcomed, the Company has several projects
under way that have the potential to more than offset the rate of decline
experienced in 1995. The program that commenced at the end of 1995 at South
Timbalier Block 63 should contribute to the effort, but the most important
source of new U.S. production in the near-term is Viosca Knoll Block 783 (30%).
This block, which is known as the Tahoe field, is located in 1,500 feet of water
and is being developed in phases. The first phase, which came on stream in early
1994, included a subsea completion of a previously drilled well that was tied-in
to production facilities on a platform 12 miles to the north in 275 feet of
water. Natural gas production from the field averaged 14.2 million cubic feet a
day in 1995 compared to 9.5 million in 1994. Oil production averaged 480 barrels
a day compared to 359 barrels a year ago. The Company currently has a 75-
percent interest in production from the field due to disproportionate sharing of
first-phase development costs. This interest will be reduced to 30 percent upon
payout of the Company's investment in the first phase, which is expected to
occur during the first quarter of 1996. Overall performance of the first phase
has been excellent, and development of the second phase commenced in the fourth
quarter of 1995. Activity in 1996 will include the drilling and completion of
three horizontal wells and the completion of a successful horizontal well
drilled in 1995. First production from the well drilled in 1995 is scheduled for
the fourth quarter of 1996, with full production from the second phase expected
in early 1997.
Production is also expected to commence in the third quarter of 1996 from
Mobile Block 863 (11.5%), a 1994 natural gas discovery in the Norphlet
formation. In addition, two exploratory wells in progress at the end of 1995
resulted in natural gas discoveries in early 1996. A well in West Cameron Block
521 (50%) logged 100 feet of net natural gas sands in two zones. Production
facilities are being designed and first production is expected in late 1996.
Also, a well drilled in West Cameron Block 631 (60%) found 338 feet of net
natural gas sands in five zones. A test of one of the zones flowed at a gross
rate of 10.4 million cubic feet a day. A five-well drilling template has been
installed, and additional drilling is under way to test other prospects on the
block. First production is anticipated in the second quarter of 1997.
The wells drilled on the West Cameron blocks, which were acquired in 1995 at
the Central Gulf of Mexico lease sale, were the initial wells of a multi-well
program planned
[CANADA MAP]
7
[OFFSHORE EASTERN CANADA MAP]
[PICTURE APPEARS HERE]
for the Gulf in 1996 to test 3-D generated prospects on recently acquired
acreage.
The Company holds a 33.3-percent interest in the Destin Dome Block 56 unit,
which includes 11 leases covering 63,360 acres located approximately 40 miles
south of Pensacola, Florida. Two wells drilled in the Norphlet formation in
prior years have proven an accumulation of natural gas reserves at depths
between 22,000 and 23,000 feet, and 64 billion cubic feet of natural gas
attributable to these wells are included in the Company's reserves. A third well
to further delineate the unit's reserve potential was commenced in the fourth
quarter of 1995. The well is expected to reach total depth in the first quarter
of 1996.
Other exploration activity during 1995 included an unsuccessful sidetrack of
a well drilled in 1994 on Mobile Block 908 (70%). A well drilled on Viosca Knoll
Block 988 (25%) found noncommercial quantities of oil and natural gas and was
abandoned. Murphy participated in the two 1995 federal lease sales held in the
Gulf of Mexico and acquired 40- to 100-percent interests in 14 blocks.
Onshore - U.S. onshore exploration activity in 1995 was principally in South
Louisiana. Shortly after year-end, a 19,000-foot exploratory well (50%) in
Vermilion Parish, Louisiana, was tested at a gross rate of 6.5 million cubic
feet of natural gas a day. An extended 30-day flow test will be required to
determine if the field is commercial. Daily production from two wells in the
East Riceville field (33.3%), also located in Vermilion Parish, averaged 7.4
million cubic feet of natural gas and 167 barrels of oil in 1995. Production in
1994 averaged eight million cubic feet of natural gas a day and 180 barrels of
oil. Infield drilling in 1995 included 10 wells in Louisiana and Texas, all of
which were successful.
Property dispositions - In late 1995, the Company announced its intention to
sell its interests in substantially all of its onshore properties in the U.S.
and 20 nonstrategic properties in the Gulf of Mexico. The properties targeted
for sale accounted for approximately seven percent and three percent,
respectively, of the Company's 1995 worldwide production and year-end reserves.
CANADA
Production of crude oil in Canada increased seven percent in 1995 to 22,853
barrels a day. Light oil production decreased seven percent to 5,157 barrels a
day, while heavy oil production increased 30 percent to 8,864. The increase in
heavy oil production was due primarily to an aggressive drilling program and the
acquisition of additional interests in heavy oil properties in Alberta. Although
gross production of synthetic crude oil in 1995 set a new record for the sixth
consecutive year, net volumes to the Company were down three percent to 8,832
8
barrels a day due to an increase in net profit royalties caused by higher oil
prices. Natural gas production of 40.9 million cubic feet a day was up eight
percent from a year ago. The 1995 production volumes for both oil and natural
gas were at record levels.
The Company conducted an active development program in 1995 that included
three wells to develop light oil. However, primary emphasis was placed on the
development of heavy oil, and the 1995 program included 27 successful horizontal
wells and 15 successful vertical wells. Five successful vertical wells were
drilled to develop natural gas.
Murphy's exploration program in Canada during 1995 focused on light oil and
natural gas prospects. Four light oil wells drilled during the year were put on
production near year-end, and three natural gas wells, including one drilled in
the Foothills of northeastern British Columbia, will be tested in early 1996.
One successful heavy oil exploration well was also drilled during the year. The
Company also acquired a 25-percent interest in an exploration license in the
Jeanne d'Arc Basin, offshore Newfoundland, located midway between the Hibernia
and Terra Nova oil fields.
The Company has a five-percent interest in the Syncrude project, the world's
largest oil sands mining and upgrading operation. This project is located on
157,990 acres leased from the province of Alberta in the Athabasca oil sands
area near Fort McMurray. Syncrude combines the technologies of mining,
extraction, and upgrading to convert oil sands into synthetic crude oil. The
deposits are mined by large draglines and moved to an extraction plant, where
the oil sands are mixed with hot water, steam, and caustic soda to produce a
slurry, from which the oil floats as a froth. The froth is treated to remove
water and solids and is fed into an upgrading process in the form of bitumen,
which is then "cracked" into naphtha, light gas oil, and heavy gas oil streams.
These streams are hydrotreated to remove sulfur and nitrogen impurities and
mixed to form synthetic crude oil. The current Syncrude license expires in the
year 2025.
Construction of the facilities for the Hibernia oil field (6.5%) in the
Grand Banks area, offshore Newfoundland, continued throughout 1995. First
production from this field, discovered in 1979, is expected to occur in late
1997 or early 1998, with peak production anticipated at 135,000 gross barrels of
oil a day. Gross recoverable reserves are estimated to be 615 million barrels.
The central production facility for the Hibernia field is a Gravity Base
Structure (GBS)--the first to be constructed to resist the impact of an
iceberg. At year-end, the GBS was approximately 80 percent complete. In 1995,
the main topside modules, which were constructed at various locations around the
world, were delivered to the construction site, where they were joined into a
single integrated unit. The GBS and the modules will be mated prior to towing
the completed structure to the production site. Tow-out is scheduled for the
summer of 1997.
In December 1995, the owners of the Terra Nova oil field (10.7%), located
approximately 20 miles southeast of Hibernia, commenced preparation of the
Development Plan Application (DPA) for the field. The development plan will
include utilization of floating production system technology with
"ice-avoidance" criteria, rather than the "ice-resistance" criteria of the GBS
for Hibernia. In addition, the project is to be developed by employing a
contractor alliance arrangement where the owners, contractors, and suppliers
work together to provide major project components. It is anticipated that the
DPA will be filed with the Newfoundland government in the second quarter of
1996. Gross recoverable reserves for Terra
[NORTH SEA MAP]
9
[SCHEMATIC APPEARS HERE]
Nova are estimated to be between 300 and 400 million barrels of oil, with peak
production estimated at 100,000 barrels a day. Project sanction is expected in
1997.
UNITED KINGDOM
Production from the Ninian field (13.8%) averaged 6,784 barrels of oil a
day in 1995 compared to 7,883 in 1994. The rate of decline in 1995 was less than
forecast primarily due to the success of an infill drilling program, which
included the redrilling of four wells to new bottom-hole locations. A recently
completed 3-D seismic survey is expected to result in additional infill
drilling. Tariff income from the processing of oil and gas from four third-party
fields continues to make an important contribution to Ninian's operating
results.
Production from "T" Block (11.3%) averaged 8,172 barrels of oil a day in
1995 compared to 5,566 in 1994. "T" Block contains four separate fields--
Tiffany, Toni, Thelma, and Southeast Thelma. The first phase of development
utilized a conventional steel platform in the Tiffany field, with wells in the
Toni field connected to the platform by a subsea system. In 1995, one production
well and one water injection well were completed at Tiffany, and an additional
injection well is scheduled for completion in the first quarter of 1996. At
Toni, the addition of a booster pump to increase water injection capacity is
planned for the second half of 1996.
The Thelma and Southeast Thelma fields received government approval for
development in April 1995. The fields, which lie approximately five miles south
of the Tiffany platform, will also incorporate a subsea system connected to the
Tiffany platform. Development drilling commenced in June 1995, and first
production is expected in late 1996. Initial production is projected at gross
rates of 20,000 barrels of oil a day and 28 million cubic feet of natural gas a
day from two wells at Southeast Thelma and one horizontal well at Thelma.
Daily production from the Amethyst field (7.4%) averaged 10.7 million cubic
feet of natural gas compared to 10.1 million in 1994. Onshore gas compression
commenced in October 1995. Drilling during the year included a successful
horizontal development well and two successful exploration wells drilled on the
nearby Flowers North and Flowers South prospects. Development of the Flowers
discoveries is planned for 1997 by the drilling of extended-reach wells from an
existing platform.
Development of the Mungo and Monan fields (12.7%) was approved by the U.K.
government in December 1995. The fields will be developed jointly with five
other oil and gas fields as part of the Eastern Trough Area Project. The Mungo
field will be developed from an unmanned platform, while the Monan field will
use a subsea system. Both fields will produce to a central processing facility,
a two-platform structure that will provide processing facilities, utilities, and
accommodations. First production is expected in late 1998, with peak gross
production estimated at 65,000 barrels of oil a day.
Exploration efforts in the
10
U.K. were concentrated to the west of the Shetland Islands, where an active
drilling program was combined with evaluation and acquisition of new acreage.
Activity in the Schiehallion field (5.9%), which underlies a portion of the
Company's Block 204/25a and adjacent blocks to the north and east, included the
drilling of three wells with field partners to establish the southern limits of
the field. In addition, an extended test of a horizontal well drilled in the
central part of the field recovered more than 700,000 barrels of oil at an
average stabilized rate of 18,000 barrels a day. Information gained from these
wells and a 3-D seismic survey contributed to an accelerated development
program, which anticipates first production in late 1997 or early 1998.
Development of the field is expected to be approved in 1996 and calls for the
drilling of wells from three subsea drilling centers linked to a floating
production storage and offloading vessel. Gross peak production is anticipated
to be in excess of 100,000 barrels of oil a day. Gross recoverable reserves are
estimated to be between 200 and 400 million barrels. The Company's initial
equity interest in the field is 5.9 percent, which is subject to redetermination
upon completion of development drilling.
In the 16th Licensing Round, the Company was awarded Block 205/8 (35%) in
the West of Shetlands area. A well is planned in 1996 to test the block. The
Company was also awarded Blocks 20/19 and 20/20 (25%) in the Central North Sea,
where 3-D seismic data was acquired during the latter half of the year in
anticipation of drilling in 1996.
ECUADOR
The Company has a 20-percent interest in risk-service contracts (similar to
production-sharing contracts) covering Block 16 and the Tivacuno field in
Ecuador. In addition, the Capiron field has been unitized as part of Block 16.
Block 16 is a 494,000-acre license located east of the Andes mountains in the
Oriente Basin. Production from the northern fields--Tivacuno, Capiron, and the
Bogi field on Block 16--commenced in mid-1994. Development of the southern
fields--Amo, Daimi, Ginta, and Iro--is under way. Initial production from the
Amo field commenced in December 1994, and the other three fields should be
capable of first production in 1996. However, our combined Ecuador production
has been subject to apportionment due to limited export pipeline capacity. As a
result, gross production for 1996, which was planned to exceed 50,000 barrels of
oil a day, is not expected to substantially exceed the current level of 30,000
barrels a day. The Company's share of production from Ecuador averaged 5,274
barrels of oil a day in 1995 compared to 1,967 in 1994.
SPAIN
Production from the Gaviota field (18%) averaged 3.6 million cubic feet of
natural gas a day in 1995 compared to 12.6 million in 1994. This field has been
converted into a natural gas storage facility under an agreement with ENAGAS,
the Spanish gas distribution company, and production ceased in early
[SCHEMATIC APPEARS HERE]
11
[PAKISTAN MAP]
1995. The gas storage project, known as ALGA, handles third-party natural gas
for a tariff, which covers operating costs and provides a return on capital
invested. The project began sustained gas injection in May 1995. Production also
commenced from the East Albatros field (18%) in May. This field is located 11
miles west of Gaviota and is produced through a subsea well connected to the
Gaviota platform. Production averaged 7.3 million cubic feet of natural gas a
day for the year.
GABON
Virtually all of the Company's production in Gabon was from the Breme field
(45%). The Breme field permit expired in December 1994, but production continued
for a short period in 1995 under a temporary extension granted by the Gabonese
government. The government subsequently chose not to renew the permit, and the
Company has withdrawn completely from Gabon.
OTHER
During 1995, Murphy acquired a 40-percent interest in three contiguous
blocks onshore Pakistan. The blocks--Leiah, Munda, and Tarind--are located in
the Middle Indus Basin and cover 4.4 million acres. The work commitment consists
of a seismic program that commenced in 1995 and continues into 1996. The Company
also has a 100-percent interest in the 6.7-million acre Kharan concession in
Pakistan; this concession remained in a force majeure status during 1995. In
China, the Company participated in the drilling of an unsuccessful exploratory
well on Block 04/36 (45%) in the Bohai Bay. The final well obligation is planned
for the second quarter of 1996. Onshore Peru, the Company holds a 100-percent
interest in Block 71, which covers 3.1 million acres in the Ucayali Basin. The
first exploration period expires in June 1996 and includes a work obligation for
certain seismic activity that was substantially completed in 1995. An optional
second exploration period, which expires in June 1997, includes a one-well
obligation. During 1995, the Company joined a bidding and evaluation group (30%)
to acquire and evaluate data in preparation for the First Round of Licensing in
the Falkland Islands.
12
REFINING, MARKETING, AND TRANSPORTATION
================================================================================
(Thousands of dollars) 1995 1994
================================================================================
Income contribution* ............................ $ 2,052 30,203
United States ............................... (3,767) 17,674
International ............................... 5,819 12,529
Total assets .................................... 680,315 712,929
United States ............................... 494,577 500,467
International ............................... 185,738 212,462
Capital expenditures ............................ 53,602 94,697
United States ............................... 27,565 80,272
International ............................... 26,037 14,425
================================================================================
Crude oil processed - barrels a day ............. 155,503 140,882
United States ............................... 125,157 108,844
International ............................... 30,346 32,038
Products sold - barrels a day ................... 161,911 161,130
United States ............................... 130,394 120,618
International ............................... 31,517 40,512
================================================================================
Average gross margin on products sold -
dollars a barrel
United States ............................... $ .46 1.07
United Kingdom .............................. 2.26 2.17
================================================================================
*Before unusual or infrequently occurring items.
================================================================================
WORLDWIDE OVERVIEW
Murphy is engaged in downstream activities in the United States, the United
Kingdom, and Canada. In the U.S., operations are conducted in two separate
regions. A 100,000-barrel-a-day refinery at Meraux, Louisiana, produces refined
petroleum products for distribution over an 11-state area in the southeastern
part of the U.S. that is generally referred to as the Gulf Coast market. A
four-state area in the upper-Midwest is served by a 35,000-barrel-a-day refinery
at Superior, Wisconsin. Operations in the United Kingdom are centered around a
108,000-barrel-a-day refinery, in which the Company has an effective 30-percent
interest, at Milford Haven, Wales. Refined products are sold at 986 branded
outlets--514 in the U.S. and seven in Canada under the SPUR brand, and 465 in
the U.K. primarily under the MURCO brand. Murphy also has varying interests in
four crude oil pipeline systems in western Canada, including two of the six
systems that export crude oil from Canada to the U.S.
The year 1995 was difficult for the Company's worldwide downstream
operations, and earnings, excluding unusual or infrequently occurring items,
totaled $2 million in 1995 compared to $30.2 million in 1994. Operations in the
U.S. lost $3.8 million compared to earning $17.7 million a year ago. Earnings
from operations in the U.K. totaled $.3 million, down from $5.2 million in 1994.
The earnings contribution from Canadian operations totaled $5.5 million in 1995
compared to $7.3 million a year ago. The Company's composite average gross
margin on product sales in the U.S. was down 57 percent, while sales of refined
products increased eight percent. Average margin in the U.K. was up four percent
compared to 1994. Sales volumes were down 22 percent compared to 1994, with the
reduction primarily in low-margin cargo sales. The decline in Canadian earnings
was due primarily to lower crude oil trading volumes and margins.
A key element of Murphy's strategy for its downstream business is a
commitment to maintain modern, efficient, and competitive refining and
distribution systems. The Company also recognizes its responsibility to operate
in an environmentally safe manner. In meeting those objectives, the Company's
worldwide downstream capital expenditures in 1995 totaled $53.6 million compared
to $94.7 million in 1994. The 1994 expenditures included nearly $25 million to
increase sour crude processing capabilities at the Meraux refinery.
UNITED STATES REFINING
The expansion and upgrade program at the Meraux refinery, completed in
December 1994, allowed the refinery to take advantage of processing and crude
selection opportunities in 1995. We continued the trend of processing higher
rates of light-sour and heavy-sweet crudes. Additional sour crude processing
capacity exists if warranted by
[GRAPH--INCOME CONTRIBUTION*--REFINING, MARKETING, AND TRANSPORTATION]
[GRAPH--CAPITAL EXPENDITURES--REFINING, MARKETING, AND TRANSPORTATION]
[GRAPH--REFINED PRODUCTS SOLD]
13
[PICTURE APPEARS HERE]
cost differentials between crudes. In total, the Meraux refinery processed a
record 91,940 barrels of crude oil a day, outpacing the previous record set in
1992 by 14 percent. Crude oil for Meraux is supplied through our own domestic
production and purchase of third-party domestic and foreign-source crudes.
The Superior refinery also posted impressive throughput results for 1995,
with average crude runs of 33,217 barrels a day, the highest in 18 years. In
response to demand for asphalt, asphaltic crude runs were emphasized throughout
the year. Canadian-source crude continued to account for 78 percent of the
refinery's crude slate, with the balance comprised of Williston Basin sweet and
sour grades.
Refining capital expenditures in the U.S. were down substantially in 1995,
with major expenditures focused on environmental projects. Capital expenditures
in 1996 are budgeted to remain near the 1995 amount, with a continuing but
diminished level of environmental expenditures, offset by an increased emphasis
on engineering for future refinery upgrades.
UNITED STATES MARKETING
Murphy's downstream operations are conducted in 11 southeastern states and
four upper-midwestern states. The southeastern system is anchored by our Meraux
refinery, located on the Mississippi River. Sales are made through 28 terminals
in this system; the terminals are supplied by barge or pipeline, including a
jointly owned line that is connected to two common carrier pipelines. In
addition, products are shipped by barge and tanker from the refinery's river
dock for sale into the wholesale cargo market and transport to marine terminals.
Our upper-midwestern distribution system includes 15 terminals owned by others
and two Company-owned terminals that are supplied by pipeline. One of the
Company-owned terminals, located near Duluth, Minnesota, was acquired in 1995 to
better serve customers from the Iron Range of northern Minnesota to areas south
of Duluth. Asphalt terminals at Crookston, Minnesota, and Rhinelander,
Wisconsin, are
14
supplied by truck. Asphalt demand remained brisk in our upper-midwestern system
during 1995, with a record volume of more than 1.5 million barrels sold through
our Company terminals.
Products sold and the initial distribution channels utilized are shown in
the following table. Included in the terminal sales volumes are 18,439 barrels a
day sold at retail through SPUR branded outlets.
- --------------------------------------------------------------------------------
(Barrels a day) Terminals Cargo
- --------------------------------------------------------------------------------
Gasoline ................................... 41,663 21,950
Kerosine ................................... 2,095 7,856
Diesel/heating oil ......................... 21,141 12,362
Residuals .................................. -- 14,795
Asphalt .................................... 4,213 --
LPG/other .................................. -- 4,602
- --------------------------------------------------------------------------------
69,112 61,565
================================================================================
Several construction sites have been selected for new stations being
planned for 1996, including joint ventures with national-brand fast food chains.
To improve the convenience of shopping at our stations, we began an aggressive
program of installing credit card readers at our pumps. This feature relieves
congestion on the driveways and allows customers who only want to purchase fuel
to avoid waiting in line to make payment. We also plan to install car wash
systems in selected new and existing stations as a one-stop convenience to our
customers.
UNITED KINGDOM REFINING
Activities at the Company's jointly owned Milford Haven refinery during 1995
were directed toward meeting impending environmental regulations, reducing
operating costs, and improving yields and operating flexibility.
To meet the imposition on October 1, 1996 of regulations reducing the sulfur
content of diesel oil to .05 percent, construction of a high-pressure distillate
hydrotreater unit is progressing on schedule for a September start-up. The new
unit is also capable of producing low-sulfur No. 2 fuel oil. Cost reduction
plans in the detailed design phase include modification of the cat cracker to
reduce catalyst consumption. Also under way is a study reviewing operations of
the crude unit to reduce energy consumption, enhance product yields, and
increase flexibility in the selection of feedstocks.
During 1995, Murphy processed an average of 30,346 barrels of crude oil a
day at the Milford Haven refinery, down five percent from 1994. The refinery
utilizes North Sea crudes purchased in the spot market. Transportation to the
refinery is provided by tankers chartered at spot rates.
UNITED KINGDOM MARKETING
The distribution system for refined products in the U.K. includes three
rail-fed terminals owned by the Company and eight terminals owned by others,
where products are received in exchange for deliveries from the Company's
terminals.
Service station profitability came under severe pressure in
[UNITED STATES MAP]
[PICTURE APPEARS HERE]
15
[UNITED KINGDOM MAP]
[PICTURE APPEARS HERE]
1995, as major oil companies defended their market share against the
supermarkets, which have garnered about 20 percent of the market. The Company's
service stations remained profitable over the year, although average gross
margin was down seven percent from 1994. Sales volume through our branded
outlets fell almost five percent from last year to 8,334 barrels a day,
reflecting our pricing strategy of emphasizing profitability over market share.
Six Company-owned stations were closed as uneconomic, and we expect further
reductions in 1996.
Products available from Milford Haven that are not required in our retail
and wholesale markets, 22,872 barrels a day in 1995, are sold in the bulk cargo
markets. To reduce our exposure to the gasoline spot market in 1995, a year
characterized by poor demand and weak pricing, we sold an average of 2,200
barrels a day on a contract basis at higher than spot prices.
The Company's three terminals operated profitably in 1995. Renegotiation of
the rail freight contract late in the year and expected higher terminal
throughputs should translate into improved results in 1996 for our terminaling
operations.
CANADA
The Company's western Canadian pipelines, which comprise four oil-gathering
and transportation systems, enjoyed a nine-percent increase in throughputs in
1995. Throughputs for the Murphy-operated Manito (52.5%) and Cactus Lake/Bodo
(13.1%/41.3%) heavy oil pipeline systems, both connected to the Interprovincial
Pipe Line, were up a combined 12 percent over 1994 due to increased heavy oil
production in the area, a major part of which was from the Company's fields. For
1995, Manito averaged 45,562 barrels a day and Cactus Lake/Bodo averaged 33,707.
Throughputs for the Milk River pipeline (100%) increased 26 percent to a record
67,508 barrels a day, as demand for Canadian crude in the Billings, Montana,
refining area increased substantially. The pipeline was expanded during the year
by construction of a 12-inch loop from the Milk River terminal to the
U.S./Canadian border and a station expansion, which pushed capacity from 70,000
to over 100,000 barrels a day. Pipelines connected to the Milk River line were
also expanded in 1995, thus providing the collective means to deliver
substantial volume increases into the Billings area to further replace the
declining U.S. crude supply. Throughputs for 1995 at the Wascana pipeline system
(100%), also a cross-border pipeline, declined from the prior year by 23 percent
to an average of 26,943 barrels a day. Demand was down due to the loss in May of
a 12,000-barrel-a-day contract. Since then, the available capacity has not been
fully
16
[PICTURE APPEARS HERE]
utilized. The Company continues working with other U.S. pipelines in the region
to expand capacity to higher-demand areas, with particular emphasis on markets
in the Salt Lake City area.
Crude oil trading earnings were down in 1995 due to lower margins and a
sharp drop in demand for Canadian heavy crudes during the fourth quarter. The
Company also operates a fleet of trucks that transport crude oil and natural gas
liquids, and earnings from these activities were up compared to a year ago.
Sales of refined products at the Company's retail outlets in Thunder Bay,
Ontario, which are supplied from our Superior refinery, increased 15 percent
over the previous year, but margins were squeezed by strong price competition.
[WESTERN CRUDE OIL PIPELINE SYSTEMS MAP]
[GRAPH--CANADIAN PIPELINE THROUGHPUTS]
17
FARM, TIMBER, AND REAL ESTATE
================================================================================
[GRAPH--INCOME CONTRIBUTION--FARM, TIMBER, AND REAL ESTATE]
[GRAPH--CAPITAL EXPENDITURES--FARM, TIMBER, AND REAL ESTATE]
[GRAPH--SALES OF FINISHED LUMBER]
================================================================================
(Thousands of dollars) 1995 1994
================================================================================
Income contribution ............................ $ 9,005 17,470
Total assets ................................... 163,834 155,583
Capital expenditures ........................... 9,133 11,403
================================================================================
Lumber sales - thousand board feet ............. 140,549 138,377
Residential lots sold .......................... 53 99
Land owned - acres
Farm ....................................... 36,000 36,000
Timber ..................................... 341,000 341,000
Real estate ................................ 9,000 10,000
================================================================================
Through its wholly owned subsidiary, Deltic Farm & Timber Co., Inc., the
Company owns 36,000 acres of farmland in South Arkansas and North Louisiana,
341,000 acres of southern pine timberland and two sawmills in Arkansas, and is
developing the premier residential community in Little Rock, Arkansas. Those
activities produced earnings of $9 million in 1995 compared to $17.5 million in
1994, a decrease of 49 percent. Earnings from all operating segments declined
from a year ago, with timber operations accounting for most of the decrease.
Deltic's timber operations earned $8.7 million in 1995, down from the
record $14.7 million earned in 1994. The decline follows three consecutive years
of earnings growth in our timber operations. Sales of finished lumber totaled
140.5 million board feet, an increase of two percent from the 138.4 million
board feet sold in 1994. However, the average sales price for finished lumber
declined 12 percent to $318 per thousand board feet. Pretax mill margins of $12
per thousand board feet declined 86 percent from the record margins of 1994
because of lower sales prices and an increase in log costs. An expansion of the
Waldo sawmill, including an addition of two steam-dry kilns, two boilers, and a
band mill, was completed in the third quarter of 1995. The expansion will
provide Deltic the product flexibility needed to extract maximum value from each
log processed, and also will offer entrance into the export market in 1996.
Sales of pine sawtimber from Deltic's fee lands decreased 12 percent to 35.7
million board feet in 1995. Pine sawtimber prices were strong during the first
six months of the year before declining in the last half of 1995. Approximately
70 percent of Deltic's sawtimber sales were made during the first half of the
year, and the average sales price increased nine percent in 1995 to $406 per
thousand board feet. Pine pulpwood sales were down slightly from 1994 levels and
totaled 12,799 cords.
A site was selected in Union County, Arkansas, for construction of a
50-percent-owned medium density
[PICTURE APPEARS HERE]
18
fiberboard (MDF) plant. MDF, which is used in the furniture, flooring, and
molding industries, is manufactured from sawmill residuals (chips, shavings, and
sawdust) held together by an adhesive bond. The plant will have an annual
production capacity of 150 million square feet, making it one of the largest of
its type in the world. Construction is scheduled to commence in mid-1996, and
first production is expected in early 1998.
Real estate operations earned $.5 million in 1995, down 74 percent from the
$1.9 million earned in 1994. Lot sales at Chenal Valley, Deltic's 4,300-acre
planned community in Little Rock, Arkansas, declined from 99 a year ago to 53 in
1995. Construction of the first office building in Chenal Valley commenced in
the fourth quarter of 1995. The Company-owned building will contain
approximately 50,000 square feet, of which approximately 25,000 square feet was
leased at year-end. Sale of commercial acreage will be actively pursued in 1996.
Farming operations earned $.2 million in 1995, down from $1.1 million earned
in 1994. Hot, dry conditions during the last half of the growing season
adversely affected the yield per acre for all crops. Cotton yields declined 15
percent to 749 pounds per acre, soybean yields were down 33 percent to 27
bushels per acre, and corn yields declined 24 percent to 86 bushels per acre.
[PICTURE APPEARS HERE]
19
FINANCIAL REVIEW
SELECTED FINANCIAL INFORMATION
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars except per share data) 1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS FOR THE YEAR(1)
Sales and other operating revenues(2) ............ $1,691,242 1,668,822 1,625,662 1,585,482 1,568,995
Net cash provided by operating activities ........ 322,939 337,283 362,973 284,159 213,635
Income (loss) from continuing operations ......... (118,612) 106,628 86,798 62,761 (9,607)
Income (loss) before extraordinary item
and cumulative effect of changes in
accounting principles ........................... (118,612) 106,628 86,798 86,616 (11,157)
Net income (loss) ................................ (118,612) 106,628 102,136 105,565 (11,157)
Per Common share
Income (loss) from continuing operations ....... (2.64) 2.37 1.94 1.40 (.24)
Income (loss) before extraordinary item
and cumulative effect of changes in
accounting principles ........................ (2.64) 2.37 1.94 1.93 (.28)
Net income (loss) .............................. (2.64) 2.37 2.28 2.35 (.28)
Dividends ...................................... 1.30 1.30 1.25 1.20 1.20
Percentage return on
Average stockholders' equity ................... (9.3) 8.6 8.4 8.8 (1.1)
Average borrowed and invested capital .......... (7.9) 8.0 8.4 9.7 1.5
Average total assets ........................... (5.1) 4.8 5.0 5.3 (.6)
- ------------------------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES FOR THE YEAR
Exploration and production(2, 3) ................. $ 231,718 286,348 520,086 138,129 147,965
Refining, marketing, and transportation .......... 53,602 94,697 86,885 68,073 63,143
Farm, timber, and real estate .................... 9,133 11,403 9,674 6,017 2,858
Corporate and other .............................. 1,831 4,876 4,034 1,477 2,203
- ------------------------------------------------------------------------------------------------------------------------------------
$ 296,284 397,324 620,679 213,696 216,169
====================================================================================================================================
FINANCIAL CONDITION AT YEAR-END
Current ratio .................................... 1.25 1.18 1.32 1.87 1.30
Working capital .................................. $ 104,509 79,594 130,242 371,682 156,204
Net property(2) .................................. 1,487,232 1,670,934 1,510,281 1,048,744 1,121,106
Total assets ..................................... 2,119,113 2,312,032 2,168,859 1,936,514 2,174,626
Long-term obligations(4) ......................... 193,935 172,452 109,218 24,929 193,152
Stockholders' equity ............................. 1,101,145 1,270,679 1,222,350 1,200,088 1,200,819
Per share ...................................... 24.56 28.34 27.28 26.76 26.71
Long-term obligations(4) - percent of
capital employed ................................ 15.0 11.9 8.2 2.0 13.9
- ------------------------------------------------------------------------------------------------------------------------------------
1 Includes effects on income of unusual or infrequently occurring items in 1995,
1994, and 1993 that are detailed in Management's Discussion and Analysis, page
21. Also, unusual or infrequently occurring items in 1992 and 1991 resulted in
an increase (decrease) to net income of $50,665, $1.13 a share, and $(67,333),
$(1.71) a share, respectively.
2 Prior year amounts have been reclassified to conform to 1995 presentation.
3 Includes amounts expensed and cost of assets acquired by assuming directly
related liabilities.
4 Includes nonrecourse debt at December 31, 1995, 1994, and 1993 of $171,499,
$122,638 and $87,509, which was 13.2 percent, 8.5 percent, and 6.6 percent,
respectively, of capital employed.
[GRAPH--INCOME EXCLUDING UNUSUAL ITEMS]
[GRAPH--NET CASH PROVIDED BY OPERATING ACTIVITIES]
[GRAPH--STOCKHOLDERS' EQUITY AT YEAR-END]
20
MANAGEMENT'S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
The Company reported a net loss in 1995 of $118.6 million, $2.64 a share,
compared to net income in 1994 of $106.6 million, $2.37 a share. In 1993, the
Company earned $102.1 million, $2.28 a share. The loss in 1995 included
after-tax charges of $168.4 million, $3.75 a share, from an asset write-down
under provisions of Statement of Financial Accounting Standards No. 121 (SFAS
No. 121), which deals with impairment of the carrying value of long-lived
assets, and $4.2 million, $.10 a share, related to reduction-in-force programs.
Results of operations for the three years ended December 31, 1995 also included
other unusual or infrequently occurring items that resulted in net gains of
$20.6 million, $.46 a share, in 1995; $20.3 million, $.45 a share, in 1994; and
$25.7 million, $.57 a share, in 1993. The 1993 net gain included $15.3 million,
$.34 a share, from adoption of new accounting standards.
Income before unusual or infrequently occurring items totaled $33.4 million
in 1995, a decrease of $52.9 million compared to 1994. Earnings from the
Company's exploration and production operations declined $15.7 million, and
income from the refining, marketing, and transportation function was down $28.2
million. Earnings from farm, timber, and real estate operations declined $8.5
million, and the cost of corporate activities increased $.5 million compared to
1994.
In 1994, income before unusual or infrequently occurring items was $86.3
million, an increase of $9.9 million compared to 1993. Earnings from exploration
and production operations improved by $8.3 million, while income from refining,
marketing, and transportation declined $1.3 million. Income from farm, timber,
and real estate operations increased $4.4 million, and the cost of corporate
functions increased $1.5 million compared to 1993.
In the following table, the Company's results of operations for the three
years ended December 31, 1995 are presented by function. Unusual or infrequently
occurring items, which can obscure underlying trends of operating results and
affect comparability between years, are set out separately. A review of the
information presented follows the table.
- ------------------------------------------------------------------------------------------------------------------------------------
(Millions of dollars) 1995 1994 1993
- ------------------------------------------------------------------------------------------------------------------------------------
Exploration and production
United States ......................................................... $ 4.8 18.1 32.7
Canada ................................................................ 21.7 15.1 6.3
United Kingdom ........................................................ 6.4 6.0 3.5
Other international ................................................... (3.4) 6.0 (5.6)
- ------------------------------------------------------------------------------------------------------------------------------------
29.5 45.2 36.9
- ------------------------------------------------------------------------------------------------------------------------------------
Refining, marketing, and transportation
United States ......................................................... (3.8) 17.7 11.2
United Kingdom ........................................................ .3 5.2 11.7
Canada ................................................................ 5.5 7.3 8.6
- ------------------------------------------------------------------------------------------------------------------------------------
2.0 30.2 31.5
- ------------------------------------------------------------------------------------------------------------------------------------
Farm, timber, and real estate ............................................ 9.0 17.5 13.1
Corporate and other ...................................................... (7.1) (6.6) (5.1)
- ------------------------------------------------------------------------------------------------------------------------------------
Income before unusual or infrequently occurring items .................... 33.4 86.3 76.4
Refund and settlement of income tax matters .............................. 13.6 6.4 14.4
Impairment of long-lived assets .......................................... (168.4) -- --
Provision for reduction-in-force ......................................... (4.2) -- --
Adjustment of estimates for self-insured liabilities ..................... 7.0 -- --
Settlement of DOE matters ................................................ -- 13.9 --
Provision for environmental remediation matters .......................... -- -- (4.0)
Cumulative effect of changes in accounting principles .................... -- -- 15.3
- ------------------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ (118.6) 106.6 102.1
====================================================================================================================================
EXPLORATION AND PRODUCTION - Earnings from exploration and production
operations before unusual or infrequently occurring items were $29.5 million in
1995, $45.2 million in 1994, and $36.9 million in 1993. The decrease in 1995
earnings was due to a three-percent reduction in natural gas sales in the U.S.,
a 14-percent decline in the average sales price for U.S. natural gas, and a
54-percent increase in exploration expenses. Partial offsets were an 11-percent
increase in crude oil and liquids production and higher crude oil sales prices.
A 50-percent increase in crude oil and liquids production and a seven-percent
reduction in
[GRAPH--INCOME CONTRIBUTION BY OPERATING FUNCTION*]
21
[GRAPH--RANGE OF U.S. CRUDE OIL SALES PRICES]
[GRAPH--RANGE OF U.S. NATURAL GAS SALES PRICES]
exploration expenses contributed to the increase in 1994 earnings. These
improvements were offset in part by lower average crude oil sales prices in most
of the Company's producing areas and nine-percent reductions in natural gas
sales volumes and prices in the U.S.
The results of operations for oil and gas producing activities for each of
the last three years are shown by major operating area on pages 46 and 47. A
summary of oil and gas revenues is presented in the following table.
- --------------------------------------------------------------------------------
(Millions of dollars) 1995 1994 1993
- --------------------------------------------------------------------------------
United States
Crude oil ........................ $ 82.2 73.7 81.7
Natural gas ...................... 112.8 136.1 165.8
Canada
Crude oil ........................ 68.3 54.2 54.1
Natural gas ...................... 14.5 19.7 16.4
Synthetic oil .................... 55.7 52.7 --
United Kingdom
Crude oil ........................ 92.6 77.8 38.4
Natural gas ...................... 9.8 9.0 11.0
Ecuador - crude oil ................. 25.9 7.9 --
Other ............................... 11.3 17.6 17.2
- --------------------------------------------------------------------------------
Total $473.1 448.7 384.6
================================================================================
Daily production rates and weighted average sales prices are shown on page
48.
Worldwide crude oil and liquids production averaged 57,015 barrels a day in
1995, 51,328 in 1994, and 34,311 in 1993. Crude oil and liquids production in
the U.S. increased three percent in 1995, with production from new drilling more
than offsetting normal reservoir depletion. In 1994, U.S. production was down
three percent compared to 1993. Canadian production increased seven percent in
the current year following a 69-percent increase in 1994. Production of heavy
oil in Canada increased 30 percent in 1995 as a result of the continuation of an
accelerated program to develop the Company's heavy oil reserves. In 1994, the
program was deferred early in the year in response to weak crude oil prices, and
production was down eight percent compared to 1993. The Company's acquisition of
a five-percent interest in a synthetic crude oil project near the end of 1993
contributed 9,065 barrels a day to the increase in Canadian production in 1994.
Murphy's average production from the U.K. increased 11 percent in 1995 after
more than doubling in 1994. Production from Block 16/17 ("T" Block) in the North
Sea, which commenced in November 1993, averaged 8,172 barrels a day in 1995
compared to 5,566 in 1994. Production from the Ninian field in the North Sea
declined 14 percent in 1995 following a 36-percent increase in 1994. The
increase in 1994 was due to the acquisition of an additional 3.82-percent
interest in the field at the beginning of the year. Production in Ecuador, which
commenced in June 1994, averaged 5,274 barrels a day in 1995 compared to 1,967
in 1994.
Worldwide sales of natural gas averaged 251.7 million cubic feet a day in
1995, 256.3 million in 1994, and 274.9 million in 1993. The three-percent
decline in U.S. sales, most of which occurred in the last half of the year, was
due to reduced deliverability in certain of the Company's larger fields. Natural
gas sales were at record levels in Canada, increasing eight percent, and were up
five percent in the U.K. Natural gas sales in Spain declined 14 percent in 1995
as sales from the Gaviota field ceased after the field was converted to a
storage facility for third-party natural gas in the first quarter of the year.
As a partial offset, sales from the Albatros field commenced in the second
quarter of 1995. In 1994, the nine-percent decline in U.S. natural gas sales was
primarily due to voluntary production curtailments in response to low sales
prices, as normal production declines were nearly offset by incremental
production from new fields placed on stream during 1993 and 1994. Natural gas
sales in 1994 increased three percent in Canada and 32 percent in Spain, but
declined 22 percent in the U.K., primarily as a result of contractual
restrictions on the deliverability of the field.
As previously indicated, worldwide crude oil prices strengthened during
1995. In the U.S., Murphy's 1995 average monthly sales prices for crude oil and
condensate ranged from $15.42 a barrel to $18.06, and averaged $16.61 for the
year, an eight-percent increase over 1994. In Canada, the average sales price
for light oil was $16.45 a barrel in 1995, an increase of 13 percent. Heavy oil
prices were strong for much of 1995, but weakened late in the year and averaged
$12.10 a barrel, up 15 percent from a year ago. The average sales price for
synthetic crude oil was $17.28, up nine percent. U.K. sales prices averaged
$16.96 in 1995, an increase of eight percent from a year ago. In 1994, average
crude oil prices declined seven percent in the U.S. and five percent in the U.K.
In Canada, average sales prices were down three percent for light oil, but up
seven percent for heavy oil compared to 1993.
Average monthly natural gas sales prices in the U.S. ranged from $1.39 an
MCF to $2.45 during 1995. For the year, prices averaged $1.64 an MCF compared to
$1.91 a year ago. The average sales price for natural gas in Canada declined 32
percent. Prices increased four percent in the U.K. and 13 percent in Spain.
Average natural gas sales prices in 1994 were down nine percent in the U.S. and
three percent in Spain. Prices in Canada and the U.K. increased 16 percent and
five percent, respectively.
Based on 1995 volumes and deducting taxes at marginal rates, each $1 a
barrel and $.10 an MCF fluctuation in price would have affected annual
exploration and production earnings by
22
$11.6 million and $5.9 million, respectively. Consolidated net income could have
been affected differently because of contrary or corollary effects on other
business segments.
Production costs were $167.5 million in 1995, $162.1 million in 1994, and
$113.9 million in 1993. These amounts are shown by major operating area on pages
46 and 47. Costs per equivalent barrel of production during the last three years
were as follows.
- --------------------------------------------------------------------------------
(Dollars per equivalent barrel) 1995 1994 1993
- --------------------------------------------------------------------------------
United States ....................... $ 3.24 3.31 3.21
Canada
Excluding
synthetic oil ................. 3.55 3.56 3.70
Synthetic oil ................... 12.17 12.09 --
United Kingdom ...................... 5.88 5.77* 6.66*
Ecuador ............................. 6.01 8.21 --
Worldwide - excluding
synthetic oil ..................... 3.90 3.94* 3.90*
- --------------------------------------------------------------------------------
*Reclassified to conform to 1995 presentation.
The increase in the cost per barrel for Canadian synthetic oil in 1995 was
due to lower production volumes. Higher per equivalent barrel cost in the U.K.
in 1995 was due to repairs to a Ninian production platform, while both 1995 and
1994 were favorably affected by higher production from "T" Block. The per-barrel
cost in Ecuador decreased in 1995 due to higher production volumes. The 1994
increase in the U.S. was due primarily to lower production volumes resulting
from curtailment of natural gas sales. The 1994 reduction in Canada, excluding
synthetic oil, was due to strengthening of the U.S. dollar in relation to the
Canadian dollar.
Exploration expenses for each of the last three years are shown in total in
the following table, and amounts are reported by major operating area on pages
46 and 47. Certain of the expenses are included in the capital expenditure
totals for exploration and production activities.
- --------------------------------------------------------------------------------
(Millions of dollars) 1995 1994 1993
- --------------------------------------------------------------------------------
Included in capital expenditures
Dry hole costs ..................... $30.9 16.6 21.5
Geological and
geophysical costs ................ 16.2 9.5 7.6
Other costs ........................ 8.0 5.6 4.9
- --------------------------------------------------------------------------------
55.1 31.7 34.0
Undeveloped lease
amortization ......................... 10.7 11.0 12.1
- --------------------------------------------------------------------------------
Total $65.8 42.7 46.1
================================================================================
Dry hole costs in 1995 included $21.5 million for an unsuccessful well
drilled on Mobile Block 908 in the Gulf of Mexico.
Depreciation, depletion, and amortization related to exploration and
production operations totaled $182.7 million in 1995, $161.5 million in 1994,
and $139.7 million in 1993. The increases in 1995 and 1994 were primarily due to
higher production volumes. The write-down of assets under SFAS No. 121, which
was adopted effective October 1, 1995, resulted in a reduction in depreciation,
depletion, and amortization in 1995 of $2.4 million ($2 million after tax).
REFINING, MARKETING, AND TRANSPORTATION - Earnings from refining, marketing, and
transportation operations before unusual or infrequently occurring items were $2
million in 1995, $30.2 million in 1994, and $31.5 million in 1993. Operations in
the U.S. lost $3.8 million in 1995 compared to earning $17.7 million in 1994.
The 1995 loss included an after-tax provision of $3.9 million for estimated
losses under crude oil swap agreements. U.S. operations earned $11.2 million in
1993. Operations in the U.K. earned $.3 million in 1995 compared to $5.2 million
in 1994. In 1995, asset write-downs under SFAS No. 121 resulted in a reduction
in depreciation, depletion and amortization of $1.5 million ($1 million after
tax). U.K. operations earned $11.7 million in 1993. Canadian operations
contributed $5.5 million to 1995 earnings compared to $7.3 million in 1994 and
$8.6 million in 1993.
Unit margins (sales realizations less crude and other feedstocks, refining,
and costs to point of delivery) averaged $.46 a barrel in the U.S. in 1995,
$1.07 in 1994, and $.82 in 1993. U.S. product sales were up eight percent in
1995 following a slight decline in 1994. Margins in the Company's southeastern
marketing area were under pressure throughout 1995, and for the year the average
unit margin was down 68 percent compared to 1994. While benefiting from a strong
asphalt market during the summer months, margins in the upper-midwestern area
were also lower during much of 1995, and the average unit margin was down 44
percent from a year ago. Margins in both areas continued to be depressed at the
end of 1995, and in early 1996 the Company was experiencing losses in its U.S.
downstream operations. Compared to 1993, unit margins in the southeastern area
were generally higher throughout most of 1994, while unit margins in the
upper-midwestern area were down slightly.
Margins in the U.K. averaged $2.26 a barrel in 1995, $2.17 in 1994, and $3.08
in 1993. Sales of petroleum products declined 22 percent following a 24-percent
increase in 1994. Most of the increase in 1994 related to low-margin cargo
sales. Margins on sales through the Company's branded outlets were under
pressure during 1995, as competition with supermarkets intensified. Losses were
also being incurred in the U.K. in early 1996.
[GRAPH--EXPLORATION EXPENSES]
23
[GRAPH--AVERAGE SAWMILL MARGIN]
Margins fluctuated widely in 1994, but were generally below levels in 1993.
Based on sales volumes for 1995 and deducting taxes at marginal rates, each
$.42 a barrel ($.01 a gallon) fluctuation in unit margins would have affected
annual refining and marketing profits by $15.7 million. Consolidated net income
could have been affected differently because of contrary or corollary effects on
other business segments.
The declines in earnings from purchasing, transporting, and reselling crude
oil in Canada in both 1995 and 1994 were due to lower crude trading volumes and
margins even though pipeline throughputs were higher.
FARM, TIMBER, AND REAL ESTATE - Earnings from farm, timber, and real estate
operations were $9 million in 1995, $17.5 million in 1994, and $13.1 million in
1993. Timber operations earned $8.7 million in 1995, down from $14.7 million in
1994. Earnings from the sale of pine sawtimber harvested from Company lands
increased slightly in 1995, as a nine-percent increase in the average sales
price more than offset a 12-percent decline in board feet harvested. Earnings
from the Company's sawmills declined to near break-even levels in 1995, with a
12-percent decline in the average sales price for finished lumber more than
offsetting a 2-percent increase in sales. The earnings contribution from real
estate operations totaled $.5 million, down $1.4 million. Lot sales declined 46
percent. Farming operations were also at break-even levels in 1995 compared to
earning $1.1 million in 1994. The improvement in 1994 earnings compared to 1993
was primarily from timber operations, a $3.4 million increase, and farming
operations, a $1.2 million increase. Earnings from real estate operations
declined $.5 million. Timber earnings were up as a result of an increase in
sales of pine sawtimber and lumber and higher sales prices for each. The farms
enjoyed favorable weather in 1994 compared to 1993. The decline in earnings from
real estate operations was due to a decrease in lot sales.
CORPORATE - This segment includes interest income and expense and corporate
overhead not allocated to operating functions. The increased loss in 1995 was
due to higher interest expense. Lower interest income accounted for the increase
in the loss in 1994 compared to 1993, which continued to benefit from interest
earned on the investment of proceeds from sale of the Company's contract
drilling business in 1992.
UNUSUAL OR INFREQUENTLY OCCURRING ITEMS - Net income for each of the three years
ended December 31, 1995 included unusual or infrequently occurring items
reviewed below. Where appropriate, pretax amounts are given, and if not
separately stated therein, the affected components of the Consolidated
Statements of Income are indicated. The information presented also indicates the
quarter in which the item occurred. Certain other quarterly information is
presented on page 28.
o Refund and settlement of income tax matters - A gain of $4.9 million for
refund of U.S. income taxes was recorded in the third quarter of 1995.
Gains of $3.2 million and $3.5 million were recorded in the third and
fourth quarters, respectively, of 1995, for settlement of income tax
matters in the U.K. A gain of $2 million for settlement of income tax
matters in Gabon was recorded in the fourth quarter of 1995. A gain of $6.4
million for settlement of income tax matters in the U.K. was recorded in
the second quarter of 1994. Gains of $11.3 million and $3.1 million were
recorded in the first and fourth quarters, respectively, of 1993, for
refund and settlement of income tax matters in the U.K.
o Impairment of long-lived assets - An after-tax provision of $168.4 million
was recorded in the fourth quarter of 1995 for the write-down of assets
determined to be impaired under provisions of SFAS No. 121 (see Note B to
the consolidated financial statements).
o Provision for reduction-in-force - An after-tax provision of $4.2 million
was recorded in the fourth quarter of 1995 for the cost of enhanced early
retirement and severance programs.
o Adjustment of estimates for self-insured liabilities - An after-tax gain of
$7 million was recorded in the first quarter of 1995 from an adjustment of
amounts previously reserved relating to matters for which the Company is
self-insured. The pretax amount of the gain, $11 million, was included in
"Interest, Income from Equity Companies, and Other Nonoperating Revenues."
o Settlement of DOE matters - An after-tax gain of $13.9 million was recorded
in the third quarter of 1994 upon settlement of a dispute with the U.S.
Department of Energy (DOE) concerning the price at which the Company sold
certain of its crude oil production under regulations in effect from
September 1973 through January 1981. The pretax amount of the gain, $21
million, was included in "Interest, Income from Equity Companies, and Other
Nonoperating Revenues" (see Note P to the consolidated financial
statements).
o Provision for environmental remediation matters - An after-tax provision of
$4 million was recorded in the fourth quarter of 1993 for environmental
remediation matters. The pretax amount of $6.2 million was included in
"Crude Oil, Products, and Related Operating Expenses."
24
o Cumulative effect of changes in accounting principles - The first quarter of
1993 included a net benefit of $15.3 million for the cumulative effect of
accounting changes that were adopted effective January 1, 1993 (see Note B to
the consolidated financial statements).
Excluding the cumulative effect of changes in accounting principles in 1993,
the income (loss) effects of unusual or infrequently occurring items are
summarized by segment in the following table for the three years ended December
31, 1995.
- --------------------------------------------------------------------------------
(Millions of dollars) 1995* 1994 1993
- --------------------------------------------------------------------------------
Exploration and
production
United States ................... $ (1.1) -- --
United Kingdom .................. (18.4) 6.4 14.4
Other international ............. (100.6) -- --
- --------------------------------------------------------------------------------
(120.1) 6.4 14.4
- --------------------------------------------------------------------------------
Refining, marketing,
and transportation
United States ................... -- -- (3.9)
United Kingdom .................. (35.6) -- (.1)
- --------------------------------------------------------------------------------
(35.6) -- (4.0)
- --------------------------------------------------------------------------------
Corporate 3.7 13.9 --
- --------------------------------------------------------------------------------
Total $ (152.0) 20.3 10.4
================================================================================
* Includes after-tax effect of asset write-down under SFAS No. 121 as follows:
exploration and production - U.S., $6; U.K., $24.2; other international,
$102.6; refining, marketing, and transportation - U.K., $35.6.
Certain of the unusual or infrequently occurring items had a significant
effect on the Company's consolidated effective income tax rates (see Note F to
the consolidated financial statements).
CAPITAL EXPENDITURES
As shown in the selected financial information on page 20, capital
expenditures were $296.3 million in 1995 compared to $397.3 million in 1994 and
$620.7 million in 1993. These amounts included $55.1 million, $31.7 million, and
$34 million of exploration expenditures that were expensed. Also included were
$7.2 million in 1995, $26.6 million in 1994, and $259.7 million in 1993 for
acquisition of proved oil and gas properties. Capital expenditures for
exploration and production activities totaled $231.7 million in 1995, 78 percent
of the Company's total capital expenditures for the year. Excluding acquisition
of proved properties, exploration and production activities accounted for 76
percent of 1995 capital expenditures and totaled $224.5 million--$10.3 million
for acquisition of undeveloped leases, $65.3 million for exploration activities,
and $148.9 million for development projects. Development expenditures included
$53.9 million for the Hibernia oil field, offshore Newfoundland, and $17.6
million for oil fields in Ecuador. The expenditures for acquisition of proved
properties in 1995 included $4.2 million for heavy oil properties in Canada.
Exploration and production capital expenditures are shown by major operating
area on pages 46 and 47. Amounts shown under "Other" in 1995 include $4 million
for exploration costs in China, including an unsuccessful well drilled on Block
04/36 in Bohai Bay; $2.2 million for exploration costs in Pakistan; and $2.1
million in Spain, primarily for development of the Albatros field.
Refining, marketing, and transportation expenditures, detailed in the
following table, were $53.6 million in 1995, or 18 percent of total capital
expenditures, compared to $94.7 million in 1994 and $86.9 million in 1993.
- --------------------------------------------------------------------------------
(Millions of dollars) 1995 1994 1993
- --------------------------------------------------------------------------------
Refining
United States ................... $22.9 72.4 64.3
United Kingdom .................. 17.9 2.1 2.1
- --------------------------------------------------------------------------------
Total refining 40.8 74.5 66.4
- --------------------------------------------------------------------------------
Marketing
United States ................... 4.6 6.8 6.9
United Kingdom .................. 4.6 10.1 9.9
Canada .......................... -- .1 .1
- --------------------------------------------------------------------------------
Total marketing 9.2 17.0 16.9
- --------------------------------------------------------------------------------
Transportation
United States ................... .1 1.0 .2
Canada .......................... 3.5 2.2 3.4
- --------------------------------------------------------------------------------
Total transportation 3.6 3.2 3.6
- --------------------------------------------------------------------------------
Total $53.6 94.7 86.9
================================================================================
Refining expenditures in the U.S. included $12.7 million for environmental
projects, including wastewater treatment facilities at both of the Company's
U.S. refineries and a new sulfur recovery unit at the Meraux, Louisiana,
refinery, and $4.7 million for improved heavy, sour crude oil processing
facilities at Meraux. Refining expenditures in the U.K. included $16.4 million
for a distillate desulfurization unit under construction at year-end. Marketing
expenditures included the costs of sites and new service stations and
improvements and normal replacements at existing stations and terminals.
Capital expenditures for farm, timber, and real estate operations totaled
$9.1 million in 1995 compared to $11.4 million in 1994 and $9.7 million in 1993.
Expenditures in 1995 included $2.7 million for timber operations, primarily
related to expansion of the Waldo sawmill, and $4.6 million for real estate
operations.
[GRAPH--CAPITAL EXPENDITURES IN 1995]
25
CASH FLOWS
Cash provided by operating activities was $322.9 million in 1995, $337.3
million in 1994, and $363 million in 1993. Such amounts included cash provided
from unusual or infrequently occurring items of $14.7 million in 1995, $5.3
million in 1994, and $11.8 million in 1993. Changes in operating working capital
other than cash and cash equivalents required cash of $36.8 million in 1995 and
$16.2 million in 1994. In 1993, those changes provided $.4 million of cash. Cash
provided by operating activities was reduced by expenditures for refinery
turnarounds and abandonment of oil and gas properties totaling $13.8 million in
1995, $55.3 million in 1994, and $13.4 million in 1993. Additional borrowings
under nonrecourse debt arrangements provided $59.5 million of cash in 1995,
$42.8 million in 1994, and $27.7 million in 1993. Other long-term borrowings
also provided $28.2 million of cash in 1994.
Capital expenditures required $296.3 million of cash in 1995, $397.3
million in 1994, and $553.3 million in 1993. The 1993 amount excludes $67.4
million of noncash, seller-financed capital expenditures. Other significant cash
outlays during the three years included $35.7 million in 1995 and $11.1 million
in 1994 for reductions of debt. Cash used for dividends to stockholders was
$58.3 million in 1995, $58.2 million in 1994, and $55.9 million in 1993. The
Company also repurchased 48,400 shares of its Common Stock in 1993 for a cost of
$1.6 million.
FINANCIAL CONDITION
Year-end working capital totaled $104.5 million in 1995, $79.6 million in
1994, and $130.2 million in 1993. The current level of working capital does not
fully reflect the Company's liquidity position, as the relatively low historical
costs assigned to inventories under LIFO accounting were $70 million below
current costs at December 31, 1995. Cash and equivalents at the end of 1995
totaled $62.3 million compared to $71.1 million a year ago and $141.2 million at
year-end 1993.
Long-term obligations increased $21.4 million and were $193.9 million at
year-end, 15 percent of total capital employed, and included $171.5 million of
nonrecourse debt incurred in connection with acquisition and development of
proved properties. Long-term obligations totaled $172.5 million at the end of
1994 compared to $109.2 million at year-end 1993. Stockholders' equity was $1.1
billion at the end of 1995 compared to $1.3 billion a year ago and $1.2 billion
at the end of 1993. The decrease in 1995 was primarily attributable to the asset
write-down upon adoption of SFAS No. 121. A summary of transactions in the
equity accounts is presented on page 33.
The primary sources of the Company's liquidity are internally generated
funds, access to outside financing, and working capital. The Company relies on
internally generated funds to finance the major portion of its capital and other
expenditures, but maintains lines of credit with banks and borrows as necessary
to meet spending requirements. Current financing arrangements are set forth in
Note D to the consolidated financial statements. The Company also had a shelf
registration on file with the SEC that would permit the offer and sale of $250
million of debt securities. The Company does not anticipate any problem in
meeting future requirements for funds.
The Company had commitments of $268 million for capital projects in
progress at December 31, 1995.
ENVIRONMENTAL
The Company's worldwide operations are subject to numerous laws and
regulations designed to protect the environment and/or impose remedial
obligations. In addition, the Company may be involved in personal injury claims,
allegedly caused by exposure to materials manufactured or used in the Company's
operations. The Company operates or has previously operated certain sites or
facilities, including refineries, oil and gas fields, service stations, and
terminals, for which known or potential obligations for environmental
remediation exist.
Under the Company's accounting policies, liabilities for environmentally
related obligations are recorded when such obligations are probable and the cost
can be reasonably estimated. In instances where there is a range of reasonably
estimated costs, the Company will record the most likely amount, or if no amount
is most likely, the minimum of the range. Amounts recorded as liabilities are
reviewed quarterly and adjusted as needed. Actual cash expenditures often occur
a number of years after recognition of the liabilities.
The Company's reserve for remedial obligations, which is included in
"Deferred Credits and Other Liabilities" in the Consolidated Balance Sheets,
contains certain amounts that are based on anticipated regulatory approval of
proposed remediation of sites that were formerly used for refinery waste. If
regulatory authorities require more costly alternatives than the proposed
processes, future expenditures could increase by up to an estimated $6 million
above the amount reserved.
The Company has received notices from the U.S. Environmental Protection
Agency that it is a Potentially Responsible Party (PRP) at five Superfund sites
and has been assigned responsibility by defendants at another Superfund site.
The potential total cost to all parties to perform necessary remedial work at
these sites is substantial; however, based on information currently available,
the Company
26
is a de minimis party, with assigned or potentially assigned responsibility of
less than two percent at all but one of the sites. At that site, the Company has
not determined either its potentially assigned responsibility percentage or its
potential total remedial cost. The Company has recorded a reserve totaling $.1
million for Superfund sites, and due to currently available information on one
site and the minor percentages involved on the other sites, the Company does not
expect that its related remedial costs will be material to its financial
condition. Additional information may become known in the future that would
alter this assessment, including any requirement to bear a pro rata share of
costs attributable to nonparticipating PRP's or indications of additional
responsibility by the Company.
Although the Company is not aware of any environmental matters that might
have a material effect on the Company's financial condition, there is the
possibility that additional expenditures could be required at currently
unidentified sites, and new or revised regulatory requirements could necessitate
additional expenditures at known sites. Such expenditures could have a material
impact on the results of operations in a future period.
The Company believes that certain liabilities for environmentally related
obligations and prior environmental expenditures are either covered by insurance
or will be recovered from other sources. The outcome of potential insurance
recoveries is the subject of ongoing litigation, including the appeal of a
judgment awarded the Company in 1995. Since no assurance can be given that the
judgment will be upheld upon appeal or that recoveries from other sources will
occur, the Company has not recognized a benefit for these potential recoveries
at December 31, 1995.
The Company's refineries also incur costs to handle and dispose of hazardous
wastes and other chemical substances on a recurring basis. These costs are
generally expensed as incurred and amounted to $2.6 million in 1995.
In addition to remediation and other recurring expenditures, Murphy commits a
significant amount of its capital expenditure program for compliance with
environmental laws and regulations. Such capital expenditures were approximately
$45 million in 1995 and are expected to be $35 million in 1996.
OTHER MATTERS
o Impact of Inflation - General inflation was moderate during the last three
years in most countries where the Company operates; however, Murphy's
revenues and costs do not necessarily correlate to changes in the general
inflation rate. The Company's capital and operating costs are influenced to a
larger extent by specific price changes in the oil and gas and allied
industries than by changes in general inflation. Crude oil and petroleum
product prices generally reflect the balance between supply and demand, with
crude oil prices being particularly sensitive to OPEC production levels
and/or attitudes of traders concerning supply/demand balance in the near
future. Natural gas prices are affected by supply and demand (which to a
significant extent is weather-related) and by the fact that delivery of
supplies is generally restricted to specific geographical areas. Lumber and
farm commodities reflect the balance between supply and demand, while real
estate sales respond to changes in the general economy and interest rates.
o Other - The effects of exchange rate fluctuations on net income and the
Company's use of derivative financial instruments are reviewed in Notes G and
L, respectively, to the consolidated financial statements.
The Financial Accounting Standards Board issued Statement No. 123,
Accounting for Stock-Based Compensation, in October 1995. The statement
recommends use of a fair value method of accounting for stock-based employee
compensation plans but allows for continued use of the Company's present
accounting method established by Accounting Principles Board Opinion No. 25.
The Company expects to continue its present method of accounting for such
compensation but will be required by the new standard to make additional
disclosures in future years of pro forma net income and earnings per share as
if the new standard had been applied. The Company has not determined the pro
forma effect for 1995.
OUTLOOK
In planning for 1996, prices for the Company's products remain uncertain.
U.S. natural gas prices rose in late 1995 and early 1996; however, crude oil
prices have retreated in early 1996, and would be under further pressure if an
agreement were reached to remove the embargo on Iraqi crude oil sales. In
addition, the Company's three downstream systems were incurring losses
subsequent to year-end. In such an environment, constant reassessment of
spending plans is required. The Company's capital expenditure budget for 1996
was prepared during the fall of 1995 and provides for expenditures of $416
million. A major portion of this amount, $324 million or 78 percent, is
allocated for exploration and production. Geographically, about 33 percent of
the exploration and production budget is designated for the U.S.; 30 percent for
Canada, including $54 million for further development of the Hibernia oil field;
29 percent for the U.K., including development costs related to
27
the "T" Block, Schiehallion, and Mungo and Monan oil fields; four percent for
further development of oil fields in Ecuador; and the remaining four percent for
other overseas operations. Refining, marketing, and transportation capital
expenditures for 1996 are budgeted at $76 million. Such amount includes $51
million for refining operations and $19 million for marketing facilities. Other
budgeted expenditures include $14 million for farm, timber, and real estate,
primarily related to real estate and the sawmills, and $2 million for
miscellaneous items. Capital and other expenditures are under constant review,
and these budgeted amounts may be adjusted to reflect changes in estimated cash
flow.
QUARTERLY INFORMATION
- ------------------------------------------------------------------------------------------------------------------------------------
1995(1)
- ------------------------------------------------------------------------------------------------------------------------------------
FIRST SECOND THIRD FOURTH
(Millions of dollars except per share amounts) QUARTER QUARTER QUARTER QUARTER YEAR
- ------------------------------------------------------------------------------------------------------------------------------------
Sales and other operating revenues(2) ............... $404.0 444.0 417.5 425.7 1,691.2
Income (loss)before income taxes .................... 25.6 37.6 1.3 (198.5) (134.0)
Net income (loss) ................................... 16.0 20.6 7.6 (162.8) (118.6)
Per Common share
Net income (loss) ............................... .36 .46 .17 (3.63) (2.64)
Dividends ....................................... .325 .325 .325 .325 1.30
Market Price
High ............................................ 45 3/8 44 3/8 42 3/8 42 1/2 45 3/8
Low ............................................. 40 3/8 40 7/8 38 3/8 37 1/2 37 1/2
- ------------------------------------------------------------------------------------------------------------------------------------
1994(1)
- ------------------------------------------------------------------------------------------------------------------------------------
Sales and other operating revenues(2) ............... $398.3 421.5 442.5 406.5 1,668.8
Income before income taxes .......................... 41.1 33.7 57.9 24.2 156.9
Net income .......................................... 23.7 27.5 37.3 18.1 106.6
Per Common share
Net income ...................................... .53 .61 .83 .40 2.37
Dividends ....................................... .325 .325 .325 .325 1.30
Market Price
High ............................................ 44 3/4 46 47 3/8 49 1/8 49 1/8
Low ............................................. 37 7/8 40 42 1/8 40 1/2 37 7/8
- ------------------------------------------------------------------------------------------------------------------------------------
1 The effects of unusual or infrequently occurring gains (losses) on quarterly
net income are reviewed in Management's Discussion and Analysis. Quarterly
totals, in millions of dollars, and the effect per Common share of these
unusual or infrequently occurring items are reported in the following table.
------------------------------------------------------------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter Year
------------------------------------------------------------------------------------------------------------------------------
1995
Quarterly totals.................................... $7.0 -- 8.1 (167.1) (152.0)
Per Common share.................................... .16 -- .18 (3.73) (3.39)
------------------------------------------------------------------------------------------------------------------------------
1994
Quarterly totals.................................... $ -- 6.4 13.9 -- 20.3
Per Common share.................................... -- .14 .31 -- .45
------------------------------------------------------------------------------------------------------------------------------
2 Each quarterly period in 1994 and the first three quarters of 1995 have been
reclassified to conform to 1995 presentation.
Market prices of Common Stock are as quoted on the New York Stock Exchange.
There were 4,873 stockholders of record at December 31, 1995.
28
REPORT OF MANAGEMENT
Preparation and integrity of the accompanying consolidated financial
statements and other financial data are the responsibility of management. The
statements were prepared in conformity with generally accepted accounting
principles appropriate in the circumstances and include some amounts based on
informed estimates and judgments, with consideration given to materiality.
Management is also responsible for maintaining a system of internal
accounting controls designed to provide reasonable assurance (but not absolute)
that financial information is objective and reliable by ensuring that all
transactions are properly recorded in the Company's accounts and records,
written policies and procedures are followed, and assets are safeguarded. The
system is also supported by careful selection and training of qualified
personnel. When establishing and maintaining such a system, judgment is required
to weigh relative costs against expected benefits. Effectiveness of the
controls is monitored by the Company's audit staff, which independently and
systematically evaluates and formally reports on the adequacy and effectiveness
of components of the system.
Our independent auditors, KPMG Peat Marwick LLP, have audited the
consolidated financial statements. Their audit was conducted in accordance with
generally accepted auditing standards and provides an independent opinion about
the fair presentation of the consolidated financial statements. When performing
their audit, KPMG Peat Marwick LLP considers the Company's internal control
structure to the extent they deem necessary to issue their opinion on the
financial statements. The Board of Directors appoints the independent
auditors; ratification of the appointment is solicited annually from the
shareholders.
Annually the Board of Directors appoints an Audit Committee to perform an
oversight role for the financial statements. This Committee is composed solely
of directors who are not employees of the Company. The Committee meets
periodically with representatives of management, the Company's audit staff, and
the independent auditors to review the Company's internal controls, the quality
of its financial reporting, and the scope and results of audits. The independent
auditors and the Company's audit staff have unrestricted access to the
Committee, without management's presence, to discuss audit findings and other
financial matters.
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Murphy Oil Corporation:
We have audited the accompanying consolidated balance sheets of Murphy Oil
Corporation and Consolidated Subsidiaries as of December 31, 1995 and 1994, and
the related consolidated statements of income, stockholders' equity and cash
flows for each of the years in the three-year period ended December 31, 1995.
These consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Murphy Oil
Corporation and Consolidated Subsidiaries as of December 31, 1995 and 1994, and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 1995, in conformity with generally
accepted accounting principles.
As discussed in Note B to the consolidated financial statements, in 1995 the
Company adopted the provisions of Financial Accounting Standards Board's
Statement of Financial Accounting Standards No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. In
addition, in 1993 the Company adopted the provisions of Statement of Financial
Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions, and Statement of Financial Accounting Standards No. 109,
Accounting for Income Taxes.
KPMG PEAT MARWICK LLP
Shreveport, Louisiana
March 1, 1996
29
CONSOLIDATED STATEMENTS OF INCOME
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars except per share amounts)
- ------------------------------------------------------------------------------------------------------------------------------------
Years Ended December 31 1995 1994* 1993*
- ------------------------------------------------------------------------------------------------------------------------------------
REVENUES
Sales ........................................................................... $1,646,053 1,620,847 1,572,849
Other operating revenues ........................................................ 45,189 47,975 52,813
Interest, income from equity companies, and other nonoperating revenues ......... 19,971 30,341 16,514
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues 1,711,213 1,699,163 1,642,176
- ------------------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Crude oil, products, and related operating expenses ............................. 1,274,780 1,231,497 1,220,397
Exploration expenses, including undeveloped lease amortization .................. 65,755 42,741 46,071
Selling and general expenses .................................................... 67,461 66,579 65,195
Depreciation, depletion, and amortization ....................................... 225,924 198,885 174,686
Impairment of long-lived assets ................................................. 198,988 -- --
Provision for reduction-in-force ................................................ 6,610 -- --
Interest expense ................................................................ 14,737 12,403 7,614
Interest capitalized ............................................................ (9,015) (9,842) (5,414)
- ------------------------------------------------------------------------------------------------------------------------------------
Total costs and expenses 1,845,240 1,542,263 1,508,549
- ------------------------------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes ............................................... (134,027) 156,900 133,627
Federal and state income taxes (benefits) ....................................... (839) 37,536 40,383
Foreign income taxes (benefits) ................................................. (14,576) 12,736 6,446
- ------------------------------------------------------------------------------------------------------------------------------------
Income (loss) before cumulative effect of changes in accounting principles ...... (118,612) 106,628 86,798
Cumulative effect of changes in accounting principles ........................... -- -- 15,338
- ------------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) ............................................................... $ (118,612) 106,628 102,136
====================================================================================================================================
PER COMMON SHARE
Income (loss) before cumulative effect of changes in accounting principles ...... $ (2.64) 2.37 1.94
Cumulative effect of changes in accounting principles ........................... -- -- .34
- ------------------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ (2.64) 2.37 2.28
====================================================================================================================================
Average Common shares outstanding 44,866,699 44,882,182 44,856,635
====================================================================================================================================
* Reclassified to conform to 1995 presentation.
See notes to consolidated financial statements, page 34.
30
CONSOLIDATED BALANCE SHEETS
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
December 31 1995 1994*
- ------------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents ................................................................ $ 62,284 71,144
Accounts receivable, less allowance for doubtful accounts
of $5,863 in 1995 and $5,554 in 1994 ................................................... 234,816 244,241
Inventories
Crude oil and raw materials .......................................................... 70,567 71,541
Finished products .................................................................... 64,996 44,890
Materials and supplies ............................................................... 40,239 36,000
Prepaid expenses ......................................................................... 29,703 36,357
Deferred income taxes .................................................................... 17,514 14,939
- ------------------------------------------------------------------------------------------------------------------------------------
Total current assets ............................................................. 520,119 519,112
Investments and noncurrent receivables ....................................................... 31,735 28,592
Property, plant, and equipment, at cost less accumulated depreciation,
depletion, and amortization of $2,702,485 in 1995 and $2,342,421 in 1994 ................... 1,487,232 1,670,934
Deferred charges and other assets ............................................................ 80,027 93,394
- ------------------------------------------------------------------------------------------------------------------------------------
$ 2,119,113 2,312,032
====================================================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term obligations .............................................. $ 10,640 7,615
Accounts payable ......................................................................... 299,189 309,795
Withholdings and collections due governmental agencies ................................... 35,603 35,090
Accrued insurance obligations ............................................................ 15,272 23,105
Other accrued liabilities ................................................................ 33,599 35,563
Income taxes ............................................................................. 21,307 28,350
- ------------------------------------------------------------------------------------------------------------------------------------
Total current liabilities ........................................................ 415,610 439,518
Notes payable and capitalized lease obligations .............................................. 22,436 49,814
Nonrecourse debt of a subsidiary ............................................................. 171,499 122,638
Deferred income taxes ........................................................................ 105,015 140,610
Reserve for dismantlement costs .............................................................. 144,893 138,894
Reserve for major repairs .................................................................... 11,417 3,244
Deferred credits and other liabilities ....................................................... 147,098 146,635
Stockholders' equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued ............. -- --
Common Stock, par $1.00, authorized 80,000,000 shares, issued 48,775,314 shares .......... 48,775 48,775
Capital in excess of par value ........................................................... 507,758 507,797
Retained earnings ........................................................................ 643,699 820,568
Currency translation adjustments ......................................................... 4,568 (2,403)
Unamortized restricted stock awards ...................................................... (592) (993)
Treasury stock ........................................................................... (103,063) (103,065)
- ------------------------------------------------------------------------------------------------------------------------------------
Total stockholders' equity 1,101,145 1,270,679
- ------------------------------------------------------------------------------------------------------------------------------------
$ 2,119,113 2,312,032
====================================================================================================================================
*Reclassified to conform to 1995 presentation.
See notes to consolidated financial statements, page 34.
31
CONSOLIDATED STATEMENTS OF CASH FLOWS
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Years Ended December 31 1995 1994* 1993*
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Income (loss) before cumulative effect of changes in accounting principles ....... $(118,612) 106,628 86,798
Adjustments to reconcile above income (loss) to net cash provided
by operating activities
Depreciation, depletion, and amortization ..................................... 225,924 198,885 174,686
Impairment of long-lived assets ............................................... 198,988 -- --
Provisions for major repairs .................................................. 25,375 22,571 17,679
Expenditures for major repairs and dismantlement costs ........................ (13,820) (55,284) (13,391)
Exploratory expenditures charged against income ............................... 55,055 31,696 33,945
Amortization of undeveloped leases ............................................ 10,700 11,045 12,126
Deferred and noncurrent income tax charges (credits) .......................... (47,167) 21,328 36,970
Gains from disposition of assets .............................................. (3,140) (1,575) (1,474)
Other - net ................................................................... 18,257 1,102 16,270
- ------------------------------------------------------------------------------------------------------------------------------------
(Increase) decrease in operating working capital other than cash
and cash equivalents ........................................................ (36,800) (16,189) 418
Cumulative effect of accounting changes on working capital .................... -- -- 25,437
Net recoveries (expenditures) on insurance claim
to repair hurricane damage .................................................. 7,619 14,673 (18,172)
Other adjustments related to operating activities ............................. 560 2,403 (8,319)
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 322,939 337,283 362,973
- ------------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures requiring cash .............................................. (296,284) (397,324) (553,309)
Proceeds from sale of property, plant, and equipment ............................. 8,408 5,506 5,721
Other - net ...................................................................... (10,375) (17,546) (14,396)
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash required by investing activities (298,251) (409,364) (561,984)
- ------------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Additions to notes payable and capitalized lease obligations ..................... 751 28,248 161
Reductions of notes payable and capitalized lease obligations .................... (28,128) (3,437) (3,738)
Additions to nonrecourse debt of a subsidiary .................................... 59,489 42,793 27,693
Reduction of nonrecourse debt of a subsidiary .................................... (7,604) (7,614) --
Decrease in short-term notes payable ............................................. -- -- (2,795)
Dividends paid ................................................................... (58,257) (58,232) (55,945)
Purchase of Common Stock for treasury ............................................ -- -- (1,636)
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided (required) by financing activities (33,749) 1,758 (36,260)
- ------------------------------------------------------------------------------------------------------------------------------------
Effect of exchange rate changes on cash and cash equivalents 201 242 (1,349)
- ------------------------------------------------------------------------------------------------------------------------------------
Net decrease in cash and cash equivalents ........................................ (8,860) (70,081) (236,620)
Cash and cash equivalents at January 1 ........................................... 71,144 141,225 377,845
- ------------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT DECEMBER 31 $ 62,284 71,144 141,225
====================================================================================================================================
* Reclassified to conform to 1995 presentation.
See notes to consolidated financial statements, page 34.
32
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Years Ended December 31 1995 1994 1993
- ------------------------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK - par $100, authorized
400,000 shares, none issued $ -- -- --
- ------------------------------------------------------------------------------------------------------------------------------------
COMMON STOCK - par $1.00, authorized 80,000,000 shares,
issued 48,775,314 shares at beginning and end of year 48,775 48,775 48,775
- ------------------------------------------------------------------------------------------------------------------------------------
CAPITAL IN EXCESS OF PAR VALUE
Balance at beginning of year ....................................................... 507,797 507,292 506,962
Exercise and surrender of stock options ............................................ 40 226 224
Restricted stock transactions ...................................................... (79) 279 106
- ------------------------------------------------------------------------------------------------------------------------------------
Capital in excess of par value at end of year 507,758 507,797 507,292
- ------------------------------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance at beginning of year ....................................................... 820,568 772,172 725,981
Net income (loss) for the year ..................................................... (118,612) 106,628 102,136
Cash dividends - $1.30 a share in 1995 and 1994 and $1.25 a share in 1993 .......... (58,257) (58,232) (55,945)
- ------------------------------------------------------------------------------------------------------------------------------------
Retained earnings at end of year 643,699 820,568 772,172
- ------------------------------------------------------------------------------------------------------------------------------------
CURRENCY TRANSLATION ADJUSTMENTS
Balance at beginning of year ....................................................... (2,403) (1,514) 21,595
Translation gains (losses) during the year ......................................... 6,971 (889) (23,109)
- ------------------------------------------------------------------------------------------------------------------------------------
Currency translation adjustments at end of year 4,568 (2,403) (1,514)
- ------------------------------------------------------------------------------------------------------------------------------------
UNAMORTIZED RESTRICTED STOCK AWARDS
Balance at beginning of year ....................................................... (993) (660) (835)
Stock awards ....................................................................... -- (800) --
Amortization, forfeitures, and changes in price of Common Stock .................... 401 467 175
- ------------------------------------------------------------------------------------------------------------------------------------
Unamortized restricted stock awards at end of year (592) (993) (660)
- ------------------------------------------------------------------------------------------------------------------------------------
TREASURY STOCK
Balance at beginning of year ....................................................... (103,065) (103,715) (102,390)
Cost of shares purchased ........................................................... -- -- (1,636)
Exercise and surrender of stock options ............................................ 67 308 360
Awarded restricted stock, net of forfeitures ....................................... (65) 342 (49)
- ------------------------------------------------------------------------------------------------------------------------------------
Treasury stock at end of year - 3,942,800 shares of Common Stock in 1995,
3,942,868 shares in 1994, and 3,967,631 shares in 1993, at cost (103,063) (103,065) (103,715)
- ------------------------------------------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY $ 1,101,145 1,270,679 1,222,350
====================================================================================================================================
See notes to consolidated financial statements, page 34.
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE A - SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation - The consolidated financial statements include the
accounts of Murphy Oil Corporation and all majority-owned subsidiaries.
Investments in 20- to 50-percent owned companies are accounted for by the equity
method. Other investments are generally carried at cost. All significant
intercompany accounts and transactions have been eliminated.
Cash Equivalents - Short-term investments (which include government securities
or other securities with government securities as collateral) that have a
maturity of three months or less from the date of purchase are classified as
cash equivalents.
Inventories - Inventories of crude oil and refined products are generally valued
at cost applied on a last-in, first-out (LIFO) basis, which in the aggregate is
lower than market. Raw materials and lumber are stated at the lower of average
cost or market. Materials and supplies are valued at the lower of average cost
or estimated value.
Property, Plant, and Equipment - The Company uses the successful efforts method
of accounting for exploration and development expenditures. Leasehold
acquisition costs are capitalized. When proved reserves are found on an
undeveloped property, leasehold cost is reclassified to proved properties.
Significant undeveloped leases are reviewed periodically, and a valuation
allowance is provided for any estimated decline in value. Cost of all other
undeveloped leases is amortized over the estimated average holding period of the
leases. Costs of exploratory drilling are initially capitalized, but if proved
reserves are not found, the costs are subsequently expensed. All other
exploratory costs are charged to expense as incurred. Development costs are
capitalized, including the cost of unsuccessful development wells.
Effective October 1, 1995, the Company adopted Statement of Financial Accounting
Standards (SFAS) No. 121, Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of. Under SFAS No. 121, oil and gas
properties are evaluated by field for potential impairment; other long-lived
assets are evaluated on a specific asset basis or in groups of similar assets,
as applicable. An impairment is recognized when the undiscounted estimated
future net cash flows of an evaluated asset are less than the carrying value of
the asset. Previously, worldwide undiscounted future net cash flows for oil and
gas properties were compared annually to net capitalized cost of proved
properties to determine if an impairment had occurred. As warranted by events,
significant, high-cost properties were assessed for permanent impairment based
on discounted future net cash flows.
Depreciation and depletion of producing oil and gas properties are provided
under the unit-of-production method. Developed reserves are used to compute unit
rates for unamortized development costs, and proved reserves are used for
unamortized leasehold costs. Estimated dismantlement, abandonment, and site
restoration costs, net of salvage value, are considered in determining
depreciation and depletion. Depreciation of refining and marketing facilities is
calculated using the composite straight-line method. Depletion of timber is
based on board feet cut. Other properties are depreciated by individual unit
based on the straight-line method.
Gains and losses on disposals or retirements that are significant or include an
entire depreciable or depletable property unit are included in income. Costs of
dismantling oil and gas production facilities and site restoration are charged
against the related reserve. All other dispositions, retirements, or
abandonments are reflected in accumulated depreciation, depletion, and
amortization.
Provisions are made for refinery turnarounds by monthly charges to expense.
Costs incurred are charged against the reserve. All other maintenance and repair
costs are charged to expense. Renewals and betterments are capitalized.
Environmental Liabilities - A provision for environmentally related obligations
is recorded by a charge to expense when it is determined that the Company's
liability for an environmental assessment and/or cleanup is probable and the
cost can be reasonably estimated. Related expenditures are charged against the
reserve. Environmental expenditures that have future economic benefit are
capitalized.
Income Taxes - The Company uses the asset and liability method of accounting for
income taxes. Under this method, the provision for income taxes includes amounts
currently payable and amounts deferred as tax assets and liabilities based on
differences between the financial statement carrying amounts and the tax bases
of existing assets and liabilities and measured using the enacted tax rates that
are assumed will be in effect when the differences reverse. Provision for
petroleum revenue taxes payable to the U.K. government is based on the estimated
effective tax rate over the life of certain U.K. properties.
Foreign Currency Translation - Local currency is the "functional currency" used
for recording operations in Canada and Spain and the majority of activities in
the U.K. and Gabon. The U.S. dollar is the functional currency used to record
all other operations. Gains or losses that result from translating accounts from
foreign functional currencies into U.S. dollars are included in "Currency
Translation Adjustments" in stockholders' equity. Gains or losses that result
from specific transactions in a currency other than the functional currency are
included in income.
Derivatives - Unrealized gains and losses under oil swap and buy/sell agreements
are deferred unless the projected cost of future crude oil purchases, including
settlement costs, exceeds the projected realizable value of related finished
products. Realized gains and losses are included in "Other Operating Revenues."
Unrealized gains and losses related to foreign currency contracts are deferred
and recognized in income or as adjustments to the carrying amounts when the
hedged transactions occur.
Excise Taxes on Refined Products - Taxes collected on the sales of refined
products and remitted to governmental agencies are not included in revenues or
costs and expenses.
Net Income per Common Share - This amount is computed by dividing net income for
each reporting period by the weighted average number of Common and Common
equivalent (stock options when dilutive) shares outstanding during the period.
Use of Estimates - In the preparation of financial statements of the Company in
conformity with generally accepted accounting principles, management has made a
number of estimates and assumptions related to the reporting of assets and
liabilities and the disclosure of contingent assets and liabilities. Actual
results may differ from the estimates.
34
NOTE B - ACCOUNTING CHANGES - Effective October 1, 1995, the Company adopted
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of. The effects of this accounting change were
a reduction in the carrying value of property, plant, and equipment by
$198,988,000 and a $168,367,000, $3.75 a share, reduction of income after
associated income tax benefit. The asset impairments resulted from management's
expectation of a continuation into the foreseeable future of the low-price
environment for crude oil, natural gas, and petroleum products that has
confronted the oil and gas industry throughout most of 1995. The carrying values
for assets determined to be impaired were adjusted to fair values based on
estimated future net cash flows for such assets, discounted at a market rate of
interest. Properties determined to be impaired were certain oil and gas assets
(Ecuadoran fields; two fields in the U.K. North Sea; four U.S. fields, primarily
in the Gulf of Mexico; and a property in Spain) and U.K. refining and marketing
assets.
Effective January 1, 1993, the Company elected the immediate recognition basis
for implementing SFAS No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions. This accounting standard requires that these costs
(supplemental health care and life insurance) be accrued over the service lives
of employees. The cumulative effect upon adoption was a charge against income of
$16,502,000, $.37 a share, after an income tax effect of $8,500,000. Excluding
the cumulative effect, adoption of the standard did not significantly affect
1993 net income.
Effective January 1, 1993, the Company also adopted SFAS No. 109, Accounting for
Income Taxes, without restating prior years' results. The cumulative effect of
the change on 1993 net income was a benefit of $31,840,000, $.71 a share. In
addition, net property, plant, and equipment was increased $82,092,000, and a
corresponding increase was recorded in deferred income tax liability,
representing the tax effect of prior business combinations originally recorded
net of tax. As a result of adopting SFAS No. 109, 1993 income before income
taxes was reduced $10,916,000. This reduction was primarily due to increased
depreciation, depletion, and amortization expense caused by the adjustment for
prior business combinations. The increased expense was essentially offset by
additional deferred tax benefits.
NOTE C - PROPERTY, PLANT, AND EQUIPMENT
- ------------------------------------------------------------------------------------------------------------------------------------
INVESTMENT Investment
(Thousands of dollars) DECEMBER 31, 1995 December 31, 1994
- ------------------------------------------------------------------------------------------------------------------------------------
COST NET(1) Cost Net
- ------------------------------------------------------------------------------------------------------------------------------------
Exploration and
production ........................... $3,163,843 975,801(3) 3,035,153(2) 1,123,954(2,3)
Refining ................................ 601,869 257,497 562,101 278,629
Marketing ............................... 160,234 92,734 156,501 104,832
Transportation .......................... 67,258 34,315 63,013 33,296
Farm, timber, and
real estate .......................... 165,119 109,778 166,061 112,217
Corporate and other ..................... 31,394 17,107 30,526 18,006
- ------------------------------------------------------------------------------------------------------------------------------------
$4,189,717 1,487,232 4,013,355 1,670,934
====================================================================================================================================
1 As a result of adopting SFAS No. 121 effective October 1, 1995, net
investment was reduced $150,301 for exploration and production, $37,085 for
refining, and $11,602 for marketing.
2 Reclassified to conform to 1995 presentation.
3 Includes $17,239 in 1995 and $17,277 in 1994 related to administrative assets
and support equipment.
The Company leases land, service stations, and other facilities under operating
leases. Future minimum rental commitments under noncancelable operating leases
are not material. Commitments for capital expenditures were approximately
$268,000,000 at December 31, 1995.
NOTE D - FINANCING ARRANGEMENTS - At December 31, 1995, the Company had three
committed credit facilities with major banks totaling an equivalent US
$313,526,000 for a combination of U.S. dollar and Canadian dollar borrowings.
Depending upon the credit facility, borrowings bear interest at prime or various
cost of funds options. Facility fees are due at varying rates on certain of the
commitments. The facilities expire at dates ranging from 1996 through 1999. At
December 31, 1995, U.S. dollar and Canadian dollar commercial paper totaling an
equivalent US $110,296,000, classified as long-term nonrecourse debt, was
outstanding under one credit facility. At December 31, 1994, outstanding debt
supported by two facilities totaled US $97,862,000, of which $69,862,000 was
classified as long-term nonrecourse debt of a subsidiary and $28,000,000 as
long-term notes payable. In addition, the Company had lines of credit with banks
totaling an equivalent US $160,521,000 for a combination of U.S. dollar and
Canadian dollar borrowings. These lines could be withdrawn at any time, and no
amounts were outstanding at December 31, 1995.
At year-end 1995, the Company had a shelf registration on file with the
Securities and Exchange Commission that would permit the offer and sale of
$250,000,000 in debt securities. No securities had been issued as of December
31, 1995.
NOTE E - LONG-TERM OBLIGATIONS
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
December 31 1995 1994
- ------------------------------------------------------------------------------------------------------------------------------------
Notes payable
Note payable to bank, 10.1%, due 2004 ........................................... $ 20,000 20,000
Notes payable to bank, 6.3125%* to 6.75%*,
due 1999 ...................................................................... -- 28,000
Other notes due 1996-2000 ....................................................... 797 170
- ------------------------------------------------------------------------------------------------------------------------------------
Subtotal 20,797 48,170
- ------------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations due 1996-2022; 6%, 8% 1,651 1,655
- ------------------------------------------------------------------------------------------------------------------------------------
Nonrecourse debt of a subsidiary
Guaranteed credit facility with bank
Commercial paper, 5.655% to 5.855%,
$40,896 payable in Canadian dollars,
supported by credit facility, due 1997 .................................. 110,296 --
Credit facility drawdown from bank, 6.1875%
to 7.455%, due 1996 ..................................................... -- 69,862
Loan payable to Canadian government, interest
free, due 1999-2008, payable in Canadian dollars .............................. 19,055 --
Promissory note, 6.25%, due 1996-1998,
payable in Canadian dollars .................................................. 52,776 60,380
- ------------------------------------------------------------------------------------------------------------------------------------
Subtotal 182,127 130,242
- ------------------------------------------------------------------------------------------------------------------------------------
Total ................................................................ 204,575 180,067
Current maturities ................................................................. (10,640) (7,615)
- ------------------------------------------------------------------------------------------------------------------------------------
Total long-term obligations $ 193,935 172,452
====================================================================================================================================
* Interest rates fluctuate in relation to bank's cost of funds.
35
Amounts becoming due for the four years after 1996 are: 1997, $13,644,000; 1998,
$28,530,000; 1999, $2,670,000; and 2000, $1,921,000.
The nonrecourse guaranteed credit facility was arranged to finance expenditures
for the Hibernia oil field, in which the Company owns a 6.5-percent interest.
Subject to certain conditions and limitations, the Canadian government has
provided an unconditional guarantee of repayment of amounts drawn
under/supported by the credit facility to lenders that possess qualifying
Participation Certificates. The Company's maximum eligible borrowing available
under the guarantee is Cdn $154,900,000 (US $113,526,000 at December 31, 1995
currency exchange rate). The Company also received other commitments from the
Canadian government, including grants and additional guarantees and
interest-free loans. The amount guaranteed declines quarterly beginning the
earlier of January 1, 2000 or two years after cumulative production reaches 25
million barrels; no guaranteed financing is available after January 1, 2016. A
guarantee fee of .5 percent is payable annually in arrears to the Canadian
government. Since the Company intends to refinance outstanding debt under the
guaranteed credit facility, the debt is not reflected as becoming due in 1997.
The 6.25-percent promissory note of Cdn $69,970,000 (US $52,776,000 at a hedged
exchange rate) is payable to the province of Alberta and is secured by a
debenture, which mortgages the Company's five-percent interest in the Syncrude
project and its share of production therefrom. The province's right to recover
the principal and interest on the note is limited to the mortgaged property and
funds available from that production.
NOTE F - INCOME TAXES - The Company adopted SFAS No. 109, Accounting for Income
Taxes, effective January 1, 1993 without restating prior years. Total income tax
expense of $38,329,000 for 1993 included $46,829,000 allocated to income before
income taxes, partially offset by a benefit of $8,500,000 allocated to the
cumulative effect of a change in accounting for postretirement benefits.
The components of income (loss) before income taxes and income tax expense
(benefit) were as follows.
- --------------------------------------------------------------------------------
(Thousands of dollars) 1995 1994 1993
- --------------------------------------------------------------------------------
Income (loss) before income taxes
United States .............. $ 9,127 105,695 84,563
Foreign .................... (143,154) 51,205 49,064
- --------------------------------------------------------------------------------
$(134,027) 156,900 133,627
================================================================================
Income tax expense (benefit)
Federal - Current* ......... $ 10,248 6,010 29,941
Deferred ......... (21,030) 23,682 97
Noncurrent ....... 9,008 3,708 4,977
- --------------------------------------------------------------------------------
(1,774) 33,400 35,015
- --------------------------------------------------------------------------------
State - Current 935 4,136 5,368
- --------------------------------------------------------------------------------
Foreign - Current .......... 22,929 15,398 (32,029)
Deferred ......... (19,580) 183 28,154
Noncurrent ....... (17,925) (2,845) 10,321
- --------------------------------------------------------------------------------
(14,576) 12,736 6,446
- --------------------------------------------------------------------------------
$ (15,415) 50,272 46,829
================================================================================
* Net of benefits of $4,273 in 1995, $1,923 in 1994, and $5,757 in 1993 for
alternative minimum tax credit and $8,079 in 1993 for net operating loss
carryforward.
Noncurrent taxes relate to petroleum revenue taxes payable to the U.K.
government ($6,330,000 and $24,461,000 at December 31, 1995 and 1994 and
classified in the Consolidated Balance Sheet as "Deferred Credits and Other
Liabilities") and to matters not resolved with various taxing authorities. The
significant components of deferred income tax expense (benefit) attributable to
income (loss) before income taxes for the years ended December 31, 1995, 1994,
and 1993 were as follows.
- --------------------------------------------------------------------------------
(Thousands of dollars) 1995 1994 1993
- --------------------------------------------------------------------------------
Deferred tax expense (exclusive of the
effects of components listed below
on deferred tax assets and liabilities
at the beginning of each year) ......... $(36,283) 23,883 18,270
Adjustments for enacted changes in tax
laws and rates ......................... -- -- 190
Estimated net operating loss and tax credit
carryforward (increase) decrease ....... (4,327) (18) 9,791
- --------------------------------------------------------------------------------
Total deferred tax expense (benefit) $(40,610) 23,865 28,251
================================================================================
Following is a reconciliation of the U.S. statutory income tax rate to the
Company's effective rates on income (loss) before income taxes.
- --------------------------------------------------------------------------------
1995 1994 1993
- --------------------------------------------------------------------------------
U.S. statutory income tax rate ................... (35)% 35% 35%
Foreign asset impairment with no tax benefit ..... 27 -- --
Foreign income subject to foreign
taxes at greater than U.S. statutory rate ..... 7 2 7
Refund and settlement of foreign tax matters ..... (6) (4) (11)
Refund and settlement of U.S. tax matters ........ (6) (2) --
State income taxes ............................... 1 2 3
Other, net ....................................... -- (1) 1
- --------------------------------------------------------------------------------
Effective income tax rates (12)% 32% 35%
================================================================================
An analysis of the Company's deferred tax assets and deferred tax liabilities at
December 31, 1995 and 1994 showing the tax effects of significant temporary
differences follows.
- --------------------------------------------------------------------------------
(Thousands of dollars) 1995 1994
- --------------------------------------------------------------------------------
Deferred tax assets
Property and leasehold costs ................... $ 60,540 64,700
Reserves for dismantlement
costs and major repairs ...................... 52,766 47,372
Federal alternative minimum
tax credit carryforward* ..................... 8,243 3,916
Postretirement and other employee benefits ..... 18,686 16,902
Other deferred tax assets ...................... 30,413 34,237
- --------------------------------------------------------------------------------
Total gross deferred tax assets ............ 170,648 167,127
Less valuation allowance ....................... (34,597) (39,315)
- --------------------------------------------------------------------------------
Net deferred tax assets 136,051 127,812
- --------------------------------------------------------------------------------
Deferred tax liabilities
Property, plant, and equipment ................. (49,071) (56,689)
Accumulated depreciation,
depletion, and amortization .................. (149,503) (167,388)
Other deferred tax liabilities ................. (25,391) (29,685)
- --------------------------------------------------------------------------------
Total gross deferred tax liabilities (223,965) (253,762)
- --------------------------------------------------------------------------------
Net deferred tax liabilities $ (87,914) (125,950)
================================================================================
* Available to reduce future U.S. federal income taxes over an indefinite
period.
In management's judgment, the net deferred tax assets in the preceding table
will more likely than not be realized as reductions of future taxable income
or by utilizing available tax planning strategies. The valuation allowance for
deferred tax assets decreased $4,718,000 in 1995 after increasing
36
$6,235,000 in 1994; the change in each year offset the change in certain
deferred tax assets. Any subsequent reductions of the valuation allowance will
be reported as reductions of income tax expense assuming no offsetting change in
the deferred tax asset.
The Company has not recorded a deferred tax liability of $7,809,000 related to
undistributed earnings of certain foreign subsidiaries at December 31, 1995,
because the earnings are considered permanently invested.
Income tax returns are subject to audit by the Internal Revenue Service and tax
authorities of other countries. In 1995, 1994, and 1993, the Company recorded
benefits to income of $13,603,000, $6,365,000, and $14,409,000, respectively,
from settlement of various U.S. and foreign tax issues related to prior years.
The Company believes that adequate accruals have been made for unsettled issues.
NOTE G - CURRENCY TRANSLATION - Cumulative translation gains and losses are
included as a separate component of stockholders' equity. At December 31, 1995,
components of the net cumulative gain of $4,568,000 were gains of $22,381,000
for pounds sterling, $1,470,000 for Spanish pesetas, and $314,000 for Gabonese
francs, partially offset by a loss of $19,597,000 for Canadian dollars. Most of
the amounts translated into U.S. dollars are from transactions denominated in
pounds sterling or Canadian dollars. Comparability of net income was not
significantly affected in 1995, 1994, or 1993 by exchange rate fluctuations.
NOTE H - STOCKHOLDER RIGHTS PLAN - The Company has a Stockholder Rights Plan,
which provides for each Common stockholder to receive a dividend of one Right
for each share of the Company's Common Stock held. The Rights will expire on
December 6, 1999, unless earlier redeemed or exchanged. The Rights will detach
from the Common Stock and become exercisable following a specified period of
time, subject to extension, after the date of the first public announcement that
a person or group of affiliated or associated persons (other than certain
persons) has become the beneficial owner of 15 percent or more of the Company's
Common Stock.
The Rights have certain antitakeover effects and will cause substantial dilution
to a person or group that attempts to acquire the Company without conditioning
the offer on a substantial number of Rights being acquired. The Rights are not
intended to prevent a takeover, but rather are designed to enhance the ability
of the Board of Directors to negotiate with an acquiror on behalf of all
shareholders.
Other terms of the Rights are set forth in, and the foregoing description is
qualified in its entirety by, the Rights Agreement between the Company and
Harris Trust Company of New York, as Rights Agent.
NOTE I - INCENTIVE PLANS - At December 31, 1995, the Company had a Stock
Incentive Plan, approved by the stockholders in 1992, that permits annual
awards of shares of the Company's Common Stock to executives and other key
employees. Under the Plan, the Executive Compensation Committee (the Committee)
is authorized to grant: (1) stock options (nonqualified or incentive), (2) stock
appreciation rights (SAR), and (3) restricted stock awards. Options for 94,855
shares were outstanding at December 31, 1995 under two prior plans that have
expired.
Changes in options outstanding under the Company's plans, excluding restricted
stock awards, were as follows.
- --------------------------------------------------------------------------------
Number Average
of Shares Price
- --------------------------------------------------------------------------------
Outstanding January 1, 1993 ................... 341,036 $35.87
Granted ....................................... 81,000 36.31
Surrendered ................................... (45,019) 29.58
- ------------------------------------------------------------
Outstanding December 31, 1993 ................. 377,017 36.72
Granted ....................................... 69,500 39.94
Surrendered ................................... (54,950) 34.86
Expired ....................................... (51,837) 41.18
- ------------------------------------------------------------
Outstanding December 31, 1994 ................. 339,730 37.00
Granted ....................................... 142,000 43.94
Surrendered ................................... (33,250) 35.86
Expired ....................................... (23,250) 39.20
- ------------------------------------------------------------
Outstanding December 31, 1995 425,230 39.28
================================================================================
Exercisable December 31, 1994 ................. 147,480 $36.32
Exercisable December 31, 1995 ................. 198,355 36.31
================================================================================
Cost of options reported in the preceding table is accrued over the vesting
periods and adjusted for subsequent changes in fair market value of the shares.
Charges against (credits to) income were $(163,000) in 1995, $1,024,000 in 1994,
and $1,190,000 in 1993.
Through December 31, 1995, 52,000 restricted shares have been awarded and 13,989
shares have been forfeited, leaving 38,011 shares outstanding. Costs of
restricted stock charged against income were $385,000 in 1995, $433,000 in 1994,
and $347,000 in 1993.
In addition to the above plans, the Company has an Incentive Compensation Plan
that provides for annual cash awards to officers, directors, and key employees
based on actual results for a year compared to measurable financial performance
objectives established at the beginning of that year. The Plan is administered
by the Committee. Provisions of $400,000, $1,200,000, and $1,732,000 were
recorded in 1995, 1994, and 1993, respectively, in anticipation of future
awards.
NOTE J - EMPLOYEE AND RETIREE BENEFITS
Retirement Plans - The Company has defined benefit retirement plans that cover
substantially all employees. Benefits are based on years of service and
final-pay or career-average-pay formulas as defined by the plans. All plans are
noncontributory. The Company also has a nonqualified supplemental plan for
directors and supplemental plans that provide benefits to employees whose
defined benefits under their retirement plan formula cannot be fully funded
because of statutory limitations on the amount of benefits that may be paid from
qualified plans. As part of a reduction-in-force
37
program, special termination benefits were offered certain U.S. employees in
1995; a curtailment gain resulted from a reduction in future service cost for
employees accepting the offer.
Retirement expense (expense reduction) and its components for 1995, 1994, and
1993 are shown in the following tables.
- --------------------------------------------------------------------------------
U.S. Plans
- --------------------------------------------------------------------------------
(Thousands of dollars) 1995 1994 1993
- --------------------------------------------------------------------------------
Service cost - benefits earned during
the year ........................... $ 3,266 3,736 3,780
Interest accrued on benefits earned
in prior years ..................... 10,984 10,465 10,295
Actual return on plan assets ......... (32,876) (3,761) (8,564)
Net amortization and deferral ........ 18,456 (10,900) (6,402)
- --------------------------------------------------------------------------------
Retirement expense reduction* ... (170) (460) (891)
Special termination benefits ......... 7,005 - 1,316
Curtailment gain ..................... (2,494) - -
- --------------------------------------------------------------------------------
Net retirement expense
(expense reduction) $ 4,341 (460) 425
================================================================================
* Major assumptions were discount rates of 7.50% for 1995 and 6.75% for 1994
and 1993; assumed long-term rate of return on plan assets was 8.50% for 1995,
1994, and 1993.
- --------------------------------------------------------------------------------
Non-U.S. Plans
- --------------------------------------------------------------------------------
(Thousands of dollars) 1995 1994 1993
- --------------------------------------------------------------------------------
Service cost - benefits earned during
the year .............................. $ 1,482 1,537 1,478
Interest accrued on benefits earned
in prior years ........................ 2,173 2,404 2,326
Actual return on plan assets ............ (3,652) (894) (4,466)
Net amortization and deferral ........... 811 (2,323) 1,463
- --------------------------------------------------------------------------------
Retirement expense* $ 814 724 801
================================================================================
* Major assumptions were discount rates of 7.50%-9.50% in 1995, 6.50%-7.50% in
1994, and 7.50%-8.50% in 1993; assumed long-term rates of return on plan
assets were 7.50%-9.50% in 1995, 6.50%-7.50% in 1994, and 7.50%-8.50% in
1993.
Amounts contributed to U.S. funded plans are actuarially determined and are at
least the minimum required by the Employee Retirement Income Security Act of
1974. Amounts contributed to non-U.S. plans are based on local laws. The
supplemental plans are unfunded, and accumulated benefits exceeded assets in one
funded plan in 1995 and 1994. Accumulated benefits in excess of assets in these
plans were $5,906,000 in 1995 and $5,916,000 in 1994; these amounts have been
netted in the following table, which sets forth the combined funded status of
plans and amounts recognized in the Consolidated Balance Sheets.
- ------------------------------------------------------------------------------------------------------------------------------------
U.S. Plans Non-U.S. Plans
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars) 1995 1994 1995 1994
- ------------------------------------------------------------------------------------------------------------------------------------
Present value of accumulated benefits based on years of
service, applicable pay formula, and present pay levels
Vested ..................................................................... $ 142,238 124,154 24,060 26,104
Nonvested .................................................................. 7,023 4,890 188 164
- ------------------------------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation(1) ........................................ 149,261 129,044 24,248 26,268
Provision for future pay increases ............................................. 17,514 19,569 6,645 5,677
- ------------------------------------------------------------------------------------------------------------------------------------
Projected benefit obligation(1) ............................................ 166,775 148,613 30,893 31,945
Plan assets - at market value(2) ............................................... 181,791 158,540 38,574 34,495
- ------------------------------------------------------------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation .................... 15,016 9,927 7,681 2,550
Unrecognized net asset from transition to SFAS No. 87(3) ....................... (15,667) (17,668) (2,268) (2,521)
Unrecognized net loss (gain) from unfavorable (favorable) actuarial experience . 7,302 18,908 (11,417) (5,102)
Unrecognized prior service cost ................................................ 1,861 2,152 2,655 2,864
Additional minimum liability ................................................... (474) (1,658) -- --
- ------------------------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) retirement cost ........................................ $ 8,038 11,661 (3,349) (2,209)
====================================================================================================================================
1 Major assumptions for U.S. plans were discount rates of 7.00% for 1995 and
7.50% for 1994 and future pay rate increases of 4.60% for 1995 and 5.00% for
1994. Major assumptions for non-U.S. plans were discount rates of 7.50%-9.50%
for 1995 and 6.50%-9.50% for 1994 and future pay rate increases of 6.00%-
7.00% for 1995 and 1994.
2 Primarily includes listed stocks and bonds, government securities, U.S.
agency bonds, corporate bonds, and group annuity contracts.
3 Being amortized over periods of 14 to 19.2 years.
Thrift Plans - Most employees of the Company in the U.S. and Canada may
participate in thrift plans by allotting up to a specified percentage of their
base pay. The Company matches contributions at a stated percentage of each
employee's allotment based on length of participation in the plans. Company
contributions to these plans were $2,952,000 in 1995, $2,707,000 in 1994, and
$2,631,000 in 1993.
Postretirement Benefits - In the U.S., the Company sponsors plans that provide
comprehensive health care benefits (supplementing Medicare benefits for those
eligible) and life insurance benefits for most retired employees. Costs are
accrued for these plans during the service lives of covered employees. Retirees
contribute the same amounts to the self-funded cost of health care benefits as
do active employees; the Company contributes the remainder. The Company pays
38
premiums for life insurance coverage, arranged through an insurance company. The
health care plan is funded on a pay-as-you-go basis. The Company has the right
to modify the benefits and/or cost-sharing provisions.
Based on actuarial computations, postretirement expense and its components for
1995, 1994, and 1993 are shown below.
- --------------------------------------------------------------------------------
(Thousands of dollars) 1995 1994 1993
- --------------------------------------------------------------------------------
Service cost ............................... $ 548 895 604
Amortization of net actuarial loss ......... 476 347 --
Interest cost .............................. 2,706 2,733 2,250
- --------------------------------------------------------------------------------
Postretirement expense $3,730 3,975 2,854
================================================================================
A summary follows of the postretirement benefit obligations recorded in the
Consolidated Balance Sheets at December 31, 1995 and 1994, classified as
"Deferred Credits and Other Liabilities." Calculation of the amount of
accumulated unfunded postretirement benefit obligations (APBO) was based on
discount rates of 7.00 percent and 7.75 percent in 1995 and 1994.
- --------------------------------------------------------------------------------
(Thousands of dollars) 1995 1994
- --------------------------------------------------------------------------------
APBO
Retirees ................................... $ 27,595 26,173
Fully eligible active participants ......... 2,443 2,790
Other active participants .................. 8,622 10,904
- --------------------------------------------------------------------------------
Total unfunded APBO ..................... 38,660 39,867
Unrecognized net actuarial loss ................ (7,765) (11,229)
- --------------------------------------------------------------------------------
Accrued APBO obligations $ 30,895 28,638
================================================================================
In determining the APBO at December 31, 1995, health care inflation cost was
assumed to increase at an annual rate of 8.5 percent, gradually decreasing to
4.5 percent in 2002 and thereafter. An increase of one percent in the assumed
health care cost trend would increase both the 1995 postretirement benefit
expense and the APBO at December 31, 1995 by 13.9 percent.
NOTE K - SUPPLEMENTAL CASH FLOWS DISCLOSURES - Cash income taxes paid, net of
refunds, were $24,638,000, $29,999,000, and $14,802,000 in 1995, 1994, and 1993.
Interest paid, net of amounts capitalized, was $5,434,000, $1,873,000, and
$1,575,000 in 1995, 1994, and 1993. A noncash investing and financing activity
excluded from the Consolidated Statements of Cash Flows was the assumption of
$67,370,000 of nonrecourse debt in 1993 upon acquisition of a five-percent
interest in the Syncrude project.
(Increases) decreases in noncash operating working capital for each of the three
years ended December 31, 1995 were:
- --------------------------------------------------------------------------------
(Thousands of dollars) 1995 1994 1993
- --------------------------------------------------------------------------------
Accounts receivable ........................ $ 9,425 (48,027) 45,183
Inventories ................................ (23,371) (408) (15,166)
Prepaid expenses ........................... 6,654 (1,315) 7,467
Deferred income tax assets ................. (2,575) 3,558 (18,497)
Accounts payable and accrued liabilities ... (19,890) 30,947 (5,922)
Current income tax liabilities ............. (7,043) (944) (12,647)
- --------------------------------------------------------------------------------
$(36,800) (16,189) 418
================================================================================
NOTE L - DERIVATIVE FINANCIAL INSTRUMENTS - The Company utilizes derivative
transactions on a limited basis to manage well-defined risks related to
commodity prices and foreign currency exchange rates. The Company does not hold
any derivatives for trading purposes.
Occasionally the Company uses derivative agreements to reduce the financial
exposure of its U.S. refinery operations to unfavorable market movements related
to crude oil inventories and/or anticipated crude oil purchases. Under each
agreement, the Company receives or pays a cash settlement at maturity based on
the differential between the agreement price and an agreed future crude oil
price. At December 31, 1995, the Company had swap agreements for 4,000,000
barrels. Maturity dates of these agreements range from the third quarter of 1996
to the third quarter of 1997. Estimated settlement costs under the agreements
using December 31, 1995 oil prices exceeded projected revenues by $7,965,000,
which is fully reserved in the 1995 Consolidated Balance Sheet.
The Company has foreign exchange contracts to manage certain foreign exchange
risks. At December 31, 1995, the Company had hedging contracts to buy Cdn
$69,970,000, fixing the U.S. dollar costs for certain Canadian dollar
nonrecourse debt. The Company also had a hedging contract to sell US $7,600,000,
fixing the Canadian dollar revenues from the sale of Canadian crude in U.S.
dollars.
NOTE M - FAIR VALUE OF FINANCIAL INSTRUMENTS - The following table presents the
carrying amounts and estimated fair values of financial instruments held by the
Company at December 31, 1995 and 1994. The fair value of a financial instrument
is the amount at which the instrument could be exchanged in a current
transaction between willing parties. The table excludes cash and cash
equivalents, trade accounts receivable, trade accounts payable, and accrued
expenses, all of which had fair values approximating carrying values.
- --------------------------------------------------------------------------------
1995 1994
- --------------------------------------------------------------------------------
Carrying or Estimated Carrying or Estimated
Notional Fair Notional Fair
(Thousands of dollars) Amount Value Amount Value
- --------------------------------------------------------------------------------
Financial assets
Investments and
noncurrent receivables $ 10,575 10,575 10,625 10,625
Financial liabilities
Long-term obligations
including current
maturities ............ (204,575) (200,127) (180,067) (178,355)
Payables (derivatives) .. (9,142) (7,965) (1,368) (4,828)
Off-balance-sheet exposures
Financial guarantees and
letters of credit ..... (41,681) (41,681) (45,164) (45,164)
================================================================================
The carrying amounts of financial assets and financial liabilities shown in the
preceding table are included in the Consolidated Balance Sheets under the
indicated captions. The following methods and assumptions were used to estimate
the fair value of each class of financial instruments for which it is
practicable to estimate that value.
o Investments and noncurrent receivables - Investments in real estate held for
sale and investments carried on an equity basis are excluded from the table.
The carrying value of the remainder approximates fair value.
39
o Long-term obligations including current maturities - The fair value is
estimated based on current rates offered the Company for debt of the same
maturities.
o Payables (derivatives) - The amounts relate to the Company's oil swap and
buy/sell agreements. The negative fair value is an estimate of the amount,
which is based on quotes from brokers, that the Company would be required
to pay at the reporting date to cancel the agreements.
o Financial guarantees and letters of credit - The fair value is based on the
estimated cost to settle these obligations.
NOTE N - CONCENTRATION OF CREDIT RISKS - The Company's primary credit risk is
from trade accounts receivable. These receivables arise mainly from sales of
crude oil, natural gas, and petroleum products to a large number of customers in
the U.S., Canada, and the U.K. The credit history and financial condition of
potential customers are reviewed before credit is extended, security may be
obtained then or later, routine follow-up evaluations are made, and an allowance
for doubtful accounts is maintained, generally based upon a risk evaluation of
specific customers. The Company also has certain off-balance-sheet financial
instruments (see Note M to the consolidated financial statements); the Company
controls the credit risks on these instruments through credit approvals and
monitoring procedures and believes such risks are minimal. Historically, the
Company has not incurred any significant credit-related losses, and at December
31, 1995, the Company had no significant concentration of credit risk outside
the oil and gas industry.
NOTE O - OTHER FINANCIAL INFORMATION - Inventories valued at cost under the LIFO
method totaled $94,779,000 and $90,515,000 at December 31, 1995 and 1994,
respectively. These amounts were $70,040,000 and $57,389,000, respectively,
less than such inventories would have been valued using the FIFO method. Net
gains from foreign currency transactions were $82,000 in 1995, $51,000 in 1994,
and $10,000 in 1993.
NOTE P - CONTINGENCIES - The Company's operations and earnings have been and may
be affected by various forms of governmental action both in the U.S. and
throughout the world. Examples of such governmental action include, but are by
no means limited to: tax increases and retroactive tax claims; restrictions on
production; import and export controls; price controls; currency controls;
allocation of supplies of crude oil and petroleum products and other goods;
expropriation of property; restrictions and preferences affecting issuance of
oil and gas or mineral leases; laws and regulations intended for the protection
and/or remediation of the environment; promotion of safety; and laws and
regulations affecting the Company's relationships with employees, suppliers,
customers, stockholders, and others. Because governmental actions are often
motivated by political considerations, may be taken without full consideration
of their consequences, and 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.
DOE Matters - In 1994 the Company and the U.S. Department of Energy (DOE)
entered into a Consent Order that settled the last remaining issues related to
DOE regulations that were in effect from 1973 through 1981. The settlement
resulted in a $21,034,000 benefit ($13,871,000 after tax), which was recorded in
"Interest, Income from Equity Companies, and Other Nonoperating Revenues" in the
Consolidated Statement of Income for 1994.
Environmental Matters - The Company's environmental contingencies are reviewed
in Management's Discussion and Analysis under the section entitled
"Environmental" on page 26.
Other Matters - The Company and its subsidiaries are engaged in a number of
other legal proceedings, all of which the Company considers routine and
incidental to its business and none of which is material as defined. In the
normal course of its business activities, the Company is required under certain
contracts with various governmental authorities and others to provide letters of
credit that may be drawn upon if the Company fails to perform under those
contracts. At December 31, 1995, the Company had contingent liabilities of
$23,992,000 on outstanding letters of credit. Contingent liabilities under
certain guaranty agreements totaled $17,689,000 at December 31, 1995.
NOTE Q - BUSINESS SEGMENTS - Information about business segments and geographic
operations is summarized in the following tables. Excise taxes on petroleum
products of $521,250,000, $524,464,000, and $391,177,000 for the years 1995,
1994, and 1993 were excluded from revenues and costs and expenses. Intracompany
and affiliated company transfers are at market prices. Companies accounted for
by the equity method are primarily engaged in the transportation of crude oil
and petroleum products.
- --------------------------------------------------------------------------------
(Thousands of dollars) 1995 1994* 1993*
- --------------------------------------------------------------------------------
REVENUES FOR THE YEAR
Petroleum
Exploration and production
United States ............. $ 205,604 215,533 253,257
Canada .................... 139,133 127,122 71,447
United Kingdom ............ 110,789 90,312 51,590
Other international ....... 37,981 24,765 16,606
- --------------------------------------------------------------------------------
493,507 457,732 392,900
- --------------------------------------------------------------------------------
Refining, marketing,
and transportation
United States ............. 1,010,967 908,705 950,907
Canada .................... 22,589 26,885 29,601
United Kingdom ............ 254,746 306,297 274,898
- --------------------------------------------------------------------------------
1,288,302 1,241,887 1,255,406
- --------------------------------------------------------------------------------
1,781,809 1,699,619 1,648,306
Intrasegment transfers
elimination ................. (169,309) (118,657) (92,025)
- --------------------------------------------------------------------------------
Total petroleum ........ 1,612,500 1,580,962 1,556,281
Farm, timber, and real estate -
United States ................. 78,742 87,860 69,381
Corporate and other ............. 19,971 30,341 16,514
- --------------------------------------------------------------------------------
$1,711,213 1,699,163 1,642,176
================================================================================
*Reclassified to conform to 1995 presentation.
40
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars) 1995(1) 1994 1993(2)
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS) FOR THE YEAR
Petroleum
Exploration and production ............................ $ (97,583) 68,386 68,637
Refining, marketing, and
transportation ...................................... (42,670) 50,642 45,539
- ------------------------------------------------------------------------------------------------------------------------------------
Total petroleum ............................. (140,253) 119,028 114,176
Farm, timber, and real estate .............................. 14,387 28,710 21,170
- ------------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) ..................... (125,866) 147,738 135,346
Nonoperating (charges) credits
Income of equity companies ............................ 1,348 1,129 973
Income taxes .......................................... 15,415 (50,272) (46,829)
Corporate and other revenues
(expenses) - net .................................... (9,509) 8,033 (2,692)
Cumulative effect of accounting
changes ............................................. -- -- 15,338
- ------------------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ (118,612) 106,628 102,136
====================================================================================================================================
NET INCOME (LOSS) FOR THE YEAR
Petroleum
Exploration and production
United States ..................................... $ 3,755 18,128 32,701
Canada ............................................ 21,669 15,097 6,304
United Kingdom .................................... (11,934) 12,409 17,931
Other international ............................... (104,075) 5,984 (5,666)
- ------------------------------------------------------------------------------------------------------------------------------------
(90,585) 51,618 51,270
- ------------------------------------------------------------------------------------------------------------------------------------
Refining, marketing, and
transportation
United States ..................................... (3,767) 17,674 7,246
Canada ............................................ 5,544 7,298 8,628
United Kingdom .................................... (35,294) 5,231 11,625
- ------------------------------------------------------------------------------------------------------------------------------------
(33,517) 30,203 27,499
- ------------------------------------------------------------------------------------------------------------------------------------
Total petroleum ............................. (124,102) 81,821 78,769
Farm, timber, and real estate -
United States ............................................ 9,005 17,470 13,154
Corporate and other ........................................ (3,515) 7,337 (5,125)
- ------------------------------------------------------------------------------------------------------------------------------------
Income (loss) before
cumulative effect of
accounting changes ....................... (118,612) 106,628 86,798
Cumulative effect of accounting
changes .................................................. -- -- 15,338
- ------------------------------------------------------------------------------------------------------------------------------------
$ (118,612) 106,628 102,136
====================================================================================================================================
ASSETS AT YEAR-END
Petroleum
Exploration and production
United States ..................................... $ 317,422 386,830 461,087
Canada ............................................ 502,830 415,318 343,880
United Kingdom .................................... 248,493 320,143 306,248
Other international ............................... 80,688 170,111 111,903
- ------------------------------------------------------------------------------------------------------------------------------------
1,149,433 1,292,402 1,223,118
- ------------------------------------------------------------------------------------------------------------------------------------
Refining, marketing, and
transportation
United States ..................................... 494,577 500,467 378,405
Canada ............................................ 56,786 55,578 63,353
United Kingdom .................................... 128,952 156,884 147,444
- ------------------------------------------------------------------------------------------------------------------------------------
680,315 712,929 589,202
- ------------------------------------------------------------------------------------------------------------------------------------
Total petroleum ............................. 1,829,748 2,005,331 1,812,320
Farm, timber, and real estate -
United States ............................................ 163,834 155,583 150,261
Corporate and other ........................................ 125,531 151,118 206,278
- ------------------------------------------------------------------------------------------------------------------------------------
$ 2,119,113 2,312,032 2,168,859
- ------------------------------------------------------------------------------------------------------------------------------------
ADDITIONS TO PROPERTY, PLANT, AND
EQUIPMENT FOR THE YEAR(3)
Petroleum
Exploration and production
United States ..................................... $ 36,064 59,847 71,883
Canada ............................................ 93,612 105,355 172,838
United Kingdom .................................... 27,527 29,063 173,392
Other international ............................... 19,460 60,387 68,028
- ------------------------------------------------------------------------------------------------------------------------------------
176,663 254,652 486,141
- ------------------------------------------------------------------------------------------------------------------------------------
Refining, marketing, and
transportation
United States ..................................... 27,565 80,272 71,363
Canada ............................................ 3,561 2,234 3,474
United Kingdom .................................... 22,476 12,191 12,048
- ------------------------------------------------------------------------------------------------------------------------------------
53,602 94,697 86,885
- ------------------------------------------------------------------------------------------------------------------------------------
Total petroleum ............................. 230,265 349,349 573,026
Farm, timber, and real estate -
United States ........................................... 9,133 11,403 9,674
Corporate and other ........................................ 1,831 4,876 4,034
- ------------------------------------------------------------------------------------------------------------------------------------
$ 241,229 365,628 586,734
====================================================================================================================================
DEPRECIATION, DEPLETION, AND
AMORTIZATION EXPENSE FOR THE YEAR(3)
Petroleum
Exploration and production
United States ..................................... $ 89,669 93,057 97,196
Canada ............................................ 26,707 25,088 21,062
United Kingdom .................................... 50,426 38,601 16,749
Other international ............................... 15,923 4,754 4,651
- ------------------------------------------------------------------------------------------------------------------------------------
182,725 161,500 139,658
- ------------------------------------------------------------------------------------------------------------------------------------
Refining, marketing, and
transportation
United States ..................................... 25,862 19,928 20,144
Canada ............................................ 1,549 1,573 1,466
United Kingdom .................................... 9,062 9,589 8,562
- ------------------------------------------------------------------------------------------------------------------------------------
36,473 31,090 30,172
- ------------------------------------------------------------------------------------------------------------------------------------
Total petroleum ............................. 219,198 192,590 169,830
Farm, timber, and real estate -
United States ............................................ 4,053 3,886 3,488
Corporate and other ........................................ 2,673 2,409 1,368
- ------------------------------------------------------------------------------------------------------------------------------------
$ 225,924 198,885 174,686
====================================================================================================================================
1 As set forth in Note B to the consolidated financial statements, the effects
from adoption of SFAS No. 121, Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of, were:
Operating income (loss) - a loss of $198,988, $150,301 related to the
exploration and production segment and $48,687 to refining, marketing,
and transportation.
Net income (loss) - a loss of $168,367, $132,798 related to the exploration
and production segment ($5,986 United States, $24,197 United Kingdom, and
$102,615 other international) and $35,569 related to refining, marketing,
and transportation - United Kingdom.
2 As set forth in Note B to the consolidated financial statements, the effect
on operating income for the exploration and production segment from adoption
of SFAS No. 109, Accounting for Income Taxes, was a reduction of $10,916.
3 Amounts for 1994 and 1993 were reclassified to conform to 1995 presentation.
41
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
The following schedules are presented in accordance with Statement of Financial
Accounting Standards No. 69 (SFAS No. 69), Disclosures about Oil and Gas
Producing Activities. The schedules provide users with a common base for
preparing estimates of future cash flows and comparing reserves among companies.
Additional background information follows concerning four of the schedules.
SCHEDULES 1 AND 2 - ESTIMATED NET PROVED OIL AND GAS RESERVES
Reserves of crude oil, condensate, and natural gas liquids and natural gas are
estimated by Company engineers and adjusted to reflect contractual arrangements
and royalty rates in effect at the end of each year. Many assumptions and
judgmental decisions are required to estimate reserves. Quantities reported are
considered reasonable, but they are subject to future revisions, some of which
may be substantial, as additional information becomes available. Such additional
knowledge may be gained as the result of: reservoir performance, new geological
and geophysical data, additional drilling, technological advancements, price
changes, and other economic factors.
Regulations published by the Securities and Exchange Commission define proved
reserves as those volumes of crude oil, condensate, and natural gas liquids and
natural gas that geological and engineering data demonstrate with reasonable
certainty are recoverable from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those volumes expected to be
recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves are those volumes expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major
expenditure is required.
Production quantities shown are net volumes withdrawn from reservoirs. These
generally differ from quantities sold due to inventory changes and, especially
in the case of natural gas, volumes consumed for fuel and/or shrinkage from
extraction of natural gas liquids. Such differences were insignificant for crude
oil and liquids. For natural gas, they amounted to approximately .5 billion
cubic feet in 1995, .7 billion cubic feet in 1994, and .9 billion cubic feet in
1993. Crude oil and natural gas liquids reserves reported under the heading
"Other" were located in Spain and Gabon.
The Company has no proved reserves attributable to either long-term supply
agreements with foreign governments or investees accounted for by the equity
method.
Reserves of synthetic crude oil in Canada are attributable to the Syncrude
project and are based on an estimated average gross production rate through the
year 2025 of 195,300 barrels a day less estimated net profit royalty. Proved
reserves will change if the future average production rate varies from the
current estimated rate, which is based on the actual rate in 1995, or the
operating permit is extended beyond 2025.
SCHEDULE 4 - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING
TO PROVED OIL AND GAS RESERVES
SFAS No. 69 requires calculation of future net cash flows using a 10-percent
annual discount factor and year-end (1995 and 1994) prices, costs, and statutory
tax rates, except for known future changes such as contracted prices and
legislated tax rates. Future net cash flows from the Company's interest in
synthetic oil are excluded.
The calculated value of proved reserves is not necessarily indicative of either
fair market value or present value of future cash flows because prices, costs,
and governmental policies do not remain static; appropriate discount rates may
vary; and a broad range of judgment is required to estimate the timing of
production. Other logical assumptions would likely have resulted in
significantly different amounts. Average crude oil prices at year-end 1995 used
for this calculation were $18.04 a barrel for the United States, $16.48 for
Canadian light, $9.66 for Canadian heavy, $17.59 for Hibernia, $18.85 for the
United Kingdom, and $13.24 for Ecuador. Average natural gas prices were $2.51 an
MCF for the United States, $1.02 for Canada, $2.21 for the United Kingdom, and
$2.70 for Spain.
Schedule 4 also presents a summary of the principal reasons for change in the
standardized measure of discounted future net cash flows for each of the three
years ended December 31, 1995.
SCHEDULE 6 - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
Results of operations from exploration and production activities by geographic
area are reported on this schedule as if these activities were a separate
corporate entity rather than part of an integrated operation that will
ultimately refine crude oil and sell refined products. Results of oil and gas
producing activities include certain unusual or infrequently occurring items
that are reviewed in Management's Discussion and Analysis (see page 24), and
should be considered in conjunction with the Company's overall performance.
42
SCHEDULE 1 - ESTIMATED NET PROVED OIL RESERVES
- ------------------------------------------------------------------------------------------------------------------------------------
Crude Oil, Condensate, and Natural Gas Liquids
----------------------------------------------------- Synthetic
United United Oil -
(Millions of barrels) States Canada* Kingdom Ecuador Other Total Canada Total
- ------------------------------------------------------------------------------------------------------------------------------------
PROVED
JANUARY 1, 1993 ..................................... 23.2 22.3 13.1 35.6 1.8 96.0 -- 96.0
Revisions of previous estimates ..................... .3 .8 (.5) (2.0) .7 (.7) -- (.7)
Purchases of minerals in place ...................... -- 14.8 16.5 -- -- 31.3 83.8 115.1
Extensions, discoveries, and other additions ........ 1.5 3.2 -- -- -- 4.7 -- 4.7
Production .......................................... (5.0) (4.6) (2.4) -- (.6) (12.6) -- (12.6)
Sales of minerals in place .......................... -- (.1) -- -- -- (.1) -- (.1)
- ------------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1993 ................................... 20.0 36.4 26.7 33.6 1.9 118.6 83.8 202.4
Revisions of previous estimates ..................... 4.3 2.8 (2.5) 2.1 (1.5) 5.2 18.3 23.5
Purchases of minerals in place ...................... -- .5 5.2 -- -- 5.7 -- 5.7
Extensions, discoveries, and other additions ........ 5.1 2.7 -- -- -- 7.8 -- 7.8
Production .......................................... (4.9) (4.5) (4.9) (.7) (.4) (15.4) (3.3) (18.7)
Sales of minerals in place .......................... -- (.4) -- -- -- (.4) -- (.4)
- ------------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1994 ................................... 24.5 37.5 24.5 35.0 -- 121.5 98.8 220.3
REVISIONS OF PREVIOUS ESTIMATES ..................... 3.9 -- .7 (3.5) -- 1.1 .7 1.8
PURCHASES OF MINERALS IN PLACE ...................... .2 2.0 -- -- -- 2.2 -- 2.2
EXTENSIONS, DISCOVERIES, AND OTHER ADDITIONS ........ 1.0 3.6 20.3 -- -- 24.9 -- 24.9
PRODUCTION .......................................... (5.0) (5.1) (5.5) (1.9) -- (17.5) (3.3) (20.8)
SALES OF MINERALS IN PLACE .......................... -- (1.7) -- -- -- (1.7) -- (1.7)
- ------------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1995 24.6 36.3 40.0 29.6 -- 130.5 96.2 226.7
====================================================================================================================================
PROVED DEVELOPED
January 1, 1993 ..................................... 16.3 22.2 11.7 -- 1.8 52.0 -- 52.0
December 31, 1993 ................................... 13.2 22.4 20.8 -- 1.9 58.3 83.8 142.1
December 31, 1994 ................................... 15.2 23.6 19.2 3.8 -- 61.8 80.5 142.3
DECEMBER 31, 1995 ................................... 21.3 22.4 19.5 7.8 -- 71.0 69.9 140.9
====================================================================================================================================
*Excludes 24.7 million barrels of crude oil to be added to proved reserves
subsequent to start-up of production from the Hibernia oil field.
[GRAPH--ESTIMATED NET PROVED OIL RESERVES]
[GRAPH--ESTIMATED NET PROVED GAS RESERVES]
[GRAPH--ESTIMATED NET PROVED HYDROCARBON RESERVES]
43
SCHEDULE 2 - ESTIMATED NET PROVED NATURAL GAS RESERVES
- ------------------------------------------------------------------------------------------------------------------------------------
United United
(Billions of cubic feet) States Canada Kingdom Spain Total
- ------------------------------------------------------------------------------------------------------------------------------------
PROVED
JANUARY 1, 1993 ................................................ 445.4 200.4 35.4 4.1 685.3
Revisions of previous estimates ................................ 48.0 (10.5) .6 4.1 42.2
Purchases of minerals in place ................................. .3 .9 -- -- 1.2
Extensions, discoveries, and other additions ................... 14.8 5.5 -- 5.9 26.2
Production ..................................................... (79.5) (13.4) (4.8) (3.5) (101.2)
Sales of minerals in place ..................................... -- (.2) -- -- (.2)
- ------------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1993 .............................................. 429.0 182.7 31.2 10.6 653.5
Revisions of previous estimates ................................ 20.2 (2.9) 2.1 1.2 20.6
Purchases of minerals in place ................................. -- .5 -- -- .5
Extensions, discoveries, and other additions ................... 53.2 11.0 -- -- 64.2
Production ..................................................... (72.1) (13.8) (3.7) (4.6) (94.2)
Sales of minerals in place ..................................... (.2) (.8) -- -- (1.0)
- ------------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1994 .............................................. 430.1 176.7 29.6 7.2 643.6
REVISIONS OF PREVIOUS ESTIMATES ................................ 3.8 (5.2) 1.9 .6 1.1
PURCHASES OF MINERALS IN PLACE ................................. 2.8 5.8 -- -- 8.6
EXTENSIONS, DISCOVERIES, AND OTHER ADDITIONS ................... 64.1 2.0 19.8 -- 85.9
PRODUCTION ..................................................... (69.3) (15.2) (3.9) (4.0) (92.4)
SALES OF MINERALS IN PLACE ..................................... -- (4.0) -- -- (4.0)
- ------------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1995 431.5 160.1 47.4 3.8 642.8
====================================================================================================================================
PROVED DEVELOPED
January 1, 1993 ................................................ 217.0 164.0 32.3 4.1 417.4
December 31, 1993 .............................................. 239.1 158.0 28.1 10.6 435.8
December 31, 1994 .............................................. 221.6 165.0 29.6 7.2 423.4
DECEMBER 31, 1995 .............................................. 229.0 150.0 27.6 3.8 410.4
====================================================================================================================================
SCHEDULE 3 - CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
- ------------------------------------------------------------------------------------------------------------------------------------
Synthetic
United United Oil -
(Millions of dollars) States Canada Kingdom Ecuador Other Subtotal Canada Total
- ------------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1995
UNPROVED OIL AND GAS PROPERTIES .......... $ 88.5 28.8 7.9 -- 4.0 129.2 -- 129.2
PROVED OIL AND GAS PROPERTIES ............ 1,405.9 599.5(1) 582.4 167.1 122.9 2,877.8 119.3 2,997.1
- ------------------------------------------------------------------------------------------------------------------------------------
GROSS CAPITALIZED COSTS ............ 1,494.4 628.3 590.3 167.1 126.9 3,007.0 119.3 3,126.3
ACCUMULATED DEPRECIATION,
DEPLETION, AND AMORTIZATION
UNPROVED OIL AND GAS PROPERTIES ...... (55.3) (15.7) (.8) -- (3.8) (75.6) -- (75.6)
PROVED OIL AND GAS PROPERTIES(2) ..... (1,186.2) (254.0) (412.5) (114.5) (116.2) (2,083.4) (8.8) (2,092.2)
- ------------------------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS $ 252.9 358.6 177.0 52.6 6.9 848.0 110.5 958.5
====================================================================================================================================
December 31, 1994(3)
Unproved oil and gas properties .......... $ 109.2 27.5 21.0 -- 9.8 167.5 -- 167.5
Proved oil and gas properties ............ 1,397.7 517.6(1) 548.2 149.6 109.9 2,723.0 108.9 2,831.9
- ------------------------------------------------------------------------------------------------------------------------------------
Gross capitalized costs ............ 1,506.9 545.1 569.2 149.6 119.7 2,890.5 108.9 2,999.4
Accumulated depreciation,
depletion, and amortization
Unproved oil and gas properties ...... (55.0) (15.3) (.8) -- (5.9) (77.0) -- (77.0)
Proved oil and gas properties(2) ..... (1,136.1) (239.5) (331.5) (3.8) (100.4) (1,811.3) (4.4) (1,815.7)
- ------------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 315.8 290.3 236.9 145.8 13.4 1,002.2 104.5 1,106.7
====================================================================================================================================
1 Includes costs of $166.2 in 1995 and $107.5 in 1994 related to oil fields
under development offshore Newfoundland.
2 Does not include reserve for dismantlement costs of $144.9 in 1995 and
$138.9 in 1994.
3 Reclassified to conform to 1995 presentation.
44
SCHEDULE 4 - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING
TO PROVED OIL AND GAS RESERVES(1)
- ------------------------------------------------------------------------------------------------------------------------------------
United United
(Millions of dollars) States Canada(2) Kingdom Ecuador Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1995
FUTURE CASH INFLOWS ................................................ $1,525.3 691.2 824.3 391.2 10.4 3,442.4
FUTURE DEVELOPMENT COSTS ........................................... (191.5) (156.2) (112.1) (57.3) -- (517.1)
FUTURE PRODUCTION AND ABANDONMENT COSTS ............................ (402.9) (281.3) (303.0) (139.0) (2.3) (1,128.5)
FUTURE INCOME TAXES ................................................ (281.4) (43.1) (100.5) (13.9) (1.0) (439.9)
- ------------------------------------------------------------------------------------------------------------------------------------
FUTURE NET CASH FLOWS ......................................... 649.5 210.6 308.7 181.0 7.1 1,356.9
10% ANNUAL DISCOUNT FOR ESTIMATED TIMING OF CASH FLOWS ............. (222.0) (100.7) (91.1) (89.7) .2 (503.3)
- ------------------------------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS $ 427.5 109.9 217.6 91.3 7.3 853.6
====================================================================================================================================
December 31, 1994
Future cash inflows ................................................ $1,071.3 714.4 453.5 387.2 21.1 2,647.5
Future development costs ........................................... (160.2) (204.1) (25.8) (68.7) (1.8) (460.6)
Future production and abandonment costs ............................ (358.7) (301.5) (233.9) (118.2) (1.8) (1,014.1)
Future income taxes ................................................ (147.0) (50.1) 11.8 (18.0) (3.6) (206.9)
- ------------------------------------------------------------------------------------------------------------------------------------
Future net cash flows ......................................... 405.4 158.7 205.6 182.3 13.9 965.9
10% annual discount for estimated timing of cash flows ............. (139.1) (98.6) (29.8) (85.7) (1.1) (354.3)
- ------------------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 266.3 60.1 175.8 96.6 12.8 611.6
====================================================================================================================================
1 Excludes future net cash flows from synthetic oil.
2 Excludes future net cash flows attributable to 24.7 million barrels of crude
oil to be added to proved reserves subsequent to start-up of production from
the Hibernia oil field.
Following are the principal sources of change in the standardized measure of
discounted future net cash flows for the years shown.
- ------------------------------------------------------------------------------------------------------------------------------------
(Millions of dollars) 1995 1994 1993
- ------------------------------------------------------------------------------------------------------------------------------------
Net changes in prices, production costs, and development costs .................... $ 81.3 (225.7) (282.6)
Sales and transfers of oil and gas produced, net of production costs .............. (226.2) (161.1) (167.0)
Net change due to extensions, discoveries, and improved recovery .................. 298.1 86.1 47.8
Net change due to purchases and sales of minerals in place ........................ 7.5 35.9 26.5
Development costs incurred during the period ...................................... 132.8 173.9 150.6
Accretion of discount ............................................................. 76.1 73.3 82.2
Revisions of previous quantity estimates .......................................... 25.4 46.3 53.4
Net change in income taxes ........................................................ (153.0) 53.6 53.8
- ------------------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) ..................................................... 242.0 82.3 (35.3)
Standardized measure at January 1 ................................................. 611.6 529.3 564.6
- ------------------------------------------------------------------------------------------------------------------------------------
Standardized measure at December 31 $ 853.6 611.6 529.3
====================================================================================================================================
45
SCHEDULE 5 - COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION,
AND DEVELOPMENT ACTIVITIES
- ------------------------------------------------------------------------------------------------------------------------------------
1995
- ------------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil -
(Millions of dollars) States Canada dom dor Other total Canada Total
- ------------------------------------------------------------------------------------------------------------------------------------
Property acquisition costs
Unproved ................................. $ 7.0 3.0 .1 -- .2 10.3 -- 10.3
Proved ................................... 2.5 4.7 -- -- -- 7.2 -- 7.2
- ------------------------------------------------------------------------------------------------------------------------------------
Total acquisition costs ................ 9.5 7.7 .1 -- .2 17.5 -- 17.5
Exploration costs .......................... 41.7 7.5 6.8 -- 9.3 65.3 -- 65.3
Development costs .......................... 20.0 76.8 25.6 17.6 1.6 141.6 7.3 148.9
- ------------------------------------------------------------------------------------------------------------------------------------
Total capital expenditures 71.2 92.0 32.5 17.6 11.1 224.4 7.3 231.7
- ------------------------------------------------------------------------------------------------------------------------------------
Charged to expense
Dry hole expense ......................... 25.9 2.9 .7 -- 1.4 30.9 -- 30.9
Geophysical and other costs .............. 9.2 2.9 4.3 -- 7.8 24.2 -- 24.2
- ------------------------------------------------------------------------------------------------------------------------------------
Total charged to expense 35.1 5.8 5.0 -- 9.2 55.1 -- 55.1
- ------------------------------------------------------------------------------------------------------------------------------------
Expenditures capitalized $36.1 86.2 27.5 17.6 1.9 169.3 7.3 176.6
====================================================================================================================================
SCHEDULE 6 - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
- ------------------------------------------------------------------------------------------------------------------------------------
1995
- ------------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil -
(Millions of dollars) States Canada dom dor Other total Canada Total
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues
Crude oil and natural gas liquids
Transfers to consolidated operations .. $67.8 45.7 20.9 -- -- 134.4 34.9 169.3
Sales to unaffiliated enterprises ..... 14.4 22.6 71.7 25.9 -- 134.6 20.8 155.4
Natural gas ............................. 112.8 14.5 9.8 -- 11.3 148.4 -- 148.4
- ------------------------------------------------------------------------------------------------------------------------------------
Total oil and gas revenues .......... 195.0 82.8 102.4 25.9 11.3 417.4 55.7 473.1
Other operating ............................ 10.6 -- 8.4 .2 .6 19.8 .6 20.4
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues 205.6 82.8 110.8 26.1 11.9 437.2 56.3 493.5
- ------------------------------------------------------------------------------------------------------------------------------------
Costs and deductions
Production costs ......................... 53.5 27.0 36.1 11.6 .1 128.3 39.2 167.5
Exploration expenses ..................... 35.1 5.8 5.0 -- 9.2 55.1 -- 55.1
Undeveloped lease amortization ........... 6.9 2.3 -- -- 1.5 10.7 -- 10.7
Depreciation, depletion, and amortization. 89.7 21.9 50.4 10.7 5.3 178.0 4.7 182.7
Impairment of long-lived assets .......... 9.2 -- 38.5 100.0 2.6 150.3 -- 150.3
Selling and general expenses ............. 14.1 5.6 3.5 .1 1.4 24.7 .1 24.8
- ------------------------------------------------------------------------------------------------------------------------------------
Total costs and deductions 208.5 62.6 133.5 122.4 20.1 547.1 44.0 591.1
- ------------------------------------------------------------------------------------------------------------------------------------
(2.9) 20.2 (22.7) (96.3) (8.2) (109.9) 12.3 (97.6)
Income tax provisions (benefits) ........... (6.6) 6.3 (10.8) 1.0 (1.4) (11.5) 4.5 (7.0)
- ------------------------------------------------------------------------------------------------------------------------------------
Results of operations* $ 3.7 13.9 (11.9) (97.3) (6.8) (98.4) 7.8 (90.6)
====================================================================================================================================
*Excludes corporate overhead and interest.
46
SCHEDULE 5 - COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION,
AND DEVELOPMENT ACTIVITIES (Continued)
- ------------------------------------------------------------------------------------------------------------------------------------
1994*
- ------------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil -
(Millions of dollars) States Canada dom dor Other total Canada Total
- ------------------------------------------------------------------------------------------------------------------------------------
Property acquisition costs
Unproved ................................. 6.8 2.5 -- -- -- 9.3 -- 9.3
Proved ................................... -- 22.2 4.4 -- -- 26.6 -- 26.6
- ------------------------------------------------------------------------------------------------------------------------------------
Total acquisition costs ................ 6.8 24.7 4.4 -- -- 35.9 -- 35.9
Exploration costs .......................... 49.2 11.7 11.6 -- 4.4 76.9 -- 76.9
Development costs .......................... 23.4 68.7 18.2 52.8 5.1 168.2 5.3 173.5
- -----------------------------------------------------------------------------------------------------------------------------------
Total capital expenditures 79.4 105.1 34.2 52.8 9.5 281.0 5.3 286.3
- ------------------------------------------------------------------------------------------------------------------------------------
Charged to expense
Dry hole expense ......................... 11.4 2.4 2.8 -- -- 16.6 -- 16.6
Geophysical and other costs .............. 8.2 2.6 2.4 -- 1.9 15.1 -- 15.1
- ------------------------------------------------------------------------------------------------------------------------------------
Total charged to expense 19.6 5.0 5.2 -- 1.9 31.7 -- 31.7
- ------------------------------------------------------------------------------------------------------------------------------------
Expenditures capitalized 59.8 100.1 29.0 52.8 7.6 249.3 5.3 254.6
====================================================================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
1993*
- ------------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil -
(Millions of dollars) States Canada dom dor Other total Canada Total
- ------------------------------------------------------------------------------------------------------------------------------------
Property acquisition costs
Unproved ................................. 2.2 1.9 -- -- .3 4.4 -- 4.4
Proved ................................... 1.4 5.0 144.3 -- -- 150.7 109.0 259.7
- ------------------------------------------------------------------------------------------------------------------------------------
Total acquisition costs ................ 3.6 6.9 144.3 -- .3 155.1 109.0 264.1
Exploration costs .......................... 39.9 9.2 5.0 -- 6.1 60.2 -- 60.2
Development costs .......................... 49.4 52.7 26.0 67.7 -- 195.8 -- 195.8
- ------------------------------------------------------------------------------------------------------------------------------------
Total capital expenditures 92.9 68.8 175.3 67.7 6.4 411.1 109.0 520.1
- ------------------------------------------------------------------------------------------------------------------------------------
Charged to expense
Dry hole expense ......................... 15.2 2.4 (.5) -- 4.4 21.5 -- 21.5
Geophysical and other costs .............. 5.8 2.6 2.5 -- 1.6 12.5 -- 12.5
- ------------------------------------------------------------------------------------------------------------------------------------
Total charged to expense 21.0 5.0 2.0 -- 6.0 34.0 -- 34.0
- ------------------------------------------------------------------------------------------------------------------------------------
Expenditures capitalized 71.9 63.8 173.3 67.7 .4 377.1 109.0 486.1
====================================================================================================================================
*Reclassified to conform to 1995 presentation.
SCHEDULE 6 - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING
ACTIVITIES (Continued)
- ------------------------------------------------------------------------------------------------------------------------------------
1994(1)
- ------------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil -
(Millions of dollars) States Canada dom dor Other total Canada Total
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues
Crude oil and natural gas liquids
Transfers to consolidated operations .. 60.3 27.7 -- -- -- 88.0 30.6 118.6
Sales to unaffiliated enterprises ..... 13.4 26.5 77.8 7.9 5.9 131.5 22.1 153.6
Natural gas ............................. 136.1 19.7 9.0 -- 11.7 176.5 -- 176.5
- ------------------------------------------------------------------------------------------------------------------------------------
Total oil and gas revenues .......... 209.8 73.9 86.8 7.9 17.6 396.0 52.7 448.7
Other operating ......................... 5.7 .5 3.5 -- (.7) 9.0 -- 9.0
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues 215.5 74.4 90.3 7.9 16.9 405.0 52.7 457.7
- ------------------------------------------------------------------------------------------------------------------------------------
Costs and deductions
Production costs ........................ 55.5 24.3 32.1 5.9 4.3 122.1 40.0 162.1
Exploration expenses .................... 19.6 5.0 5.2 -- 1.9 31.7 -- 31.7
Undeveloped lease amortization .......... 8.2 2.8 -- -- -- 11.0 -- 11.0
Depreciation, depletion, and amortization 93.1 19.9 38.5 3.8 1.0 156.3 5.2 161.5
Impairment of long-lived assets ......... -- -- -- -- -- -- -- --
Selling and general expenses ............ 13.8 4.6 3.1 .1 1.3 22.9 .1 23.0
- ------------------------------------------------------------------------------------------------------------------------------------
Total costs and deductions 190.2 56.6 78.9 9.8 8.5 344.0 45.3 389.3
- ------------------------------------------------------------------------------------------------------------------------------------
25.3 17.8 11.4 (1.9) 8.4 61.0 7.4 68.4
Income tax provisions (benefits) ........... 7.2 7.8 (1.0) .5 -- 14.5 2.3 16.8
- ------------------------------------------------------------------------------------------------------------------------------------
Results of operations(2) 18.1 10.0 12.4 (2.4) 8.4 46.5 5.1 51.6
====================================================================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
1993(1)
- ------------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil-
(Millions of dollars) States Canada dom dor Other total Canada Total
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues
Crude oil and natural gas liquids
Transfers to consolidated operations .. 65.1 27.0 -- -- -- 92.1 -- 92.1
Sales to unaffiliated enterprises ..... 16.6 27.1 38.4 -- 8.0 90.1 -- 90.1
Natural gas ............................. 165.8 16.4 11.0 -- 9.2 202.4 -- 202.4
- ------------------------------------------------------------------------------------------------------------------------------------
Total oil and gas revenues .......... 247.5 70.5 49.4 -- 17.2 384.6 -- 384.6
Other operating ......................... 5.8 .9 2.2 -- (.6) 8.3 -- 8.3
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues 253.3 71.4 51.6 -- 16.6 392.9 -- 392.9
- ------------------------------------------------------------------------------------------------------------------------------------
Costs and deductions
Production costs ........................ 58.1 25.4 20.7 -- 9.7 113.9 -- 113.9
Exploration expenses .................... 21.0 5.0 2.0 -- 6.0 34.0 -- 34.0
Undeveloped lease amortization .......... 8.9 2.5 -- -- .7 12.1 -- 12.1
Depreciation, depletion, and amortization 97.2 21.1 16.8 -- 4.6 139.7 -- 139.7
Impairment of long-lived assets ......... -- -- -- -- -- -- -- --
Selling and general expenses ............ 14.3 5.7 3.3 .1 1.1 24.5 -- 24.5
- ------------------------------------------------------------------------------------------------------------------------------------
Total costs and deductions 199.5 59.7 42.8 .1 22.1 324.2 -- 324.2
- ------------------------------------------------------------------------------------------------------------------------------------
53.8 11.7 8.8 (.1) (5.5) 68.7 -- 68.7
Income tax provisions (benefits) ........... 21.1 5.4 (9.1) -- -- 17.4 -- 17.4
- ------------------------------------------------------------------------------------------------------------------------------------
Results of operations(2) 32.7 6.3 17.9 (.1) (5.5) 51.3 -- 51.3
====================================================================================================================================
1 Reclassified to conform to 1995 presentation.
2 Excludes corporate overhead and interest.
47
STATISTICAL SUMMARY
- ------------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------------
EXPLORATION AND PRODUCTION
Net crude oil and condensate production - barrels a day
United States....................................................... 12,772 12,503 12,864 12,586 12,565
Canada - light oil.................................................. 4,417 4,775 4,546 3,972 4,305
heavy oil.................................................. 8,864 6,840 7,449 5,366 4,744
synthetic oil.............................................. 8,832 9,065 - - -
United Kingdom...................................................... 14,588 13,389 6,342 5,931 7,607
Ecuador............................................................. 5,274 1,967 - - -
Other international................................................. 117 1,038 1,550 1,350 2,985
Net natural gas liquids production - barrels a day
United States....................................................... 964 852 863 768 761
Canada.............................................................. 740 748 697 847 368
United Kingdom...................................................... 447 151 - - 160
- ------------------------------------------------------------------------------------------------------------------------------------
Total 57,015 51,328 34,311 30,820 33,495
====================================================================================================================================
Net natural gas sold - thousands of cubic feet a day
United States....................................................... 189,250 195,555 215,471 188,068 151,157
Canada.............................................................. 40,907 37,945 36,792 30,328 25,679
United Kingdom...................................................... 10,671 10,138 13,074 12,802 9,354
Spain............................................................... 10,898 12,620 9,571 19,402 22,207
- ------------------------------------------------------------------------------------------------------------------------------------
Total 251,726 256,258 274,908 250,600 208,397
====================================================================================================================================
Total hydrocarbons produced - equivalent barrels(1) a day 98,969 94,038 80,129 72,587 68,228
- ------------------------------------------------------------------------------------------------------------------------------------
Estimated net hydrocarbon reserves - million equivalent barrels(1, 2) 333.8 327.6 311.3 210.2 202.8
- ------------------------------------------------------------------------------------------------------------------------------------
Weighted average sales prices(3)
Crude oil and condensate - dollars a barrel
United States..................................................... $16.61 15.36 16.60 18.85 19.80
Canada(4) - light oil............................................. 16.45 14.61 15.01 16.69 17.47
heavy oil............................................. 12.10 10.56 9.84 11.02 9.09
synthetic oil......................................... 17.28 15.92 - - -
United Kingdom.................................................... 16.96 15.77 16.63 18.86 19.86
Ecuador........................................................... 13.03 12.07 - - -
Other international............................................... 15.12 14.80 14.14 18.85 16.57
Natural gas liquids - dollars a barrel
United States..................................................... 12.62 12.19 13.36 14.71 15.65
Canada(4)......................................................... 9.70 9.21 9.59 9.74 13.91
United Kingdom.................................................... 13.99 12.16 - - 15.35
Natural gas - dollars a thousand cubic feet
United States..................................................... 1.64 1.91 2.10 1.75 1.62
Canada(4)......................................................... .97 1.42 1.22 1.01 1.12
United Kingdom(4)................................................. 2.53 2.43 2.31 2.86 3.00
Spain(4).......................................................... 2.88 2.55 2.64 2.58 2.87
- ------------------------------------------------------------------------------------------------------------------------------------
Net wells completed
Oil wells - United States........................................... 3.0 2.6 3.0 4.9 5.7
Canada.................................................. 29.6 20.7 24.3 19.1 10.0
Other................................................... 3.7 2.7 2.0 .3 .4
Gas wells - United States........................................... 3.6 4.0 8.5 5.1 9.4
Canada.................................................. 2.3 14.5 4.1 2.4 1.4
Other................................................... .2 .4 - .5 .5
Dry holes - United States........................................... 1.9 4.1 6.5 5.2 5.9
Canada.................................................. 5.9 6.5 6.9 2.6 6.9
Other................................................... .6 .5 .6 2.0 1.4
- ------------------------------------------------------------------------------------------------------------------------------------
Total 50.8 56.0 55.9 42.1 41.6
====================================================================================================================================
Net undeveloped acreage - thousands of acres(2) 13,107 12,218 9,306 8,389 10,114
====================================================================================================================================
1 Natural gas converted on an energy equivalent basis of 6:1.
2 At December 31.
3 Includes intracompany and affiliated company transfers at market prices.
4 U.S. dollar equivalent.
48
- ------------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------------
REFINING
Crude capacity* of refineries - barrels per stream day 167,400 167,400 167,400 167,400 167,400
- ------------------------------------------------------------------------------------------------------------------------------------
Inputs/yields at refineries - barrels a day
Crude - Meraux, Louisiana........................................... 91,940 78,252 78,732 80,842 75,059
Superior, Wisconsin......................................... 33,217 30,592 30,358 26,207 26,916
Milford Haven, Wales........................................ 30,346 32,038 27,991 24,245 25,969
Other feedstocks.................................................... 8,280 8,731 10,350 12,857 11,310
- ------------------------------------------------------------------------------------------------------------------------------------
Total inputs 163,783 149,613 147,431 144,151 139,254
====================================================================================================================================
Gasoline............................................................ 73,964 67,746 66,460 67,710 60,491
Kerosine............................................................ 15,113 16,989 16,024 13,338 15,662
Diesel and home heating oils........................................ 39,351 35,553 34,356 32,848 32,055
Residuals........................................................... 19,641 15,444 16,441 18,474 17,237
Asphalt, LPG, and other............................................. 10,158 10,077 9,627 7,133 9,838
Fuel and loss....................................................... 5,556 3,804 4,523 4,648 3,971
- ------------------------------------------------------------------------------------------------------------------------------------
Total yields 163,783 149,613 147,431 144,151 139,254
====================================================================================================================================
Average cost of crude inputs to refineries - dollars a barrel
United States....................................................... $17.34 15.81 16.81 18.93 19.72
United Kingdom...................................................... 17.59 16.32 17.44 19.84 20.74
====================================================================================================================================
MARKETING
Products sold - barrels a day
United States - Gasoline............................................ 63,364 60,327 61,577 59,128 50,075
Kerosine............................................ 9,945 11,911 11,682 10,855 12,156
Diesel and home heating oils........................ 33,495 30,172 29,252 26,446 24,626
Residuals........................................... 14,775 10,454 11,812 12,339 11,926
Asphalt, LPG, and other............................. 8,815 7,754 6,519 5,611 5,228
- ------------------------------------------------------------------------------------------------------------------------------------
130,394 120,618 120,842 114,379 104,011
- ------------------------------------------------------------------------------------------------------------------------------------
United Kingdom - Gasoline........................................... 14,277 16,601 13,270 13,549 13,030
Kerosine........................................... 4,387 6,044 4,660 2,724 3,147
Diesel and home heating oils....................... 6,647 9,200 7,525 7,112 7,593
Residuals.......................................... 4,993 5,157 5,068 6,245 5,383
LPG and other...................................... 930 3,264 1,996 1,861 4,213
- ------------------------------------------------------------------------------------------------------------------------------------
31,234 40,266 32,519 31,491 33,366
- ------------------------------------------------------------------------------------------------------------------------------------
Canada 283 246 234 172 129
- ------------------------------------------------------------------------------------------------------------------------------------
Total products sold 161,911 161,130 153,595 146,042 137,506
====================================================================================================================================
Average gross margin on products sold - dollars a barrel
United States....................................................... $ .46 1.07 .82 .48 1.59
United Kingdom...................................................... 2.26 2.17 3.08 2.67 3.52
- ------------------------------------------------------------------------------------------------------------------------------------
Branded retail outlets*
United States....................................................... 514 588 606 643 622
United Kingdom...................................................... 465 470 428 391 370
Canada.............................................................. 7 8 8 7 6
====================================================================================================================================
TRANSPORTATION
Pipeline throughputs of crude oil - barrels a day - Canada 173,720 159,517 151,722 118,050 90,660
====================================================================================================================================
* At December 31.
49
- ------------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------------
FARM, TIMBER, AND REAL ESTATE
Acres owned(1) - Farmland............................................ 36,000 36,000 36,000 36,000 36,000
Timberland.......................................... 341,000 341,000 341,000 342,000 341,000
Real estate......................................... 9,000 10,000 10,000 10,000 10,000
- ------------------------------------------------------------------------------------------------------------------------------------
Acres harvested
Cotton............................................................ 4,263 3,972 4,839 4,518 4,099
Soybeans.......................................................... 14,695 14,318 14,863 12,798 15,584
Wheat............................................................. 2,787 1,405 1,482 1,209 6,391
Corn ............................................................. 5,340 5,567 3,717 4,586 4,162
Rice ............................................................. 502 491 330 622 1,019
- ------------------------------------------------------------------------------------------------------------------------------------
Yields per acre
Cotton - pounds................................................... 749 883 661 831 969
Soybeans - bushels................................................ 27 40 24 39 30
Wheat - bushels................................................... 41 59 40 59 21
Corn - bushels.................................................... 86 113 70 118 87
Rice - bushels.................................................... 91 124 107 107 112
- ------------------------------------------------------------------------------------------------------------------------------------
Estimated standing pine timber inventories(1)
Sawtimber - MBF-DS (thousand board feet - Doyle scale)............ 765,000 812,000 810,000 805,000 766,000
Pulpwood - cords.................................................. 1,180,000 991,000 963,000 940,000 989,000
- ------------------------------------------------------------------------------------------------------------------------------------
Company-owned pine timber harvested
Average sawtimber price(2) - dollars an MBF-DS.................... $ 406 372 310 274 202
Sawtimber - MBF-DS................................................ 35,736 40,616 37,635 30,177 32,956
Pulpwood - cords.................................................. 12,799 12,988 12,536 8,767 15,038
- ------------------------------------------------------------------------------------------------------------------------------------
Sawmills
Production
Finished lumber - MBF (thousand board feet)..................... 140,555 136,713 112,365 101,203 92,846
Pine chips - tons............................................... 224,148 227,506 193,618 236,180 229,105
Annual capacity(1) - MBF........................................ 165,000 165,000 122,600 100,100 100,100
Sales of finished lumber
MBF............................................................. 140,549 138,377 115,136 105,619 95,024
Average price - dollars an MBF.................................. $ 318 363 335 259 215
Average margin - dollars an MBF................................. 12 87 82 34 13
- ------------------------------------------------------------------------------------------------------------------------------------
Real estate
Residential lots sold............................................. 53 99 147 120 98
Average price - dollars a lot................................... $46,200 60,400 48,200 53,200 49,700
Commercial acres sold............................................. -- -- -- -- 17
Average price - dollars an acre................................. $ -- -- -- -- 32,700
====================================================================================================================================
STOCKHOLDER AND EMPLOYEE DATA
Common shares outstanding(1) (thousands)............................. 44,833 44,832 44,808 44,844 44,966
Number of stockholders of record(1).................................. 4,873 4,778 5,265 6,522 5,826
Number of employees(1)............................................... 1,794 1,767 1,803 1,787 3,991
Average number of employees.......................................... 1,786 1,778 1,787 1,857 4,001
Salaries, wages, and benefits (thousands)............................ $96,035 93,216 90,734 92,486 166,883
====================================================================================================================================
1 At December 31.
2 Includes intracompany transfers at market prices.
50
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13
(1995 Annual Report to Security Holders, Which is Incorporated in This
Form 10-K)
Providing a Narrative of Graphic and Image Material Appearing on
Pages 4 Through 50 of Paper Format
Exhibit 13
Page No. Map Narrative
- ---------- -------------
5 Gulf of Mexico - The locations and areal extent of acreage under lease
by the Company in the Gulf of Mexico (offshore Texas, Louisiana,
Mississippi, Alabama, and Florida) are shown. Additionally, each
lease is categorized as either: (1) producing or producible; (2)
discovery--commerciality to be determined/facilities to be installed;
(3) unexplored, dry hole(s), or noncommercial shows; or (4)
unexplored--acquired in 1995.
7 Canada - The locations and areal extent of acreage under lease by the
Company in British Columbia, Alberta, Saskatchewan, and Manitoba are
shown. Additionally, specific areas of production are identified
along with the types of production--natural gas, light oil, heavy
oil, and oil sands.
8 Offshore Eastern Canada - Depicted are the locations in the
North Atlantic Ocean east of Newfoundland of the Hibernia and Terra
Nova oil fields, in which the Company holds interests, and the
location where the production platform for the Hibernia field is
being constructed. Also depicted is an exploration license that the
Company acquired in 1995 in the Jeanne d'Arc Basin, midway between
the Hibernia and Terra Nova fields.
9 North Sea - The locations and areal extent of producing and
nonproducing acreage under license by the Company, primarily in the
U.K. sector of the North Sea, are shown. Blocks on which the
Company has significant oil and/or natural gas production, or
significant ongoing development projects, are specifically
identified.
12 Pakistan - The location and areal extent of two separate
exploration concessions located in Pakistan are shown. One
concession, acquired in 1995 in the Middle Indus Basin, includes
three blocks covering 4.4 million acres. Operations in the 6.7-
million-acre Kharan concession in western Pakistan remain suspended
under force majeure.
15 United States - The locations of the Company's refineries in Superior,
Wisconsin, and Meraux, Louisiana, are shown along with a depiction of
the predominant routes and means of moving crude oil to the
refineries, the routes and means of moving finished products from the
refineries into marketing areas, the terminal facilities used to
store and/or distribute products to wholesalers and consumers, and
the areal extent of the Company's marketing territories in 11 states
in the Southeast and four states in the upper-Midwest.
A-1
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Map Narrative (Continued)
- ---------- -------------
16 United Kingdom - The Company's jointly owned refinery in Milford Haven,
Wales, is shown along with a depiction of the normal route and means
of moving crude oil to the refinery, the routes and means of moving
finished products from the refinery into U.K. marketing areas,
locations of the terminal facilities used to store and/or distribute
products to wholesalers and consumers, and the areal extent of the
Company's marketing territory, which covers most of England and
southern Wales.
17 Western Crude Oil Pipeline Systems - The locations are shown in
southern Alberta and Saskatchewan of major Canadian crude oil
pipelines and two pipeline systems that are partially owned and
operated by the Company and deliver heavy oil into one of the major
pipelines. In addition, the locations are shown of two pipelines
owned by the Company that transport crude oil to the U.S. border for
further movement to refining centers in Montana, Wyoming, and
Colorado through pipelines owned by others and a pipeline system in
Montana and Wyoming in which the Company has an ownership.
Picture/Schematic Narrative
---------------------------
6 An aerial view is shown of a semi-submersible drilling barge in
the Gulf of Mexico on location at Viosca Knoll Block 783, where the
Company holds a 30-percent interest in the Tahoe field. After a
lengthy performance evaluation of the first well in the field and
interpretation of additional 3-D seismic information, the Company is
now engaged in a drilling program to bring additional production from
the field on stream by the fourth quarter of 1996.
8 A view is shown at Bull Arm, Newfoundland, depicting topside
modules for the Hibernia oil field being assembled on a pier. After
assembly is completed in the spring of 1997, the modules are to be
mounted on a concrete and steel Gravity Base Structure, which is
being constructed nearby. The completed 735-feet tall, 650,000-ton
structure will be towed at mid-year 1997 to the field, which is
approximately 200 miles east of St. John's, Newfoundland.
10 A schematic drawing depicts a recently approved production plan
for seven fields in the U.K. North Sea; the fields are known
collectively as the Eastern Trough Area Project. The drawing is a
cut-away view from the ocean surface, through the ocean floor, and
into the subsurface hydrocarbon formations of the fields. Murphy has
a 12.7-percent ownership interest in two of the fields--Mungo and
Monan, which are expected to reach peak gross production of 65,000
barrels of oil a day in 1999.
A-2
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Picture/Schematic Narrative (Continued)
- ---------- ---------------------------
11 A schematic drawing depicts the proposed development of the
Schiehallion field on Blocks 204/20 and 204/25, located west of the
Shetland Islands. The drawing is a cut-away view from the ocean
surface, through the ocean floor, and into the subsurface hydrocarbon
formation. Development of Schiehallion, in which the Company owns a
5.9-percent interest, is expected to begin in the second quarter of
1996, with first production in late 1997 or early 1998.
14 A view at dusk is shown from the eastern edge of the Company's
100,000-barrel-a-day refinery at Meraux, Louisiana; the refinery
established a new record of 91,940 barrels of crude processed per day
during 1995.
15 An outside view of a U.S. convenience store is shown as an
example of the Company's newly introduced retail service station
design.
16 A view is shown of the installation of the reactor vessel for a
high-pressure distillate hydrotreater unit being built at the 30-
percent owned Milford Haven, Wales, refinery. The hydrotreater unit
is expected to be commissioned in late 1996 and will enable the
refinery to make low-sulfur diesel fuel.
17 Company-owned trucking equipment is shown in front of several
crude oil storage tanks at the Milk River, Alberta, terminal operated
by the Company. The terminal serves as a crude handling location for
the Milk River Pipeline, one of two Company-operated pipelines that
carry Canadian crude oil to the U.S. border, from which it moves by
other pipelines to Rocky Mountain area refineries.
18 Two Deltic Farm & Timber employees are shown taking growth rate
measurements in a Company-owned pine forest. These measurements are
used to make growth rate predictions for similar pine forest tracts.
19 An aerial view is shown of the highly rated golf course and
certain surrounding single-family residences within the Chenal Valley
development in western Little Rock, Arkansas.
Graph Narrative
---------------
4 INCOME CONTRIBUTION* - EXPLORATION AND PRODUCTION
Scale - 0 to 50 (millions of dollars).
1991 1992 1993 1994 1995
---- ---- ---- ---- ----
Income* 23.4 35.9 36.9 45.2 29.5
==== ==== ==== ==== ====
*Before unusual or infrequently occurring items.
This is a vertical bar graph with each year's value printed above the
appropriate bar.
A-3
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- ---------- ---------------
4 CAPITAL EXPENDITURES - EXPLORATION AND PRODUCTION
Scale - 0 to 600 (millions of dollars).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Proved Property Acquisitions
(top) .3 13.9 259.7 26.6 7.2
Development Costs 45.7 36.8 195.8 173.5 148.9
Exploration Costs (bottom) 102.0 87.4 64.6 86.2 75.6
----- ----- ----- ----- -----
Totals 148.0 138.1 520.1 286.3 231.7
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
4 NET HYDROCARBONS PRODUCTION
Scale 0 to 120 (thousands of barrels a day on an energy
equivalent basis).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Other International (top) 6.7 4.6 3.2 5.1 7.2
United Kingdom 9.3 8.1 8.5 15.2 16.8
Canada 13.7 15.2 18.8 27.8 29.7
United States (bottom) 38.5 44.7 49.6 45.9 45.3
----- ----- ----- ----- -----
Totals 68.2 72.6 80.1 94.0 99.0
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
6 CRUDE OIL AND NGL PRODUCTION
Scale 0 to 70 (thousands of barrels a day).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Other International (top) 3.0 1.3 1.6 3.0 5.4
United Kingdom 7.8 5.9 6.3 13.5 15.0
Canada - Synthetic Oil - - - 9.1 8.9
Canada - Other Oil 9.4 10.2 12.7 12.4 14.0
United States (bottom) 13.3 13.4 13.7 13.3 13.7
----- ----- ----- ----- -----
Totals 33.5 30.8 34.3 51.3 57.0
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
6 NATURAL GAS SALES
Scale 0 to 320 (millions of cubic feet a day).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Spain (top) 22.2 19.4 9.5 12.6 10.9
United Kingdom 9.3 12.8 13.1 10.1 10.7
Canada 25.7 30.3 36.8 38.0 40.9
United States (bottom) 151.2 188.1 215.5 195.6 189.2
----- ----- ----- ----- -----
Totals 208.4 250.6 274.9 256.3 251.7
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
A-4
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- ---------- ---------------
13 INCOME CONTRIBUTION* - REFINING, MARKETING, AND TRANSPORTATION
Scale 0 to 50 (millions of dollars).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Income* 43.3 8.0 31.5 30.2 2.0
===== ===== ===== ===== =====
*Before unusual or infrequently occurring items.
This is a vertical bar graph with each year's value printed
above the appropriate bar.
13 CAPITAL EXPENDITURES - REFINING, MARKETING, AND TRANSPORTATION
Scale 0 to 120 (millions of dollars).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Transportation (top) 3.3 6.0 3.6 3.2 3.5
Marketing 15.2 14.1 16.9 17.0 9.2
Refining (bottom) 44.6 48.0 66.4 74.5 40.9
---- ---- ---- ---- ----
Totals 63.1 68.1 86.9 94.7 53.6
==== ==== ==== ==== ====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
13 REFINED PRODUCTS SOLD
Scale 0 to 200 (thousands of barrels a day).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
United Kingdom (top) 33.4 31.5 32.5 40.3 31.2
United States (bottom) 104.1 114.5 121.1 120.8 130.7
----- ----- ----- ----- -----
Totals 137.5 146.0 153.6 161.1 161.9
===== ====== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
17 CANADIAN PIPELINE THROUGHPUTS
Scale 0 to 200 (thousands of barrels a day).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Throughputs 90.7 118.1 151.7 159.5 173.7
==== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
18 INCOME CONTRIBUTION - FARM, TIMBER, AND REAL ESTATE
Scale 0 to 20 (millions of dollars).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Income 4.8 8.4 13.1 17.5 9.0
=== === ==== ==== ===
This is a vertical bar graph with each year's value printed
above the appropriate bar.
A-5
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- ---------- ---------------
18 CAPITAL EXPENDITURES - FARM, TIMBER, AND REAL ESTATE
Scale 0 to 14 (millions of dollars).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Capital Expenditures 2.9 6.0 9.7 11.4 9.1
=== === === ==== ===
This is a vertical bar graph with each year's value printed
above the appropriate bar.
18 SALES OF FINISHED LUMBER
Scale 0 to 160 (millions of board feet).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Lumber Sales 95.0 105.6 115.1 138.4 140.5
==== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
20 INCOME EXCLUDING UNUSUAL ITEMS
Scale 0 to 100 (millions of dollars).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Income Excluding Unusual Items 57.7 54.9 76.4 86.3 33.4
==== ==== ==== ==== ====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
20 NET CASH PROVIDED BY OPERATING ACTIVITIES
Scale 0 to 420 (millions of dollars).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Cash Provided 213.6 284.2 363.0 337.3 322.9
===== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
20 STOCKHOLDERS' EQUITY AT YEAR-END
Scale 0 to 1,500 (millions of dollars).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Stockholders' Equity 1,201 1,200 1,222 1,271 1,101
===== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
21 INCOME CONTRIBUTION BY OPERATING FUNCTION*
Scale 0 to 120 (millions of dollars).
1993 1994 1995
----- ----- -----
Farm, Timber, and Real Estate (top) 13.1 17.5 9.0
Refining, Marketing, and Transportation 31.5 30.2 2.0
Exploration and Production (bottom) 36.9 45.2 29.5
---- ---- ----
Totals 81.5 92.9 40.5
==== ==== ====
*Excludes Corporate and unusual or infrequently
occurring items.
This is a stacked vertical bar graph with the value for
each element printed within or beside the element.
A-6
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- ---------- ---------------
22 RANGE OF U.S. CRUDE OIL SALES PRICES
Scale 10 to 20 (dollars a barrel).
1993 1994 1995
----- ----- -----
High Monthly Crude Oil Price (top of bar) 18.42 17.58 18.06
Average Crude Oil Price (colored line) 16.60 15.36 16.61
Low Monthly Crude Oil Price (bottom of bar) 12.52 12.71 15.42
This is a floating vertical bar graph with a contrasting-
color line between the top and bottom each year and highs
printed above bars, averages printed above colored lines, and
lows printed below bars.
22 RANGE OF U.S. NATURAL GAS SALES PRICES
Scale 1.25 to 2.75 (dollars a thousand cubic feet).
1993 1994 1995
----- ----- -----
High Monthly Natural Gas Price (top of bar) 2.51 2.40 2.45
Average Natural Gas Price (colored line) 2.10 1.91 1.64
Low Monthly Natural Gas Price (bottom of bar) 1.63 1.42 1.39
This is a floating vertical bar graph with a contrasting-
color line between the top and bottom each year and highs
printed above bars, averages printed above colored lines, and
lows printed below bars.
23 EXPLORATION EXPENSES
Scale 0 to 75 (millions of dollars).
1993 1994 1995
----- ----- -----
Undeveloped Lease Amortization (top) 12.1 11.0 10.7
Geological, Geophysical, and Other Costs 12.5 15.1 24.2
Dry Hole Costs (bottom) 21.5 16.6 30.9
---- ---- ----
Totals 46.1 42.7 65.8
==== ==== ====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
24 AVERAGE SAWMILL MARGIN
Scale 0 to 100 (dollars a thousand board feet).
1993 1994 1995
----- ----- -----
Average Margin 82 87 12
== == ==
This is a vertical bar graph with each year's value printed
above the appropriate bar.
A-7
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- ---------- ---------------
25 CAPITAL EXPENDITURES IN 1995
Scale 0 to 350 (millions of dollars).
Percent
-------
Other - $1.9 (top) 1
Farm, Timber, and Real Estate - $9.1 3
Refining, Marketing, and Transportation - $53.6 18
Exploration and Production - $231.7 (bottom) 78
This is a stacked vertical bar graph with a line from each
component to its respective percentage and "Total - $296.3"
printed below graph.
43 ESTIMATED NET PROVED OIL RESERVES
Scale 0 to 250 (millions of barrels).
1991 1992 1993 1994 1995
---- ---- ---- ---- ----
Other International (top) .2 1.8 1.9 - -
Ecuador 33.5 35.6 33.6 35.0 29.6
United Kingdom 14.7 13.1 26.7 24.5 40.0
Canada 21.8 22.3 120.2 136.3 132.5
United States (bottom) 22.8 23.2 20.0 24.5 24.6
---- ---- ----- ----- -----
Totals 93.0 96.0 202.4 220.3 226.7
==== ==== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
43 ESTIMATED NET PROVED GAS RESERVES
Scale 0 to 800 (billions of cubic feet).
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Spain (top) 16.6 4.1 10.6 7.2 3.8
United Kingdom 41.1 35.4 31.2 29.6 47.4
Canada 204.9 200.4 182.7 176.7 160.1
United States (bottom) 396.2 445.4 429.0 430.1 431.5
----- ----- ----- ----- -----
Totals 658.8 685.3 653.5 643.6 642.8
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
43 ESTIMATED NET PROVED HYDROCARBON RESERVES
Scale 0 to 400 (millions of barrels on an energy
equivalent basis).
1991 1992 1993 1994 1995
---- ---- ---- ---- ----
Other International (top) 36.5 38.1 37.2 36.2 30.2
United Kingdom 21.5 19.0 31.9 29.4 47.9
Canada 56.0 55.7 150.7 165.8 159.2
United States (bottom) 88.8 97.4 91.5 96.2 96.5
----- ----- ----- ----- -----
Totals 202.8 210.2 311.3 327.6 333.8
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
A-8
EXHIBIT 21
MURPHY OIL CORPORATION
PARENTS AND SUBSIDIARIES AS OF DECEMBER 31, 1995
Percentage
of Voting
Securities
State or Other Owned by
Jurisdiction Immediate
Name of Company of Incorporation Parent
- ---------------------------------------------------------------------- ---------------- ----------
MURPHY OIL CORPORATION (REGISTRANT)
A. Deltic Farm & Timber Co., Inc. Arkansas 100.0
1. Chenal Properties, Inc. Arkansas 100.0
2. Deltic Timber Purchasers, Inc. Arkansas 100.0
B. El Dorado Engineering Inc. Delaware 100.0
1. El Dorado Contractors Inc. Delaware 100.0
C. Murphy Eastern Oil Company Delaware 100.0
D. Murphy Exploration & Production Company (formerly Ocean
Drilling & Exploration Company) Delaware 100.0
1. Canam Offshore A. G. (Switzerland) Switzerland 100.0
2. Canam Offshore Limited Bahamas 100.0
a. Odeco Drilling Limited Bahamas 100.0
b. Rimrock Offshore Limited Bahamas 100.0
3. El Dorado Exploration, S.A. Delaware 100.0
4. Mentor Holding Corporation Delaware 100.0
a. Mentor Excess and Surplus Lines Insurance Company Delaware 100.0
b. Mentor Insurance and Reinsurance Company Louisiana 100.0
c. Mentor Insurance Limited Bermuda 99.993
(1) Mentor Insurance Company (U.K.) Limited England 100.0
(2) Mentor Underwriting Agents (U.K.) Limited England 100.0
5. MEPCO Venezuela, Ltd. Bahamas 100.0
6. Murphy Building Corporation Delaware 100.0
7. Murphy Denmark Oil Company Delaware 100.0
8. Murphy Ecuador Oil Company Ltd. Bermuda 100.0
9. Murphy Equatorial Guinea Oil Company Delaware 100.0
10. Murphy France Oil Company Delaware 100.0
11. Murphy Indus Energy Ltd. Bahamas 100.0
12. Murphy Ireland Oil Company Delaware 100.0
13. Murphy Italy Oil Company Delaware 100.0
14. Murphy New Zealand Oil Company Delaware 100.0
15. Murphy Overseas Ventures Inc. Delaware 100.0
16. Murphy Pacific Rim, Ltd. Bahamas 100.0
17. Murphy Pakistan Oil Company Delaware 100.0
18. Murphy Peru Oil Company, S.A. Panama 100.0
19. Murphy Somali Oil Company Delaware 100.0
20. Murphy-Spain Oil Company Delaware 100.0
21. Murphy Western Oil Company Delaware 100.0
22. Murphy Yemen Oil Company Delaware 100.0
23. Norske Murphy Oil Company Delaware 100.0
24. Norske Ocean Exploration Company Delaware 100.0
25. Ocean Exploration Company Delaware 100.0
26. Ocean France Oil Company Delaware 100.0
27. Ocean Gabon Oil Company Delaware 100.0
28. Ocean International Finance Corporation Delaware 100.0
29. Ocean Spain Oil Company Delaware 100.0
Ex. 21-1
EXHIBIT 21 (CONTD.)
MURPHY OIL CORPORATION
PARENTS AND SUBSIDIARIES AS OF DECEMBER 31, 1995 (CONTD.)
Percentage
of Voting
Securities
State or Other Owned by
Jurisdiction Immediate
Name of Company of Incorporation Parent
- ---------------------------------------------------------------------- ---------------- ----------
MURPHY OIL CORPORATION (REGISTRANT) - Contd.
D. Murphy Exploration & Production Company - Contd.
30. Odeco Gabon Oil Company Delaware 100.0
31. Odeco International Corporation Panama 100.0
32. Odeco Italy Oil Company Delaware 100.0
33. Sub Sea Offshore (M) Sdn. Bhd. Malaysia 60.0
E. Murphy Oil Company, Ltd. Canada 100.0
1. 340236 Alberta Ltd. Canada 100.0
2. Manito Pipelines Ltd. Canada 52.5
3. Murphy Atlantic Offshore Oil Company Ltd. Canada 100.0
4. Wascana Pipe Line Ltd. Canada 100.0
F. Murphy Oil USA, Inc. Delaware 100.0
1. Arkansas Oil Company Delaware 100.0
2. Murphy Gas Gathering Inc. Delaware 100.0
3. Murphy Latin America Refining & Marketing, Inc. Delaware 100.0
4. Murphy LOOP, Inc. Delaware 100.0
5. Murphy Oil Trading Company (Eastern) Delaware 100.0
6. Spur Oil Corporation Delaware 100.0
G. Murphy Ventures Corporation Delaware 100.0
H. New Murphy Oil (UK) Corporation Delaware 100.0
1. Murphy Petroleum Limited England 100.0
a. Murco Petroleum Limited England 100.0
(1) Alnery No. 166 Ltd. England 100.0
(2) European Petroleum Distributors Ltd. England 100.0
(3) H. Hartley (Doncaster) Ltd. England 100.0
(4) Murco Petroleum (Ireland) Ltd. Ireland 100.0
Ex. 21-2
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
-----------------------------
The Board of Directors
Murphy Oil Corporation:
We consent to incorporation by reference in the Registration Statements (Nos.
2-82818, 2-86749, and 2-86760) on Form S-8 and (No. 33-55161) on Form S-3 of
Murphy Oil Corporation of our report dated March 1, 1996, relating to the
consolidated balance sheets of Murphy Oil Corporation and Consolidated
Subsidiaries as of December 31, 1995 and 1994, and the related consolidated
statements of income, stockholders' equity, and cash flows for each of the years
in the three-year period ended December 31, 1995, which report is included in
the December 31, 1995, annual report on Form 10-K of Murphy Oil Corporation.
Our report refers to changes in 1995 in the method of accounting for the
impairment of long-lived assets and for long-lived assets to be disposed of and
to changes in 1993 in the methods of accounting for income taxes and
postretirement benefits other than pensions.
KPMG PEAT MARWICK LLP
Shreveport, Louisiana
March 26, 1996
Ex. 23-1
5
1,000
YEAR
DEC-31-1995
DEC-31-1995
62,248
0
240,679
5,863
175,802
520,119
4,189,717
2,702,485
2,119,113
415,610
193,935
48,775
0
0
1,052,370
2,119,113
1,646,053
1,711,213
1,500,704
1,500,704
264,743
0
5,722
(134,027)
(15,415)
(118,612)
0
0
0
(118,612)
(2.64)
(2.64)
INCLUDES 198,988 FOR IMPAIRMENT OF LONG-LIVED ASSETS.
5
1,000
YEAR
DEC-31-1994
DEC-31-1994
71,144
0
249,795
5,554
152,431
519,112
4,013,355
2,342,421
2,312,032
439,518
172,452
48,775
0
0
1,221,904
2,312,032
1,620,847
1,699,163
1,430,382
1,430,382
42,741
0
2,561
156,900
50,272
106,628
0
0
0
106,628
2.37
2.37
AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO 1995 PRESENTATION.
EXHIBIT 99.1
UNDERTAKINGS
To be incorporated by reference into Form S-8 Registration Statements No.
2-82818, 2-86749 and 2-86760, and Form S-3 Registration Statement No. 33-55161.
The undersigned registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being made, a
post-effective amendment to this registration statement:
(i) To include any prospectus required by section 10(a)(3) of the
Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events arising after the
effective date of the registration statement (or the most recent post-effective
amendment thereof) which, individually or in the aggregate, represents a
fundamental change in the information set forth in the registration statement;
(iii) To include any material information with respect to the plan of
distribution not previously disclosed in the registration statement or any
material change to such information in the registration statement;
(2) That, for the purpose of determining any liability under the Securities
Act of 1933, each such post-effective amendment shall be deemed to be a new
registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial bona
fide offering thereof.
(3) To remove from registration by means of a post-effective amendment any
of the securities being registered which remain unsold at the termination of the
offering.
The undersigned registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
registrant's annual report pursuant to section 13(a) or section 15(d) of the
Securities Exchange Act of 1934 (and, where applicable, each filing of an
employee benefit plan's annual report pursuant to section 15(d) of the
Securities Exchange Act of 1934) that is incorporated by reference in the
registration statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
The undersigned registrant hereby undertakes:
(1) To deliver or cause to be delivered with the prospectus to each
employee to whom the prospectus is sent or given a copy of the registrant's
annual report to stockholders for its last fiscal year, unless such employee
otherwise has received a copy of such report, in
Ex. 99.1-1
which case the registrant shall state in the prospectus that it will promptly
furnish, without charge, a copy of such report on written request of the
employee. If the last fiscal year of the registrant has ended within 120 days
prior to the use of the prospectus, the annual report of the registrant for the
preceding fiscal year may be so delivered, but within such 120 day period the
annual report for the last fiscal year will be furnished to each such employee.
(2) To transmit or cause to be transmitted to all employees participating
in the plan who do not otherwise receive such material as stockholders of the
registrant, at the time and in the manner such material is sent to its
stockholders, copies of all reports, proxy statements and other communications
distributed to its stockholders generally.
Where interests in a plan are registered herewith, the undersigned
registrant and plan hereby undertake to transmit or cause to be transmitted
promptly, without charge, to any participant in the plan who makes a written
request, a copy of the then latest annual report of the plan filed pursuant to
section 15(d) of the Securities Exchange Act of 1934 (Form 11-K). If such
report is filed separately on Form 11-K, such form shall be delivered upon
written request. If such report is filed as a part of the registrant's annual
report on Form 10-K, that entire report (excluding exhibits) shall be delivered
upon written request. If such report is filed as a part of the registrant's
annual report to stockholders delivered pursuant to paragraph (1) or (2) of this
undertaking, additional delivery shall not be required.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
registrant pursuant to the foregoing provisions, or otherwise, the registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Act and is,
therefore, unenforceable. In the event that a claim for indemnification against
such liabilities (other than the payment by the registrant of expenses incurred
or paid by a director, officer or controlling person of the registrant in the
successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Act and will be governed by the final adjudication of
such issue.
Ex. 99.1-2
