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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, 2000
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 incorporation or organization) (I.R.S. Employer Identification Number)
200 Peach Street, P. O. Box 7000, El Dorado, Arkansas 71731-7000
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (870) 862-6411
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Stock, $1.00 Par Value New York Stock Exchange
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, 2001, as quoted by the New
York Stock Exchange, was approximately $1,949,012,000.
Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31,
2001 was 45,047,369.
Documents incorporated by reference:
Portions of the Registrant's definitive Proxy Statement relating to the Annual
Meeting of Stockholders on May 9, 2001 have been incorporated by reference in
Part III herein.
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MURPHY OIL CORPORATION
TABLE OF CONTENTS - 2000 FORM 10-K REPORT
Page
Number
------
PART I
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 17
Item 8. Financial Statements and Supplementary Data 18
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 18
PART III
Item 10. Directors and Executive Officers of the Registrant 18
Item 11. Executive Compensation 18
Item 12. Security Ownership of Certain Beneficial Owners and Management 18
Item 13. Certain Relationships and Related Transactions 19
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 19
Exhibit Index 19
Signatures 21
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, Marketing and Transportation." For reporting purposes, Murphy's
exploration and production activities are subdivided into five geographic
segments - the United States, Canada, the United Kingdom, Ecuador and all other
countries; Murphy's refining, marketing and transportation activities are
subdivided into three geographic segments - the United States, the United
Kingdom and Canada. Additionally, "Corporate and Other Activities" include
interest income, interest expense and overhead not allocated to the segments. In
November 2000, Murphy acquired Beau Canada Exploration Ltd. (Beau Canada), an
independent oil and gas company with exploration and production assets in
western Canada.
The information appearing in the 2000 Annual Report to Security Holders (2000
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-9, F-21 through F-23, and F-26 through F-28 of this
Form 10-K report and on pages 4 through 8 of the 2000 Annual Report.
Exploration and Production
During 2000, Murphy's principal exploration and production activities were
conducted in the United States and Ecuador 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 2000 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 Malaysia, the Faroe
Islands, Ireland and Spain.
Murphy's estimated net quantities of proved oil and gas reserves and proved
developed oil and gas reserves at December 31, 1997, 1998, 1999 and 2000 by
geographic area are reported on page F-25 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, 2000 are shown on page 9 of the 2000 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-24 through F-29 of this Form 10-K report.
At December 31, 2000, 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 4 3 40 20 44 23
- Gulf of Mexico 878 522 302 112 1,180 634
- Frontier 119 44 - - 119 44
------ ------- ------ ----- ------ ------
Total United States 1,001 569 342 132 1,343 701
------ ------- ------ ----- ------ ------
Canada - Onshore 1,318 894 1,178 368 2,496 1,262
- Offshore 12,519 2,118 56 3 12,575 2,121
- Oil sands 160 8 96 5 256 13
------ ------- ------ ----- ------ ------
Total Canada 13,997 3,020 1,330 376 15,327 3,396
------ ------- ------ ----- ------ ------
United Kingdom 1,297 418 79 11 1,376 429
Ecuador - - 494 99 494 99
Malaysia 6,498 5,319 - - 6,498 5,319
Ireland 954 239 - - 954 239
Spain 330 99 - - 330 99
------ ------- ------ ---- ------ ------
Totals 24,077 9,664 2,245 618 26,322 10,282
====== ======= ====== ==== ====== ======
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, 2000.
Oil Wells Gas Wells
------------------ ------------------
Country Gross Net Gross Net
- ------- ------- ------- ------ -----
United States 287 123.8 190 73.8
Canada 3,068 798.0 850 385.0
United Kingdom 109 13.1 21 1.6
Ecuador 64 12.8 - -
-------- ------- ------ ------
Totals 3,528 947.7 1,061 460.4
======== ======= ====== ======
Wells included above with multiple
completions and counted as one well each 82 38.2 76 59.0
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
--------------- --------------- -------------- --------------- --------------- ---------------
Pro- Pro- Pro- Pro- Pro- Pro-
ductive Dry ductive Dry ductive Dry ductive Dry ductive Dry ductive Dry
-------- ---- ------- ---- ------- --- ------- --- ------- --- ------- ---
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
1998
- ----
Exploratory 9.0 .8 4.8 7.5 - - - - - 1.0 13.8 9.3
Development .6 - 5.4 - 1.9 - 1.2 - - - 9.1 -
Murphy's drilling wells in progress at December 31, 2000 are shown below.
Exploratory Development Total
--------------- ------------- -----------------
Country Gross Net Gross Net Gross Net
- ------- ----- --- ----- --- ----- ---
United States 3 .7 - - 3 .7
Canada 11 6.5 5 1.8 16 8.3
United Kingdom - - 4 .3 4 .3
----- --- ---- ---- ---- ----
Totals 14 7.2 9 2.1 23 9.3
===== === ==== ==== ==== ====
Additional information about current exploration and production activities is
reported on pages 1 through 6 of the 2000 Annual Report.
Refining, Marketing and Transportation
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, 2000 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 4,453,000 2,852,000 2,638,000 9,943,000
*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 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, 2000, the Company marketed
products through 276 Murphy USA stations and 436 SPUR stations (19 of which are
either owned or leased by the Company). MOUSA plans to add up to 125 new Murphy
USA stations at Wal-Mart sites in the southern and midwestern United States in
2001.
At the end of 2000, Murco distributed refined products in the United Kingdom
from the Milford Haven refinery, three wholly owned terminals supplied by rail,
six terminals owned by others where products are received in exchange for
deliveries from the Company's terminals, and 386 branded stations under the
brand names MURCO and EP.
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 22% interest in a 312-mile crude oil pipeline in Montana
and Wyoming, with a capacity of 120,000 barrels a day, and a 3.2% 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.
4
At December 31, 2000, MOCL operated the following Canadian crude oil pipelines,
with the ownership percentage, extent and capacity in barrels a day of each as
shown. MOCL also operated and owned all or most of several short lateral
connecting pipelines. In 2001, the Company entered into an agreement to sell its
Canadian pipeline and trucking operation.
Pipeline Description Percent Miles Bbls./Day Route
- -------- ----------- ------- ----- --------- -----
Manito Dual heavy oil 100 101 70,000 Dulwich to Kerrobert, Sask.
North-Sask Dual heavy oil 36.1 40 20,000 Paradise Hill to Dulwich, Sask.
Cactus Lake Dual heavy oil 13.1 40 50,000 Cactus Lake to Kerrobert, Sask.
Bodo Dual heavy oil 76.3 15 18,000 Bodo, Alta. to Cactus Lake, Sask.
Milk River Dual medium/light oil 100 10.5 118,000 Milk River, Alta. to U.S. border
Wascana Single light oil 100 108 45,000 Regina, Sask. to U.S. border
Senlac Dual heavy oil 100 28 15,000 Senlac to Unity, Sask.
Additional information about current refining, marketing and transportation
activities and a statistical summary of key operating and financial indicators
for each of the five years ended December 31, 2000 are reported on pages 1, 3,
7, 8 and 10 of the 2000 Annual Report.
Employees
At December 31, 2000, Murphy had 3,109 employees - 1,711 full-time and 1,398
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 purchases refined products and 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" on page 17 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, marketing and transportation of crude oil and petroleum products.
The occurrence of a significant event could result in the loss of hydrocarbons,
environmental pollution, personal injury and loss of life, damage to the
property of the Company and others, and loss of revenues, 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 potentially
significant events or that insurance coverage will continue to be available in
the future on terms that justify its purchase. The occurrence of a significant
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, 2001, 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 43; 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 46; 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.
Steven A. Cosse' - Age 53; 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.
Herbert A. Fox Jr. - Age 66; Vice President since October 1994. Mr. Fox has also
been President of MOUSA since 1992. He served with MOUSA as Vice President,
Manufacturing, from 1990 to 1992.
Bill H. Stobaugh - Age 49; 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.
Odie F. Vaughan - Age 64; Treasurer since August 1991. From 1975 through July
1991, he was with ODECO as Vice President of Taxes and Treasurer.
John W. Eckart - Age 42; 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 38; 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
On June 29, 2000, the U.S. Government and the State of Wisconsin each filed a
lawsuit against Murphy in the U.S. District Court for the Western District of
Wisconsin. The State action was subsequently dismissed by the federal court and
refiled in state court in Douglas County, Wisconsin. The suits, arising out of a
1998 compliance inspection, include claims for alleged violations of federal and
state environmental laws at Murphy's Superior, Wisconsin refinery. The suits
seek compliance as well as substantial federal and state monetary penalties,
which could exceed $100,000. The Company believes it has valid defenses to these
allegations and plans a vigorous defense. The enforcement actions are ongoing
and while no assurance can be given about the outcome, the Company does not
believe that the resolution of these matters 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. On February 9, 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 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.
6
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 results of operations 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 2000.
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 3,185
stockholders of record as of December 31, 2000. Information as to high and low
market prices per share and dividends per share by quarter for 2000 and 1999 are
reported on page F-30 of this Form 10-K report.
Item 6. SELECTED FINANCIAL DATA
(Thousands of dollars except per share data) 2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Results of Operations for the Year/1/
Sales and other operating revenues/2/ $ 4,614,341 2,752,083 2,342,644 3,301,542 3,262,418
Net cash provided by continuing operations/2/ 747,751 341,711 297,467 365,825 440,458
Income (loss) from continuing operations 305,561 119,707 (14,394) 132,406 125,956
Income (loss) before cumulative effect
of accounting change 305,561 119,707 (14,394) 132,406 137,855
Net income (loss) 296,828 119,707 (14,394) 132,406 137,855
Per Common share - diluted
Income (loss) from continuing operations 6.75 2.66 (.32) 2.94 2.80
Income (loss) before cumulative effect
of accounting change 6.75 2.66 (.32) 2.94 3.07
Net income (loss) 6.56 2.66 (.32) 2.94 3.07
Cash dividends per Common share 1.45 1.40 1.40 1.35 1.30
Percentage return on
Average stockholders' equity 26.4 12.3 (1.3) 12.7 12.2
Average borrowed and invested capital 20.3 9.7 (.6) 10.4 10.4
Average total assets 11.2 5.2 (.6) 6.0 6.2
Capital Expenditures for the Year
Exploration and production $ 392,732 295,958 331,647 423,181 373,984
Refining, marketing and transportation 153,750 88,075 55,025 37,483 42,880
Corporate and other 11,415 2,572 2,127 7,367 1,192
----------- --------- --------- --------- ---------
$ 557,897 386,605 388,799 468,031 418,056
=========== ========= ========= ========= =========
Financial Condition at December 31
Current ratio 1.10 1.22 1.15 1.10 1.10
Working capital $ 71,710 105,477 56,616 48,333 56,128
Net property, plant and equipment 2,184,719 1,782,741 1,662,362 1,655,838 1,556,830
Total assets 3,134,353 2,445,508 2,164,419 2,238,319 2,243,786
Long-term debt 524,759 393,164 333,473 205,853 201,828
Stockholders' equity 1,259,560 1,057,172 978,233 1,079,351 1,027,478
Per share 27.96 23.49 21.76 24.04 22.90
Long-term debt - percent of capital employed 29.4 27.1 25.4 16.0 16.4
/1/Includes effects on income of special items in 2000, 1999 and 1998 that are
detailed in Management's Discussion and Analysis of Financial Condition and
Results of Operations. Also, special items in 1997 and 1996 increased net
income by $68, with no per share effect, and $22,124, $.49 a diluted share,
respectively.
/2/Prior year amounts have been reclassified to conform to 2000 presentation.
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 2000 of $296.8 million, $6.56 a
diluted share, compared to net income in 1999 of $119.7 million, $2.66 a diluted
share. In 1998, the Company lost $14.4 million, $.32 a diluted share. Net income
for the three years ended December 31, 2000 included certain special items that
resulted in a net charge of $7.2 million, $.16 a diluted share, in 2000; a net
benefit of $19.7 million, $.44 a diluted share, in 1999; and a net charge of
$57.9 million, $1.29 a diluted share, in 1998. The special items in 2000
included an after-tax charge of $17.8 million, $.39 a diluted share, from write-
down of assets determined to be impaired under Statement of Financial Accounting
Standards (SFAS) No. 121; 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.
Unusual items that increased earnings in 2000 included a $25.6 million
settlement of income tax matters, $.56 a share, and a gain on sale of assets of
$1.5 million, $.03 a share. 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.
Special items in 1998 included an after-tax charge of $57.6 million, $1.28 a
diluted share, from write-down of assets under SFAS No. 121.
2000 vs. 1999 - Excluding special items, income in 2000 totaled a Company record
$304 million, $6.72 a diluted share. The results for 2000 represented a $204
million improvement compared to income of $100 million, $2.22 a diluted share,
before special items 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 a barrel in 2000
and $17.08 a barrel in 1999. The average sales price of North American natural
gas improved from $2.25 a thousand cubic feet (MCF) in 1999 to $3.90 in 2000.
Earnings from refining, marketing and transportation 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, which include interest income and expense and corporate
overhead not allocated to operating functions, were $28.8 million in 2000,
excluding special items, compared to $36.1 million in 1999. The $7.3 million
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.
1999 vs. 1998 - Excluding special items, income in 1999 totaled $100 million,
$2.22 a share, an increase of $56.5 million from the $43.5 million earned in
1998. The increase in income was primarily attributable to stronger earnings
from exploration and production operations, which totaled $121.2 million in 1999
compared to $5.8 million in 1998. This improvement was partially offset by lower
earnings from refining, marketing and transportation operations, which earned
$14.9 million in 1999, down from $49.2 million earned in 1998. The improvement
in exploration and production earnings in 1999 was primarily attributable to an
increase of $5.91 a barrel in the average worldwide crude oil sales price, up
53% compared to 1998, and record crude oil production. In addition, the
Company's worldwide natural gas sales volume and U.S. natural gas sales prices
both increased 4% in 1999. Refining, marketing and transportation operations
were adversely affected by the increase in the prices of crude oil and other
refinery feedstocks. This segment's decline in earnings was primarily
attributable to lower U.S. operating results, as rising crude oil prices
squeezed margins throughout most of the year. The costs of corporate and other
activities were $36.1 million in 1999 compared to $11.5 million in 1998. The
increase in 1999 was principally due to higher net interest costs and higher
costs of awards under the Company's incentive plans.
In the following table, the Company's results of operations for the three years
ended December 31, 2000 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, marketing and
transportation activities follow the table.
8
(Millions of dollars) 2000 1999 1998
---- ---- ----
Exploration and production
United States $ 63.9 30.3 20.1
Canada 112.3 47.0 2.6
United Kingdom 90.2 37.2 .7
Ecuador 28.9 14.4 2.4
Other (17.0) (7.7) (20.0)
-------- ------- -------
278.3 121.2 5.8
-------- ------- -------
Refining, marketing and transportation
United States 23.9 (5.9) 27.7
United Kingdom 23.0 14.0 16.8
Canada 7.6 6.8 4.7
-------- ------- -------
54.5 14.9 49.2
-------- ------- -------
Corporate and other (28.8) (36.1) (11.5)
-------- ------- -------
Income before special items and
cumulative effect of accounting change 304.0 100.0 43.5
Settlement of income tax matters 25.6 5.0 -
Gain on sale of assets 1.5 7.5 2.9
Impairment of properties (17.8) - (57.6)
Gain (loss) on transportation and other
disputed contractual items in Ecuador (7.8) 8.2 2.4
Provision for reduction in force - (1.0) -
Charge resulting from cancellation of a drilling rig contract - - (4.2)
Write-down of crude oil inventories to market value - - (4.2)
Settlement of U.K. long-term sales contract - - 2.8
-------- ------- -------
Income (loss) before cumulative effect
of accounting change 305.5 119.7 (14.4)
Cumulative effect of accounting change (8.7) - -
--------- ------- -------
Net income (loss) $ 296.8 119.7 (14.4)
========= ======= =======
Exploration and Production - Earnings from exploration and production operations
before special items were a record $278.3 million in 2000, compared to earnings
of $121.2 million in 1999 and $5.8 million in 1998. The year over year
improvements in 2000 and 1999 were both primarily due to increases in the
Company's crude oil sales prices. The Company's 2000 earnings were also
favorably affected by 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 partially offset the effects of higher
commodity prices. Total oil production in 1999 was a Company record due
primarily to production from new fields in the United Kingdom and Canada. In
addition, natural gas sales volumes in 1999 were higher than in 1998 in both the
United States and Canada.
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-27 and F-28 of
this Form 10-K report. Daily production and sales rates and weighted average
sales prices are shown on page 9 of the 2000 Annual Report.
A summary of oil and gas revenues, including intersegment sales that are
eliminated in the consolidated financial statements, is presented in the
following table.
9
(Millions of dollars) 2000 1999 1998
---- ---- ----
United States
Crude oil $ 72.4 54.4 35.9
Natural gas 211.4 147.6 136.3
Canada
Crude oil 193.9 107.7 57.4
Natural gas 99.0 40.2 25.1
Synthetic oil 91.5 74.8 53.0
United Kingdom
Crude oil 214.6 134.7 70.3
Natural gas 7.8 7.7 10.0
Ecuador - crude oil 52.2 36.1 24.2
-------- ------ -----
Total oil and gas revenues $ 942.8 603.2 412.2
======== ====== =====
The Company's crude oil and gas liquids production averaged 65,259 barrels a day
in 2000, 66,083 in 1999 and 59,128 in 1998. Sales of crude oil and gas liquids
in 2000 were slightly higher and averaged 65,745 barrels a day. Crude oil and
liquids production in the United States declined 21% in 2000, following a 9%
increase in 1999. The reduction in 2000 was primarily due to declines from
existing fields in the Gulf of Mexico. Oil production in Canada increased 4% in
2000 to a record volume of 31,296 barrels a day. Production at Hibernia rose
2,795 barrels a day due to improved operations. Heavy oil production in western
Canada was 1,475 barrels a 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 a day
in 2000 due to a combination of more downtime for maintenance and a higher net
profit royalty caused by higher prices. Before royalties, the Company's
synthetic oil production was 10,145 barrels a day in 2000, 11,146 in 1999 and
10,501 in 1998. Production of light oil in Canada decreased 400 barrels a day in
2000. U.K. production increased by 357 barrels a 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 a day in
2000 due to transportation constraints. When compared to 1998 oil production,
1999 volumes were up 663 barrels a day in the United States, while production at
Hibernia was up 2,212, synthetic oil production was up 497 and U.K. production
was 5,127 higher. Production of heavy oil in western Canada fell 577 barrels a
day in 1999, light oil declined 351, and production in Ecuador was down 616. The
1999 increase in the United States was due to new production from several small
fields in the Gulf of Mexico. Hibernia was improved due to more stabilized
operations achieved during the latter half of 1999. Synthetic oil production was
up due to higher gross production, partially offset by a higher net profit
royalty rate caused by higher prices. Heavy oil production was lower in 1999
because of selective field shut-ins due to low prices during the early part of
the year. The improvement in the United Kingdom in 1999 was due to a full year
of operations at Mungo/Monan and Schiehallion, both of which commenced
production in the third quarter of 1998. The decline in Ecuador production in
1999 was due to pipeline restrictions.
Worldwide sales of natural gas averaged 229.4 million cubic feet a day in 2000,
240.4 million in 1999 and 230.9 million in 1998. Sales of natural gas in the
United States were 144.8 million cubic feet a day in 2000, 171.8 million in 1999
and 169.5 million in 1998. The 16% reduction in 2000 was due to reduced
deliverability from maturing fields in the Gulf of Mexico. The increase in 1999
was mainly due to sales from several new fields in the Gulf of Mexico that more
than offset declining production from other fields. Natural gas sales in Canada
in 2000 were at record levels for the fifth consecutive year as sales increased
31% to 73.8 million cubic feet a day. Canadian natural gas sales had increased
15% in 1999. The increase in 2000 was primarily due to production from new
discoveries in western Canada, plus production obtained through the acquisition
of Beau Canada Exploration Ltd. (Beau Canada) in November. Natural gas sales in
the United Kingdom were 10.8 million cubic feet a day in 2000, down 1.6 million
compared to 1999. U.K. natural gas sales in 1999 were essentially unchanged from
1998 levels.
Worldwide crude oil sales prices continued to strengthen through much of 2000
following a solid improvement in 1999. In the United States, Murphy's 2000
average monthly sales prices for crude oil and condensate ranged from $26.12 a
barrel to $34.03 a barrel, and averaged $30.38 for the year, 68% above the
average 1999 price of $18.09. In Canada, the average sales price for light oil
was $27.68 a barrel in 2000, an increase of 63%. Heavy oil prices averaged
$17.83 a barrel, up 40% compared to a year ago. The average sales price for
synthetic oil in 2000 was $29.62, up 59% from 1999. The sales price for crude
oil from the Hibernia field increased 42% to $27.16 a barrel. U.K. sales prices
averaged
10
54% higher in 2000 at $27.78 a barrel. Sales prices in Ecuador were $22.01 a
barrel in 2000, up 53% from a year earlier. U.S. oil prices increased 40% in
1999 compared to 1998. In Canada, crude oil prices in 1999 were up 41% for light
oil, 95% for heavy oil, 36% for synthetic oil, and 62% for Hibernia. Oil prices
in the United Kingdom were up 44% in 1999, and prices in Ecuador were up 68%.
Worldwide oil prices showed signs of weakening in late 2000 and into early 2001.
Although the Organization of Petroleum Exporting Countries (OPEC) announced a
production cut effective February 1, 2001, the Company can make no assurances
that oil prices will remain at or near year-end 2000 prices of about $26.00 a
barrel for West Texas Intermediate grade crude oil.
North American natural gas sales prices strengthened as 2000 progressed 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.
Average monthly natural gas sales prices in the United States in 2000 ranged
from $2.48 an MCF in January to $6.68 in December. For the year, U.S. sales
prices increased 71% and averaged $4.01 an MCF compared to $2.34 in 1999. The
average price for natural gas sold in Canada during 2000 increased 87% to $3.67
an MCF, while prices in the United Kingdom increased 8% to $1.81. Average U.S.
natural gas sales prices were up 4% in 1999, and prices were up in Canada by 40%
as Canadian natural gas sales prices moved closer to parity with U.S. prices
during the year. The average U.K. gas sales price in 1999 fell 25% mainly as a
result of a contractual price basis adjustment at the Company's primary North
Sea gas field.
Based on 2000 volumes and deducting taxes at marginal rates, each $1 a barrel
and $.10 an MCF fluctuation in prices would have affected annual exploration and
production earnings by $16.2 million and $5.3 million, respectively. The effect
of these price fluctuations on consolidated net income cannot be measured
because operating results of the Company's refining, marketing and
transportation segments could be affected differently.
Production expenses were $181.9 million in 2000, $162.1 million in 1999 and
$167.3 million in 1998. These amounts are shown by major operating area on pages
F-27 and F-28 of this Form 10-K report. Cost per equivalent barrel during the
last three years were as follows.
(Dollars per equivalent barrel) 2000 1999 1998
---- ---- ----
United States $ 3.72 2.98 3.66
Canada
Excluding synthetic oil 4.24 3.99 3.91
Synthetic oil 13.06 9.09 8.99
United Kingdom 3.46 3.73 5.60
Ecuador 6.65 5.10 4.28
Worldwide - excluding synthetic oil 4.05 3.62 4.18
The increase in the cost per equivalent barrel in the United States in 2000 was
attributable to a combination of lower production and higher well servicing
costs. 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 in the cost per equivalent barrel for
Canadian synthetic oil in 2000 was due to lower 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 lower-cost Mungo/Monan and Schiehallion fields.
Higher cost per barrel in Ecuador in 2000 was attributable to both lower
production and higher overall operating expenses. The decrease in U.S.
production cost per equivalent barrel in 1999 was attributable to lower well
servicing costs combined with higher production volumes. The increase in Canada
in 1999, excluding synthetic oil, was caused by higher well servicing costs at
heavy oil properties. The increase in the Canadian synthetic oil unit rate was
due to an increase in royalty barrels caused by higher sales prices. The
decrease in the U.K. rate was due to higher production from the lower-cost
Mungo/Monan and Schiehallion fields. The higher cost in Ecuador in 1999 was
caused by higher field operating costs combined with lower production during the
year.
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-27
and F-28 of this Form 10-K report. Certain of the expenses are included in the
capital expenditure totals for exploration and production activities.
11
(Millions of dollars) 2000 1999 1998
---- ---- ----
Exploratory expenditures charged against income
Dry hole costs $ 66.0 32.4 31.5
Geological and geophysical costs 36.3 18.7 17.0
Other costs 9.2 8.5 6.6
-------- ------ -------
111.5 59.6 55.1
Undeveloped lease amortization 14.1 11.0 10.5
-------- ------ -------
Total exploration expenses $ 125.6 70.6 65.6
======== ====== =======
Depreciation, depletion and amortization related to exploration and production
operations totaled $169.2 million in 2000, $166.9 million in 1999 and $163.6
million in 1998. The increases in both 2000 and 1999 were due to higher
production from the Hibernia field, offshore eastern Canada. Additionally, 2000
includes higher depreciation rates per unit on production from fields acquired
from Beau Canada.
Refining, Marketing and Transportation - Earnings from refining, marketing and
transportation operations before special items were $54.5 million in 2000, $14.9
million in 1999 and $49.2 million in 1998. Operations in the United States
earned $23.9 million in 2000 compared to a loss of $5.9 million in 1999, as
product sales realizations increased more than the costs of crude oil and other
refinery feedstocks. U.S. operations earned $27.7 million in 1998. The decline
in 1999 was due to the inability to fully recover higher costs of crude oil
through increases in average product sales prices. Operations in the United
Kingdom earned $23 million in 2000, $14 million in 1999 and $16.8 million in
1998. The improvement in 2000 was also caused by a larger increase in the sales
realizations for finished products than for the costs of refining feedstocks.
Canadian operations contributed $7.6 million to 2000 earnings compared to $6.8
million in 1999 and $4.7 million in 1998.
Unit margins (sales realizations less costs of crude oil, other feedstocks,
refining and transportation to point of sale) averaged $1.91 a barrel in the
United States in 2000, $.66 in 1999 and $1.45 in 1998. U.S. product sales
totaled a record 149,469 barrels a day in 2000, up 18% following an 8% decline
in 1999. The increase in 2000 was attributable to a combination of record crude
oil throughputs at the Company's U.S. refineries plus continued expansion of
retail gasoline operations at Wal-Mart stores. The decline in sales volumes in
1999 was primarily due to a turnaround at the Meraux refinery early in the year.
Unit margins in the United Kingdom averaged $4.69 a barrel in 2000, $3.38 in
1999 and $2.81 in 1998. Sales of petroleum products were down 7% in 2000
following an 11% decrease in 1999. The volume decline in 2000 was attributable
to lower consumer demand in the United Kingdom caused by the large increase in
product prices during the year. The decline in 1999 was due to lower sales in
the cargo market. Although unit margins improved in 2000, the Company's branded
outlets still face competition from other motor fuel marketers. Unit margins
have softened in early 2001, and the Company was experiencing weaker financial
results in its U.K. downstream operations.
Based on sales volumes for 2000 and deducting taxes at marginal rates, each $.42
a barrel ($.01 a gallon) fluctuation in unit margins would have affected annual
refining and marketing profits by $17.5 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.
The improvement in the Company's Canadian downstream operating results in 2000
was due to higher pipeline throughputs after the acquisition of the minority
interest in the Manito pipeline system in mid-year. Higher earnings in 1999 were
attributable to improved operating results from crude oil trading and pipeline
operations. The Company entered into an agreement to sell its Canadian pipeline
and trucking operation in 2001.
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 2000 and 1999 are presented on page F-30 of this Form 10-K
report.
. Settlement of income tax matters - Gains of $15.5 million, $10.1 million
and $5 million for settlement of U.S. income tax matters were recorded
in the third quarter of 2000, the fourth quarter of 2000 and the fourth
quarter of 1999, respectively.
12
. Gain on sale of assets - After-tax gains on sale of assets included
$1.5 million recorded in the second quarter of 2000 from sale of U.S.
corporate assets, $6.3 million and $1.2 million recorded in the third
and fourth quarters, respectively, of 1999 from sale of U.S. service
stations, and $2.9 million recorded in the fourth quarter of 1998 from
sale of a U.K. service station.
. Impairment of properties - After-tax provisions of $13.6 million, $4.2
million and $57.6 million were recorded in the third quarter of 2000,
the fourth quarter of 2000 and the fourth quarter of 1998,
respectively, for the write-down of assets determined to be impaired.
(See Note D to the consolidated financial statements.)
. 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 gains of $8.2 million, $1.4 million and $1 million were
recorded in the fourth quarter of 1999, the second quarter of 1998 and
the fourth quarter of 1998, respectively, 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.)
. Charge resulting from cancellation of a drilling rig contract - An
after-tax charge of $4.2 million was recorded in the fourth quarter of
1998 resulting from cancellation of a drilling rig contract for the
Terra Nova oil field, offshore eastern Canada. The contract was
cancelled because market conditions allowed a more efficient and
modern rig to be obtained, thus reducing drilling costs for the Terra
Nova project compared to what they might otherwise have been.
. Write-down of crude oil inventories to market value - An after-tax
charge of $4.2 million was recorded in the fourth quarter of 1998 to
establish a valuation allowance to reduce the carried amount of crude
oil inventories in the United Kingdom and Canada to market values.
. Settlement of U.K. long-term sales contract - An after-tax gain of
$2.8 million was recorded in the second quarter of 1998 related to
settlement of a U.K. long-term sales contract.
. Cumulative effect of accounting change - An after-tax charge of $8.7
million was recorded in the first quarter of 2000 to carry 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, 2000 are summarized by segment in the following table.
(Millions of dollars) 2000 1999 1998
---- ---- ----
Exploration and production
United States $ (13.6) 5.0 (19.4)
Canada (4.2) - (10.1)
United Kingdom - - (14.0)
Ecuador (7.8) 8.2 2.4
Other - - (15.1)
------- ------ -------
(25.6) 13.2 (56.2)
------- ------ -------
Refining, marketing and transportation
United States - 7.5 -
United Kingdom - - .5
Canada - - (2.2)
------- ------ -------
- 7.5 (1.7)
------- ------ -------
Corporate and other 27.1 (1.0) -
------- ------ -------
Cumulative effect of accounting change (8.7) - -
------- ------ -------
Total income (loss) from special items $ (7.2) 19.7 (57.9)
======= ====== =======
13
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 $557.9 million in 2000 compared to $386.6 million in 1999 and $388.8
million in 1998. These amounts included $111.5 million, $59.6 million and $55.1
million of exploration costs that were expensed. Capital expenditures for
exploration and production activities totaled $392.7 million in 2000, 70% of the
Company's total capital expenditures for the year. Exploration and production
capital expenditures in 2000 included $44.3 million for acquisition of
undeveloped leases, $4.4 million for acquisition of proved oil and gas
properties, $156.7 million for exploration activities, and $187.3 million for
development projects. Development expenditures included $60.7 million for the
Terra Nova oil field, offshore Newfoundland; $18.5 million for synthetic oil
operations in Canada; and $44.6 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-26 of this Form 10-K report. Amounts shown under
"Other" in 2000 included $18.4 million for exploration costs in Malaysia,
including costs to drill a shallow-water discovery on Block SK 309, offshore
Sarawak.
Refining, marketing and transportation expenditures, detailed in the following
table, were 28% of total capital expenditures in 2000.
(Millions of dollars) 2000 1999 1998
---- ---- ----
Refining
United States $ 19.2 17.4 27.0
United Kingdom 4.3 7.0 .7
------ ------ ------
Total refining 23.5 24.4 27.7
------ ------ ------
Marketing
United States 92.8 58.7 16.7
United Kingdom 8.1 4.4 6.1
------ ------ ------
Total marketing 100.9 63.1 22.8
------ ------ ------
Transportation
United States - .3 1.9
Canada 29.4 .3 2.6
------ ------ ------
Total transportation 29.4 .6 4.5
------ ------ ------
Total $153.8 88.1 55.0
====== ====== ======
U.S. and U.K. refining 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
environmentally driven changes to U.S. motor fuel specifications. Marketing
expenditures in the United States primarily included the costs of new stations
built on land leased from Wal-Mart, and improvements and normal replacements at
existing stations and terminals. U.K. marketing expenditures in 2000 were
primarily for redevelopment of shops and station purchases; expenditures in 1999
and 1998 were primarily for improvements and normal replacements at existing
stations and terminals. Capital expenditures for Canadian transportation in 2000
primarily consisted of the mid-year acquisition of the minority interest in the
Manito pipeline system.
Cash Flows
Cash provided by operating activities was $747.8 million in 2000, $341.7 million
in 1999 and $297.5 million in 1998. Special items decreased cash flow from
operations by $2.7 million in 2000 and $6.3 million in 1998, 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
$35.2 million and $3.8 million in 1999 and 1998, respectively. Cash provided by
operating activities was further reduced by expenditures for refinery
turnarounds and abandonment of oil and gas properties totaling $16.6 million in
2000, $44.1 million in 1999 and $24.6 million in 1998.
Cash proceeds from property sales were $20.7 million in 2000, $40.9 million in
1999 and $9.5 million in 1998. Borrowings under notes payable provided $175
million of cash in 2000, $247.8 million in 1999 and $161.3 million in 1998.
14
Property additions and dry hole costs required $512.3 million of cash in 2000,
$359.4 million in 1999 and $365.2 million in 1998. Cash outlays for debt
repayment during the three years included $130.5 million in 2000, $195.9 million
in 1999 and $34.5 million in 1998. The acquisition of Beau Canada in November
2000 utilized $127.5 million of cash. Cash used for dividends to stockholders
was $65.3 million in 2000, $63 million in 1999 and $62.9 million in 1998.
Financial Condition
Year-end working capital totaled $71.7 million in 2000, $105.5 million in 1999
and $56.6 million in 1998. 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 $124 million below current costs at
December 31, 2000. Cash and cash equivalents at the end of 2000 totaled $132.7
million compared to $34.1 million a year ago and $28.3 million at the end of
1998.
Long-term debt increased $131.6 million during 2000 to $524.8 million at the end
of the year, 29.4% of total capital employed, and included $126.4 million of
nonrecourse debt incurred in connection with the acquisition and development of
Hibernia. The increase in long-term debt in 2000 was attributable to the
acquisition of Beau Canada. Long-term debt totaled $393.2 million at the end of
1999 compared to $333.5 million at December 31, 1998. Stockholders' equity was
$1.3 billion at the end of 2000 compared to $1.1 billion a year ago and $1
billion at the end of 1998. A summary of transactions in stockholders' equity
accounts is presented on page F-5 of this Form 10-K report.
The primary sources of the Company's liquidity are internally generated funds,
access to outside financing and working capital. The Company relies on
internally generated funds to finance the major portion of its capital and other
expenditures, but maintains lines of credit with banks and borrows as necessary
to meet spending requirements. Current financing arrangements are set forth in
Note E to the consolidated financial statements. The Company does not expect any
problem in meeting future requirements for funds.
Murphy had commitments of $353 million for capital projects in progress at
December 31, 2000, including $176 million related to a clean fuels expansion
project at the Meraux refinery and $67 million related to the Company's
multiyear contract for a semisubmersible deepwater drilling rig. Certain costs
committed under the rig contract will be charged to Murphy's partners when
future deepwater wells are drilled.
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 reserve for remedial obligations, which is included in Deferred
Credits and Other Liabilities in the Consolidated Balance Sheets, contains
certain amounts that are based on anticipated regulatory approval for proposed
remediation of former refinery waste sites. If regulatory authorities require
more costly alternatives than the proposed processes, future expenditures could
exceed the amount reserved 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 does not expect that its related remedial
15
costs will be material to its financial condition or its results of operations,
and it has not provided a reserve for remedial costs on Superfund sites.
Additional information may become known in the future that would alter this
assessment, including any requirement to bear a pro rate share of costs
attributable to nonparticipating PRPs or indications of additional
responsibility by the Company.
Lawsuits filed against Murphy by the U.S. Government and the State of Wisconsin
are discussed under the caption "Legal Proceedings" on page 6 of this Form 10-K
report.
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. Such expenditures could have a material
adverse effect on the results of operations in a future period.
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, 2000.
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 $2.9 million in 2000. 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
$26 million in 2000 and are projected to be $86 million in 2001.
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.
If crude oil and natural gas sales prices remain strong, the Company believes
that the future prices for oil field goods and services could be adversely
affected.
Accounting matters - The Financial Accounting Standards Board (FASB) issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities," in
1998. This statement established accounting and reporting standards for
derivative instruments and hedging activities. Subsequent to the issuance of
SFAS No. 133, the FASB received many requests to review and clarify certain
implementation issues. In June 2000, the FASB issued SFAS No. 138, which amended
certain provisions of SFAS No. 133. Effective January 1, 2001, Murphy must
recognize the fair value of all derivative instruments as either assets or
liabilities in its Consolidated Balance Sheet. A derivative instrument meeting
certain conditions may be designated as a hedge of a specific exposure;
accounting for changes in a derivative's fair value will depend on the intended
use of the derivative and the resulting designation. Changes in a derivative's
fair value for a qualifying hedge of a forecasted transactions will be deferred
and recorded as a component of Other Accumulated Comprehensive Income in the
Consolidated Balance Sheet until the forecasted transaction occurs, at which
time the derivative's value will be recognized in earnings. Ineffective portions
of a hedging derivative's change in fair value will be immediately recognized in
earnings. Transition adjustments resulting from adopting this statement will be
reported in net income or other comprehensive income, as appropriate, as the
cumulative effect of an accounting change. As described under the heading
"Quantitative and Qualitative Disclosures About Market Risk" on Page 17 of this
Form 10-K report, the Company makes limited use of derivative instruments to
hedge specific market risks. The Company has determined that the adoption of
SFAS 133 will increase other comprehensive income by approximately $4 million
and the overall effect on net income from adoption of this standard will not be
significant.
As described in Note B to the consolidated financial statements, the Company has
adopted a change in accounting for unsold crude oil production effective January
1, 2000, and also has retroactively applied two consensuses of the FASB Emerging
Issue Task Force to 2000 and all prior years presented.
16
Outlook
Prices for the Company's primary products are often quite volatile. During 1999
and most of 2000, increased worldwide demand and disciplined management of
supply by the world's producers - primarily by members of OPEC - led to stronger
oil prices. During late 2000 and early 2001, crude oil sales prices weakened
slightly. In mid-January 2001, OPEC announced a reduction in crude oil
production beginning February 1, 2001 and light sweet crude oil for March
delivery sold for more than $31 a barrel at that date. The Company can give no
assurance that the price of crude oil will remain at this high level during the
remainder of 2001 and beyond. Due to colder than normal weather across much of
North America during the early winter of 2000-2001, the price of natural gas
remained well above its normal trading range in January 2001. The Company can
give no assurance that the price of natural gas will remain at or above its
normal trading range in the future. The Company's U.K. refining and marketing
operations were experiencing weaker unit margins in early 2001. In such a
volatile operating environment, constant reassessment of spending plans is
required.
The Company's capital expenditure budget for 2001 was prepared during the fall
of 2000 and provides for expenditures of $692 million. Of this amount, $518
million or 75%, is allocated for exploration and production. Geographically, 39%
of the exploration and production budget is allocated to the United States,
including $84 million for development of deepwater projects in the Gulf of
Mexico; another 43% is allocated to Canada, including $29 million for continued
development of the Terra Nova oil field, which is currently scheduled for
start-up late in 2001, and $22 million for further expansion of synthetic oil
operations; 7% is allocated to the United Kingdom; 3% is allocated to Ecuador;
and 8% is allocated to other foreign operations, which primarily includes
Malaysia. Planned refining, marketing and transportation capital expenditures
for 2001 are $168 million, including $145 million in the United States, $20
million in the United Kingdom and $3 million in Canada. U.S. amounts include
funds to build additional stations at Wal-Mart sites, as well as early spending
for "green fuel" projects at the Meraux refinery. Capital and other expenditures
are under constant review and planned capital expenditures may be adjusted to
reflect changes in estimated cash flow during 2001.
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, 2000, the Company was a party to interest rate swaps with
notional amounts totaling $100 million that were designed to convert a similar
amount of variable-rate debt to fixed rates. 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, 2000, the interest rate to be
received by the Company averaged 6.72%. 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 $2 million at
December 31, 2000.
At December 31, 2000, 20% of the Company's debt had variable interest rates and
12% was denominated in Canadian dollars. Based on debt outstanding at December
31, 2000, a 10% increase in variable interest rates would reduce the
17
Company's interest expense by $.1 million in 2001 after a $.7 million 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 2001 by $.2 million
and increase current maturities of long-term debt by $.8 million for debt
denominated in Canadian dollars.
At December 31, 2000, Murphy was a party to natural gas price swap agreements
for a total notional volume of 7 million MMBTU that are intended to reduce a
portion of the financial exposure of its Meraux, Louisiana refinery to
fluctuations in the price of natural gas purchased for fuel in 2002 through
2004. In each month of settlement, the swaps require Murphy to pay an average
natural gas price of $2.61 an MMBTU and to receive the average NYMEX Henry Hub
price for the final three trading days of the month. At December 31, 2000, the
estimated fair value of these agreements was a gain of $6.2 million; a 10%
fluctuation in the average NYMEX Henry Hub price of natural gas would have
changed the estimated year-end fair value of these swaps by $2.1 million.
At December 31, 2000, Murphy was also a party to certain natural gas swap
agreements for a total notional volume of 20,000 gigajoules (GJ) a day through
October 2001 that are intended to reduce a portion of the financial exposure of
its Canadian natural gas production to changes in natural gas sales prices. In
each month, the swaps require Murphy to pay the AECO "C" index price and to
receive an average of C$2.47 per GJ. The Company also has a natural gas swap
agreement for the purchase of 10,000 GJ per day through October 2001 that
requires Murphy to pay C$5.64 per GJ and to receive based on the AECO "C" index.
At December 31, 2000, the estimated net fair value of these agreements was a
liability of $18.3 million; a 10% fluctuation in the average price of the AECO
"C" index would have changed the estimated year-end fair value of these swaps by
$1.7 million.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information required by this item appears on pages F-1 through F-30, which
follow page 21 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 9, 2001 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 9, 2001 under the captions "Compensation of Directors," "Executive
Compensation," "Option Exercises and Fiscal Year-End Values," "Option Grants,"
"Compensation Committee Report for 2000," "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 9, 2001 under the captions "Security Ownership of Certain Beneficial
Owners" and "Security Ownership of Management."
18
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by this item is incorporated by reference to the
Registrant's definitive Proxy Statement for the Annual Meeting of Stockholders
on May 9, 2001 under the caption "Compensation Committee Interlocks and Insider
Participation."
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 Statements of Comprehensive Income F-2
Consolidated Balance Sheets F-3
Consolidated Statements of Cash Flows F-4
Consolidated Statements of Stockholders' Equity F-5
Notes to Consolidated Financial Statements F-6
Supplemental Oil and Gas Information (unaudited) F-24
Supplemental Quarterly Information (unaudited) F-30
2. Financial Statement Schedules - Financial statement schedules are
omitted because either they are not applicable or the required
information is included in the consolidated financial statements or
notes thereto.
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 as of Exhibit 3.1 of Murphy's Form 10-K report for the
September 25, 1986 year ended December 31, 1996
*3.2 By-Laws of Murphy Oil Corporation as amended effective February 7,
2001
4 Instruments Defining the Rights of Security Holders. Murphy is party
to several long-term debt instruments in addition to the ones in
Exhibits 4.1 and 4.2, 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 Credit Agreement among Murphy Oil Corporation and certain Exhibit 4.1 of Murphy's Form 10-K report for the
subsidiaries and the Chase Manhattan Bank et al as of November 13, year ended December 31, 1997
1997
19
4.2 Form of Indenture and Form of Supplemental Indenture between Murphy Exhibits 4.1 and 4.2 of Murphy's Form 8-K report
Oil Corporation and SunTrust Bank, Nashville, N.A., as Trustee filed April 29, 1999 under the Securities Exchange
Act of 1934
4.3 Rights Agreement dated as of December 6, 1989 between Murphy Oil Exhibit 4.3 of Murphy's Form 10-K report for
Corporation and Harris Trust Company of New York, as Rights the year ended December 31, 1999
Agent
4.4 Amendment No. 1 dated as of April 6, 1998 to Rights Agreement dated Exhibit 3 of Murphy's Form 8-A/A, Amendment No. 1,
as of December 6, 1989 between Murphy Oil Corporation and Harris filed April 14, 1998 under the Securities Exchange
Trust Company of New York, as Rights Agent Act of 1934
4.5 Amendment No. 2 dated as of April 15, 1999 to Rights Agreement dated Exhibit 4 of Murphy's Form 8-A/A, Amendment No. 2,
as of December 6, 1989 between Murphy Oil Corporation and Harris filed April 19, 1999 under the Securities Exchange
Trust Company of New York, as Rights Agent Act of 1934
10.1 1987 Management Incentive Plan as amended February 7, 1990 Exhibit 10.1 of Murphy's Form 10-K report for the
retroactive to February 3, 1988 year ended December 31, 1999
10.2 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
10.3 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 2000 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 December 31, 2000 To be filed as an amendment to this Form 10-K
covering the Thrift Plan for Employees of Murphy Oil Corporation report not later than 180 days after December 31,
2000
#99.3 Form 11-K, Annual Report for the fiscal year ended December 31, To be filed as an amendment to this Form 10-K
2000 covering the Thrift Plan for Employees of Murphy Oil USA, report not later than 180 days after December 31,
Inc. Represented by United Steelworkers of America, AFL-CIO, 2000
Local No. 8363
#99.4 Form 11-K, Annual Report for the fiscal year ended December 31, 2000 To be filed as an amendment to this Form 10-K
covering the Thrift Plan for Employees of Murphy Oil USA, Inc. report not later than 180 days after December 31,
Represented by International Union of Operating Engineers, 2000
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, 2000.
20
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
MURPHY OIL CORPORATION
By /s/ CLAIBORNE P. DEMING Date: March 22, 2001
-------------------------------------- ---------------------
Claiborne P. Deming, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below on March 22, 2001 by the following persons on behalf of
the registrant and in the capacities indicated.
/s/ R. MADISON MURPHY /s/ WILLIAM C. NOLAN JR.
- ---------------------------------------- -----------------------------------
R. Madison Murphy, Chairman and Director William C. Nolan Jr., Director
/s/ CLAIBORNE P. DEMING /s/ WILLIAM L. ROSOFF
- ---------------------------------------- -----------------------------------
Claiborne P. Deming, President and Chief William L. Rosoff, Director
Executive Officer and Director
(Principal Executive Officer)
/s/ B. R. R. BUTLER /s/ DAVID J. H. SMITH
- ---------------------------------------- -----------------------------------
B. R. R. Butler, Director David J. H. Smith, Director
/s/ GEORGE S. DEMBROSKI /s/ CAROLINE G. THEUS
- ---------------------------------------- -----------------------------------
George S. Dembroski, Director Caroline G. Theus, Director
/s/ H. RODES HART /s/ STEVEN A. COSSE
- ---------------------------------------- -----------------------------------
H. Rodes Hart, Director Steven A. Cosse, Senior Vice
President and General Counsel
(Principal Financial Officer)
/s/ ROBERT A. HERMES /s/ JOHN W. ECKART
- ---------------------------------------- -----------------------------------
Robert A. Hermes, Director John W. Eckart, Controller
(Principal Accounting Officer)
/s/ MICHAEL W. MURPHY
- ----------------------------------------
Michael W. Murphy, Director
21
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 perform an
oversight role for the financial statements. This Committee is composed solely
of directors who are not employees of the Company. The Committee meets
periodically with representatives of management, the Company's audit staff and
the independent auditors to review the Company's internal controls, the quality
of its financial reporting, and the scope and results of audits. The independent
auditors and the Company's audit staff have unrestricted access to the
Committee, without management's presence, to discuss audit findings and other
financial matters.
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders of Murphy Oil Corporation:
We have audited the accompanying consolidated balance sheets of Murphy Oil
Corporation and Consolidated Subsidiaries as of December 31, 2000 and 1999, 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, 2000. 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, 2000 and 1999, and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 2000, 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, 2000, the Company changed its method of accounting for crude oil
inventories.
Shreveport, Louisiana /s/ KPMG LLP
January 26, 2001
F-1
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31 (Thousands of dollars except per share amounts) 2000 1999* 1998*
---- ---- ----
Revenues
Crude oil and natural gas sales $ 751,498 470,643 324,882
Petroleum product sales 2,731,988 1,515,537 1,312,727
Crude oil trading sales 1,041,524 705,969 638,106
Other operating revenues 89,331 59,934 66,929
Interest and other nonoperating revenues 24,824 4,358 4,378
------------ ------------ ------------
Total revenues 4,639,165 2,756,441 2,347,022
------------ ------------ ------------
Costs and Expenses
Crude oil, products and related operating expenses 3,704,936 2,198,701 1,927,325
Exploration expenses, including undeveloped lease amortization 125,629 70,557 65,582
Selling and general expenses 85,474 81,817 61,363
Depreciation, depletion and amortization 213,539 205,077 203,163
Impairment of properties 27,916 -- 80,127
Charge resulting from cancellation of a drilling rig contract -- -- 7,255
Provision for reduction in force -- 1,513 --
Interest expense 29,936 28,139 18,090
Interest capitalized (13,599) (7,865) (7,606)
------------ ------------ ------------
Total costs and expenses 4,173,831 2,577,939 2,355,299
------------ ------------ ------------
Income (loss) before income taxes and cumulative effect of
accounting change 465,334 178,502 (8,277)
Income tax expense 159,773 58,795 6,117
------------ ------------ ------------
Income (loss) before cumulative effect of accounting change 305,561 119,707 (14,394)
Cumulative effect of accounting change, net of tax (Note B) (8,733) -- --
------------ ------------ ------------
Net Income (Loss) $ 296,828 119,707 (14,394)
============ ============ ============
Income (Loss) per Common Share - Basic
Before cumulative effect of accounting change $ 6.78 2.66 (.32)
Cumulative effect of accounting change (.19) -- --
------------ ------------ ------------
Net Income (Loss) - Basic 6.59 2.66 (.32)
============ ============ ============
Income (Loss) per Common Share - Diluted
Before cumulative effect of accounting change $ 6.75 2.66 (.32)
Cumulative effect of accounting change (.19) -- --
------------ ------------ ------------
Net Income (Loss) - Diluted 6.56 2.66 (.32)
============ ============ ============
Average Common shares outstanding - basic 45,031,665 44,970,457 44,955,679
Average Common shares outstanding - diluted 45,239,706 45,030,225 44,955,679
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Years Ended December 31 (Thousands of dollars) 2000 1999 1998
---- ---- ----
Net income (loss) $ 296,828 119,707 (14,394)
Other comprehensive income (loss) - net gain (loss) from
foreign currency translation (33,282) 18,536 (24,411)
------------ ------------ ------------
Comprehensive Income (Loss) $ 263,546 138,243 (38,805)
============ ============ ============
*Reclassified to conform to 2000 presentation.
See notes to consolidated financial statements, page F-6.
F-2
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31 (Thousands of dollars) 2000 1999
---- ----
Assets
Current assets
Cash and cash equivalents $ 132,701 34,132
Accounts receivable, less allowance for doubtful accounts
of $10,208 in 2000 and $8,298 in 1999 469,616 357,472
Inventories, at lower of cost or market
Crude oil and blend stocks 47,875 61,853
Finished products 68,464 50,572
Materials and supplies 48,416 39,218
Prepaid expenses 23,949 28,145
Deferred income taxes 25,916 21,720
----------- -----------
Total current assets 816,937 593,112
Property, plant and equipment, at cost less accumulated depreciation,
depletion and amortization of $3,144,369 in 2000 and $3,007,578 in 1999 2,184,719 1,782,741
Goodwill, net 48,396 --
Deferred charges and other assets 84,301 69,655
----------- -----------
Total assets $ 3,134,353 2,445,508
=========== ===========
Liabilities and Stockholders' Equity
Current liabilities
Current maturities of long-term debt $ 37,242 71
Accounts payable 528,416 334,420
Withholdings and collections due governmental agencies 65,262 65,706
Other accrued liabilities 45,964 49,143
Income taxes 68,343 38,295
----------- -----------
Total current liabilities 745,227 487,635
Notes payable 398,375 248,569
Nonrecourse debt of a subsidiary 126,384 144,595
Deferred income taxes 229,968 154,109
Reserve for dismantlement costs 160,049 158,377
Reserve for major repairs 34,302 22,099
Deferred credits and other liabilities 180,488 172,952
Stockholders' equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued -- --
Common Stock, par $1.00, authorized 80,000,000 shares, issued 48,775,314 shares 48,775 48,775
Capital in excess of par value 514,474 512,488
Retained earnings 833,490 601,956
Accumulated other comprehensive loss - foreign currency translation (38,266) (4,984)
Unamortized restricted stock awards (1,410) (2,328)
Treasury stock (97,503) (98,735)
----------- -----------
Total stockholders' equity 1,259,560 1,057,172
----------- -----------
Total liabilities and stockholders' equity $ 3,134,353 2,445,508
=========== ===========
See notes to consolidated financial statements, page F-6.
F-3
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31 (Thousands of dollars) 2000 1999* 1998*
---- ---- ----
Operating Activities
Income (loss) before cumulative effect of accounting change $ 305,561 119,707 (14,394)
Adjustments to reconcile above income (loss) to net cash provided
by operating activities
Depreciation, depletion and amortization 213,539 205,077 203,163
Impairment of properties 27,916 -- 80,127
Provisions for major repairs 22,761 18,721 20,420
Expenditures for major repairs and dismantlement costs (16,603) (44,096) (24,582)
Dry hole costs 65,987 32,422 31,504
Amortization of undeveloped leases 14,076 10,968 10,454
Deferred and noncurrent income tax charges (credits) 63,431 38,027 (937)
Pretax gains from disposition of assets (4,010) (11,940) (3,857)
Net (increase) decrease in noncash operating working capital
excluding acquisition of Beau Canada Exploration Ltd. 66,002 (35,159) (3,810)
Cumulative effect of accounting change on working capital (11,170) -- --
Other operating activities - net 261 7,984 (621)
--------- --------- ---------
Net cash provided by operating activities 747,751 341,711 297,467
--------- --------- ---------
Investing Activities
Property additions and dry hole costs (512,331) (359,438) (365,175)
Acquisition of Beau Canada Exploration Ltd., net of cash acquired (127,476) -- --
Proceeds from sale of property, plant and equipment 20,705 40,871 9,463
Other investing activities - net 391 (3,532) (1,767)
--------- --------- ---------
Net cash required by investing activities (618,711) (322,099) (357,479)
--------- --------- ---------
Financing Activities
Additions to notes payable 175,000 247,776 161,342
Reductions of notes payable (124,254) (190,806) (218)
Additions to nonrecourse debt of a subsidiary -- -- 240
Reductions of nonrecourse debt of a subsidiary (6,207) (5,120) (34,234)
Cash dividends paid (65,294) (62,950) (62,939)
Other financing activities - net (4,125) (1,742) 552
--------- --------- ---------
Net cash provided (required) by financing activities (24,880) (12,842) 64,743
--------- --------- ---------
Effect of exchange rate changes on cash and cash equivalents (5,591) (909) (748)
--------- --------- ---------
Net increase in cash and cash equivalents 98,569 5,861 3,983
Cash and cash equivalents at January 1 34,132 28,271 24,288
--------- --------- ---------
Cash and cash equivalents at December 31 $ 132,701 34,132 28,271
========= ========= =========
*Reclassified to conform to 2000 presentation.
See notes to consolidated financial statements, page F-6.
F-4
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years Ended December 31 (Thousands of dollars) 2000 1999 1998
---- ---- ----
Cumulative Preferred Stock - par $100, authorized
400,000 shares, none issued $ -- -- --
----------- ----------- -----------
Common Stock - par $1.00, authorized 80,000,000 shares,
issued 48,775,314 shares at beginning and end of each year 48,775 48,775 48,775
----------- ----------- -----------
Capital in Excess of Par Value
Balance at beginning of year 512,488 510,116 509,615
Exercise of stock options 1,749 797 103
Restricted stock transactions (202) 1,344 142
Sale of stock under employee stock purchase plans 439 231 256
----------- ----------- -----------
Balance at end of year 514,474 512,488 510,116
----------- ----------- -----------
Retained Earnings
Balance at beginning of year 601,956 545,199 622,532
Net income (loss) for the year 296,828 119,707 (14,394)
Cash dividends - $1.45 a share in 2000, $1.40 a share in 1999
and 1998 (65,294) (62,950) (62,939)
----------- ----------- -----------
Balance at end of year 833,490 601,956 545,199
----------- ----------- -----------
Accumulated Other Comprehensive Income (Loss) -
Foreign Currency Translation
Balance at beginning of year (4,984) (23,520) 891
Translation gains (losses) during the year (33,282) 18,536 (24,411)
----------- ----------- -----------
Balance at end of year (38,266) (4,984) (23,520)
----------- ----------- -----------
Unamortized Restricted Stock Awards
Balance at beginning of year (2,328) (2,361) (944)
Stock awards -- -- (3,238)
Amortization, forfeitures and changes in price of Common Stock 918 33 1,821
----------- ----------- -----------
Balance at end of year (1,410) (2,328) (2,361)
----------- ----------- -----------
Treasury Stock
Balance at beginning of year (98,735) (99,976) (101,518)
Exercise of stock options 1,140 704 110
Awarded restricted stock, net of forfeitures (349) -- 1,136
Sale of stock under employee stock purchase plan 441 537 296
----------- ----------- -----------
Balance at end of year - 3,729,769 shares of Common
Stock in 2000, 3,777,319 shares in 1999 and
3,824,838 shares in 1998 (97,503) (98,735) (99,976)
----------- ----------- -----------
Total Stockholders' Equity $ 1,259,560 1,057,172 978,233
=========== =========== ===========
See notes to consolidated financial statements, page F-6.
F-5
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, operates two
petroleum refineries in the United States and has an interest in a U.K.
refinery. 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
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, 2000 and 1999, 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. Significant undeveloped
leases are reviewed periodically and a valuation allowance is provided for any
estimated decline in value. Cost of other undeveloped leases is expensed over
the estimated average 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
development costs using proved developed reserves and for unamortized leasehold
costs using all proved reserves. Estimated dismantlement, abandonment and site
restoration costs, net of salvage value, are considered in determining
depreciation and depletion. Refineries and certain marketing facilities are
depreciated primarily using the composite straight-line method. Gasoline
stations and other properties are depreciated 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. Costs of
dismantling oil and gas production facilities and site restoration are charged
against the related reserve. All other dispositions, retirements or abandonments
are reflected in accumulated depreciation, depletion and amortization.
Provisions for turnarounds of refineries and a synthetic oil upgrading facility
are charged to expense monthly. Costs incurred are charged against the reserve.
All other maintenance and repairs are expensed. Renewals and betterments are
capitalized.
F-6
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. Inventories of refinery feedstocks and finished products 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 and is being amortized on a straight-line basis
over 15 years. The Company assesses the recoverability of goodwill by comparing
undiscounted future net cash flows for western Canadian oil and gas properties
with the unamortized goodwill balance.
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 reserve. 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 - The Company uses 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 either with creditworthy major
financial institutions or over national exchanges. Effective January 1, 2001,
the Company will adopt SFAS No. 133, which requires recognition of the fair
value of all derivative instruments as assets or liabilities in its Consolidated
Balance Sheet. The adoption of this standard will not have a significant effect
on net income.
Designated instruments that are highly effective at reducing the exposure of
assets, liabilities or anticipated transactions to interest rate, commodity
price or currency risks are accounted for as hedges. Gains and losses on an
instrument accounted for as a hedge of anticipated transactions are generally
deferred and recognized during the same period for which the underlying hedged
exposures are recognized. Certain commodity instruments acquired through an
acquisition have been recorded as a liability based on their fair value at date
of acquisition; gains and losses on these instruments partially offset changes
to the recorded liability. Gains or losses on derivatives that cease to qualify
as hedges are recognized in income or expense. When derivative instruments
accounted for as hedges are terminated prior to maturity, the resulting gain or
loss is generally deferred and recognized at the time that the underlying hedged
exposure is recognized.
Gains and losses on interest rate swaps are recorded as an adjustment to
Interest Expense in the Company's Consolidated Statements of Income. Gains and
losses on crude oil and natural gas swaps that hedge the purchase prices of
these commodities by the Company's refineries are recorded as a component of
Crude Oil, Products and Related Operating Expenses in the Consolidated
Statements of Income. Gains and losses on natural gas swaps that hedge the
F-7
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
sales prices for certain natural gas produced and sold by the Company in Canada
are recorded as an adjustment to the recorded liability in the Consolidated
Balance Sheets or as an adjustment to Crude Oil and Natural Gas Sales in the
Consolidated Statements of Income.
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 generally accepted U.S. accounting principles, 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
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 restated its operating results for the first three quarters
of 2000 and 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 three years ended December 31, 2000, 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 1998
---- ---- ----
Net income (loss) - As reported $ 296,828 119,707 (14,394)
Pro forma 305,561 111,336 (13,884)
Net income (loss) per share - As reported, basic $ 6.59 2.66 (.32)
Pro forma, basic 6.78 2.48 (.31)
As reported, diluted 6.56 2.66 (.32)
Pro forma, diluted 6.75 2.47 (.31)
In 2000, the Company also applied the provisions of Emerging Issue Task Force
(EITF) Issues 99-19, "Reporting Revenue Gross as a Principal Versus Net as an
Agent," and 00-10, "Accounting for Shipping and Handling Fees." Prior to
applying EITF 99-19, the Company reported the results of crude oil trading and
certain other downstream activities on a net margin basis in either Other
Operating Revenues or Crude Oil, Products and Related Operating Expenses in its
Statements of Income and in its refining, marketing and transportation segment
disclosures. Under EITF 99-19, the Company began reporting these activities as
gross revenues and cost of sales. Before applying EITF 00-10, the Company
reduced Crude Oil and Natural Gas Sales for certain gathering and pipeline
charges incurred prior to the point of sale. Such costs have now been recorded
as cost of sales rather than as a reduction of revenues. Due to applying these
two accounting principles, the Company's previously reported revenues and cost
of sales for the first nine months of 2000 and all preceding years presented
have been reclassified to reflect the new presentation.
Note C - Acquisition of Beau Canada Exploration Ltd.
In early 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; consequently, Beau Canada's operations subsequent
to the acquisition date have been included in the Company's consolidated
financial statements for the year ended December 31, 2000. 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.
F-8
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company also assumed debt in the acquisition of $124,227,000 that was repaid
before the end of the year through issuance of a structural loan (see Note F).
Murphy recorded goodwill of $48,396,000 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.
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 income from continuing operations 303,479 121,011
Pro forma income from continuing operations per Common share - diluted 6.71 2.69
Note D - Property, Plant and Equipment
December 31, 2000 December 31, 1999
----------------------- ------------------------
(Thousands of dollars) Cost Net Cost Net
---------- ---------- ----------- ----------
Exploration and production $4,156,422 1,616,424* 3,750,077 1,324,685*
Refining 710,623 256,469 698,100 259,883
Marketing 307,429 224,677 219,124 140,786
Transportation 111,409 62,210 84,391 38,762
Corporate and other 43,205 24,939 38,627 18,625
---------- ---------- ---------- ----------
$5,329,088 2,184,719 4,790,319 1,782,741
========== ========== ========== ==========
*Includes $17,370 in 2000 and $16,270 in 1999 related to administrative assets
and support equipment.
In the 2000 and 1998 Consolidated Statements of Income, the Company recorded
noncash charges of $27,916,000 and $80,127,000, respectively, for impairment of
certain properties. After related income tax benefits, these write-downs reduced
net income by $17,817,000 in 2000 and $57,573,000 in 1998. The 2000 charges
related to two natural gas fields in the Gulf of Mexico and two Canadian heavy
oil properties that depleted earlier than anticipated. The 1998 charges resulted
from management's expectation of a continuation of the low-price environment for
sales of crude oil and natural gas that existed at the end of 1998; the
write-down included certain oil and gas assets in the U.S. Gulf of Mexico, the
U.K. North Sea, China, and Canada and certain marketing assets in Canada. The
carrying values for properties determined to be impaired were reduced to the
assets' fair values based on projected future discounted net cash flows, using
the Company's estimates of future commodity prices.
Note E - Financing Arrangements
At December 31, 2000, the Company had an unused committed credit facility with a
major banking consortium of an equivalent US $300,000,000 for a combination of
U.S. dollar and Canadian dollar borrowings. U.S. dollar and Canadian dollar
commercial paper totaling an equivalent US $110,633,000 at December 31, 2000 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 certain of the commitments. The facilities expire
during 2002. In addition, the Company had unused uncommitted lines of credit
with banks at December 31, 2000 totaling an equivalent US $155,548,000 for a
combination of U.S. dollar and Canadian dollar borrowings.
F-9
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2000.
Note F - Long-term Debt
December 31 (Thousands of dollars) 2000 1999
--------- ---------
Notes payable
7.05% notes, due 2029 $ 247,369 247,277
6.23% structured loan, due 2001-2005 175,000 --
Other, 6% to 8%, due 2001-2021 1,244 1,363
--------- ---------
Total notes payable 423,613 248,640
--------- ---------
Nonrecourse debt of a subsidiary
Guaranteed credit facilities with banks
Commercial paper, 5.73% to 6.60%, $41,233 payable in
Canadian dollars, supported by credit facility, due 2001-2008 110,633 112,191
Loan payable to Canadian government, interest free, payable in
Canadian dollars, due 2001-2008 27,755 32,404
--------- ---------
Total nonrecourse debt of a subsidiary 138,388 144,595
--------- ---------
Total debt including current maturities 562,001 393,235
Current maturities (37,242) (71)
--------- ---------
Total long-term debt $ 524,759 393,164
========= =========
Maturities for the four years after 2001 are: $45,412,000 in 2002, $48,805,000
in 2003, $51,985,000 in 2004 and $63,062,000 in 2005.
In 1999, $250,000,000 of 7.05% notes were issued in the public market. These
notes mature in May 2029 and are shown in the above table net of unamortized
discount.
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 reduces in quarterly
installments over a five-year period beginning in 2001. 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 at
December 31, 2000. Beginning in 2001, the amount guaranteed will reduce
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 loan from the Canadian government was 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 early 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
F-10
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
Note H - Income Taxes
The components of income (loss) before income taxes and cumulative effect of
accounting change for each of the three years ended December 31, 2000 and income
tax expense (benefit) attributable thereto were as follows.
(Thousands of dollars) 2000 1999 1998
--------- --------- ---------
Income (loss) before income taxes and cumulative
effect of accounting change
United States $ 102,519 15,074 44,600
Foreign 362,815 163,428 (52,877)
--------- --------- ---------
$ 465,334 178,502 (8,277)
========= ========= =========
Income tax expense (benefit) before cumulative
effect of accounting change
Federal - Current/1/ $ 19,215 (13,497) 6,431
Deferred 5,665 1,597 6,232
Noncurrent (2,261) 16,366 3,785
--------- --------- ---------
22,619 4,466 16,448
--------- --------- ---------
State - Current 3,129 1,342 2,021
--------- --------- ---------
Foreign - Current 76,184 40,726 (3,498)
Deferred/2/ 59,776 11,165 (10,201)
Noncurrent (1,935) 1,096 1,347
--------- --------- ---------
134,025 52,987 (12,352)
--------- --------- ---------
Total $ 159,773 58,795 6,117
========= ========= =========
/1/ Net of benefit of $3,150 in 2000 for alternative minimum tax credits.
/2/ Net of benefit of $609 in 1999 for a reduction in the U.K. tax rate.
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) 2000 1999 1998
--------- --------- ---------
Income tax expense (benefit) based on the
U.S. statutory tax rate $ 162,867 62,475 (2,897)
Foreign income subject to foreign taxes at a rate
different than the U.S. statutory rate 13,010 1,988 5,692
State income taxes 2,034 872 1,313
Settlement of U.S. taxes (17,016) (5,000) (704)
Settlement of foreign taxes -- -- (1,410)
Foreign asset impairment with no tax benefit -- -- 5,293
Other, net (1,122) (1,540) (1,170)
--------- --------- ---------
Total $ 159,773 58,795 6,117
========= ========= =========
F-11
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, 2000 and 1999 showing the tax effects of significant temporary
differences follows.
(Thousands of dollars) 2000 1999
---- ----
Deferred tax assets
Property and leasehold costs $ 70,570 64,469
Reserves for dismantlements and major repairs 63,754 53,470
Federal alternative minimum tax credit carryforward -- 3,177
Postretirement and other employee benefits 27,950 24,637
Foreign tax operating losses 27,888 23,135
Other deferred tax assets 26,681 29,379
--------- ---------
Total gross deferred tax assets 216,843 198,267
Less valuation allowance (60,958) (57,388)
--------- ---------
Net deferred tax assets 155,885 140,879
--------- ---------
Deferred tax liabilities
Property, plant and equipment (45,860) (32,985)
Accumulated depreciation, depletion and amortization (285,444) (213,674)
Other deferred tax liabilities (28,633) (27,364)
--------- ---------
Total gross deferred tax liabilities (359,937) (274,023)
--------- ---------
Net deferred tax liabilities $(204,052) (133,144)
========= =========
The Company has tax loss and other carryforwards of $111,551,000 associated with
its operations in Ecuador. The losses have a carryforward period of no more than
five years, with certain losses limited to 25% of each year's taxable income.
These losses begin to expire in 2002.
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 $3,570,000 in 2000, but
decreased $4,970,000 in 1999; 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 $27,625,000 related to
undistributed earnings of certain foreign subsidiaries at December 31, 2000
because the earnings are considered permanently invested.
Tax returns are subject to audit by various taxing authorities. In 2000, 1999
and 1998, the Company recorded benefits to income of $25,618,000, $5,000,000 and
$2,114,000, respectively, from settlements of U.S. and foreign tax issues
primarily related to prior years. The Company believes that adequate accruals
have been made for unsettled issues.
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 options and restricted
stock over the vesting/performance periods and adjusting costs for changes in
fair market value of Common Stock. Compensation cost charged against (credited
to) income for stock-based plans was $7,914,000 in 2000, $13,161,000 in 1999 and
$(4,646,000) in 1998; outstanding awards were not significantly modified in the
last three years.
F-12
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) 2000 1999 1998
---- ---- ----
Net income (loss) - As reported $ 296,828 119,707 (14,394)
Pro forma 299,031 124,543 (18,182)
Earnings per share - As reported, basic $ 6.59 2.66 (.32)
Pro forma, basic 6.64 2.77 (.40)
As reported, diluted 6.56 2.66 (.32)
Pro forma, diluted 6.61 2.76 (.40)
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 2000, 1999 and 1998; fair values of
options have been estimated by using the Black-Scholes pricing model and the
assumptions as shown.
2000 1999 1998
---- ---- ----
Fair value per share at grant date $ 15.00 $ 7.76 $ 9.01
Assumptions
Dividend yield 2.91% 2.87% 2.91%
Expected volatility 26.06% 24.21% 17.27%
Risk-free interest rate 6.76% 4.77% 5.46%
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, 1997 770,689 $ 48.04
Granted at FMV 312,000 49.75
Exercised (17,400) 36.04
Forfeited (12,040) 49.34
---------
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
=========
Exercisable at December 31, 1998 284,529 $ 39.53
Exercisable at December 31, 1999 441,119 45.36
Exercisable at December 31, 2000 590,820 51.80
F-13
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Additional information about stock options outstanding at December 31, 2000 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 $42.25 443,570 6.9 $ 36.88 123,070 $ 39.99
$49.75 to $50.38 396,250 6.8 49.94 251,000 50.06
$55.41 to $65.49 612,750 8.0 58.23 216,750 60.54
--------- -------
1,452,570 7.4 49.45 590,820 51.80
========= =======
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. For the pro forma net income calculation, the
fair value per share of restricted stock granted in 1998 was $49.50, the market
price of the stock at the date granted. 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. On December 31, 1998, all
shares granted in 1994 were forfeited because financial objectives were not
achieved. Changes in restricted stock outstanding were as follows.
(Number of shares) 2000 1999 1998
---- ---- ----
Balance at beginning of year 83,364 83,364 39,856
Granted -- -- 59,750
Awarded (12,077) -- --
Forfeited (12,954) -- (16,242)
------- ------- -------
Balance at end of year 58,333 83,364 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 $6,970,000, $5,301,000 and $518,000 was
recorded in 2000, 1999, and 1998, respectively, for these plans.
EMPLOYEE STOCK PURCHASE PLAN (ESPP) - The Company has an ESPP, under which, as
amended in 2000, 150,000 shares of the Company's Common Stock could be purchased
by employees. Each quarter, an eligible U.S. or Canadian 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 13,675 shares at an average price of $51.08 a
share in 2000, 20,487 shares at $37.56 in 1999 and 11,315 shares at $48.81 in
1998. At December 31, 2000, 100,197 shares remained available for sale under the
ESPP. Compensation costs related to the ESPP were immaterial.
F-14
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 noncontributory defined
benefit pension plans that cover substantially all full-time employees. During
2000, certain employees in Canada converted their defined benefit pension plan
coverage to a contributory defined contribution plan. Henceforth, new Canadian
employees may only participate in the defined contribution plan. The Company
recorded a settlement gain of $1,824,000 associated with these conversions in
2000. The Company also sponsors health care and life insurance benefit plans for
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,
2000 and 1999 and a statement of the funded status as of December 31, 2000 and
1999.
Pension Postretirement
Benefits Benefits
---------------------- --------------------
(Thousands of dollars) 2000 1999 2000 1999
---- ---- ---- ----
Change in benefit obligation
Obligation at January 1 $ 240,630 238,022 34,350 36,749
Service cost 5,460 5,791 753 712
Interest cost 17,010 15,516 2,699 2,366
Plan amendments 3,502 225 -- --
Participant contributions -- -- 566 531
Actuarial (gain) loss 1,203 (6,167) 3,219 (2,916)
Curtailment -- 226 -- --
Settlements (2,257) (82) -- --
Special early retirement benefits -- 1,079 -- --
Exchange rate changes (3,461) 18 -- --
Benefits paid (14,369) (13,998) (3,133) (3,092)
--------- --------- --------- ---------
Obligation at December 31 247,718 240,630 38,454 34,350
--------- --------- --------- ---------
Change in plan assets
Fair value of plan assets at January 1 304,474 286,846 -- --
Actual return on plan assets 15,393 30,613 -- --
Employer contributions 687 842 2,567 2,561
Participant contributions -- -- 566 531
Settlements (2,271) (82) -- --
Exchange rate changes (3,711) 253 -- --
Benefits paid (14,369) (13,998) (3,133) (3,092)
--------- --------- --------- ---------
Fair value of plan assets at December 31 300,203 304,474 -- --
--------- --------- --------- ---------
Reconciliation of funded status
Funded status at December 31 52,485 63,844 (38,454) (34,350)
Unrecognized actuarial (gain) loss (22,440) (43,292) 6,594 3,610
Unrecognized transition asset (13,047) (8,729) -- --
Unrecognized prior service cost 7,806 6,391 -- --
--------- --------- --------- ---------
Net plan asset (liability) recognized $ 24,804 18,214 (31,860) (30,740)
========= ========= ========= =========
Amounts recognized in the Consolidated
Balance Sheets at December 31
Prepaid benefit asset $ 40,152 34,200 -- --
Accrued benefit liability (17,051) (16,300) (31,860) (30,740)
Intangible asset 1,703 314 -- --
--------- --------- --------- ---------
Net plan asset (liability) recognized $ 24,804 18,214 (31,860) (30,740)
========= ========= ========= =========
F-15
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company's U.S. and Canadian nonqualified retirement plans and U.S.
directors' retirement plan were the only pension plans with accumulated benefit
obligations in excess of plan assets at December 31, 2000 and 1999. The
accumulated benefit obligations of these plans at December 31, 2000 and 1999
were $10,060,000 and $7,784,000, respectively; there were no assets in these
plans. The Company's postretirement benefit plan had no plan assets; the benefit
obligations for this plan at December 31, 2000 and 1999 were $38,454,000 and
$34,350,000, respectively.
The table that follows provides the components of net periodic benefit expense
(credit) for each of the three years ended December 31, 2000.
Pension Benefits Postretirement Benefits
-------------------------------- ------------------------------
(Thousands of dollars) 2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ----
Service cost $ 5,461 5,791 5,242 753 712 601
Interest cost 17,010 15,516 15,309 2,699 2,366 2,474
Expected return on plan assets (24,412) (23,105) (22,180) -- -- --
Amortization of prior service cost 791 622 626 -- -- --
Amortization of transitional asset (2,585) (2,204) (2,211) -- -- --
Recognized actuarial (gain) loss (395) (766) (758) 234 203 194
-------- -------- -------- -------- -------- --------
(4,130) (4,146) (3,972) 3,686 3,281 3,269
Settlement gain (1,824) -- -- -- -- --
Special early retirement benefits -- 1,041 -- -- -- --
-------- -------- -------- -------- -------- --------
Net periodic benefit
expense (credit) $ (5,954) (3,105) (3,972) 3,686 3,281 3,269
======== ======== ======== ======== ======== ========
The preceding tables include the following amounts related to foreign benefit
plans.
Pension Postretirement
Benefits Benefits
------------------- -------------------
(Thousands of dollars) 2000 1999 2000 1999
---- ---- ---- ----
Benefit obligation at December 31 $ 49,608 53,675 - -
Fair value of plan assets at December 31 55,473 61,462 - -
Net plan liability recognized (876) (3,178) - -
Net periodic benefit expense (credit) (1,960) 364 - -
The following table provides the weighted-average assumptions used in the
measurement of the Company's benefit obligations at December 31, 2000 and 1999.
Pension Postretirement
Benefits Benefits
------------------- -------------------
2000 1999 2000 1999
---- ---- ---- ----
Discount rate 7.25% 7.26% 7.50% 7.50%
Expected return on plan assets 8.33% 8.34% - -
Rate of compensation increase 4.63% 4.66% - -
For purposes of measuring postretirement benefit obligations at December 31,
2000, the future annual rates of increase in the cost of health care were
assumed to be 5.5% for 2001 and 4.5% for 2002 and beyond.
F-16
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2000 $ 236 (224)
Effect on the health care component of the accumulated
postretirement benefit obligation at December 31, 2000 2,191 (2,123)
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. Amounts charged to
expense for these plans were $3,699,000 in 2000, $2,523,000 in 1999 and
$3,333,000 in 1998.
Note K - Financial Instruments
DERIVATIVE INSTRUMENTS - As discussed in Note A, Murphy utilizes derivative
instruments on a limited basis to manage risks related to interest rates,
foreign currency exchange rates and commodity prices. At December 31, 2000 and
1999, the Company had interest rate swap agreements with notional amounts
totaling $100,000,000 that serve to convert an equal amount of variable rate
long-term debt to fixed rates. The swaps mature in 2002 and 2004. The swaps
require Murphy to pay an average interest rate of 6.46% over their composite
lives and to receive a variable rate, which averaged 6.72% at December 31, 2000.
The variable rate received by the Company under each contact is repriced
quarterly.
Prior to April 2000, the Company was a party to crude oil swap agreements for a
total notional volume of 2.3 million barrels that reduced a portion of the
financial exposure of Murphy's U.S. refineries to crude oil price movements in
2001 and 2002. Under each swap agreement, Murphy would have paid a fixed crude
oil price and would have received the average near-month NYMEX West Texas
Intermediate crude oil price during the agreement's contractual maturity period.
In April 2000, Murphy settled contracts for 1.7 million barrels, receiving cash
of $5,806,000 from the counterparties, and entered into offsetting contracts for
the remaining swap agreements, locking in a future cash settlement of
$1,929,000. These settlement gains have been deferred and will be recognized as
a reduction of costs of crude oil purchases in 2001 and 2002.
The Company periodically uses natural gas swap agreements to reduce a portion of
the financial exposure of its Meraux, Louisiana refinery to fluctuations in the
price of natural gas purchased for fuel. At December 31, 2000, Murphy was a
party to natural gas swap agreements for a total notional volume of 7 million
MMBTU that hedge natural gas purchases in 2002 through 2004. The swaps require
Murphy to pay an average natural gas price of $2.61 an MMBTU and to receive the
average NYMEX Henry Hub price for the final three trading days of each
respective month. Unrealized gains or losses on such swap contracts are deferred
and recognized in connection with the associated fuel purchases.
The Company has natural gas swaps obtained through the acquisition of Beau
Canada that reduce a portion of the financial exposure of certain Canadian
natural gas production to fluctuations in sales prices. At December 31, 2000,
Murphy was a party to natural gas swap agreements for the sale of a notional
amount of 20,000 gigajoules (GJ) per day through October 2001. The swaps require
Murphy to pay based on the AECO "C" index and to receive an average of C$2.47
per GJ. In addition, the Company was a party to a natural gas swap agreement for
the purchase of 10,000 GJ per day through October 2001. The swap requires Murphy
to pay C$5.64 per GJ and to receive based on the AECO "C" index. The fair value
of these swaps was recorded as a net liability upon the acquisition of Beau
Canada. The swaps are settled monthly and net payments by the Company are
recorded as a reduction of the associated liability, with any differences
recorded as an adjustment of natural gas sales revenue.
F-17
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
FAIR VALUE - The following table presents the carrying amounts and estimated
fair values of financial instruments held by the Company at December 31, 2000
and 1999. 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.
2000 1999
------------------------ ------------------------
Carrying Fair Carrying Fair
(Thousands of dollars) Amount Value Amount Value
------ ----- ------ -----
Financial liabilities and deferred credits
Current and long-term debt $ (562,001) (526,891) (393,235) (373,546)
Natural gas swaps (12,615) (17,905) - -
Off-balance-sheet exposures -
unrealized gain (loss)
Interest rate swaps - (1,956) - 266
Crude oil swaps - 1,793 - 2,668
Natural gas swaps - 6,196 - (83)
Financial guarantees and letters of credit - - - -
The carrying amounts of current and long-term debt in the preceding table are
included in the Consolidated Balance Sheets under Current Maturities of
Long-Term Debt, Notes Payable and Nonrecourse Debt of a Subsidiary. The recorded
natural gas swaps are included in Other Accrued Liabilities. The following
methods and assumptions were used to estimate the fair value of each class of
financial instruments shown in the table.
. Current and long-term debt - The fair value is estimated based on current
rates offered the Company for debt of the same maturities.
. Interest rate swaps, crude oil swaps and natural gas swaps - The fair values
are based on published index prices or quotes from counterparties.
. Financial guarantees and letters of credit - The fair value, which represents
fees associated with obtaining the instruments, was nominal.
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 transactions are major financial institutions.
F-18
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 (loss) per Common share for each of the
three years ended December 31, 2000. No difference existed between net income
(loss) used in computing basic and diluted income (loss) per Common share for
these years.
(Weighted-average shares outstanding) 2000 1999 1998
---------- ---------- ----------
Basic method 45,031,665 44,970,457 44,955,679
Dilutive stock options 208,041 59,768 --
---------- ---------- ----------
Diluted method 45,239,706 45,030,225 44,955,679
========== ========== ==========
The computations of diluted earnings per share in the Consolidated Statements of
Income did not consider outstanding options at year end of 147,000 shares in
2000, 684,750 shares in 1999 and 1,053,249 shares in 1998 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, $53.34 and
$48.73, respectively.
Note N - Other Financial Information
INVENTORIES - Inventories accounted for under the LIFO method totaled
$85,968,000 and $72,452,000 at December 31, 2000 and 1999, respectively, and
were $123,963,000 and $115,236,000 less than such inventories would have been
valued using the first-in first-out method.
FOREIGN CURRENCY - Cumulative translation gains and losses, net of insignificant
related income tax effects, are included in Accumulated Other Comprehensive Loss
in the Consolidated Balance Sheets. At December 31, 2000, components of the net
cumulative loss of $38,266,000 were gains (losses) of $12,715,000 for pounds
sterling, $(51,248,000) for Canadian dollars and $267,000 for other currencies.
Comparability of net income was not significantly affected by exchange rate
fluctuations in 2000, 1999 or 1998. Net gains (losses) from foreign currency
transactions included in the Consolidated Statements of Income were $252,000 in
2000, $(847,000) in 1999 and $282,000 in 1998.
F-19
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 $53,583,000, $(5,343,000) and $26,227,000 in 2000, 1999 and 1998,
respectively. Interest paid, net of amounts capitalized, was $15,185,000,
$17,140,000 and $9,551,000 in 2000, 1999 and 1998, respectively.
Noncash operating working capital (increased) decreased for each of the three
years ended December 31, 2000 as follows.
(Thousands of dollars) 2000 1999 1998
---- ---- ----
Accounts receivable $ (95,675) (123,566) 38,541
Inventories (12,197) (21,866) 28,639
Prepaid expenses 5,794 4,147 15,031
Deferred income tax assets (4,196) (8,600) 2,158
Accounts payable and accrued liabilities 142,228 99,382 (85,503)
Current income tax liabilities 30,048 15,344 (2,676)
--------- --------- ---------
Net (increase) decrease in noncash operating working capital
excluding acquisition of Beau Canada $ 66,002 (35,159) (3,810)
========= ========= =========
Note O - Commitments
The Company leases land, gasoline stations and other facilities under operating
leases. Future minimum rental commitments under noncancellable operating leases
are not material. Commitments for capital expenditures were approximately
$353,000,000 at December 31, 2000, including $176,000,000 related to a clean
fuels expansion project at the Meraux refinery and $67,000,000 related to the
Company's multiyear contract for a semisubmersible deepwater drilling rig.
Certain costs committed under the rig contract will be charged to the Company's
partners when future deepwater wells are drilled.
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.
ENVIRONMENTAL MATTERS - On June 29, 2000, the U.S. Government and the State of
Wisconsin each filed a lawsuit against Murphy in the U.S. District Court for the
Western District of Wisconsin. The State action was subsequently dismissed by
the federal court and refiled in state court in Douglas County, Wisconsin. The
suits, arising out of a 1998 compliance inspection, include claims for alleged
violations of federal and state environmental laws at Murphy's Superior,
Wisconsin refinery. The suits seek compliance as well as substantial monetary
penalties. The Company believes it has valid defenses to these allegations and
plans a vigorous defense. The Company does not have an estimate or a range of
potential liability at this time and can give no assurance about the outcome.
The Company does not believe that the resolution of these suits or other known
environmental matters will have a material adverse effect on its financial
condition. There is the possibility that expenditures could be required at
currently unidentified sites, and new or revised regulations could require
additional expenditures at known sites. Such expenditures could materially
affect the results of operations in a future period.
F-20
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Other matters related to the Company's environmental contingencies are reviewed
in Management's Discussion and Analysis of Financial Condition and Results of
Operations under the section entitled "Environmental" beginning on page 15 of
this Form 10-K report.
OTHER MATTERS - The Company and its subsidiaries are engaged in a number of
other legal proceedings, all of which the Company considers routine and
incidental to its business and none of which is considered material. 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, 2000, the Company had contingent
liabilities of $128,500,000 under certain financial guarantees and $58,200,000
on outstanding letters of credit.
Note Q - Subsequent Event (unaudited)
On March 1, 2001, the Company announced it had entered into an agreement,
subject to conditions, to sell its Canadian pipeline and trucking operation for
total proceeds of approximately $163,000,000, including inventory. The
transaction should close in the second quarter and would result in an after-tax
gain of approximately $69,000,000.
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, and all other countries; each of
these segments derives revenues primarily from the sale of crude oil and natural
gas. The refining, marketing and transportation segments in the United States
and the United Kingdom derive revenues mainly from the sale of petroleum
products; the Canadian segment derives revenues primarily from the
transportation and trading of crude oil. 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 $1,052,760,000,
$898,917,000 and $831,385,000 for the years 2000, 1999 and 1998, 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-22, Certain Long-Lived Assets at December 31
exclude investments, noncurrent receivables, deferred tax assets and intangible
assets. In the tables on pages F-22 and F-23, certain amounts for 1999 and 1998
have been reclassified to conform to 2000 presentation.
F-21
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Exploration and Production
Segment Information -------------------------------------------------------------------
(Millions of dollars) U.S. Canada U.K. Ecuador Other Total
--- ------ --- ------- ----- -----
Year ended December 31, 2000
Segment income (loss) before cumulative
effect of accounting change $ 50.3 108.1 90.2 21.1 (17.0) 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 .5 169.2
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 8.9 541.2
Total assets at year-end 413.6 1,131.1 261.7 79.8 16.4 1,902.6
- ------------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1999
Segment income (loss) $ 35.3 47.0 37.2 22.6 (7.7) 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) 236.3
Total assets at year-end 391.0 737.9 299.4 60.0 9.5 1,497.8
- ------------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1998
Segment income (loss) $ .7 (7.5) (13.3) 4.8 (35.1) (50.4)
Revenues from external customers 151.2 95.6 82.8 26.4 2.7 358.7
Intersegment revenues 32.4 42.5 12.3 - - 87.2
Interest income - - - - - -
Interest expense, net of capitalization - - - - - -
Income of equity companies - - - - - -
Income tax expense (benefit) (.1) (11.3) (1.6) (.8) .1 (13.7)
Significant noncash charges (credits)
Depreciation, depletion, amortization 66.0 44.5 42.9 10.2 - 163.6
Impairment of properties 29.9 10.1 24.3 - 15.1 79.4
Provisions for major repairs - 3.1 - - - 3.1
Amortization of undeveloped leases 6.7 3.8 - - - 10.5
Deferred and noncurrent income taxes (3.3) (6.3) (4.3) - .7 (13.2)
Additions to property, plant, equipment 104.0 94.1 67.5 10.2 .7 276.5
Total assets at year-end 399.1 595.6 317.6 60.3 13.3 1,385.9
- ------------------------------------------------------------------------------------------------------------------------------------
Geographic Information Certain Long-Lived Assets at December 31
------------------------------------------------------------------
(Millions of dollars) U.S. Canada U.K. Ecuador Other Total
---- ------ ---- ------- ----- -----
2000 $ 764.8 1,063.2 297.1 59.0 14.6 2,198.7
1999 687.0 724.4 331.6 53.5 7.7 1,804.2
1998 675.5 600.4 352.0 54.3 8.4 1,690.6
F-22
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Segment Information (Continued) Refining, Marketing & Transportation
------------------------------------ Corp. & Consoli-
(Millions of dollars) U.S. U.K. Canada Total Other dated
---- ---- ------ ----- ----- -----
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
- ---------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1998
Segment income (loss) $ 27.7 17.3 2.5 47.5 (11.5) (14.4)
Revenues from external customers 1,413.9 287.9 282.1 1,983.9 4.4 2,347.0
Intersegment revenues 3.1 - .3 3.4 - 90.6
Interest income - - - - 4.0 4.0
Interest expense, net of capitalization - - - - 10.5 10.5
Income of equity companies .8 - - .8 - .8
Income tax expense (benefit) 15.7 7.9 3.1 26.7 (6.9) 6.1
Significant noncash charges (credits)
Depreciation, depletion, amortization 29.3 5.2 1.9 36.4 3.2 203.2
Impairment of properties - - .7 .7 - 80.1
Provisions for major repairs 15.2 2.0 - 17.2 .1 20.4
Amortization of undeveloped leases - - - - - 10.5
Deferred and noncurrent income taxes 2.9 .6 (.3) 3.2 9.1 (.9)
Additions to property, plant, equipment 45.6 6.8 2.6 55.0 2.2 333.7
Total assets at year-end 465.5 160.8 50.2 676.5 102.0 2,164.4
- ---------------------------------------------------------------------------------------------------------------------------
Geographic Information Revenues from External Customers for the Year
---------------------------------------------------------------------
(Millions of dollars) U.S. U.K. Canada Ecuador Other Total
---- ---- ------ ------- ----- -----
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
1998 1,565.4 374.2 378.3 26.4 2.7 2,347.0
F-23
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.
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 2000 crude oil prices used for this calculation were
$23.24 a barrel for the United States, $24.73 for Canadian light, $7.74 for
Canadian heavy, $22.97 for Canadian offshore, $22.33 for the United Kingdom and
$17.75 for Ecuador. Average year-end 2000 natural gas prices used were $6.58 an
MCF for the United States, $5.68 for Canada and $2.76 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, 2000.
F-24
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 Total Canada Total
------ ------ ------- ------- ----- ------ -----
Proved
December 31, 1997 19.1 49.1 57.3 31.1 156.6 103.5 260.1
Revisions of previous estimates (1.0) 6.7 5.0 2.6 13.3 15.9 29.2
Purchases - 1.3 - - 1.3 - 1.3
Extensions and discoveries 8.0 .3 - 1.3 9.6 - 9.6
Production (2.8) (6.5) (5.6) (2.8) (17.7) (3.8) (21.5)
Sales (.3) (.1) - - (.4) - (.4)
---- ---- ---- ---- ----- ---- -----
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
==== ==== ==== ==== ===== ==== =====
Proved Developed
December 31, 1997 15.3 22.5 18.3 20.6 76.7 70.4 147.1
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
Schedule 2 - Estimated Net Proved Natural Gas Reserves
United United
(Billions of cubic feet) States Canada Kingdom Total
------ ------ ------- -----
Proved
December 31, 1997 435.4 140.4 36.4 612.2
Revisions of previous estimates (14.3) (.2) 7.2 (7.3)
Purchases - 6.3 - 6.3
Extensions and discoveries 80.9 2.6 - 83.5
Production (61.9) (17.9) (4.5) (84.3)
Sales - (1.1) - (1.1)
------ ------ ----- -----
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
====== ====== ===== =====
Proved Developed
December 31, 1997 304.2 135.2 24.0 463.4
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
F-25
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 Other Subtotal Canada Total
------ ------ ------- ------- ----- -------- ------ -----
Year Ended December 31, 2000
Property acquisition costs
Unproved $ 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 23.1 156.7 - 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 23.1 374.2 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 - 1.9 66.0 - 66.0
Geophysical and other costs 10.6 21.2 1.4 - 12.3 45.5 - 45.5
------- ----- ---- ---- ---- ----- ---- -----
Total charged to expense 67.3 26.9 3.1 - 14.2 111.5 - 111.5
------- ----- ---- ---- ---- ----- ---- -----
Expenditures capitalized $ 69.9 407.0 24.6 12.3 8.9 522.7 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 7.9 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 7.9 269.1 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 - 6.7 27.2 - 27.2
------- ----- ---- ---- ---- ----- ---- -----
Total charged to expense 34.9 12.8 3.9 - 8.0 59.6 - 59.6
------- ----- ---- ---- ---- ----- ---- -----
Expenditures capitalized $ 60.7 116.2 25.6 7.1 (.1) 209.5 26.8 236.3
======= ===== ==== ==== ==== ===== ==== =====
Year Ended December 31, 1998
Property acquisition costs
Unproved $ 14.1 2.7 .2 - - 17.0 - 17.0
Proved 3.8 1.1 - - - 4.9 - 4.9
------- ----- ---- ---- ---- ----- ---- -----
Total acquisition costs 17.9 3.8 .2 - - 21.9 - 21.9
Exploration costs 77.6 18.3 2.6 - 21.9 120.4 - 120.4
Development costs 25.1 69.4 68.2 10.2 - 172.9 16.4 189.3
------- ----- ---- ---- ---- ----- ---- -----
Total capital expenditures 120.6 91.5 71.0 10.2 21.9 315.2 16.4 331.6
------- ----- ---- ---- ---- ----- ---- -----
Charged to expense
Dry hole expense 10.8 8.9 (.4) - 12.2 31.5 - 31.5
Geophysical and other costs 5.8 4.9 3.9 - 9.0 23.6 - 23.6
------- ----- ---- ---- ---- ----- ---- -----
Total charged to expense 16.6 13.8 3.5 - 21.2 55.1 - 55.1
------- ----- ---- ---- ---- ----- ---- -----
Expenditures capitalized $ 104.0 77.7 67.5 10.2 .7 260.1 16.4 276.5
======= ===== ==== ==== ==== ===== ==== =====
F-26
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 Other Subtotal Canada Total
------ ------ ------- ------- ----- -------- ------ -----
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 - 14.2 111.5 - 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 .5 161.7 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 other
disputed contractual items - - - 7.8 - 7.8 - 7.8
------- ----- -------- ------- ------- ------- -------- ------
Total costs and expenses 201.6 162.5 76.7 30.4 19.2 490.4 48.0 538.4
------- ----- -------- ------- ------- ------- -------- ------
77.4 130.9 146.4 21.1 (17.0) 358.8 43.5 402.3
Income tax expense (benefit) 27.1 49.2 56.2 - - 132.5 17.1 149.6
------- ----- -------- ------- ------- ------- -------- ------
Results of operations/1/ $ 50.3 81.7 90.2 21.1 (17.0) 226.3 26.4 252.7
======= ===== ======== ======= ======= ======= ======== ======
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/2/ 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 - 8.0 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 9.2 374.6 43.6 418.2
------- ----- ------- ------- ------- ------- -------- ------
45.6 40.6 61.7 22.6 (7.2) 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/1/ $ 35.3 26.3 37.2 22.6 (7.7) 113.7 20.7 134.4
======= ===== ======= ======= ======= ======= ======== ======
/1/ Excludes corporate overhead and interest in 2000 and 1999 and cumulative
effect of accounting change in 2000.
/2/ Includes $3.3 from gain on disputed contractual item in Ecuador.
F-27
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 Other Subtotal Canada Total
------ ------ ------- ------- ----- -------- ------ -----
Year Ended December 31, 1998
Revenues
Crude oil and natural gas liquids
Transfers to consolidated operations $ 32.4 7.1 12.3 - - 51.8 35.4 87.2
Sales to unaffiliated enterprises 3.5 50.3 58.0 24.2 - 136.0 17.6 153.6
Natural gas
Sales to unaffiliated enterprises 136.3 25.1 10.0 - - 171.4 - 171.4
------- ----- ------- ------- ------- ------- -------- ------
Total oil and gas revenues 172.2 82.5 80.3 24.2 - 359.2 53.0 412.2
Other operating revenues/1/ 11.4 2.7 14.8 2.2 2.7 33.8 (.1) 33.7
------- ----- ------- ------- ------- ------- -------- ------
Total revenues 183.6 85.2 95.1 26.4 2.7 393.0 52.9 445.9
------- ----- ------- ------- ------- ------- -------- ------
Costs and expenses
Production expenses 48.1 36.9 35.7 12.1 - 132.8 34.5 167.3
Exploration costs charged to expense 16.6 13.8 3.5 - 21.2 55.1 - 55.1
Undeveloped lease amortization 6.7 3.8 - - - 10.5 - 10.5
Depreciation, depletion and amortization 66.0 38.3 42.9 10.2 - 157.4 6.2 163.6
Impairment of properties 29.9 10.1 24.3 - 15.1 79.4 - 79.4
Cancellation of a drilling rig contract - 7.2 - - - 7.2 - 7.2
Selling and general expenses 15.7 6.0 3.6 .1 1.4 26.8 .1 26.9
------- ----- ------- ------- ------- ------- -------- ------
Total costs and expenses 183.0 116.1 110.0 22.4 37.7 469.2 40.8 510.0
------- ----- ------- ------- ------- ------- -------- ------
.6 (30.9) (14.9) 4.0 (35.0) (76.2) 12.1 (64.1)
Income tax expense (benefit) (.1) (15.2) (1.6) (.8) .1 (17.6) 3.9 (13.7)
------- ----- ------- ------- ------- ------- -------- ------
Results of operations/2/ $ .7 (15.7) (13.3) 4.8 (35.1) (58.6) 8.2 (50.4)
======= ===== ======= ======= ======= ======= ======== ======
/1/ Includes pretax gains of $4 from settlement of a U.K. long-term sales
contract and $2.4 from disputed contractual items 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 Other Subtotal Canada Total
------ ------ ------- ------- ----- -------- ------ -----
December 31, 2000
Unproved oil and gas properties $ 109.9 76.2 .2 - 11.3 197.6 - 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 11.3 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
======= ======= ===== ===== ====== ======= ===== =======
December 31, 1999
Unproved oil and gas properties $ 91.5 37.7 .3 - 3.5 133.0 - 133.0
Proved oil and gas properties 1,453.7 902.6 841.5 206.6 - 3,404.4 176.7 3,581.1
------- ------- ----- ----- ------ ------- ----- -------
Gross capitalized costs 1,545.2 940.3 841.8 206.6 3.5 3,537.4 176.7 3,714.1
Accumulated depreciation,
depletion and amortization
Unproved oil and gas properties (34.4) (22.1) (.3) - (3.5) (60.3) - (60.3)
Proved oil and gas properties* (1,182.0) (370.0) (609.1) (153.1) - (2,314.2) (31.2) (2,345.4)
------- ------- ----- ----- ------ ------- ----- -------
Net capitalized costs $ 328.8 548.2 232.4 53.5 - 1,162.9 145.5 1,308.4
======= ======= ===== ===== ====== ======= ===== =======
*Does not include reserve for dismantlement costs of $160 in 2000 and $158.4 in
1999.
F-28
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 Total
------ ------ ------- ------- -----
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 $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) 2000 1999 1998
---- ---- ----
Net changes in prices, production costs and development costs $ 722.0 1,188.2 (894.8)
Sales and transfers of oil and gas produced, net of production costs (485.1) (317.9) (132.3)
Net change due to extensions and discoveries 544.4 250.0 125.4
Net change due to purchases and sales of proved reserves 519.2 (2.0) 4.5
Development costs incurred 156.6 163.4 165.4
Accretion of discount 229.3 71.9 129.0
Revisions of previous quantity estimates (73.7) 220.7 30.7
Net change in income taxes (659.9) (505.2) 191.0
-------- -------- --------
Net increase (decrease) 952.8 1,069.1 (381.1)
Standardized measure at January 1 1,651.0 581.9 963.0
-------- -------- ----------
Standardized measure at December 31 $ 2,603.8 1,651.0 581.9
======= ======= ==========
F-29
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, 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
Year Ended December 31, 1999/1/
Sales and other operating revenues $ 433.5 600.4 811.8 906.4 2,752.1
Income (loss) before income taxes (11.2) 28.2 80.5 81.0 178.5
Net income (loss) (6.7) 15.7 51.2 59.5 119.7
Net income (loss) per Common share - basic (.15) .35 1.14 1.32 2.66
Net income (loss) per Common share - diluted (.15) .35 1.14 1.32 2.66
Cash dividends per Common share .35 .35 .35 .35 1.40
Market Price of Common Stock/2/
High 42.6250 50.9375 54.6250 61.5625 61.5625
Low 32.8750 41.3750 47.6875 51.2500 32.8750
/1/ The effects 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
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
1999
----
Quarterly totals $ (1.0) - 6.3 14.4 19.7
Per Common share - basic (.02) - .14 .32 .44
Per Common share - diluted (.02) - .14 .32 .44
/2/ Prices are as quoted on the New York Stock Exchange.
F-30