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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
For the fiscal year ended December 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
----- -----
Commission file number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 71-0361522
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
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: (870) 862-6411
Securities registered pursuant to Section 12(b) of the Act: None
Title of each class Name of each exchange on which registered
Common Stock, $1.00 Par Value New York Stock Exchange
Toronto Stock Exchange
Series A Participating Cumulative New York Stock Exchange
Preferred Stock Purchase Rights Toronto Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months, and (2) has been subject to such filing requirements
for the past 90 days. Yes X No .
-- --
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of the voting stock held by non-affiliates of the
registrant, based on average price at January 31, 2002, as quoted by the New
York Stock Exchange, was approximately $2,721,379,000.
Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31,
2002 was 45,359,683.
Documents incorporated by reference:
Portions of the Registrant's definitive Proxy Statement relating to the Annual
Meeting of Stockholders on May 8, 2002 have been incorporated by reference in
Part III herein.
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MURPHY OIL CORPORATION
TABLE OF CONTENTS - 2001 FORM 10-K REPORT
Page
PART I Number
------
Item 1. Business 1
Item 2. Properties 1
Item 3. Legal Proceedings 6
Item 4. Submission of Matters to a Vote of Security Holders 7
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 7
Item 6. Selected Financial Data 7
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations 8
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 19
Item 8. Financial Statements and Supplementary Data 20
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 20
PART III
Item 10. Directors and Executive Officers of the Registrant 20
Item 11. Executive Compensation 20
Item 12. Security Ownership of Certain Beneficial Owners and Management 20
Item 13. Certain Relationships and Related Transactions 20
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 21
Exhibit Index 21
Signatures 23
i
PART I
Items 1. and 2. BUSINESS AND PROPERTIES
Summary
Murphy Oil Corporation is a worldwide oil and gas exploration and production
company with refining and marketing operations in the United States and the
United Kingdom. As used in this report, the terms Murphy, Murphy Oil, we, our,
its and Company may refer to Murphy Oil Corporation or any one or more of its
consolidated subsidiaries.
The Company was originally incorporated in Louisiana in 1950 as Murphy
Corporation. It was reincorporated in Delaware in 1964, at which time it adopted
the name Murphy Oil Corporation, and was reorganized in 1983 to operate
primarily as a holding company of its various businesses. Its operations are
classified into two business activities: (1) "Exploration and Production" and
(2) "Refining and Marketing." For reporting purposes, Murphy's exploration and
production activities are subdivided into six geographic segments, including the
United States, Canada, the United Kingdom, Ecuador, Malaysia and all other
countries. Murphy's refining and marketing activities are presently subdivided
into geographic segments for the United States and United Kingdom. Canadian
pipeline and trucking operations were sold in May 2001. Additionally, "Corporate
and Other Activities" include interest income, interest expense and overhead not
allocated to the segments.
The information appearing in the 2001 Annual Report to Security Holders (2001
Annual Report) is incorporated in this Form 10-K report as Exhibit 13 and is
deemed to be filed as part of this Form 10-K report as indicated under Items 1,
2 and 7. A narrative of the graphic and image information that appears in the
paper format version of Exhibit 13 is included in the electronic Form 10-K
document as an appendix to Exhibit 13.
In addition to the following information about each business activity, data
about Murphy's operations, properties and business segments, including revenues
by class of products and financial information by geographic area, are provided
on pages 7 through 15, F-11, F-25 through F-27, and F-30 through F-32 of this
Form 10-K report and on pages 1 through 8 of the 2001 Annual Report.
Exploration and Production
During 2001, Murphy's principal exploration and production activities were
conducted in the United States, Ecuador and Malaysia by wholly owned Murphy
Exploration & Production Company (Murphy Expro) and its subsidiaries, in western
Canada and offshore eastern Canada by wholly owned Murphy Oil Company Ltd.
(MOCL) and its subsidiaries, and in the U.K. North Sea and the Atlantic Margin
by wholly owned Murphy Petroleum Limited. Murphy's crude oil and natural gas
liquids production in 2001 was in the United States, Canada, the United Kingdom
and Ecuador; its natural gas was produced and sold in the United States, Canada
and the United Kingdom. MOCL owns a 5% interest in Syncrude Canada Ltd., which
utilizes its assets to extract bitumen from oil sand deposits in northern
Alberta and to upgrade this into synthetic crude oil. Subsidiaries of Murphy
Expro conducted exploration activities in various other areas including Ireland
and Spain.
Murphy's estimated net quantities of proved oil and gas reserves and proved
developed oil and gas reserves at December 31, 1998, 1999, 2000 and 2001 by
geographic area are reported on page F-29 of this Form 10-K report. Murphy has
not filed and is not required to file any estimates of its total net proved oil
or gas reserves on a recurring basis with any federal or foreign governmental
regulatory authority or agency other than the U.S. Securities and Exchange
Commission. Annually, Murphy reports gross reserves of properties operated in
the United States to the U.S. Department of Energy; such reserves are derived
from the same data from which estimated net proved reserves of such properties
are determined.
Net crude oil, condensate, and gas liquids production and sales, and net natural
gas sales by geographic area with weighted average sales prices for each of the
five years ended December 31, 2001 are shown on page 9 of the 2001 Annual
Report.
1
Production expenses for the last three years in U.S. dollars per equivalent
barrel are discussed on page 11 of this Form 10-K report. For purposes of these
computations, natural gas sales volumes are converted to equivalent barrels of
crude oil using a ratio of six thousand cubic feet (MCF) of natural gas to one
barrel of crude oil.
Supplemental disclosures relating to oil and gas producing activities are
reported on pages F-28 through F-33 of this Form 10-K report.
At December 31, 2001, Murphy held leases, concessions, contracts or permits on
nonproducing and producing acreage as shown by geographic area in the following
table. Gross acres are those in which all or part of the working interest is
owned by Murphy; net acres are the portions of the gross acres applicable to
Murphy's working interest.
Nonproducing Producing Total
--------------- ---------- ---------------
Area (Thousands of acres) Gross Net Gross Net Gross Net
- ------------------------- ------ ------ ----- --- ------ ------
United States - Onshore 7 5 38 20 45 25
- Gulf of Mexico 878 544 300 100 1,178 644
- Frontier 59 16 5 1 64 17
------ ------ ----- --- ------ ------
Total United States 944 565 343 121 1,287 686
------ ------ ----- --- ------ ------
Canada - Onshore 1,297 890 1,040 336 2,337 1,226
- Offshore 12,803 2,221 54 2 12,857 2,223
- Oil sands 240 72 96 5 336 77
------ ------ ----- --- ------ ------
Total Canada 14,340 3,183 1,190 343 15,530 3,526
------ ------ ----- --- ------ ------
United Kingdom 940 266 83 12 1,023 278
Ecuador - - 494 99 494 99
Malaysia 8,659 7,057 - - 8,659 7,057
Ireland 709 177 - - 709 177
Spain 330 99 - - 330 99
------ ------ ----- --- ------ ------
Totals 25,922 11,347 2,110 575 28,032 11,922
====== ====== ===== === ====== ======
As used in the three tables that follow, "gross" wells are the total wells in
which all or part of the working interest is owned by Murphy, and "net" wells
are the total of the Company's fractional working interests in gross wells
expressed as the equivalent number of wholly owned wells.
The following table shows the number of oil and gas wells producing or capable
of producing at December 31, 2001.
Oil Wells Gas Wells
------------- -------------
Country Gross Net Gross Net
- ------- ----- ----- ----- -----
United States 273 114.7 181 72.3
Canada 2,839 682.8 884 402.5
United Kingdom 109 13.1 21 1.5
Ecuador 66 13.2 - -
----- ----- ----- -----
Totals 3,287 823.8 1,086 476.3
===== ===== ===== =====
Wells included above with multiple
completions and counted as one well each 72 31.7 75 58.4
2
Murphy's net wells drilled in the last three years are shown in the following
table.
United United
States Canada Kingdom Ecuador Other Total
---------------- ---------------- ---------------- ---------------- ---------------- ----------------
Productive Dry Productive Dry Productive Dry Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- --- ---------- --- ---------- --- ---------- ---
2001
- ----
Exploratory 6.9 1.7 27.3 12.1 - - - - 1.0 2.0 35.2 15.8
Development 4.1 - 24.7 1.7 .6 .1 2.4 - - - 31.8 1.8
2000
- ----
Exploratory 2.0 3.9 6.4 12.0 .1 .3 - - .8 - 9.3 16.2
Development .3 - 51.7 4.0 .6 .1 1.0 - - - 53.6 4.1
1999
- ----
Exploratory 1.4 1.0 5.3 5.5 - - .4 - - - 7.1 6.5
Development .6 - 13.7 .2 1.0 - .8 - - - 16.1 .2
Murphy's drilling wells in progress at December 31, 2001 are shown below.
Exploratory Development Total
-------------- -------------- --------------
Country Gross Net Gross Net Gross Net
- ------- ----- --- ----- --- ----- ---
United States - - 2 .6 2 .6
Canada 7 3.2 3 .3 10 3.5
United Kingdom - - 2 .1 2 .1
----- --- ----- --- ----- ---
Totals 7 3.2 7 1.0 14 4.2
===== === ===== === ===== ===
Additional information about current exploration and production activities is
reported on pages 1 through 8 of the 2001 Annual Report.
Refining and Marketing
Murphy Oil USA, Inc. (MOUSA), a wholly owned subsidiary, owns and operates two
refineries in the United States. The Meraux, Louisiana refinery is located on
fee land and on two leases that expire in 2010 and 2021, at which times the
Company has options to purchase the leased acreage at fixed prices. The refinery
at Superior, Wisconsin is located on fee land. Murco Petroleum Limited (Murco),
a wholly owned U.K. subsidiary serviced by Murphy Eastern Oil Company, has an
effective 30% interest in a refinery at Milford Haven, Wales that can process
108,000 barrels of crude oil a day. Refinery capacities at December 31, 2001 are
shown in the following table.
3
Milford Haven,
Meraux, Superior, Wales
Louisiana Wisconsin (Murco's 30%) Total
--------- --------- ------------- ----------
Crude capacity - b/sd* 100,000 35,000 32,400 167,400
Process capacity - b/sd*
Vacuum distillation 50,000 20,500 16,500 87,000
Catalytic cracking - fresh feed 38,000 11,000 9,960 58,960
Pretreating cat-reforming feeds 22,000 9,000 5,490 36,490
Catalytic reforming 18,000 8,000 5,490 31,490
Distillate hydrotreating 15,000 7,800 20,250 43,050
Gas oil hydrotreating 27,500 - - 27,500
Solvent deasphalting 18,000 - - 18,000
Isomerization - 2,000 3,400 5,400
Production capacity - b/sd*
Alkylation 8,500 1,500 1,680 11,680
Asphalt - 7,500 - 7,500
Crude oil and product storage
capacity - barrels 4,300,000 3,104,000 2,638,000 10,042,000
*Barrels per stream day.
MOUSA markets refined products through a network of retail gasoline stations and
branded and unbranded wholesale customers in a 23-state area of the southern and
midwestern United States. Murphy's retail stations are primarily located in the
parking areas of Wal-Mart stores in 21 states and use the brand name Murphy
USA(R). Branded wholesale customers use the brand name SPUR(R). Refined
products are supplied from 11 terminals that are wholly owned and operated by
MOUSA, 16 terminals that are jointly owned and operated by others, and numerous
terminals owned by others. Of the terminals wholly owned or jointly owned, four
are supplied by marine transportation, three are supplied by truck, two are
adjacent to MOUSA's refineries and 18 are supplied by pipeline. MOUSA receives
products at the terminals owned by others either in exchange for deliveries from
the Company's terminals or by outright purchase. At December 31, 2001, the
Company marketed products through 387 Murphy USA stations and 428 SPUR stations.
MOUSA plans to add about 110 new Murphy USA stations at Wal-Mart sites in the
southern and midwestern United States in 2002.
At the end of 2001, Murco distributed refined products in the United Kingdom
from the Milford Haven refinery, three wholly owned terminals supplied by rail,
five terminals owned by others where products are received in exchange for
deliveries from the Company's terminals, and 411 branded stations under the
brand names MURCO and EP.
In February 2002, the Company and Wal-Mart reached an agreement for a Canadian
subsidiary of the Company to market products through Murphy Canada stations at
select Wal-Mart stores across Canada. The Company's subsidiary plans to
construct about five to seven stations at Wal-Mart sites in Canada in 2002.
Further stations are expected to be added gradually after 2002.
Murphy owns a 20% interest in a 120-mile refined products pipeline, with a
capacity of 165,000 barrels a day, that transports products from the Meraux
refinery to two common carrier pipelines serving the southeastern United States.
The Company also owns a 3.2% interest in LOOP LLC, which provides deepwater
unloading accommodations off the Louisiana coast for oil tankers and onshore
facilities for storage of crude oil. A crude oil pipeline with a diameter of 24
inches connects LOOP storage at Clovelly, Louisiana to the Meraux refinery.
Murphy owns 29.4% of the first 22 miles of this pipeline from Clovelly to
Alliance, Louisiana and 100% of the remaining 24 miles from Alliance to Meraux.
The pipeline is connected to another company's pipeline system, allowing crude
oil transported by that system to also be shipped to the Meraux refinery. In
February 2002, the Company sold its 22% interest in a 312-mile crude oil
pipeline in Montana and Wyoming for $7 million.
4
In May 2001, the Company sold its Canadian pipeline and trucking operation,
including seven crude oil pipelines with various ownership percentages and
capacities. Murphy realized an after-tax gain of $71 million on this sale.
Additional information about current refining and marketing activities and a
statistical summary of key operating and financial indicators for each of the
five years ended December 31, 2001 are reported on pages 1, 7, 8 and 10 of the
2001 Annual Report.
Employees
At December 31, 2001, Murphy had 3,779 employees - 1,863 full-time and 1,916
part-time.
Competition and Other Conditions Which May Affect Business
Murphy operates in the oil industry and 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 also purchases refined products,
particularly gasoline needed to supply its Wal-Mart stores. The Company may be
required to respond to operating and pricing policies of others, including
producing country governments from whom it makes purchases. Additional
information concerning current conditions of the Company's business is reported
under the caption "Outlook" beginning on page 18 of this Form 10-K report.
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 setting prices,
determining rates of production, and controlling who may buy and sell the
production. In addition, prices and availability of crude oil, natural gas and
refined products could be influenced by political unrest and by various
governmental policies to restrict or increase petroleum usage and supply. Other
governmental actions that could affect Murphy's operations and earnings include
tax changes and regulations concerning: currency fluctuations, protection and
remediation of the environment (See the caption "Environmental" beginning on
page 15 of this Form 10-K report), preferential and discriminatory awarding of
oil and gas leases, restrictions on drilling and/or production, restraints and
controls on imports and exports, safety, and relationships between employers and
employees. Because these and other factors too numerous to list are subject to
constant changes caused by governmental and 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 business is subject to operational hazards and risks normally
associated with the exploration for and production of oil and natural gas and
the refining and marketing of crude oil and petroleum products. The occurrence
of an event, including but not limited to acts of nature, mechanical equipment
failures, industrial accidents, fires and intentional attacks could result in
the loss of hydrocarbons and associated revenues, environmental pollution or
contamination, and personal injury or bodily injury, including death, for which
the Company could be deemed to be liable, and could subject the Company to
substantial fines and/or claims for punitive damages. Murphy maintains insurance
against certain, but not all, hazards that could arise from its operations, and
such insurance is believed to be reasonable for the hazards and risks faced by
the Company. There can be no assurance that such insurance will be adequate to
offset lost revenues or costs associated with certain events or that insurance
coverage will continue to be available in the future on terms that justify its
purchase. The occurrence of an event that is not fully insured could have a
material adverse effect on the Company's financial condition and results of
operations in the future.
5
Executive Officers of the Registrant
The age at January 1, 2002, present corporate office and length of service in
office of each of the Company's executive officers are reported in the following
listing. Executive officers are elected annually but may be removed from office
at any time by the Board of Directors.
R. Madison Murphy - Age 44; Chairman of the Board since October 1994 and
Director and Member of the Executive Committee since 1993. Mr. Murphy
served as Executive Vice President and Chief Financial and Administrative
Officer from 1993 to 1994; Executive Vice President and Chief Financial
Officer from 1992 to 1993; Vice President, Planning/Treasury, from 1991 to
1992; and Vice President, Planning, from 1988 to 1991, with additional
duties as Treasurer from 1990 until August 1991.
Claiborne P. Deming - Age 47; President and Chief Executive Officer since
October 1994 and Director and Member of the Executive Committee since 1993.
He served as Executive Vice President and Chief Operating Officer from 1992
to 1993 and President of MOUSA from 1989 to 1992.
Herbert A. Fox Jr. - Age 67; Executive Vice President - Worldwide Downstream
Operations since November 2001. Mr. Fox was elected Vice President in 1994
and served as President of MOUSA between 1992 and October 2001. He served
as Vice President, Manufacturing, for MOUSA from 1990 to 1992.
Steven A. Cosse' - Age 54; Senior Vice President since October 1994 and General
Counsel since August 1991. Mr. Cosse' was elected Vice President in 1993.
For the eight years prior to August 1991, he was General Counsel for Ocean
Drilling & Exploration Company (ODECO), a majority-owned subsidiary of
Murphy.
Bill H. Stobaugh - Age 50; Vice President since May 1995, when he joined the
Company. Prior to that, he had held various engineering, planning and
managerial positions, the most recent being with an engineering consulting
firm.
Kevin G. Fitzgerald - Age 46; Treasurer since July 2001. Mr. Fitzgerald was
Director of Investor Relations from 1996 to June 2001, and also served in
various capacities with the Company and ODECO between 1982 and 1996.
John W. Eckart - Age 43; Controller since March 2000. Mr. Eckart had been
Assistant Controller since February 1995. He joined the Company as Auditing
Manager in 1990.
Walter K. Compton - Age 39; Secretary since December 1996. He has been an
attorney with the Company since 1988 and became Manager, Law Department, in
November 1996.
Item 3. LEGAL PROCEEDINGS
In June 2000, the U.S. Government filed a lawsuit against Murphy Oil USA, Inc.,
the Company's wholly-owned subsidiary, in federal court in Madison, Wisconsin,
alleging violations of environmental laws at the Company's Superior, Wisconsin
refinery. The lawsuit was divided into liability and damage phases, and on
August 1, 2001, the court ruled against the Company in the liability phase of
the trial. Subsequent to the court ruling, the Company and the U.S. Government
reached a tentative settlement agreement that was filed with the federal court
in January 2002. The settlement is subject to approval by the court following a
30-day public comment period that expires March 7, 2002. According to the
tentative settlement agreement, the Company is to pay a civil penalty of $5.5
million and implement other environmental projects to resolve Clean Air Act
violations. The Company has recorded a liability of $5.5 million to cover the
penalty. Although the settlement is tentative and no assurance can be given, the
Company does not believe that the ultimate resolution of this matter will have a
material adverse effect on its financial condition.
In December 2000, two of the Company's Canadian subsidiaries as plaintiffs filed
an action in the Court of Queen's Bench of Alberta seeking a constructive trust
over oil and gas leasehold rights to Crown lands in British Columbia. The suit
alleges that the defendants acquired the lands after first inappropriately
obtaining confidential and proprietary data belonging to the Company and its
joint venturer. In January 2001, one of the defendants, representing an
undivided 75% interest in the lands in question, settled its portion of the
litigation by conveying its interest to the Company and its joint venturer at
cost. In February 2001, the remaining defendants, representing the remaining
undivided 25% of the lands in question, filed a counterclaim against the
Company's two Canadian subsidiaries and one officer individually
6
seeking compensatory damages of C$6.14 billion. The Company believes the
counterclaim is without merit and the amount of damages sought is frivolous and
the Company does not believe that the ultimate resolution of this suit will have
a material adverse effect on its financial condition.
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 expected to have a material adverse effect on the Company's financial
condition. The ultimate resolution of matters referred to in this item could
have a material adverse effect on the Company's earnings in a future period.
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 2001.
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock is traded on the New York Stock Exchange and the
Toronto Stock Exchange using "MUR" as the trading symbol. There were 2,991
stockholders of record as of December 31, 2001. Information as to high and low
market prices per share and dividends per share by quarter for 2001 and 2000 are
reported on page F-34 of this Form 10-K report.
Item 6. SELECTED FINANCIAL DATA
(Thousands of dollars except per share data) 2001 2000 1999 1998 1997
--------- --------- --------- --------- ---------
Results of Operations for the Year*
Sales and other operating revenues $4,466,821 4,614,341 2,752,083 2,342,644 3,301,542
Net cash provided by operating activities 635,704 747,751 341,711 297,467 365,825
Income (loss) before cumulative effect
of accounting change 330,903 305,561 119,707 (14,394) 132,406
Net income (loss) 330,903 296,828 119,707 (14,394) 132,406
Per Common share - diluted
Income (loss) before cumulative effect
of accounting change 7.26 6.75 2.66 (.32) 2.94
Net income (loss) 7.26 6.56 2.66 (.32) 2.94
Cash dividends per Common share 1.50 1.45 1.40 1.40 1.35
Percentage return on
Average stockholders' equity 23.5 26.4 12.3 (1.3) 12.7
Average borrowed and invested capital 17.7 20.3 9.7 (.6) 10.4
Average total assets 10.2 11.2 5.2 (.6) 6.0
Capital Expenditures for the Year
Exploration and production $ 683,448 392,732 295,958 331,647 423,181
Refining and marketing 175,186 153,750 88,075 55,025 37,483
Corporate and other 5,806 11,415 2,572 2,127 7,367
---------- --------- --------- --------- ---------
$ 864,440 557,897 386,605 388,799 468,031
========== ========= ========= ========= =========
Financial Condition at December 31
Current ratio 1.07 1.10 1.22 1.15 1.10
Working capital $ 38,604 71,710 105,477 56,616 48,333
Net property, plant and equipment 2,525,807 2,184,719 1,782,741 1,662,362 1,655,838
Total assets 3,259,099 3,134,353 2,445,508 2,164,419 2,238,319
Long-term debt 520,785 524,759 393,164 333,473 205,853
Stockholders' equity 1,498,163 1,259,560 1,057,172 978,233 1,079,351
Per share 33.05 27.96 23.49 21.76 24.04
Long-term debt - percent of capital employed 25.8 29.4 27.1 25.4 16.0
*Includes effects on income of special items in 2001, 2000 and 1999 that are
detailed in Management's Discussion and Analysis of Financial Condition and
Results of Operations. Also, special items in 1998 and 1997 increased
(decreased) net income by $(57,935), $(1.29) per diluted share, and $68, with no
per share effect, respectively.
7
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Results of Operations
The Company reported record net income in 2001 of $330.9 million, $7.26 a
diluted share, compared to net income in 2000 of $296.8 million, $6.56 a diluted
share. In 1999, the Company earned $119.7 million, $2.66 a diluted share. Net
income for the three years ended December 31, 2001 included certain special
items that resulted in a net benefit of $67.6 million, $1.48 a diluted share, in
2001; a net charge of $7.2 million, $.16 a diluted share, in 2000; and a net
benefit of $19.7 million, $.44 a diluted share, in 1999. The special items in
2001 included an after-tax benefit of $71 million, $1.56 a diluted share, from
the sale of Canadian pipeline and trucking assets; and a benefit of $8.9
million, $.19 a diluted share, from settlement of income tax matters and a
reduction of a provincial tax rate in Canada. Other special items that decreased
earnings in 2001 included an after-tax charge of $6.8 million, $.15 a diluted
share, for asset impairments under Statement of Financial Accounting Standards
(SFAS) No. 121; and a charge of $5.5 million, $.12 a diluted share, relating to
resolution of Clean Air Act violations at the Company's Superior, Wisconsin
refinery. The special items in 2000 included a benefit from settlement of income
tax matters for $25.6 million, $.56 a share, and a gain on sale of assets of
$1.5 million, $.03 a share. Unusual items that decreased earnings in 2000
included an after-tax charge of $17.8 million, $.39 a diluted share, from asset
impairments; a charge of $7.8 million, $.17 a share, for transportation and
other disputed contractual items under the Company's concessions in Ecuador; and
an after-tax charge of $8.7 million, $.19 a share, for a change in accounting
for the Company's unsold crude oil production. The 1999 special items included
after-tax gains of $7.5 million, $.17 a diluted share, from sale of assets; and
$12.2 million, $.27 a diluted share, primarily from settlements of income taxes
and other matters.
2001 vs. 2000 - Excluding special items, income in 2001 totaled $263.3 million,
$5.78 a diluted share, which was $40.7 million lower than the $304 million,
$6.72 a diluted share, earned in 2000. The decline primarily arose from a
decrease of $90.2 million in earnings from exploration and production operations
caused by an 18% reduction in realized oil prices during 2001 and higher
exploration expenses. The Company's North American natural gas sales price
declined 1% during 2001 to a realized price of $3.87 per MCF. Production of oil
and natural gas were at record levels during 2001, increasing by 3% and 23%,
respectively, compared to 2000. Refining and marketing operations produced
record earnings during 2001 as income before special items increased by 63% to
$89 million. Stronger unit margins in the U.S. during the first half of the year
caused the improved results. The costs of corporate activities, which include
interest income and expense and corporate overhead not allocated to operating
functions, were $13.8 million in 2001, excluding special items, compared to
$28.8 million in 2000. The $15 million reduction in 2001 was primarily due to
higher income tax benefits in the current year.
2000 vs. 1999 - Income before special items in 2000 was a Company record $304
million, $6.72 a diluted share. The results for 2000 represented a $204 million
improvement compared to income before special items of $100 million, $2.22 a
diluted share, in 1999. The improvement primarily arose from record earnings
from the Company's exploration and production operations, which amounted to
$278.3 million in 2000 compared to $121.2 million in 1999. Higher sales prices
for both crude oil and natural gas were the principal reasons behind the higher
exploration and production earnings. The Company's average worldwide sales price
for crude oil and condensate was $25.96 per barrel in 2000 and $17.08 per barrel
in 1999. The average sales price of North American natural gas improved from
$2.25 per thousand cubic feet (MCF) in 1999 to $3.90 in 2000. Earnings from
refining and marketing operations increased from $14.9 million in 1999 to $54.5
million in 2000. These results improved due to better unit margins in both the
United States and the United Kingdom. The costs of corporate activities were
$28.8 million in 2000, excluding special items, compared to $36.1 million in
1999. The reduction in 2000 was primarily due to lower net interest costs and
lower compensation expense for awards under the Company's stock-based incentive
plans.
8
In the following table, the Company's results of operations for the three years
ended December 31, 2001 are presented by segment. Special items, which can
obscure underlying trends of operating results and affect comparability between
years, are set out separately. More detailed reviews of operating results for
the Company's exploration and production and refining and marketing activities
follow the table.
(Millions of dollars) 2001 2000 1999
------ ----- -----
Exploration and production
United States $ 63.6 63.9 30.3
Canada 79.7 112.3 47.0
United Kingdom 76.7 90.2 37.2
Ecuador 11.5 28.9 14.4
Malaysia (36.1) (10.7) (1.7)
Other (7.3) (6.3) (6.0)
------ ----- -----
188.1 278.3 121.2
------ ----- -----
Refining and marketing
United States 71.1 23.9 (5.9)
United Kingdom 14.1 23.0 14.0
Canada 3.8 7.6 6.8
------ ----- -----
89.0 54.5 14.9
------ ----- -----
Corporate and other (13.8) (28.8) (36.1)
------ ----- -----
Income before special items and
cumulative effect of accounting change 263.3 304.0 100.0
Gain on sale of assets 71.0 1.5 7.5
Income tax settlements and tax rate change 8.9 25.6 5.0
Impairment of properties (6.8) (17.8) -
Provision for environmental matter (5.5) - -
Gain (loss) on transportation and other
disputed contractual items in Ecuador - (7.8) 8.2
Provision for reduction in force - - (1.0)
------ ----- -----
Income before cumulative effect
of accounting change 330.9 305.5 119.7
Cumulative effect of accounting change - (8.7) -
------ ----- -----
Net income $330.9 296.8 119.7
====== ===== =====
Exploration and Production - Earnings from exploration and production operations
before special items were $188.1 million in 2001, compared to earnings of $278.3
million in 2000 and $121.2 million in 1999. The decline in 2001 was primarily
attributable to an 18% decline in the Company's average oil sales price compared
to 2000. Additionally, exploration expenses increased over 2000, a significant
portion of which were in foreign jurisdictions where the Company has no realized
income tax benefits. Production of crude oil, condensate and natural gas liquids
increased from 65,259 barrels per day in 2000 to 67,355 in 2001, a 3% increase.
Natural gas sales volumes totaled 281.2 million cubic feet per day in 2001, up
23% from 229.4 million in 2000. The improvement in 2000 earnings compared to
1999 was primarily due to increases in the Company's crude oil sales prices and
higher sales prices for its North American natural gas production. Production of
crude oil, condensate and natural gas liquids decreased 1% in 2000, and natural
gas sales volumes fell 5% as declines in the U.S. Gulf of Mexico more than
offset higher oil and gas sales volumes in Canada. Higher exploration expenses
in 2000 compared to 1999 partially offset the effects of higher commodity
prices.
The results of operations for oil and gas producing activities for each of the
last three years are shown by major operating area on pages F-31 and F-32 of
this Form 10-K report. Daily production and sales rates and weighted average
sales prices are shown on page 9 of the 2001 Annual Report.
9
A summary of oil and gas revenues, including intersegment sales that are
eliminated in the consolidated financial statements, is presented in the
following table.
(Millions of dollars) 2001 2000 1999
------ ----- -----
United States
Crude oil $ 51.9 72.4 54.4
Natural gas 192.8 211.4 147.6
Canada
Crude oil 167.2 193.9 107.7
Natural gas 182.6 99.0 40.2
Synthetic oil 95.8 91.5 74.8
United Kingdom
Crude oil 181.5 214.6 134.7
Natural gas 12.1 7.8 7.7
Ecuador - crude oil 33.4 52.2 36.1
------ ----- -----
Total oil and gas revenues $917.3 942.8 603.2
====== ===== =====
The Company's crude oil, condensate and natural gas liquids production averaged
67,355 barrels per day in 2001, 65,259 in 2000 and 66,083 in 1999. Sales volumes
in 2001 were slightly higher and averaged 67,884 barrels per day. Oil production
in the United States declined 14% in 2001, following a 21% decline in 2000. The
reduction in both years was primarily due to declines from existing fields in
the Gulf of Mexico. Oil production in Canada increased 15% in 2001 to a record
volume of 36,059 barrels per day. The Company's share of net production at its
synthetic oil operation improved 2,036 barrels per day, or 24%, in 2001 due to a
combination of higher gross production and a lower net profit royalty caused by
increased capital spending and a lower oil price. Before royalties, the
Company's synthetic oil production was 11,157 barrels per day in 2001, 10,145 in
2000 and 11,146 in 1999. Production of light oil increased 1,258 barrels per
day, or 41%, and heavy oil production increased 11% to 11,707 barrels per day in
2001 with both increases primarily due to the Company's acquisition of Beau
Canada Exploration Ltd. (Beau Canada) in November 2000. Production at Hibernia
rose 4% in 2001 to 9,535 barrels per day due to better operating efficiency,
primarily associated with improved handling of gas production. U.K. production
was down by 681 barrels per day, or 3%, due to declines from the Company's
existing fields in the North Sea. In 2000, oil production increased 4% in
Canada. Production at Hibernia rose 2,795 barrels per day due to improved
operations. Heavy oil production in western Canada was 1,475 barrels per day
higher in 2000 due primarily to an active drilling program in the early part of
the year. The Company's share of net production at its synthetic oil operation
in Canada was down 2,554 barrels per day in 2000 due to a combination of more
downtime for maintenance and a higher net profit royalty caused by higher
prices. Production of light oil in Canada decreased 400 barrels per day in 2000.
U.K. production increased 357 barrels per day in 2000 as improved volumes at
Mungo/Monan and Schiehallion were almost offset by declines at more mature
fields in the North Sea. Production in Ecuador was down 699 barrels per day in
2000 due to pipeline constraints.
Worldwide sales of natural gas were a record 281.2 million cubic feet per day in
2001, up from 229.4 million in 2000. Natural gas sales were 240.4 million cubic
feet per day in 1999. Sales of natural gas in the United States were 115.5
million cubic feet per day in 2001, 144.8 million in 2000 and 171.8 million in
1999. The reductions in 2001 and 2000 were due to lower deliverability from
maturing fields in the Gulf of Mexico. Natural gas sales in Canada in 2001 were
at record levels for the sixth consecutive year as sales increased 107% to 152.6
million cubic feet per day. Canadian natural gas sales had increased 31% in
2000. The increase in 2001 was primarily due to the acquisition of Beau Canada;
production in both 2001 and 2000 benefited from new discoveries in western
Canada. Natural gas sales in the United Kingdom were 13.1 million cubic feet per
day in 2001, up 21% compared to 2000. U.K. natural gas sales in 2000 decreased
1.6 million cubic feet per day from 1999 levels.
Worldwide crude oil sales prices declined during 2001 compared to 2000. In the
United States, the Company's average monthly sale price for crude oil and
condensate declined 18% compared to 2000 and averaged $24.92 per barrel for the
year. In Canada, the average sales price for light oil fell 19% to $22.40 per
barrel. Heavy oil prices averaged $11.06 per barrel, down 38% from 2000. The
average sales price for crude oil from the Hibernia field decreased 12% to
$23.77 per barrel. Synthetic oil prices in 2001 averaged $25.04 per barrel, down
15% from a year ago. Average sales prices in the U.K. averaged $24.44 per
barrel, a decline of 12%, and sales prices in Ecuador were down 23% to $17.00
per barrel.
10
Worldwide crude oil sales prices in 2000 were significantly higher than in 1999.
In the United States, Murphy's 2000 average sales prices for crude oil and
condensate averaged $30.38 per barrel for the year, 68% above 1999. In Canada,
the average sales price for light oil was $27.68 per barrel in 2000, an increase
of 63%. Heavy oil prices averaged $17.83 per barrel, up 40% compared to 1999.
The average sales price for synthetic oil in 2000 was $29.62 per barrel, up 59%.
The sales price for crude oil from the Hibernia field increased 42% to $27.16
per barrel. U.K. sales prices averaged 54% higher in 2000 at $27.78 per barrel.
Sales prices in Ecuador were $22.01 per barrel in 2000, up 53% from a year
earlier.
The Company's North American natural gas sales price averaged $3.87 per MCF for
the year 2001 compared to $3.90 in 2000. U.S. sales prices averaged $4.64 per
MCF compared to $4.01 a year ago. However, the average price for natural gas
sold in Canada declined 11% to $3.28 per MCF. Prices in the United Kingdom
increased to $2.52 per MCF from $1.81 in 2000.
North American natural gas sales prices strengthened during 2000 due to supply
being short of demand. A combination of a hotter than normal summer and a colder
than normal early winter near the end of 2000 in the United States strained an
already below-normal level of gas storage throughout the country. Natural gas
sales prices in the United States increased 71% from 1999 and averaged $4.01 per
MCF in 2000 compared to $2.34 in the prior year. The average price for natural
gas sold in Canada during 2000 increased 87% to $3.67 per MCF, while prices in
the United Kingdom increased 8% to $1.81.
Based on 2001 volumes and deducting taxes at marginal rates, each $1 per barrel
and $.10 per MCF fluctuation in prices would have affected annual exploration
and production earnings by $16.2 million and $6.4 million, respectively. The
effect of these price fluctuations on consolidated net income cannot be measured
because operating results of the Company's refining and marketing segments could
be affected differently.
Production expenses were $218 million in 2001, $181.9 million in 2000 and $162.1
million in 1999. These amounts are shown by major operating area on pages F-31
and F-32 of this Form 10-K report. Cost per equivalent barrel during the last
three years were as follows.
(Dollars per equivalent barrel) 2001 2000 1999
------ ----- ----
United States $ 5.30 3.72 2.98
Canada
Excluding synthetic oil 3.84 4.24 3.99
Synthetic oil 13.58 13.06 9.09
United Kingdom 3.75 3.46 3.73
Ecuador 7.60 6.65 5.10
Worldwide - excluding synthetic oil 4.36 4.05 3.62
The increase in the cost per equivalent barrel in the United States in both 2001
and 2000 was attributable to a combination of lower production and higher well
servicing costs. The decrease in Canada during 2001, excluding synthetic oil,
was primarily due to increased production in all categories. The increase in the
cost per equivalent barrel for Canadian synthetic oil in 2001 was due to higher
maintenance costs. The increase in unit cost in the United Kingdom during 2001
was the result of higher costs to maintain mature properties, including Ninian,
and the increase in Ecuador in 2001 was due to lower production during the year.
The 2000 increase in Canada, excluding synthetic oil, was due to an increase in
well servicing costs at heavy oil properties offset in part by the effect of
higher production at Hibernia, where production expenses are lower than in
western Canada. The increase for Canadian synthetic oil in 2000 was due to lower
net production caused by a combination of less gross production volumes and an
increase in royalty barrels caused by higher oil prices. Based on the Company's
interest in Syncrude's gross production, cost per barrel increased 21% in 2000.
A lower unit cost in the United Kingdom in 2000 was due to a favorable impact
from higher production at the Mungo/Monan and Schiehallion fields. Higher cost
per barrel in Ecuador in 2000 was attributable to both lower production and
higher overall operating expenses.
11
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 F-31
and F-32 of this Form 10-K report. Certain of the expenses are included in the
capital expenditure totals for exploration and production activities.
(Millions of dollars) 2001 2000 1999
---- ---- ----
Exploratory expenditures charged against income
Dry hole costs $ 82.8 66.0 32.4
Geological and geophysical costs 36.0 36.3 18.7
Other costs 15.0 9.2 8.5
------ ----- ----
133.8 111.5 59.6
Undeveloped lease amortization 23.1 14.1 11.0
------ ----- ----
Total exploration expenses $156.9 125.6 70.6
====== ===== ====
Depreciation, depletion and amortization related to exploration and production
operations totaled $183.7 million in 2001, $169.2 million in 2000 and $166.9
million in 1999. The increase in 2001 was due to record levels of oil and
natural gas sales during the year. The increase in 2000 was due to higher
production from Hibernia field, offshore eastern Canada, and higher depreciation
rates per unit on production from properties acquired from Beau Canada in
November 2000.
Refining and Marketing - Earnings before special items from refining and
marketing operations were a record $89 million in 2001. Comparable earnings in
2000 and 1999 were $54.5 million and $14.9 million, respectively. Operations in
the United States earned $71.1 million in 2001 compared to $23.9 million in
2000, due to stronger refining margins and a higher percentage of sales through
the Company's retail stations at Wal-Mart stores. U.S. operations lost $5.9
million in 1999. The increase in 2000 was due to product sales realizations
increasing more than the cost of crude oil and other refinery feedstocks.
Operations in the United Kingdom earned $14.1 million in 2001, $23 million in
2000 and $14 million in 1999. The decline in 2001 earnings was caused by
generally weaker U.K. refining margins compared to 2000. Strong refining margins
in the United Kingdom in 2000 led to record earnings for this operation. The
Company earned $3.8 million in 2001 from its crude oil trading and
transportation business in Canada prior to the sale of these pipeline and
trucking assets in May 2001. The Canadian operations earned $7.6 million and
$6.8 million in 2000 and 1999, respectively.
Unit margins (sales realizations less costs of crude oil, other feedstocks,
refining and transportation to point of sale) averaged $3.23 per barrel in the
United States in 2001, $1.91 in 2000 and $.66 in 1999. U.S. product sales
increased 17% to a record 174,256 barrels per day in 2001, following an 18%
increase in 2000. Higher product sales volumes in 2001 and 2000 were
attributable to a combination of higher crude oil throughputs compared to the
previous year at the Company's U.S. refineries, plus continued expansion of the
Company's retail gasoline network at Wal-Mart stores.
Unit margins in the United Kingdom averaged $3.29 per barrel in 2001, $4.69 in
2000 and $3.38 in 1999. Sales of petroleum products were up 4% in 2001 due to
higher volumes sold in the cargo market. Sales volumes in 2000 were down 7%
compared to 1999, with the decline attributable to lower consumer demand in the
United Kingdom caused by the large increase in product prices during the year.
Both U.S. and U.K. unit margins have been significantly weaker in early 2002,
and both operations were experiencing losses during the early part of the year.
Based on sales volumes for 2001 and deducting taxes at marginal rates, each $.42
per barrel ($.01 per gallon) fluctuation in unit margins would have affected
annual refining and marketing profits by $19.9 million. The effect of these unit
margin fluctuations on consolidated net income cannot be measured because
operating results of the Company's exploration and production segments could be
affected differently.
Special Items - Net income for the last three years included certain special
items reviewed in the following paragraphs. The effects of special items on
quarterly results for 2001 and 2000 are presented on page F-34 of this Form 10-K
report.
. Gain on sale of assets - After-tax gains of $67.6 million and $3.4
million were recorded in the second and fourth quarter, respectively,
of 2001 for the sale of Canadian pipeline and trucking assets.
After-tax gains of $1.5 million were recorded in the second quarter of
2000 from the sale of U.S. corporate assets, and $6.3 million and $1.2
million were recorded in the third and fourth quarters, respectively,
of 1999 from the sale of U.S. service stations.
12
. Income tax settlements and tax rate change - Income of $5.5 million was
recorded in the third quarter of 2001 from a reduction in a Canadian
provincial tax rate. In addition, settlement of income tax matters in
the U.S. and U.K. provided income of $3.4 million in the fourth quarter
of 2001. Income of $15.5 million, $10.1 million and $5 million from
settlement of U.S. income tax matters was recorded in the third quarter
of 2000, the fourth quarter of 2000 and the fourth quarter of 1999,
respectively.
. Impairment of properties - After-tax provisions of $6.8 million, $13.6
million and $4.2 million were recorded in the fourth quarter of 2001,
the third quarter of 2000 and the fourth quarter of 2000, respectively,
for the write-down of assets determined to be impaired. (See Note D to
the consolidated financial statements.)
. Provision for U.S. environmental matters - A $5.5 million charge was
recorded in the third quarter of 2001 to resolve Clean Air Act
violations at the Company's Superior, Wisconsin refinery.
. Gain (loss) on transportation and other disputed contractual items in
Ecuador - A loss of $7.8 million was recorded in the fourth quarter of
2000 and a gain of $8.2 million was recorded in the fourth quarter of
1999 related to transportation and other contractual disputes under the
Company's concessions in Ecuador.
. Provision for reduction in force - An after-tax charge of $1 million
for a reduction in force program was recorded in the first quarter of
1999. (See Note G to the consolidated financial statements.)
. Cumulative effect of accounting change - An after-tax charge of $8.7
million was recorded in the first quarter of 2000 to account for the
Company's unsold crude oil production at cost rather than at market
value as in the past. (See Note B to the consolidated financial
statements.)
The income (loss) effects of special items for each of the three years ended
December 31, 2001 are summarized by segment in the following table.
(Millions of dollars) 2001 2000 1999
---- ---- ----
Exploration and production
United States $ (5.8) (13.6) 5.0
Canada 5.8 (4.2) -
United Kingdom 1.9 - -
Ecuador - (7.8) 8.2
------ ----- ----
1.9 (25.6) 13.2
------ ----- ----
Refining and marketing
United States (6.5) - 7.5
Canada 71.1 - -
------ ----- ----
64.6 - 7.5
------ ----- ----
Corporate and other 1.1 27.1 (1.0)
------ ----- ----
Cumulative effect of accounting change - (8.7) -
------ ----- ----
Total income (loss) from special items $ 67.6 (7.2) 19.7
====== ===== ====
Capital Expenditures
As shown in the selected financial information on page 7 of this Form 10-K
report, capital expenditures, including discretionary exploration expenditures,
were $864.4 million in 2001 compared to $557.9 million in 2000 and $386.6
million in 1999. These amounts included $133.8 million, $111.5 million and $59.6
million of exploration costs that were expensed. Capital expenditures for
exploration and production activities totaled $683.5 million in 2001, 79% of the
Company's total capital expenditures for the year. Exploration and production
capital expenditures in 2001 included $65.2 million for acquisition of
undeveloped leases, $21.6 million for acquisition of proved oil and gas
properties, $242.2 million for exploration activities, and $354.5 million for
development projects. Development expenditures included $60.6 million for the
Terra Nova oil field, offshore Newfoundland; $27.2 million for synthetic oil
operations at Syncrude in Canada; and $96.3 million for heavy oil and natural
gas projects in western Canada. Exploration and production capital expenditures
are shown by major operating area on page F-30 of this Form 10-K report.
13
Refining and marketing expenditures, detailed in the following table, were 20%
of total capital expenditures in 2001.
(Millions of dollars) 2001 2000 1999
----- ----- ----
Refining
United States $ 87.8 19.2 17.7
United Kingdom 1.1 4.3 7.0
------ ----- ----
Total refining 88.9 23.5 24.7
------ ----- ----
Marketing
United States 75.0 92.8 58.7
United Kingdom 11.3 8.1 4.4
------ ----- ----
Total marketing 86.3 100.9 63.1
------ ----- ----
Other - Canada - 29.4 .3
------ ----- ----
Total $175.2 153.8 88.1
====== ===== ====
U.S. refining expenditures in 2001 included $55.1 million for clean fuels and
crude throughput expansion projects at the Meraux refinery. U.S. refining
expenditures in 2000 and 1999 and U.K. expenditures during the three years were
primarily for capital projects to keep the refineries operating efficiently and
within industry standards and to study alternatives for meeting anticipated
future clean fuel specifications. Marketing expenditures in the United States
primarily included the costs of new stations built at Wal-Mart stores. U.K.
marketing expenditures in 2001 and 2000 were primarily for redevelopment of
stores and station purchases; expenditures in 1999 were primarily for
improvements and normal replacements at existing stations and terminals. Other
capital expenditures in Canada in 2000 primarily consisted of the mid-year
acquisition of the minority interest in the Manito pipeline system. The Manito
pipeline and other Canadian pipeline and trucking assets were sold by the
Company in May 2001.
Cash Flows
Cash provided by operating activities was $635.7 million in 2001, $747.8 million
in 2000 and $341.7 million in 1999. Special items decreased cash flow from
operations by $32.3 million in 2001 and $2.7 million in 2000, but increased cash
by $18.9 million in 1999. Changes in operating working capital other than cash
and cash equivalents provided cash of $66 million in 2000, but required cash of
$28 million and $35.2 million in 2001 and 1999, respectively. Cash provided by
operating activities was further reduced by expenditures for refinery
turnarounds and abandonment of oil and gas properties totaling $16.4 million in
2001, $16.6 million in 2000 and $44.1 million in 1999.
Cash proceeds from property sales were $173 million in 2001, $20.7 million in
2000 and $40.9 million in 1999. Borrowings under notes payable and other
long-term debt provided $88.2 million of cash in 2001, $175 million in 2000 and
$247.8 million in 1999. Cash proceeds from stock option exercises and employee
stock purchase plans amounted to $18.9 million in 2001, $3.8 million in 2000 and
$2.3 million in 1999.
Property additions and dry hole costs required $813.5 million of cash in 2001,
$512.3 million in 2000 and $359.4 million in 1999. Cash outlays for debt
repayment during the three years included $77.7 million in 2001, $130.5 million
in 2000 and $195.9 million in 1999. The acquisition of Beau Canada in November
2000 utilized $127.5 million of cash. Cash used for dividends to stockholders
was $67.8 million in 2001, $65.3 million in 2000 and $63 million in 1999.
Financial Condition
Year-end working capital totaled $38.6 million in 2001, $71.7 million in 2000
and $105.5 million in 1999. The current level of working capital does not fully
reflect the Company's liquidity position as the carrying values for inventories
under last-in first-out accounting were $51 million below current costs at
December 31, 2001. Cash and cash equivalents at the end of 2001 totaled $82.7
million compared to $132.7 million a year ago and $34.1 million at the end of
1999.
Long-term debt was reduced by $4 million during 2001 to $520.8 million at the
end of the year, 25.8% of total capital employed, and included $104.7 million of
nonrecourse debt incurred in connection with the acquisition and development of
the Hibernia oil field. The decrease in long-term debt in 2001 was attributable
to repayments of nonrecourse debt, partially offset by other new borrowings.
Long-term debt totaled $524.8 million at the end of 2000 compared to $393.2
million at December 31, 1999. Stockholders' equity was $1.5 billion at the end
of 2001 compared
14
to $1.3 billion a year ago and $1.1 billion at the end of 1999. A summary of
transactions in stockholders' equity accounts is presented on page F-5 of this
Form 10-K report.
Murphy had commitments of $506 million for capital projects in progress at
December 31, 2001, including $206 million related to clean fuels and crude
throughput expansion projects at the Meraux refinery and $94 million for costs
to develop the Medusa field in the deepwater Gulf of Mexico.
The primary sources of the Company's liquidity are internally generated funds,
access to outside financing and working capital. The Company typically 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. The Company anticipates that long-term debt will
increase during 2002 caused by significant capital expenditure commitments, as
described in the preceding paragraph, and an expectation that oil and natural
gas prices for much of 2002 will remain below trading ranges experienced in 2000
and early 2001. At December 31, 2001, the Company had access to short-term and
long-term revolving credit facilities in the amount of $450 million, and also
had unused available lines of credit with banks of $142.6 million. In addition,
the Company has a shelf registration on file with the U.S. Securities and
Exchange Commission that permits the offer and sale of up to $1 billion in debt
and equity securities. Current financing arrangements are set forth more fully
in Note E to the consolidated financial statements. Based on the financing
arrangements currently available, the Company does not expect to have any
problems in meeting future requirements for funds.
At December 31, 2001, Murphy had $49 million of lease bonus and drilling costs
in Property, Plant and Equipment associated with several leases in the eastern
Gulf of Mexico. The U.S. government has thus far failed to issue the permits
needed to develop and produce a large natural gas discovery on Company-held
acreage in this area due to purported environmental concerns of the state of
Florida. The Company and its co-venturers have sued the U.S. government over its
failure to issue such permits, and the Company cannot predict whether the U.S.
government will issue the permits needed to develop the discovery, or whether
the Company will be compensated by the government in the event the permits are
not issued.
Environmental
The Company's operations are subject to numerous laws and regulations intended
to protect the environment and/or impose remedial obligations. The Company is
also involved in personal injury and property damage claims, allegedly caused by
exposure to or by the release or disposal of materials manufactured or used in
the Company's operations. The Company operates or has previously operated
certain sites and facilities, including refineries, oil and gas fields, service
stations, and terminals, for which known or potential obligations for
environmental remediation exist.
Under the Company's accounting policies, an environmental liability is recorded
when such an obligation is probable and the cost can be reasonably estimated. If
there is a range of reasonably estimated costs, the most likely amount will be
recorded, or if no amount is most likely, the minimum of the range is used.
Recorded liabilities are reviewed quarterly. Actual cash expenditures often
occur one or more years after a liability is recognized.
The Company's liability for remedial obligations includes certain amounts that
are based on anticipated regulatory approval for proposed remediation of former
refinery waste sites. If regulatory authorities require more costly alternatives
than the proposed processes, future expenditures could exceed the accrued
liability by up to an estimated $3 million.
The Company has received notices from the U.S. Environmental Protection Agency
(EPA) that it is currently considered a Potentially Responsible Party (PRP) at
three Superfund sites and has also been assigned responsibility by defendants at
another Superfund site. The potential total cost to all parties to perform
necessary remedial work at these sites may be substantial. Based on currently
available information, the Company has reason to believe that it is a "de
minimus" party as to ultimate responsibility at the four sites. The Company has
not recorded a liability for remedial costs on Superfund sites. The Company
could be required to bear a pro rata share of costs attributable to
nonparticipating PRPs. Additionally, the Company could be assigned additional
responsibility for remediation at these or other Superfund sites.
There is the possibility that environmental expenditures could be required at
currently unidentified sites, and new or revised regulations could require
additional expenditures at known sites.
15
The amount of future remediation costs incurred at known or currently
unidentified sites could have a material adverse effect on future earnings. The
Company does not expect that future costs for these matters will have a material
adverse effect on its financial condition.
Certain environmental expenditures are likely to be recovered by the Company
from other sources, primarily environmental funds maintained by certain states.
Since no assurance can be given that future recoveries from other sources will
occur, the Company has not recorded a benefit for likely recoveries at December
31, 2001.
The Company's refineries also incur costs to handle and dispose of hazardous
waste and other chemical substances. These costs are expensed as incurred and
amounted to $2.6 million in 2001. In addition to these expenses, Murphy
allocates a portion of its capital expenditure program to comply with
environmental laws and regulations. Such capital expenditures were approximately
$109 million in 2001 and are projected to be $166 million in 2002.
A lawsuit filed against Murphy by the U.S. Government is discussed under the
caption "Legal Proceedings" on page 6 of this Form 10-K report.
Other Matters
Impact of inflation - General inflation was moderate during the last three years
in most countries where the Company operates; however, the Company's revenues
and capital and operating costs are influenced to a larger extent by specific
price changes in the oil and gas and allied industries than by changes in
general inflation. Crude oil 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 and demand in the near future. Natural gas prices are affected by supply
and demand, which to a significant extent are affected by the weather and by the
fact that delivery of gas is generally restricted to specific geographic areas.
Because crude oil and natural gas sales prices were strong during 2000 and early
2001, prices for oil field goods and services were adversely affected.Although
oil and natural gas prices have weakened in the latter part of 2001 and into
2002, it is not possible to determine what effect these lower prices will have
on the future cost of oil field goods and services.
Accounting changes and recent accounting pronouncements - As described in Note B
on page F-9 of this Form 10-K report, Murphy adopted Statement of Financial
Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS No. 138, effective January 1, 2001. In
addition, the Company adopted a change in accounting for unsold crude oil
production effective January 1, 2000 that resulted in an $8.7 million charge to
earnings for the cumulative effect of the accounting change.
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible
Assets." SFAS No. 141 requires that all future business combinations be
accounted for using the purchase method of accounting and that certain acquired
intangible assets in a business combination be recognized and reported as assets
apart from goodwill. SFAS No. 142 requires that amortization of goodwill be
replaced with annual tests for impairment and that intangible assets other than
goodwill be amortized over their useful lives. The Company adopted SFAS No. 141
immediately and will adopt SFAS No. 142 on January 1, 2002. The Company had
unamortized goodwill of $50.4 million at December 31, 2001, which will be
subject to the transition provisions of SFAS No. 142. Amortization expense
related to goodwill was $3.1 million for the year ended December 31, 2001.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 requires the Company to record a liability equal to
the fair value of the estimated cost to retire an asset. The asset retirement
liability must be recorded in the period in which the obligation meets the
definition of a liability, which is generally when the asset is placed in
service. When the liability is initially recorded, the Company will increase the
carrying amount of the related long-lived asset by an amount equal to the
original liability. The liability is accreted to its present value each period,
and the capitalized cost is depreciated over the useful life of the related
long-lived asset. Upon adoption of SFAS No. 143 on January 1, 2003, the Company
will recognize transition adjustments for existing asset retirement obligations,
long-lived assets and accumulated depreciation, all net of related income tax
effects, as the cumulative effect of a change in accounting principle. After
adoption, any difference between costs incurred upon settlement of an asset
retirement obligation and the recorded liability will be recognized as a gain or
loss in the Company's earnings.
16
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," which supercedes SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
of," and the accounting and reporting provisions of APB Opinion No. 30,
"Reporting the Results of Operations-Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual, and Infrequently Occurring
Events and Transactions." The Company will adopt the provisions of SFAS No. 144
effective January 1, 2002, and its provisions are generally to be applied
prospectively.
At this time, it is not practicable to reasonably estimate the impact of
adopting these accounting standards on the Company's financial statements,
including whether any transitional goodwill impairment losses will be required
to be recognized as the cumulative effect of a change in accounting principle.
Significant accounting policies - In preparing the financial statements of the
Company in accordance with accounting principles generally accepted in the
United States, management must make a number of estimates and assumptions
related to the reporting of assets, liabilities, revenues, and expenses and the
disclosure of contingent assets and liabilities. Application of certain of the
Company's accounting policies requires significant estimates. These accounting
policies are described below.
. Proved oil and natural gas reserves - Proved reserves are defined by the
U.S. Securities and Exchange o Commission (SEC) as those volumes of crude
oil, condensate, 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 volumes expected to be recovered through existing
wells with existing equipment and operating methods. Although the Company's
engineers are knowledgeable of and follow the guidelines for reserves as
established by the SEC, the estimation of reserves requires the engineers
to make a significant number of assumptions based on professional judgment.
Estimated reserves are often subject to future revision, certain of which
could be substantial, based on the availability of additional information,
including: reservoir performance, new geological and geophysical data,
additional drilling, technological advancements, price changes and other
economic factors. Changes in oil and natural gas prices can lead to a
decision to start-up or shut-in production, which can lead to revisions to
reserve quantities. Reserve revisions inherently lead to adjustments of
depreciation rates utilized by the Company. The Company can not predict the
types of reserve revisions that will be required in future periods.
. Successful efforts accounting - The Company utilizes the successful efforts
method to account for exploration and development expenditures.
Unsuccessful exploration wells are expensed and can have a significant
effect on operating results. Successful exploration drilling costs and all
development capital expenditures are capitalized and systematically charged
to expense using the units of production method based on proved developed
oil and natural gas reserves as estimated by the Company's engineers. The
Company also uses proved developed reserves to recognize expense for future
estimated dismantlement and abandonment costs. Costs of exploration wells
in progress at year-end 2001 were not significant.
. Impairment of properties - The Company continually monitors its long-lived
assets recorded in Property, Plant and Equipment in the Consolidated
Balance Sheet to make sure that they are fairly presented. The Company must
evaluate its properties for potential impairment when circumstances
indicate that the carrying value of an asset could exceed its fair value. A
significant amount of judgment is involved in performing these evaluations
since the results are based on estimated future events. Such events include
a projection of future oil and natural gas sales prices, an estimate of the
ultimate amount of recoverable oil and natural gas reserves that will be
produced from a field, the timing of this future production, future costs
to produce the oil and natural gas, and future inflation levels. The need
to test a property for impairment can be based on several factors,
including a significant reduction in sales prices for oil and/or natural
gas, unfavorable adjustments to reserves, or other changes to contracts,
environmental regulations or tax laws. All of these same factors must be
considered when testing a property's carrying value for impairment. The
Company can not predict the amount of impairment charges that may be
recorded in the future.
. Income taxes - The Company is subject to income and other similar taxes in
all areas in which it operates. When recording income tax expense, certain
estimates are required because: (a) income tax returns are generally filed
months after the close of its calendar year; (b) tax returns are subject to
audit by taxing authorities and audits can often take years to complete and
settle; and (c) future events often impact the timing of when income tax
expenses
17
and benefits are recognized by the Company. The Company has deferred tax
assets relating to tax operating loss carryforwards and other deductible
differences in Ecuador and Malaysia. The Company routinely evaluates all
deferred tax assets to determine the likelihood of their realization. A
valuation allowance has been recognized for deferred tax assets due to
management's belief that certain of these assets are not likely to be
realized. The Company occasionally is challenged by taxing authorities over
the amount and/or timing of recognition of revenues and deductions in its
various income tax returns. Although the Company believes that it has
adequate accruals for matters not resolved with various taxing authorities,
gains or losses could occur in future years from changes in estimates or
resolution of outstanding matters.
. Legal, environmental and other contingent matters - A provision for legal,
environmental and other contingent matters is charged to expense when the
loss is probable and the cost can be reasonably estimated. Judgment is
often required to determine when expenses should be recorded for legal,
environmental and other contingent matters. In addition, the Company often
must estimate the amount of such losses. In many cases, management's
judgment is based on interpretation of laws and regulations, which can be
interpreted differently by regulators and/or courts of law. The Company's
management closely monitors known and potential legal, environmental and
other contingent matters, and makes its best estimate of when the Company
should record losses for these based on information available to the
Company.
Contractual obligations and guarantees - The Company is obligated to make future
cash payments under borrowing arrangements, operating leases and capital
commitments. Total payments due after 2001 under such contractual obligations
are shown below.
Amounts Due
-----------------------------------------------------
(Millions of dollars) Total 2002 2003-2005 2006-2007 After 2007
-------- ----- --------- --------- ----------
Long-term debt $ 569.0 48.2 165.2 81.7 273.9
Operating leases 236.8 17.6 49.7 31.6 137.9
Capital commitments 505.5 401.6 103.9 - -
-------- ----- ----- ----- -----
Total $1,311.3 467.4 318.8 113.3 411.8
======== ===== ===== ===== =====
In the normal course of its business, the Company is required under certain
contracts with various governmental authorities and others to provide financial
guarantees or letters of credit that may be drawn upon if the Company fails to
perform under those contracts. The amount of commitments that expire in future
periods is shown below.
Commitment Expiration Per Period
-------------------------------
(Millions of dollars) Total 2002 2003-2005 2006-2007 After 2007
------ ---- --------- --------- ----------
Financial guarantees $33.8 2.1 4.9 3.2 23.6
Letters of credit 35.6 6.8 13.3 2.2 13.3
----- --- ---- --- ----
Total $69.4 8.9 18.2 5.4 36.9
===== === ==== === ====
Outlook
Prices for the Company's primary products are often quite volatile. During 2000
and early 2001, increased worldwide demand and disciplined management of supply
by the world's producers - primarily by members of OPEC - led to stronger oil
prices. Due to economic slowdowns in many major countries during 2001, crude oil
demand softened leading to significantly weaker sales prices. In response to
lower oil prices, OPEC and other major oil producers have agreed to reduce oil
production in early 2002. It is too early to determine whether these production
cuts will lead to a meaningful improvement in oil prices. Due to a combination
of warmer than normal weather across much of North America during the early
winter of 2001-2002 and increased gas storage levels, the price of natural gas
in early 2002 remained below trading ranges during most of the last two years.
In addition, refined product margins in both the United States and United
Kingdom were extremely weak in early 2002, leading to losses in refining and
marketing operations in both areas. If oil and natural gas sales prices and
refining and marketing margins continue at the levels experienced in January
2002, the Company expects that future operating results could be near
break-even. In such a volatile operating environment, constant reassessment of
spending plans is required.
The Company's capital expenditure budget for 2002 was prepared during the fall
of 2001 and provides for expenditures of $866 million. Of this amount, $604
million or 70%, is allocated for exploration and production. Geographically, 39%
of the exploration and production budget is allocated to the United States,
including $139 million for development
18
of deepwater projects in the Gulf of Mexico; another 36% is allocated to Canada,
including $41 million for light oil and natural gas development, $28 million for
continued development of the Hibernia and Terra Nova oil fields, and $49 million
for further expansion of synthetic oil operations; 6% is allocated to the United
Kingdom; 5% is allocated to Ecuador; and 14% is allocated to other foreign
operations, which primarily includes Malaysia. Budgeted refining and marketing
capital expenditures for 2002 are $259 million, including $235 million in the
United States, and $12 million each in the United Kingdom and Canada. U.S. and
Canadian amounts include funds to build additional stations at Wal-Mart sites.
U.S. amounts also include spending for clean fuels and crude throughput
expansion projects at the Meraux refinery. Due to an expectation of lower
natural gas sales prices compared to the price assumptions used in the 2002
Budget, the Company has announced intentions to reduce 2002 capital expenditures
by approximately $100 million. Capital and other expenditures are under constant
review and planned capital expenditures may be adjusted further to reflect
changes in estimated cash flow during 2002.
Based on the Company's projected capital expenditures in 2002 and weaker than
anticipated natural gas sales prices and refining and marketing margins early in
the year, a significant portion of capital expenditures is anticipated to be
funded through new long-term borrowings during the year. Murphy's 2002 Budget
anticipates an increase in long-term debt of approximately $300 million during
the year. Although the Company is actively managing capital expenditures in
light of anticipated lower operating cash flows, it is possible that long-term
debt could exceed the budgeted year-end 2002 levels, especially if cash flows
continue to be adversely affected in upcoming months by low natural gas sales
prices and weak refining and marketing margins such as those experienced in
early 2002.
Forward-Looking Statements
This Form 10-K report, including documents incorporated by reference herein,
contains statements of the Company's expectations, intentions, plans and beliefs
that are forward-looking and are dependent on certain events, risks and
uncertainties that may be outside of the Company's control. These
forward-looking statements are made in reliance upon the safe harbor provisions
of the Private Securities Litigation Reform Act of 1995. Actual results and
developments could differ materially from those expressed or implied by such
statements due to a number of factors, including those described in the context
of such forward-looking statements as well as those contained in the Company's
January 15, 1997 Form 8-K report on file with the U.S. Securities and Exchange
Commission.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of
crude oil, natural gas and petroleum products, and foreign currency exchange
rates. As described in Note A to the consolidated financial statements, Murphy
makes limited use of derivative financial and commodity instruments to manage
risks associated with existing or anticipated transactions.
At December 31, 2001, the Company was a party to interest rate swaps with
notional amounts totaling $100 million that were designed to hedge fluctuations
in cash flows of a similar amount of variable-rate debt. These swaps mature in
2002 and 2004. The swaps require the Company to pay an average interest rate of
6.46% over their composite lives, and at December 31, 2001, the interest rate to
be received by the Company averaged 2.28%. The variable interest rate received
by the Company under each swap contract is repriced quarterly. The Company
considers these swaps to be a hedge against potentially higher future interest
rates. As described in Note K to the consolidated financial statements, the
estimated fair value of these interest rate swaps was a loss of $4.3 million at
December 31, 2001.
At December 31, 2001, 26% of the Company's debt had variable interest rates and
9% was denominated in Canadian dollars. Based on debt outstanding at December
31, 2001, a 10% increase in variable interest rates would have an insignificant
impact on the Company's interest expense for the next 12 months after including
the favorable effect resulting from lower net settlement payments under the
aforementioned interest rate swaps. A 10% increase in the exchange rate of the
Canadian dollar versus the U.S. dollar would increase interest expense in 2002
by $.1 million for debt denominated in Canadian dollars.
Murphy was a party to natural gas price swap agreements at December 31, 2001 for
a total notional volume of 7.7 million British Thermal Units (MMBTU) that are
intended to hedge a portion of the financial exposure of its Meraux, Louisiana
refinery to fluctuations in the future price of natural gas purchased for fuel.
In each month of settlement, the
19
swaps require Murphy to pay an average natural gas price of $2.68 per MMBTU and
to receive the average NYMEX price for the final three trading days of the
month. At December 31, 2001, the estimated fair value of these agreements was
recorded as an asset of $4.3 million. A 10% increase in the average NYMEX price
of natural gas would have increased this asset by $2.1 million, while a 10%
decrease would have reduced the asset by a similar amount.
In addition, the Company was a party to natural gas swap agreements at December
31, 2001 that are intended to hedge the financial exposure of a limited portion
of its U.S. natural gas production to changes in gas sales prices through March
2002. The swaps are for a notional volume that averages 32,000 MMBTU per day in
the first quarter of 2002 and require Murphy to pay the average NYMEX price for
the final trading day of each month and receive a price ranging from $2.54 to
$2.94 per MMBTU. At December 31, 2001, the estimated fair value of these
agreements was recorded as an asset of $.8 million. A 10% increase in the
average NYMEX price of natural gas would have reduced this asset by $.7 million,
while a 10% decrease would have increased the asset by a similar amount.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information required by this item appears on pages F-1 through F-34, which
follow page 23 of this Form 10-K report.
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 on
page 6 of this Form 10-K report. Other information required by this item is
incorporated by reference to the Registrant's definitive Proxy Statement for the
Annual Meeting of Stockholders on May 8, 2002 under the caption "Election of
Directors."
Item 11. EXECUTIVE COMPENSATION
Information required by this item is incorporated by reference to the
Registrant's definitive Proxy Statement for the Annual Meeting of Stockholders
on May 8, 2002 under the captions "Compensation of Directors," "Executive
Compensation," "Option Exercises and Fiscal Year-End Values," "Option Grants,"
"Compensation Committee Report for 2001," "Shareholder Return Performance
Presentation" and "Retirement Plans."
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by this item is incorporated by reference to the
Registrant's definitive Proxy Statement for the Annual Meeting of Stockholders
on May 8, 2002 under the captions "Security Ownership of Certain Beneficial
Owners" and "Security Ownership of Management."
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
20
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1. Financial Statements - The consolidated financial statements of Murphy
Oil Corporation and consolidated subsidiaries are located or begin on
the pages of this Form 10-K report as indicated below.
Page No.
--------
Report of Management F-1
Independent Auditors' Report F-1
Consolidated Statements of Income F-2
Consolidated Balance Sheets F-3
Consolidated Statements of Cash Flows F-4
Consolidated Statements of Stockholders' Equity F-5
Consolidated Statements of Comprehensive Income F-6
Notes to Consolidated Financial Statements F-7
Supplemental Oil and Gas Information (unaudited) F-28
Supplemental Quarterly Information (unaudited) F-34
2. Financial Statement Schedules
Schedule II - Valuation Accounts and Reserves F-35
All other financial statement schedules are omitted because either they
are not applicable or the required information is included in the
consolidated financial statements or notes thereto.
3. Exhibits - The following is an index of exhibits that are hereby filed
as indicated by asterisk (*), that are to be filed by an amendment as
indicated by pound sign (#), or that are incorporated by reference.
Exhibits other than those listed have been omitted since they either
are not required or are not applicable.
Exhibit
No. Incorporated by Reference to
- ------- ----------------------------
3.1 Certificate of Incorporation of Murphy Oil Corporation Exhibit 3.1 of Murphy's Form 10-Q report for the quarterly
as amended, effective May 17, 2001 period ended June 30, 2001
3.2 By-Laws of Murphy Oil Corporation as amended Exhibit 3.2 of Murphy's Form 10-K report for the year
effective February 7, 2001 ended December 31, 2000
4 Instruments Defining the Rights of Security Holders.
Murphy is party to several long-term debt instruments
in addition to the one in Exhibit 4.1, none of which
authorizes securities exceeding 10% of the total
consolidated assets of Murphy and its subsidiaries.
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 Form of Indenture and Form of Supplemental Indenture Exhibits 4.1 and 4.2 of Murphy's Form 8-K report filed
between Murphy Oil Corporation and SunTrust Bank, April 29, 1999 under the Securities Exchange Act of 1934
Nashville, N.A., as Trustee
4.2 Rights Agreement dated as of December 6, 1989 Exhibit 4.3 of Murphy's Form 10-K report for the year
between Murphy Oil Corporation and Harris Trust ended December 31, 1999
Company of New York, as Rights Agent
21
4.3 Amendment No. 1 dated as of April 6, 1998 to Rights Exhibit 3 of Murphy's Form 8-A/A, Amendment No. 1,
Agreement dated as of December 6, 1989 between filed April 14, 1998 under the Securities Exchange
Murphy Oil Corporation and Harris Trust Company of Act of 1934
New York, as Rights Agent
4.4 Amendment No. 2 dated as of April 15, 1999 to Rights Exhibit 4 of Murphy's Form 8-A/A, Amendment No. 2,
Agreement dated as of December 6, 1989 between filed April 19, 1999 under the Securities Exchange
Murphy Oil Corporation and Harris Trust Company of Act of 1934
New York, as Rights Agent
10.1 1992 Stock Incentive Plan as amended May 14, 1997 Exhibit 10.2 of Murphy's Form 10-Q report for the
quarterly period ended June 30, 1997
10.2 Employee Stock Purchase Plan as amended May 10, 2000 Exhibit 99.01 of Murphy's Form S-8 Registration
Statement filed August 4, 2000 under the Securities
Act of 1933
*13 2001 Annual Report to Security Holders including
Narrative to Graphic and Image Material as an appendix
*21 Subsidiaries of the Registrant
*23 Independent Auditors' Consent
*99.1 Undertakings
#99.2 Form 11-K, Annual Report for the fiscal year ended To be filed as an amendment to this Form 10-K report
December 31, 2001 covering the Thrift Plan for Employees not later than 180 days after December 31, 2001
of Murphy Oil Corporation
#99.3 Form 11-K, Annual Report for the fiscal year ended To be filed as an amendment to this Form 10-K report
December 31, 2001 covering the Thrift Plan for Employees not later than 180 days after December 31, 2001
of Murphy Oil USA, Inc. Represented by United Steelworkers
of America, AFL-CIO, Local No. 8363
#99.4 Form 11-K, Annual Report for the fiscal year ended To be filed as an amendment to this Form 10-K report
December 31, 2001 covering the Thrift Plan for Employees not later than 180 days after December 31, 2001
of Murphy Oil USA, Inc. Represented by International Union
of Operating Engineers, AFL-CIO, Local No. 305
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the quarter ended December 31,
2001.
22
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
MURPHY OIL CORPORATION
By CLAIBORNE P. DEMING Date: March 22, 2002
------------------------------ ------------------------
Claiborne P. Deming, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below on March 22, 2002 by the following persons on behalf of
the registrant and in the capacities indicated.
R. MADISON MURPHY WILLIAM C. NOLAN JR.
- ---------------------------------------- ------------------------------
R. Madison Murphy, Chairman and Director William C. Nolan Jr., Director
CLAIBORNE P. DEMING WILLIAM L. ROSOFF
- ---------------------------------------- ---------------------------
Claiborne P. Deming, President and Chief William L. Rosoff, Director
Executive Officer and Director
(Principal Executive Officer)
B. R. R. BUTLER DAVID J. H. SMITH
------------------------- ---------------------------
B. R. R. Butler, Director David J. H. Smith, Director
GEORGE S. DEMBROSKI CAROLINE G. THEUS
----------------------------- ---------------------------
George S. Dembroski, Director Caroline G. Theus, Director
H. RODES HART STEVEN A. COSSE'
----------------------- ---------------------------------------
H. Rodes Hart, Director Steven A. Cosse', Senior Vice President
and General Counsel
(Principal Financial Officer)
ROBERT A. HERMES JOHN W. ECKART
-------------------------- ------------------------------
Robert A. Hermes, Director John W. Eckart, Controller
(Principal Accounting Officer)
MICHAEL W. MURPHY
---------------------------
Michael W. Murphy, Director
23
REPORT OF MANAGEMENT
The management of Murphy Oil Corporation is responsible for the preparation and
integrity of the accompanying consolidated financial statements and other
financial data. The statements were prepared in conformity with generally
accepted U.S. 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. The Company's audit staff
independently and systematically evaluates and formally reports on the adequacy
and effectiveness of the internal control system.
Our independent auditors, KPMG LLP, have audited the consolidated financial
statements. Their audit was conducted in accordance with auditing standards
generally accepted in the United States of America and provides an independent
opinion about the fair presentation of the consolidated financial statements.
When performing their audit, KPMG LLP considers the Company's internal control
structure to the extent they deem necessary to issue their opinion on the
financial statements. The Board of Directors appoints the independent auditors;
ratification of the appointment is solicited annually from the shareholders.
The Board of Directors appoints an Audit Committee annually to implement and to
support the Board's oversight function of the Company's financial reporting,
accounting policies, internal controls and independent and objective outside
auditors. 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 and
discuss the adequacy and effectiveness of the Company's internal controls, the
quality and clarity of its financial reporting, and the scope and results of
independent and internal audits, and to fulfill other responsibilities included
in the Committee's Charter dated May 10, 2000. The independent auditors and the
Company's audit staff have unrestricted access to the Committee, without
management presence, to discuss audit findings and other financial matters.
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders of Murphy Oil Corporation:
We have audited the accompanying consolidated balance sheets of Murphy Oil
Corporation and Consolidated Subsidiaries as of December 31, 2001 and 2000, and
the related consolidated statements of income, comprehensive income,
stockholders' equity and cash flows for each of the years in the three-year
period ended December 31, 2001. 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 auditing standards generally accepted
in the United States of America. 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, 2001 and 2000, and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note B to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities.
Shreveport, Louisiana /s/ KPMG LLP
February 1, 2002
F-1
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31 (Thousands of dollars except per share amounts) 2001 2000 1999
---- ---- ----
Revenues
Crude oil and natural gas sales $ 832,510 751,498 470,643
Petroleum product sales 2,783,617 2,731,988 1,515,537
Crude oil trading sales 605,143 1,041,524 705,969
Other operating revenues 245,551 89,331 59,934
Interest and other nonoperating revenues 11,688 24,824 4,358
----------- ---------- ----------
Total revenues 4,478,509 4,639,165 2,756,441
----------- ---------- ----------
Costs and Expenses
Crude oil, products and related operating 3,456,021 3,704,936 2,198,701
expenses
Exploration expenses, including undeveloped 156,919 125,629 70,557
lease amortization
Selling and general expenses 97,835 85,474 81,817
Depreciation, depletion and amortization 229,222 213,539 205,077
Amortization of goodwill 3,120 -- --
Impairment of properties 10,478 27,916 --
Provision for reduction in force -- -- 1,513
Interest expense 39,289 29,936 28,139
Interest capitalized (20,283) (13,599) (7,865)
----------- ---------- ----------
Total costs and expenses 3,972,601 4,173,831 2,577,939
----------- ---------- ----------
Income before income taxes and cumulative
effect of accounting change 505,908 465,334 178,502
Income tax expense 175,005 159,773 58,795
----------- ---------- ----------
Income before cumulative effect of accounting change 330,903 305,561 119,707
Cumulative effect of accounting change, net of tax (Note B) -- (8,733) --
----------- ---------- ----------
Net Income $ 330,903 296,828 119,707
=========== ========== ==========
Income (Loss) per Common Share - Basic
Before cumulative effect of accounting change $ 7.32 6.78 2.66
Cumulative effect of accounting change -- (.19) --
----------- ---------- ----------
Net Income - Basic 7.32 6.59 2.66
=========== ========== ==========
Income (Loss) per Common Share - Diluted
Before cumulative effect of accounting change $ 7.26 6.75 2.66
Cumulative effect of accounting change -- (.19) --
----------- ---------- ----------
Net Income - Diluted 7.26 6.56 2.66
=========== ========== ==========
Average Common shares outstanding - basic 45,221,472 45,031,665 44,970,457
Average Common shares outstanding - diluted 45,590,999 45,239,706 45,030,225
See notes to consolidated financial statements, page F-7.
F-2
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31 (Thousands of dollars) 2001 2000
---- ----
Assets
Current assets
Cash and cash equivalents $ 82,652 132,701
Accounts receivable, less allowance for doubtful accounts
of $11,263 in 2001 and $10,208 in 2000 262,022 469,616
Inventories, at lower of cost or market
Crude oil and blend stocks 38,917 47,875
Finished products 85,133 68,464
Materials and supplies 49,098 48,416
Prepaid expenses 61,062 23,949
Deferred income taxes 19,777 25,916
---------- ----------
Total current assets 598,661 816,937
Property, plant and equipment, at cost less accumulated depreciation,
depletion and amortization of $3,277,673 in 2001 and $3,144,369 in 2000 2,525,807 2,184,719
Goodwill, net 50,412 48,396
Deferred charges and other assets 84,219 84,301
---------- ----------
Total assets $3,259,099 3,134,353
========== ==========
Liabilities and Stockholders' Equity
Current liabilities
Current maturities of long-term debt $ 48,250 37,242
Accounts payable 325,323 528,416
Income taxes 48,378 68,343
Other taxes payable 86,844 65,262
Other accrued liabilities 51,262 45,964
---------- ----------
Total current liabilities 560,057 745,227
Notes payable 416,061 398,375
Nonrecourse debt of a subsidiary 104,724 126,384
Deferred income taxes 302,868 229,968
Accrued dismantlement costs 160,764 160,049
Accrued major repair costs 44,570 34,302
Deferred credits and other liabilities 171,892 180,488
Stockholders' equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued -- --
Common Stock, par $1.00, authorized 200,000,000 shares at December 31, 2001
and 80,000,000 shares at December 31, 2000, issued 48,775,314 shares 48,775 48,775
Capital in excess of par value 527,126 514,474
Retained earnings 1,096,567 833,490
Accumulated other comprehensive loss (83,309) (38,266)
Unamortized restricted stock awards (968) (1,410)
Treasury stock (90,028) (97,503)
---------- ----------
Total stockholders' equity 1,498,163 1,259,560
---------- ----------
Total liabilities and stockholders' equity 3,259,099 $3,134,353
========== ==========
See notes to consolidated financial statements, page F-7.
F-3
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31 (Thousands of dollars) 2001 2000 1999
---- ---- ----
Operating Activities
Income before cumulative effect of accounting change $ 330,903 305,561 119,707
Adjustments to reconcile above income to net cash provided
by operating activities
Depreciation, depletion and amortization 229,222 213,539 205,077
Impairment of properties 10,478 27,916 --
Provisions for major repairs 21,070 22,761 18,721
Expenditures for major repairs and dismantlement costs (16,395) (16,603) (44,096)
Dry hole costs 82,825 65,987 32,422
Amortization of undeveloped leases 23,154 14,076 10,968
Amortization of goodwill 3,120 -- --
Deferred and noncurrent income tax charges 80,052 63,431 38,027
Pretax gains from disposition of assets (105,504) (4,010) (11,940)
Net (increase) decrease in noncash operating working capital
excluding acquisition of Beau Canada Exploration Ltd. (27,951) 66,002 (35,159)
Cumulative effect of accounting change on working capital -- (11,170) --
Other operating activities - net 4,730 261 7,984
--------- --------- ---------
Net cash provided by operating activities 635,704 747,751 341,711
--------- --------- ---------
Investing Activities
Property additions and dry hole costs (813,500) (512,331) (359,438)
Acquisition of Beau Canada Exploration Ltd., net of cash acquired -- (127,476) --
Proceeds from sale of property, plant and equipment 172,972 20,705 40,871
Other investing activities - net (1,410) 391 (3,532)
--------- --------- ---------
Net cash required by investing activities (641,938) (618,711) (322,099)
--------- --------- ---------
Financing Activities
Additions to notes payable 87,000 175,000 247,776
Reductions of notes payable (62,214) (124,254) (190,806)
Additions to nonrecourse debt of a subsidiary 1,241 -- --
Reductions of nonrecourse debt of a subsidiary (15,499) (6,207) (5,120)
Proceeds from exercise of stock options
and employee stock purchase plans 18,864 3,769 2,269
Cash dividends paid (67,826) (65,294) (62,950)
Other financing activities - net (3,050) (7,894) (4,011)
--------- --------- ---------
Net cash required by financing activities (41,484) (24,880) (12,842)
--------- --------- ---------
Effect of exchange rate changes on cash and cash equivalents (2,331) (5,591) (909)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents (50,049) 98,569 5,861
Cash and cash equivalents at January 1 132,701 34,132 28,271
--------- --------- ---------
Cash and cash equivalents at December 31 $ 82,652 132,701 34,132
========= ========= =========
See notes to consolidated financial statements, page F-7.
F-4
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years Ended December 31 (Thousands of dollars) 2001 2000 1999
---- ---- ----
Cumulative Preferred Stock - par $100, authorized
400,000 shares, none issued $ -- -- --
---------- --------- ---------
Common Stock - par $1.00, authorized 200,000,000 shares
at December 31, 2001 and 80,000,000 shares at
December 31, 2000 and 1999, issued 48,775,314 shares at
beginning and end of each year 48,775 48,775 48,775
---------- --------- ---------
Capital in Excess of Par Value
Balance at beginning of year 514,474 512,488 510,116
Exercise of stock options, net of income taxes 10,440 1,749 797
Restricted stock transactions 1,272 (202) 1,344
Sale of stock under employee stock purchase plans 940 439 231
---------- --------- ---------
Balance at end of year 527,126 514,474 512,488
---------- --------- ---------
Retained Earnings
Balance at beginning of year 833,490 601,956 545,199
Net income for the year 330,903 296,828 119,707
Cash dividends - $1.50 per share in 2001, $1.45 per share in 2000
and $1.40 per share in 1999 (67,826) (65,294) (62,950)
---------- --------- ---------
Balance at end of year 1,096,567 833,490 601,956
---------- --------- ---------
Accumulated Other Comprehensive Loss
Balance at beginning of year (38,266) (4,984) (23,520)
Foreign currency translation gains (49,596) (33,282) 18,536
(losses)
Cash flow hedging gains, net of income taxes 4,553 -- --
---------- --------- ---------
Balance at end of year (83,309) (38,266) (4,984)
---------- --------- ---------
Unamortized Restricted Stock Awards
Balance at beginning of year (1,410) (2,328) (2,361)
Amortization, forfeitures and changes in price of Common Stock 442 918 33
---------- --------- ---------
Balance at end of year (968) (1,410) (2,328)
---------- --------- ---------
Treasury Stock
Balance at beginning of year (97,503) (98,735) (99,976)
Exercise of stock options 6,833 1,140 704
Awarded restricted stock, net of (9) (349) --
forfeitures
Sale of stock under employee stock purchase plans 651 441 537
---------- --------- ---------
Balance at end of year - 3,444,234 shares of Common
Stock in 2001, 3,729,769 shares in 2000 and
3,777,319 shares in 1999 (90,028) (97,503) (98,735)
---------- --------- ---------
Total Stockholders' Equity $1,498,163 1,259,560 1,057,172
========== ========= =========
See notes to consolidated financial statements, page F-7.
F-5
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Years Ended December 31 (Thousands of dollars) 2001 2000 1999
---- ---- ----
Net income $330,903 296,828 119,707
Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative gains 26 -- --
Reclassification adjustments (2,115) -- --
-------- ------- ------
Total cash flow hedges (2,089) -- --
Net gain (loss) from foreign currency translation (49,596) (33,282) 18,536
-------- ------- ------
Other comprehensive income (loss) before
cumulative effect of accounting change (51,685) (33,282) 18,536
Cumulative effect of accounting change (Note B) 6,642 -- --
-------- ------- -------
Other comprehensive income (loss) (45,043) (33,282) 18,536
-------- ------- ------
Comprehensive Income $285,860 263,546 138,243
-------- ------- -------
See notes to consolidated financial statements, page F-7.
F-6
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note A - Significant Accounting Policies
NATURE OF BUSINESS - Murphy Oil Corporation is an international oil and gas
company that conducts its business through various operating subsidiaries. The
Company produces oil and natural gas in the United States, Canada, the United
Kingdom, and Ecuador, and conducts exploration activities worldwide. The Company
has an interest in a Canadian synthetic oil operation, owns two petroleum
refineries in the United States and has an interest in a refinery in the United
Kingdom. Murphy markets petroleum products under various brand names and to
unbranded wholesale customers in the United States and the United Kingdom.
PRINCIPLES OF CONSOLIDATION - The consolidated financial statements include the
accounts of Murphy Oil Corporation and all majority-owned subsidiaries.
Investments in affiliates in which the Company owns from 20% to 50% are
accounted for by the equity method. Other investments are generally carried at
cost. All significant intercompany accounts and transactions have been
eliminated.
REVENUE RECOGNITION - Revenues associated with sales of refined products and the
Company's share of crude oil production are recorded when title passes to the
customer. The Company uses the sales method to record revenues associated with
oil and natural gas production. The Company records a liability for natural gas
balancing when the Company has sold more than its working interest share of
natural gas production and the estimated remaining reserves make it doubtful
that partners can recoup their share of production from the field. At December
31, 2001 and 2000, the liabilities for gas balancing arrangements were
immaterial. Excise taxes collected on sales of refined products and remitted to
governmental agencies are not included in revenues or in costs and expenses.
CASH EQUIVALENTS - Short-term investments, which include government securities
and other instruments with government securities as collateral, that have a
maturity of three months or less from the date of purchase are classified as
cash equivalents.
PROPERTY, PLANT AND EQUIPMENT - The Company uses the successful efforts method
to account for exploration and development expenditures. Leasehold acquisition
costs are capitalized. If proved reserves are found on an undeveloped property,
leasehold cost is transferred to proved properties. Costs of undeveloped leases
are generally expensed over the life of the leases. Cost of exploratory drilling
is initially capitalized but is subsequently expensed if proved reserves are not
found. Other exploratory costs are charged to expense as incurred. Development
costs, including unsuccessful development wells, are capitalized.
Oil and gas properties are evaluated by field for potential impairment; other
properties are evaluated on a specific asset basis or in groups of similar
assets, as applicable. An impairment is recognized when the estimated
undiscounted future net cash flows of an evaluated asset are less than its
carrying value.
Depreciation and depletion of producing oil and gas properties are recorded
based on units of production. Unit rates are computed for unamortized
exploration drilling and development costs using proved developed reserves and
for unamortized leasehold costs using all proved reserves. As more fully
described on page F-28 of this Form 10-K report, proved reserves are estimated
by the Company's engineers and are subject to future revisions based on
availability of additional information. Estimated dismantlement, abandonment and
site restoration costs, net of salvage value, are generally recognized using the
units of production method and are included in depreciation expense. Costs for
future dismantlement, abandonment and site restoration are estimated by the
Company's engineers using existing regulatory requirements and anticipated
future inflation rates. Refineries and certain marketing facilities are
depreciated primarily using the composite straight-line method with depreciable
lives ranging from 16 to 25 years. Gasoline stations and other properties are
depreciated over 3 to 20 years by individual unit on the straight-line method.
Gains and losses on disposals or retirements that are significant or include an
entire depreciable or depletable property unit are included in income. Actual
costs of dismantling oil and gas production facilities and site restoration are
charged against the related liability. All other dispositions, retirements or
abandonments are reflected in accumulated depreciation, depletion and
amortization.
F-7
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Murphy accrues in advance for estimated costs of major repairs by recording
monthly expense provisions for turnarounds of refineries and a synthetic oil
upgrading facility. Future major repair costs are estimated by the Company's
engineers. Actual costs incurred are charged against the accrued liability. All
other maintenance and repairs are expensed. Renewals and betterments are
capitalized.
INVENTORIES - Inventories of crude oil other than refinery feedstocks are valued
at the lower of cost, generally applied on a first-in first-out (FIFO) basis, or
market. Refinery inventories of crude oil and other feedstocks and finished
product inventories are valued at the lower of cost, generally applied on a
last-in first-out (LIFO) basis, or market. Materials and supplies are valued at
the lower of average cost or estimated value.
GOODWILL - The excess of the purchase price over the fair value of net assets
acquired associated with the purchase of Beau Canada Exploration Ltd. (Beau
Canada) was recorded as goodwill. Through 2001, goodwill was amortized on a
straight-line basis over 15 years, and its recoverability was assessed by
determining whether future goodwill amortization can be recovered through
undiscounted future net cash flows for western Canadian oil and gas properties.
Effective January 1, 2002, in accordance with Statement of Financial Accounting
Standards (SFAS) No.142, "Goodwill and Other Intangible Assets", goodwill can no
longer be amortized. SFAS 142 requires an annual assessment of recoverability of
the carrying value of goodwill. Beginning in 2002, the Company will assess
goodwill recoverability by comparing the fair value of net assets for
conventional oil and natural gas properties in Canada with the carrying value of
these net assets, including goodwill. Should this assessment indicate that
goodwill is not fully recoverable, an impairment charge to write down the
carrying value of goodwill must be recorded.
ENVIRONMENTAL LIABILITIES - A provision for environmental obligations is charged
to expense when 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 liability. Environmental remediation
liabilities have not been discounted for the time value of future expected
payments. Environmental expenditures that have future economic benefit are
capitalized.
INCOME TAXES - The Company accounts for income taxes using the asset and
liability method. Under this method, income taxes are provided for amounts
currently payable, and for amounts deferred as tax assets and liabilities based
on differences between the financial statement carrying amounts and the tax
bases of existing assets and liabilities.
Deferred income taxes are measured using the enacted tax rates that are assumed
will be in effect when the differences reverse. Petroleum revenue taxes are
provided using the estimated effective tax rate over the life of applicable U.K.
properties. The Company uses the deferral method to account for Canadian
investment tax credits associated with the Hibernia and Terra Nova oil fields.
FOREIGN CURRENCY - Local currency is the functional currency used for recording
operations in Canada and Spain and the majority of activities in the United
Kingdom. The U.S. dollar is the functional currency used to record all other
operations. Gains or losses from translating foreign functional currency into
U.S. dollars are included in Accumulated Other Comprehensive Loss on the
Consolidated Balance Sheets. Exchange gains or losses from transactions in a
currency other than the functional currency are included in income.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Effective January 1, 2001, the
Company adopted SFAS 133, as amended by SFAS 138. See also Notes B and K for
further information about the Company's derivative instruments. The fair value
of a derivative instrument is recognized as an asset or liability in the
Company's Consolidated Balance Sheet. Upon entering into a derivative contract,
the Company may designate the derivative as either a fair value hedge or a cash
flow hedge, or decide that the contract is not a hedge, and thenceforth, mark
the contract to market through earnings. The Company documents the relationship
between the derivative instrument designated as a hedge and the hedged items, as
well as its objective for risk management and strategy for use of the hedging
instrument to manage the risk. Derivative instruments designated as fair value
or cash flow hedges are linked to specific assets and liabilities or to specific
firm commitments or forecasted transactions. The Company assesses at inception,
and on an ongoing basis, whether a derivative instrument used as a hedge is
highly effective in offsetting changes in the fair value or cash flows of the
hedged item. A derivative that is not a highly effective hedge does not qualify
for hedge accounting. Changes in the fair value of a qualifying fair value hedge
are recorded in earnings along
F-8
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
with the gain or loss on the hedged item. Changes in the fair value of a
qualifying cash flow hedge are recorded in other comprehensive income, until
earnings are affected by the cash flows of the hedged item. When the cash flow
of the hedged item is recognized in the Statement of Income, the fair value of
the associated cash flow hedge is reclassified from other comprehensive income
into earnings.
Ineffective portions of a cash flow hedging derivative's change in fair value
are recognized currently in earnings. If a derivative instrument no longer
qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or
loss that was recorded in other comprehensive income is recognized immediately
in earnings.
NET INCOME PER COMMON SHARE - Basic income per Common share is computed by
dividing net income for each reporting period by the weighted average number of
Common shares outstanding during the period. Diluted income per Common share is
computed by dividing net income for each reporting period by the weighted
average number of Common shares outstanding during the period plus the effects
of potentially dilutive Common shares.
USE OF ESTIMATES - In preparing the financial statements of the Company in
conformity with accounting principles generally accepted in the United States of
America, management has made a number of estimates and assumptions related to
the reporting of assets, liabilities, revenues, and expenses and the disclosure
of contingent assets and liabilities. Actual results may differ from the
estimates.
Note B - New Accounting Principles and Recent Accounting Pronouncements
Effective January 1, 2001, Murphy was required to adopt SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended by
SFAS No. 138. Under SFAS Nos. 133/138, Murphy records the fair values of its
derivative instruments as either assets or liabilities. Adoption of SFAS Nos.
133/138 resulted in a transition adjustment gain to Accumulated Other
Comprehensive Loss (AOCL) of $6.6 million, net of $2.8 million in income taxes,
for the cumulative effect on prior years; there was no cumulative effect on
earnings. Excluding the transition adjustment, the effect of this accounting
change decreased AOCL for the year ended December 31, 2001 by $2.1 million, net
of $.4 million in income taxes, and decreased net income for the year by $.1
million, net of taxes. During the year ended December 31, 2001, losses of $2.1
million, net of $.8 million in income taxes, associated with the transition
adjustment were reclassified from AOCL to earnings.
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
141, "Business Combinations," requiring that all future business combinations be
accounted for using the purchase method of accounting and that certain acquired
intangible assets in a business combination be recognized and reported as assets
apart from goodwill. The Company adopted SFAS No. 141 immediately.
In 2000, Murphy adopted the revenue recognition guidance in the Securities and
Exchange Commission's Staff Accounting Bulletin 101. As a result of the change,
Murphy records revenues related to its crude oil as the oil is sold, and carries
its unsold crude oil production at cost rather than market value as in the past.
Consequently, Murphy recorded a transition adjustment of $8,733,000, net of
income tax benefits of $3,886,000, for the cumulative effect on prior years.
Excluding the cumulative effect transition adjustment, this accounting change
increased income in 2000 by $1,145,000. The transition adjustment included a
cumulative reduction of prior years' revenue of $20,591,000. Pro forma net
income for the years ended December 31, 2000 and 1999, assuming that the new
revenue recognition method had been applied retroactively in each year, was as
follows.
(Thousands of dollars except per share data) 2000 1999
---- ----
Net income - As reported $296,828 119,707
Pro forma 305,561 111,336
Net income per share - As reported, basic $6.59 2.66
Pro forma, basic 6.78 2.48
As reported, diluted 6.56 2.66
Pro forma, diluted 6.75 2.47
F-9
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets," which requires that amortization of goodwill be replaced with annual
tests for impairment and that intangible assets other than goodwill be amortized
over their useful lives. The Company will adopt SFAS No. 142 on January 1, 2002.
The Company's unamortized goodwill of $50,412,000 at December 31, 2001 will be
subject to the transition provisions of SFAS No. 142.
In July 2001, the FASB also issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," which will require the Company to record a liability
equal to the fair value of the estimated cost to retire an asset. The asset
retirement liability must be recorded in the period in which the obligation
meets the definition of a liability, which is generally when the asset is placed
in service. When the liability is initially recorded, the Company will increase
the carrying amount of the related long-lived asset by an amount equal to the
original liability. The liability is accreted to its present value each period,
and the capitalized cost is depreciated over the useful life of the related
long-lived asset. Upon adoption of SFAS No. 143 on January 1, 2003, the Company
will recognize transition adjustments for existing asset retirement obligations,
long-lived assets and accumulated depreciation, all net of related income tax
effects, as the cumulative effect of a change in accounting principle. After
adoption, any difference between costs incurred upon settlement of an asset
retirement obligation and the recorded liability will be recognized as a gain or
loss in the Company's earnings.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," which supercedes SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"
and the accounting and reporting provisions of APB Opinion No. 30, "Reporting
the Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual, and Infrequently Occurring Events and
Transactions." The Company will adopt the provisions of SFAS No. 144 effective
January 1, 2002, and its provisions are generally to be applied prospectively.
At this time, it is not practicable to reasonably estimate the impact of
adopting SFAS Nos. 142, 143 and 144 on the Company's financial statements,
including whether any transitional goodwill impairment losses will be required
to be recognized as the cumulative effect of a change in accounting principle.
Note C - Acquisition of Beau Canada Exploration Ltd.
In November 2000, Murphy acquired Beau Canada, an independent oil and natural
gas company that primarily owned exploration licenses and producing natural gas
and heavy oil fields in western Canada. The acquisition has been accounted for
as a purchase. Beau Canada's operations subsequent to the acquisition date have
been included in the Company's consolidated financial statements. The Company
paid net cash of $127,476,000 to purchase all of Beau Canada's common stock at a
price of approximately $1.44 a share.
The Company recorded property, plant and equipment of $260,000,000 associated
with the purchase of Beau Canada. The Company valued the property, plant and
equipment acquired using both proved and certain probable reserves as estimated
by the Company's engineers, and an estimate of future oil and natural gas sales
prices based on the then prevailing pricing environment for the projected timing
of future production.
The Company also assumed debt in the acquisition of $124,227,000 that was repaid
by December 31, 2000 through issuance of a structured loan (see Note F). As
subsequently adjusted in 2001, Murphy recorded goodwill of $56,280,000
associated with the Beau Canada acquisition, primarily due to the purchase price
being greater than the fair value of the net assets acquired and deferred income
tax liabilities required to be established in recording the acquisition.
F-10
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table reflects the unaudited results of operations on a pro forma
basis as if the Beau Canada acquisition had been completed at the beginning of
2000 and 1999. The pro forma financial information is not necessarily indicative
of the operating results that would have occurred had the acquisition been
consummated as of the dates indicated, nor is it necessarily indicative of
future operating results.
Years Ended December 31,
(Thousands of dollars except per share data) 2000 1999
---- ----
Pro forma revenues $4,727,574 2,830,973
Pro forma net income 303,479 121,011
Pro forma net income per Common share - diluted 6.71 2.69
Note D - Property, Plant and Equipment
December 31, 2001 December 31, 2000
--------------------- ---------------------
(Thousands of dollars) Cost Net Cost Net
---------- --------- --------- ---------
Exploration and production $4,553,034 1,885,124* 4,156,422 1,616,424*
Refining 795,742 319,813 710,623 256,469
Marketing 377,721 289,344 307,429 224,677
Transportation 33,396 4,314 111,409 62,210
Corporate and other 43,587 27,212 43,205 24,939
---------- --------- --------- ---------
$5,803,480 2,525,807 5,329,088 2,184,719
========== ========= ========= =========
*Includes $20,174 in 2001 and $17,370 in 2000 related to administrative assets
and support equipment.
In the 2001 and 2000 Consolidated Statements of Income, the Company recorded
noncash charges of $10,478,000 and $27,916,000 respectively, for impairment of
certain properties. After related income tax benefits, these write-downs reduced
net income by $6,811,000 in 2001 and $17,817,000 in 2000. The charges related to
natural gas fields in the Gulf of Mexico and Canadian heavy oil properties. The
U.S. impairments were all caused by downward reserve revisions for poor well
performance of natural gas fields. The Canadian heavy oil impairment was due to
a downward reserve revision for one field and high operating costs on another
field. The carrying value of impaired properties were reduced to the asset's
fair value based on projected future discounted net cash flows, using the
Company's estimate of future commodity prices.
Note E - Financing Arrangements
At December 31, 2001, the Company had three unused committed credit facilities
with a major banking consortium totaling US $450,000,000. The Company and a
subsidiary may borrow under a $150,000,000 revolving credit agreement maturing
in December 2006. Additionally, the Company and the subsidiary have available a
$150,000,000 one-year revolving credit agreement maturing in December 2002 with
an option to convert any outstanding amounts to a one-year term loan at
maturity. The Company's Canadian subsidiary has available a $150,000,000
one-year revolving agreement with an option to convert any outstanding amounts
to a five-year term at maturity. The two one-year revolving credit agreements
are extendable for up to one year upon approval of a majority of the banking
consortium. U.S. dollar and Canadian dollar commercial paper totaling an
equivalent US $96,476,000 at December 31, 2001 was outstanding and classified as
nonrecourse debt. This outstanding debt is supported by a similar amount of
credit facilities with major banks based on loan guarantees from the Canadian
government. Depending on the credit facility, borrowings bear interest at prime
or varying cost of fund options. Facility fees are due at varying rates on the
commitments. The Company also had uncommitted lines of credit with banks at
December 31, 2001 totaling an equivalent US $192,602,000 for a combination of
U.S. dollar and Canadian dollar borrowings. At December 31, 2001, US $50,000,000
of the uncommitted lines was outstanding and classified as long-term debt based
on the ability of the Company to replace this debt with borrowings under the
existing long-term credit facilities. The Company has a shelf registration
statement on file with the U.S. Securities and Exchange Commission that permits
the offer and sale of up to $1 billion in debt and equity securities. No
securities had been issued under this shelf registration as of December 31,
2001.
F-11
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note F - Long-term Debt
December 31 (Thousands of dollars) 2001 2000
---- ----
Notes payable
7.05% notes, due 2029, net of unamortized discount of $2,539
at December 31, 2001 $ 247,461 247,369
6.23% structured loan, due 2002-2005 149,832 175,000
Notes payable to bank, 2.30% to 2.90%,due 2002 50,000 -
Other, 6% to 8%, due 2002-2021 1,187 1,244
--------- -------
Total notes payable 448,480 423,613
--------- -------
Nonrecourse debt of a subsidiary
Guaranteed credit facilities with banks
Commercial paper, 2.075% to 2.275%, $27,076 payable in
Canadian dollars, supported by credit facility, due 2002-2008 96,476 110,633
Loans payable to Canadian government interest free, payable in
Canadian dollars, due 2002-2008 24,079 27,755
--------- -------
Total nonrecourse debt of a subsidiary 120,555 138,388
--------- -------
Total debt including current maturities 569,035 562,001
Current maturities (48,250) (37,242)
--------- -------
Total long-term debt $ 520,785 524,759
========= =======
Maturities for the four years after 2002 are: $50,536,000 in 2003, $52,488,000
in 2004, $62,194,000 in 2005 and $65,879,000 in 2006.
Notes payable to bank due in 2002 have been classified as long-term debt since
the borrowing is capable of being refinanced under an existing long-term credit
facility.
With the support of a major bank consortium, the structured loan was borrowed by
a Canadian subsidiary in December 2000 to replace temporary financing of the
Beau Canada acquisition. The 6.23% fixed-rate loan is reduced in quarterly
installments. Payment of interest under the loan has been guaranteed by the
Company.
The nonrecourse guaranteed credit facilities were arranged to finance certain
expenditures for the Hibernia oil field. Subject to certain conditions and
limitations, the Canadian government has unconditionally guaranteed repayment of
amounts drawn under the facilities to lenders having qualifying Participation
Certificates. Additionally, payment is secured by a debenture that mortgages the
Company's share of the Hibernia properties and the production therefrom.
Recourse of the lenders is limited to the Canadian government's guarantee; the
government's recourse to the Company is limited, subject to certain covenants,
to Murphy's interest in the assets and operations of Hibernia. The Company has
borrowed the maximum amount available under the Primary Guarantee Facility.
Beginning in 2001, the amount guaranteed is reduced quarterly by the greater of
30% of Murphy's after-tax free cash flow from Hibernia or 1/32 of the original
total guarantee. A guarantee fee of .5% is payable annually in arrears to the
Canadian government.
The interest-free loans from the Canadian government were also used to finance
expenditures for the Hibernia field. The outstanding balance is to be repaid in
equal annual installments through 2008.
Note G - Provision for Reduction in Force
In 1999 the Company offered enhanced voluntary retirement benefits to eligible
exploration, production and administrative employees in its New Orleans and
Calgary offices and severed certain other employees at these locations. The
voluntary retirements and severances reduced the Company's workforce by 31
employees, and a charge of $1,513,000 was recorded to income in 1999. The
provision included additional defined benefit plan expense of $1,041,000 and
severance and other costs of $472,000, the latter of which was essentially all
paid during 1999.
F-12
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note H - Income Taxes
The components of income before income taxes and cumulative effect of accounting
change for each of the three years ended December 31, 2001 and income tax
expense (benefit) attributable thereto were as follows.
(Thousands of dollars) 2001 2000 1999
---- ---- ----
Income before income taxes and cumulative
effect of accounting change
United States $161,056 102,519 15,074
Foreign 344,852 362,815 163,428
-------- ------- -------
$505,908 465,334 178,502
======== ======= =======
Income tax expense (benefit) before
cumulative effect of accounting change
Federal - Current/1/ $ 30,153 19,215 (13,497)
Deferred 33,167 5,665 1,597
Noncurrent (4,136) (2,261) 16,366
-------- ------- -------
59,184 22,619 4,466
-------- ------- -------
State - Current 4,710 3,129 1,342
-------- ------- -------
Foreign - Current 60,090 76,184 40,726
Deferred/2/ 50,916 59,776 11,165
Noncurrent 105 (1,935) 1,096
-------- ------- -------
111,111 134,025 52,987
-------- ------- -------
Total $175,005 159,773 58,795
======== ======= =======
/1/Net of benefit of $3,150 in 2000 for alternative minimum tax credits.
/2/Net of benefits of $5,540 in 2001 for a reduction in a provincial tax rate in
Canada and $609 in 1999 for a reduction in the U.K. tax rate.
In 2001, income tax benefits attributable to employee stock option transactions
of $1,685,000 were included in Capital in Excess of Par Value in the
Consolidated Balance Sheet and income tax charges of $2,447,000 relating to
derivatives were included in AOCL.
Total income tax expense in 2000, including tax benefits associated with the
cumulative effect of accounting change, was $155,887,000.
Noncurrent taxes, classified in the Consolidated Balance Sheets as a component
of Deferred Credits and Other Liabilities, relate primarily to matters not
resolved with various taxing authorities.
The following table reconciles income taxes based on the U.S. statutory tax rate
to the Company's income tax expense before cumulative effect of accounting
change.
(Thousands of dollars) 2001 2000 1999
---- ---- ----
Income tax expense based on the
U.S. statutory tax rate $177,068 162,867 62,475
Foreign income subject to foreign taxes
at a rate different than the U.S.
statutory rate 2,498 13,010 1,988
State income taxes 3,062 2,034 872
Settlement of U.S. taxes (1,446) (17,016) (5,000)
Settlement of foreign taxes (1,915) - -
Reduction in provincial tax rate in Canada (5,540) - -
Other, net 1,278 (1,122) (1,540)
-------- ------- ------
Total $175,005 159,773 58,795
======== ======= ======
F-13
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
An analysis of the Company's deferred tax assets and deferred tax liabilities at
December 31, 2001 and 2000 showing the tax effects of significant temporary
differences follows.
(Thousands of dollars) 2001 2000
---- ----
Deferred tax assets
Property and leasehold costs $ 72,390 70,570
Liabilities for dismantlements and major repairs 68,755 63,754
Postretirement and other employee benefits 29,345 27,950
Foreign tax operating losses 26,844 27,888
Other deferred tax assets 22,029 26,681
--------- -------
Total gross deferred tax assets 219,363 216,843
Less valuation allowance (67,745) (60,958)
--------- --------
Net deferred tax assets 151,618 155,885
--------- --------
Deferred tax liabilities
Property, plant and equipment (53,494) (45,860)
Accumulated depreciation, depletion and amortization (343,925) (285,444)
Other deferred tax liabilities (37,290) (28,633)
--------- --------
Total gross deferred tax liabilities (434,709) (359,937)
--------- --------
Net deferred tax liabilities $(283,091) (204,052)
========= ========
At December 31, 2001, the Company had tax losses and other carryforwards of
$98,231,000 associated with its operations in Ecuador. The losses, available
only to Ecuador operations, have a carryforward period of no more than five
years, with certain losses limited to 25% of each year's taxable income. These
losses expire in 2002 to 2007.
In management's judgment, the net deferred tax assets in the preceding table
will more likely than not be realized as reductions of future taxable income or
by utilizing available tax planning strategies. The valuation allowance for
deferred tax assets relates primarily to tax assets arising in foreign tax
jurisdictions, and in the judgment of management, these tax assets are not
likely to be realized. The valuation allowance increased $6,787,000 and
$3,570,000 in 2001 and 2000, respectively; the change in each year primarily
offset the change in certain deferred tax assets. Any subsequent reductions of
the valuation allowance will be reported as reductions of tax expense assuming
no offsetting change in the deferred tax asset.
The Company has not recorded a deferred tax liability of $29,463,000 related to
undistributed earnings of certain foreign subsidiaries at December 31, 2001
because the earnings are considered permanently invested.
Tax returns are subject to audit by various taxing authorities. In 2001, 2000
and 1999, the Company recorded benefits to income of $3,361,000, $25,618,000 and
$5,000,000, respectively, from settlements of U.S. and foreign tax issues
primarily related to prior years. Although the Company believes that adequate
accruals have been made for unsettled issues, additional gains or losses could
occur in future years from resolution of outstanding matters.
Note I - Incentive Plans
The Company's 1992 Stock Incentive Plan (the Plan) authorized the Executive
Compensation and Nominating Committee (the Committee) to make annual grants of
the Company's Common Stock to executives and other key employees as follows: (1)
stock options (nonqualified or incentive), (2) stock appreciation rights (SAR),
and/or (3) restricted stock. Annual grants may not exceed 1% (.5% prior to 2000)
of shares outstanding at the end of the preceding year; allowed shares not
granted may be granted in future years. The Company uses APB Opinion No. 25 to
account for stock-based compensation, accruing costs of restricted stock and any
stock options deemed to be variable in nature over the vesting/performance
periods and adjusting costs for changes in fair market value of Common Stock.
Compensation cost charged against income for stock-based plans was $1,892,000 in
2001, $7,914,000 in 2000 and $13,161,000 in 1999. Outstanding awards were not
significantly modified in the last three years.
F-14
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Had compensation cost of the Plan been based on the fair value of the
instruments at the date of grant using the provisions of Statement of Financial
Accounting Standards (SFAS) No. 123, the Company's net income and earnings per
share would be the pro forma amounts shown in the following table. The pro forma
effects on net income in the table may not be representative of the pro forma
effects on net income of future years because the SFAS No. 123 provisions used
in these calculations were only applied to stock options and restricted stock
granted after 1994.
(Thousands of dollars except per share data) 2001 2000 1999
---- ---- ----
Net income - As reported $330,903 296,828 119,707
Pro forma 324,358 299,031 124,543
Net income per share - As reported, basic $ 7.32 6.59 2.66
Pro forma, basic 7.17 6.64 2.77
As reported, diluted 7.26 6.56 2.66
Pro forma, diluted 7.12 6.61 2.76
STOCK OPTIONS - The Committee fixes the option price of each option granted at
no less than fair market value (FMV) on the date of the grant and fixes the
option term at no more than 10 years from such date. Each option granted to date
under the Plan has had a term of 10 years, has been nonqualified, and has had an
option price equal to FMV at date of grant, except for certain 1997 grants with
option prices above FMV. Generally, one-half of each grant may be exercised
after two years and the remainder after three years.
The pro forma net income calculations in the preceding table reflect the
following fair values of options granted in 2001, 2000 and 1999; fair values of
options have been estimated by using the Black-Scholes pricing model and the
assumptions as shown.
2001 2000 1999
---- ---- ----
Fair value per share at grant date $ 14.40 $ 15.00 $ 7.76
Assumptions
Dividend yield 2.84% 2.91% 2.87%
Expected volatility 26.34% 26.06% 24.21%
Risk-free interest rate 4.93% 6.76% 4.77%
Expected life 5 yrs. 5 yrs. 5 yrs.
Changes in options outstanding, including shares issued under a prior plan, were
as follows.
Average
Number Exercise
of Shares Price
--------- --------
Outstanding at December 31, 1998 1,053,249 $ 48.73
Granted at FMV 325,500 35.69
Exercised (109,130) 39.57
Forfeited (15,250) 45.27
---------
Outstanding at December 31, 1999 1,254,369 46.19
Granted at FMV 396,000 56.97
Exercised (192,549) 43.63
Forfeited (5,250) 49.75
---------
Outstanding at December 31, 2000 1,452,570 49.45
Granted at FMV 518,000 61.66
Exercised (261,200) 47.28
---------
Outstanding at December 31, 2001 1,709,370 53.48
=========
Exercisable at December 31, 1999 441,119 $ 45.36
Exercisable at December 31, 2000 590,820 51.80
Exercisable at December 31, 2001 635,120 49.13
F-15
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Additional information about stock options outstanding at December 31, 2001 is
shown below.
Options Outstanding Options Exercisable
------------------------------------- ---------------------
Range of Exercise No. of Avg. Life Avg. No. of Avg.
Prices Per Share Options in Years Price Options Price
- ---------------- ------- -------- ----- ------- -----
$34.56 to $42.25 352,370 6.0 $ 36.74 192,120 $ 37.61
$49.75 to $56.97 717,000 7.0 54.19 321,000 50.76
$60.45 to $65.49 640,000 8.3 61.91 122,000 62.97
--------- -------
1,709,370 7.3 53.48 635,120 49.13
========= =======
SAR - SAR may be granted in conjunction with or independent of stock options;
the Committee determines when SAR may be exercised and the price. No SAR have
been granted.
RESTRICTED STOCK - Shares of restricted stock were granted under the Plan in
certain years. Each grant will vest if the Company achieves specific financial
objectives at the end of a five-year performance period. Additional shares may
be awarded if objectives are exceeded, but some or all shares may be forfeited
if objectives are not met. During the performance period, a grantee receives
dividends and may vote these shares, but shares are subject to transfer
restrictions and are all or partially forfeited if a grantee terminates. The
Company may reimburse a grantee up to 50% of the award value for personal income
tax liability on stock awarded. On December 31, 2000, approximately 50% of
eligible shares granted in 1996 were awarded, and the remaining shares were
forfeited based on financial objectives achieved. Changes in restricted stock
outstanding were as follows.
(Number of shares) 2001 2000 1999
---- ---- ----
Balance at beginning of year 58,333 83,364 83,364
Awarded - (12,077) -
Forfeited (750) (12,954) -
------ ------ -------
Balance at end of year 57,583 58,333 83,364
====== ====== ======
CASH AWARDS - The Committee also administers the Company's incentive
compensation plans, which provide for annual or periodic cash awards to
officers, directors and key employees if the Company achieves specific financial
objectives. Compensation expense of $11,816,000, $6,970,000 and $5,301,000 was
recorded in 2001, 2000 and 1999, respectively, for these plans.
EMPLOYEE STOCK PURCHASE PLAN (ESPP) - The Company has an ESPP under which
150,000 shares of the Company's Common Stock could be purchased by eligible U.S.
and Canadian employees. Each quarter, an eligible employee may elect to withhold
up to 10% of his or her salary to purchase shares of the Company's stock at a
price equal to 90% of the fair value of the stock as of the first day of the
quarter. The ESPP will terminate on the earlier of the date that employees have
purchased all 150,000 shares or June 30, 2007. Employee stock purchases under
the ESPP were 16,828 shares at an average price of $60.71 per share in 2001,
13,675 shares at $51.08 in 2000 and 20,487 shares at $37.56 in 1999. At December
31, 2001, 83,369 shares remained available for sale under the ESPP. Compensation
costs related to the ESPP were immaterial.
F-16
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note J - Employee and Retiree Benefit Plans
PENSION AND POSTRETIREMENT PLANS - The Company has defined benefit pension plans
that are principally noncontributory and cover most full-time employees. All
pension plans are funded except for the U.S. and Canadian nonqualified
supplemental plans and the U.S. directors' plan. All U.S. tax qualified plans
meet the funding requirements of federal laws and regulations. The Company also
sponsors health care and life insurance benefit plans, which are not funded,
that cover most retired U.S. employees. The health care benefits are
contributory; the life insurance benefits are noncontributory.
The tables that follow provide a reconciliation of the changes in the plans'
benefit obligations and fair value of assets for the years ended December 31,
2001 and 2000 and a statement of the funded status as of December 31, 2001 and
2000.
Pension Postretirement
Benefits Benefits
-------------------- ------------------
(Thousands of dollars) 2001 2000 2001 2000
-------- ------- ------- -------
Change in benefit obligation
Obligation at January 1 $247,718 240,630 38,454 34,350
Service cost 5,757 5,461 935 753
Interest cost 17,370 17,010 3,009 2,699
Plan amendments - 3,501 - -
Participant contributions 71 - 551 566
Actuarial loss 8,811 1,203 4,311 3,219
Settlements (1,660) (2,257) - -
Exchange rate changes (1,773) (3,461) - -
Benefits paid (15,112) (14,369) (3,925) (3,133)
-------- ------- ------- -------
Obligation at December 31 261,182 247,718 43,335 38,454
-------- ------- ------- -------
Change in plan assets
Fair value of plan assets at January 1 300,203 304,474 - -
Actual return on plan assets (25,379) 15,393 - -
Employer contributions 1,089 687 3,374 2,567
Participant contributions 71 - 551 566
Settlements (1,924) (2,271) - -
Exchange rate changes (2,076) (3,711) - -
Benefits paid (15,112) (14,369) (3,925) (3,133)
-------- ------- ------- -------
Fair value of plan assets at December 31 256,872 300,203 - -
-------- ------- ------- -------
Reconciliation of funded status
Funded status at December 31 (4,310) 52,485 (43,335) (38,454)
Unrecognized actuarial (gain) loss 35,809 (22,440) 10,505 6,594
Unrecognized transition asset (9,091) (13,047) - -
Unrecognized prior service cost 6,956 7,806 - -
-------- ------- ------- -------
Net plan asset (liability) recognized $ 29,364 24,804 (32,830) (31,860)
======== ======= ======= =======
Amounts recognized in the Consolidated
Balance Sheets at December 31
Prepaid benefit asset $ 45,454 40,152 - -
Accrued benefit liability (17,310) (17,051) (32,830) (31,860)
Intangible asset 1,220 1,703 - -
-------- ------- ------- -------
Net plan asset (liability) recognized $ 29,364 24,804 (32,830) (31,860)
======== ======= ======= =======
F-17
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
At December 31, 2001 and 2000, accumulated benefit obligations for nonqualified
and directors' retirement plans that are not funded were $10,541,000 and
$10,060,000, respectively. Due to declines in the market value of plan assets
during the year, certain funded retirement plans had accumulated benefit
obligations in excess of plan assets at year-end 2001; these plans had
obligations of $55,794,000 and assets of $54,223,000. At December 31, 2001 and
2000, the accumulated benefit obligations for the Company's postretirement
benefit plans, which are not funded, amounted to $43,335,000 and $38,454,000,
respectively.
The table that follows provides the components of net periodic benefit expense
(credit) for each of the three years ended December 31, 2001.
Pension Benefits Postretirement Benefits
----------------------------- -------------------------
(Thousands of dollars) 2001 2000 1999 2001 2000 1999
------ ---- ----- ---- ---- -----
Service cost $ 5,757 5,461 5,791 935 753 712
Interest cost 17,370 17,010 15,516 3,009 2,699 2,366
Expected return on plan assets (24,123) (24,412) (23,105) - - -
Amortization of prior service cost 782 791 622 - - -
Amortization of transitional asset (2,552) (2,585) (2,204) - - -
Recognized actuarial (gain) loss (181) (395) (766) 400 234 203
-------- ------- ------- ----- ----- -----
(2,947) (4,130) (4,146) 4,344 3,686 3,281
Settlement gain (901) (1,824) - - - -
Special early retirement benefits - - 1,041 - - -
-------- ------- ------- ----- ----- -----
Net periodic benefit
expense (credit) $ (3,848) (5,954) (3,105) 4,344 3,686 3,281
======== ======= ======= ===== ===== =====
Settlement gains in 2001 related to employee reductions from the sale of
Canadian pipeline and trucking assets, while 2000 gains were due to voluntary
conversion of certain Canadian employees' retirement coverage from the defined
benefit pension plan to a defined contribution plan.
The preceding tables include the following amounts related to foreign benefit
plans.
Pension Postretirement
Benefits Benefits
------------------------ ----------------
(Thousands of dollars) 2001 2000 2001 2000
--------- ------- ---- ----
Benefit obligation at December 31 $ 49,010 49,608 - -
Fair value of plan assets at December 31 46,709 55,473 - -
Net plan asset (liability) recognized 73 (876) - -
Net periodic benefit credit (704) (1,960) - -
The following table provides the weighted-average assumptions used in the
measurement of the Company's benefit obligations at December 31, 2001 and 2000.
Pension Postretirement
Benefits Benefits
------------------------ ----------------
2001 2000 2001 2000
--------- ------- ---- ----
Discount rate 7.00% 7.25% 7.25% 7.50%
Expected return on plan assets 8.30% 8.33% - -
Rate of compensation increase 4.59% 4.63% - -
Discount rates are adjusted as necessary, generally based on changes in AA-rated
corporate bond rates. Expected plan asset returns are based on long-term
expectations for asset portfolios with similar investment mix characteristics.
Expected compensation increases are based on historical averages for the
Company.
F-18
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For purposes of measuring postretirement benefit obligations at December 31,
2001, the future annual rates of increase in the cost of health care were
assumed to be 7.5% for 2002 decreasing .5% per year to an ultimate rate of 5.0%
in 2007 and thereafter.
Assumed health care cost trend rates have a significant effect on the expense
and obligation reported for the postretirement benefit plan. A 1% change in
assumed health care cost trend rates would have the following effects.
(Thousands of dollars) 1% Increase 1% Decrease
----------- -----------
Effect on total service and interest cost components of
net periodic postretirement benefit expense for the
year ended December 31, 2001 $ 257 (240)
Effect on the health care component of the accumulated
postretirement benefit obligation at December 31, 2001 2,280 (2,184)
THRIFT PLANS - Most employees of the Company may participate in thrift or
savings plans by allotting up to a specified percentage of their base pay. The
Company matches contributions at a stated percentage of each employee's
allotment based on years of participation in the plans. A U.K. savings plan
allows eligible employees to allot a portion of their base pay to purchase
Company Common Stock at market value. Such employee allotments are matched by
the Company. Common Stock issued from the Company's treasury under this savings
plan was 8,068 shares in 2001 and 3,180 shares in 2000. Amounts charged to
expense for these plans were $4,061,000 in 2001, $3,699,000 in 2000 and
$2,523,000 in 1999.
Note K - Financial Instruments and Risk Management
DERIVATIVE INSTRUMENTS - Murphy utilizes derivative instruments on a limited
basis to manage certain risks related to interest rates, commodity prices, and
foreign currency exchange rates. The use of derivative instruments for risk
management is covered by operating policies and is closely monitored by the
Company's senior management. The Company does not hold any derivatives for
trading purposes, and it does not use derivatives with leveraged or complex
features. Derivative instruments are traded primarily with creditworthy major
financial institutions or over national exchanges.
. Interest Rate Risks - Murphy has variable-rate debt obligations that expose
the Company to the effects of changes in interest rates. To limit its
exposure to interest rate risk, Murphy has interest rate swap agreements
with notional amounts totaling $100,000,000 to hedge fluctuations in cash
flows of a similar amount of variable rate debt. The swaps mature in 2002
and 2004. Under the interest rate swaps, the Company pays fixed rates
averaging 6.46% over their composite lives and receives variable rates
which averaged 2.28% at December 31, 2001. The variable rate received by
the Company under each contract is repriced quarterly. The Company has a
risk management control system to monitor interest rate cash flow risk
attributable to the Company's outstanding and forecasted debt obligations
as well as the offsetting interest rate swaps. The control system involves
using analytical techniques, including cash flow sensitivity analysis, to
estimate the impact of interest rate changes on future cash flows.
The fair value of the effective portions of the interest rate swaps and
changes thereto is deferred in Accumulated Other Comprehensive Loss (AOCL)
and is subsequently reclassified into Interest Expense as a rate adjustment
in the periods in which the hedged interest payments on the variable-rate
debt affect earnings. For the year ended December 31, 2001, the income
effect from cash flow hedging ineffectiveness was insignificant.
The fair value of the interest rate swaps are estimated using projected
Federal funds rates, Canadian overnight funding rates and LIBOR forward
curve rates obtained from published indices and counterparties. The
estimated fair value approximates the values based on quotes from each of
the counterparties.
F-19
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
. Natural Gas Fuel Price Risks - The Company purchases natural gas as fuel at
its Meraux, Louisiana refinery. The cost of natural gas is subject to
commodity price risk. Murphy has reduced the effect of changes in the price
of natural gas used for fuel at Meraux by entering into natural gas swap
contracts with a notional volume of 7.7 million British Thermal Units
(MMBTU) to hedge fluctuations in cash flows resulting from such risk during
2004 and 2005.
Under the natural gas swaps, the Company pays a fixed rate averaging $2.68
per MMBTU and receives a floating rate in each month of settlement based on
the average NYMEX price for the final three trading days of the month.
Murphy has a risk management control system to monitor natural gas price
risk attributable both to forecasted natural gas fuel requirements and to
Murphy's natural gas swaps. The control system involves using analytical
techniques, including various correlations of natural gas purchase prices to
futures prices, to estimate the impact of changes in natural gas fuel prices
on Murphy's cash flows.
The fair value of the effective portions of the natural gas swaps and
changes thereto is deferred in AOCL and is subsequently reclassified into
Crude Oil, Products and Related Operating Expenses in the periods in which
the hedged natural gas fuel purchases affect earnings. For the year ended
December 31, 2001, the income effect from cash flow hedging ineffectiveness
was insignificant.
. Natural Gas Sales Price Risks - The sales price of natural gas produced by
the Company is subject to commodity price risk. Murphy has minimized the
effect of changes in the selling price of a portion of its U.S. natural gas
production through March 2002 by entering into natural gas swap contracts
to hedge cash flow fluctuations resulting from such risk. The natural gas
swaps are for a notional volume averaging approximately 32,000 MMBTU per
day in the first quarter of 2002 and require Murphy to pay the average
NYMEX price for the final trading day of each month and receive a price
ranging from $2.54 to $2.94 per MMBTU. Murphy has a risk management control
system to monitor natural gas price risk attributable both to forecasted
natural gas sales prices and to Murphy's hedging instruments. The control
system involves using analytical techniques, including various correlations
of natural gas sales prices to futures prices, to estimate the impact of
changes in natural gas prices on Murphy's cash flows from the sale of
natural gas.
The natural gas price risk pertaining to a portion of gas sales from
properties Murphy acquired from Beau Canada in 2000 was limited by natural
gas swap agreements that expired in October 2001 that were obtained in the
acquisition. These agreements hedged fluctuations in cash flows resulting
from such risk. Certain swaps required Murphy to pay a floating price and
receive a fixed price and were partially offset by swaps on a lesser volume
that require Murphy to pay a fixed price and receive a floating price. The
fair value of these swaps was recorded as a net liability upon the
acquisition of Beau Canada and adjusted on January 1, 2001 upon transition
to SFAS 133. Net payments by the Company were recorded as a reduction of
the associated liability, with any differences recorded as an adjustment of
natural gas revenue.
The fair values of the effective portions of the natural gas swaps and
changes thereto are deferred in AOCL and are subsequently reclassified into
Crude Oil and Natural Gas Sales in the periods in which the hedged natural
gas sales affect earnings. For the year ended December 31, 2001, Murphy's
earnings were not significantly impacted from cash flow hedging
ineffectiveness arising from the natural gas swaps in the United States and
western Canada.
The fair value of the natural gas fuel swaps and the natural gas sales swaps
are both based on the average fixed price of the swaps and the published
NYMEX futures price or natural gas price quotes from counterparties.
F-20
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
. Crude Oil Purchase Price Risks - Each month, the Company purchases crude
oil as the primary feedstock for its U.S. refineries. Prior to April 2000,
the Company was a party to crude oil swap agreements that limited the
exposure of its U.S. refineries to the risks of fluctuations in cash flows
resulting from changes in the prices of crude oil purchased in 2001 and
2002. Under each swap, Murphy would have paid a fixed crude oil price and
would have received a floating price during the agreement's contractual
maturity period. In April 2000, the Company settled certain of the swaps by
receiving $5,806,000 in cash and entered into offsetting contracts for the
remaining swap agreements, locking in an additional future net gain of
$1,929,000. The fair values of these settlement gains were recorded in AOCL
as part of the transition adjustment and are recognized as a reduction of
costs of crude oil purchases in the period the forecasted transaction
occurs. During 2001, pretax gains of $1,957,000 were reclassified from AOCL
into earnings. Approximately $5,778,000 of gains will be reclassified from
AOCL into earnings during 2002.
The fair value of the offsetting crude oil swap contracts is based on the
fixed swap price and the NYMEX crude oil futures price.
The Company expects to reclassify approximately $2,300,000 in after-tax gains
from AOCL into earnings during the next 12 months as the forecasted transactions
actually occur. All forecasted transactions currently being hedged are expected
to occur by December 2005.
FAIR VALUE - The following table presents the carrying amounts and estimated
fair values of financial instruments held by the Company at December 31, 2001
and 2000. The fair value of a financial instrument is the amount at which the
instrument could be exchanged in a current transaction between willing parties.
The table excludes cash and cash equivalents, trade accounts receivable,
investments and noncurrent receivables, trade accounts payable, and accrued
expenses, all of which had fair values approximating carrying amounts. The fair
value of current and long-term debt is estimated based on current rates offered
the Company for debt of the same maturities. The company has off-balance sheet
exposures relating to certain financial guarantees and letters of credit. The
fair value of these, which represents fees associated with obtaining the
instruments, was nominal.
2001 2000
---------------------- --------------------
Carrying Fair Carrying Fair
(Thousands of dollars) Amount Value Amount Value
-------- --------- -------- --------
Financial assets (liabilities):
Crude oil swaps $ 1,914 1,914 - 1,793
Natural gas fuel swaps 4,309 4,309 - 6,196
Natural gas sales swaps 842 842 (12,615) (17,905)
Interest rate swaps (4,269) (4,269) - (1,956)
Current and long-term debt (569,035) (542,115) (562,001) (526,891)
The carrying amounts of crude oil swaps, natural gas swaps and interest rate
swaps in the preceding table are included in Deferred Charges and Other Assets
or Other Accrued Liabilities. Current and long-term debt are included in the
Consolidated Balance Sheets under Current Maturities of Long-Term Debt, Notes
Payable and Nonrecourse Debt of a Subsidiary.
CREDIT RISKS - The Company's primary credit risks are associated with trade
accounts receivable, cash equivalents and derivative instruments. Trade
receivables arise mainly from sales of crude oil, natural gas and petroleum
products to a large number of customers in the United States, Canada and the
United Kingdom. The credit history and financial condition of potential
customers are reviewed before credit is extended, security is obtained when
deemed appropriate based on a potential customer's financial condition, and
routine follow-up evaluations are made. The combination of these evaluations and
the large number of customers tends to limit the risk of credit concentration to
an acceptable level. Cash equivalents are placed with several major financial
institutions, which limits the Company's exposure to credit risk. The Company
controls credit risk on derivatives through credit approvals and monitoring
procedures and believes that such risks are minimal because counterparties to
the majority of transactions are major financial institutions.
F-21
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note L - Stockholder Rights Plan
The Company's Stockholder Rights Plan provides for each Common stockholder to
receive a dividend of one Right for each share of the Company's Common Stock
held. The Rights will expire on April 6, 2008 unless earlier redeemed or
exchanged. The Rights will detach from the Common Stock and become exercisable
following a specified period of time after the first public announcement that a
person or group of affiliated or associated persons (other than certain persons)
has become the beneficial owner of 15% or more of the Company's Common Stock.
The Rights have certain antitakeover effects and will cause substantial dilution
to a person or group that attempts to acquire the Company without conditioning
the offer on a substantial number of Rights being acquired. The Rights are not
intended to prevent a takeover, but rather are designed to enhance the ability
of the Board of Directors to negotiate with an acquiror on behalf of all
shareholders. Other terms of the Rights are set forth in, and the foregoing
description is qualified in its entirety by, the Rights Agreement, as amended,
between the Company and Harris Trust Company of New York, as Rights Agent.
Note M - Earnings per Share
The following table reconciles the weighted-average shares outstanding for
computation of basic and diluted income per Common share for each of the three
years ended December 31, 2001. No difference existed between net income used in
computing basic and diluted income per Common share for these years.
(Weighted-average shares outstanding) 2001 2000 1999
---- ---- ----
Basic method 45,221,472 45,031,665 44,970,457
Dilutive stock options 369,527 208,041 59,768
---------- ---------- ----------
Diluted method 45,590,999 45,239,706 45,030,225
========== ========== ==========
The computations of diluted earnings per share in the Consolidated Statements of
Income did not consider outstanding options of 147,000 shares at year-end 2000
and 684,750 shares at year-end 1999 because the effects of these options would
have improved the Company's earnings per share. Average exercise prices per
share of the options not used were $62.97 and $53.34, respectively. There were
no antidilutive options for the year ending 2001.
Note N - Other Financial Information
INVENTORIES - Inventories accounted for under the LIFO method totaled
$90,464,000 and $85,968,000 at December 31, 2001 and 2000, respectively, and
were $51,054,000 and $123,963,000 less than such inventories would have been
valued using the FIFO method.
ACCUMULATED OTHER COMPREHENSIVE LOSS - At December 31, 2001 and 2000, the
components of Accumulated Other Comprehensive Loss were as follows.
(Thousands of dollars) 2001 2000
---- ----
Foreign currency translation loss, net $(87,862) (38,266)
Cash flow hedge gains, net 4,553 -
-------- -------
Balance at end of year $(83,309) (38,266)
======== =======
At December 31, 2001, components of the net foreign currency translation loss of
$87,862,000 were gains (losses) of $8,017,000 for pounds sterling, $(96,036,000)
for Canadian dollars and $157,000 for other currencies. Comparability of net
income was not significantly affected by exchange rate fluctuations in 2001,
2000 and 1999. Net gains (losses) from foreign currency transactions included in
the Consolidated Statements of Income were $1,406,000 in 2001, $252,000 in 2000
and $(847,000) in 1999.
F-22
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
CASH FLOW DISCLOSURES - In association with the Beau Canada acquisition, the
Company assumed debt of $124,227,000, a nonmonetary transaction excluded from
both financing and investing activities in the Consolidated Statement of Cash
Flows for the year ended December 31, 2000. Cash income taxes paid (refunded)
were $135,734,000, $53,583,000 and $(5,343,000) in 2001, 2000 and 1999,
respectively. Interest paid, net of amounts capitalized, was $12,945,000,
$15,185,000 and $17,140,000 in 2001, 2000 and 1999, respectively.
Noncash operating working capital (increased) decreased for each of the three
years ended December 31, 2001 as follows.
(Thousands of dollars) 2001 2000 1999
---- ---- ----
Accounts receivable $ 207,594 (95,675) (123,566)
Inventories (8,393) (12,197) (21,866)
Prepaid expenses (37,113) 5,794 4,147
Deferred income tax assets 6,139 (4,196) (8,600)
Accounts payable and accrued liabilities (176,213) 142,228 99,382
Current income tax liabilities (19,965) 30,048 15,344
--------- ------- --------
Net (increase) decrease in noncash
operating working capital excluding
acquisition of Beau Canada $ (27,951) 66,002 (35,159)
========= ======= ========
Note O - Commitments
The Company leases land, gasoline stations and other facilities under operating
leases. During the next five years, future minimum rental commitments under
noncancellable operating leases decline gradually from $17,600,000 in 2002 to
$15,800,000 in 2006. Rental expense for noncancellable operating leases,
including contingent payments when applicable, was $23,859,000 in 2001,
$17,425,000 in 2000 and $9,800,000 in 1999. Commitments for capital expenditures
were approximately $506,000,000 at December 31, 2001, including $206,000,000
related to clean fuels and crude throughput expansion projects at the Meraux
refinery and $94,000,000 related to development of the Company's Medusa field in
the Gulf of Mexico.
Note P - Contingencies
The Company's operations and earnings have been and may be affected by various
forms of governmental action both in the United States and throughout the world.
Examples of such governmental action include, but are by no means limited to:
tax increases and retroactive tax claims; import and export controls; price
controls; currency controls; allocation of supplies of crude oil and petroleum
products and other goods; expropriation of property; restrictions and
preferences affecting the issuance of oil and gas or mineral leases;
restrictions on drilling and/or production; laws and regulations intended for
the promotion of safety and the protection and/or remediation of the
environment; governmental support for other forms of energy; and laws and
regulations affecting the Company's relationships with employees, suppliers,
customers, stockholders and others. Because governmental actions are often
motivated by political considerations, may be taken without full consideration
of their consequences, and may be taken in response to actions of other
governments, it is not practical to attempt to predict the likelihood of such
actions, the form the actions may take or the effect such actions may have on
the Company.
F-23
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ENVIRONMENTAL MATTERS AND LEGAL MATTERS - In addition to being subject to
numerous laws and regulations intended to protect the environment and/or impose
remedial obligations, the Company is also involved in personal injury and
property damage claims, allegedly caused by exposure to or by the release or
disposal of materials manufactured or used in the Company's operations. The
Company operates or has previously operated certain sites and facilities,
including refineries, oil and gas fields, service stations, and terminals, for
which known or potential obligations for environmental remediation exist.
The Company's liability for remedial obligations includes certain amounts that
are based on anticipated regulatory approval for proposed remediation of former
refinery waste sites. If regulatory authorities require more costly alternatives
than the proposed processes, future expenditures could exceed the accrued
liability by up to an estimated $3 million.
The Company has received notices from the U.S. Environmental Protection Agency
(EPA) that it is currently considered a Potentially Responsible Party (PRP) at
three Superfund sites and has also been assigned responsibility by defendants at
another Superfund site. The potential total cost to all parties to perform
necessary remedial work at these sites may be substantial. Based on currently
available information, the Company believes that it is a "de minimus" party as
to ultimate responsibility at the four sites. The Company has not recorded a
liability for remedial costs on Superfund sites. The Company could be required
to bear a pro rata share of costs attributable to nonparticipating PRPs;
additionally, the Company could be assigned additional responsibility for
remediation at these or other Superfund sites.
There is the possibility that environmental expenditures could be required at
currently unidentified sites, and new or revised regulations could require
additional expenditures at known sites. The Company does not expect that future
costs for these matters will have a material adverse effect on its financial
condition.
In June 2000, the U.S. Government filed a lawsuit against Murphy Oil USA, Inc.,
the Company's wholly-owned subsidiary, in federal court in Madison, Wisconsin,
alleging violations of environmental laws at the Company's Superior, Wisconsin
refinery. The lawsuit was divided into liability and damage phases, and on
August 1, 2001, the court ruled against the Company in the liability phase of
the trial. Subsequent to the court ruling, the Company and the U.S. Government
reached a tentative agreement that was filed with the federal court in January
2002. The settlement is subject to approval by the court following a 30-day
public comment period that expires March 7, 2002. According to the tentative
settlement agreement, the Company is to pay a civil penalty of $5.5 million and
implement other environmental projects to resolve Clean Air Act violations. The
Company has recorded a liability of $5.5 million to cover the penalty. Although
the settlement is tentative and no assurance can be given, the Company does not
believe that the ultimate resolution of this matter will have a material adverse
effect on its financial condition.
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 expected to have a material adverse effect on the Company's financial
condition. The ultimate resolution of environmental and legal matters referred
to in this note could have a material adverse effect on the Company's earnings
in a future period.
OTHER MATTERS - In the normal course of its business, the Company is required
under certain contracts with various governmental authorities and others to
provide financial guarantees or letters of credit that may be drawn upon if the
Company fails to perform under those contracts. At December 31, 2001, the
Company had contingent liabilities of $33,789,000 under certain financial
guarantees and $35,578,000 on outstanding letters of credit. The Company
believes that the likelihood of having the guarantees or letters of credit drawn
are remote.
F-24
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note Q - Common Stock Issued and Outstanding
Activity in the number of shares of Common Stock issued and outstanding for the
three years ended December 31, 2001 is shown below.
(Number of shares outstanding) 2001 2000 1999
---- ---- ----
At beginning of year 45,045,545 44,997,995 44,950,476
Stock options exercised 261,200 43,678 26,953
Employee stock purchase plans 24,896 16,855 20,487
Restricted stock forfeitures (750) (12,954) -
All other 189 (29) 79
---------- ---------- ----------
At end of year 45,331,080 45,045,545 44,997,995
========== ========== ==========
Note R - Business Segments
Murphy's reportable segments are organized into two major types of business
activities, each subdivided into geographic areas of operations. The Company's
exploration and production activity is subdivided into segments for the United
States, Canada, the United Kingdom, Ecuador, Malaysia and all other countries;
each of these segments derives revenues primarily from the sale of crude oil and
natural gas. The refining and marketing segments in the United States and the
United Kingdom derive revenues mainly from the sale of petroleum products; the
Canadian segment derived revenues primarily from the transportation and trading
of crude oil. The Company sold its Canadian pipeline and trucking assets in May
2001. The Company's management evaluates segment performance based on income
from operations, excluding interest income and interest expense. Intersegment
transfers of crude oil, natural gas and petroleum products are at market prices
and intersegment services are recorded at cost.
Information about business segments and geographic operations is reported in the
following tables. Excise taxes on petroleum products of $1,005,018,000,
$1,052,760,000 and $898,917,000 for the years 2001, 2000 and 1999, respectively,
were excluded from revenues and costs and expenses. For geographic purposes,
revenues are attributed to the country in which the sale occurs. The Company had
no single customer from which it derived more than 10% of its revenues. Murphy's
equity method investments are in companies that transport crude oil and
petroleum products. Corporate and other activities, including interest income,
miscellaneous gains and losses, interest expense and unallocated overhead, are
shown in the tables to reconcile the business segments to consolidated totals.
As used in the table on page F-26, Certain Long-Lived Assets at December 31
exclude investments, noncurrent receivables, deferred tax assets and intangible
assets.
F-25
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Segment Information Exploration and Production
--------------------------------------------------------------------
(Millions of dollars) U.S. Canada U.K. Ecuador Malaysia Other Total
---- ------ ---- ------- -------- ----- -----
Year ended December 31, 2001
Segment income (loss) $ 57.8 85.5 78.6 11.5 (36.1) (7.3) 190.0
Revenues from external customers 185.6 417.6 194.2 33.4 - 2.2 833.0
Intersegment revenues 54.7 30.1 - - - - 84.8
Interest income - - - - - - -
Interest expense, net of capitalization - - - - - - -
Income of equity companies - - - - - - -
Income tax expense (benefit) 30.7 51.6 44.3 - - (1.0) 125.6
Significant noncash charges (credits)
Depreciation, depletion, amortization 40.3 99.0 37.2 6.4 .5 .3 183.7
Amortization of goodwill - 3.1 - - - - 3.1
Impairment of properties 8.9 - - - - - 8.9
Provisions for major repairs - 3.3 - - - - 3.3
Amortization of undeveloped leases 9.5 13.6 - - - - 23.1
Deferred and noncurrent income taxes 27.0 53.2 (3.3) - - .5 77.4
Additions to property, plant, equipment 226.2 287.0 17.9 9.0 9.6 - 549.7
Total assets at year-end 582.1 1,255.8 213.5 69.9 22.2 7.5 2,151.0
- -------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2000
Segment income (loss) before cumulative
effect of accounting change $ 50.3 108.1 90.2 21.1 (10.7) (6.3) 252.7
Revenues from external customers 205.6 278.6 211.5 51.5 - 2.2 749.4
Intersegment revenues 73.4 106.3 11.6 - - - 191.3
Interest income - - - - - - -
Interest expense, net of capitalization - - - - - - -
Income of equity companies - - - - - - -
Income tax expense (benefit) 27.1 66.3 56.2 - - - 149.6
Significant noncash charges (credits)
Depreciation, depletion, amortization 50.2 70.0 41.7 6.8 .4 .1 169.2
Impairment of properties 21.0 6.9 - - - - 27.9
Provisions for major repairs - 3.3 - - - - 3.3
Amortization of undeveloped leases 7.7 6.4 - - - - 14.1
Deferred and noncurrent income taxes (5.1) 55.6 (1.5) - - 1.0 50.0
Additions to property, plant, equipment 69.9 425.5 24.6 12.3 8.1 .8 541.2
Total assets at year-end 413.6 1,131.1 261.7 79.8 9.3 7.1 1,902.6
- -------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1999
Segment income (loss) $ 35.3 47.0 37.2 22.6 (1.6) (6.1) 134.4
Revenues from external customers 155.8 164.2 119.0 39.0 - 2.0 480.0
Intersegment revenues 50.6 58.7 23.4 - - - 132.7
Interest income - - - - - - -
Interest expense, net of capitalization - - - - - - -
Income of equity companies - - - - - - -
Income tax expense (benefit) 10.3 24.8 24.5 - - .5 60.1
Significant noncash charges (credits)
Depreciation, depletion, amortization 65.1 50.9 42.8 8.0 .1 - 166.9
Provisions for major repairs - 2.5 - - - - 2.5
Amortization of undeveloped leases 7.0 4.0 - - - - 11.0
Deferred and noncurrent income taxes 12.6 21.3 (3.8) - - 1.3 31.4
Additions to property, plant, equipment 60.7 143.0 25.6 7.1 1.1 (1.2) 236.3
Total assets at year-end 391.0 737.9 299.4 60.0 1.3 8.2 1,497.8
- -------------------------------------------------------------------------------------------------------------------------
Geographic Information Certain Long-Lived Assets at December 31
------------------------------------------------------------------
(Millions of dollars) U.S. Canada U.K. Ecuador Malaysia Other Total
---- ------ ---- ------- -------- ----- -----
2001 $1,058.8 1,117.5 272.3 61.6 17.7 5.7 2,533.6
2000 764.8 1,063.2 297.1 59.0 8.7 5.9 2,198.7
1999 687.0 724.4 331.6 53.5 1.0 6.7 1,804.2
F-26
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Segment Information (Continued) Refining and Marketing
------------------------------------- Corp. & Consoli-
(Millions of dollars) U.S. U.K. Canada Total Other dated
---- ---- ------ ----- ------- -----
Year ended December 31, 2001
Segment income (loss) $ 64.7 14.1 74.9 153.7 (12.8) 330.9
Revenues from external customers 2,952.4 374.6 306.8 3,633.8 11.7 4,478.5
Intersegment revenues - - .2 - - 85.0
Interest income - - - - 11.6 11.6
Interest expense, net of capitalization - - - - 19.0 19.0
Income of equity companies .9 - - .9 - .9
Income tax expense (benefit) 41.5 5.0 29.7 76.2 (26.8) 175.0
Significant noncash charges (credits)
Depreciation, depletion, amortization 36.0 6.1 .9 43.0 2.5 229.2
Amortization of goodwill - - - - - 3.1
Impairment of properties 1.6 - - 1.6 - 10.5
Provisions for major repairs 15.7 1.9 - 17.6 .1 21.0
Amortization of undeveloped leases - - - - - 23.1
Deferred and noncurrent income taxes 3.9 2.5 (1.4) 5.0 (2.3) 80.1
Additions to property, plant, equipment 162.8 12.4 - 175.2 5.8 730.7
Total assets at year-end 734.4 184.4 - 918.8 189.3 3,259.1
- ------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2000
Segment income (loss) before cumulative
effect of accounting change $ 23.9 23.0 7.6 54.5 (1.7) 305.5
Revenues from external customers 2,842.1 458.2 564.6 3,864.9 24.9 4,639.2
Intersegment revenues .9 - .7 1.6 - 192.9
Interest income - - - - 21.7 21.7
Interest expense, net of capitalization - - - - 16.3 16.3
Income of equity companies .6 - - .6 - .6
Income tax expense (benefit) 13.2 11.3 6.9 31.4 (21.2) 159.8
Significant noncash charges (credits)
Depreciation, depletion, amortization 32.7 5.6 2.6 40.9 3.4 213.5
Impairment of properties - - - - - 27.9
Provisions for major repairs 17.6 1.8 - 19.4 .1 22.8
Amortization of undeveloped leases - - - - - 14.1
Deferred and noncurrent income taxes 5.2 1.2 - 6.4 7.0 63.4
Additions to property, plant, equipment 112.0 12.4 29.4 153.8 11.4 706.4
Total assets at year-end 670.4 222.6 125.6 1,018.6 213.2 3,134.4
- ------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1999
Segment income (loss) $ 1.6 14.0 6.8 22.4 (37.1) 119.7
Revenues from external customers 1,641.4 337.9 292.7 2,272.0 4.4 2,756.4
Intersegment revenues 4.6 - .6 5.2 - 137.9
Interest income - - - - 3.9 3.9
Interest expense, net of capitalization - - - - 20.3 20.3
Income of equity companies .5 - - .5 - .5
Income tax expense (benefit) .4 6.6 6.6 13.6 (14.9) 58.8
Significant noncash charges (credits)
Depreciation, depletion, amortization 27.6 5.8 2.0 35.4 2.7 205.0
Provisions for major repairs 14.2 1.9 - 16.1 .1 18.7
Amortization of undeveloped leases - - - - - 11.0
Deferred and noncurrent income taxes 7.9 (.5) - 7.4 (.8) 38.0
Additions to property, plant, equipment 76.4 11.4 .3 88.1 2.6 327.0
Total assets at year-end 549.7 199.0 89.6 838.3 109.4 2,445.5
- ------------------------------------------------------------------------------------------------------------------
Geographic Information Revenues from External Customers for the Year
------------------------------------------------------------
(Millions of dollars) U.S. U.K. Canada Ecuador Other Total
---- ---- ------ ------- ----- -----
2001 $ 3,142.1 573.1 727.7 33.4 2.2 4,478.5
2000 3,065.9 674.2 845.4 51.5 2.2 4,639.2
1999 1,798.4 459.8 457.2 39.0 2.0 2,756.4
F-27
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
The following schedules are presented in accordance with SFAS No. 69,
"Disclosures about Oil and Gas Producing Activities", to provide users with a
common base for preparing estimates of future cash flows and comparing reserves
among companies. Additional background information follows concerning four of
the schedules.
SCHEDULES 1 AND 2 - ESTIMATED NET PROVED OIL AND NATURAL GAS RESERVES - Reserves
of crude oil, condensate, natural gas liquids and natural gas are estimated by
the Company's engineers and are adjusted to reflect contractual arrangements and
royalty rates in effect at the end of each year. Many assumptions and judgmental
decisions are required to estimate reserves. Reported quantities are subject to
future revisions, some of which may be substantial, as additional information
becomes available from: reservoir performance, new geological and geophysical
data, additional drilling, technological advancements, price changes and other
economic factors.
The U.S. Securities and Exchange Commission defines proved reserves as those
volumes of crude oil, condensate, 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 volumes expected to be recovered
through existing wells with existing equipment and operating methods. Proved
undeveloped reserves are volumes expected to be recovered as a result of
additional investments for drilling new wells to offset productive units,
recompleting existing wells, and/or installing facilities to collect and
transport production.
Production quantities shown are net volumes withdrawn from reservoirs. These may
differ from sales quantities 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.
Oil reserves discovered in Malaysia in 2001 are associated with a production
sharing contract for Block SK 309. Reserves include oil to be received for both
cost recovery and profit provisions under the contract.
Synthetic oil reserves in Canada are attributable to Murphy's share, after
deducting estimated net profit royalty, of the Syncrude project and include
currently producing leases. Additional reserves will be added as development
progresses.
The Company has no proved reserves attributable to either long-term supply
agreements with foreign governments or investees accounted for by the equity
method.
SCHEDULE 4 - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES -
Results of operations from exploration and production activities by geographic
area are reported as if these activities were not part of an operation that also
refines crude oil and sells refined products. Results of oil and gas producing
activities include certain special items that are reviewed in Management's
Discussion and Analysis of Financial Condition and Results of Operations on page
9 of this Form 10-K report, and should be considered in conjunction with the
Company's overall performance.
SCHEDULE 6 - 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% annual discount factor and year-end 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 reported value of proved reserves is not necessarily indicative of either
fair market value or present value of future cash flows because prices, costs
and governmental policies do not remain static; appropriate discount rates may
vary; and extensive judgment is required to estimate the timing of production.
Other logical assumptions would likely have resulted in significantly different
amounts. Average year-end 2001 crude oil prices used for this calculation were
$17.17 per barrel for the United States, $19.14 for Canadian light, $11.26 for
Canadian heavy, $18.46 for Canadian offshore, $18.61 for the United Kingdom,
$11.98 for Ecuador and $19.99 for Malaysia. Average year-end 2001 natural gas
prices used were $2.40 per MCF for the United States, $2.30 for Canada and $3.12
for the United Kingdom.
Schedule 6 also presents the principal reasons for change in the standardized
measure of discounted future net cash flows for each of the three years ended
December 31, 2001.
F-28
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued)
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 Malaysia Total Canada Total
------ ------ ------- ------- -------- ----- --------- -----
Proved
December 31, 1998 23.0 50.8 56.7 32.2 - 162.7 115.6 278.3
Revisions of previous estimates (1.6) 9.1 7.7 4.5 - 19.7 8.9 28.6
Extensions and discoveries 15.8 .7 - 2.9 - 19.4 - 19.4
Production (3.1) (6.9) (7.5) (2.6) - (20.1) (4.0) (24.1)
------ ------ ----- ------ ----- ----- ----- -----
December 31, 1999 34.1 53.7 56.9 37.0 - 181.7 120.5 302.2
Revisions of previous estimates (1.7) 4.5 1.8 3.6 - 8.2 7.6 15.8
Purchases - 11.7 - - - 11.7 - 11.7
Extensions and discoveries 15.3 4.0 - 2.6 - 21.9 - 21.9
Production (2.4) (8.4) (7.7) (2.3) - (20.8) (3.1) (23.9)
Sales - (1.6) - - - (1.6) - (1.6)
------ ----- ----- ------ ----- ----- ----- -----
December 31, 2000 45.3 63.9 51.0 40.9 - 201.1 125.0 326.1
Revisions of previous estimates (.8) 2.8 .5 (.3) - 2.2 9.8 12.0
Improved recovery - 1.5 - - - 1.5 - 1.5
Purchases - .2 - - - .2 - .2
Extensions and discoveries 46.2 3.3 - - 15.0 64.5 - 64.5
Production (2.1) (9.4) (7.4) (1.9) - (20.8) (3.8) (24.6)
Sales - (1.8) - - - (1.8) - (1.8)
------ ------ ----- ------ ----- ----- ----- -----
December 31, 2001 88.6 60.5 44.1 38.7 15.0 246.9 131.0 377.9
====== ====== ===== ====== ===== ===== ===== =====
Proved Developed
December 31, 1998 14.5 27.9 31.5 21.0 - 94.9 67.1 162.0
December 31, 1999 11.7 26.6 34.1 21.2 - 93.6 66.0 159.6
December 31, 2000 10.3 34.3 36.3 20.1 - 101.0 66.0 167.0
December 31, 2001 8.8 37.9 33.3 21.3 - 101.3 66.0 167.3
Schedule 2 - Estimated Net Proved Natural Gas Reserves
United United
(Billions of cubic feet) States Canada Kingdom Total
------ ------ ------- ------
Proved
December 31, 1998 440.1 130.1 39.1 609.3
Revisions of previous estimates (2.6) 5.5 3.9 6.8
Extensions and discoveries 53.6 10.8 - 64.4
Production (62.7) (20.6) (4.5) (87.8)
Sales (1.1) - - (1.1)
------ ------ ----- ------
December 31, 1999 427.3 125.8 38.5 591.6
Revisions of previous estimates (41.9) (5.0) .3 (46.6)
Purchases 5.4 163.3 - 168.7
Extensions and discoveries 31.2 40.1 - 71.3
Production (53.0) (27.0) (4.0) (84.0)
Sales - (3.6) - (3.6)
------ ------ ----- ------
December 31, 2000 369.0 293.6 34.8 697.4
Revisions of previous estimates (20.2) (2.1) 4.9 (17.4)
Improved recovery - .9 - .9
Purchases - 30.7 - 30.7
Extensions and discoveries 89.0 44.7 - 133.7
Production (42.1) (56.6) (4.8) (103.5)
Sales - (1.7) - (1.7)
------ ------ ----- ------
December 31, 2001 395.7 309.5 34.9 740.1
====== ====== ===== ======
Proved Developed
December 31, 1998 291.8 120.3 29.9 442.0
December 31, 1999 284.8 111.3 32.9 429.0
December 31, 2000 233.8 255.2 32.3 521.3
December 31, 2001 189.6 277.5 34.1 501.2
F-29
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)(Continued)
Schedule 3 - Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities
Synthetic
United United Oil -
(Millions of dollars) States Canada Kingdom Ecuador Malaysia Other Subtotal Canada Total
------ ------ ------- ------- -------- ----- -------- ------ -----
Year Ended December 31, 2001
Property acquisition costs
Unproved $ 40.1 25.1 - - - - 65.2 - 65.2
Proved .3 21.3 - - - - 21.6 - 21.6
----- ----- ----- ----- ----- ----- ----- ----- -----
Total acquisition costs 40.4 46.4 - - - - 86.8 - 86.8
Exploration costs 86.5 105.9 .9 - 44.3 4.6 242.2 - 242.2
Development costs 132.1 167.4 17.9 9.0 .9 - 327.3 27.2 354.5
----- ----- ----- ----- ----- ----- ----- ----- -----
Total capital expenditures 259.0 319.7 18.8 9.0 45.2 4.6 656.3 27.2 683.5
----- ----- ----- ----- ----- ----- ----- ----- -----
Charged to expense
Dry hole expense 23.7 47.0 .1 - 8.4 3.6 82.8 - 82.8
Geophysical and other costs 9.1 12.9 .8 - 27.2 1.0 51.0 - 51.0
----- ----- ----- ----- ----- ----- ----- ----- -----
Total charged to expense 32.8 59.9 .9 - 35.6 4.6 133.8 - 133.8
----- ----- ----- ----- ----- ----- ----- ----- -----
Expenditures capitalized $ 226.2 259.8 17.9 9.0 9.6 - 522.5 27.2 549.7
===== ===== ===== ===== ===== ===== ===== ===== =====
Year Ended December 31, 2000
Property acquisition costs
Unproved S 19.2 25.1 - - - - 44.3 - 44.3
Proved 1.5 2.9 - - - - 4.4 - 4.4
----- ----- ----- ----- ----- ----- ----- ----- -----
Total 20.7 28.0 - - - - 48.7 - 48.7
Exploration costs 96.2 32.1 5.2 .1 18.4 4.7 156.7 - 156.7
Development costs 20.3 113.8 22.5 12.2 - - 168.8 18.5 187.3
----- ----- ----- ----- ----- ----- ----- ----- -----
Total capital expenditures 137.2 173.9 27.7 12.3 18.4 4.7 374.2 18.5 392.7
----- ----- ----- ----- ----- ----- ----- ----- -----
Beau Canada property acquisition
Unproved - 18.2 - - - - 18.2 - 18.2
Proved - 241.8 - - - - 241.8 - 241.8
----- ----- ----- ----- ----- ----- ----- ----- -----
Total - 260.0 - - - - 260.0 - 260.0
----- ----- ----- ----- ----- ----- ----- ----- -----
Charged to expense
Dry hole expense 56.7 5.7 1.7 - 1.3 .6 66.0 - 66.0
Geophysical and other costs 10.6 21.2 1.4 - 9.0 3.3 45.5 - 45.5
----- ----- ----- ----- ----- ----- ----- ----- -----
Total charged to expense 67.3 26.9 3.1 - 10.3 3.9 111.5 - 111.5
----- ----- ----- ----- ----- ----- ----- ----- -----
Expenditures capitalized $ 69.9 407.0 24.6 12.3 8.1 .8 522.7 18.5 541.2
===== ===== ===== ===== ===== ===== ===== ===== =====
Year Ended December 31, 1999
Property acquisition costs
Unproved $ 12.1 6.2 - - - - 18.3 - 18.3
Proved - .4 - - - - .4 - .4
----- ----- ----- ----- ----- ----- ----- ----- -----
Total acquisition costs 12.1 6.6 - - - - 18.7 - 18.7
Exploration costs 54.9 14.2 1.2 1.0 2.6 5.3 79.2 - 79.2
Development costs 28.6 108.2 28.3 6.1 - - 171.2 26.8 198.0
----- ----- ----- ----- ----- ----- ----- ----- -----
Total capital expenditures 95.6 129.0 29.5 7.1 2.6 5.3 269.1 26.8 295.9
----- ----- ----- ----- ----- ----- ----- ----- -----
Charged to expense
Dry hole expense 24.2 3.9 3.0 - - 1.3 32.4 - 32.4
Geophysical and other costs 10.7 8.9 .9 - 1.5 5.2 27.2 - 27.2
----- ----- ----- ----- ----- ----- ----- ----- -----
Total charged to expense 34.9 12.8 3.9 - 1.5 6.5 59.6 - 59.6
----- ----- ----- ----- ----- ----- ----- ----- -----
Expenditures capitalized $ 60.7 116.2 25.6 7.1 1.1 (1.2) 209.5 26.8 236.3
===== ===== ===== ===== ===== ===== ===== ===== =====
F-30
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued)
Schedule 4 - Results of Operations for Oil and Gas Producing Activities
Synthetic
United United Oil -
(Millions of dollars) States Canada Kingdom Ecuador Malaysia Other Subtotal Canada Total
------ ------ ------- ------- -------- ----- -------- --------- -----
Year Ended December 31, 2001
Revenues
Crude oil and natural gas liquids
Transfers to consolidated operations $ 50.9 14.7 - - - - 65.6 15.4 81.0
Sales to unaffiliated enterprises 1.0 152.5 181.5 33.4 - - 368.4 80.4 448.8
Natural gas
Transfers to consolidated companies 3.8 - - - - - 3.8 - 3.8
Sales to unaffiliated enterprises 189.0 182.6 12.1 - - - 383.7 - 383.7
----- ----- ----- ---- ---- ---- ----- ---- -----
Total oil and gas revenues 244.7 349.8 193.6 33.4 - - 821.5 95.8 917.3
Other operating revenues (4.4) 2.1 .6 - - 2.2 .5 - .5
----- ----- ----- ---- ---- ---- ----- ---- -----
Total revenues 240.3 351.9 194.2 33.4 - 2.2 822.0 95.8 917.8
----- ----- ----- ---- ---- ---- ----- ---- -----
Costs and expenses
Production expenses 48.4 72.0 30.8 14.9 - - 166.1 51.9 218.0
Exploration costs charged to expense 32.8 59.9 .9 - 35.6 4.6 133.8 - 133.8
Undeveloped lease amortization 9.5 13.6 - - - - 23.1 - 23.1
Depreciation, depletion and amortization 40.3 90.7 37.2 6.4 .5 .3 175.4 8.3 183.7
Amortization of goodwill - 3.1 - - - - 3.1 - 3.1
Impairment of properties 8.9 - - - - - 8.9 - 8.9
Selling and general expenses 11.9 11.0 2.4 .6 - 5.6 31.5 .1 31.6
----- ----- ----- ---- ---- ---- ----- ---- -----
Total costs and expenses 151.8 250.3 71.3 21.9 36.1 10.5 541.9 60.3 602.2
----- ----- ----- ---- ---- ---- ----- ---- -----
88.5 101.6 122.9 11.5 (36.1) (8.3) 280.1 35.5 315.6
Income tax expense (benefit)/1/ 30.7 39.1 44.3 - - (1.0) 113.1 12.5 125.6
----- ----- ----- ---- ---- ---- ----- ---- -----
Results of operations/2/ $ 57.8 62.5 78.6 11.5 (36.1) (7.3) 167.0 23.0 190.0
===== ===== ===== ==== ==== ==== ===== ==== =====
Year Ended December 31, 2000
Revenues
Crude oil and natural gas liquids
Transfers to consolidated operations $ 68.6 68.4 11.6 - - - 148.6 37.9 186.5
Sales to unaffiliated enterprises 3.8 125.5 203.0 52.2 - - 384.5 53.6 438.1
Natural gas
Transfers to consolidated operations 4.8 - - - - - 4.8 - 4.8
Sales to unaffiliated enterprises 206.6 99.0 7.8 - - - 313.4 - 313.4
----- ----- ----- ---- ---- ---- ----- ---- -----
Total oil and gas revenues 283.8 292.9 222.4 52.2 - - 851.3 91.5 942.8
Other operating revenues (4.8) .5 .7 (.7) - 2.2 (2.1) - (2.1)
----- ----- ----- ---- ---- ---- ----- ---- -----
Total revenues 279.0 293.4 223.1 51.5 - 2.2 849.2 91.5 940.7
----- ----- ----- ---- ---- ---- ----- ---- -----
Costs and expenses
Production expenses 41.9 55.0 29.1 15.5 - - 141.5 40.4 181.9
Exploration costs charged to expense 67.3 26.9 3.1 - 10.3 3.9 111.5 - 111.5
Undeveloped lease amortization 7.7 6.4 - - - - 14.1 - 14.1
Depreciation, depletion and amortization 50.2 62.5 41.7 6.8 .4 .1 161.7 7.5 169.2
Impairment of properties 21.0 6.9 - - - - 27.9 - 27.9
Selling and general expenses 13.5 4.8 2.8 .3 - 4.5 25.9 .1 26.0
Loss on transportation and othe
disputed contractual items - - - 7.8 - - 7.8 - 7.8
----- ----- ----- ---- ---- ---- ----- ---- -----
Total costs and expenses 201.6 162.5 76.7 30.4 10.7 8.5 490.4 48.0 538.4
----- ----- ----- ---- ---- ---- ----- ---- -----
77.4 130.9 146.4 21.1 (10.7) (6.3) 358.8 43.5 402.3
Income tax expense 27.1 49.2 56.2 - - - 132.5 17.1 149.6
----- ----- ----- ---- ---- ---- ----- ---- -----
Results of operations/2/ $ 50.3 81.7 90.2 21.1 (10.7) (6.3) 226.3 26.4 252.7
===== ===== ===== ==== ==== ==== ===== ==== =====
/1/Includes gains of $5.8 for a provincial tax rate reduction in Canada and
$1.9 from settlement of U.K. income tax matters.
/2/Excludes corporate overhead and interest in 2001 and 2000 and cumulative
effect of accounting change in 2000.
F-31
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued)
Schedule 4 - Results of Operations for Oil and Gas Producing
Activities (Continued)
Synthetic
United United Oil -
(Millions of dollars) States Canada Kingdom Ecuador Malaysia Other Subtotal Canada Total
------ ------ ------- ------- -------- ----- -------- ------ -----
Year Ended December 31, 1999
Revenues
Crude oil and natural gas liquids
Transfers to consolidated operations $ 48.8 15.9 23.4 - - - 88.1 42.8 130.9
Sales to unaffiliated enterprises 5.6 91.8 111.3 36.1 - - 244.8 32.0 276.8
Natural gas
Transfer to consolidated operations 1.8 - - - - - 1.8 - 1.8
Sales to unaffiliated enterprises 145.8 40.2 7.7 - - - 193.7 - 193.7
----- ----- ----- ----- ----- ----- ----- ----- -----
Total oil and gas revenues 202.0 147.9 142.4 36.1 - - 528.4 74.8 603.2
Other operating revenues/1/ 4.4 .2 - 2.9 - 2.0 9.5 - 9.5
----- ----- ----- ----- ----- ----- ----- ----- -----
Total revenues 206.4 148.1 142.4 39.0 - 2.0 537.9 74.8 612.7
----- ----- ----- ----- ----- ----- ----- ----- -----
Costs and expenses
Production expenses 40.3 41.3 30.8 13.2 - - 125.6 36.5 162.1
Exploration costs charged to expense 34.9 12.8 3.9 - 1.5 6.5 59.6 - 59.6
Undeveloped lease amortization 7.0 4.0 - - - - 11.0 - 11.0
Depreciation, depletion and amortization 65.1 43.8 42.8 8.0 .1 - 159.8 7.1 166.9
Selling and general expenses 13.5 5.6 3.2 .1 - 1.1 23.5 - 23.5
Gain on disputed transportation - - - (4.9) - - (4.9) - (4.9)
----- ----- ----- ----- ----- ----- ----- ----- -----
Total costs and expenses 160.8 107.5 80.7 16.4 1.6 7.6 374.6 43.6 418.2
----- ----- ----- ----- ----- ----- ----- ---- -----
45.6 40.6 61.7 22.6 (1.6) (5.6) 163.3 31.2 194.5
Income tax expense 10.3 14.3 24.5 - - .5 49.6 10.5 60.1
----- ----- ----- ----- ----- ----- ----- ----- -----
Results of operations/2/ $ 35.3 26.3 37.2 22.6 (1.6) (6.1) 113.7 20.7 134.4
===== ===== ===== ===== ===== ===== ===== ===== =====
/1/Includes $3.3 from gain on disputed contractual item in Ecuador.
/2/Excludes corporate overhead and interest.
Schedule 5 - Capitalized Costs Relating to Oil and Gas Producing Activities
Synthetic
United United Oil -
(Millions of dollars) States Canada Kingdom Ecuador Malaysia Other Subtotal Canada Total
------ ------ ------- ------- -------- ----- -------- ------ -----
December 31, 2001
Unproved oil and gas properties $ 128.6 130.6 .3 - .4 3.5 263.4 - 263.4
Proved oil and gas properties 1,673.8 1,326.7 794.8 227.9 15.1 - 4,038.3 204.0 4,242.3
------- ------- ------ ------ ---- ---- -------- ----- --------
Gross capitalized costs 1,802.4 1,457.3 795.1 227.9 15.5 3.5 4,301.7 204.0 4,505.7
Accumulated depreciation,
depletion and amortization
Unproved oil and gas properties (23.0) (33.8) (.2) - - (3.5) (60.5) - (60.5)
Proved oil and gas properties* (1,289.7) (469.3) (612.6) (166.3) - - (2,537.9) (42.3) (2,580.2)
------- ------- ------ ------ ---- ---- -------- ----- --------
Net capitalized costs $ 489.7 954.2 182.3 61.6 15.5 - 1,703.3 161.7 1,865.0
======= ======= ====== ====== ==== ==== ======== ===== ========
December 31, 2000
Unproved oil and gas properties $ 109.9 76.2 .2 - 7.8 3.5 197.6 - 197.6
Proved oil and gas properties 1,493.6 1,213.5 805.2 219.0 - - 3,731.3 188.5 3,919.8
------- ------- ------ ------ ---- ---- -------- ----- --------
Gross capitalized costs 1,603.5 1,289.7 805.4 219.0 7.8 3.5 3,928.9 188.5 4,117.4
Accumulated depreciation,
depletion and amortization
Unproved oil and gas properties (38.4) (24.2) (.1) - - (3.5) (66.2) - (66.2)
Proved oil and gas properties* (1,244.0) (409.8) (601.4) (160.0) - - (2,415.2) (37.0) (2,452.2)
------- ------- ------ ------ ---- ---- -------- ----- --------
Net capitalized costs $ 321.1 855.7 203.9 59.0 7.8 - 1,447.5 151.5 1,599.0
======= ======= ====== ====== ==== ==== ======== ===== ========
*Does not include reserve for dismantlement costs of $160.8 in 2001 and $160 in
2000.
F-32
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued)
Schedule 6 - Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves
United United
(Millions of dollars) States Canada* Kingdom Ecuador Malaysia Total
------ ------- ------- ------- -------- -----
December 31, 2001
Future cash inflows $ 2,468.1 1,699.2 910.2 463.1 299.8 5,840.4
Future development costs (490.1) (98.5) (61.1) (63.2) (70.9) (783.8)
Future production and abandonment costs (740.8) (515.3) (401.0) (247.2) (79.3) (1,983.6)
Future income taxes (365.3) (287.7) (139.7) (37.8) (61.0) (891.5)
--------- ------- ------ ------ ----- --------
Future net cash flows 871.9 797.7 308.4 114.9 88.6 2,181.5
10% annual discount for estimated timing of
cash flows (372.8) (211.5) (94.0) (45.3) (31.5) (755.1)
--------- ------- ----- ------ ----- --------
Standardized measure of discounted future
net cash flows $ 499.1 586.2 214.4 69.6 57.1 1,426.4
========= ======= ===== ====== ===== ========
December 31, 2000
Future cash inflows $ 3,479.9 2,860.4 1,209.4 725.5 - 8,275.2
Future development costs (321.8) (97.3) (55.0) (72.2) - (546.3)
Future production and abandonment costs (479.2) (615.5) (378.8) (320.4) - (1,793.9)
Future income taxes (935.6) (673.4) (294.8) (95.6) - (1,999.4)
--------- ------- ------- ------ ----- --------
Future net cash flows 1,743.3 1,474.2 480.8 237.3 - 3,935.6
10% annual discount for estimated timing of
cash flows (620.4) (456.1) (153.3) (102.0) - (1,331.8)
--------- ------- ------- ------ ----- --------
Standardized measure of discounted future
net cash flows $ 1,122.9 1,018.1 327.5 135.3 - 2,603.8
========== ======= ======= ====== ===== ========
December 31, 1999
Future cash inflows $ 1,779.1 1,454.2 1,426.4 711.8 - 5,371.5
Future development costs (210.6) (90.1) (66.0) (48.1) - (414.8)
Future production and abandonment costs (443.5) (375.6) (417.4) (251.0) - (1,487.5)
Future income taxes (356.4) (202.8) (315.9) (115.9) - (991.0)
---------- ------- ------- ------ ----- --------
Future net cash flows 768.6 785.7 627.1 296.8 - 2,478.2
10% annual discount for estimated timing of
cash flows (271.3) (230.6) (205.5) (119.8) - (827.2)
---------- ------- ------- ------ ----- --------
Standardized measure of discounted future
net cash flows $ 497.3 555.1 421.6 177.0 - 1,651.0
========== ======= ======= ====== ===== ========
*Excludes future net cash flows from synthetic oil of $188 at December 31, 2001,
$441.5 at December 31, 2000 and $410.2 at December 31,1999.
Following are the principal sources of change in the standardized measure of
discounted future net cash flows for the years shown.
(Millions of dollars) 2001 2000 1999
---- ---- ----
Net changes in prices, production costs and development costs $(3,024.6) 722.0 1,188.2
Sales and transfers of oil and gas produced, net of production costs (267.7) (485.1) (317.9)
Net change due to extensions and discoveries 691.6 544.4 250.0
Net change due to purchases and sales of proved reserves 19.3 519.2 (2.0)
Development costs incurred 308.7 156.6 163.4
Accretion of discount 390.6 229.3 71.9
Revisions of previous quantity estimates 1.4 (73.7) 220.7
Net change in income taxes 703.3 (659.9) (505.2)
--------- ------- ------
Net increase (decrease) (1,177.4) 952.8 1,069.1
Standardized measure at January 1 2,603.8 1,651.0 581.9
--------- ------- -------
Standardized measure at December 31 $ 1,426.4 2,603.8 1,651.0
========= ======= =======
F-33
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)
First Second Third Fourth
(Millions of dollars except per share amounts) Quarter Quarter Quarter Quarter Year
------- ------- ------- ------- ----
Year Ended December 31, 2001/1/
Sales and other operating revenues $1,185.7 1,297.0 1,136.4 847.7 4,466.8
Income before income taxes 156.0 247.0 69.6 33.3 505.9
Net income 97.8 162.6 41.7 28.8 330.9
Net income per Common share - basic 2.17 3.60 .92 .63 7.32
Net income per Common share - diluted 2.16 3.56 .91 .63 7.26
Cash dividends per Common share .375 .375 .375 .375 1.50
Market Price of Common Stock/2/
High 69.00 87.85 85.70 84.98 87.85
Low 55.25 67.14 66.55 68.00 55.25
Year Ended December 31, 2000/1/
Sales and other operating revenues $1,019.3 1,092.4 1,232.2 1,270.4 4,614.3
Income before income taxes and
cumulative effect of accounting change 74.0 119.9 133.0 138.4 465.3
Income before cumulative effect of
accounting change 49.1 73.1 90.1 93.2 305.5
Cumulative effect of accounting change (8.7) -- -- -- (8.7)
Net income 40.4 73.1 90.1 93.2 296.8
Income per Common share - basic
Income before cumulative effect of
accounting change 1.09 1.62 2.00 2.07 6.78
Cumulative effect of accounting change (.19) -- -- -- (.19)
Net income .90 1.62 2.00 2.07 6.59
Income per Common share - diluted
Income before cumulative effect of
accounting change 1.09 1.61 1.99 2.06 6.75
Cumulative effect of accounting change (.19) -- -- -- (.19)
Net income .90 1.61 1.99 2.06 6.56
Cash dividends per Common share .35 .35 .375 .375 1.45
Market Price of Common Stock/2/
High 63.4375 66.5000 69.0625 68.8750 69.0625
Low 48.1875 54.7500 56.0000 53.3750 48.1875
/1/The effect of special gains (losses) on quarterly net income are reviewed
in Management's Discussion and Analysis of Financial Condition and Results
of Operations on pages 12 and 13 of this Form 10-K report. Quarterly totals,
in millions of dollars, and the effect per Common share of these special
items are shown in the following table.
First Second Third Fourth
Quarter Quarter Quarter Quarter Year
2001
----
Quarterly totals $ -- 67.6 -- -- 67.6
Per Common share - basic -- 1.50 -- -- 1.50
Per Common share - diluted -- 1.48 -- -- 1.48
2000
----
Quarterly totals $ -- 1.5 1.9 (1.9) 1.5
Per Common share - basic -- .03 .04 (.04) .03
Per Common share - diluted -- .03 .04 (.04) .03
/2/Prices are as quoted on the New York Stock Exchange.
F-34
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SCHEDULE II - VALUATION ACCOUNTS AND RESERVES
Additions
--------------------
Charged
Balance at (Credited) Balance at
(Millions of dollars) January 1 to Expense Other* Deductions December 31
---------- ---------- ------ ---------- -----------
2001
Deducted from asset accounts:
Allowance for doubtful accounts 10.2 2.3 -- (1.2) 11.3
Deferred tax asset valuation allowance 61.0 6.7 -- -- 67.7
Included in liabilities:
Accrued major repair costs 34.3 21.1 (.3) (10.5) 44.6
- ----------------------------------------------------------------------------------------------------------------
2000
Deducted from asset accounts:
Allowance for doubtful accounts 8.3 2.1 -- (.2) 10.2
Deferred tax asset valuation allowance 57.4 3.6 -- -- 61.0
Included in liabilities:
Accrued major repair costs 22.1 22.8 (.5) (10.1) 34.3
- ----------------------------------------------------------------------------------------------------------------
1999
Deducted from asset accounts:
Allowance for doubtful accounts 11.0 (2.5) -- (.2) 8.3
Allowance for inventory valuation 6.8 - -- (6.8) --
Deferred tax asset valuation allowance 47.3 10.1 -- -- 57.4
Included in liabilities:
Accrued major repair costs 43.5 18.7 .2 (40.3) 22.1
- ----------------------------------------------------------------------------------------------------------------
*Amounts represent changes in foreign currency exchange rates.
F-35