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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, 1993
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [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, 71731-7000
El Dorado, Arkansas (Zip Code)
(Address of principal executive offices)
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
Preferred Stock Purchase Rights New York Stock Exchange
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. [X] Yes [_] 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. [ X ]
Aggregate market value of the voting stock held by non-affiliates of the
registrant, based on average price at February 28, 1994 as quoted by the New
York Stock Exchange, was approximately $1,276,693,000.
Number of shares of Common Stock, $1.00 Par Value, outstanding at February 28,
1994, was 44,806,705.
Documents incorporated by reference
The Registrant's definitive Proxy Statement relating to the Annual Meeting of
Stockholders on May 11, 1994 (Part III)
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TABLE OF CONTENTS--1993 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
and Management 10
Item 13. Certain Relationships and Related Transactions 10
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 11
Signatures 18
Exhibit Index 19
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 business segments.
The information appearing on pages 4 through 62 of the 1993 Annual Report
to Security Holders (1993 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 62 is included in the
electronic Form 10-K document as an appendix to Exhibit 13 (pages A-1
through A-9).
In addition to the following information about each business segment, data
relative to Murphy's continuing operations, properties, and industry
segments, including revenues by class of products and financial information
by geographic areas, are described on pages 23 through 30 and 50 through 53
of the 1993 Annual Report, which is filed in this 10-K report as Exhibit
13.
PETROLEUM--EXPLORATION AND PRODUCTION
During 1993, Murphy's principal exploration and/or production activities
were conducted in the United States, Ecuador, Spain, Gabon, and Peru by
Murphy Exploration & Production Company (Murphy Expro) and its
subsidiaries; in Canada by Murphy Oil Company Ltd. (MOCL); and in the U.K.
North Sea by Murphy Petroleum Limited. Murphy's crude oil and natural gas
liquids production is in the United States, Canada, the U.K. North Sea,
Gabon, and Spain; its natural gas is produced and sold in the United
States, Canada, the U.K. North Sea, and Spain. In December 1993, MOCL
acquired a five-percent interest in a project (Syncrude) that 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, 1991 and at December 31, 1991,
1992, and 1993 by geographic area are reported on pages 55 and 56 of the
1993 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 U.S. operated properties to the
U.S. Department of Energy; such reserves are derived from the same data
from which estimated total proved net reserves of such properties are
determined.
In 1993, essentially all of Murphy's U.S. crude oil, condensate, and
natural gas liquids production 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,
1993 appear on page 60 of the 1993 Annual Report, which is filed in this
10-K report as Exhibit 13.
3
PETROLEUM - EXPLORATION AND PRODUCTION (Contd.)
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 in the following
table.
United United
Year States Canada Kingdom Ecuador Other
---- ------ ------ ------- ------- -----
1993 $ 3.21 3.70 6.80 - 8.42
1992 3.00 4.18 8.73 - 7.01
1991 3.42 4.90 7.25 - 3.62
Supplemental disclosures about oil and gas producing activities are reported on
pages 54 through 59 of the 1993 Annual Report, which is filed in this report as
Exhibit 13.
At December 31, 1993, Murphy held leases, concessions, 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 State - Onshore 79 36 285 60 364 96
- Gulf of Mexico 600 352 442 162 1,042 514
- Frontier 259 139 - - 259 139
------ ----- ----- --- ------ -----
Total United States 938 527 727 222 1,665 749
------ ----- ----- --- ------ -----
Canada - Onshore 748 346 443 180 1,191 526
- Offshore 83 5 - - 83 5
- Oil sands 126 42 27 3 153 45
------ ----- ----- --- ------ -----
Total Canada 957 393 470 183 1,427 576
------ ----- ----- --- ------ -----
United Kingdom 615 124 80 11 695 135
Gabon 2 - 34 9 36 9
Spain 61 11 28 5 89 16
Ecuador 494 99 - - 494 99
Pakistan 6,720 6,720 - - 6,720 6,720
Peru 2,471 988 - - 2,471 988
Somalia 4,023 402 - - 4,023 402
Tunisia 165 42 - - 165 42
------ ----- ----- --- ------ -----
Totals 16,446 9,306 1,339 430 17,785 9,736
====== ===== ===== === ====== =====
Oil and gas wells producing or capable of producing at December 31, 1993 are
summarized as follows.
Oil Wells Gas Wells
---------------- ----------------
Country Gross Net Gross Net
------- ----- ------- ----- -------
United States 1,585 567.9 426 146.4
Canada 4,041 630.0 607 206.0
United Kingdom 80 7.9 16 1.1
Gabon 7 3.1 - -
Spain - - 2 .3
Ecuador (under development) 13 2.6 - -
----- ------- ----- -----
Totals 5,726 1,211.5 1,051 353.8
===== ======= ===== =====
Wells included above with multiple
completions and counted as one well each 120 49.9 115 65.4
===== ======= ===== =====
Gross wells are wells 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 States Canada United Kingdom Ecuador Other Totals
---------------- ---------------- ---------------- ---------------- ---------------- -----------------
Productive Dry Productive Dry Productive Dry Productive Dry Productive Dry Productive Dry
---------- --- --------- --- ---------- --- ---------- --- ---------- --- ---------- ----
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
1992
Exploratory 7.8 5.2 3.1 1.3 .5 1.0 - - - 1.0 11.4 8.5
Development 2.2 - 18.4 1.3 .3 - - - - - 20.9 1.3
1991
Exploratory 13.4 5.3 3.7 5.0 .3 1.1 - - .3 .3 17.7 11.7
Development 1.7 .6 7.7 1.9 .3 - - - - - 9.7 2.5
The wells that Murphy was drilling at December 31, 1993 are summarized as
follows.
Exploratory Development Totals
------------- ------------- -------------
Country Gross Net Gross Net Gross Net
- - - -------------- ----- --- ----- --- ----- ---
United States 4 1.6 - - 4 1.6
Canada 5 2.5 5 3.1 10 5.6
United Kingdom 2 .4 - - 2 .4
-- --- -- --- -- ---
Totals 11 4.5 5 3.1 16 7.6
== === == === == ===
Additional information about current exploration and production activities is
reported on pages 4 through 14 of the 1993 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, 1993 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 40,000 20,000 16,500 76,500
Catalytic cracking - fresh feed 40,000 11,000 9,960 60,960
Pretreating cat-reforming feeds 29,000 9,000 5,400 43,400
Catalytic reforming 23,000 8,000 5,400 36,400
Distillate hydrotreating 15,000 5,800 9,000 29,800
Gas oil hydrotreating 28,000 - - 28,000
Solvent deasphalting 14,000 - - 14,000
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. 4,257,000 2,852,000 2,638,000 9,747,000
*Barrels per stream day.
Murphy distributes refined products in the U.S. (by Murphy USA) and Canada (by
MOCL) under the brand name SPUR and to unbranded wholesale accounts from 47
terminals. Four of these are marine terminals, two are supplied by truck, two
are adjacent to the refineries, and 38 are supplied by pipeline. Eight terminals
are wholly owned and operated by Murphy USA, 15 are jointly owned and operated
by others, and the remaining 24 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 1993, refined
products were marketed at wholesale and/or retail through 606 branded outlets in
14 southeastern and upper midwestern states and eight branded outlets in the
Thunder Bay area of Ontario, Canada.
At the end of 1993, Murco distributed refined products in the United Kingdom
through three wholly owned terminals, 10 terminals owned by others where
products are received in exchange for deliveries from the Company's wholly owned
terminals, and 428 retail 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, thus allowing crude oil from wells serviced by that system to
be shipped to the refinery.
MOCL has 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 trunk line is available. This pipeline has a
throughput capacity of 50,000 barrels a day. MOCL also owns a 13.1-percent
interest in a 40-mile, 38,000-barrel-a-day dual pipeline to transport heavy
crude oil from Cactus Lake, Saskatchewan, to Kerrobert; a 26.3-percent interest
in a 15-mile, 9,000-barrel-a-day dual crude oil pipeline from Bodo, Alberta, to
Cactus Lake; a 100-percent interest in a 10.5-mile, 48,000-barrel-a-day dual
crude oil pipeline from Milk River, Alberta, to the U.S. border; a 100-percent
interest in a 108-mile, 36,000-barrel-a-day crude oil pipeline from Regina,
Saskatchewan, to the U.S. border; and a 100-percent interest in a 28-mile,
15,000-barrel-a-day heavy crude oil pipeline from Eyehill, Saskatchewan, to
Unity, Saskatchewan. MOCL is operator of these pipelines.
6
PETROLEUM--REFINING, MARKETING, AND TRANSPORTATION (Contd.)
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, 1993 are reported on pages 15
through 20 and 61 of the 1993 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 western
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 122.6 million
board feet of lumber. The Ola mill is designed 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 1993. 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.
1993 1992 1991
------- ------- -------
Pine sawtimber - MBF* 810,162 805,260 766,130
Hardwood sawtimber - MBF* 113,290 114,000 111,104
Pine pulpwood - cords 962,563 940,477 988,790
Hardwood pulpwood - cords 417,293 448,100 436,208
======= ======= =======
*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 recent years, Deltic has been developing in
stages a 4,300-acre planned community centered around an 18-hole golf course
(voted in 1991 by "Golf Digest" as being one of the three best new private
courses in the United States) and selling real estate, primarily residential
lots thus far, in this area of western Little Rock, Arkansas. The golf course
and associated country club are in a nonprofit corporation not owned by the
Company.
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, 1993 are reported on pages 21, 22, and 62 of
the 1993 Annual Report, which is filed in this 10-K report as Exhibit 13.
DISCONTINUED OPERATIONS
Prior to the sale effective January 1, 1992 of its wholly owned subsidiary Odeco
Drilling Inc., Murphy was engaged in contract drilling in offshore waters
throughout the world. Further information about the sale is reported by Note D
on page 39 of the 1993 Annual Report, which is filed in this 10-K report as
Exhibit 13.
Effective December 31, 1984, Murphy Expro, at that time named Ocean Drilling &
Exploration Company (ODECO) and owned 59.4 percent by Murphy, elected to cease
the operations of Mentor Insurance Limited, its wholly owned subsidiary that was
engaged in the international insurance and reinsurance business. Events related
to the liquidation of this business are reported by Note E on page 39 of the
1993 Annual Report, which is filed in this 10-K report as Exhibit 13.
EMPLOYEES
Murphy had 1,803 full-time employees at December 31, 1993.
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.
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 categories of 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 of the
environment (See Management's Discussion and Analysis - Environmental
Obligations, page 30 of the 1993 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 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. OIL
was organized to insure 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, 1994), 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.
C. H. Murphy Jr - Age 73; Chairman of the Board since 1972. He has been a
Director and Member of the Executive Committee since incorporation of the
Company in 1950 and was Chief Executive Officer from incorporation until 1984.
Jack W. McNutt - Age 59; President, Chief Executive Officer, Director, and
Member of the Executive Committee since 1988. Mr. McNutt was Executive Vice
President, Director, and Member of the Executive Committee from 1981 to 1988;
he was named Chief Operating Officer in 1986.
Claiborne P. Deming - Age 39; Executive Vice President and Chief Operating
Officer, Director, and Member of the Executive Committee since February 1993.
Mr. Deming had been Executive Vice President and Chief Operating Officer since
March 1992. Prior to that, he was President of Murphy USA from 1989 to 1992
and Vice President, Petroleum Operations, for Murphy from 1988 to 1989.
R. Madison Murphy - Age 36; Executive Vice President and Chief Financial and
Administrative Officer, Director, and member of the Executive Committee since
February 1993. Mr. Murphy had been Executive Vice President and Chief
Financial Officer since March 1992. Prior to that, he was 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.
8
EXECUTIVE OFFICERS OF THE REGISTRANT (Contd.)
Steven A. Cosse - Age 46; Vice President and General Counsel since February
1993. Mr. Cosse was General Counsel from August 1991 to February 1993. For the
eight years prior to that, he was General Counsel for ODECO.
Odie F. Vaughan - Age 57; Treasurer since August 1991. From 1975 through July
1991, he was with ODECO as Vice President of Taxes and Treasurer.
Ronald W. Herman - Age 56; Controller since August 1991. He was Controller of
ODECO from 1977 through July 1991.
W. Bayless Rowe - Age 41; Secretary and General Attorney since 1988. He has
been an attorney with the Company since 1977.
ITEM 3. LEGAL PROCEEDINGS.
Information contained in Note E, page 39, and Note S, pages 49 through 50, of
the 1993 Annual Report, which is filed in this 10-K report as Exhibit 13, is
incorporated herein. Also, Murphy Oil USA, Inc., which owns and operates two
oil refineries in the U.S., is a defendant in three 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.
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 1993.
9
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
Information required by this item is reported on pages 31 and 44 through
46, Notes K and L, of the 1993 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 23 of the 1993 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 24 through 30 of the
1993 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 31 through 59 of the
1993 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 11, 1994,
under the caption "Election of Directors."
ITEM 11. EXECUTIVE COMPENSATION.
Information is incorporated by reference to the Registrant's definitive
proxy statement for the annual meeting of stockholders on May 11, 1994,
under the captions "Compensation of Directors," "Executive Compensation,"
"Option Exercises and Fiscal Year-End Values," "Option Grants,"
"Compensation Committee Report for 1993," "Shareholder Return Performance
Presentation," and "Retirement Plans."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information is incorporated by reference to the Registrant's definitive
proxy statement for the annual meeting of stockholders on May 11, 1994,
under the caption "Certain Stock Ownerships."
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information is incorporated by reference to the Registrant's definitive
proxy statement for the annual meeting of stockholders on May 11, 1994,
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 32
Consolidated Statements of Income 33
Consolidated Balance Sheets 34
Consolidated Statements of Cash Flows 35
Consolidated Statements of Stockholders' Equity 36
Notes to Consolidated Financial Statements 37 through 53
(a) 2. FINANCIAL STATEMENT SCHEDULES
The following financial statement schedules of Murphy Oil Corporation
and consolidated subsidiaries are included in this 10-K report on the
pages as indicated below. All other schedules are omitted because either
they are not applicable or the required information is included in the
consolidated financial statements or notes thereto.
10-K
Page Nos.
---------
Independent Auditors' Report on Schedules 12
Schedule I --Marketable Securities 13
Schedule V --Property, Plant, and Equipment 14
Schedule VI--Accumulated Depreciation,
Depletion, and Amortization
of Property, Plant, and Equipment 15
Schedule IX--Short-term Borrowings 16
Schedule X --Supplementary Income
Statement Information 17
(a) 3. EXHIBITS
The Exhibit Index on page 19 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,
1993.
11
INDEPENDENT AUDITORS' REPORT ON SCHEDULES
-----------------------------------------
The Board of Directors
Murphy Oil Corporation:
Under date of March 4, 1994, we reported on the consolidated balance sheets of
Murphy Oil Corporation and Consolidated Subsidiaries as of December 31, 1993 and
1992, 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,
1993, as contained in the 1993 annual report to stockholders. These consolidated
financial statements and our report thereon are included in Exhibit 13 in the
annual report on Form 10-K for the year 1993. In connection with our audits of
the aforementioned consolidated financial statements, we also have audited the
financial statement schedules as listed under Item 14 (a) 2. These financial
statement schedules are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statement schedules
based on our audits.
In our opinion, such financial statement schedules, when considered in relation
to the basic consolidated financial statements taken as a whole, present fairly,
in all material respects, the information set forth therein.
As discussed in Note B to the consolidated financial statements, the Company
adopted the provisions of Financial Accounting Standards Board's 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," in 1993.
KPMG PEAT MARWICK
Shreveport, Louisiana
March 4, 1994
12
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SCHEDULE I - MARKETABLE SECURITIES
December 31, 1993
----------------------------------------------------
(Thousands of dollars)
Approx.
Market
Value at Balance
Principal Above Sheet
Name of Issuer and Title of Issue Amount Cost Date* Amount*
- - - ---------------------------------- --------- ------ -------- -------
United States Government - Treasury bills $ 91,608 90,620 90,932 90,932
Government of Canada - Treasury bills 8,259 8,227 8,242 8,242
Reverse repurchase agreements 15,170 15,170 15,175 15,175
-------- ------- ------- -------
Total Marketable Securities $115,037 114,017 114,349 114,349
======== ======= ======= =======
*Includes accrued interest.
13
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SCHEDULE V--PROPERTY, PLANT, AND EQUIPMENT
Three years ended December 31, 1993
----------------------------------------------------
(Thousands of dollars)
Balance at Other Balance at
beginning Additions changes - end of
Classification of period at cost Retirements add/(deduct) period
- - - -------------- ---------- --------- ----------- ------------- ----------
YEAR ENDED DECEMBER 31, 1991
Exploration and production $2,233,477 116,758 27,528 55 (1)
111,960 (2)
(10,648) (3)
161 (4)
9,636 (5) 2,433,871
Refining 349,664 44,588 114 8 (1)
(1,556) (3) 392,590
Marketing 122,394 15,184 5,769 (20) (1)
(1,352) (3)
853 (6) 131,290
Transportation 57,666 3,371 46 (43) (1)
79 (3) 61,027
Farms, timber, and real estate 155,685 2,858 1,923 (5,225) (7) 151,395
Corporate and other 60,220 2,203 324 (48) (3) 62,051
---------- ------- ------- -------- ---------
$2,979,106 184,962 35,704 103,860 3,232,224
========== ======= ======= ======== =========
YEAR ENDED DECEMBER 31, 1992
Exploration and production $2,433,871 115,296 112,353 41,742 (1)
(129,363) (3)
1,494 (4) 2,350,687
Refining 392,590 47,942 224 (21,011) (3) 419,297
Marketing 131,290 14,111 3,592 (12,462) (3) 129,347
Transportation 61,027 6,020 125 (5,026) (1)
(2,997) (3) 58,899
Farms, timber, and real estate 151,395 6,017 2,619 (928) (7) 153,865
Corporate and other 62,051 1,477 362 (36,716) (1)
(878) (3) 25,572
---------- ------- ------- -------- ---------
$3,232,224 190,863 119,275 (166,145) 3,137,667
========== ======= ======= ======== =========
YEAR ENDED DECEMBER 31, 1993
Exploration and production $2,350,687 503,018 56,768 (140) (1)
(44,585) (3)
97 (4)
107,515 (8)
(828) (9) 2,858,996
Refining 419,297 66,364 58 209 (1)
(1,769) (3) 484,043
Marketing 129,347 16,941 4,723 93 (1)
(1,180) (3) 140,478
Transportation 58,899 3,580 148 134 (1)
(1,337) (3)
580 (8) 61,708
Farms, timber, and real estate 153,865 9,674 3,737 (6) (1)
(1,045) (7)
(11)(10) 158,740
Corporate and other 25,572 4,034 3,089 (291) (1)
(209) (3) 26,017
---------- ------- ------- -------- ---------
$3,137,667 603,611 68,523 57,227 3,729,982
========== ======= ======= ======== =========
(1) Transfers between classifications.
(2) Fair value in excess of book value of properties acquired from minority
interest.
(3) Amounts applicable to foreign currency translations.
(4) Depreciation applicable to used well equipment included in purchase of
producing properties.
(5) Reclassified from investments.
(6) Cancellation or reclassification of capitalized lease obligations.
(7) Reclassified to investments and deferred charges.
(8) Effect of SFAS No. 109 on prior business combinations.
(9) Reclassified from deferred income tax liability.
(10) Other.
14
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION, AND
AMORTIZATION OF PROPERTY, PLANT, AND EQUIPMENT
Three years ended December 31, 1993
------------------------------------------------------
(Thousands of dollars)
Additions
Balance at charged to Other Balance at
beginning costs and changes - end of
Classification of period expenses Retirements add/(deduct) period
- - - -------------- ---------- ---------- ----------- ------------ ----------
YEAR ENDED DECEMBER 31, 1991
Exploration and production $1,593,936 159,448 24,557 (184) (1)
(8,397) (2)
161 (3)
9,128 (4) 1,729,535
Refining 215,012 17,358 95 5 (1)
(793) (2) 231,487
Marketing 40,969 5,988 2,370 3 (1)
(421) (2)
853 (5) 45,022
Transportation 24,375 2,638 35 177 (1)
35 (2) 27,190
Farms, timber, and real estate 43,513 3,221 346 - 46,388
Corporate and other 20,476 3,673 257 (1) (1)
(29) (2)
99 (4) 23,961
---------- ------- ------- -------- ----------
$1,938,281 192,326 27,660 636 2,103,583
========== ======= ======= ======== ==========
YEAR ENDED DECEMBER 31, 1992
Exploration and production $1,729,535 147,407 111,051 15,964 (1)
(91,893) (2)
1,494 (3) 1,691,456
Refining 231,487 20,623 193 (14) (1)
(8,487) (2) 243,416
Marketing 45,022 6,696 3,076 45 (1)
(4,817) (2) 43,870
Transportation 27,190 2,560 120 (3,220) (1)
(1,262) (2) 25,148
Farms, timber, and real estate 46,388 3,120 710 - 48,798
Corporate and other 23,961 1,432 297 (12,775) (1)
(644) (2)
123 (7) 11,800
---------- ------- ------- -------- ----------
$2,103,583 181,838 115,447 (105,486) 2,064,488
========== ======= ======= ======== ==========
YEAR ENDED DECEMBER 31, 1993
Exploration and production $1,691,456 148,689 49,518 (421) (1)
(32,965) (2)
97 (3)
26,003 (6) 1,783,341
Refining 243,416 19,873 56 119 (1)
(764) (2) 262,588
Marketing 43,870 7,014 4,552 20 (1)
(432) (2) 45,920
Transportation 25,148 2,698 101 433 (1)
(552) (2) 27,626
Farms, timber, and real estate 48,798 3,500 1,381 (11) (7) 50,906
Corporate and other 11,800 1,582 2,709 (151) (1)
(171) (2) 10,351
---------- ------- ------- -------- ----------
$2,064,488 183,356 58,317 (8,795) 2,180,732
========== ======= ======= ======== ==========
(1) Transfers between classifications.
(2) Amounts applicable to foreign currency translations.
(3) Depreciation applicable to used well equipment included in purchase of
producing properties.
(4) Reclassified from investments.
(5) Cancellation or reclassification of capitalized lease obligations.
(6) Effect of SFAS No. 109 on prior business combinations.
(7) Other.
15
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SCHEDULE IX - SHORT-TERM BORROWINGS
Three years ended December 31, 1993
----------------------------------------------------
(Thousands of dollars)
At end of period Outstanding during the period
------------------------ ------------------------------------
Weighted Weighted
average average
Category of aggregate interest Maximum Average interest
short-term borrowings Balance (1) rate amount amount (2) rate (2)
- - - --------------------- ----------- -------- -------- ---------- --------
Year ended December 31, 1991
Payable to banks for borrowings $ 37,680 6.2% $ 88,663 15,576 7.7%
Year ended December 31, 1992
Payable to banks for borrowings 2,795 7.2% (3) 123,886 27,418 5.7%
Year ended December 31, 1993
Payable to banks for borrowings - -% 3,104 1,355 6.2%
(1) The unused lines of credit can be withdrawn by the banks at any time.
Outstanding amounts are normally repayable within one year and bear
interest based on the banks' prime lending rates or costs of funds rates.
(2) Average interest rates and average amounts outstanding are based on daily
rates and amounts.
(3) Primarily borrowings in the U.K., with a corresponding deposit earning
interest at a rate that may be up to .5% lower.
16
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
Three years ended December 31, 1993
-------------------------------------------------------
(Thousands of dollars)
Charged to Costs and Expenses
------------------------------
Item 1993 1992 1991
---- ------- ------- -------
Maintenance and repairs $88,618 90,238 72,840
======= ====== ======
No other items required to be reported on this schedule exceeded one percent of
total revenues.
17
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 JACK W. McNUTT Date: March 29, 1994
-------------------------------------- ----------------------------------
Jack W. McNutt, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below on March 29, 1994 by the following persons on behalf of
the registrant and in the capacities indicated.
C. H. MURPHY JR. VESTER T. HUGHES JR.
--------------------------------------- ---------------------------------------
C. H. Murphy Jr., Chairman of the Board Vester T. Hughes Jr., Director
and Director
JACK W. McNUTT MICHAEL W. MURPHY
--------------------------------------- ---------------------------------------
Jack W. McNutt, President and Director Michael W. Murphy, Director
(Principal Executive Officer)
CLAIBORNE P. DEMING WILLIAM C. NOLAN JR.
--------------------------------------- ---------------------------------------
Claiborne P. Deming, Executive William C. Nolan Jr., Director
Vice President and Director
R. MADISON MURPHY CAROLINE G. THEUS
--------------------------------------- ---------------------------------------
R. Madison Murphy, Executive Vice Caroline G. Theus, Director
President and Chief Financial and
Administrative Officer and Director
(Principal Financial Officer)
B. R. R. BUTLER LORNE C. WEBSTER
--------------------------------------- ---------------------------------------
B. R. R. Butler, Director Lorne C. Webster, Director
JOHN W. DEMING RONALD W. HERMAN
--------------------------------------- ---------------------------------------
John W. Deming, Director Ronald W. Herman, Controller
(Principal Accounting Officer)
H. RODES HART
---------------------------------------
H. Rodes Hart, Director
18
EXHIBIT INDEX
Exhibit Page Number or Incorporation by
No. Reference to
- - - ------- -------------------------------
3.1 Certificate of Incorporation of Murphy Oil Corporation as of Exhibit 3.1, Page Ex. 3.1-0 of
September 25, 1986 Murphy's Annual Report on
Form 10-K for the year ended
December 31, 1991
3.2 Bylaws of Murphy Oil Corporation at February 3, 1993 Exhibit 3.3, Page 3.3-0 of
Murphy's Annual Report on
Form 10-K for the year ended
December 31, 1992
3.3 Bylaws of Murphy Oil Corporation at February 2, 1994 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 Murphy Exhibit 4.1, Page 4.1-0 of Murphy's
Oil Corporation and Harris Trust Company of New York, as Annual Report on Form 10-K for
Rights Agent the year ended December 31, 1989
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 10.3, Page 10.3-0 of
amended February 7, 1990 retroactive to February 3, 1988) Murphy's Annual Report on Form
10-K for the year ended December
31, 1989
10.3 1992 Stock Incentive Plan Exhibit 10.3, Page 10.3-0 of
Murphy's Annual Report on Form
10-K for the year ended December
31, 1992.
13 1993 Annual Report to Security Holders Ex. 13-0 - pages 4 through 62
Appendix - Narrative of Graphic and Image Material A-1
21 Subsidiaries of the Registrant Ex. 21-1
23 Independent Auditors' Consent Ex. 23-1
99.1 Undertakings Ex. 99.1-1
99.2 Form 11-K, Annual Report for the fiscal year ended To be filed as an amendment of
December 31, 1993 covering Combined Thrift Plans for this Annual Report on Form 10-K
Employees of Murphy Oil USA, Inc., and Deltic Farm & not later than 180 days after
Timber Co., Inc. December 31, 1993.
Exhibits other than those listed above have been omitted since they either are
not required or are not applicable.
19
EXHIBIT 3.3
BYLAWS
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.
Ex. 3.3-1
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 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.
Ex. 3.3-2
Section 2. Number and Term of Office. The number of directors shall be
twelve, 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 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.
Ex. 3.3-3
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.
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.
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.
Ex. 3.3-4
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, an Executive Vice President, one or more Vice
Presidents, 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 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.
Ex. 3.3-5
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. Executive Vice President. The Executive Vice President shall in
the absence or disability of the President perform the duties and exercise the
powers of such office. He shall perform such other duties and have such other
powers as the President or the board of directors may from time to time
prescribe.
Section 10. 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, and the Executive Vice 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 11. 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 12. 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 13. 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.
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.
Ex. 3.3-7
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 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.
Ex. 3.3-8
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 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.
Ex. 3.3-9
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 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.
Ex. 3.3-10
(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
MURPHY OIL CORPORATION
1993 ANNUAL REPORT TO SECURITY HOLDERS
Ex.13-0
CONTENTS
- - - ---------------------------------------------------------------
Highlights.................................. 1
Letter from Executive Management............ 2
Petroleum
Exploration and Production............... 4
Refining, Marketing, and Transportation.. 15
Farm, Timber, and Real Estate............... 21
Financial Review
Selected Financial Information........... 23
Management's Discussion and Analysis.... 24
Quarterly Information.................... 31
Report of Management........................ 32
Independent Auditors' Report................ 32
Consolidated Financial Statements........... 33
Notes to Consolidated Financial Statements.. 37
Supplemental Oil and Gas Information........ 54
Statistical Summary......................... 60
Directors................................... 63
Officers.................................... 63
Principal Subsidiaries...................... 64
Corporate Information....................... Inside back cover
BUSINESS ACTIVITIES
- - - --------------------------------------------------------------------------------
Murphy Oil Corporation is a natural resources company that operates through
wholly owned subsidiaries in the United States and internationally to conduct
the various business activities of the Murphy 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.
PETROLEUM
Exploration and Production --
During 1993 Murphy was engaged in onshore and/or offshore exploration
activities in nine countries. Crude oil and natural gas liquids are produced in
the United States, Canada, the U.K. North Sea, Gabon, and Spain. Natural gas is
produced in the United States, Canada, the U.K. North Sea, and Spain.
Refining, Marketing, and Transportation --
Murphy owns two refineries in the United States and shares ownership in a
refinery in the United Kingdom. Petroleum products are sold at wholesale and
retail in the United States, Western Europe, and Canada. Murphy also purchases,
transports, and resells crude oil in Canada.
FARM, TIMBER, AND REAL ESTATE
Murphy is engaged in farming, timber and land management, and lumber
manufacturing operations, primarily in Arkansas and North Louisiana, and in real
estate development in western Little Rock, Arkansas.
COVER
- - - --------------------------------------------------------------------------------
In January 1992, the Company sold its contract drilling business for $372
million in cash and announced a program to reinvest the proceeds of that sale in
its oil and gas business. The pictured production platform for "T" Block in the
U.K. North Sea is symbolic of the results of that program, which has added
substantial reserves to Murphy's books at a cost we believe to be attractive.
Inside Front Cover
HIGHLIGHTS
FINANCIAL
___________________________________________________________________________________
(Thousands of dollars except per share data) 1993 1992 1991
___________________________________________________________________________________
FOR THE YEAR*
Revenues....................................... $ 1,671,137 1,685,415 1,690,086
Income (loss) from continuing operations....... 86,798 62,761 (9,607)
Income (loss) before extraordinary item
and cumulative effect of changes
in accounting principles..................... 86,798 86,616 (11,157)
Net income (loss).............................. 102,136 105,565 (11,157)
Cash dividends paid............................ 55,945 53,821 47,234
Capital expenditures -- continuing operations.. 637,556 235,565 223,221
Net cash provided by continuing operations..... 362,973 284,159 213,635
Average Common shares outstanding.............. 44,856,635 44,931,208 39,457,719
___________________________________________________________________________________
AT YEAR-END
Working capital................................ $ 130,242 371,682 156,204
Total assets................................... 2,168,859 1,936,514 2,174,626
Notes payable and other long-term obligations.. 21,709 24,929 193,152
Nonrecourse debt of a subsidiary............... 87,509 -- --
Stockholders' equity........................... 1,222,350 1,200,088 1,200,819
___________________________________________________________________________________
PER SHARE OF COMMON STOCK*
Income (loss) from continuing operations....... $ 1.94 1.40 (.24)
Income (loss) before extraordinary item
and cumulative effect of changes
in accounting principles..................... 1.94 1.93 (.28)
Net income (loss).............................. 2.28 2.35 (.28)
Cash dividends paid............................ 1.25 1.20 1.20
Stockholders' equity........................... 27.28 26.76 26.71
___________________________________________________________________________________
*Includes unusual or infrequently occurring items that are detailed in
Management's Discussion and Analysis, page 24.
OPERATING
_______________________________________________________________________
1993 1992 1991
_______________________________________________________________________
Net crude oil and gas liquids produced --
barrels a day.............................. 34,311 30,820 33,495
United States............................. 13,727 13,354 13,326
International............................. 20,584 17,466 20,169
Net natural gas sold -- thousands of cubic
feet a day................................. 274,908 250,600 208,397
United States............................. 215,471 188,068 151,157
International............................. 59,437 62,532 57,240
Crude oil refined -- barrels a day.......... 137,081 131,294 127,944
United States............................. 109,090 107,049 101,975
United Kingdom............................ 27,991 24,245 25,969
Petroleum products sold -- barrels a day.... 153,595 146,042 137,506
United States............................. 120,842 114,379 104,011
Western Europe............................ 32,519 31,491 33,366
Canada.................................... 234 172 129
_______________________________________________________________________
[GRAPH: Working Capital and Long-Term Obligations at Year-End]
[GRAPH: Capital Expenditures]
[GRAPH: Market Price and Stockholders' Equity at Year-End]
1
LETTER FROM EXECUTIVE MANAGEMENT
DEAR SHAREHOLDER:
[Picture appears here]
Much of the industrialized world remained mired in recession during 1993.
Growth in Gross Domestic Product dropped to 1.1 percent in the OECD as a whole,
with Germany and Japan registering negative rates of 1.5 percent and .5 percent,
respectively. In contrast, the U.S. grew three percent for the year, bolstered
by a booming fourth quarter annualized rate of 7.5 percent. The most attractive
financing costs in two decades finally "kicked in," and inflation remained
moderate at about three percent in both the U.S. and OECD.
Predictably, world crude oil demand was weak, declining by .2 million barrels
to 66.9 million barrels a day. The strengthening U.S. economy consumed 17.2
million barrels of oil a day, up .4 percent, and 20.5 trillion cubic feet of
natural gas, up 4.8 percent. On the supply side, decline in former U.S.S.R.
production was more than offset by increased output from other producers.
A weak world economy, with reduced and oversupplied oil demand, had a
disastrous effect on prices. Average oil price for 1993 was about $2.25 a barrel
lower than in 1992, and year-end 1993 was more than $5 below the previous year-
end. In the U.S., higher total energy requirements had a positive impact on gas
markets. Domestic prices exceeded 1992 by $.35 a thousand cubic feet. Downstream
margins widened because of lower raw material cost and increased refinery
utilization of 91.5 percent in the U.S.
Low interest rates accelerated housing starts from an annual rate of 1.2
million in January to 1.6 million in December. Higher demand and restricted
cutting on federal lands propelled lumber prices to record highs by year-end.
FINANCIAL HIGHLIGHTS
Net income for 1993 was $102.1 million, $2.28 a share, compared to $105.6
million, $2.35 a share, in 1992. The overall numbers masked improved operating
results, which totaled $76.4 million, $1.71 a share, up from $54.9 million,
$1.22 a share, in 1992. Unusual items added $25.7 million to 1993 income,
largely a result of the cumulative effect of accounting changes and settlement
of income tax matters. All operating segments registered improvement over 1992.
Lower oil prices were offset by higher oil and record gas volumes, lower
exploration expenses, and improved North American gas prices. Downstream
earnings, while not robust, improved considerably from 1992. Farm, timber, and
real estate turned in record earnings on the combined strength of stumpage
prices and sawmill margins.
Net cash provided by operating activities increased $79 million to $363
million, which when supplemented by a $237 million drawdown of cash, essentially
covered capital expenditures and dividends to shareholders. Quarterly dividends
were increased 8.33 percent to 32.5 cents a share. Oil and gas property
acquisitions and attendant development costs of $342 million boosted total
capital expenditures to $638 million. At year-end, long-term debt was $109.2
million, of which $87.5 million was nonrecourse to the Company; cash and
marketable securities totaled $141.2 million.
OPERATING HIGHLIGHTS
Reserves -- On a per-equivalent-barrel basis, proved hydrocarbon reserves
increased 101.1 million barrels, or 48 percent, to 311.3 million barrels. Major
additions resulted from the acquisition of: (1) an 11.26-percent interest in
Block 16/17, "T" Block, in the U.K. North Sea, 16.5 million barrels (reflecting
only Tiffany and Toni fields); (2) a five-percent stake in the Syncrude project
in northern Alberta, 83.8 million barrels (an additional 23 million barrels will
be booked when the license is extended by seven years to 2025); and (3) the
assumption of a 6.5-percent interest in the Hibernia oil field, offshore
Newfoundland, 13.9 million barrels (approximately 19 million additional barrels
will be added at Hibernia subsequent to start-up of production based on a
consensus view of 525 million barrels of recoverable reserves).
Acquisitions -- Financial terms of the acquisitions of interests in Hibernia
and "T" Block have been reported in earlier communications. The interest in
Syncrude was purchased near year-end for $109 million. Similar to the Hibernia
transaction, this acquisition involved nonrecourse debt, with the seller
financing 60 percent of the consideration at a 6.25-percent fixed rate over five
2
years. Cost of Syncrude reserves was $1.30 a barrel. Production from Syncrude
averaged a record 183,500 barrels a day in 1993, with operating costs of $11.60
a barrel.
On a smaller scale, an additional 3.8-percent interest in the Ninian field was
acquired effective January 1, 1994 through exercise of preemption rights. At
five million barrels for $15 million, this was an unexpected bargain, a view
shared by two other Ninian partners, who acquired the balance of the available
interest.
Production -- Production in the second quarter should average in excess of
100,000 barrels of oil equivalent a day, including over 50,000 barrels of oil
and 300 million cubic feet of natural gas. This increase results from start-up
of 50 million cubic feet a day of new field developments and "first fruits" from
acquisitions. The former is a combination of three Gulf of Mexico fields --
Viosca Knoll Blocks 203-204 (67%), South Timbalier Block 86 (87%), and Viosca
Knoll Block 783, or Tahoe (30%). The latter is primarily production from "T"
Block -- Tiffany field commenced in November and Toni field in December.
Exploration -- Although several discoveries were made in the Gulf of Mexico,
onshore South Louisiana, and Canada, no major accumulations were found during
1993. Several "impact" wildcats, however, are drilling or will spud in the first
half of 1994. Mobile Block 908 No. 3 (100%) is drilling, as is Mobile Block 863
No. 3 (11.5%). Pending results of these wells, other Norphlet prospects will
likely spud in the second half of the year. The second well in Peru Block 62 was
successfully farmed out and should commence drilling at no cost to the Company
in the third quarter. A 20-percent interest is retained in the block.
Downstream -- Refinery crude throughputs increased 4.4 percent for the year to
a record 137,000 barrels a day. Environmental considerations dominate
investment decisions and operating results. Units designed to make mandated low-
sulfur diesel came on stream on time and below budget at both Meraux and
Superior. Milford Haven refinery (30%) is heavily engaged in front-end
engineering on a similar unit. An additional sulfur plant will be added at
Meraux this year, while a state-of-the-art waste-water treatment facility will
be added at Superior.
Canadian pipelines enjoyed their fourth consecutive record throughput year,
averaging 152,000 barrels a day. Milk River Pipeline (100%), one of Murphy's two
U.S.-Canada border crossings, was the big gainer.
Farm and Timber -- This segment enjoyed its best year ever. An upgrade and
expansion at the Ola sawmill came on stream just as margins improved. An
expansion at Waldo, designed to increase volume and quality of finished lumber,
is under way and will be completed at year-end. A record 147 residential lots
were sold in Chenal during 1993.
OUTLOOK
No one expects continuation of economic growth in the U.S. at the
extraordinary rate experienced in the fourth quarter. Nonetheless, recovery is
under way. As a consequence, demand for oil and natural gas will increase at a
time of shrinking oil supplies from the former U.S.S.R. and much-reduced surplus
in the North American natural gas market. This is a recipe for growth.
Your Company is superbly positioned with strategic and financial balance
provided by integrated operations and flexibility afforded by a strong financial
condition. Even under draconian commodity price and margin assumptions, we
expect cash flow from operations to carry the 1994 capital budget with only a
modest draft of working capital. Borrowing capacity is reserved for
opportunistic purchases and/or development of hydrocarbon reserves. The people
and assets are in place for a good year. On the exploration front, important
wildcats are planned, both in the U.S. and out, with renewed focus on obtaining
frontier concessions. Crude oil production increases again when Ecuador comes on
stream in the second quarter. Downstream, refineries will run heavier and higher
sulfur crudes, and we are expanding our retail network, most notably in the U.K.
Timber and real estate markets are booming, with no signs of letup.
Your Company's employees continue to merit confidence and support. They are
our finest asset and are dedicated to increasing your wealth, while preserving
the environment and maintaining safe work practices.
R. Madison Murphy
Executive Vice President
and Chief Financial and
Administrative Officer
Claiborne P. Deming
Executive Vice President
and Chief Operating Officer
Jack W. McNutt
President and
Chief Executive Officer
March 2, 1994
3
PETROLEUM
EXPLORATION AND
PRODUCTION
- - - -------------------------------------------------------------------------------
(Thousands of dollars) 1993 1992
- - - -------------------------------------------------------------------------------
Income contribution*....................... $ 36,861 35,935
United States............................ 32,701 42,182
International............................ 4,160 (6,247)
Total assets............................... 1,223,118 789,494
United States............................ 461,087 426,231
International............................ 762,031 363,263
Capital expenditures....................... 536,963 159,998
United States............................ 92,912 72,883
International............................ 444,051 87,115
- - - -------------------------------------------------------------------------------
Crude oil and liquids produced --
barrels a day............................. 34,311 30,820
United States............................ 13,727 13,354
International............................ 20,584 17,466
Natural gas sold -- MCF a day.............. 274,908 250,600
United States............................ 215,471 188,068
International............................ 59,437 62,532
* Before unusual or infrequently occurring items.
Earnings from the Company's exploration and production activities, excluding
unusual or infrequently occurring items, totaled $36.9 million in 1993 compared
to $35.9 million a year ago. The increase was due to higher crude oil
production, record natural gas production, higher average sales prices for U.S.
natural gas, and lower exploration expenses. These factors were partially offset
by lower average crude oil prices. Production of crude oil and liquids totaled
34,311 barrels a day, up 11 percent, with all of our oil-producing areas
experiencing increases. Natural gas production increased 10 percent to a record
274.9 million cubic feet a day, with the U.S. and Canada accounting for most of
the increase. Crude oil prices in the U.S. and U.K. were each down 12 percent.
Canadian light oil prices were down 10 percent, and heavy oil prices declined 11
percent. Sales prices for U.S. and Canadian natural gas were up 20 percent and
21 percent, respectively. On an energy equivalent basis, the Company's
production was up 10 percent to 80,129 barrels a day.
The exploration and production function represents the Company's best
opportunity for extraordinary growth. Murphy's exploration program includes a
balance between low-cost, low-risk wells and high-risk frontier prospects that
have potential for significant reserve additions.
Capital expenditures for exploration and production, including exploration
expenditures charged to expense, totaled $537 million in 1993 compared to $160
million in 1992. In addition to participation in 166 wells, the current year
included $259.7 million for acquisitions of proved properties. The more
significant acquisitions are reviewed in the sections that follow. All but
seven of 114 development wells were successful, and 28 of 52 exploratory wells
were successful.
As shown in the schedules on pages 55 and 56, proved reserves of crude oil and
liquids increased 106.4 million barrels, while natural gas reserves declined by
31.8 billion cubic feet. The acquisition of an 11.26-percent interest in "T"
Block in the U.K. added an initial 16.5 million barrels of oil. Additional
reserves will be added as development of this multi-field block takes place.
[GRAPH: Income Contribution -- Exploration and Production]
[GRAPH: Capital Expenditures -- Exploration and Production]
4
[MAP: Gulf of Mexico]
The five-percent interest acquired in a synthetic crude oil project in Canada
(Syncrude) added 83.8 million barrels. During the year, the Company also booked
13.9 million of the 32.6 million barrels of oil attributable to its acquisition
of a 6.5-percent interest in the Hibernia oil field, offshore Newfoundland. The
Company expects to add the remaining 18.7 million barrels subsequent to start-up
of production. The reserve amounts are based on the consensus of participants
in the project that the field contains 525 million barrels of gross recoverable
reserves. Other changes included a 2 million barrel reduction in Ecuador
because of low oil prices at year-end, a 4.1 billion cubic feet upward revision
in Spain due to well performance in the Gaviota field, and a 5.9 billion cubic
feet addition in Spain due to the decision to develop the Albatros field. On an
energy equivalent basis, Murphy's reserves totaled 311.3 million barrels at the
end of 1993 compared to 210.2 million barrels at year-end 1992.
Details concerning the Company's exploration and production activities are
presented in the sections that follow. The Company's working interest
percentage is given, 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.
UNITED STATES
Average U.S. crude oil and liquids production totaled 13,727 barrels a day in
1993, up three percent from 1992, when production from certain fields was
curtailed as a result of damage sustained from Hurricane Andrew in August.
Natural gas production reached a record 215.5 million cubic feet a day in 1993,
an increase of 15 percent when compared to 1992. The increase was due in part
to commencement of production from Viosca Knoll Blocks 203 and 204 in October,
and as with crude oil, 1992 production levels were adversely affected by
Hurricane Andrew. Two other developments -- Viosca Knoll Block 783, a deep-
water gas development project known as Tahoe, and South Timbalier Block 86, a
sour gas discovery -- will be first quarter 1994 additions to production.
Exploration activities were conducted in the Gulf of Mexico; onshore
Louisiana, Arkansas, and Texas; and offshore Alaska. In the Gulf
of Mexico, the Company participated in 23 exploratory wells; 12 of which
were successful. In addition, two deep tests of the Norphlet gas formation
commenced in the fourth quarter. The Company also participated in 10 onshore
exploratory wells; seven were successful. Offshore Alaska, we participated in
two disappointing delineation wells. A total of 16 development wells were
drilled in the U.S. during 1993; all were successful.
Gulf of Mexico -- Repair and replacement activities resulting from damages
caused by Hurricane Andrew continued during 1993. The eye of the hurricane
passed through several of the Company's major fields in the Ship Shoal, South
Pelto, and South Timbalier areas. Four major production platforms were lost,
and 55 satellite well structures were lost or severely damaged. Restoration of
pre-hurricane production levels was completed in June 1993, and replacement of
platforms and other facilities was completed by year-end. As a result of the
storm, daily oil volumes were reduced by approximately 700 barrels in 1993 and
1,400 in 1992, and daily natural gas volumes were reduced by approximately 5
million cubic feet in 1993 and 13 million in 1992. The Company is adequately
insured for costs of repair and replacement of property damaged, the effect on
recoverable reserves was minor, and there was no environmental damage.
Ongoing interpretation of 3-D seismic data acquired in prior years led to
drilling four successful wells during 1993 in the Ship Shoal Block 113 field
(50-70%), one of the Company's oldest
5
[PICTURE APPEARS HERE]
[GRAPH: Crude Oil and NGL Production]
[GRAPH: Natural Gas Sales]
[PICTURE APPEARS HERE]
properties and our primary source of oil production in the U.S. Another 3-D
location being drilled at year-end was successfully completed in early 1994.
Four of the wells were oil and one was gas. To date, 31 of the 34 wells drilled
from use of the 3-D data have been successful, and the results have more than
offset normal production declines. Drilling is expected to continue through
1994 in this important field. Additional 3-D seismic data was acquired over the
western portion of the field during the year, and early interpretation has
already resulted in several leads. Oil production averaged 4,103 barrels a day
in 1993 compared to 3,550 in 1992, and natural gas production averaged 14.5
million cubic feet a day compared to 10.6 million in 1992.
Drilling based on 3-D data in the South Pelto Block 20 field (50%), another
older property, resulted in one successful oil well and one dry hole. In
addition, two unsuccessful wells were drilled on the adjacent South Pelto Blocks
12 (85%) and 19 (50%). Oil production averaged 1,408 barrels a day in 1993
compared to 1,215 in 1992. Natural gas production averaged 7.8 million cubic
feet a day in 1993 compared to 4.7 million a year ago.
The Ship Shoal Block 113A field (100%) was again one of the Company's major
sources of natural gas production. Production associated with workover activity
during 1993 offset normal decline, resulting essentially in a constant level of
production. Although performance of this field continues to be excellent, it
has been on stream since 1982, and deliverability is being affected. Production
averaged 45.9 million cubic feet a day in 1993 compared to 39.2 million in 1992.
Oil production from the South Timbalier Block 86 field (86.9%) averaged 441
barrels a day in 1993, down from 695 in 1992. Development of a 1990 sour gas
discovery is scheduled for completion in the first quarter of 1994, with an
expected production rate of 5 million cubic feet a day.
In South Timbalier Block 63 (100%), oil production averaged 449 barrels a day
in 1993 compared to 255 in 1992. Natural gas production averaged 9.8 million
cubic feet a day compared to 5.3 million in 1992. An aggressive exploratory
program is planned for this block in 1994 following interpretation of a 3-D
seismic survey acquired during 1993.
A well in progress on Matagorda Island Block 589 (62.7%) at the end of 1992
was successfully completed and connected to facilities in Matagorda Island Block
604 (62.7%). The Block 604/589 area, another major source of gas production,
currently has 13 wells on production, and two shallow gas wells drilled in prior
years are available for hookup. Production in 1993 averaged 40.4 million cubic
feet of natural gas a day compared to 36.9 million in 1992.
The Company has an interest in four natural gas fields offshore Alabama. Two
wells in Mobile Blocks 952 and 953 (33.3%) and one in Mobile Block 955 (50%)
flow into the facilities of the four-block Mobile Block 864 unit (13.1%).
Production from these three fields commenced in March 1992 and averaged 8.7
million cubic feet a day in 1993 compared to 6.4 million in 1992. Production
from the fourth field, Viosca Knoll Blocks 203 and 204 (66.7%), commenced in
October 1993, when a gas pipeline was placed in service. The field includes
production from eight wells, including one drilled horizontally for 1,200 feet.
The horizontal completion allows the well to produce at a rate approximately
three times that of a conventional completion. Production for the year averaged
7 million cubic feet of natural gas a day, with year-end production at 33
million.
During 1993, the Company participated in the development of Viosca Knoll Block
783 (30%), a 300-billion cubic feet natural gas discovery located in 1,500 feet
of water. The first phase of development included a subsea completion of a
previously drilled well, and installation of two four-inch pipelines and a
control umbilical to connect the subsea wellhead to production facilities on a
platform 12 miles to the north in 275 feet of water. The well came on stream in
January 1994 at a rate of 10.4 million cubic feet of natural gas a day. The
second phase, which anticipates full development of the block, will
6
depend on evaluation of the reservoir and subsea production performance of the
first phase.
A well drilled during the year on Mustang Island Block 789 (40%) resulted in a
natural gas discovery. Field development will include installation of a 6.5-
mile pipeline to existing production facilities in an adjacent block. First
production is expected in the third quarter of 1994 at an estimated rate of 6.7
million cubic feet a day.
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. A well tested in 1990 confirmed a 1988 natural gas
discovery in the Norphlet formation, the source of production from several large
natural gas fields in the Mobile Bay area, about 45 miles to the west. The two
wells have proven an accumulation of natural gas 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 3-D seismic survey over the 11-
block unit has been acquired and interpreted. Other prospective Norphlet
structures have been identified on several of the blocks. The operator of the
unit continues to seek regulatory approval of a Plan of Development that
addresses operational matters and environmental concerns.
The Company also holds interests in 10 leases in federal waters south of
Mobile Bay, Alabama, the majority of which are prospective for significant
Norphlet gas reserves below 20,000 feet. Wells on two high-potential Norphlet
prospects, Mobile Blocks 908 (100%) and 863 (11.5%), were commenced in the
fourth quarter of 1993. These wells should reach total depth in the second
quarter of 1994. Interpretation of 3-D seismic data is ongoing, and wells to
evaluate other Norphlet structures are planned.
The Company participated in 12 other exploratory wells in the Gulf of Mexico
during 1993, five of which were successful. One of the successful wells
resulted in a small oil discovery in Ship Shoal Block 101 (40%), which will be
produced using facilities in an adjacent block. The remaining successful wells
were in existing gas fields and included two in South Marsh Island Block 249
(15% and 16.7%), one in High Island Block A-370 (18.8%), and one in High Island
Block A-332 (19.4%).
Murphy participated in the two 1993 federal lease sales held in the Gulf of
Mexico and acquired 25- to 100-percent interests in eight blocks.
Onshore -- U.S. onshore exploration activity was principally in South
Louisiana. Drilling activity in the East Riceville field (33.3%), located in
Vermilion Parish, Louisiana, included a well drilled as an extension to the west
of the field. The well did not encounter the sand found in the two producing
wells and was abandoned. A field wildcat well (41.6%) on a separate fault block
is planned for the second quarter of 1994. Daily production from the two
producing wells in this field, which were placed on stream during 1992, averaged
9.6 million cubic feet of natural gas and 207 barrels of oil in 1993. Production
in 1992 averaged 4.3 million cubic feet and 92 barrels of oil.
During 1993, the Company drilled the Cherry
[PICTURE APPEARS HERE]
7
[MAP; CANADA]
Ridge Land Co. No. 1 (75%), located in Cameron Parish, Louisiana. Although the
well was dry in its deep objective, it was completed as a gas/condensate well in
a shallower sand. Production commenced in late February 1994 at 2.2 million
cubic feet of natural gas a day.
Alaska -- During 1993, the Company participated in two disappointing wells in an
effort to delineate the size of the 1992 Kuvlum (3.9%) discovery in the eastern
Beaufort Sea, offshore Alaska. Current plans are to complete the processing of
700 lines of seismic data acquired over the prospect area and update our
interpretation by integrating the well data and the new seismic information.
Other activities in Alaska during 1993 included ongoing geophysical
interpretation of the Sandpiper unit (57.6%), where two wells drilled in prior
years found accumulations of hydrocarbons. We currently have interests in 47
leases offshore Alaska, mostly in the Beaufort Sea area.
Acreage Summary -- A summary of Murphy's net undeveloped acreage in the U.S. by
area at year-end 1993 and 1992 follows.
- - - -------------------------------------------------------------------------------
(Thousands of acres) 1993 1992
- - - -------------------------------------------------------------------------------
Offshore - Lower 48
Gulf of Mexico....................................... 351 344
Atlantic Coast....................................... 34 34
Offshore - Alaska
Beaufort Sea......................................... 94 105
Chukchi Sea.......................................... -- 41
Bering Sea........................................... 11 11
Onshore - Lower 48..................................... 36 55
- - - -------------------------------------------------------------------------------
526 590
===============================================================================
CANADA
Production of crude oil and liquids in Canada increased 25 percent in 1993 to
12,692 barrels a day, with light oil at 5,243 barrels a day and heavy oil at
7,449 barrels a day. Natural gas production was up 21 percent from a year ago
to 36.8 million cubic feet a day. The 1993 production volumes for both oil and
gas were at record levels.
The Company conducted an active drilling program in 1993, targeting high-
margin development projects and high-reward exploratory plays. Development of
light oil in 1993 included the drilling of eight successful horizontal wells at
Bonanza, Parkman, Elswick, and Grand Forks (12.5-33.3%). In addition, eight
successful vertical light oil development wells were drilled at Trout-Kidney and
Grand Forks (20.5-33.2%). Light oil production also increased 501 barrels a day
with the acquisition of a 32.5-percent interest in 11 Nisku oil wells in the
Swalwell area of southern Alberta. The heavy oil program included 31 successful
horizontal wells. In Saskatchewan, nine wells were drilled in Plover, Cactus
Lake, Senlac, Tangleflags, and Eyehill (33-100%). Twenty-one wells were drilled
in Alberta at South Bodo and Hayter (6.3-25%), and a 100-percent well was
drilled at Lindbergh. A program at West Provost (25%) for 20 vertical wells and
three wells at Tangleflags and Hayter (6.3-50%) completed the heavy oil
program. This program resulted in a 39-percent increase in heavy oil production
in 1993. However, because of the sharp drop in crude oil prices late in the
year, some
8
of the heavy oil production has been shut in, and development
activities for heavy oil in 1994 will depend on the level of oil prices.
Natural gas drilling activity consisted of eight successful wells in Umbach,
Three Hills Creek, and Boundary Lake South (18-50%). In the Manir field (26.2%)
in central Alberta, a conservation project to process gas that was being flared
was successfully completed in March 1993. Another gas conservation project was
initiated at Haynes to process the gas being flared from a 1992 light oil
discovery. The project will also generate fees from processing third-party oil
and gas in the area.
Murphy's exploration program in Canada during 1993 focused on high-potential
prospects for gas in northeastern British Columbia and for light oil in central
Alberta. The Company participated in 15 exploratory wells, eight of which were
successful. Two were successful natural gas discoveries at Boundary Lake (25%)
and Fort Pitt (100%). Three light oil step-out wells were completed in the
Trout area (30.9-33.3%), and three exploratory horizontal heavy oil wells were
successful in the Senlac and Cactus Lake areas (50-66.7%). In addition, a light
oil prospect started at Loon Lake (66.7%) in December resulted in a discovery in
January 1994. Further drilling is planned for 1994 to delineate the reserves.
Two separate prospects offsetting this discovery are also scheduled for testing
in 1994.
The Company continued to be selective in its land acquisition program. A
total of 38,465 net acres were acquired, with our working interest averaging 72
percent. Natural gas prospects were acquired in northeastern British Columbia,
including prospects on the high-potential Devonian Foothills trend. Light oil
acreage continued to be enhanced with further acquisitions in Pembina, Cutbank,
Haynes, Loon Lake, and Otter.
In December 1993, the Company acquired a five-percent interest in the Syncrude
project, the world's largest oil sands mining and synthetic crude oil upgrading
operation. This project is located on 96,645 acres leased from the province of
Alberta in the Athabasca oil sands area near Fort McMurray. Synthetic crude oil
is produced by a process that includes mining, extraction, and upgrading. 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 together to form synthetic crude oil. The current Syncrude license expires
in the year 2018. Application has been made to the Alberta Energy Resources
Conservation Board for an extension to 2025. Murphy's share of the reserves is
estimated at 83.8 million barrels, and our share of production will be
approximately 9,000 barrels a day of synthetic crude oil.
During 1993, the Company also acquired a 6.5-percent interest in the Hibernia
oil field in the Grand Banks area, offshore Newfoundland. This field,
discovered in 1979, is under
[MAP; HIBERNIA]
[PICTURE APPEARS HERE]
9
[PICTURE APPEARS HERE]
development, with first production projected in 1997. The peak production level
of 125,000 gross barrels of oil a day is expected to be reached in 1999. Gross
recoverable reserves are estimated to be 525 million barrels. The central
production facility for the Hibernia field is a Gravity Base Structure (GBS) --
the first GBS to be constructed to resist the impact of an iceberg. The skirting
and base slab of the GBS are completed, and work is progressing on the walls and
shafts. Construction of the main topside modules is well under way. Total pre-
production costs to be incurred by the Company, net of government grants, are
currently estimated at approximately $165 million, the majority of which will be
funded through government-guaranteed nonrecourse loans.
UNITED KINGDOM
Production from the Ninian field (10%) averaged 5,780 barrels of oil a day in
1993, virtually the same as a year ago. Deployment of a flotel alongside the
central platform, to provide accommodations for construction personnel, has
allowed workover and drilling crews to accomplish an active and successful
program to slow the rate of decline in production from this important field.
Construction continued on the central and southern platforms in preparation for
transporting third-party production from the Lyell and Strathspey fields to the
Sullom Voe terminal. Lyell production commenced in March 1993, and Strathspey
followed in December. Tariff income from third-party fields is expected to make
an increasingly significant contribution to future Ninian cash flow. In
November, an agreement was reached among the Ninian field owners to provide a
commercial framework that will allow nearby marginal fields and prospects,
containing a total of approximately 100 million barrels of oil, to use Ninian's
processing facilities at predetermined tariff rates. Some of this oil is
expected to be developed for production and transportation in 1994. A review of
operating costs completed in 1992 led to a 15-percent cost reduction in 1993,
with further reductions expected in 1994. Early in 1994, the Company exercised
preemption rights to acquire an additional 3.82-percent interest in the Ninian
field, increasing our interest to 13.82 percent.
Daily production from the Amethyst field (6.8%), which averaged 13.1 million
cubic feet of natural gas and 99 barrels of condensate, was level with 1992
production. A 3-D seismic survey was acquired over the field and surrounding
prospects during 1993, and interpretation of the data is in progress to finalize
the locations for three development wells planned in 1994. The second
redetermination of field equity interests is due to commence in March 1994.
Appraisal of the Mungo and Monan fields (12.7%) in Blocks 23/16a and 22/20
continued throughout the year, and interpretation of the 3-D seismic survey
acquired in 1992 was completed. A well in the Mungo field, which underlies both
blocks, was successfully tested at gross daily rates of 12,000 barrels of oil
and 7 million cubic feet of natural gas. Due to the results of the short-term
well test, an extended test was carried out during the summer of 1993 to
determine well productivity and assist in estimating reserves. The test was
conducted using a semi-submersible rig linked to a dynamically positioned
storage tanker. A total of 777,500 barrels of oil were produced, the sale of
which offset most of the cost of the test. The results of the test were
encouraging, and gross recoverable reserves are expected to exceed 100 million
barrels of oil equivalent. Feasibility studies for development of the two fields
have shown that it is more attractive to jointly develop several fields in the
area than pursue stand-alone development. The joint development project, known
as the Eastern Trough Area Project (ETAP), will likely include a central
processing platform for one of the larger fields, with other fields, including
Mungo and Monan, produced via satellite platforms or subsea facilities. An
engineering design agreement was signed by the ETAP participants in January
1994. Development approval is anticipated in 1995, at which time the Company
will book its share of reserves. First production is expected in late
10
[PICTURE APPEARS HERE]
11
[MAP; NORTH SEA]
1998 or early 1999.
During 1993, the Company purchased an 11.26-percent interest in Block 16/17,
also known as "T" Block. The block is located in the central North Sea
approximately 150 miles northeast of Aberdeen, Scotland, and contains four
separate oil and gas fields: Tiffany, Toni, Thelma, and Southeast Thelma. The
first phase of development involved the Tiffany and Toni fields, using a
conventional steel platform in the Tiffany field, with wells in the Toni field
being connected to the platform from two subsea manifolds. Production
commenced from Tiffany in November 1993 and from Toni in December. Peak
production from Tiffany and Toni is expected to average 10,500 barrels a day.
The 1993 average was 462 barrels a day. Initial production from Tiffany has
been from four wells drilled in prior years. Three additional production wells
and four water injection wells will be drilled from the platform in 1994 and
1995, with water injection commencing in mid-1994. The development of Toni
involved two subsea well clusters, one for production and one for water
injection. Four production wells and two injection wells have been drilled, and
a third injection well will be drilled in 1994, if required. Control and
monitoring of the subsea facilities is conducted from the Tiffany platform. Oil
production from Tiffany and Toni flows to the Brae/Forties pipeline system;
associated gas is transported to the Brae system for reinjection.
The Thelma and Southeast Thelma fields lie approximately five miles south of
the Tiffany field, and development studies are under way, with first production
from a subsea system anticipated in 1996. Development plans will be submitted to
the U.K. government in 1994 for approval.
The Company has added 16.5 million barrels of oil to its proved reserves for
the Tiffany and Toni fields. The associated gas has not been recognized in
reserves because it is being sold at a price significantly lower than market to
facilitate field development.
Exploration activity in the U.K. declined in 1993 from levels in recent years,
partly as a result of tax changes announced in March by the U.K. government. At
year-end, the Company was participating in two exploratory wells. One was
designed to test a structure adjacent to a natural gas discovery on Block 43/22
(28%), which tested in 1992 at a gross daily rate of 12.5 million cubic feet,
and the other was in Block 3/3 (19.4%) on the northeast flank of the Ninian
field. Success at Block 43/22 may lead to commercial development. Success at
Block 3/3 would lead to processing through the Ninian northern platform.
Additional exploratory wells may be drilled to identify analogous structures on
the east flank of the Ninian field. A 3-D seismic survey over Block 204/25a
(17.7%) is planned for 1994. Evaluation of this block, located west of the
Shetland Islands, will be of particular interest since a recent well drilled by
others on Block 204/20 reportedly resulted in a significant oil discovery. The
discovery is located approximately one mile north of our block. In the 14th
Licensing Round, the Company was awarded Block 29/20b (30%), where an
exploratory well is planned in 1994.
SPAIN
Production from the Gaviota field (18%) in the Bay of Biscay off the northern
coast of Spain, averaged 9.6 million cubic feet of natural gas and 103 barrels
of condensate a day in 1993. In 1992, daily production averaged 19.4 million
cubic feet of gas and 239 barrels of condensate. Although gas and condensate
rates were down substantially from
12
[MAP; ECUADOR]
1992 levels, well performance following the water breakthrough experienced last
year has been better than predicted, and the original forecast for gas
production in 1993 was exceeded by 36 percent. Cost-cutting initiatives led to a
30-percent reduction in operating costs, and modest reductions are expected in
1994. Evaluation of reservoir performance has led to an eight-percent increase
in gross recoverable natural gas reserves, from 268 to 290 billion cubic feet,
resulting in an addition to the Company's reserves in 1993 of 4.1 billion cubic
feet.
Based on remaining reserves and current production rates, abandonment of the
Gaviota field would likely occur in 1995 or 1996. However, plans have been
formulated by the operator of the field to use the reservoir for strategic gas
storage, and natural gas owned by third parties will be injected into the
reservoir during the summer months and extracted for distribution during the
winter months. The current production facilities will require modifications, and
three gas-injection wells will be drilled. Capital expenditures, operating
costs, and a profit element will be recovered by means of tariffs. The operator
has agreed on the project terms with ENAGAS, the Spanish gas distribution
company, and as a co-owner of the Gaviota field, the Company is negotiating
final commercial details for participation in the project. Under the agreement,
production from the Gaviota field will cease at the end of March 1994, and
ENAGAS will purchase all remaining reserves. The target date for first gas
injection is August 1994.
Conversion of the Gaviota field to long-term use as a gas storage facility now
permits development of the Albatros field (18%), located 11 miles west of
Gaviota. This field, discovered several years ago, contains gross recoverable
reserves of up to 50 billion cubic feet of natural gas and will be developed in
1994 using a single subsea well connected to the Gaviota platform. First gas
production is expected in mid-1995. Plans for 1994 also include a step-out well
to the west of the discovery well.
GABON
Virtually all of the production in Gabon is from the Breme field (45%).
Production quantities reported under Production Sharing Contracts include
entitlements for cost recovery and a share of the profit oil after cost
recovery. Entitlements for 1993 averaged 1,447 barrels of oil a day compared to
1,111 in 1992.
ECUADOR
The Company has a 20-percent interest in risk-service contracts (similar to
production-sharing contracts) covering Block 16 and the Tivacuno field, an oil
discovery north of Block 16. Block 16 is a 494,000-acre license located east of
the Andes mountains in the Oriente Basin. This block is adjacent to and on
trend with major producing fields to the west and north and has multiple
structures similar to those producing in the area. In addition, the Capiron
field, also located to the north, has been unitized as part of Block 16. The
development plan, which is based on gross reserves in excess of 200 million
barrels of crude oil, provides for construction of two central production
facilities, an extensive drilling program, and construction of a pipeline to
connect with the existing pipeline infrastructure. In 1993, development
activity involving the northern fields -- Capiron, Tivacuno, and the Bogi field
on Block 16 -- included drilling and/or completion of six wells, with two wells
in progress at year-end. In addition, 147 miles of pipeline were installed, and
47 miles of road were constructed. Completion of pipelines, roads, and the
northern production facility is anticipated late in the first quarter of 1994,
allowing for first production from the Capiron, Tivacuno, and Bogi fields.
During 1994, road and pipeline construction will continue to the Amo field in
the southern part of Block 16, and development drilling will be concentrated at
Capiron and Amo. As a result of the fall in oil prices, construction of the
southern
13
[PICTURE APPEARS HERE]
production facility has been deferred until 1995-96. Prior to completion of the
southern facility, the Amo field will be produced through the northern facility
and is expected to be on stream in the fourth quarter of 1994.
The Block 16 owners submitted the sole bid in 1990 for a license to Block 22,
directly east of Block 16; however, an exploratory work program remains to be
negotiated.
OTHER
During 1993, Murphy entered into a farmin agreement covering an onshore block
in the Maranon Basin of Peru, under which the Company earned a 40-percent
interest in a production-sharing contract covering 2.4 million acres. A well
drilled during the year on the Pucacuro prospect was dry. A second well is
planned in mid-1994 on a closure known as the Arabella prospect. Subsequent to
year-end, the Company farmed out half of its interest in this block. Technical
evaluations of the other areas in Peru are ongoing.
A study group was formed with two other companies to evaluate acreage
available in the Irish Frontier Licensing Round. As a result, in December 1993
the group applied for a large area west of Ireland. In China, preparations are
under way to participate in the second onshore bid round scheduled for the
second quarter of 1994.
In Somalia, Murphy has a 10-percent interest in four million acres
encompassing onshore Block 35 and offshore Block M10A. The Company also has a
100-percent interest in the 6.7-million acre Kharan concession in Pakistan.
Both of these concessions remained in a force majeure status during 1993;
however, discussions were held with the Pakistani government during the year on
lifting the force majeure in order to commence exploration activity.
14
REFINING, MARKETING, AND TRANSPORTATION
- - - -----------------------------------------------------------
(Thousands of dollars) 1993 1992
- - - -----------------------------------------------------------
Income contribution*........... $ 31,541 8,005
United States................ 11,188 (6,011)
International................ 20,353 14,016
Total assets.................... 589,202 575,061
United States................. 378,405 346,151
International................. 210,797 228,910
Capital expenditures............ 86,885 68,073
United States................. 71,363 44,198
International................. 15,522 23,875
- - - -----------------------------------------------------------
Crude oil processed--barrels
a day......................... 137,081 131,294
United States................. 109,090 107,049
International................. 27,991 24,245
Products sold--barrels a day.... 153,595 146,042
United States................. 120,842 114,379
International................. 32,753 31,663
Average gross margin on products
sold--dollars a barrel
United States................. $ .82 .48
Western Europe................ 3.08 2.67
*Before unusual or infrequently occurring items.
Earnings from the Company's refining, marketing, and transportation
operations, excluding unusual or infrequently occurring items, totaled $31.5
million in 1993 compared to $8 million in 1992. Our U.S. operations earned
$11.2 million compared to a loss of $6 million a year ago. Earnings from
operations in Western Europe totaled $11.7 million, up from $4.6 million in
1992. The earnings contribution from purchasing, transporting, and reselling
crude oil in Canada totaled $8.6 million in 1993 compared to $9.4 million a year
ago. The Company's composite average gross margin on product sales in the U.S.
was up 71 percent. Regionally, margins in the Southeast continued to be under
pressure, while in the upper-Midwest, margins increased due primarily to an
improved asphalt season. Margins in Western Europe were up 15 percent from the
depressed levels of 1992. Sales volumes increased six percent in the U.S. to
120,842 barrels a day and three percent in Western Europe to 32,519 barrels. The
decline in Canadian earnings was due primarily to lower crude oil trading
volumes.
Maintaining modern, efficient, and competitive refining and distribution
systems is a key element of Murphy's strategy for its downstream business. This
strategy has required investment of substantial sums in recent years, and
additional projects are under way or planned. Capital expenditures for 1993
totaled $86.9 million compared to $68.1 million in 1992. The 1993 expenditures
included nearly $38 million for distillate desulfurization projects. A
significant portion of capital expenditures in our downstream operations relates
to the responsibility to operate in an environmentally safe manner. Capital
expenditures addressing environmental concerns, including the distillate
desulfurization expenditures, were $54 million in 1993.
[GRAPH: Income Contribution--Refining, Marketing, and Transportation]
[GRAPH: Capital Expenditures--Refining, Marketing, and Transportation]
[GRAPH: Refined Products Sold]
15
UNITED STATES
The Company is engaged in downstream activities in two separate regions of the
U.S. A 100,000-barrel-a-day refinery in Meraux, Louisiana, produces refined
petroleum products for distribution over an eleven-state area in the
southeastern part of the U.S. that is generally referred to as the Gulf Coast
market. A five-state area in the upper-Midwest is served by a 35,000-barrel-a-
day refinery in Superior, Wisconsin.
The Gulf Coast market is highly competitive, and margins in the area have been
depressed in recent years by excess refinery capacity and a weak U.S. economy.
A successful refiner in this market must seek advantage through operating
efficiencies and a continuing effort to reduce costs. To achieve those goals,
the Company has under way a capital investment program that commenced with
expansion of crude oil processing capacity to the current 100,000-barrel-a-day
level in 1991. During 1993, construction of a distillate desulfurizer was
completed. This important project, finished ahead of schedule and below budget,
enables the refinery to produce low-sulfur diesel fuel as mandated by the 1990
Clean Air Act. Low-sulfur diesel accounted for 79 percent of the refinery's
diesel production for the final four months of 1993, allowing the Company to
capitalize on the initial high spreads between low-sulfur and conventional
diesel fuel. In addition to producing a new value-added product, the distillate
desulfurizer has also allowed us to include additional quantities of less
expensive, heavier crudes in the array of crudes we can process. The unit also
served as the foundation to further reduce crude costs by increasing
[MAP: United States]
[GRAPH: Meraux Refinery Crude Charge]
[GRAPH: Meraux Refinery Yields]
16
sour crude processing capacity, and a project is scheduled for completion in
1994 that will move the Meraux refinery to the next level by permitting a 50-
percent light sour crude slate. Completion of the sour crude project will finish
the capital investment program designed to improve the competitiveness of the
Meraux refinery. Additional capital investments planned at Meraux include a low-
cost project to produce reformulated gasoline by January 1995.
Crude oil processed at the Meraux refinery during 1993 averaged 78,732 barrels
a day, down from 80,842 in 1992. Inputs of other feedstocks averaged 6,398
barrels a day compared to 5,477 a year ago. Market-driven curtailments and
downtime on the No. 2 cat cracker combined to reduce inputs in the current year.
Crude oil requirements at Meraux are met through a combination of foreign-source
crudes, our own production of U.S. crudes, and third-party purchases at posted
prices. The flexibility provided by this mix, along with the ongoing capital
investment program, are providing opportunities to minimize overall crude costs.
This combination has resulted in reducing the light sweet crude component of our
crude runs during the past two years from 69 percent in 1991 to 45 percent in
1993. The light sweet crude has been replaced with less expensive heavy and sour
crudes. Average crude gravity declined from 34.2 degrees in 1991 to 32.8 degrees
in 1993, and despite the reduction in crude quality, residual yields declined
from 12.8 percent to 11.7 percent during the two-year period. Light sour crude
runs have increased from two percent in 1991 to 26 percent in 1993.
Crude runs at the Company's Superior refinery were 30,358 barrels a day, an
increase of 16 percent over 1992. Asphalt sales were up 25 percent over 1992.
A key component of the increase in asphalt sales was the successful operation of
the Company's new Crookston, Minnesota, asphalt terminal. New markets reached
by this terminal were major contributors to the successful year. The blend of
crude oil processed at the refinery continued to complement Murphy's Canadian
production of heavy oil. The volume of heavy asphaltic crude processed in 1993
increased by 27 percent over 1992 runs. Additional synergies will be achieved
in 1994 by processing the Company's share of production from the Canadian
synthetic crude oil project.
A revamp of an existing hydrotreater was completed at Superior in August 1993,
enabling low-sulfur diesel to be introduced ahead of schedule and allowing the
refinery to capitalize on initial demand and attendant high margins during the
third quarter.
The Company's distribution system in the Southeast consists of 29 terminals,
21 of which are either wholly or jointly owned, that are supplied from the
Meraux refinery by barge or pipeline. The refinery's strategic location on the
Mississippi River provides flexibility to maximize margins through product
trading and by shifting between terminal and cargo sales as market conditions
dictate. Total product sales in the Southeast totaled 91,618 barrels a day, an
increase of two percent. In the upper-Midwest, 10 terminals serving markets in
North Dakota, Minnesota, and western Wisconsin are supplied from the Superior
refinery by pipeline. Markets in southeastern Wisconsin and western Michigan
are served from five terminals supplied by pipeline from Chicago, where products
are received from others in exchange for deliveries at Superior. Asphalt
terminals in Crookston and Rhinelander, Wisconsin, are supplied by truck. Total
product sales in the upper-Midwest increased by 18 percent to 29,224 barrels a
day.
Sixty-nine percent of Murphy's U.S. gasoline sales were at terminals in 1993,
39 percent of which were sales to SPUR branded outlets. The remaining 31
percent of gasoline sales were in the bulk cargo market. Seventy percent of
diesel and home heating oil sales were at terminals, with the balance going to
the cargo market. Twenty-three percent of the terminal sales were to SPUR
outlets. We sold 14 percent of our kerosine at terminals, and the remaining 86
percent
[PICTURE APPEARS HERE]
17
was sold in the bulk cargo market.
During 1993, the Company's U.S. marketing efforts included a program of
consolidation that emphasized retaining quality stations in our primary market
areas. Emphasis is being placed on providing attractive outlets for our
products, with particular attention directed to expansion of convenience stores.
At December 31, 1993, there were 606 SPUR branded stations in 14 states.
UNITED KINGDOM
During 1993, Murphy processed an average of 27,991 barrels of crude oil a day
at our jointly owned refinery in Milford Haven, Wales, compared with 24,245 in
1992. As a result of higher crude runs in 1993, processing of intermediate
feedstocks was reduced from 7,102 barrels a day in 1992 to 3,638 barrels in the
current year. The triennial maintenance turnaround occurred in the second
quarter, at which time modifications were made to further increase the capacity
of the alkylation unit. Turnaround work on the crude unit allowed an increase in
crude runs. Modifications were also undertaken to improve the quality of
feedstocks to the naphtha isomerization unit. This unit, commissioned in late
1992, has increased the ability of the refinery to produce higher octane
unleaded gasolines. To further accommodate the increasing demand for unleaded
gasolines, along with reducing volatility and benzene levels, facilities to
handle methyl tertiary butyl ether are under construction and should be
available for use early in the second quarter of 1994.
Concerns over environmental emissions within the European Union continue to
influence investment decisions. Regulations to impose further reductions in the
sulfur content of both diesel oil and gasoline are scheduled to take effect over
the next few years. An engineering design study has been completed for
construction of a high-pressure distillate
[MAP: United Kingdom]
[PICTURE APPEARS HERE]
18
[PICTURE APPEARS HERE]
hydrotreater to start operating in 1996. A project is also under review to
modify the cat cracker to meet lower sulfur limits in gasoline while maintaining
the capability to process medium-sulfur crudes. Other projects under review
include an on-line gasoline blending system that would provide more consistent
product quality and improve production flexibility. Detailed planning for a
butane isomerization unit has also commenced. This unit will enable the refinery
to produce higher-value feedstock for the alkylation unit from lower-value
butane, which will no longer be blended into gasoline due to restrictions on
vapor emissions.
Milford Haven is supplied by North Sea crude oil purchased in the spot market
or, alternatively, with proprietary Brent or Forties Blend. Exposure to price
volatility is reduced to the extent possible by pricing each spot purchase over
the same period of time that crude is processed and products are sold.
Additional feedstocks for the cat cracker and alkylation units are purchased in
the spot market when required. Transportation to the refinery is provided by
tankers chartered at spot rates.
Demand for road fuels in the U.K. remained weak in 1993 -- diesel sales showed
a modest increase, but gasoline sales were down for the second consecutive year.
However, retail sales through the Company's branded outlets increased by five
percent, from 7,717 barrels a day in 1992 to 8,119 in 1993, despite increased
competition from supermarket operators. Gross margin from branded retail sales
was up 8.6 percent. The Company opened a new marketing area in southwest Wales
during 1993, and 12 stations were in operation at year-end. Company-owned
stations totaled 134 at the end of 1993, an increase of nine; dealer stations
were up 28 to 294. Wholesale product sales in the U.K. were down from 1,135
barrels a day in 1992 to 520 in 1993.
The remainder of the Company's Milford Haven production is sold into the bulk
cargo markets; these sales totaled 23,880 barrels a day in 1993, up five percent
over 1992. Demand for kerosine and diesel increased over 1992, but gasoline
sales were down, accounting for 25 percent of bulk sales in 1993 compared to 28
percent a year ago.
19
CANADA
Murphy conducts an active crude oil trading operation in Canada and has
interests in four crude oil pipeline systems, including two of the six systems
that cross the border from Canada into the U.S. Anciliary activities include
crude oil and LPG trucking operations and sale of refined products in Thunder
Bay, Ontario. Margins on sales of purchased crude were essentially unchanged
from a year ago, but sharply lower crude oil prices adversely affected trading
volumes. While pipeline throughputs increased 29 percent in 1993 to 151,722
barrels a day, operating costs also increased and partially offset the
volumetric gains.
The Manito pipeline system (52.5%) transported 44,844 barrels a day of heavy
oil blend in 1993, basically unchanged from a year ago. Throughput volumes on
the Bodo/Cactus Lake system (26.3%/13.1%) increased 48 percent to 31,195 barrels
a day on increased crude production in areas supplying the system. Throughput
volume in the Milk River system (100%), one of the systems crossing the U.S.
border, was up 53 percent to 47,152 barrels a day, partially due to a new light
oil stream. The other cross-border pipeline is the Wascana system (100%), which
had a throughput of 28,531 barrels a day, an improvement of 43 percent. The
increase was partially due to a higher level of demand for medium-sour crude in
the Rocky Mountain area of the U.S. (PADD IV) that is expected to continue in
1994. Crude oil hauled by our trucking operations was down in 1993, but sales of
refined products at Thunder Bay increased 36 percent. Thunder Bay is supplied
from our Superior refinery, and the Company operates seven branded retail
outlets and one branded wholesale outlet in the area.
[MAP: Canada--Pipelines]
[GRAPH: Canadian Pipeline Throughputs]
20
FARM, TIMBER, AND REAL ESTATE
- - - ------------------------------------------------------------
(Thousands of dollars) 1993 1992
- - - ------------------------------------------------------------
Income contribution............. $ 13,154 8,362
Total assets.................... 150,261 141,784
Capital expenditures............ 9,674 6,017
- - - ------------------------------------------------------------
Lumber sales--thousand board feet 115,136 105,619
Residential lots sold........... 147 120
Land owned--acres
Farm.......................... 36,000 36,000
Timber........................ 341,000 342,000
Real Estate................... 10,000 10,000
The Company's farm, timber, and real estate operations are conducted through
its wholly owned subsidiary, Deltic Farm & Timber Co., Inc. Deltic reported
record earnings in 1993 of $13.1 million, up 56 percent from the $8.4 million
earned in 1992. Substantial improvements were recorded by timber and real
estate operations, while operating results on the farms were off sharply
compared to 1992.
Farming operations reported a loss of $.1 million in 1993 compared to earnings
of $1.2 million a year ago. Cold, wet, springtime conditions were followed by
heavy rainfall during early summer and prolonged drought during late summer.
These weather patterns reduced yields on all crops. Corn yields of 70 bushels
per acre in 1993 were 48 bushels per acre lower than in 1992, a decrease of 41
percent. Soybean yields declined 38 percent to 24 bushels per acre in 1993
compared to 39 bushels per acre in 1992. Cotton yields of 661 pounds per acre
in 1993 represented a 170-pound per acre reduction from 1992, down 20 percent.
Although adverse weather conditions resulted in disappointing yields during
1993, Deltic is confident that no-till and minimum-till cultivation practices
will enhance the profitability of the farms and prove to be ecologically
beneficial. Future efforts will continue to emphasize improved cultivation
methods, more effective cost-control practices, and research for heavy-soil crop
alternatives.
The interest-rate-induced pickup in U.S. housing starts and the associated
effect on lumber demand pushed Deltic's earnings from timber operations to an
all-time high of $11.3 million, up 95 percent compared to 1992 earnings of $5.8
million. Finished lumber production from Deltic's two sawmills reached record
levels and totaled 112.4 million board feet, an increase of 11 percent from the
101.2 million produced in 1992. The average sales price for finished lumber
also set a record, rising to $335 per thousand board feet in 1993 compared to
$259 in 1992, an increase of 29 percent. Average pretax mill margins were $82
per thousand board feet compared to $34 a year ago. The Ola, Arkansas, mill
upgrade was completed, and production using the new equipment started in April
1993. The upgrade allowed the Ola mill to produce a more valuable mix of
finished lumber and increases the yield per log by over 20 percent. The Waldo,
Arkansas, mill increased production of finished lumber by 5.8 million board feet
in 1993 to 71.1 million, due in part to the new trimmer-optimizer installed in
1992. An additional $8.3-million expansion planned for the Waldo mill in 1994,
will provide the product flexibility needed to further maximize the value from
each log processed.
[GRAPH: Income Contribution -- Farm, Timber, and Real Estate]
[GRAPH: Capital Expenditures -- Farm, Timber, and Real Estate]
[GRAPH: Sales of Finished Lumber]
21
[PICTURE APPEARS HERE]
Rising lumber prices and harvest curtailments on federal lands continue to
enhance the value of Deltic's timber. Sales of pine sawtimber increased to 37.6
million board feet in 1993 compared to 30.2 million in 1992. Average sales
prices increased 13 percent to $310 per thousand board feet. Hardwood sawtimber
sales were 2.8 million board feet in 1993, unchanged from a year ago. Pine
pulpwood sales totaled 12,536 cords in 1993 compared to 8,767 in 1992.
Real estate operations contributed $2.4 million to earnings in 1993 compared
to $1.8 million in 1992, an increase of 33 percent. Lower long-term mortgage
rates sparked an increase in residential lot sales at Chenal Valley, Deltic's
4,300-acre planned community in Little Rock, Arkansas. This development is
firmly established as the location of preference in the Little Rock area and
continued to increase its residential market share with a total of 147 lot sales
in 1993 compared to 120 in 1992. Chenal's newest residential areas -- Avignon
Court, Aberdeen Court, Bayonne Place, and LaMarche Place -- accounted for sales
of 126 lots in 1993. Aberdeen Court and Bayonne Place were the first two areas
to be opened on the north slope of Chenal Valley. Plans are under way to
continue development in this area in 1994. Construction of the first model home
in The Oaks will commence in early 1994 as part of Deltic's plans to capture a
greater portion of the residential real estate dollar. Lot buyers will be able
to select from a set of eight floor plans under a turnkey arrangement that will
provide a finished home. Deltic also believes that the number of homes in
Chenal has now reached a level that will support commercial development, and
plans are under way to enter that market in 1994.
[PICTURE APPEARS HERE]
[PICTURE APPEARS HERE]
22
FINANCIAL REVIEW
SELECTED FINANCIAL INFORMATION
- - - -------------------------------------------------------------------------------------------------------
(Thousands of dollars except per share data) 1993 1992 1991 1990 1989
- - - -------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS FOR THE YEAR(1)
Sales and other operating revenues............ $1,636,668 1,631,441 1,600,935 1,867,381 1,551,557
Net cash provided by continuing operations.... 362,973 284,159 213,635 284,431 303,673
Income (loss) from continuing operations...... 86,798 62,761 (9,607) 113,524 78,783
Income (loss) before extraordinary item
and cumulative effect of changes in
accounting principles....................... 86,798 86,616 (11,157) 98,746 46,551
Net income (loss)............................. 102,136 105,565 (11,157) 114,009 46,551
Per Common share
Income (loss) from continuing operations... 1.94 1.40 (.24) 3.34 2.32
Income (loss) before extraordinary item
and cumulative effect of changes in
accounting principles.................... 1.94 1.93 (.28) 2.91 1.37
Net income (loss).......................... 2.28 2.35 (.28) 3.36 1.37
Dividends.................................. 1.25 1.20 1.20 1.00 1.00
Percentage return on
Average stockholders' equity............... 8.4 8.8 (1.1) 13.8 6.2
Average borrowed and invested capital...... 8.4 9.7 1.5 13.2 6.8
Average total assets....................... 5.0 5.3 (.6) 6.5 2.2
- - - -------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES FOR THE YEAR
Exploration and production(2)................. $ 536,963 159,998 155,017 146,679 135,366
Refining, marketing, and transportation....... 86,885 68,073 63,143 59,056 28,205
Farm, timber, and real estate................. 9,674 6,017 2,858 10,375 11,201
Corporate and other........................... 4,034 1,477 2,203 4,039 4,886
- - - -------------------------------------------------------------------------------------------------------
$ 637,556 235,565 223,221 220,149 179,658
=======================================================================================================
FINANCIAL CONDITION AT YEAR-END
Current ratio......................... 1.32 1.87 1.30 1.17 1.30
Working capital....................... $ 130,242 371,682 156,204 106,518 144,846
Net property.......................... 1,549,250 1,073,179 1,128,641 1,040,825 1,075,585
Total assets.......................... 2,168,859 1,936,514 2,174,626 2,126,719 2,064,042
Long-term obligations(3).............. 109,218 24,929 193,152 207,867 330,339
Minority interest..................... -- -- -- 180,516 158,803
Stockholders' equity.................. 1,222,350 1,200,088 1,200,819 873,163 769,578
Per share.......................... 27.28 26.76 26.71 25.76 22.71
Long-term obligations(3) -- percent of
capital employed.................... 8.2 2.0 13.9 16.5 26.2
- - - -------------------------------------------------------------------------------------------------------
(1) Includes effects on income of unusual or infrequently occurring items in
1993, 1992, and 1991 that are detailed in Management's Discussion and
Analysis, page 24. Also, unusual or infrequently occurring items in 1990 and
1989 resulted in an increase (decrease) to net income of $17,923 and
$(32,232), $.53 a share and $(.95) a share, respectively.
(2) Includes amounts expensed and cost of assets acquired by assuming directly
related liabilities.
(3) Includes nonrecourse debt in 1993 of $87,509, which is 6.6 percent of
capital employed.
[GRAPH: Income Excluding Unusual Items]
[GRAPH: Cash Provided by Continuing Operations]
[GRAPH: Stockholders' Equity at Year-End]
23
MANAGEMENT'S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Consolidated net income for 1993 was $102.1 million, $2.28 a share, compared
to $105.6 million, $2.35 a share, in 1992. In 1991, the Company reported a loss
of $11.2 million, $.28 a share, on fewer average Common shares outstanding. As
reviewed in Note D to the consolidated financial statements, the Company sold
its contract drilling business effective January 1, 1992. This activity has been
accounted for as discontinued operations, and net income for 1992 included a
gain of $23.9 million, $.53 a share, from disposal of the contract drilling
business. Consolidated results of operations in 1991 included a loss from
discontinued contract drilling operations of $1.6 million, $.04 a share. Results
of operations for the three years ended December 31, 1993 also included other
unusual or infrequently occurring items that resulted in a net gain of $25.7
million, $.57 a share, in 1993; a net gain of $26.8 million, $.60 a share, in
1992; and a net charge of $67.3 million, $1.71 a share, in 1991. The 1993 net
gain included $15.3 million, $.34 a share, from adoption of new accounting
standards.
Income from continuing operations before unusual or infrequently occurring
items totaled $76.4 million in 1993, an increase of $21.5 million, or 39
percent, over 1992. Earnings from the Company's exploration and production
operations increased $1 million, and income from the refining, marketing, and
transportation function improved $23.5 million. Income from farm, timber, and
real estate operations increased $4.7 million, and the contribution from
corporate activities declined $7.7 million.
In 1992, earnings from continuing operations before unusual or infrequently
occurring items were $54.9 million, a decrease of $2.8 million from 1991. Income
from exploration and production operations improved $12.5 million. Refining,
marketing, and transportation profits declined $35.3 million from 1991, while
earnings from farm, timber, and real estate operations increased $3.6 million.
Corporate functions were profitable in 1992, a $16.4 million improvement
compared to 1991.
In the following table, the Company's results of operations for the three
years ended December 31, 1993 are presented by function, and unusual or
infrequently occurring items are detailed. A review of the information presented
follows the table.
- - - -------------------------------------------------------------------------------
(Millions of dollars) 1993 1992* 1991
- - - -------------------------------------------------------------------------------
Exploration and production
United States........................................ $ 32.7 42.2 27.1
Canada............................................... 6.3 1.2 (3.4)
United Kingdom....................................... 3.5 (1.6) 1.8
Spain................................................ 1.4 6.3 2.0
Other international.................................. (7.0) (12.2) (4.1)
- - - -------------------------------------------------------------------------------
36.9 35.9 23.4
- - - -------------------------------------------------------------------------------
Refining, marketing, and transportation
United States........................................ 11.2 (6.0) 20.9
Western Europe....................................... 11.7 4.6 15.6
Canada............................................... 8.6 9.4 6.8
- - - -------------------------------------------------------------------------------
31.5 8.0 43.3
- - - -------------------------------------------------------------------------------
Farm, timber, and real estate.......................... 13.1 8.4 4.8
Corporate and other.................................... (5.1) 2.6 (13.8)
- - - -------------------------------------------------------------------------------
Income from continuing operations before unusual
or infrequently occurring items...................... 76.4 54.9 57.7
Refund and settlement of income tax matters............ 14.4 33.7 34.5
Provision for environmental remediation matters........ (4.0) (6.9) --
Write-off of costs to acquire minority interest
in a subsidiary not attributable to specific assets.. -- -- (83.9)
Write-down of oil and gas properties................... -- -- (33.3)
Settlement of insurance subsidiary litigation.......... -- -- 10.6
Settlement of windfall profit tax dispute.............. -- -- 4.8
- - - -------------------------------------------------------------------------------
Income (loss) from continuing operations............... 86.8 81.7 (9.6)
Cumulative effect of changes in accounting principles
for
Income taxes......................................... 31.8 -- --
Postretirement benefits other than pensions, net..... (16.5) -- --
Loss from discontinued contract drilling operations.... -- -- (1.6)
Gain on disposal of contract drilling.................. -- 23.9 --
- - - -------------------------------------------------------------------------------
Net income (loss)...................................... $102.1 105.6 (11.2)
===============================================================================
*The tax benefit of utilizing a financial net operating loss carryforward of
$18.9, reported in the 1992 Consolidated Statement of Income as an
extraordinary item, is allocated in this summary.
[GRAPH: Income Contribution by Operating Function]
24
EXPLORATION AND PRODUCTION--Earnings from exploration and production
operations before unusual or infrequently occurring items were $36.9 million in
1993, $35.9 million in 1992, and $23.4 million in 1991. While the net increase
in earnings in 1993 was modest, crude oil and liquids production was up 11
percent, natural gas production increased 10 percent to a record level of 274.9
million cubic feet a day, the average sales price for U.S. natural gas was up 20
percent, and exploration expenses declined 26 percent. These improvements were
essentially offset by lower average crude oil sales prices throughout most of
the year, exacerbated by a near-collapse at the end of 1993. The increase in
1992 was due primarily to a 20-percent increase in natural gas production and an
eight-percent increase in the average sales price for U.S. natural gas. As
partial offsets, crude oil and liquids production was down eight percent,
average crude oil sales prices were generally lower, and exploration expenses
were higher.
Oil and gas revenues for each of the last three years are shown by major
operating area on page 59. A summary is presented in the following
table.
- - - ----------------------------------------------
(Millions of dollars) 1993 1992 1991
- - - ----------------------------------------------
United States
Crude oil............. $ 81.7 90.9 94.7
Natural gas........... 165.8 122.0 89.8
Canada
Crude oil............. 54.1 48.8 44.9
Natural gas........... 16.4 11.2 10.6
United Kingdom
Crude oil............. 38.4 41.0 56.6
Natural gas........... 11.0 13.4 10.2
Spain -- natural gas... 9.2 18.3 23.2
Other -- crude oil..... 8.0 10.0 17.0
- - - ----------------------------------------------
Total................ $384.6 355.6 347.0
==============================================
Daily production rates and weighted average sales prices are shown in the
statistical summary on page 60. As subsequently reviewed, the Company made
several acquisitions in 1993 that will result in substantial contributions to
production levels in future years. Expected initial contributions of the
significant acquisitions are indicated in the following paragraphs. These
contributions may be partially offset by normal production declines from other
producing properties.
Crude oil and liquids production in the U.S. was essentially unchanged during
the two years ended December 31, 1993. In 1993, normal production declines
nearly offset the restoration of production from certain fields damaged by
Hurricane Andrew in August 1992. In 1992, a generally higher level of production
during the first eight months of the year was offset by the temporary loss of
production from fields damaged by the hurricane. Canadian production increased
25 percent in the current year following an eight-percent increase in 1992. The
improvements include increases in heavy oil of 39 percent in 1993 and 13 percent
in 1992, both resulting from an accelerated program to develop the Company's
heavy oil reserves. This program may be adversely affected if the low level of
crude oil prices at the end of 1993 continues. The Company's acquisition of a
five-percent interest in a synthetic crude oil project (Syncrude), reviewed in
subsequent sections, is expected to contribute approximately 9,000 barrels a day
commencing January 1, 1994. Murphy's average production from the U.K. increased
seven percent in 1993 and included 462 barrels a day as a result of the
acquisition of an 11.26-percent interest in Block 16/17 ("T" Block) in the North
Sea. This block commenced production in November 1993 and is expected to reach
peak production in the second quarter of 1994, with the year projected to
average 8,000 barrels a day. Production from the Ninian field in the North Sea
was down one percent in 1993 and 24 percent in 1992. Production levels in both
years were affected by construction activity in the field in preparation for
transporting crude oil and natural gas from other fields through the Ninian
facilities. Production in 1993 benefited from a successful workover program. The
acquisition of an additional 3.82-percent interest in the Ninian field in early
1994 is projected to add 1,900 barrels a day to U.K. production.
Natural gas production in 1993 increased 15 percent in the U.S. to an all-time
high and also reached record levels in Canada on the strength of a 21-percent
increase. Natural gas production was about level in the U.K. Production in
Spain, which is all from the Gaviota field, declined 51 percent. This field is
nearing depletion, and the Company is in final negotiations to participate in a
project to use the field's facilities to store third-party natural gas. The
increase in U.S. natural gas production was partially due to commencement of
production from a new field in the Gulf of Mexico during the fourth quarter of
1993. Two additional fields in the Gulf of Mexico commenced production early in
1994, and after allowing for normal declines from other properties, a 10-percent
increase in U.S. natural gas production in 1994 could be achieved under market
and other conditions existing at the end of 1993. Production of natural gas in
1992 increased 24 percent in the U.S. despite the adverse effects of Hurricane
Andrew. Production increased 18 percent in Canada and 37 percent in the U.K.,
but declined 13 percent in Spain.
As previously indicated, worldwide crude oil prices were under pressure
throughout most of 1993 and at year-end were well below levels of recent years.
In the U.S., Murphy's 1993 average monthly sales prices for crude oil
[GRAPH: Range of U.S. Crude Oil Sales Prices]
[GRAPH: Range of U.S. Natural Gas Sales Prices]
25
ranged from $18.42 a barrel to $14.73 through November, before falling
to $12.52 in December. U.K. average sales prices ranged from $19.51 a barrel to
$15.22 over the first 11 months, and then declined to $13.56 in the final month
of the year. Yearly averages were $16.60 a barrel in the U.S. and $16.63 in the
U.K., both decreases of 12 percent when compared to 1992. In Canada, the average
sales price for light oil was $15.01 a barrel, a decrease of 10 percent, and the
average price for heavy oil declined 11 percent to $9.84. In December 1993,
light and heavy oil sales prices averaged $10.73 a barrel and $6.58 a barrel,
respectively. Average crude oil prices in 1992 were five percent lower in the
U.S. and the U.K. and four percent lower for light oil in Canada. The average
sales price for heavy oil in Canada ran counter to the trend and increased 21
percent compared to 1991.
In 1993, natural gas sales prices in the U.S. were more stable than in 1992
and ranged from $2.51 an MCF to $1.63. Prices for the year averaged $2.10 an MCF
compared to $1.75 a year ago. In Canada, the average 1993 sales price for
natural gas increased 21 percent, reflecting a gradual recognition of market
conditions, as expiring contracts are being renewed at higher prices. Prices
declined 19 percent in the U.K., mostly the result of a stronger U.S. dollar in
relation to the pound sterling, and increased two percent in Spain.
Based on 1993 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 $7.2 million and $6.4 million, respectively. Consolidated
net income could have been affected differently because of contrary or corollary
effects on other business segments.
Production costs were $114.4 million in 1993, $110 million in 1992, and $106.2
million in 1991. These amounts are shown by major operating area on page 59.
Geographically, costs per equivalent barrel during the last three years were as
follows.
- - - ------------------------------------------
(Millions of dollars) 1993 1992 1991
- - - ------------------------------------------
United States.......... $3.21 3.00 3.42
Canada................. 3.70 4.18 4.90
United Kingdom......... 6.80 8.73 7.25
Spain.................. 5.18 4.69 3.02
==========================================
U.S. costs were down because of higher production volumes, offset in 1993 by
higher insurance costs as a result of Hurricane Andrew. Reductions in Canada
were due to higher production volumes and a strengthening of the U.S. dollar in
relation to the Canadian dollar. The 1993 decline in U.K. cost per equivalent
barrel was due to a cost-reduction program in the Ninian field, higher volumes,
and strengthening of the U.S. dollar, partially offset by an increase in Ninian
workover costs. The increase in 1992 was primarily due to lower production
volumes.
The per-barrel equivalent costs for the most significant acquisitions -- "T"
Block and Syncrude -- are estimated to be $2.70 and $11.30, respectively, in
1994.
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
58 and 59.
- - - --------------------------------------------
(Millions of dollars) 1993 1992 1991
- - - --------------------------------------------
Included in capital
expenditures
Dry hole costs....... $21.5 29.9 21.3
Geological and
geophysical costs.. 7.6 8.9 11.1
Other costs.......... 4.9 5.9 5.8
- - - --------------------------------------------
34.0 44.7 38.2
Undeveloped lease
amortization........... 12.1 17.4 14.1
- - - ---------------------------------------------
Total................. $46.1 62.1 52.3
=============================================
Exploration expenses included in "Other international" in the table on page 24
totaled $6.6 million in 1993, $13.5 million in 1992, and $6.3 million in 1991.
Depreciation, depletion, and amortization totaled $141.2 million in 1993;
$129.7 million in 1992; and $116.1 million in 1991, excluding write-downs of oil
and gas properties. The increase in each year was primarily due to higher
production volumes. In addition, as reviewed in Note B to the consolidated
financial statements, adoption of Statement of Financial Accounting Standards
No. 109, Accounting for Income Taxes, resulted in an addition to net property,
plant, and equipment, representing the tax effect of prior business combinations
originally recorded net of tax. Depreciation, depletion, and amortization in
1993 included $10.9 million attributable to that adjustment; this amount was
essentially offset by additional deferred income tax benefits. The 1993
acquisitions of proved properties will result in a substantial increase in
depreciation, depletion, and amortization in 1994 as the acquired reserves are
produced. The projected 1994 rates per barrel, including dismantlement costs,
are $11.25 for "T" Block and $1.50 for Syncrude.
REFINING, MARKETING, AND TRANSPORTATION--Earnings from refining, marketing,
and transportation operations before unusual or infrequently occurring items
were $31.5 million in 1993, $8 million in 1992, and $43.3 million in 1991.
Operations in the U.S. earned $11.2 million in 1993 compared to a
[GRAPH: Exploration Expenses]
26
loss of $6 million in 1992. U.S. earnings in 1991 totaled $20.9 million.
Operations in Western Europe earned $11.7 million compared to $4.6 million in
1992 and $15.6 million in 1991. Canadian operations contributed $8.6 million to
1993 earnings compared to $9.4 million in 1992 and $6.8 million in 1991.
Unit margins (sales realizations less crude and other feedstocks, refining,
and costs to point of delivery) averaged $.82 a barrel in the U.S. in 1993, $.48
in 1992, and $1.59 in 1991. U.S. product sales increased six percent in 1993 and
10 percent in 1992. Margins in the Company's southeastern marketing area
remained under pressure during 1993 in a highly competitive environment. Margins
in the upper-midwest area benefited from a strong asphalt market and were up
substantially compared to a year ago. In 1992, the weak U.S. economy adversely
affected product prices, and margins suffered in both areas compared to 1991.
Margins in Western Europe averaged $3.08 a barrel in 1993, $2.67 in 1992, and
$3.52 in 1991. Sales of petroleum products increased three percent following a
six-percent decline in 1992. Western European margins fluctuated widely in 1993,
but were on an upward trend late in the year. Margins in 1992 were also affected
by depressed economic activity and reflected a reduced level of demand for
petroleum products.
Based on sales volumes for 1993 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 $14.9 million. Consolidated net income
could have been affected differently because of contrary or corollary effects on
other business segments.
The earnings decline in 1993 from purchasing, transporting, and reselling
crude oil in Canada was due to lower crude trading volumes and increased
pipeline operating costs, which more than offset higher pipeline throughputs.
The improvement in 1992 was due to higher crude trading volumes and margins and
an increase in throughput volumes.
FARM, TIMBER, AND REAL ESTATE--Earnings from farm, timber, and real estate
operations were $13.1 million in 1993, $8.4 million in 1992, and $4.8 million in
1991. The increase in 1993 was due to a strong performance from timber
operations, which earned $11.3 million, a $5.5 million improvement. Sales of
finished lumber increased nine percent, and the average sales price increased 29
percent to a record $335 per thousand board feet. The earnings contribution from
real estate operations totaled $2.4 million, up $.6 million on increased lot
sales. Farming operations were hampered by adverse weather throughout the year
and basically broke even in 1993 compared to earning $1.2 million in 1992. The
improvement in 1992 earnings was primarily from timber operations, a $2.7
million increase, and farming operations, a $.9 million increase. Timber
earnings were up mainly as a result of an increase in lumber sales combined with
higher sales prices and improved operating efficiencies. The farms enjoyed
favorable weather compared to 1991, when spring rains hurt early crops and led
to higher operating costs. The earnings contribution from real estate operations
increased $.1 million in 1992.
CORPORATE AND OTHER--This segment includes interest income and expense and
corporate overhead not allocated to operating functions and ordinarily results
in a net burden. The contribution to earnings in 1992 of $2.6 million was due to
use of proceeds from sale of the contract drilling business, which resulted in a
substantial increase in interest income from invested funds and a significant
reduction in long-term debt and related interest expense when compared to 1991.
During 1993, a substantial amount of the invested funds were used to acquire oil
and gas properties, resulting in lower interest income compared to a year ago.
UNUSUAL OR INFREQUENTLY OCCURRING ITEMS--Net income for each of the three years
ended December 31, 1993 included certain unusual or infrequently occurring items
reviewed below. The information presented indicates the quarter in which the
item occurred. Certain other quarterly information is presented on page 31.
. Refund and settlement of income tax matters--Gains of $11.3 million and $3.1
million were recorded in the first and fourth quarters of 1993, respectively,
for refund and settlement of income tax matters in the U.K. A $21.5 million
gain for refund of U.S. income taxes was recorded in the second quarter of
1992, and a $12.2 million gain for settlement of income tax matters in the
U.K. and Gabon was recorded in the third quarter of 1992. A gain of $34.5
million for refund of U.S. income taxes was recorded in the third quarter of
1991.
. Provision for environmental remediation matters--An after-tax provision of
$4 million was recorded in the fourth quarter of 1993 for environmental
remediation matters. After-tax provisions of $3.6 million and $3.3 million
were recorded in the second and fourth quarters of 1992, respectively.
. Write-off of costs to acquire minority interest in a subsidiary not
attributable to specific assets--The second quarter of 1991 included a
charge of $83.9 million related to acquisition of the minority interest in
Ocean Drilling & Exploration Company. The charge represents write-off of the
cost of acquisition in excess of the fair values of the assets
[GRAPH: Average Sales Price of U.S. Refined Products]
[GRAPH: Average Sawmill Margin]
[GRAPH: Selling and General Expenses]
27
acquired and includes estimated expenses of consolidating the organizations.
(See Note C to the consolidated financial statements.)
. Write-down of oil and gas properties -- The second quarter of 1991 included a
loss from the write-down in carrying value of certain oil and gas properties.
The write-down included $17.3 million for Canadian properties and $16 million
for U.S. properties.
. Settlement of insurance subsidiary litigation--Litigation relating to the
liquidation of an insurance subsidiary was settled in early 1992, and the
fourth quarter of 1991 reflected a $10.6 million reversal of the excess
portion of a loss provision made in 1987. (See Note E to the consolidated
financial statements.)
. Settlement of windfall profit tax dispute--Settlement of the dispute
resulted in a first quarter 1991 gain of $4.8 million.
. Discontinued operations--The first quarter of 1992 included a net gain of
$20.3 million from sale of the contract drilling business; the fourth quarter
included a $3.6 million adjustment to increase that gain. In 1991, the
discontinued contract drilling business had losses of $5 million, $1 million,
and $.2 million in the first, second, and fourth quarters, respectively,
partially offset by income of $4.6 million in the third quarter. (See Note D
to the consolidated financial statements.)
. 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 accounting changes in 1993 and discontinued
contract drilling operations in 1992 and 1991, the income (loss) effects of
unusual or infrequently occurring items are summarized by function in the
following table for the three years ended December 31, 1993.
- - - -------------------------------------------------
(Millions of dollars) 1993 1992 1991
- - - -------------------------------------------------
Exploration and
production
United States........ $ -- (.2) (11.1)
Canada............... -- -- (17.3)
United Kingdom....... 14.4 3.3 --
Other international.. -- 4.2 --
- - - -------------------------------------------------
14.4 7.3 (28.4)
- - - -------------------------------------------------
Refining, marketing,
and transportation
United States........ (3.9) (5.9) --
Western Europe....... (.1) (2.8) --
- - - -------------------------------------------------
(4.0) (8.7) --
- - - -------------------------------------------------
Corporate and other...... -- 28.2 (38.9)
- - - -------------------------------------------------
Total................ $10.4 26.8 (67.3)
=================================================
Certain of the unusual or infrequently occurring items had a significant
effect on the Company's consolidated effective income tax rates, which were 35
percent in 1993, nine percent in 1992, and 124 percent in 1991. (See Note J to
the consolidated financial statements.)
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
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.
CAPITAL EXPENDITURES
As shown on page 23, capital expenditures were $637.6 million in 1993 compared
to $235.6 million in 1992 and $223.2 million in 1991. Capital expenditures for
exploration and production activities totaled $537 million in 1993, 84 percent
of the Company's total capital expenditures for the year, and included $259.7
million for acquisition of proved properties. Excluding this amount, exploration
and production activities accounted for 73 percent of 1993 capital expenditures
and totaled $277.3 million--$4.4 million for acquisition of undeveloped leases,
$60.2 million for exploration activities, and $212.7 million for development
projects. Development expenditures included $67.7 million for oil fields in
Ecuador. The expenditures for acquisition of proved properties included $143.1
million for the 11.26-percent interest in "T" Block. The five-percent interest
in the Syncrude project in Canada accounted for $109 million of the proved
property acquisition costs, $67.4 million of which was noncash and seller-
financed by nonrecourse debt. Development expenditures associated with
properties acquired in 1993 included $23.7 million for "T" Block and $38.4
million attributable to a 6.5-percent interest in the Hibernia oil field,
offshore Newfoundland. A 1992 acquisition of a 30-percent interest in Viosca
Knoll Block 783 required development expenditures of $20.2 million during 1993.
Exploration and production capital expenditures are shown by major operating
area on page 58.
[GRAPH: Capital Expenditures in 1993]
28
Amounts shown under "Other" in 1993 include $4.4 million for an unsuccessful
well in Peru.
Refining, marketing, and transportation expenditures, detailed below, were
$86.9 million in 1993, or 13 percent of total capital expenditures.
- - - -------------------------------------------------
(Millions of dollars) 1993 1992 1991
- - - -------------------------------------------------
Refining
United States............... $64.3 36.9 31.9
United Kingdom.............. 2.1 11.1 12.7
- - - -------------------------------------------------
Total refining........... 66.4 48.0 44.6
- - - -------------------------------------------------
Marketing
United States............... 6.9 6.8 9.5
United Kingdom.............. 9.9 6.5 5.3
Canada...................... .1 .8 .4
- - - -------------------------------------------------
Total marketing.......... 16.9 14.1 15.2
- - - -------------------------------------------------
Transportation
United States............... .2 .6 .3
Canada...................... 3.4 5.4 3.0
- - - -------------------------------------------------
Total transportation..... 3.6 6.0 3.3
- - - -------------------------------------------------
Total.................... $86.9 68.1 63.1
=================================================
Refining expenditures of $66.4 million included $32.3 million at Meraux,
Louisiana, and $5.1 million at Superior, Wisconsin, for distillate
desulfurization projects; $6.1 million at Meraux for sour crude processing
facilities; and $13.7 million related to environmental standards and
regulations. The remaining $9.2 million was for replacements and improvements
and included $6.1 million at Meraux, $1.3 million at Superior, and $1.8 million
at Milford Haven. Marketing expenditures of $16.9 million included the costs of
sites and new service stations, acquisition of stations, and improvements and
normal replacements at existing stations and terminals. The U.S. expenditures
included $.6 million for replacement of underground storage tanks and
installation of leak detection systems at stations.
Deltic spent $5.7 million for real estate development, $3.6 million for timber
operations including sawmill upgrades, and $.4 million on the farms.
CASH FLOWS
Cash provided by continuing operations was $363 million in 1993, $284.2 million
in 1992, and $213.6 million in 1991. Resolution of certain tax matters provided
$11.8 million of cash in 1993, $41.5 million in 1992, and $39.3 million in 1991.
Cash provided by nonrecourse debt arrangements totaled $27.7 million in 1993.
Disposition of assets provided $365.4 million in 1992, primarily from sale of
the contract drilling business. Cash provided by discontinued operations was $26
million in 1991.
Capital expenditures required $570.2 million of cash in 1993, $235.6 million
in 1992, and $223.2 million in 1991. These amounts included $34 million, $44.7
million, and $38.2 million of exploration expenditures that were expensed. Other
significant cash outlays during the three years included $217 million in 1992
for net reductions of debt. Cash used for dividends to stockholders was $55.9
million in 1993; $53.8 million in 1992; and $49.2 million in 1991, including $2
million to minority stockholders of a subsidiary. The Company also repurchased
48,400 shares of its Common Stock in 1993 and 161,100 shares in 1992 for $1.6
million and $5.4 million, respectively. Cash used for investing activities of
discontinued operations totaled $18.4 million in 1991, primarily for capital
expenditures.
FINANCIAL CONDITION
Year-end working capital totaled $130.2 million in 1993, $371.7 million in
1992, and $156.2 million in 1991. The changes during the two most recent years
primarily reflect in 1992 the cash sale of the Company's contract drilling
business for $372 million and the retirement of most debt, and in 1993 the
investments to expand the Company's oil and gas business. 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 $46.3 million below current costs at December 31, 1993. Cash and
equivalents at the end of 1993 totaled $141.2 million compared to $377.8 million
a year ago and $242.1 million at year-end 1991.
Long-term obligations increased $84.3 million and were $109.2 million at year-
end, 8.2 percent of total capital employed, and included $87.5 million of
nonrecourse debt incurred in connection with the acquisition and development of
proved properties. Long-term obligations totaled $24.9 million at the end of
1992 compared to $193.1 million at year-end 1991. Stockholders' equity was $1.2
billion at each year-end. A summary of transactions in the equity accounts is
presented on page 36.
The primary sources of the Company's liquidity are internally generated funds,
access to outside financing by bank borrowings, 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. Because of the Company's current
financial position, no problem is anticipated in meeting future requirements for
funds. Current financing arrangements are set forth in Note H to the
consolidated financial statements.
The Company had commitments of $274 million for capital projects in progress
at December 31, 1993.
[GRAPH: Sources of Cash and Cash Equivalents in 1993]
[GRAPH: Uses of Cash and Cash Equivalents in 1993]
29
ENVIRONMENTAL OBLIGATIONS
The Company's worldwide operations are subject to numerous laws and
regulations designed to protect the environment. In addition, the Company may be
involved in personal injury claims, allegedly caused by exposure to materials
manufactured or used by the Company. 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
will be recorded. The need to adjust amounts recorded is reviewed quarterly.
Actual cash expenditures often follow recognition of the obligation by a number
of years.
The Company currently 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. During 1993, the Company increased its reserve for
remediation obligations by a pretax provision of $6.3 million. Included in the
reserve are certain amounts that are based on anticipated regulatory approval of
proposed remediation processes involving a land farm, formerly used for disposal
of refinery waste, and closure of water basins. If regulatory authorities
require more costly alternatives than the proposed processes, future
expenditures could increase by up to an estimated $9 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 two Superfund sites and has
been assigned responsibility by defendants at another Superfund site. In
addition, the Company is aware of three other sites at which it could be named
as a PRP. The potential total cost to all parties to perform necessary
remediation work at these sites is substantial. However, based on information
currently available, the Company is a de minimus party, with assigned or
potentially assigned responsibility of less than one percent at each site. The
Company has recorded a reserve totaling $.1 million for these sites. Due to
these minor percentages, the Company does not expect that its remediation costs
at these sites will be material to its financial condition. Additional
information may become known in the future that would alter this assessment,
including a 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 its 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 of the environmental remediation obligations
are covered by insurance; however, the issue is the subject of ongoing
litigation and no assurance can be given that the Company's position will be
sustained. Therefore, no insurance recoveries have been used to reduce the
environmental liabilities recorded at December 31, 1993.
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 1993.
In addition to remediation and other recurring expenditures, Murphy commits a
substantial amount of its capital expenditure program for compliance with
environmental laws and regulations. Such capital expenditures were approximately
$74 million in 1993 and are expected to be $58 million in 1994.
OUTLOOK
In planning for 1994, prices for the Company's products remain an uncertainty.
Crude oil prices, which dropped sharply in late 1993, remain at depressed levels
in early 1994, and prices for natural gas and product margins have fluctuated
significantly in recent months. In such an environment, constant reassessment of
spending plans is required. The Company's capital expenditure budget for 1994
was prepared during the fall of 1993 and provides for expenditures of $444
million. A major portion of this amount, $313 million or 70 percent, is
allocated for exploration and production. Geographically, about 36 percent of
the exploration and production money is designated for the U.S., with primary
emphasis in the Gulf of Mexico; 30 percent for Canada, including $49 million for
development of the Hibernia oil field (most of which will be funded by
additional nonrecourse debt); 17 percent for development of oil fields in
Ecuador; and the remaining 17 percent for other overseas operations. Capital
expenditures for refining, marketing, and transportation are budgeted at $108
million, including $19 million to expand sour crude processing capabilities at
the Meraux refinery and $13 million for environmental compliance projects at the
Superior refinery. Budgeted marketing capital expenditures total $12 million in
the U.S. and $14 million in the U.K. Other budgeted expenditures include $16
million for farm, timber, and real estate, about equally divided between real
estate and sawmills, and $7 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.
30
QUARTERLY INFORMATION
- - - --------------------------------------------------------------------------------------------
1993(1)
- - - --------------------------------------------------------------------------------------------
FIRST SECOND THIRD FOURTH
(Millions of dollars except per share amounts) QUARTER QUARTER QUARTER QUARTER YEAR
- - - --------------------------------------------------------------------------------------------
Sales and other operating revenues............. $390.9 421.5 410.4 413.9 1,636.7
Income from continuing operations before
income taxes................................. 23.3 42.2 33.8 34.3 133.6
Income from continuing operations.............. 23.9 22.7 20.2 20.0 86.8
Cumulative effect of changes in accounting
principles................................... 15.3 -- -- -- 15.3
Net income..................................... 39.2 22.7 20.2 20.0 102.1
Per Common share(2)
Income from continuing operations........... .53 .51 .45 .45 1.94
Cumulative effect of changes in accounting
principles................................ .34 -- -- -- .34
Net income.................................. .87 .51 .45 .45 2.28
Dividends................................... .30 .30 .325 .325 1.25
Market Price
High........................................ 42 3/8 45 1/8 47 3/4 47 7/8 47 7/8
Low......................................... 33 38 7/8 39 1/2 37 5/8 33
- - - --------------------------------------------------------------------------------------------
1992(1)
- - - --------------------------------------------------------------------------------------------
Sales and other operating revenues.............. $359.2 409.9 415.3 447.0 1,631.4
Income (loss) from continuing operations
before income taxes........................... 5.3 36.1 (1.0) 28.9 69.3
Income (loss) from -- Continuing operations..... (1.1) 27.5 14.7 21.7 62.8
Discontinued operations... 20.3 -- -- 3.5 23.8
Income before extraordinary item................ 19.2 27.5 14.7 25.2 86.6
Extraordinary item(3)........................... 4.1 6.4 2.4 6.1 19.0
Net income...................................... 23.3 33.9 17.1 31.3 105.6
Per Common share(2)
Income (loss) from -- Continuing operations.. (.02) .61 .33 .48 1.40
Discontinued operations .45 -- -- .08 .53
Income before extraordinary item............. .43 .61 .33 .56 1.93
Extraordinary item(3)........................ .09 .14 .05 .14 .42
Net income................................... .52 .75 .38 .70 2.35
Dividends.................................... .30 .30 .30 .30 1.20
Market Price
High......................................... 37 1/4 38 3/8 37 7/8 37 7/8 38 3/8
Low.......................................... 32 3/8 32 5/8 33 1/8 34 1/4 32 3/8
- - - --------------------------------------------------------------------------------------------
(1) The amounts reflected in continuing operations include certain unusual or
infrequently occurring gains (losses) that are reviewed in Management's
Discussion and Analysis. Quarterly totals, in millions of dollars, and the
effect per Common share are reported in the following table.
- - - --------------------------------------------------------------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER YEAR
- - - --------------------------------------------------------------------------------------------
1993
Quarterly totals................................ $ 11.3 -- -- (.9) 10.4
Per Common share(2)............................. .25 -- -- (.02) .23
- - - --------------------------------------------------------------------------------------------
1992
Quarterly totals................................ $ -- 17.9 12.2 (3.3) 26.8
Per Common share(2)............................. -- .40 .27 (.07) .60
- - - --------------------------------------------------------------------------------------------
(2) Based on average number of Common and Common equivalent shares outstanding
during the respective periods.
(3) Represents a credit for tax benefit from utilization of a financial net
operating loss carryforward. This credit offsets an equivalent charge in
continuing operations.
Market prices of Common Stock are as quoted on the New York Stock Exchange.
There were 5,265 stockholders of record at December 31, 1993.
31
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, but not absolute, assurance
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, 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 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 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, 1993 and 1992, 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, 1993.
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, 1993 and 1992, and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 1993, in conformity with generally
accepted accounting principles.
As discussed in Note B to the consolidated financial statements, the Company
adopted the provisions of Financial Accounting Standards Board's 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, in 1993.
KPMG PEAT MARWICK
Shreveport, Louisiana
March 4, 1994
32
CONSOLIDATED STATEMENTS OF INCOME
- - - -----------------------------------------------------------------------------------------------
(Thousands of dollars except per share amounts)
- - - -----------------------------------------------------------------------------------------------
Years Ended December 31 1993 1992 1991
- - - -----------------------------------------------------------------------------------------------
REVENUES
Sales...................................................... $1,599,833 1,596,394 1,573,314
Other operating revenues................................... 36,835 35,047 27,621
Interest and other revenues................................ 34,469 53,974 89,151
- - - -----------------------------------------------------------------------------------------------
Total revenues 1,671,137 1,685,415 1,690,086
- - - -----------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Crude oil, products, and operating expenses................ 1,247,831 1,301,485 1,229,117
Exploration expenses, including undeveloped
lease amortization....................................... 46,071 62,097 52,339
Selling and general expenses............................... 65,195 72,861 71,842
Depreciation, depletion, and amortization.................. 176,213 164,822 149,648
Write-off of costs to acquire minority interest in a
subsidiary not attributable to specific assets........... -- -- 85,644
Write-down of oil and gas properties....................... -- -- 43,471
Interest expense........................................... 7,614 17,079 30,982
Interest capitalized....................................... (5,414) (2,254) (2,972)
- - - -----------------------------------------------------------------------------------------------
Total costs and expenses 1,537,510 1,616,090 1,660,071
- - - -----------------------------------------------------------------------------------------------
Income from continuing operations before income taxes and
minority interest........................................ 133,627 69,325 30,015
Federal and state income taxes............................. 40,383 19,018 23,682
Foreign income taxes (benefits)............................ 6,446 (12,454) 13,475
Minority interest in income of a subsidiary................ -- -- 2,465
- - - -----------------------------------------------------------------------------------------------
Income (loss) from continuing operations 86,798 62,761 (9,607)
- - - -----------------------------------------------------------------------------------------------
DISCONTINUED OPERATIONS
Loss from operations, net of minority interest............. -- -- (1,550)
Gain on disposal........................................... -- 23,855 --
- - - -----------------------------------------------------------------------------------------------
Income (loss) from discontinued operations -- 23,855 (1,550)
- - - -----------------------------------------------------------------------------------------------
Income (loss) before extraordinary item and cumulative
effect of changes in accounting principles............... 86,798 86,616 (11,157)
Extraordinary tax benefit from utilization of financial
net operating loss carryforward.......................... -- 18,949 --
Cumulative effect of changes in accounting principles...... 15,338 -- --
- - - -----------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ 102,136 105,565 (11,157)
===============================================================================================
PER COMMON SHARE
Income (loss) from continuing operations................. $ 1.94 1.40 (.24)
Income (loss) from discontinued operations............... -- .53 (.04)
- - - -----------------------------------------------------------------------------------------------
Income (loss) before extraordinary item and cumulative
effect of changes in accounting principles............... 1.94 1.93 (.28)
Extraordinary item........................................ -- .42 --
Cumulative effect of changes in accounting principles..... .34 -- --
- - - -----------------------------------------------------------------------------------------------
Net income (loss) $ 2.28 2.35 (.28)
===============================================================================================
Average Common shares outstanding 44,856,635 44,931,208 39,457,719
===============================================================================================
See notes to consolidated financial statements, page 37.
33
CONSOLIDATED BALANCE SHEETS
- - - ----------------------------------------------------------------------------------------
(Thousands of dollars)
- - - ----------------------------------------------------------------------------------------
December 31 1993 1992
- - - ----------------------------------------------------------------------------------------
ASSETS
Current assets
Cash and interest-bearing deposits......................... $ 26,876 137,861
Marketable securities...................................... 114,349 239,984
- - - ----------------------------------------------------------------------------------------
Cash and cash equivalents................................ 141,225 377,845
Accounts receivable, less allowance for doubtful accounts
of $5,379 in 1993 and $6,318 in 1992...................... 196,214 241,397
Inventories
Crude oil and raw materials............................... 76,741 60,977
Finished products......................................... 42,959 50,497
Materials and supplies.................................... 32,323 25,383
Prepaid expenses........................................... 35,042 42,509
Deferred income taxes...................................... 18,497 --
- - - ----------------------------------------------------------------------------------------
Total current assets..................................... 543,001 798,608
Investments and noncurrent receivables...................... 42,518 27,403
Property, plant, and equipment, at cost less accumulated
depreciation, depletion, and amortization of $2,180,732
in 1993 and $2,064,488 in 1992............................ 1,549,250 1,073,179
Deferred charges and other assets........................... 34,090 37,324
- - - ----------------------------------------------------------------------------------------
$2,168,859 1,936,514
========================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term obligations................ $ 10,859 3,662
Short-term notes payable................................... -- 2,795
Accounts payable........................................... 255,332 251,462
Accrued insurance obligations.............................. 28,420 34,941
Accrued taxes other than taxes on income................... 33,303 29,392
Other accrued liabilities.................................. 55,551 62,733
Income taxes............................................... 29,294 41,941
- - - ----------------------------------------------------------------------------------------
Total current liabilities................................ 412,759 426,926
Notes payable and other long-term obligations............... 21,709 24,929
Nonrecourse debt of a subsidiary............................ 87,509 --
Deferred income taxes....................................... 117,571 43,918
Reserve for dismantlement costs............................. 123,107 112,719
Reserve for major repairs................................... 26,023 19,139
Deferred credits and other liabilities...................... 157,831 108,795
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 in 1993 and 1992................. 48,775 48,775
Capital in excess of par value............................. 507,292 506,962
Retained earnings.......................................... 772,172 725,981
Currency translation adjustments........................... (1,514) 21,595
Unamortized restricted stock awards........................ (660) (835)
Treasury stock............................................. (103,715) (102,390)
- - - ----------------------------------------------------------------------------------------
Total stockholders' equity 1,222,350 1,200,088
- - - ----------------------------------------------------------------------------------------
$2,168,859 1,936,514
========================================================================================
See notes to consolidated financial statements, page 37.
34
CONSOLIDATED STATEMENTS OF CASH FLOWS
- - - -----------------------------------------------------------------------------------------------------------
(Thousands of dollars)
- - - -----------------------------------------------------------------------------------------------------------
Years Ended December 31 1993 1992 1991
- - - -----------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Income (loss) from continuing operations................................... $ 86,798 62,761 (9,607)
Adjustments to reconcile income (loss) to net cash provided
by operating activities
Depreciation, depletion, amortization.................................... 176,213 164,822 149,648
Write-off of costs to acquire minority interest in a
subsidiary not attributable to specific assets, net of taxes............ -- -- 83,944
Write-down of oil and gas properties, net of taxes and minority interest. -- -- 33,260
Expenditures for major repairs and dismantlement costs................... (13,391) (3,455) (29,757)
Exploratory expenditures charged against income.......................... 33,945 44,701 38,259
Amortization of undeveloped leases....................................... 12,126 17,396 14,080
Deferred and noncurrent income tax charges (credits)..................... 36,970 (21,740) 23,175
Charge equivalent to federal income tax benefit of
operating loss carryforward............................................. -- 18,949 --
Minority interest in income of a subsidiary.............................. -- -- 4,816
Gains from disposition of assets......................................... (1,474) (1,709) (697)
Other -- net............................................................. 32,422 39,399 20,005
- - - -----------------------------------------------------------------------------------------------------------
363,609 321,124 327,126
(Increase) decrease in operating working capital other than cash
and cash equivalents...................................................... 418 (30,917) (96,436)
Cumulative effect of accounting changes on working capital................. 25,437 -- --
Net expenditures under insurance claim to repair hurricane damage.......... (18,172) (11,560) --
Other adjustments related to continuing operations......................... (8,319) 5,512 (17,055)
- - - -----------------------------------------------------------------------------------------------------------
Net cash provided by continuing operations................................. 362,973 284,159 213,635
Net cash provided by discontinued operations............................... -- -- 26,008
- - - -----------------------------------------------------------------------------------------------------------
Net cash provided by operating activities............................... 362,973 284,159 239,643
- - - -----------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures requiring cash........................................ (570,186) (235,565) (223,221)
Proceeds from sale of property, plant, and equipment....................... 5,721 3,716 12,105
Other continuing operations -- net......................................... 2,481 (2,847) (1,661)
Sale of discontinued operations............................................ -- 361,673 --
Investing activities of discontinued operations............................ -- -- (18,390)
- - - -----------------------------------------------------------------------------------------------------------
Net cash provided (required) by investing activities.................... (561,984) 126,977 (231,167)
- - - -----------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Additions to notes payable and other long-term obligations................. 161 236 49,760
Reductions of notes payable and other long-term obligations................ (3,738) (182,355) (67,479)
Increase in nonrecourse debt of a subsidiary............................... 27,693 -- --
Increase (decrease) in short-term notes payable............................ (2,795) (34,885) 32,175
Dividends paid
Murphy shareholders...................................................... (55,945) (53,821) (47,234)
Minority shareholders.................................................... -- -- (2,006)
Purchase of Common Stock for treasury...................................... (1,636) (5,440) --
- - - -----------------------------------------------------------------------------------------------------------
Net cash required by financing activities............................... (36,260) (276,265) (34,784)
- - - -----------------------------------------------------------------------------------------------------------
Effect of exchange rate changes on cash and cash equivalents............... (1,349) (7,230) 1,951
- - - -----------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents....................... (236,620) 127,641 (24,357)
(Increase) decrease applicable to discontinued operations.................. -- 8,139 (3,676)
- - - -----------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
OF CONTINUING OPERATIONS.................................................. (236,620) 135,780 (28,033)
Cash and cash equivalents of continuing operations at January 1............ 377,845 242,065 270,098
- - - -----------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS OF CONTINUING OPERATIONS AT DECEMBER 31.......... $ 141,225 377,845 242,065
===========================================================================================================
See notes to consolidated financial statements, page 37.
35
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
- - - ----------------------------------------------------------------------------------------------------
(Thousands of dollars)
- - - ----------------------------------------------------------------------------------------------------
Years Ended December 31 1993 1992 1991
- - - ----------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK -- par $100, authorized
400,000 shares, none issued $ -- -- --
- - - ----------------------------------------------------------------------------------------------------
COMMON STOCK
Balance at beginning of year..................................... 48,775 48,775 37,742
Add 11,032,956 shares issued to acquire minority
interest in a subsidiary........................................ -- -- 11,033
- - - ----------------------------------------------------------------------------------------------------
Common Stock, par $1.00, authorized 80,000,000 shares,
issued 48,775,314 shares at end of year 48,775 48,775 48,775
- - - ----------------------------------------------------------------------------------------------------
CAPITAL IN EXCESS OF PAR VALUE
Balance at beginning of year..................................... 506,962 506,559 150,977
Issuance of Common Stock to acquire minority interest
in a subsidiary................................................. -- -- 355,499
Exercise and surrender of stock options.......................... 224 115 24
Restricted stock transactions.................................... 106 288 --
Capital transactions of subsidiaries............................. -- -- 59
- - - ----------------------------------------------------------------------------------------------------
Capital in excess of par value at end of year 507,292 506,962 506,559
- - - ----------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance at beginning of year..................................... 725,981 674,237 732,628
Net income (loss) for the year................................... 102,136 105,565 (11,157)
Cash dividends -- $1.25 a share in 1993, $1.20 a share
in 1992 and 1991................................................ (55,945) (53,821) (47,234)
- - - ----------------------------------------------------------------------------------------------------
Retained earnings at end of year 772,172 725,981 674,237
- - - ----------------------------------------------------------------------------------------------------
CURRENCY TRANSLATION ADJUSTMENTS
Balance at beginning of year..................................... 21,595 69,223 50,718
Increase applicable to acquisition of minority interest
in a subsidiary................................................. -- -- 18,399
Translation gains (losses) during the year....................... (23,109) (47,628) 106
- - - ----------------------------------------------------------------------------------------------------
Currency translation adjustments at end of year (1,514) 21,595 69,223
- - - ----------------------------------------------------------------------------------------------------
UNAMORTIZED RESTRICTED STOCK AWARDS
Balance at beginning of year..................................... (835) -- --
Stock awards..................................................... -- (1,180) --
Amortization, forfeitures, and changes in price of Common Stock.. 175 345 --
- - - ----------------------------------------------------------------------------------------------------
Unamortized restricted stock awards at end of year (660) (835) --
- - - ----------------------------------------------------------------------------------------------------
TREASURY STOCK -- 3,967,631 shares of Common Stock
in 1993, 3,931,076 shares in 1992, and 3,809,785 shares
in 1991, at cost (103,715) (102,390) (97,975)
- - - ----------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY $1,222,350 1,200,088 1,200,819
====================================================================================================
See notes to consolidated financial statements, page 37.
36
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. The
contract drilling business segment, which was sold effective January 1, 1992, is
accounted for as discontinued operations. Information presented in the footnotes
is based on continuing operations unless otherwise indicated. Investments in
jointly owned companies are accounted for by the equity method. All significant
intercompany accounts and transactions have been eliminated.
Marketable Securities--Marketable securities (short-term investments in
government securities, or with government securities as collateral, that have a
maturity of three months or less from the date of purchase) are recorded at cost
plus accrued interest, which approximates market value, and are treated 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.
Exploration and Development--The Company uses the successful efforts method of
accounting for exploration and development expenditures. Direct acquisition
costs of developed and undeveloped leases are capitalized. Cost of undeveloped
leases on which proved reserves are found is transferred to producing oil and
gas properties. Each undeveloped lease with significant acquisition cost is
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. Worldwide undiscounted future net revenues are compared
annually to net capitalized cost of proved properties to determine if an
impairment has occurred in the amount capitalized. As warranted by events,
significant, high-cost properties are assessed for permanent impairment based on
discounted future net revenues.
Depreciation and Depletion--Depreciation and depletion of producing oil and gas
properties are provided under the unit-of-production method on a
property-by-property basis. Developed reserves are used to compute unit rates
for unamortized tangible and intangible development costs, and proved reserves
are used for unamortized leasehold costs. Estimated costs (net of salvage value)
of dismantling oil and gas production facilities, including abandonment and site
restoration costs, are computed by the Company's engineers and included in
depreciation and depletion using the unit-of-production method. Depreciation of
refining and marketing facilities is calculated using the composite
straight-line method. Depletion of timber is based on board feet cut. Office
buildings, pipelines, and other properties are depreciated by individual unit
based on the straight-line method.
Asset Retirements--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.
Major Repairs--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--Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. (See
Note B to the consolidated financial statements for a discussion of the effects
of this change.) Under the asset and liability method of accounting for income
taxes required by SFAS No. 109, deferred tax assets and liabilities are based on
differences between the financial statement carrying amounts and the tax bases
of existing assets and liabilities, and are measured using the enacted tax rates
that are assumed will be in effect when the differences are expected to reverse.
The effect on deferred taxes of a change in a tax rate is recognized in the
statement of income for the period covering the enactment date. Provision for
petroleum revenue taxes payable to the U.K. government is based on the estimated
effective tax rate over the life of certain properties.
37
Employee Retirement Plans--Retirement benefits for substantially all employees
of the Company are funded by contributions to trustees. Retirement expense is
computed in accordance with SFAS No. 87, Employers' Accounting for Pensions.
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 as a separate
component of stockholders' equity entitled "Currency Translation Adjustments."
Gains or losses that result from specific transactions in a currency other than
the functional currency are included in net income.
Foreign Currency Contracts--Foreign currency contracts may be executed to hedge
future commitments or to offset certain U.S. dollar transactions. Gains or
losses on capital hedge transactions are included in property, plant, and
equipment; gains or losses on hedged nonrecourse debt are recorded in "Currency
Translation Adjustments;" and other gains or losses are included in net income.
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 the weighted
average number of Common and Common equivalent shares outstanding during each
reporting period into net income.
NOTE B--ACCOUNTING CHANGES--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 the actuarially determined costs of postretirement benefits
(supplemental health care and life insurance) to be accrued over the estimated
service lives of employees. Previously, the Company expensed these costs when
incurred. The cumulative effect of adopting SFAS No. 106, which was recorded as
of January 1, 1993 based on a nine-percent discount rate, resulted in a charge
against net income of $16,502,000, $.37 a share, after an income tax effect of
$8,500,000. Excluding the charge against income for the cumulative effect, the
adoption of SFAS No. 106 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. The Company previously accounted for income taxes using the deferred
method prescribed by Accounting Principles Board Opinion No. 11. Under this
method, deferred income taxes were recognized for certain revenues and expenses
that affected financial and taxable income in different years, were recorded
using the tax rates applicable for the year of calculation, and were not
adjusted for subsequent tax rate changes.
As a result of adopting SFAS No. 109, 1993 income from continuing operations
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.
In November 1992, the Financial Accounting Standards Board issued SFAS No. 112,
Employers' Accounting for Postemployment Benefits, which established standards
of accounting for the cost of benefits provided former or inactive employees
before they retire. The Company's accounting practices already complied with
the new standard in all material aspects; therefore, no cumulative effect of a
change in accounting principle was required upon adoption in 1993.
NOTE C--ACQUISITION OF MINORITY SHAREHOLDERS' OWNERSHIP OF OCEAN DRILLING &
EXPLORATION COMPANY (ODECO) -- On June 3, 1991, Murphy offered shareholders of
ODECO (at that time a 61-percent owned subsidiary) .55 share of Murphy Common
Stock for each share of ODECO Common Stock outstanding that was not then owned
by Murphy. Required shares of ODECO Common Stock were tendered, and a short-form
merger was completed under Delaware law, with ODECO, later renamed Murphy
Exploration & Production Company, becoming a wholly owned subsidiary of Murphy.
A total of 11,032,956 shares of Murphy Common Stock were issued in the exchange.
The acquisition was accounted for by Murphy using the purchase method. Cost of
the acquisition that exceeded the book value of net tangible assets acquired was
allocated to those properties up to their fair values at the date of
acquisition.
38
Unallocated amounts that exceeded fair values of the assets and estimated
expenses of consolidating the organizations were written off (Write-off) by a
charge against income of $85,644,000, $83,944,000 net of tax. The following pro
forma information reflects results of operations for the year 1991 as though the
acquisition had occurred at January 1, 1991 excluding the Write-off.
- - - --------------------------------------------------
(Thousands of dollars, except per share amounts)
- - - --------------------------------------------------
PRO FORMA 1991
- - - --------------------------------------------------
Revenues.............................. $ 1,690,086
Income from continuing operations..... 68,416
Net income............................ 62,007
Per Common share
Income from continuing operations... 1.52
Net income.......................... 1.38
Average Common shares outstanding..... 44,996,612
==================================================
NOTE D -- DISCONTINUED OPERATIONS -- Effective January 1, 1992, the Company sold
its contract drilling business for $372,127,000 in cash and reported a net gain
in 1992 of $23,855,000 from disposal of these operations. As a result of the
sale, contract drilling activities have been accounted for as discontinued
operations and are presented as net amounts in the Consolidated Statements of
Income. Selected operating results in 1991 for the contract drilling business
included revenues of $189,051,000, income tax provisions totaling $2,885,000,
and a loss from operations, net of minority interest, of $1,550,000.
NOTE E -- MENTOR LIQUIDATION -- In January 1992, ODECO settled litigation
related to its discontinued casualty insurance operations that were primarily
conducted by a Bermuda subsidiary, Mentor Insurance Limited (Mentor), which is
in liquidation. As a part of the settlement, all Mentor-related litigation was
dismissed, and ODECO paid $500,000 to the Mentor estate. In settlement of
separate litigation with certain banks, ODECO had previously recorded a
$100,000,000 loss in 1987 relating to letters of credit issued by such banks on
Mentor's behalf. In 1991, the Company included $10,544,000 in "Interest and
Other Revenues," primarily representing a reduction of the loss recorded in
1987.
NOTE F -- INVENTORIES -- Inventories valued at cost under the LIFO method
totaled $89,721,000 at December 31, 1993 and $77,607,000 at December 31, 1992.
These amounts were $46,255,000 and $78,005,000, respectively, less than such
inventories would have been valued using the FIFO method.
The Company has entered into crude oil price swap agreements to reduce exposure
to changes in the cost of 3,500,000 barrels of the Company's 1996 and 1997 crude
oil requirements for U.S. refineries. Any gains anticipated under these
agreements will be deferred, with the cost of the related crude oil being
adjusted when the agreements are settled. Any losses will similarly be deferred
unless at any time prior to settlement the estimated realizable value of
products is less than the cost of products produced from crude, as adjusted for
the effect of these agreements.
NOTE G -- PROPERTY, PLANT, AND EQUIPMENT
- - - ------------------------------------------------------------------------------------------------------
1993 INVESTMENT Investment
(Thousands of dollars) ADDITIONS DECEMBER 31, 1993 December 31, 1992
- - - ------------------------------------------------------------------------------------------------------
COST % COST NET % Cost Net %
- - - ------------------------------------------------------------------------------------------------------
Exploration and production..... $503,018 83 2,858,996 1,075,655* 70 2,350,687 659,231* 62
Refining....................... 66,364 11 484,043 221,455 14 419,297 175,881 16
Marketing...................... 16,941 3 140,478 94,558 6 129,347 85,477 8
Transportation................. 3,580 - 61,708 34,082 2 58,899 33,751 3
Farm, timber, and real estate.. 9,674 2 158,740 107,834 7 153,865 105,067 10
Corporate and other............ 4,034 1 26,017 15,666 1 25,572 13,772 1
- - - ------------------------------------------------------------------------------------------------------
$603,611 100 3,729,982 1,549,250 100 3,137,667 1,073,179 100
======================================================================================================
*Includes $18,021 in 1993 and $22,959 in 1992 related to administrative assets
and support equipment.
Exploration and production additions in 1993 include expenditures for acquiring
and/or developing an 11.26-percent interest in U.K. North Sea Block 16/17,
$166,807,000; a 6.5-percent interest in the Hibernia oil field, offshore
Newfoundland, $38,438,000; and a five-percent interest in the Syncrude project
in northern Alberta, $109,005,000, of which $67,370,000 was financed by assuming
directly related liabilities.
Capital leases, consisting of a fluid catalytic cracking unit in the U.K. and
other refinery assets, were as follows at December 31, 1993 and 1992.
- - - ---------------------------------------------------
(Thousands of dollars) 1993 1992
- - - ---------------------------------------------------
Property, plant, and equipment.. $ 57,748 58,838
Accumulated amortization........ (34,701) (32,515)
- - - ---------------------------------------------------
$ 23,047 26,323
===================================================
39
Long-term obligations on the lease of the fluid catalytic cracking unit have
been paid. Future rental commitments on this equipment are not material.
The Company also 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 $274,000,000 at December
31, 1993. This includes $102,000,000 applicable to the Hibernia oil field, most
of which will be financed with additional nonrecourse debt.
NOTE H -- FINANCING ARRANGEMENTS -- At December 31, 1993, Murphy Oil Corporation
and certain wholly owned subsidiaries had lines of credit with banks for short-
term borrowings at prime or various cost of funds rate options for $90,000,000
plus Cdn $28,000,000 (US $21,151,000 equivalent at December 31, 1993 currency
exchange rate). At year-end, no amounts were borrowed under these agreements.
These lines may be withdrawn by the banks at any time.
Certain wholly owned subsidiaries have a credit facility available until
February 15, 1995, which provides for borrowings of U.S. and/or Canadian dollars
up to an aggregate or equivalent of US $100,000,000 (Cdn $132,380,000 at
December 31, 1993 currency exchange rate). The Company has options under the
facility to select interest rates based on Canadian dollar prime rate or various
cost of funds options. At December 31, 1993, US $27,100,000 was outstanding
under this facility and classified as long-term nonrecourse debt of a
subsidiary. (See Note I to the consolidated financial statements.)
Murphy Oil Corporation and certain wholly owned subsidiaries have a revolving
and term loan agreement that provides for borrowings of U.S. and/or Canadian
dollars up to an aggregate or equivalent of US $125,000,000, with the Canadian
dollar component limited to Cdn $70,000,000. The agreement commenced April 1,
1992 and is comprised of a seven-year revolving period and a two-year term
period. Commitment fees are due on the undrawn balance. The Company has options
under the agreement to select interest rates based on certain banks' prime rates
or various costs of funds options. At December 31, 1993, no amount was
outstanding under this agreement.
Murphy Oil Corporation and certain wholly owned subsidiaries also have a short-
term facility agreement that provides for borrowings of U.S. and/or Canadian
dollars up to an aggregate or equivalent of US $25,000,000 (Cdn $33,095,000 at
December 31, 1993 currency exchange rate). The facility, which may be renewed,
is scheduled to expire March 28, 1994. Facility fees are due on the entire
amount. The Company has options under the agreement to select interest rates
based on certain costs of funds options offered by the lending bank. At December
31, 1993, no amount was borrowed under this agreement.
NOTE I -- LONG-TERM OBLIGATIONS
- - - --------------------------------------------------------------------------------------------
(Thousands of dollars)
- - - --------------------------------------------------------------------------------------------
December 31 1993 1992
- - - --------------------------------------------------------------------------------------------
Notes payable
Note payable to bank, 10.1%, due 2004................................ $ 20,000 20,000
Note payable to bank, face value of $3,333 at 7%,
discounted to a 10% effective rate, due 1994........................ 3,257 6,429
Other notes due 1994--2000........................................... 99 501
- - - --------------------------------------------------------------------------------------------
Subtotal........................................................... 23,356 26,930
- - - --------------------------------------------------------------------------------------------
Capitalized lease obligations due 1994--2022, 6% and 8%................ 1,658 1,661
- - - --------------------------------------------------------------------------------------------
Nonrecourse debt of a subsidiary
Guaranteed credit facility with bank, 3.75% to 3.875%, due 1995...... 27,100 --
Promissory note, 6.25%, due 1994--1998, payable in Canadian dollars.. 67,963 --
- - - --------------------------------------------------------------------------------------------
Subtotal 95,063 --
- - - --------------------------------------------------------------------------------------------
Total.............................................................. 120,077 28,591
Current maturities..................................................... (10,859) (3,662)
- - - --------------------------------------------------------------------------------------------
Total long-term obligations $109,218 24,929
============================================================================================
Amounts becoming due for the four years after 1994 are: 1995, $7,565,000; 1996,
$10,587,000; 1997, $13,610,000; and 1998, $28,696,000.
The nonrecourse guaranteed credit facility was incurred to finance 1993
expenditures for the Hibernia oil field, in which the Company owns a 6.5-percent
interest. In connection with this acquisition, the government of Canada has
provided, subject to certain conditions and limitations, an unconditional
40
guarantee of repayment of amounts drawn under the facility to lenders possessing
Participation Certificates issued by the guarantee's trustee. The Company's
maximum eligible borrowing available under the guarantee is Cdn $154,885,000 (US
$117,000,000 at December 31, 1993 currency exchange rate). The Company also
received other commitments from the Canadian government, including grants and
additional guarantees and loans. The amount guaranteed declines on a quarterly
basis 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. The guaranteed credit facility is not
reflected in the amounts becoming due in 1995, since the Company intends to
refinance the debt.
Along with a cash payment, the 6.25-percent promissory note of Cdn $89,970,000
(US $67,963,000 at December 31, 1993 currency exchange rate), payable to the
province of Alberta, was used to acquire a five-percent interest in the Syncrude
project in northern Alberta. As collateral for the note, Murphy gave the
province a debenture, which mortgages the acquired assets and the Company's
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. After year-end, the Company entered into forward foreign
exchange contracts with matching amounts and maturities to purchase Canadian
dollars payable under terms of the note.
NOTE J -- INCOME AND OTHER TAXES -- As discussed in Note B to the consolidated
financial statements, the Company adopted SFAS No. 109, Accounting for Income
Taxes, effective January 1, 1993 without restating prior years.
Total income tax expense for the year ended December 31, 1993 was $38,329,000.
This amount included $46,829,000 allocated to income from continuing operations,
partially offset by a benefit of $8,500,000 allocated to the cumulative effect
of a change in accounting for postretirement benefits.
Income tax expense (benefit) attributable to income from continuing operations
included the following.
- - - -------------------------------------------------------------------------------------------------------------------
(Thousands of dollars) 1993 1992 1991
- - - -------------------------------------------------------------------------------------------------------------------
Federal -- Current................................................................. $29,941* 17,213 6,717
Deferred................................................................ 97 (6,565) (5,619)
Noncurrent.............................................................. 4,977 (15,282) 15,487
Charge equivalent to income tax benefit
of net operating loss carryforward..................................... -- 18,949 --
- - - -------------------------------------------------------------------------------------------------------------------
35,015 14,315 16,585
- - - -------------------------------------------------------------------------------------------------------------------
State -- Current................................................................ 5,368 4,703 7,016
Noncurrent............................................................. -- -- 81
- - - -------------------------------------------------------------------------------------------------------------------
5,368 4,703 7,097
- - - -------------------------------------------------------------------------------------------------------------------
Foreign -- Current................................................................ (32,029) (12,561) 8,109
Deferred............................................................... 28,154 (6,363) (9,013)
Noncurrent............................................................. 10,321 6,470 14,379
- - - -------------------------------------------------------------------------------------------------------------------
6,446 (12,454) 13,475
- - - -------------------------------------------------------------------------------------------------------------------
$46,829 6,564 37,157
===================================================================================================================
*Net of benefits of $8,079 for net operating loss carryforward and $5,757 for
alternative minimum tax credit.
Noncurrent taxes relate to petroleum revenue taxes payable to the U.K.
government ($26,034,000 and $16,236,000 at December 31, 1993 and 1992 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 attributable to income
from continuing operations for the year ended December 31, 1993 were as follows.
41
- - - --------------------------------------------------------------------------------------
(Thousands of dollars) 1993
- - - --------------------------------------------------------------------------------------
Deferred tax expense (exclusive of the effects of components listed below on
January 1, 1993 deferred tax assets and liabilities)......................... $18,270
Adjustments for enacted changes in tax laws and rates......................... 190
Estimated net operating loss and tax credit carryforwards used or adjusted.... 9,791
- - - ---------------------------------------------------------------------------------------
Total deferred tax expense $28,251
=======================================================================================
Prior to adoption of SFAS No. 109, deferred income taxes (benefits) resulted
from recognizing income and expenses in different financial and tax reporting
periods. Timing differences and the tax effect of each were as follows for the
years ended December 31, 1992 and 1991.
- - - --------------------------------------------------------------------
(Thousands of dollars) 1992 1991
- - - --------------------------------------------------------------------
Unremitted earnings of foreign subsidiaries and
other companies not permanently invested........ $ (827) (2,432)
Depreciation..................................... 1,018 1,164
Intangible development costs..................... (580) (1,789)
Petroleum revenue tax............................ (1,827) (4,354)
Product inventory valuation...................... (283) 3,055
Alternative minimum tax.......................... (9,078) (3,187)
Asset sales and writedowns....................... -- (7,860)
Other, net....................................... (1,351) 771
- - - --------------------------------------------------------------------
$(12,928) (14,632)
====================================================================
A reconciliation of the U.S. statutory income tax rates to the Company's
effective rates on income from continuing operations follows.
- - - -------------------------------------------------------------------------------------------------
1993 1992 1991
- - - -------------------------------------------------------------------------------------------------
U.S. statutory income tax rates............................................ 35% 34% 34%
Subsidiary acquisition costs written off................................... -- -- 88
Settlement of prior years' U.S. federal tax audits......................... -- (10) (39)
Foreign income (losses) subject to foreign taxes
at greater than U.S. statutory rates...................................... 7 (8) 5
State income taxes......................................................... 3 -- 16
Asset sales and write-downs................................................ -- -- 14
Amortization of fair value in excess of book value of properties acquired.. -- 7 11
Refund and settlement of foreign tax matters............................... (11) (15) --
Other, net................................................................. 1 1 (5)
- - - -------------------------------------------------------------------------------------------------
Effective income tax rates 35% 9% 124%
=================================================================================================
An analysis of the Company's deferred tax assets and deferred tax liabilities at
December 31, 1993 showing the tax effects of significant temporary differences
follows.
42
- - - ------------------------------------------------------------------
(Thousands of dollars) 1993
- - - ------------------------------------------------------------------
Deferred tax assets
Property and leasehold costs.......................... $ 58,673
Reserves for dismantlement costs and major repairs.... 51,305
Federal alternative minimum tax credit carryforward... 3,898
Postretirement and other employee benefits............ 16,290
Other deferred tax assets............................. 46,816
- - - ------------------------------------------------------------------
Total gross deferred tax assets..................... 176,982
Less valuation allowance.............................. (33,080)
- - - ------------------------------------------------------------------
Net deferred tax assets 143,902
- - - ------------------------------------------------------------------
Deferred tax liabilities
Property, plant, and equipment........................ (65,841)
Accumulated depreciation, depletion, and amortization. (151,483)
Other deferred tax liabilities........................ (25,887)
- - - ------------------------------------------------------------------
Total gross deferred tax liabilities (243,211)
- - - ------------------------------------------------------------------
Net deferred tax liabilities $ (99,309)
==================================================================
In management's judgment, the net deferred tax assets in the preceding table
will more likely than not be realized as reductions in future taxable income or
by utilizing available tax planning strategies. Uncertainties that may affect
the ultimate realization of these assets include the future levels of crude oil
and natural gas prices, product margins, operating costs, and tax rates. The
Company will periodically review the likelihood of realizing these assets and
adjust the valuation allowance as needed. The valuation allowance for deferred
tax assets of $33,080,000 at December 31, 1993, has increased $6,410,000 (the
same as the increase in certain deferred tax assets) from the amount determined
as of January 1, 1993. Any subsequently recognized tax benefits relating to
reductions in the valuation allowance will be reported as reductions of income
tax expense assuming no offsetting change in the deferred tax asset.
The Company had undistributed earnings in certain foreign subsidiaries of
$24,106,000 for which no deferred tax provision has been made because the
earnings are considered permanently invested. Determination of the unrecognized
tax liability on these earnings is not practicable. The amount of unrecognized
deferred tax liability on undistributed earnings of jointly owned companies in
the U.S. prior to January 1, 1993 is insignificant.
Income (loss) from continuing operations before income taxes and minority
interest was generated from U.S. and foreign sources as follows.
- - - ----------------------------------------------
(Thousands of dollars) 1993 1992 1991
- - - ----------------------------------------------
United States......... $84,563 60,105 (4,549)
Foreign............... 49,064 9,220 34,564
==============================================
Income taxes are levied on the Company by the U.S. and several foreign
countries. Because of differences in the tax structures of these countries, the
relationship between income reported each year in the preceding table and the
related U.S. and foreign income tax provisions is not meaningful.
Income tax returns are subject to audit by the Internal Revenue Service (IRS),
which is currently examining the years 1987 and 1988, and tax authorities of
other countries. In 1993, the Company recorded benefits to income of $14,409,000
from refund and settlement of U.K. income taxes. During 1992, the Company
settled the final issue with the IRS related to the year 1979, resulting in a
refund and a $21,500,000 benefit to income. Also during 1992, the Company
settled income tax matters in the U.K. and Gabon that resulted in recording
benefits to income of $12,186,000. In 1991, U.S. income tax refunds of
$34,500,000 were recorded in income and represented the settlement of various
issues from audits in prior years. A tentative settlement for the years 1981,
1982, 1983, 1984, and 1986 has been reached with the IRS subject to approval by
the Joint Committee on Taxation. Based on this tentative settlement, adequate
accruals have been made for all years.
At December 31, 1993, the Company had alternative minimum tax credit
carryforwards of $3,898,000 available to reduce future U.S. federal income
taxes, if any, over an indefinite period.
Taxes included in various costs and expenses on the Consolidated Statements of
Income are as follows.
-43-
- - - -------------------------------------------------------------------------------
(Thousands of dollars) 1993 1992 1991
- - - -------------------------------------------------------------------------------
Payroll......................................... $ 5,729 5,502 5,580
Property........................................ 8,124 7,732 7,222
Production/severance............................ 4,175 4,094 3,997
Other........................................... 3,604 1,959 1,808
- - - -------------------------------------------------------------------------------
Total charged to costs and expenses........... 21,632 19,287 18,607
Excise on petroleum products*................... 391,177 358,968 329,823
- - - -------------------------------------------------------------------------------
Total $412,809 378,255 348,430
===============================================================================
*Excluded from revenues and costs and expenses.
NOTE K -- STOCKHOLDERS' EQUITY -- A portion of the Company's operations is in
foreign currencies. Cumulative translation gains and losses are included as a
separate component of stockholders' equity as provided by SFAS No. 52, Foreign
Currency Translation. At December 31, 1993, components of the net cumulative
reduction of $1,514,000 were: a $14,112,000 reduction for Canadian dollars,
mostly offset by additions of $10,849,000 for pounds sterling, $1,657,000 for
Spanish pesetas, and $92,000 for Gabonese francs.
In 1992, stockholders adopted a Stock Incentive Plan that provides for annual
awards of shares of the Company's Common Stock to executives and other key
employees. The Executive Compensation Committee (Committee) is authorized to
grant: (1) stock options (nonqualified or incentive), (2) stock appreciation
rights (SAR), and (3) restricted stock awards. Total shares granted in a year
may not exceed .5 percent of shares issued and outstanding at the end of the
preceding year, and no more than 50 percent of the shares available each year
may be granted as incentive stock options or restricted stock. If a grantee
terminates for any reason other than normal retirement, total disability, or
death, any outstanding stock options and SAR are canceled. If termination
results from retirement, disability, or death, exercisable stock options and
SAR may be exercised for the next two years if within the overall term. Other
significant provisions of the Plan follow.
Stock options -- Option price for an incentive option is fair market value on
date of grant; for a nonqualified option, the Committee may establish a price
at no less than fair market on the date of grant. For each option, the Committee
fixes the term, not to exceed 10 years from date of grant, and determines the
earliest date the option may be exercised. Upon exercise, the grantee may pay
the option price by using cash, surrender of shares, or a combination.
SAR -- SAR may be granted in conjunction with or independent of stock options;
the Committee determines when SAR may be exercised and the price. When
exercised, the grantee is paid the excess of fair market value of SAR shares
exercised over the price set by the Committee. Upon exercise, rights under any
related stock option terminate, and if a stock option is exercised, any related
SAR terminate. Payment to the grantee may be made in cash, shares, or a
combination as determined by the Committee. No SAR were awarded in 1993 or 1992.
Restricted stock awards -- Shares are awarded contingent upon the Company's
achieving specific financial objectives at the end of a performance period. If
the objectives are achieved, the grantee receives full ownership. If achievement
is less than a threshold level, all shares are forfeited; if achievement is
between the threshold and objectives, a percentage of the shares is forfeited;
and if achievement is above objectives, additional shares may be awarded. The
grantee may vote and receive dividends on the shares during the performance
period and will be reimbursed by the Company for personal income tax liability
on the stock, within limitations. Shares are subject to transfer restrictions
and are forfeited if a grantee terminates during the performance period for any
reason other than normal retirement, death, or full disability. If a grantee
terminates for one of these reasons, vesting may occur at the end of the
performance period on a pro rata number of shares based on months employed
during the period. In 1992, 32,000 restricted shares were awarded. Subsequently,
4,489 shares have been forfeited, leaving 27,511 shares outstanding at
December 31, 1993.
Options for 137,517 shares were outstanding and exercisable at December 31, 1993
under two other Murphy stock option plans that have terminated. These options,
which will expire from 1994-2001 if not exercised, have an average exercise
price of $37.26. At the discretion of the Committee, grantees may surrender
these options for Common Stock or cash.
Changes in options outstanding under the Company's plans, excluding restricted
stock awards, were as follows.
44
- - - ---------------------------------------------------
Number Average
of Shares Price
- - - ---------------------------------------------------
Outstanding Jan. 1, 1991...... 165,441 $32.04
Granted....................... 89,500 37.88
Conversion of subsidiary's
options..................... 59,671 40.65
Exercised..................... (250) 25.50
Surrendered................... (9,037) 26.94
Expired....................... (6,950) 42.92
- - - ----------------------------------------
Outstanding Dec. 31, 1991..... 298,375 35.42
Granted....................... 115,750 35.94
Exercised..................... (800) 30.46
Surrendered................... (52,015) 29.82
Expired....................... (20,274) 45.25
- - - ----------------------------------------
Outstanding Dec. 31, 1992..... 341,036 35.87
Granted....................... 81,000 36.31
Surrendered................... (45,019) 29.58
- - - ----------------------------------------
Outstanding Dec. 31, 1993 377,017 36.72
========================================
Exercisable Dec. 31, 1993 137,517 37.26
========================================
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 $1,190,000 in 1993, $276,000 in 1992,
and $(374,000) in 1991.
Changes in treasury stock for each of the three years ended December 31, 1993
are summarized as follows.
- - - ---------------------------------------------------
Number
(Thousands of dollars) of Shares Amount
- - - ---------------------------------------------------
At January 1, 1991............ 3,845,845 $ 98,902
Purchased..................... 11 1
Exercised options for cash.... (250) (6)
Issued shares for
surrender of options........ (2,198) (57)
Issued shares to effect
exchange offer.............. (33,623) (865)
- - - ---------------------------------------------------
At December 31, 1991.......... 3,809,785 97,975
Purchased..................... 161,100 5,440
Exercised options for cash.... (800) (20)
Issued shares for
surrender of options........ (9,602) (249)
Awarded restricted stock,
net of forfeitures.......... (29,407) (756)
- - - ---------------------------------------------------
At December 31, 1992.......... 3,931,076 102,390
Purchased..................... 48,400 1,635
Issued shares for
surrender of options........ (13,741) (359)
Forfeited restricted stock.... 1,896 49
- - - ---------------------------------------------------
At December 31, 1993 3,967,631 $103,715
===================================================
NOTE L -- STOCKHOLDER RIGHTS PLAN -- The Company has a Stockholder Rights Plan,
which provides that each Common stockholder at the close of business on December
20, 1989 and each certificate issued thereafter will 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.
Rights will detach from the Common Stock and become exercisable following a
specified period of time, subject to extension (Distribution Date), after the
date of the first public announcement (Stock Acquisition Date) 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
(an Acquiring Person). After the Distribution Date, each holder of a Right
(excluding those Rights held by an Acquiring Person) will be entitled for each
Right to:
. Purchase from the Company for $130.00, subject to adjustment (Purchase
Price), .01 of a share of a new series of Participating Cumulative Preferred
Stock, par value $100.00 per share.
. Purchase at the then-current Purchase Price Common Stock of the Company
(in lieu of the new series of Preferred Stock) that has a value of twice the
then-current Purchase Price.
. Purchase at the then-current Purchase Price Common Stock of the other party
to a transaction that has a value of twice the then-current Purchase Price if
the Company is acquired in a merger or other business combination in which the
Company is not the surviving corporation or its Common Stock is changed into
or exchanged for other security or assets or sells more than 50 percent of its
assets or earning power.
Prior to the Distribution Date, the Board of Directors may redeem the Rights for
$.01 each, subject to adjustment. Alternatively, after an Acquiring Person
becomes the beneficial owner of at least 15 percent but less than 50 percent of
the Company's Common Stock, the Board of Directors may exchange all or part of
the Rights for shares of Common Stock at an exchange ratio, subject to
adjustment, of one share of Common Stock for each Right.
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. However, 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.
45
Other terms of the Rights are set forth in, and the foregoing description of the
Rights is qualified in its entirety by, the Rights Agreement between the Company
and Harris Trust Company of New York, as Rights Agent.
NOTE M -- FOREIGN CURRENCY TRANSACTIONS -- Net gains (losses) from foreign
currency transactions were $10,000 in 1993, $(214,000) in 1992, and $420,000 in
1991.
NOTE N -- 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 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.
Retirement expense (expense reduction) and its components for 1993, 1992, and
1991 are shown in the following table except for an expense reduction of
$4,524,000 in 1992 that relates to a U.S. Employee Plan and an expense of
$1,555,000 that relates to a Foreign Employee Plan. These amounts arose from
Plan curtailments and special termination benefits that occurred primarily upon
disposal of the contract drilling business segment. This net expense reduction
is included in the 1992 Consolidated Statement of Income under Discontinued
Operations as a component of "Gain on Disposal."
Special termination benefits were offered to eligible employees under the
provisions of certain U.S. retirement plans in 1993 and 1991. Based on employees
who accepted these benefits, actuarially determined costs were charged to
retirement expense.
- - - -----------------------------------------------------------------------------------
(Thousands of dollars) 1993 1992 1991
- - - -----------------------------------------------------------------------------------
U.S. employee plans
Service cost -- benefits earned during the year..... $ 3,780 4,422 5,239
Interest accrued on benefits earned in prior years.. 10,295 9,995 9,399
Actual return on plan assets........................ (8,564) (15,996) (23,034)
Net amortization and deferral....................... (6,402) (1,659) 9,909
- - - ------------------------------------------------------------------------------------
Retirement expense (expense reduction)*............ (891) (3,238) 1,513
Special termination benefits........................ 1,316 -- 681
Curtailment gain.................................... -- (1,091) --
- - - ------------------------------------------------------------------------------------
Net retirement expense (expense reduction) $ 425 (4,329) 2,194
====================================================================================
*Major assumptions were discount rates of 7.00% in 1993 and 7.25% in 1992 and
1991 and long-term rates of return on plan assets of 8.50% in 1993 and 9.00% in
1992 and 1991.
- - - ------------------------------------------------------------------------------------
(Thousands of dollars) 1993 1992 1991
- - - ------------------------------------------------------------------------------------
Foreign employee plans
Service cost -- benefits earned during the year..... $ 1,478 2,174 2,207
Interest accrued on benefits earned in prior years.. 2,326 2,282 1,998
Actual return on plan assets........................ (4,466) (2,458) (5,875)
Net amortization and deferral....................... 1,463 (1,357) 2,492
- - - ------------------------------------------------------------------------------------
Net retirement expense* $ 801 641 822
====================================================================================
*Major assumptions were discount rates of 7.50%-8.50% in each year. Assumed
long-term rates of return on plan assets were 7.50%-8.50% in 1993 and 7.50%-
9.00% in 1992 and 1991.
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 foreign plans are based on local laws. Two
supplemental plans are unfunded, and projected benefit obligations exceeded
assets in two funded plans in 1993 and 1992. Projected benefit obligations in
excess of assets in these plans were $8,748,000 in 1993 and $7,338,000 in 1992;
these amounts have been netted against assets in the following table, which sets
forth the funded status of plans and amounts recognized in the Consolidated
Balance Sheets.
46
- - - ------------------------------------------------------------------------------------------------------------
United States Foreign
- - - ------------------------------------------------------------------------------------------------------------
(Thousands of dollars) 1993 1992 1993 1992
- - - ------------------------------------------------------------------------------------------------------------
Present value of accumulated benefits based on years of
service, applicable pay formula, and present pay levels
Vested........................................................ $130,872 116,020 27,428 23,338
Nonvested..................................................... 5,098 4,606 222 148
- - - ------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation(1)........................... 135,970 120,626 27,650 23,486
Provision for future pay increases.............................. 20,671 21,332 4,918 6,136
- - - ------------------------------------------------------------------------------------------------------------
Projected benefit obligation(1)............................. 156,641 141,958 32,568 29,622
Plan assets -- at market value(2).............................. 163,319 163,064 36,338 34,865
- - - ------------------------------------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation....... 6,678 21,106 3,770 5,243
Unrecognized net asset from transition to SFAS 87(3)............ (19,669) (21,915) (2,737) (6,856)
Unrecognized net loss (gain) from unfavorable
(favorable) actuarial experience............................... 24,846 12,730 (5,699) (1,774)
Unrecognized prior service cost................................. (130) (131) 2,892 2,278
- - - ------------------------------------------------------------------------------------------------------------
Prepaid (accrued) retirement cost........................... $ 11,725 11,790 (1,774) (1,109)
============================================================================================================
(1) Major assumptions were discount rates of 6.50%-7.50% in 1993 and 7.00%-8.50%
in 1992 and future pay rate increases of 5.00%-6.00% in 1993 and 5.00%-7.00%
in 1992.
(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 15 to 19.7 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 makes matching contributions at a stated percentage of
each employee's allotment based on length of participation in the plans.
Aggregate Company contributions to these plans for 1993, 1992, and 1991 were
$2,631,000, $2,502,000, and $2,996,000, respectively. Of the 1991 contribution,
$793,000 was allocated to discontinued operations.
Postretirement Benefits -- The Company sponsors plans that provide comprehensive
health care benefits (as a supplement to Medicare benefits for those eligible)
and life insurance benefits for most U.S. retired employees. Retirees contribute
the same amounts to the self-funded cost of health care benefits as do active
employees, with the Company contributing the remainder. The Company pays
premiums for life insurance coverage, which is 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. No
postretirement benefits are provided by the Company for foreign employees.
Under SFAS No. 106, which was adopted January 1, 1993, the Company's
postretirement expense in 1993 based on actuarial computations was $2,854,000;
cash payments totaled $1,411,000 in 1993. The cash costs of these benefits in
1992 and 1991 were $1,295,000 and $1,608,000; amounts were expensed when paid.
Components of the postretirement benefit expense for 1993 were as follows.
- - - ------------------------------------------------------------------------------------------------------------
Health Life
(Thousands of dollars) Care Insurance Total
- - - ------------------------------------------------------------------------------------------------------------
Service cost -- benefits earned during year................................. $ 581 23 604
Interest cost -- on accumulated postretirement benefit obligations.......... 1,989 261 2,250
- - - ------------------------------------------------------------------------------------------------------------
Postretirement benefit expense $2,570 284 2,854
============================================================================================================
The following table summarizes the accrued obligation recorded in the
Consolidated Balance Sheet at December 31, 1993, and classified as "Deferred
Credits and Other Liabilities." Calculation of the amount of accumulated
unfunded postretirement benefit obligations (APBO) was based on a 7.25-percent
discount rate.
47
- - - ----------------------------------------------------------------------------------------------------------
Health Life
(Thousands of dollars) Care Insurance Total
- - - ----------------------------------------------------------------------------------------------------------
APBO
Retirees.............................................................. $14,229 2,857 17,086
Fully eligible active participants.................................... 3,095 361 3,456
Other active participants............................................. 13,115 586 13,701
- - - ----------------------------------------------------------------------------------------------------------
Total unfunded APBO................................................. 30,439 3,804 34,243
Unrecognized obligations resulting from change in discount rate........ (7,183) (772) (7,955)
- - - ----------------------------------------------------------------------------------------------------------
Accrued APBO obligations $23,256 3,032 26,288
==========================================================================================================
For measurement purposes, health care inflation cost for 1993 was determined
assuming an annual increase of 12 percent, gradually decreasing to a rate of six
percent in 2003 and thereafter. An increase of one percent in the assumed health
care cost trend in each year would increase the postretirement benefit expense
by 12.8 percent and the APBO at December 31, 1993 by 16.8 percent.
NOTE O -- INCENTIVE COMPENSATION PLAN -- In 1992, the Board of Directors adopted
an Incentive Compensation Plan that provides for annual cash awards to officers,
directors, and key employees based on actual results for the year compared to
measurable financial performance objectives established at the beginning of each
year. The Plan is administered by the Executive Compensation Committee.
Provisions of $1,732,000 and $1,500,000 were recorded in 1993 and 1992 in
anticipation of future awards. A provision of $623,000 was recorded in 1991
under terms of a previous management incentive plan.
NOTE P -- FAIR VALUE OF FINANCIAL INSTRUMENTS -- 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.
- - - - Cash and cash equivalents, trade receivables, short-term debt, and trade
payables -- The carrying amounts approximate fair value because of the short
maturity of these instruments.
- - - - Investments and noncurrent receivables -- Of the total reported, disclosure of
fair value is not required on $29,733,000 of insurance receivables or on
$3,002,000 of investments carried on an equity basis. The carrying amount of
the remainder approximates fair value.
- - - - Long-term obligations including current maturities -- The fair value is
estimated based on current rates offered to the Company for debt of the same
remaining maturities.
- - - - Foreign currency contracts -- The fair value is estimated from quotes obtained
from brokers.
- - - - Financial guarantees and letters of credit -- The fair value is based on the
estimated cost to terminate or otherwise settle these obligations with the
counterparties.
- - - - Crude oil price swaps -- The fair value is estimated from quotes for
offsetting agreements with the same maturities.
Following is a summary of the estimated fair value at December 31, 1993 and 1992
of the Company's financial instruments other than those on which the carrying
amount approximates fair value.
- - - ----------------------------------------------------------------------------------------------------------------
1993 1992
- - - ----------------------------------------------------------------------------------------------------------------
Carrying Notional Estimated Carrying Notional Estimated
(Thousands of dollars) Amount Amount Fair Value Amount Amount Fair Value
- - - ----------------------------------------------------------------------------------------------------------------
Long-term obligations including
current maturities................ $120,077 125,172 28,591 31,693
Foreign currency contracts......... -- 2,639 2,639 -- 6,750 6,596
Financial guarantees and letters
of credit......................... -- 83,888 83,888 -- 92,494 92,494
Crude oil price swaps.............. -- 2,400 2,400 -- -- --
================================================================================================================
48
NOTE Q -- CONCENTRATION OF CREDIT RISK -- The Company's cash equivalents consist
primarily of U.S. Treasury Bills and securities issued by certain foreign
governments. Trade accounts receivable balances arise primarily from sales of
crude oil, natural gas, and petroleum products to a large number of customers
who are geographically dispersed. 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 including foreign currency contracts, financial guarantees, letters
of credit, and crude oil price swaps; 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, 1993, the Company had no
significant concentration of credit risk.
NOTE R -- SUPPLEMENTAL CASH FLOWS DISCLOSURES -- Cash income taxes paid, net of
refunds, were $14,802,000, $(20,347,000), and $85,996,000 in 1993, 1992, and
1991. Interest paid, net of amounts capitalized, was $12,158,000, $14,714,000,
and $19,856,000 in 1993, 1992, and 1991.
Noncash investing and financing activities excluded from the Consolidated
Statements of Cash Flows were:
1993 -- Assumption of $67,370,000 of nonrecourse debt upon acquisition of a
five-percent interest in the Syncrude project.
1991 -- Issuance of Common Stock in exchange for Common Stock of a subsidiary
held by minority interests, $385,796,000, and a reduction of $10,545,000
previously shown as a long-term obligation as the result of settling
litigation regarding an insurance subsidiary.
(Increases) decreases in noncash operating working capital for each of the three
years ended December 31, 1993 were as follows.
- - - -----------------------------------------------------------------------------------------
(Thousands of dollars) 1993 1992 1991
- - - -----------------------------------------------------------------------------------------
Accounts receivable........................... $ 45,183 48,865 31,520
Inventories................................... (15,166) (17,107) 8,126
Prepaid expenses.............................. 7,467 (23,813) (4,853)
Deferred income taxes......................... (18,497) -- --
Accounts payable and accrued liabilities...... (5,922) (41,409) (92,409)
Current income tax liability.................. (12,647) 2,547 (38,820)
- - - -----------------------------------------------------------------------------------------
$ 418 (30,917) (96,436)
=========================================================================================
NOTE S -- 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, shareholders, 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 which such actions may take, or the effect such actions may
have on the Company.
DOE Matters -- On February 19, 1987, the U.S. Department of Energy (DOE)
published a Proposed Remedial Order (PRO) alleging that the Company received
approximately $13,367,000 for crude oil and/or related transportation charges in
excess of amounts allowed under DOE regulations that were in effect from
September 1973 through January 1981. The PRO sought restitution of this amount,
plus interest of approximately $24,522,000 calculated to the date of the PRO.
On June 17, 1992, DOE's Office of Hearings and Appeals sustained the allegations
of the PRO in their entirety and issued the Company a Remedial Order. The
Company filed a Notice of Appeal to issuance of the Remedial Order and contested
the material allegations in an appeal proceeding before the Federal Energy
Regulatory Commission (FERC). On January 24, 1994, the presiding FERC
49
administrative law judge issued a Decision and Proposed Order, which sustained
the position of the Company on most of the material allegations in the
proceeding. The record of the entire proceeding has been certified to the FERC,
which will review the Decision and Proposed Order and affirm, reverse, or modify
it. If the FERC should reverse the decision of its presiding administrative law
judge, the Company will continue to vigorously defend its position on these
issues. Under any circumstances, the Company believes that adequate accruals
have been made.
Environmental Matters -- The Company's environmental contingencies are reviewed
in Management's Discussion and Analysis under the section entitled
"Environmental Obligations" on page 30.
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, 1993, letters of credit outstanding amounted to
$68,059,000. Contingent liability under a guaranty and pipeline throughput
agreement was $15,829,000 at December 31, 1993.
NOTE T -- BUSINESS SEGMENTS -- Information about business segments and
geographic operations is summarized in the following tables. Companies accounted
for by the equity method are primarily engaged in the transportation of crude
oil and petroleum products. Intracompany and affiliated company transfers are at
market prices.
- - - -----------------------------------------------------------------------------------------
(Thousands of dollars) 1993 1992 1991
- - - -----------------------------------------------------------------------------------------
Revenues for the year
Petroleum
Exploration and production
United States................................. $ 248,180 213,865 193,183
Canada....................................... 70,507 59,998 55,463
United Kingdom............................... 53,567 56,548 68,358
Other international.......................... 17,186 28,267 40,247
- - - -----------------------------------------------------------------------------------------
389,440 358,678 357,251
- - - -----------------------------------------------------------------------------------------
Refining, marketing, and transportation
United States................................ 940,990 968,398 937,269
Canada....................................... 29,444 29,237 22,683
Western Europe............................... 272,699 285,978 329,550
- - - -----------------------------------------------------------------------------------------
1,243,133 1,283,613 1,289,502
- - - -----------------------------------------------------------------------------------------
1,632,573 1,642,291 1,646,753
Intrasegment transfers elimination............. (65,041) (69,660) (85,182)
- - - -----------------------------------------------------------------------------------------
Total petroleum............................ 1,567,532 1,572,631 1,561,571
Farm, timber, and real estate -- United States..... 69,136 58,810 46,982
Income from equity companies....................... 973 2,180 1,174
Corporate and other................................ 33,496 51,794 80,359
- - - -----------------------------------------------------------------------------------------
$1,671,137 1,685,415 1,690,086
=========================================================================================
50
- - - ----------------------------------------------------------------------------------------------------
(Thousands of dollars) 1993(1) 1992(2) 1991
- - - ----------------------------------------------------------------------------------------------------
Operating income (loss) for the year
Petroleum........................................................... $ 91,682 27,752 65,317
Farm, timber, and real estate....................................... 20,813 12,624 7,293
Income from equity companies........................................ 973 2,180 1,174
Corporate and other................................................. 22,359 41,594 (15,759)
- - - ----------------------------------------------------------------------------------------------------
135,827 84,150 58,025
- - - ----------------------------------------------------------------------------------------------------
Deductions from (additions to) operating income
Interest expense--net............................................... 2,200 14,825 28,010
Income taxes........................................................ 46,829 6,564 37,157
Minority interest................................................... -- -- 2,465
(Gain) loss from discontinued operations, net of minority interest
and income taxes.................................................. -- (23,855) 1,550
Extraordinary item.................................................. -- (18,949) --
Cumulative effect of changes in accounting principles............... (15,338) -- --
- - - ----------------------------------------------------------------------------------------------------
33,691 (21,415) 69,182
- - - ----------------------------------------------------------------------------------------------------
Net income (loss) for the year
Petroleum
Exploration and production
United States................................................... 32,701 42,044 16,026
Canada.......................................................... 6,304 1,181 (20,708)
United Kingdom.................................................. 17,931 1,692 1,778
Other international............................................. (5,666) (1,676) (2,117)
- - - ----------------------------------------------------------------------------------------------------
51,270 43,241 (5,021)
- - - ----------------------------------------------------------------------------------------------------
Refining, marketing, and transportation
United States................................................... 7,246 (11,954) 20,924
Canada.......................................................... 8,628 9,377 6,835
Western Europe.................................................. 11,625 1,895 15,585
- - - ----------------------------------------------------------------------------------------------------
27,499 (682) 43,344
- - - ----------------------------------------------------------------------------------------------------
Total petroleum............................................... 78,769 42,559 38,323
Farm, timber, and real estate--United States........................ 13,154 8,362 4,790
Corporate and other................................................. (5,125) 30,789 (52,720)
- - - ----------------------------------------------------------------------------------------------------
Income (loss) from continuing operations...................... 86,798 81,710 (9,607)
Gain (loss) from discontinued operations............................ -- 23,855 (1,550)
Cumulative effect of changes in accounting principles............... 15,338 -- --
- - - ----------------------------------------------------------------------------------------------------
$102,136 105,565 (11,157)
====================================================================================================
(1) As set forth in Note B to the consolidated financial statements, the effect
on operating income of the petroleum segment from adoption of SFAS No. 109,
Accounting for Income Taxes, was a reduction of $10,916, while the adoption
of SFAS No. 106, Employers' Accounting for Postretirement Benefits Other
Than Pensions, had no significant effect on operating income.
(2) The tax benefit of utilizing a financial net operating loss carryforward of
$18,949 in 1992, reported in the Consolidated Statement of Income as an
extraordinary item, is allocated to the applicable segments in the net
income (loss) summary.
51
- - - --------------------------------------------------------------------------------------------
(Thousands of dollars) 1993 1992 1991
- - - --------------------------------------------------------------------------------------------
Assets at year-end
Petroleum
Exploration and production
United States....................................... $ 461,087 426,231 402,699
Canada.............................................. 343,880 162,888 184,159
United Kingdom...................................... 306,248 133,499 120,201
Other international................................. 111,903 66,876 84,233
- - - --------------------------------------------------------------------------------------------
1,223,118 789,494 791,292
- - - --------------------------------------------------------------------------------------------
Refining, marketing, and transportation
United States....................................... 378,405 346,151 337,070
Canada.............................................. 63,353 67,599 51,450
Western Europe...................................... 147,444 161,311 164,664
- - - --------------------------------------------------------------------------------------------
589,202 575,061 553,184
- - - --------------------------------------------------------------------------------------------
Total petroleum................................... 1,812,320 1,364,555 1,344,476
Farm, timber, and real estate--United States............ 150,261 141,784 134,590
Corporate and other..................................... 206,278 430,175 357,984
Net investment in discontinued operations............... -- -- 337,576
- - - --------------------------------------------------------------------------------------------
$2,168,859 1,936,514 2,174,626
============================================================================================
Additions to property, plant, and equipment for the year
Petroleum
Exploration and production
United States....................................... $ 71,883 56,038 72,264
Canada.............................................. 172,838 15,988 11,203
United Kingdom...................................... 190,269 33,037 24,202
Other international................................. 68,028 10,233 9,089
- - - --------------------------------------------------------------------------------------------
503,018 115,296 116,758
- - - --------------------------------------------------------------------------------------------
Refining, marketing, and transportation
United States....................................... 71,363 44,198 41,753
Canada.............................................. 3,474 6,225 3,376
Western Europe...................................... 12,048 17,650 18,014
- - - --------------------------------------------------------------------------------------------
86,885 68,073 63,143
- - - --------------------------------------------------------------------------------------------
Total petroleum................................... 589,903 183,369 179,901
Farm, timber, and real estate--United States.......... 9,674 6,017 2,858
Corporate and other..................................... 4,034 1,477 2,203
- - - --------------------------------------------------------------------------------------------
$ 603,611 190,863 184,962
============================================================================================
52
- - - --------------------------------------------------------------------------------------------
(Thousands of dollars) 1993 1992 1991
- - - --------------------------------------------------------------------------------------------
Depreciation, depletion, and amortization expense for the year
Petroleum
Exploration and production*
United States................................................ $ 97,196 81,935 80,591
Canada....................................................... 21,062 19,058 43,582
United Kingdom............................................... 18,276 20,294 18,150
Other international.......................................... 4,651 8,409 17,294
- - - --------------------------------------------------------------------------------------------
141,185 129,696 159,617
- - - --------------------------------------------------------------------------------------------
Refining, marketing, and transportation
United States................................................ 20,144 20,741 17,722
Canada....................................................... 1,466 1,298 1,212
Western Europe............................................... 8,562 8,503 7,529
- - - --------------------------------------------------------------------------------------------
30,172 30,542 26,463
- - - --------------------------------------------------------------------------------------------
Total petroleum............................................ 171,357 160,238 186,080
Farm, timber, and real estate -- United States................. 3,488 3,152 3,221
Corporate and other............................................ 1,368 1,432 3,818
- - - --------------------------------------------------------------------------------------------
$176,213 164,822 193,119
============================================================================================
*Includes amounts related to write-down of oil and gas properties in 1991 and
excludes undeveloped lease amortization in all years.
53
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 as a
result of making additional investments by drilling new wells on acreage
offsetting productive units, recompleting existing wells, and/or installing
facilities to collect and transport volumes produced.
Crude oil and natural gas liquids reserves reported at December 31, 1993 under
the heading "Other" are located in Spain and Gabon. 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 .9 billion cubic feet in 1993, .7
billion cubic feet in 1992, and 4.5 billion cubic feet in 1991.
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 2018 of 183,500 barrels a day. Proved reserves will change if the future
average production rate varies from the current estimated rate, which is based
on the actual rate in 1993, or the operating permit is extended beyond 2018.
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 (1993 and 1992) 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 extensive 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 1993 used for this calculation
were $12.53 a barrel for the United States, $11.04 for Canadian light, $6.90 for
Canadian heavy, $9.63 for Hibernia, $12.93 for the United Kingdom, $7.71 for
Ecuador, and $12.33 for Other. Average natural gas prices were $2.43 an MCF for
the United States, $1.49 for Canada, $2.37 for the United Kingdom, and $2.24 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, 1993.
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 should be considered in conjunction with the Company's
overall performance.
54
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, 1991.................. 23.9 24.6 18.8 -- .3 67.6 -- 67.6
Revisions of previous estimates.. .6 .4 (1.3) -- 1.0 .7 -- .7
Purchase of minerals in place.... .1 -- -- -- -- .1 -- .1
Extensions, discoveries, and
other additions................. 3.1 .2 -- 33.5 -- 36.8 -- 36.8
Production....................... (4.9) (3.4) (2.8) -- (1.1) (12.2) -- (12.2)
- - - -----------------------------------------------------------------------------------------------------------
DECEMBER 31, 1991................ 22.8 21.8 14.7 33.5 .2 93.0 -- 93.0
Revisions of previous estimates.. 1.9 1.7 .7 2.1 2.1 8.5 -- 8.5
Purchases of minerals in place... 1.5 .2 -- -- -- 1.7 -- 1.7
Extensions, discoveries, and
other additions................ 1.9 2.5 -- -- -- 4.4 -- 4.4
Production....................... (4.9) (3.7) (2.3) -- (.5) (11.4) -- (11.4)
Sales of minerals in place....... -- (.2) -- -- -- (.2) -- (.2)
- - - -----------------------------------------------------------------------------------------------------------
DECEMBER 31, 1992................ 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
===========================================================================================================
PROVED DEVELOPED
January 1, 1991.................. 17.4 24.5 16.9 -- .2 59.0 -- 59.0
December 31, 1991................ 16.9 21.8 13.0 -- .2 51.9 -- 51.9
December 31, 1992................ 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
===========================================================================================================
*Excludes 18.7 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: NET HYDROCARBONS PRODUCTION]
55
SCHEDULE 2 -- ESTIMATED NET PROVED GAS RESERVES
- - - ------------------------------------------------------------------------------------------
United United
(Billions of cubic feet) States Canada Kingdom Spain Total
- - - ------------------------------------------------------------------------------------------
PROVED
JANUARY 1, 1991............................... 378.5 201.6 40.9 32.6 653.6
Revisions of previous estimates............... 4.2 11.3 3.6 (7.9) 11.2
Purchase of minerals in place................. 10.0 -- -- -- 10.0
Extensions, discoveries, and other additions.. 63.1 1.4 -- -- 64.5
Production.................................... (59.6) (9.4) (3.4) (8.1) (80.5)
- - - ------------------------------------------------------------------------------------------
DECEMBER 31, 1991............................. 396.2 204.9 41.1 16.6 658.8
Revisions of previous estimates............... 11.4 1.2 (1.0) (5.4) 6.2
Purchases of minerals in place................ 91.9 3.4 -- -- 95.3
Extensions, discoveries, and other additions.. 15.4 8.9 -- -- 24.3
Production.................................... (69.5) (11.1) (4.7) (7.1) (92.4)
Sales of minerals in place.................... -- (6.9) -- -- (6.9)
- - - -------------------------------------------------------------------------------------------
DECEMBER 31, 1992............................. 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
===========================================================================================
PROVED DEVELOPED
January 1, 1991............................... 213.4 142.5 24.1 24.3 404.3
December 31, 1991............................. 230.5 172.5 25.5 16.6 445.1
December 31, 1992............................. 217.0 164.0 32.3 4.1 417.4
DECEMBER 31, 1993............................. 239.1 158.0 28.1 10.6 435.8
===========================================================================================
SCHEDULE 3 -- CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
---------------------------------------------------------------------------------------------------------------
Synthetic
United United Sub- Oil--
(Millions of dollars) States Canada Kingdom Ecuador Other total Canada Total
- - - -----------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1993
Unproved oil and gas
properties................... $ 92.3 29.1 13.5 -- 11.0 145.9 -- 145.9
Proved oil and gas properties.. 1,377.9 457.1(1) 541.3 96.7 94.4 2,567.4 109.9 2,677.3
- - - -----------------------------------------------------------------------------------------------------------------
Gross capitalized costs.... 1,470.2 486.2 554.8 96.7 105.4 2,713.3 109.9 2,823.2
Accumulated depreciation,
depletion, and amortization
Unproved oil and gas
properties............... (50.6) (15.8) (.7) -- (5.9) (73.0) -- (73.0)
Proved oil and gas
properties(2)............ (1,069.8) (246.6) (284.4) -- (91.8) (1,692.6) -- (1,692.6)
- - - -----------------------------------------------------------------------------------------------------------------
Net capitalized costs.... $ 349.8 223.8 269.7 96.7 7.7 947.7 109.9 1,057.6
==================================================================================================================
DECEMBER 31, 1992
Unproved oil and gas
properties.................. $ 88.2 30.7 10.6 -- 11.4 140.9 -- 140.9
Proved oil and gas properties.. 1,298.9 363.2 363.8 27.5 114.9 2,168.3 -- 2,168.3
- - - -----------------------------------------------------------------------------------------------------------------
Gross capitalized costs.... 1,387.1 393.9 374.4 27.5 126.3 2,309.2 -- 2,309.2
Accumulated depreciation,
depletion, and amortization
Unproved oil and gas
properties.............. (45.9) (17.0) (1.8) -- (5.2) (69.9) -- (69.9)
Proved oil and gas
properties(2)......... (1,009.1) (224.9) (274.1) -- (94.9) (1,603.0) -- (1,603.0)
- - - ------------------------------------------------------------------------------------------------------------------
Net capitalized costs... $ 332.1 152.0 98.5 27.5 26.2 636.3 -- 636.3
==================================================================================================================
(1) Includes Hibernia oil field, $37.4.
(2) Does not include reserve for dismantlement costs of $123.1 in 1993 and
$112.7 in 1992.
56
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, 1993
FUTURE CASH INFLOWS...................... $1,284.2 617.2 410.5 220.1 49.1 2,581.1
FUTURE PRODUCTION AND DEVELOPMENT COSTS.. (505.7) (466.4) (248.0) (220.1) (49.0) (1,489.2)
FUTURE INCOME TAXES...................... (217.5) (67.9) -- (3.0) -- (288.4)
- - - -------------------------------------------------------------------------------------------------------
FUTURE NET CASH FLOWS.................. 561.0 82.9 162.5 (3.0) .1 803.5
10% ANNUAL DISCOUNT FOR ESTIMATED
TIMING OF CASH FLOWS................... (184.4) (59.3) (18.3) (16.4) 4.2 (274.2)
- - - -------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS................ $ 376.6 23.6 144.2 (19.4) 4.3 529.3
=======================================================================================================
DECEMBER 31, 1992
Future cash inflows...................... $1,377.8 554.3 296.4 428.0 38.0 2,694.5
Future production and development costs.. (549.4) (284.2) (197.3) (288.1) (45.1) (1,364.1)
Future income taxes...................... (235.5) (97.4) (28.8) (29.2) -- (390.9)
- - - -------------------------------------------------------------------------------------------------------
Future net cash flows.................. 592.9 172.7 70.3 110.7 (7.1) 939.5
10% annual discount for estimated
timing of cash flows................... (212.5) (64.4) (16.5) (85.9) 4.4 (374.9)
- - - -------------------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows................ $ 380.4 108.3 53.8 24.8 (2.7) 564.6
=======================================================================================================
Following are the principal sources of change in the standardized measure of
discounted future net cash flows for the years shown.
- - - ---------------------------------------------------------------------------------------------------
(Millions of dollars) 1993 1992 1991
- - - ---------------------------------------------------------------------------------------------------
Net changes in prices and costs....................................... $(203.6) 106.0 (612.1)
Sales and transfers of oil and gas produced, net of production costs.. (167.0) (186.3) (151.9)
Net change due to extensions, discoveries, and improved recovery...... 47.8 30.8 72.7
Net change due to purchases and sales of minerals in place............ 26.5 100.0 8.6
Development costs incurred during the period.......................... 150.6 58.7 52.7
Accretion of discount................................................. 82.2 60.2 115.5
Revisions of previous quantity estimates and other.................... (25.6) 50.2 (38.6)
Net change in income taxes............................................ 53.8 (92.1) 256.6
- - - ---------------------------------------------------------------------------------------------------
Net increase (decrease)........................................... (35.3) 127.5 (296.5)
Standardized measure at January 1..................................... 564.6 437.1 733.6
- - - ---------------------------------------------------------------------------------------------------
Standardized measure at December 31................................... $529.3 564.6 437.1
==================================================================================================
(1) Excludes future net cash flows from synthetic oil.
(2) Excludes future net cash flows attributable to 18.7 million barrels of crude
oil to be added to proved reserves subsequent to start-up of production
from the Hibernia oil field.
57
SCHEDULE 5 -- COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION,
AND DEVELOPMENT ACTIVITIES
- - - -------------------------------------------------------------------------------------------------
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 42.9 67.7 -- 212.7 -- 212.7
- - - -------------------------------------------------------------------------------------------------
Total capital expenditures. 92.9 68.8 192.2 67.7 6.4 428.0 109.0 537.0
- - - -------------------------------------------------------------------------------------------------
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 63.8 190.2 67.7 .4 394.0 109.0 503.0
=================================================================================================
- - - -------------------------------------------------------------------------------------------------------------------------
1992 1991
- - - -------------------------------------------------------------------------------------------------------------------------
United United
United King- Ecua- United King- Ecua-
(Millions of dollars) States Canada dom dor Other Total States Canada dom dor Other Total
- - - -------------------------------------------------------------------------------------------------------------------------
Property acquisition costs
Unproved..................... 2.1 2.4 -- -- 3.5 8.0 22.0 1.7 -- -- -- 23.7
Proved....................... 12.5 1.4 -- -- -- 13.9 .3 -- -- -- -- .3
- - - -------------------------------------------------------------------------------------------------------------------------
Total acquisition costs.... 14.6 3.8 -- -- 3.5 21.9 22.3 1.7 -- -- -- 24.0
Exploration costs.............. 44.5 7.6 16.5 .1 10.7 79.4 45.1 7.4 15.1 -- 10.7 78.3
Development costs.............. 13.8 10.4 28.0 5.7 .8 58.7 17.3 8.3 22.2 4.0 .9 52.7
- - - -------------------------------------------------------------------------------------------------------------------------
Total capital expenditures. 72.9 21.8 44.5 5.8 15.0 160.0 84.7 17.4 37.3 4.0 11.6 155.0
- - - -------------------------------------------------------------------------------------------------------------------------
Charged to expense
Dry hole expense............. 11.3 2.7 8.6 -- 7.3 29.9 6.9 2.7 9.4 -- 2.3 21.3
Geophysical and other costs.. 5.6 3.1 2.9 .1 3.1 14.8 5.6 3.5 3.6 -- 4.2 16.9
- - - -------------------------------------------------------------------------------------------------------------------------
Total charged to expense... 16.9 5.8 11.5 .1 10.4 44.7 12.5 6.2 13.0 -- 6.5 38.2
- - - -------------------------------------------------------------------------------------------------------------------------
Expenditures capitalized....... 56.0 16.0 33.0 5.7 4.6 115.3 72.2 11.2 24.3 4.0 5.1 116.8
=========================================================================================================================
58
SCHEDULE 6 -- RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
- - - -------------------------------------------------------------------------------------------
1993
- - - -------------------------------------------------------------------------------------------
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 -- -- -- -- 65.1 -- 65.1
Sales to unaffiliated
enterprises............ 16.6 54.1 38.4 -- 8.0 117.1 -- 117.1
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
Settlement of windfall
profit tax dispute...... -- -- -- -- -- -- -- --
Other.................... .7 -- 4.2 -- -- 4.9 -- 4.9
- - - -------------------------------------------------------------------------------------------
Total revenues......... 248.2 70.5 53.6 -- 17.2 389.5 -- 389.5
- - - -------------------------------------------------------------------------------------------
Costs and deductions
Production costs......... 58.1 25.4 21.2 -- 9.7 114.4 -- 114.4
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 18.3 -- 4.6 141.2 -- 141.2
Write-down of certain
properties.............. -- -- -- -- -- -- -- --
Minority interest and
other deductions.......... 9.2 4.8 3.3 .1 1.7 19.1 -- 19.1
- - - -------------------------------------------------------------------------------------------
Total costs and
deductions............ 194.4 58.8 44.8 .1 22.7 320.8 -- 320.8
- - - -------------------------------------------------------------------------------------------
53.8 11.7 8.8 (.1) (5.5) 68.7 -- 68.7
Income tax provision
(benefit)................. 21.1 5.4 (9.1) -- -- 17.4 -- 17.4
- - - -------------------------------------------------------------------------------------------
Results of operations*..... $ 32.7 6.3 17.9 (.1) (5.5) 51.3 -- 51.3
===========================================================================================
- - - --------------------------------------------------------------------------------------------------------------------------
1992 1991
- - - --------------------------------------------------------------------------------------------------------------------------
United United
United King- Ecua- United King- Ecua-
(Millions of dollars) States Canada dom dor Other Total States Canada dom dor Other Total
- - - --------------------------------------------------------------------------------------------------------------------------
Revenues
Crude oil and natural gas
liquids
Transfers to
consolidated
operations............. 62.6 -- 7.1 -- -- 69.7 70.5 -- 14.7 -- -- 85.2
Sales to unaffiliated
enterprises............ 28.3 48.8 33.9 -- 10.0 121.0 24.2 44.9 41.9 -- 17.0 128.0
Natural gas.............. 122.0 11.2 13.4 -- 18.3 164.9 89.8 10.6 10.2 -- 23.2 133.8
- - - --------------------------------------------------------------------------------------------------------------------------
Total oil and gas
revenues.............. 212.9 60.0 54.4 -- 28.3 355.6 184.5 55.5 66.8 -- 40.2 347.0
Settlement of windfall
profit tax dispute...... -- -- -- -- -- -- 7.6 -- -- -- -- 7.6
Other.................... 1.0 -- 2.1 -- -- 3.1 1.1 -- 1.6 -- -- 2.7
- - - --------------------------------------------------------------------------------------------------------------------------
Total revenues......... 213.9 60.0 56.5 -- 28.3 358.7 193.2 55.5 68.4 -- 40.2 357.3
- - - --------------------------------------------------------------------------------------------------------------------------
Costs and deductions
Production costs......... 49.1 23.3 25.8 -- 11.8 110.0 48.1 24.5 24.7 -- 8.9 106.2
Exploration expenses..... 16.9 5.8 11.5 .1 10.4 44.7 12.5 6.2 13.0 -- 6.5 38.2
Undeveloped lease
amortization............ 10.3 3.8 -- -- 3.3 17.4 9.8 4.1 -- -- .2 14.1
Depreciation, depletion,
and amortization........ 81.9 19.1 20.3 -- 8.4 129.7 62.3 18.4 18.2 -- 17.2 116.1
Write-down of certain
properties.............. -- -- -- -- -- -- 18.3 25.2 -- -- -- 43.5
Minority interest and
other deductions.......... 13.5 5.1 5.1 .1 8.7 32.5 20.4 6.9 3.3 -- 2.4 33.0
- - - --------------------------------------------------------------------------------------------------------------------------
Total costs and
deductions............ 171.7 57.1 62.7 .2 42.6 334.3 171.4 85.3 59.2 -- 35.2 351.1
- - - --------------------------------------------------------------------------------------------------------------------------
42.2 2.9 (6.2) (.2) (14.3) 24.4 21.8 (29.8) 9.2 -- 5.0 6.2
Income tax provision
(benefit)................. .2 1.7 (7.9) -- (12.8) (18.8) 5.8 (9.1) 7.4 -- 7.1 11.2
- - - --------------------------------------------------------------------------------------------------------------------------
Results of operations*..... 42.0 1.2 1.7 (.2) (1.5) 43.2 16.0 (20.7) 1.8 -- (2.1) (5.0)
==========================================================================================================================
*Excludes corporate overhead and interest.
59
STATISTICAL SUMMARY
[CAPTION]
- - - -----------------------------------------------------------------------------------------------------
1993 1992 1991 1990 1989
- - - -----------------------------------------------------------------------------------------------------
EXPLORATION AND PRODUCTION
Net crude oil and condensate production --
barrels a day
United States...................................... 12,864 12,586 12,565 12,490 14,026
Canada -- light oil................................ 4,546 3,972 4,305 4,674 4,658
heavy oil................................ 7,449 5,366 4,744 4,921 4,319
United Kingdom..................................... 6,342 5,931 7,607 12,324 15,668
Other international................................ 1,550 1,350 2,985 3,063 3,830
Net natural gas liquids production -- barrels a day
United States...................................... 863 768 761 959 876
Canada............................................. 697 847 368 336 211
United Kingdom..................................... -- -- 160 271 464
- - - -----------------------------------------------------------------------------------------------------
Total 34,311 30,820 33,495 39,038 44,052
=====================================================================================================
Net natural gas sold -- MCF a day
United States..................................... 215,471 188,068 151,157 195,017 178,514
Canada............................................ 36,792 30,328 25,679 25,598 25,683
United Kingdom.................................... 13,074 12,802 9,354 3,716 --
Spain............................................. 9,571 19,402 22,207 22,977 27,776
- - - -----------------------------------------------------------------------------------------------------
Total 274,908 250,600 208,397 247,308 231,973
=====================================================================================================
Total hydrocarbons produced -- equivalent
barrels(1) a day 80,129 72,587 68,228 80,256 82,714
- - - -----------------------------------------------------------------------------------------------------
Weighted average sales prices(2)
Crude oil and condensate -- dollars a barrel
United States.................................... $16.60 18.85 19.80 22.85 18.40
Canada(3) -- light oil........................... 15.01 16.69 17.47 21.41 16.98
heavy oil............................. 9.84 11.02 9.09 14.56 11.82
United Kingdom................................... 16.63 18.86 19.86 21.50 18.22
Other international.............................. 14.14 18.85 16.57 17.70 15.94
Natural gas liquids -- dollars a barrel
United States.................................... 13.36 14.71 15.65 15.32 10.97
Canada(3)........................................ 9.59 9.74 13.91 13.39 9.23
United Kingdom................................... -- -- 15.35 13.86 8.85
Natural gas -- dollars an MCF
United States.................................... 2.10 1.75 1.62 1.81 1.81
Canada(3)........................................ 1.22 1.01 1.12 1.24 1.17
United Kingdom(3)................................ 2.31 2.86 3.00 2.94 --
Spain(3)......................................... 2.64 2.58 2.87 3.05 2.61
- - - -----------------------------------------------------------------------------------------------------
Net wells completed
Oil wells -- United States........................ 3.0 4.9 5.7 8.0 3.8
Canada............................... 24.3 19.1 10.0 5.6 12.4
United Kingdom....................... .8 .3 .4 .5 .4
Other international.................. 1.2 -- -- -- .2
Gas wells -- United States........................ 8.5 5.1 9.4 10.7 9.2
Canada............................... 4.1 2.4 1.4 10.6 1.7
United Kingdom....................... -- .5 .2 .4 .2
Other international.................. -- -- .3 -- --
Dry holes -- United States........................ 6.5 5.2 5.9 10.5 8.3
Canada............................... 6.9 2.6 6.9 6.2 4.6
United Kingdom....................... .1 1.0 1.1 .5 .4
Other international.................. .5 1.0 .3 -- 1.1
- - - -----------------------------------------------------------------------------------------------------
Total 55.9 42.1 41.6 53.0 42.3
=====================================================================================================
Net undeveloped acreage(4) -- thousands of acres 9,306 8,389 10,114 9,935 9,789
- - - -----------------------------------------------------------------------------------------------------
(1)Natural gas converted on an energy equivalent basis of 6:1.
(2)Includes intracompany and affiliated company transfers at market prices.
(3)U.S. dollar equivalent.
(4)At December 31.
60
- - - -------------------------------------------------------------------------------------------------------------
1993 1992 1991 1990 1989
- - - -------------------------------------------------------------------------------------------------------------
REFINING
Crude capacity* of Company refineries --
barrels per stream day................................ 167,400 167,400 167,400 167,400 147,400
- - - -------------------------------------------------------------------------------------------------------------
Inputs/yields at Company refineries -- barrels a day
Crude -- Meraux, Louisiana........................... 78,732 80,842 75,059 74,962 70,204
Superior, Wisconsin......................... 30,358 26,207 26,916 26,350 26,483
Milford Haven, Wales........................ 27,991 24,245 25,969 22,628 25,594
Other feedstocks..................................... 10,350 12,857 11,310 13,243 11,959
- - - -------------------------------------------------------------------------------------------------------------
Total inputs 147,431 144,151 139,254 137,183 134,240
=============================================================================================================
Gasoline............................................. 66,460 67,710 60,491 62,469 64,629
Kerosine............................................. 16,024 13,338 15,662 15,885 15,824
Diesel and home heating oils......................... 34,356 32,848 32,055 30,462 28,749
Residuals............................................ 16,441 18,474 17,237 16,155 13,596
Asphalt, LPG, and other.............................. 9,627 7,133 9,838 8,258 7,330
Fuel and loss........................................ 4,523 4,648 3,971 3,954 4,112
- - - -------------------------------------------------------------------------------------------------------------
Total yields 147,431 144,151 139,254 137,183 134,240
=============================================================================================================
Average cost of crude inputs to Company
refineries -- dollars a barrel
United States........................................ $16.81 18.93 19.72 23.60 18.77
United Kingdom....................................... 17.44 19.84 20.74 24.06 18.71
- - - -------------------------------------------------------------------------------------------------------------
MARKETING
Products sold -- barrels a day
United States -- Gasoline............................ 61,577 59,128 50,075 52,922 53,636
Kerosine............................ 11,682 10,855 12,156 12,964 12,775
Diesel and home heating oils........ 29,252 26,446 24,626 23,838 22,204
Residuals........................... 11,812 12,339 11,926 10,823 9,208
Asphalt, LPG, and other............. 6,519 5,611 5,228 6,021 5,809
- - - -------------------------------------------------------------------------------------------------------------
120,842 114,379 104,011 106,568 103,632
- - - -------------------------------------------------------------------------------------------------------------
Western Europe -- Gasoline........................... 13,270 13,549 13,030 11,546 13,385
Kerosine........................... 4,660 2,724 3,147 2,989 2,772
Diesel and home heating oils....... 7,525 7,112 7,593 6,262 6,833
Residuals.......................... 5,068 6,245 5,383 6,075 4,419
LPG and other...................... 1,996 1,861 4,213 3,422 2,305
- - - -------------------------------------------------------------------------------------------------------------
32,519 31,491 33,366 30,294 29,714
- - - -------------------------------------------------------------------------------------------------------------
Canada 234 172 129 76 39
- - - -------------------------------------------------------------------------------------------------------------
Total products sold 153,595 146,042 137,506 136,938 133,385
=============================================================================================================
Average gross margin on products sold --
dollars a barrel
United States........................................ $ .82 .48 1.59 1.49 1.59
Western Europe....................................... 3.08 2.67 3.52 3.72 2.78
- - - -------------------------------------------------------------------------------------------------------------
Branded retail outlets*
United States........................................ 606 643 622 643 644
Canada............................................... 8 7 6 4 2
United Kingdom....................................... 428 391 370 345 326
- - - -------------------------------------------------------------------------------------------------------------
TRANSPORTATION
Pipeline throughputs of crude --
barrels a day -- Canada 151,722 118,050 90,660 62,844 62,492
- - - -------------------------------------------------------------------------------------------------------------
*At December 31.
61
- - - ------------------------------------------------------------------------------------------------------------
1993 1992 1991 1990 1989
- - - ------------------------------------------------------------------------------------------------------------
FARM, TIMBER, AND REAL ESTATE
Acres owned(1) -- Farmland.......................... 36,000 36,000 36,000 36,000 36,000
Timberland........................ 341,000 342,000 341,000 341,000 344,000
Real estate....................... 10,000 10,000 10,000 10,000 7,000
- - - ------------------------------------------------------------------------------------------------------------
Acres harvested
Cotton............................................. 4,839 4,518 4,099 2,919 1,672
Soybeans........................................... 14,863 12,798 15,584 14,993 12,169
Wheat.............................................. 1,482 1,209 6,391 7,889 6,171
Corn............................................... 3,717 4,586 4,162 4,313 4,195
Rice............................................... 330 622 1,019 1,499 1,186
- - - ------------------------------------------------------------------------------------------------------------
Yields per acre
Cotton -- pounds................................... 661 831 969 908 671
Soybeans -- bushels................................ 24 39 30 23 25
Wheat -- bushels................................... 40 59 21 36 29
Corn -- bushels.................................... 70 118 87 114 82
Rice -- bushels.................................... 107 107 112 107 115
- - - ------------------------------------------------------------------------------------------------------------
Estimated standing pine timber inventories(1)
Sawtimber -- thousand board
feet -- Doyle scale (MBF-DS)...................... 810,162 805,260 766,130 729,473 773,741
Pulpwood -- cords.................................. 962,563 940,477 988,790 972,089 1,002,330
- - - ------------------------------------------------------------------------------------------------------------
Company-owned pine timber harvested
Average sawtimber price(2) -- $ per MBF-DS......... $ 310 274 202 211 166
Sawtimber -- MBF-DS................................ 37,635 30,177 32,956 44,595 39,221
Pulpwood -- cords.................................. 12,536 8,767 15,038 10,004 21,654
- - - ------------------------------------------------------------------------------------------------------------
Sawmills
Production
Finished lumber -- thousand board feet (MBF)..... 112,365 101,203 92,846 108,209 90,190
Pine chips -- tons............................... 193,618 236,180 229,105 368,631 332,165
Annual capacity(1) -- MBF..........................122,600 100,100 100,100 120,600 120,600
Sales of finished lumber
Thousand board feet (MBF)........................ 115,136 105,619 95,024 108,204 92,279
Average price -- $ per MBF....................... $ 335 259 215 209 209
Average margin -- $ per MBF...................... 82 34 13 2 9
- - - ------------------------------------------------------------------------------------------------------------
Real estate
Residential lots sold.............................. 147 120 98 53 28
Average price -- $ per lot....................... $ 48,200 53,200 49,700 74,000 92,500
Commercial acres sold.............................. -- -- 17 11 --
Average price -- $ per acre...................... $ -- -- 32,700 37,000 --
- - - ------------------------------------------------------------------------------------------------------------
STOCKHOLDER AND EMPLOYEE DATA
Common shares outstanding(1) (thousands)............. 44,808 44,844 44,966 33,897 33,887
Number of stockholders of record(1).................... 5,265 6,522 5,826 4,584 4,953
Number of employees(1)................................. 1,803 1,787 3,991 4,029 4,538
Average number of employees.......................... 1,787 1,857 4,001 4,213 4,428
Salaries, wages, and benefits (thousands)............ $ 90,734 92,486 166,883 158,009 157,044
- - - ------------------------------------------------------------------------------------------------------------
(1) At December 31.
(2) Includes intracompany transfers at market prices.
62
DIRECTORS
C. H. MURPHY JR. (1)
Chairman
Murphy Oil Corporation
El Dorado, Arkansas
Director since 1950
JACK W. McNUTT (1)
President and Chief Executive Officer
Murphy Oil Corporation
El Dorado, Arkansas
Director since 1981
B. R. R. BUTLER (3,4)
Managing Director, Retired
The British Petroleum Company p.l.c.
Holbeton, Devon, England
Director since 1991
CLAIBORNE P. DEMING (1)
Executive Vice President and Chief Operating Officer
Murphy Oil Corporation
El Dorado, Arkansas
Director since 1993
JOHN W. DEMING (3,4)
Physician, Retired
Alexandria, Louisiana
Director since 1950
H. RODES HART (2,3,4)
Chairman and Chief Executive Officer
Franklin Industries, Inc.
Nashville, Tennessee
Director since 1975
VESTER T. HUGHES JR. (2,3,4)
Partner
Hughes & Luce
Dallas, Texas
Director since 1973
MICHAEL W. MURPHY (1,2,3,4)
President
Marmik Oil Company
El Dorado, Arkansas
Director since 1977
R. MADISON MURPHY (1)
Executive Vice President and Chief Financial and Administrative Officer
Murphy Oil Corporation
El Dorado, Arkansas
Director since 1993
WILLIAM C. NOLAN JR. (1,2,3,4)
Partner
Nolan and Alderson
El Dorado, Arkansas
Director since 1977
CAROLINE G. THEUS (2,3,4)
President
Inglewood Land and Development Company
Alexandria, Louisiana
Director since 1985
LORNE C. WEBSTER (2,3,4)
Chairman and Chief Executive Officer
Prenor Group Ltd.
Montreal, Quebec, Canada
Director since 1989
DIRECTORS EMERITI
GEORGE S. ISHIYAMA
WILLIAM C. NOLAN
Members of Board Committees
(1) Executive Committee.
(2) Audit Committee chaired by Mr. Hughes.
(3) Executive Compensation Committee chaired by Dr. Deming.
(4) Nominating Committee chaired by Dr. Deming.
OFFICERS
C. H. MURPHY JR.
Chairman
JACK W. McNUTT
President and Chief Executive Officer
CLAIBORNE P. DEMING
Executive Vice President and Chief Operating Officer
R. MADISON MURPHY
Executive Vice President and Chief Financial and Administrative Officer
STEVEN A. COSSE
Vice President and General Counsel
ODIE F. VAUGHAN
Treasurer
RONALD W. HERMAN
Controller
W. BAYLESS ROWE
Secretary
63
PRINCIPAL SUBSIDIARIES
MURPHY OIL USA, INC.
200 Peach Street
P. O. Box 7000
El Dorado, Arkansas 71731-7000
(501) 862-6411
Engaged in refining, marketing, and transporting of petroleum products
in the United States.
HERBERT A. FOX JR.
President
STEVEN A. COSSE
Vice President and
General Counsel
ODIE F. VAUGHAN
Treasurer
RONALD W. HERMAN
Controller
W. BAYLESS ROWE
Secretary
MURPHY OIL COMPANY LTD.
2100--555--4th Avenue S.W.
P. O. Box 2721, Station M
Calgary, Alberta T2P 3Y3
Canada
(403) 294-8000
Engaged in crude oil and natural gas exploration and production; purchasing,
transporting, and reselling of crude oil; and marketing of petroleum products
in Canada.
G. CARL THOMPSON
President and Chief
Executive Officer
R. D. URQUHART
Vice President, Supply and
Transportation
W. GILL COLVIN
Controller
ROBERT A. LEHODEY
Secretary
ODIE F. VAUGHAN
Treasurer
MURPHY EASTERN OIL COMPANY
Winston House, Dollis Park,
Finchley
London N3 1HZ, England
081-349-9191
Provides technical and professional services to certain of Murphy Oil
Corporation's subsidiaries engaged in crude oil and natural gas exploration and
production in the Eastern Hemisphere and refining, marketing, and transporting
of petroleum products in Western Europe.
GERALD MCAULLY
President
JAMES N. COPELAND
Vice President, Legal and
Personnel
ODIE F. VAUGHAN
Treasurer
W. BAYLESS ROWE
Secretary
DELTIC FARM & TIMBER CO., INC.
200 Peach Street
P. O. Box 7000
El Dorado, Arkansas 71731-7000
(501) 862-6411
Engaged in farming, timber and land management, lumber manufacturing
and marketing, and real estate development in the United States.
RON L. PEARCE
President
ODIE F. VAUGHAN
Vice President and Treasurer
EMILY R. EVERS
Controller
JAMES E. BAINE
Secretary
MURPHY EXPLORATION &
PRODUCTION COMPANY
131 South Robertson Street
P. O. Box 61780
New Orleans, Louisiana 70161
(504) 561-2811
Engaged worldwide in crude oil and natural gas exploration and production.
ENOCH L. DAWKINS
President
CLEFTON D. VAUGHAN
Vice President
STEPHEN C. HURLEY
Vice President, Oil and Gas
Exploration
G. L. GILREATH
Vice President, Administration
STEVEN A. COSSE
Vice President, General Counsel,
and Secretary
ODIE F. VAUGHAN
Vice President and Treasurer
BOBBY R. CAMPBELL
Controller
64
CORPORATE INFORMATION
CORPORATE OFFICES
200 Peach Street
P. O. Box 7000
El Dorado, Arkansas 71731-7000
(501) 862-6411
STOCK EXCHANGE LISTINGS
Trading Symbol: MUR
New York Stock Exchange
The Toronto Stock Exchange
TRANSFER AGENTS
Harris Trust Company of New York
77 Water Street
New York, New York 10005
Montreal Trust Company of Canada
151 Front Street West
Toronto, Ontario M5J 2N1
REGISTRAR
Harris Trust Company of New York
77 Water Street
New York, New York 10005
ANNUAL MEETING
The annual meeting of the Company's
shareholders will be held at 10 A.M. on
May 11, 1994, at the South Arkansas Arts
Center, 110 East 5th Street, El Dorado,
Arkansas. A formal notice of the meeting,
together with a proxy statement and
proxy form, will be mailed to all share-
holders under separate cover.
FORM 10-K
A copy of the Company's Annual Report
on Form 10-K, filed with the Securities
and Exchange Commission, may be
obtained by writing to Murphy Oil
Corporation, Controller's Department,
P. O. Box 7000, El Dorado,
Arkansas 71731-7000.
INQUIRIES
Inquiries regarding shareholder account
matters should be addressed to the Secretary,
Murphy Oil Corporation, P. O. Box 7000,
El Dorado, Arkansas 71731-7000.
Members of the financial community
should direct their inquiries to Ronald
W. Herman, Controller, Murphy Oil
Corporation, P. O. Box 7000,
El Dorado, Arkansas 71731-7000,
(501) 862-6411.
Printed in U.S.A. on recycled paper. [RECYCLING LOGO]
Inside Back Cover
Appendix to Electronically Filed Exhibit 13
(1993 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 62 of Paper Format
Exhibit 13
Page No. Map Narrative
- - - ---------- -------------
5 Gulf of Mexico - The location 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 1993.
8 Canada - The location 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 type of production - natural gas, light oil, heavy
oil, and oil sands.
9 Hibernia - The location of the Hibernia oil field in the North Atlantic
east of Newfoundland, in which the Company holds an interest, is
shown along with the location onshore Newfoundland where the
production platform for this field is being constructed.
12 North Sea - The location and areal extent of producing and nonproducing
acreage under license by the Company, primarily in the U.K. North
Sea, is shown. Highlighted are a block where production began in
late 1993 and two blocks where production is anticipated to begin in
1998 or 1999.
13 Ecuador - Depicted are the areal extent of acreage in which the Company
has an interest in a risk-service contract for producing crude oil
reserves discovered in prior years (production is expected to
commence late in the first quarter of 1994), the location of support
facilities, and the route for moving the crude into an existing
transportation system. Also shown is adjoining acreage for which the
Company had bid with others to obtain a license.
16 United States - The locations of the Company's two refineries are
identified 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 market 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 the Southeast and upper-Midwest.
18 United Kingdom - The location of the Company's refinery is identified
along with a depiction of the route and means of moving crude oil to
the refinery, the routes and means of moving finished products from
the refinery into U.K. market areas, the terminal facilities used to
store and/or distribute products to wholesalers and consumers, and
the areal extent of the Company's marketing system.
Ex.13_A-1
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Map Narrative (Continued)
- - - ---------- -------------
20 Canada - Pipelines - The location of major crude oil pipelines in
southern Alberta and Saskatchewan are shown, including those that are
operated and partially or wholly owned by the Company. Further detail
is shown for Company-operated pipelines to indicate terminaling
points.
Picture Narrative
-----------------
6 In the Gulf of Mexico, offshore Louisiana, a new production platform is
shown being lifted from a barge for field installation. The platform
provides permanent replacement facilities for producing crude oil and
natural gas that were necessitated by destruction caused by Hurricane
Andrew in August 1992.
6 In the Gulf of Mexico, another production platform and related
equipment is shown being moved by barge to a new gas field. The
platform and equipment were salvaged from a depleted field.
7 A bucketwheel reclaimer is shown at work at the Syncrude project in
northern Alberta. This equipment scoops oil sands that have been
placed in windrows onto a conveyor system, which transports the sands
to a facility for further processing into light, sweet synthetic
crude oil.
9 An areal view is shown at Bull Arm, Newfoundland, of the work site and
progress made toward construction of a concrete Gravity Base
Structure, which when completed and towed to the field site will be
used to produce crude oil from the Hibernia oil field, offshore
Newfoundland.
10 A drilling rig is shown on location at Plover Lake, southwestern
Saskatchewan, as it horizontally drills a heavy oil well. This is
representative of the level of activity that caused the Company's
Canadian heavy oil production to increase 39 percent over the prior
year.
11 A gas compression module is shown onshore in the U.K. This module was
subsequently moved to the Ninian field in the U.K. North Sea and
installed on a production platform to allow development of nearby
marginally economic fields by utilizing (on a tariff basis accruing
to the Company and its Ninian partners) Ninian's existing
infrastructure.
14 Members of the Company's Board of Directors are shown observing
archaeological efforts to identify artifacts in Ecuador near oil
field development. The pipeline that will serve the development was
rerouted to preserve the site.
17 A distillate desulfurizer unit at the Meraux, Louisiana, refinery is
shown. This unit, which began operating in August 1993, can extract
sulfur from up to 27,500 barrels a day of diesel fuel.
Ex. 13_A-2
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Picture Narrative (Continued)
- - - ---------- -----------------
18 An employee of the Milford Haven, Wales, refinery is shown operating
valves that control product flow within a maze of pipelines.
Throughput volumes at the refinery set a new record for the year.
19 A recently acquired service station and convenience store is shown in
Wales, near the Milford Haven refinery. The Company's strategy is to
expand its sales in this area.
22 A view is shown looking across a golf course fairway and at adjacent
houses, illustrating one of the many amenities of living at the
Company's planned community in western Little Rock, Arkansas. Lot
sales set a new record for the year, spurred by the lowest interest
rate in more than 20 years.
22 Deltic's foresters are shown examining an increment core taken from a
pine tree on a Company-owned timber tract in southern Arkansas.
Examining the core helps determine the age and growth rate of the
timber.
22 Pine logs are shown at the Ola, Arkansas, sawmill after removal of bark
and just prior to being sawed into lumber by an upgraded system of
saws that was installed in early 1993 to significantly improve lumber
yields. This aided in meeting the high demand for lumber experienced
throughout the year.
Graph Narrative
---------------
4 INCOME CONTRIBUTION* - EXPLORATION AND PRODUCTION
Scale - 0 to 75 (millions of dollars).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Income* 53.0 66.3 23.4 35.9 36.9
===== ===== ===== ===== =====
*Before unusual or infrequently occurring items.
This is a vertical bar graph with each year's value printed above the
appropriate bar.
4 CAPITAL EXPENDITURES - EXPLORATION AND PRODUCTION
Scale - 0 to 600 (millions of dollars).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Proved Property Acquisitions
(top) 6.8 3.5 .3 13.9 259.7
Development Costs 63.3 54.2 52.7 58.7 212.7
Exploration Costs (bottom) 65.3 89.0 102.0 87.4 64.6
----- ----- ----- ----- -----
Totals 135.4 146.7 155.0 160.0 537.0
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's
total printed above the appropriate bar.
Ex. 13_A-3
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- - - ---------- ---------------
6 CRUDE OIL AND NGL PRODUCTION
Scale - 0 to 50 (thousands of barrels a day).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Other International (top) 3.8 3.1 3.0 1.3 1.6
United Kingdom 16.2 12.6 7.8 5.9 6.3
Canada 9.2 9.9 9.4 10.2 12.7
United States (bottom) 14.9 13.4 13.3 13.4 13.7
----- ----- ----- ----- -----
Totals 44.1 39.0 33.5 30.8 34.3
===== ===== ===== ===== =====
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).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Spain (top) 27.8 23.0 22.2 19.4 9.5
United Kingdom -- 3.7 9.3 12.8 13.1
Canada 25.7 25.6 25.7 30.3 36.8
United States (bottom) 178.5 195.0 151.2 188.1 215.5
----- ----- ----- ----- -----
Totals 232.0 247.3 208.4 250.6 274.9
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
15 INCOME CONTRIBUTION* -- REFINING, MARKETING, AND TRANSPORTATION
Scale - 0 to 50 (millions of dollars).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Income* 39.9 40.7 43.3 8.0 31.5
===== ===== ===== ===== =====
*Before unusual or infrequently occurring items.
This is a vertical bar graph with each year's value printed
above the appropriate bar.
15 CAPITAL EXPENDITURES -- REFINING, MARKETING, AND TRANSPORTATION
Scale - 0 to 100 (millions of dollars).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Transportation (top) 1.4 3.3 3.3 6.0 3.6
Marketing 12.4 24.9 15.2 14.1 16.9
Refining (bottom) 14.4 30.9 44.6 48.0 66.4
----- ----- ----- ----- -----
Totals 28.2 59.1 63.1 68.1 86.9
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
Ex. 13_A-4
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- - - ---------- ---------------
15 REFINED PRODUCTS SOLD
Scale 0 to 175 (thousands of barrels a day).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Western Europe (top) 29.7 30.3 33.4 31.5 32.5
United States (bottom) 103.7 106.6 104.1 114.5 121.1
----- ----- ----- ----- -----
Totals 133.4 136.9 137.5 146.0 153.6
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
16 MERAUX REFINERY CRUDE CHARGE
Scale 0 to 100 (percentages of total).
1991 1992 1993
----- ----- -----
Light Sour (top) 2.1 25.3 26.1
Heavy Sweet 29.3 23.5 29.0
Light Sweet (bottom) 68.6 51.2 44.9
----- ----- -----
Totals 100.0 100.0 100.0
===== ===== =====
This is a stacked vertical bar graph.
16 MERAUX REFINERY YIELDS
Scale 0 to 100 (percentages of total).
1991 1992 1993
----- ----- -----
Fuel and Other (top) 5.8 5.5 6.4
Residuals 12.8 13.3 11.7
Middle Distillates 36.1 31.6 33.6
Gasoline (bottom) 45.3 49.6 48.3
----- ----- -----
Totals 100.0 100.0 100.0
===== ===== =====
This is a stacked vertical bar graph.
20 CANADIAN PIPELINE THROUGHPUTS
Scale 0 to 175 (thousands of barrels a day).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Throughputs 62.5 62.8 90.7 118.1 151.7
===== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
21 INCOME CONTRIBUTION - FARM, TIMBER, AND REAL ESTATE
Scale 0 to 16 (millions of dollars).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Income--value plotted 3.30 6.16 4.79 8.36 13.15
===== ===== ===== ===== =====
--value printed 3.3 6.2 4.8 8.4 13.1
===== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
Ex. 13_A-5
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- - - ---------- ---------------
21 CAPITAL EXPENDITURES - FARM, TIMBER, AND REAL ESTATE
Scale 0 to 14 (millions of dollars).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Capital Expenditures --
value plotted 11.20 10.38 2.86 6.02 9.67
===== ===== ===== ===== =====
value printed 11.2 10.4 2.9 6.0 9.7
===== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed above the
appropriate bar.
21 SALES OF FINISHED LUMBER
Scale 0 to 140 (millions of board feet).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Lumber Sales 92.3 108.2 95.0 105.6 115.1
===== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed above the
appropriate bar.
23 INCOME EXCLUDING UNUSUAL ITEMS
Scale 0 to 120 (millions of dollars).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Income 78.8 96.1 57.7 54.9 76.4
===== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed above the
appropriate bar.
23 CASH PROVIDED BY CONTINUING OPERATIONS
Scale 0 to 420 (millions of dollars).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Cash Provided 303.7 284.4 213.6 284.2 363.0
===== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed above the
appropriate bar.
23 STOCKHOLDERS' EQUITY AT YEAR-END
Scale 0 to 1,400 (millions of dollars).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Stockholders' Equity 770 873 1,201 1,200 1,222
===== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed above the
appropriate bar.
Ex. 13_A-6
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- - - ---------- ---------------
24 INCOME CONTRIBUTION BY OPERATING FUNCTION*
Scale 0 to 100 (millions of dollars).
1991 1992 1993
---- ---- ----
Farm, Timber, and
Real Estate (top) 4.8 8.4 13.1
Refining, Marketing,
and Transportation 43.3 8.0 31.5
Exploration and
Production (bottom) 23.4 35.9 36.9
---- ---- ----
Totals 71.5 52.3 81.5
==== ==== ====
*Excludes Corporate and unusual or infrequently
occurring items.
This is a stacked vertical bar graph with the value for
each element printed within the element.
25 RANGE OF U.S. CRUDE OIL SALES PRICES
Scale 10 to 25 (dollars a barrel).
1991 1992 1993
---- ---- ----
High monthly crude oil
price (top of bar) 22.15 20.67 18.42
Average crude oil price
(colored line) 19.80 18.85 16.60
Low monthly crude oil
price (bottom of bar) 17.89 17.34 12.52
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.
25 RANGE OF U.S. NATURAL GAS SALES PRICES
Scale 1.00 to 2.75 (dollars a thousand cubic feet).
1991 1992 1993
---- ---- ----
High monthly natural gas
price (top of bar) 1.97 2.60 2.51
Average natural gas price
(colored line) 1.62 1.75 2.10
Low monthly natural gas
price (bottom of bar) 1.28 1.16 1.63
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.
26 EXPLORATION EXPENSES
Scale 0 to 70 (millions of dollars).
1991 1992 1993
---- ---- ----
Undeveloped Lease
Amortization (top) 14.1 17.4 12.1
Geological, Geophysical,
and Other Costs 16.9 14.8 12.5
Dry Hole Costs (bottom) 21.3 29.9 21.5
---- ---- ----
Totals 52.3 62.1 46.1
==== ==== ====
This is a stacked vertical bar graph with each year's
total printed above the appropriate bar.
Ex. 13_A-7
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- - - ---------- ---------------
27 AVERAGE SALES PRICE OF U.S. REFINED PRODUCTS
Scale 0 to 28 (dollars a barrel).
1991 1992 1993
----- ----- -----
Average Sales Price 24.84 23.25 21.44
===== ===== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
27 AVERAGE SAWMILL MARGIN
Scale 0 to 100 (dollars a thousand board feet).
1991 1992 1993
----- ----- -----
Average Margin 13 34 82
===== ===== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
27 SELLING AND GENERAL EXPENSES
Scale 0 to 80 (millions of dollars).
1991 1992 1993
----- ----- -----
Selling and General Expenses 71.8 72.9 65.2
===== ===== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
28 CAPITAL EXPENDITURES IN 1993
Scale 0 to 700 (millions of dollars).
Percent
-------
Other - $4 (top) 1
Farm, Timber, and Real Estate - $9.7 2
Refining, Marketing, and Transportation - $86.9 13
Exploration and Production - $537* (bottom) 84
*Includes proved property acquisitions of $259.7.
This is a stacked vertical bar graph with a line from each
component to its respective percentage and "Total -- $637.6"
printed below graph.
29 SOURCES OF CASH AND CASH EQUIVALENTS IN 1993
Scale 0 to 450 (millions of dollars).
Percent
-------
Sale of Property and Other - $8.2 (top) 2
Tax Settlements - $11.8 3
Nonrecourse Debt - $27.7 7
Operations - $351.2 (bottom) 88
This is a stacked vertical graph with a line from each
component to its respective percentage and "Total -- $398.9"
printed below graph.
Ex. 13_A-8
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- - - ---------- ---------------
29 USES OF CASH AND CASH EQUIVALENTS IN 1993
Scale 0 to 700 (millions of dollars).
Percent
-------
Debt Reduction and Other - $9.4 (top) 1
Dividends - $55.9 9
Cash Capital Expenditures - $570.2* (bottom) 90
*Includes cash component of proved property acquisitions - $192.3.
This is a stacked vertical bar graph with a line from each component to its respective
percentage and "Total - $635.5" printed below graph.
55 ESTIMATED NET PROVED OIL RESERVES
Scale 0 to 240 (millions of barrels).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Other International (top) 5.9 .3 .2 1.8 1.9
Ecuador - - 33.5 35.6 33.6
United Kingdom 32.4 18.8 14.7 13.1 26.7
Canada* 23.8 24.6 21.8 22.3 120.2
United States (bottom) 25.1 23.9 22.8 23.2 20.0
----- ----- ----- ----- -----
Totals 87.2 67.6 93.0 96.0 202.4
===== ===== ===== ===== =====
*1993 includes synthetic oil - 83.8.
This is a stacked vertical bar graph with each year's total printed above the appropriate bar.
55 ESTIMATED NET PROVED GAS RESERVES
Scale 0 to 800 (billions of cubic feet).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Spain (top) 50.4 32.6 16.6 4.1 10.6
United Kingdom 42.3 40.9 41.1 35.4 31.2
Canada 181.4 201.6 204.9 200.4 182.7
United States (bottom) 374.0 378.5 396.2 445.4 429.0
----- ----- ----- ----- -----
Totals 648.1 653.6 658.8 685.3 653.5
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total printed above the appropriate bar.
55 NET HYDROCARBONS PRODUCTION
Scale 0 to 100 (thousands of barrels a day on an energy equivalent basis).
1989 1990 1991 1992 1993
----- ----- ----- ----- -----
Other International (top) 8.5 6.9 6.7 4.6 3.2
United Kingdom 16.1 13.2 9.3 8.1 8.5
Canada 13.5 14.2 13.7 15.2 18.8
United States (bottom) 44.6 46.0 38.5 44.7 49.6
----- ----- ----- ----- -----
Totals 82.7 80.3 68.2 72.6 80.1
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total printed above the appropriate bar.
Ex. 13_A-9
EXHIBIT 21
MURPHY OIL CORPORATION
PARENTS AND SUBSIDIARIES AS OF DECEMBER 31, 1993
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
(1) Odeco Drilling (Africa)
Limited S.A. Panama 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 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 Ireland Oil Company Delaware 100.0
12. Murphy Italy Oil Company Delaware 100.0
13. Murphy Myanmar Oil Company S.A. Panama 100.0
14. Murphy Overseas Ventures Inc. Delaware 100.0
15. Murphy New Zealand Oil Company 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 Yemen Oil Company Delaware 100.0
22. Norske Murphy Oil Company Delaware 100.0
23. Norske Ocean Exploration Company Delaware 100.0
24. Ocean Exploration Company Delaware 100.0
25. Ocean France Oil Company Delaware 100.0
26. Ocean Gabon Oil Company Delaware 100.0
27. Ocean International Finance Corporation Delaware 100.0
28. Ocean Spain Oil Company Delaware 100.0
29. Ocean Western Oil Company Delaware 100.0
30. Odeco Gabon Oil Company Delaware 100.0
31. Odeco International Corporation Panama 100.0
Ex. 21-1
EXHIBIT 21 (CONTD.)
MURPHY OIL CORPORATION
PARENTS AND SUBSIDIARIES AS OF DECEMBER 31, 1993 (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.
32. Odeco Italy Oil Company Delaware 100.0
33. Sub Sea Offshore (M) Sdn. Bhd. Malaysia 50.0
E. Murphy Oil Company, Ltd. Canada 100.0
1. 340236 Alberta Ltd. Canada 100.0
2. Manito Pipelines Ltd. Canada 52.5
3. Murcan Transportation Ltd. Canada 100.0
4. Murphy Atlantic Offshore Oil Company
Ltd. Canada 100.0
5. Spur Oil Ltd. Canada 100.0
6. 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 LOOP, Inc. Delaware 100.0
4. Murphy Oil Trading Company (Eastern) 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) 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 of Murphy Oil Corporation of our
reports dated March 4, 1994, relating to the consolidated balance sheets of
Murphy Oil Corporation and Consolidated Subsidiaries as of December 31, 1993 and
1992, and the related consolidated statements of income, stockholders' equity,
and cash flows and related financial statement schedules for each of the years
in the three-year period ended December 31, 1993, which reports are included in
the December 31, 1993, annual report on Form 10-K of Murphy Oil Corporation. Our
report refers to changes in the methods of accounting for income taxes and
postretirement benefits other than pensions in 1993.
KPMG PEAT MARWICK
Shreveport, Louisiana
March 29, 1994
Ex. 23-1
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. 2-82818.
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
