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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, 1999
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ___________________________ to _________________
Commission file number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 71-0361522
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
200 PEACH STREET, P.O. BOX 7000, 71731-7000
EL DORADO, ARKANSAS (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (870) 862-6411
Securities registered pursuant to Section 12(b) of the Act:
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, 2000, as quoted by the New
York Stock Exchange, was approximately $1,927,840,000.
Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31,
2000 was 45,013,897.
Documents incorporated by reference:
Portions of the Registrant's definitive Proxy Statement relating to the Annual
Meeting of Stockholders on May 10, 2000 have been incorporated by reference in
Part III herein.
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MURPHY OIL CORPORATION
TABLE OF CONTENTS - 1999 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 18
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 and crude oil transportation and trading operations in Canada. 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. On
December 31, 1996, Murphy completed a spin-off to its stockholders of its wholly
owned farm, timber and real estate subsidiary, Deltic Farm & Timber Co., Inc.
(reincorporated as "Deltic Timber Corporation").
The information appearing in the 1999 Annual Report to Security Holders (1999
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 14, F-8, F-19 through F-21, and F-24 through F-26 of this
Form 10-K report and on pages 6 through 19 of the 1999 Annual Report.
EXPLORATION AND PRODUCTION
During 1999, 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 1999 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, Pakistan, Philippines, Spain and Ireland.
Murphy's estimated net quantities of proved oil and gas reserves and proved
developed oil and gas reserves at December 31, 1996, 1997, 1998 and 1999 by
geographic area are reported on page F-23 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 net natural gas sales
by geographic area with weighted average sales prices for each of the five years
ended December 31, 1999 are shown on page 21 of the 1999 Annual Report.
1
Production costs for the last three years in U.S. dollars per equivalent barrel
produced are discussed on page 11 of this Form 10-K report. For purposes of
these computations, natural gas 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-22 through F-27 of this Form 10-K report.
At December 31, 1999, 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 3 3 40 21 43 24
- Gulf of Mexico 805 454 313 115 1,118 569
- Frontier 119 44 -- -- 119 44
------ ------ ----- ---- ------ ------
Total United States 927 501 353 136 1,280 637
------ ------ ----- ---- ------ ------
Canada - Onshore 781 529 1,226 199 2,007 728
- Offshore 3,874 908 55 3 3,929 911
- Oil sands 222 63 10 2 232 65
------ ------ ----- ---- ------ ------
Total Canada 4,877 1,500 1,291 204 6,168 1,704
------ ------ ----- ---- ------ ------
United Kingdom 1,423 448 77 11 1,500 459
Ecuador -- -- 494 99 494 99
Ireland 896 224 -- -- 896 224
Malaysia 6,498 5,319 -- -- 6,498 5,319
Pakistan 3,795 3,795 -- -- 3,795 3,795
Philippines 3,695 2,956 -- -- 3,695 2,956
Spain 330 99 -- -- 330 99
Tunisia 109 36 -- -- 109 36
------ ------ ----- ---- ------ ------
Totals 22,550 14,878 2,215 450 24,765 15,328
====== ====== ===== ==== ====== ======
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, 1999.
Oil Wells Gas Wells
-------------- --------------
Country Gross Net Gross Net
- - - - - ------- ----- ----- ----- -----
United States 300 131.6 209 77.1
Canada 3,932 786.0 768 272.0
United Kingdom 149 18.0 21 1.6
Ecuador 59 11.8 -- --
----- ----- ----- -----
Totals 4,440 947.4 998 350.7
===== ===== ===== =====
Wells included above with multiple
completions and counted as one well each 82 37.9 80 59.8
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
------- --- ------- --- ------- --- ------- --- ------- --- ------- ---
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 -
1997
- - - - - ----
Exploratory 7.6 6.8 15.8 8.3 .5 .6 - - .4 1.0 24.3 16.7
Development 2.9 - 83.0 - .9 .3 1.6 - - - 88.4 .3
Murphy's drilling wells in progress at December 31, 1999 are shown below.
Exploratory Development Total
---------------- ------------- ---------------
Country Gross Net Gross Net Gross Net
- - - - - ------- ----- --- ----- --- ----- ---
United States 3 1.6 -- -- 3 1.6
Canada 2 .7 3 .7 5 1.4
United Kingdom -- -- 5 .5 5 .5
Ecuador -- -- 1 .2 1 .2
----- --- ----- --- ----- ---
Totals 5 2.3 9 1.4 14 3.7
===== === ===== === ===== ===
Additional information about current exploration and production activities is
reported on pages 1 through 15 of the 1999 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, 1999 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 branded and unbranded
wholesale customers and retail gasoline stations in the United States and
Canada. Branded wholesale customers use the brand name SPUR(R). Murphy's retail
stations are primarily located in the parking areas of Wal-Mart stores and use
the brand name Murphy USA(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, 1999, the Company marketed products through 145 Murphy
USA stations in a 13-state area of the southern United States, 480 SPUR stations
(25 of which are either owned or leased by the Company) in a 14-state area in
the southeastern and upper-midwestern United States, and eight SPUR stations in
the Thunder Bay area of Ontario, Canada. The Company plans to add up to 150 new
Murphy USA stations at Wal-Mart sites in the southern and midwestern United
States in 2000.
At the end of 1999, Murco distributed refined products in the United Kingdom
from the Milford Haven refinery, three wholly owned terminals supplied by rail,
seven terminals owned by others where products are received in exchange for
deliveries from the Company's terminals, and 384 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, 1999, 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.
Pipeline Description Percent Miles Bbls./Day Route
- - - - - -------- ----------- ------- ----- --------- -----
Manito Dual heavy oil 52.5 101 65,000 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 41.3 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, 1999 are reported on pages 1
through 3, 5, 16 through 19, and 22 of the 1999 Annual Report.
EMPLOYEES
At December 31, 1999, Murphy had 2,153 employees -- 1,476 full-time and 677
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 16 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" 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, 2000, 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 42; 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 45; 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 52; Senior Vice President since October 1994 and General
Counsel since August 1991. Mr. Cosse' was elected Vice President in 1993. For
the eight years prior to August 1991, he was General Counsel for Murphy
Expro, at that time named Ocean Drilling & Exploration Company (ODECO), a
majority-owned subsidiary of Murphy.
Herbert A. Fox Jr. - Age 65; 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 48; 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 63; Treasurer since August 1991. From 1975 through July
1991, he was with ODECO as Vice President of Taxes and Treasurer.
John W. Eckart - Age 41; 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 37; 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
Following a 1998 compliance inspection of the Superior, Wisconsin refinery, the
U.S. Environmental Protection Agency (EPA) gave the Company notices of violation
of environmental laws. Although the penalty amounts were not listed, the
statutes involved provide for rates of up to $27,500 per day of violation. The
EPA has referred the matter to the U.S. Department of Justice for enforcement.
The Superior refinery also received a notice of violation from the Wisconsin
Department of Natural Resources for alleged failure to meet new source
performance emission standards for the sulfur plant at the refinery. This item
has been referred to the Wisconsin Department of Justice for enforcement.
Penalties for these alleged state and federal violations could exceed $100,000.
The Company believes it has valid defenses to these alleged violations and plans
vigorous defenses. While the enforcement actions are in their preliminary stages
and no assurance can be given, the Company does not believe that the ultimate
resolution of these matters will have a material adverse effect on its financial
condition.
Murphy and its subsidiaries are engaged in a number of other legal proceedings,
all of which Murphy considers routine and incidental to its business and none of
which is expected to have a material adverse effect on the Company's financial
condition.
6
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 1999.
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 3,431
stockholders of record as of December 31, 1999. Information as to high and low
market prices per share and dividends per share by quarter for 1999 and 1998 are
reported on page F-28 of this Form 10-K report.
ITEM 6. SELECTED FINANCIAL DATA
(Thousands of dollars except per share data) 1999 1998 1997 1996 1995
---- ---- ---- ---- ----
RESULTS OF OPERATIONS FOR THE YEAR/1/
Sales and other operating revenues $2,036,840 1,694,470 2,133,387 2,009,736 1,613,848
Net cash provided by continuing operations 368,878 321,091 401,843 472,480 309,878
Income (loss) from continuing operations 119,707 (14,394) 132,406 125,956 (127,919)
Net income (loss) 119,707 (14,394) 132,406 137,855 (118,612)
Per Common share - diluted
Income (loss) from continuing operations 2.66 (.32) 2.94 2.80 (2.85)
Net income (loss) 2.66 (.32) 2.94 3.07 (2.65)
Cash dividends per Common share 1.40 1.40 1.35 1.30 1.30
Percentage return on
Average stockholders' equity 12.3 (1.3) 12.7 12.2 (9.3)
Average borrowed and invested capital 9.7 (.6) 10.4 10.4 (7.9)
Average total assets 5.2 (.6) 6.0 6.2 (5.2)
CAPITAL EXPENDITURES FOR THE YEAR
Exploration and production $ 295,958 331,647 423,181 373,984 231,718
Refining, marketing and transportation 88,075 55,025 37,483 42,880 53,602
Corporate and other 2,572 2,127 7,367 1,192 1,831
------- ------- ------- ------- -------
$ 386,605 388,799 468,031 418,056 287,151
======= ======= ======= ======= =======
FINANCIAL CONDITION AT DECEMBER 31
Current ratio 1.22 1.15 1.10 1.10 1.22
Working capital $ 105,477 56,616 48,333 56,128 87,388
Net property, plant and equipment 1,782,741 1,662,362 1,655,838 1,556,830 1,377,455
Total assets 2,445,508 2,164,419 2,238,319 2,243,786 2,098,466
Long-term debt 393,164 333,473 205,853 201,828 193,146
Stockholders' equity 1,057,172 978,233 1,079,351 1,027,478/2/ 1,101,145
Per share 23.49 21.76 24.04 22.90 24.56
Long-term debt - percent of capital employed 27.1 25.4 16.0 16.4 14.9
/1/Includes effects on income of special items in 1999, 1998 and 1997 that are
detailed in Management's Discussion and Analysis of Financial Condition and
Results of Operations. Also, special items in 1996 and 1995 increased
(decreased) net income by $22,124, $.49 a diluted share, and $(152,066),
$(3.39) a diluted share, respectively.
/2/Reflects $172,561 charge for distribution of common stock of Deltic Timber
Corporation to Murphy's stockholders.
7
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
The Company reported net income in 1999 of $119.7 million, $2.66 a diluted
share, compared to a net loss in 1998 of $14.4 million, $.32 a diluted share. In
1997, the Company earned $132.4 million, $2.94 a diluted share. Results of
operations for the three years ended December 31, 1999 included certain special
items that resulted in a net benefit of $19.7 million, $.44 a diluted share, in
1999; a net charge of $57.9 million, $1.29 a diluted share, in 1998; and a net
benefit of $.1 million, with no per share effect, in 1997. 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 tax and other matters. The 1998 special items included an after-tax
charge of $57.6 million, $1.28 a diluted share, from a write-down of assets
determined to be impaired under Statement of Financial Accounting Standards
(SFAS) No. 121.
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 record 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 the Company's 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 $6.05 a barrel in the average worldwide crude oil
sales price, up 56% 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, which include interest income and expense and corporate overhead not
allocated to operating functions, were $36.1 million in 1999 compared to $11.5
million in 1998. The increase in corporate costs in 1999 was primarily
attributable to higher net interest costs and higher costs of awards under the
Company's incentive plans.
1998 VS. 1997 - Excluding special items, income totaled $43.5 million in 1998,
$.97 a diluted share, a decrease of $88.8 million from the $132.3 million earned
in 1997. The income reduction was primarily attributable to a $79.2 million
decline in earnings from the Company's exploration and production operations.
Sharply lower crude oil prices in 1998 were the main reason for the reduction.
The Company's average crude oil sales price declined by $5.62 a barrel in 1998,
down 34% from oil prices realized in 1997. Higher crude oil production from new
fields in Canada and the United Kingdom were mostly offset by lower production
from maturing U.S. and U.K. oil fields and by selective shut-in of Canadian
heavy oil production. Natural gas sales prices in the United States declined 15%
in 1998 and U.S. natural gas sales volume was down 20%. Earnings from the
Company's refining, marketing and transportation operations were down $7.5
million in 1998, as record levels of finished product sales volumes were more
than offset by lower unit margins on product sales in the United States. The
costs of corporate and other activities increased $2.1 million in 1998 compared
to 1997, primarily due to higher net interest costs offset in part by lower
costs under the Company's incentive plans.
In the following table, the Company's results of operations for the three years
ended December 31, 1999 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) 1999 1998 1997
----- ---- ----
Exploration and production
United States $ 30.3 20.1 56.5
Canada 47.0 2.6 18.8
United Kingdom 37.2 .7 13.1
Ecuador 14.4 2.4 12.9
Other (7.7) (20.0) (16.3)
----- ---- ----
121.2 5.8 85.0
----- ---- -----
Refining, marketing and transportation
United States (5.9) 27.7 41.3
United Kingdom 14.0 16.8 9.2
Canada 6.8 4.7 6.2
----- ---- -----
14.9 49.2 56.7
----- ---- -----
Corporate and other (36.1) (11.5) (9.4)
----- ---- -----
Income before special items 100.0 43.5 132.3
Gain on sale of assets 7.5 2.9 11.5
Settlement of income tax matters 5.0 -- 3.2
Settlement of crude oil transportation rate 4.9 -- --
Net recovery pertaining to 1996 modifications of
foreign crude oil contracts 3.3 2.4 1.6
Provision for reduction in force (1.0) -- --
Impairment of long-lived assets -- (57.6) (16.2)
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 --
----- ---- -----
Net income (loss) $ 119.7 (14.4) 132.4
===== ==== =====
EXPLORATION AND PRODUCTION - Earnings from exploration and production operations
before special items were a record $121.2 million in 1999, compared to earnings
of $5.8 million in 1998 and $85 million in 1997. The improvement in 1999 was
primarily attributable to an increase in the Company's average worldwide crude
oil sales price, which averaged $16.86 a barrel in 1999 compared to $10.81 in
1998. The year 1999 also included a Company record for crude oil and condensate
production, which increased primarily due to higher production from new fields
in the United Kingdom and Canada. Natural gas sales volumes increased in 1999 in
both the United States and Canada, and each area benefited from higher average
natural gas sales prices. Lower average natural gas sales prices in the United
Kingdom served as a partial offset. The earnings decline in 1998 was primarily
due to lower worldwide crude oil sales prices, which averaged $10.81 a barrel in
1998 and $16.43 in 1997. Lower U.S. natural gas sales prices and volumes also
contributed to the 1998 decline. Partial offsets were provided by higher crude
oil production and lower exploration costs. Crude oil production from new fields
in the United Kingdom brought on stream during the third quarter of 1998 and
from the Hibernia field, offshore Newfoundland, which came on stream in late
1997, was partially offset by selective shut-in of heavy oil production in
western Canada in response to lower heavy oil prices and by lower production
from mature oil fields in the United States and the United Kingdom.
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-25 and F-26 of
this Form 10-K report. Daily production rates and weighted average sales prices
are shown on page 21 of the 1999 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) 1999 1998 1997
---- ---- ----
United States
Crude oil $ 54.1 35.6 74.9
Natural gas 143.2 132.1 196.7
Canada
Crude oil 106.8 55.4 71.6
Natural gas 38.9 24.0 22.1
Synthetic oil 74.8 53.0 67.9
United Kingdom
Crude oil 134.7 70.3 95.3
Natural gas 7.7 10.0 12.2
Ecuador - crude oil 37.2 19.1 34.7
----- ----- -----
Total oil and gas revenues $ 597.4 399.5 575.4
===== ===== =====
The Company's crude oil and gas liquids production averaged 66,083 barrels a day
in 1999, 59,128 in 1998 and 57,494 in 1997. Crude oil and liquids production in
the United States increased 9% in 1999, with the increase primarily due to new
production from several small fields on the continental shelf of the Gulf of
Mexico. In 1998, U.S. production was down 28% from 1997, primarily due to
declining production at mature oil fields in the Gulf of Mexico. Crude oil
production in Canada rose 6% in 1999 and established a record of 29,980 barrels
a day. The increase was primarily attributable to an increase of 2,212 barrels a
day at Hibernia, which averaged 6,404 in 1999. Hibernia, which came on stream in
the fourth quarter of 1997, produced 4,192 barrels a day in 1998 and 224 in
1997. Production at the Company's synthetic oil operation in Canada increased 5%
in 1999, but this increase was offset by 6% and 9% reductions in onshore
Canadian heavy oil and light oil production, respectively, during the year. The
higher net production of synthetic oil in 1999 was due to a 6% increase in gross
production, partially offset by a slightly higher net profit royalty rate caused
by higher oil prices. The Company's net interest in production of synthetic oil
in Canada increased 12% in 1998 due to a 1% increase in gross production and a
decrease in the net profits royalty rate as a result of lower oil prices. Before
royalties, the Company's synthetic oil production was 11,146 barrels a day in
1999, 10,501 in 1998 and 10,371 in 1997. Heavy oil production declined by 577
barrels a day in 1999 due to continued selective shut-in of fields caused by low
oil prices during the early part of the year. In 1998, crude oil production in
Canada increased 12%. As a result of selective shut-ins in the second half of
the year, production of heavy oil in Canada decreased 16% in 1998, compared to
1997. The Company's U.K. oil production increased 33% in 1999 after an 11%
increase in 1998. Oil production from the Mungo/Monan and Schiehallion fields,
which commenced in the third quarter of 1998, averaged 5,568 and 4,721 barrels a
day, respectively, in 1999. Mungo/Monan produced 2,025 barrels a day in 1998 and
Schiehallion produced 1,219. Oil production from the "T" Block field in the
United Kingdom declined by 24% during 1999, after an 18% decline in 1998.
Production from Ninian, the Company's other major North Sea oil field, declined
7% in 1999, after having declined 8% in 1998. Production in Ecuador declined 8%
in 1999 due to pipeline restrictions, after being essentially unchanged in 1998
when compared to 1997.
Worldwide sales of natural gas averaged 240.4 million cubic feet a day in 1999,
230.9 million in 1998 and 268.7 million in 1997. U.S. natural gas sales were
171.8 million cubic feet a day in 1999, 169.5 million in 1998 and 211.2 million
in 1997. The 1% increase in U.S. natural gas sales in 1999 was mainly due to
sales from several new fields in the Gulf of Mexico that offset lower sales from
maturing fields in the Gulf. The 20% decrease in U.S. natural gas sales in 1998
was mainly due to reduced deliverability in certain maturing Gulf of Mexico
fields. Natural gas sales in Canada in 1999 of 56.2 million cubic feet were at
record levels for the fourth straight year, as sales increased 15% in 1999
following a 9% increase in 1998. Natural gas sales in the United Kingdom of 12.4
million cubic feet were essentially unchanged in 1999, following a 2% decline in
1998.
As previously indicated, worldwide crude oil sales prices strengthened
considerably throughout 1999 after a significant downturn during 1998. In the
United States, Murphy's 1999 monthly sales prices for crude oil and condensate
ranged from $10.71 to $25.80 a barrel, and averaged $17.97 for the year, 41%
above the average 1998 price. In Canada, the average sales price for light oil
was $17.00 a barrel in 1999, also an increase of 41%. Heavy oil prices in Canada
averaged $12.77 a barrel, up 95% from prices in 1998. The average sales price
for synthetic oil in 1999 was $18.64 a barrel, 36% higher than a year earlier.
The sales price for crude oil from the Hibernia field averaged $18.69 a barrel,
up 78%. Sales prices in the United Kingdom were up 44% in 1999 and averaged
$18.09 a barrel. Sales prices in Ecuador averaged $12.94 a barrel in 1999, up
91% compared to a year ago. In 1998, U.S. crude and condensate sales prices
decreased 34% compared to 1997 and averaged $12.76 a barrel for the year. In
Canada, crude oil prices in 1998 declined 32% for light oil, 39% for heavy oil,
10
31% for synthetic oil and 31% for Hibernia. Sales prices in the United Kingdom
were down 34% in 1998 and prices in Ecuador were down 44%. Although crude oil
sales prices were strong in early 2000, the Company can give no assurance that
prices will remain at or near these levels in the future.
Average monthly natural gas sales prices in the United States ranged from $1.73
to $2.88 an MCF during 1999. For the year, U.S. sales prices averaged $2.27 an
MCF compared to $2.18 a year ago. The average price for natural gas sold in
Canada during 1999 was $1.90 an MCF, an increase of 42% from the average in
1998, as Canadian natural gas sales prices moved closer to parity with other
North American gas prices during the year. The average price in the United
Kingdom declined 25% to $1.68. The decline in average U.K. sales prices
primarily resulted from a contractual price basis adjustment at the Company's
largest gas producing field in the United Kingdom. Average U.S. natural gas
sales prices in 1998 were 15% lower than in 1997, prices were essentially
unchanged in Canada, and prices in the United Kingdom declined by 16%.
Based on 1999 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 $5.5 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 costs were $152 million in 1999, $155.1 million in 1998 and $164.8
million in 1997. These amounts are shown by major operating area on pages F-25
and F-26 of this Form 10-K report. Costs per equivalent barrel of production
during the last three years were as follows.
(Dollars per equivalent barrel) 1999 1998 1997
---- ---- ----
United States $2.63 3.32 2.59
Canada
Excluding synthetic oil 3.84 3.64 4.63
Synthetic oil 9.09 8.99 11.32
United Kingdom 3.73 5.60 5.58
Ecuador 3.62 2.48 3.87
Worldwide - excluding synthetic oil 3.33 3.79 3.72
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. cost per barrel was due
to higher production from lower-cost fields at Mungo/Monan and Schiehallion. The
higher cost in Ecuador in 1999 was caused by higher field operating costs
combined with lower production during the year. The increase in the U.S. cost
per equivalent barrel in 1998 was attributable to lower production volumes
combined with higher workover costs. The decline in Canada in 1998, excluding
synthetic oil, was caused by higher oil production at Hibernia, voluntary shut-
in of certain high-cost heavy oil production and a lower Canadian dollar
exchange rate vs. the U.S. dollar. The decrease in the cost for synthetic oil in
1998 was due to lower maintenance costs, a decrease in royalty barrels due to
lower sales prices and a lower Canadian dollar exchange rate. The lower cost in
Ecuador in 1998 was caused by lower energy and other field operating costs
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-25
and F-26 of this Form 10-K report. Certain of the expenses are included in the
capital expenditure totals for exploration and production activities.
(Millions of dollars) 1999 1998 1997
---- ---- ----
Exploratory expenditures charged against income
Dry hole costs $32.4 31.5 48.3
Geological and geophysical costs 18.7 17.0 26.4
Other costs 8.5 6.6 9.6
---- ---- ----
59.6 55.1 84.3
Undeveloped lease amortization 11.0 10.5 10.5
---- ---- ----
Total exploration expenses $70.6 65.6 94.8
==== ==== ====
11
Depreciation, depletion and amortization for exploration and production
operations totaled $166.3 million in 1999, $163.1 million in 1998 and $172.4
million in 1997. The 1999 increase was primarily due to higher production from
the Hibernia field offshore eastern Canada. The decrease in 1998 was primarily
attributable to lower worldwide hydrocarbon production.
REFINING, MARKETING AND TRANSPORTATION - Earnings from refining, marketing and
transportation operations before special items were $14.9 million in 1999, $49.2
million in 1998 and $56.7 million in 1997. Operations in the United States lost
$5.9 million in 1999 compared to earnings of $27.7 million in 1998, as the
average cost of crude oil and other feedstocks increased more than product sales
realizations. U.S. operations earned $41.3 million in 1997. Settlement of crude
oil swap agreements increased earnings by $5 million in 1997. U.K. operations
earned $14 million in 1999, $16.8 million in 1998 and $9.2 million in 1997. The
lower earnings in the United Kingdom in 1999 were caused by a larger increase in
the cost of refining feedstock than in product sales realizations. Canadian
operations contributed $6.8 million to 1999 earnings compared to $4.7 million in
1998 and $6.2 million in 1997.
Unit margins (sales realizations less costs of crude oil, other feedstocks,
refining and transportation to point of sale) averaged $.70 a barrel in the
United States in 1999, $1.47 in 1998 and $1.79 in 1997. U.S. product sales
declined 8% in 1999 following a 3% increase in 1998. The decline in sales volume
in the United States in 1999 was caused by a turnaround at the Company's Meraux
refinery early in the year. U.S. margins were under pressure during most of 1999
and the second half of 1998. Unit margins were very weak in early 2000 and the
Company was experiencing losses in its U.S. downstream operations.
Unit margins in the United Kingdom averaged $3.38 a barrel in 1999, $2.81 in
1998 and $2.90 in 1997. Sales of petroleum products were 11% lower in 1999
following a 25% increase in 1998. The volume decline in 1999 was attributable to
lower sales in the cargo market. Sales in both terminal and cargo markets
increased in 1998. Although margins improved in 1999, the Company's branded
outlets still face stiff competition from supermarket sales of motor fuels. Unit
margins have weakened considerably in early 2000.
Based on sales volumes for 1999 and deducting taxes at marginal rates, each $.42
a barrel ($.01 a gallon) fluctuation in unit margins would have affected annual
refining and marketing profits by $15.6 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.
Income before special items from purchasing, transporting and reselling crude
oil in Canada in 1999 increased by $2.1 million due to improved earnings from
the Company's crude oil trading and pipeline operations. Earnings declined by
$1.5 million in 1998 as lower prices for heavy oil led to production shut-ins,
which brought about lower pipeline throughputs and fewer barrels available for
crude trading activities.
SPECIAL ITEMS - Net income for the last three years included the special items
reviewed in the following paragraphs; the quarter in which each item occurred is
indicated. The effects of special items on quarterly results for 1999 and 1998
are presented on page F-28 of this Form 10-K report.
. GAIN ON SALE OF ASSETS - After-tax gains on sale of assets included
$6.3 million and $1.2 million recorded in the third and fourth
quarter, respectively, of 1999 from sale of U.S. service stations,
$2.9 million recorded in the fourth quarter of 1998 from sale of a
U.K. service station, and $11.5 million recorded in the fourth quarter
of 1997 from sale of a Canadian heavy oil property.
. SETTLEMENT OF INCOME TAX MATTERS - A gain of $5 million for settlement
of U.S. income taxes was recorded in the fourth quarter of 1999. A
gain of $3.2 million for settlement of U.K. income taxes was recorded
in the third quarter of 1997.
. SETTLEMENT OF CRUDE OIL TRANSPORTATION RATE - A gain of $4.9 million
for settlement of a crude oil transportation rate dispute in Ecuador
was recorded in the fourth quarter of 1999.
. NET RECOVERY PERTAINING TO 1996 MODIFICATIONS OF FOREIGN CRUDE OIL
CONTRACTS - Gains of $3.3 million, $1.4 million, $1 million and $1.6
million were recorded in the fourth quarter of 1999, the second
quarter of 1998, the fourth quarter of 1998 and the fourth quarter of
1997, respectively, for partial recoveries of a 1996 loss resulting
from modification of a crude oil production contract in Ecuador. (See
Note N to the consolidated financial statements.)
12
. 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 E to the consolidated financial statements.)
. IMPAIRMENT OF LONG-LIVED ASSETS - An after-tax provision of $57.6
million was recorded in the fourth quarter of 1998 and after-tax
provisions of $3.3 million and $12.9 million were recorded in the
third and fourth quarters, respectively, of 1997 for the write-down of
assets determined to be impaired. (See Note B 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 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.
The income (loss) effects of special items for each of the three years ended
December 31, 1999 are summarized by segment in the following table.
(Millions of dollars) 1999 1998 1997
---- ---- ----
Exploration and production
United States $ 5.0 (19.4) (4.9)
Canada -- (10.1) .2
United Kingdom -- (14.0) 3.2
Ecuador 8.2 2.4 1.6
Other -- (15.1) --
---- ---- ----
13.2 (56.2) .1
---- ---- ----
Refining, marketing and transportation
United States 7.5 -- --
United Kingdom -- .5 --
Canada -- (2.2) --
---- ---- ----
7.5 (1.7) --
---- ---- ----
Corporate and other (1.0) -- --
---- ---- ----
Total income (loss) from special items $19.7 (57.9) .1
==== ==== ====
CAPITAL EXPENDITURES
As shown in the selected financial data on page 7 of this Form 10-K report,
capital expenditures were $386.6 million in 1999 compared to $388.8 million in
1998 and $468 million in 1997. Expenditures charged to expense during each of
these years were $59.6 million, $55.1 million and $84.3 million, respectively.
Capital expenditures for exploration and production activities totaled $295.9
million in 1999, 77% of the Company's total capital expenditures for the year.
Exploration and production capital expenditures in 1999 included $18.3 million
for acquisition of undeveloped leases, $.4 million for acquisition of proved oil
and gas properties, $79.2 million for exploration activities and $198 million
for development projects. Development expenditures included $79.2 million for
the Terra Nova oil field, offshore Newfoundland; $26.8 million for expansion of
the synthetic oil operations in Canada; and $11.9 million and $11.8 million for
the Schiehallion and Mungo/Monan fields, respectively, offshore United Kingdom.
Capital expenditures for exploration and production activities are shown by
major operating area on page F-24 of this Form 10-K report. Amounts shown under
"Other" included $9.5 million in 1998 from drilling two unsuccessful offshore
wildcat wells in the Falkland Islands and $18.3 million in 1997 for exploration
drilling and related costs in Bohai Bay, China.
13
Refining, marketing and transportation expenditures, detailed in the following
table, were $88.1 million in 1999, or 23% of total capital expenditures,
compared to $55 million in 1998 and $37.5 million in 1997.
(Millions of dollars) 1999 1998 1997
---- ---- ----
Refining
United States $ 17.4 27.0 12.5
United Kingdom 7.0 .7 1.5
---- ---- ----
Total refining 24.4 27.7 14.0
---- ---- ----
Marketing
United States 58.7 16.7 14.1
United Kingdom 4.4 6.1 2.2
---- ---- ----
Total marketing 63.1 22.8 16.3
---- ---- ----
Transportation
United States .3 1.9 2.6
Canada .3 2.6 4.6
---- --- ----
Total transportation .6 4.5 7.2
---- ---- ----
Total $ 88.1 55.0 37.5
==== ==== ====
U.S. and U.K. refining expenditures 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
included the costs of new stations, primarily on land leased from Wal-Mart, and
improvements and normal replacements at existing stations and terminals. U.K.
marketing expenditures were primarily for improvements and normal replacements
at existing stations and terminals.
CASH FLOWS
Cash provided by operating activities was $368.9 million in 1999, $321.1 million
in 1998 and $401.8 million in 1997. Special items increased cash flow from
operations by $18.9 million in 1999 and $3.8 million in 1997, but reduced cash
by $6.3 million in 1998. Changes in operating working capital other than cash
and cash equivalents required cash of $35.2 million, $3.8 million and $72.4
million in 1999, 1998 and 1997, respectively. Cash provided by operating
activities was further reduced by expenditures for refinery turnarounds and
abandonment of oil and gas properties totaling $44.1 million in 1999, $24.6
million in 1998 and $14.4 million in 1997.
Cash proceeds from property sales were $40.9 million in 1999, $9.5 million in
1998 and $43.8 million in 1997. Borrowings under long-term notes payable
provided $247.8 million of cash in 1999, $161.3 million in 1998 and $9.7 million
in 1997. Additional borrowings under nonrecourse debt arrangements provided $6.4
million of cash in 1997.
Capital expenditures required $386.6 million of cash in 1999, $388.8 million in
1998 and $468 million in 1997. Other significant cash outlays during the three
years included $195.9 million in 1999, $34.5 million in 1998 and $17.3 million
in 1997 for debt repayment. Cash used for dividends to stockholders was $63
million in 1999, $62.9 million in 1998 and $60.6 million in 1997.
FINANCIAL CONDITION
Year-end working capital totaled $105.5 million in 1999, $56.6 million in 1998
and $48.3 million in 1997. 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 $115.2 million below current costs at
December 31, 1999. Cash and cash equivalents at the end of 1999 totaled $34.1
million compared to $28.3 million a year ago and $24.3 million at the end of
1997.
Long-term debt increased $59.7 million during 1999 to $393.2 million at the end
of the year, 27.1% of total capital employed, and included $144.6 million of
nonrecourse debt incurred in connection with the acquisition and development of
Hibernia. The increase in long-term debt in 1999 was attributable to the sale of
$250 million of long-term notes due in 2029; the proceeds of these notes were
used primarily to pay down borrowings under other long-term credit facilities.
Long-term debt totaled $333.5 million at the end of 1998 compared to $205.9
million at December 31, 1997. Stockholders' equity was $1.1 billion at the end
of 1999 compared to $1 billion a year ago and $1.1 billion at the end of 1997. A
summary of transactions in the stockholders' equity accounts is presented on
page F-5 of this Form 10-K report.
14
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 C to the consolidated financial statements. The Company does not expect any
problem in meeting future requirements for funds.
Murphy had commitments of $256 million for capital projects in progress at
December 31, 1999, including $84 million related to its share of a multiyear
contract for a semisubmersible deepwater drilling rig and associated equipment.
Certain costs committed under this 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 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 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 rata share of costs attributable to nonparticipating
PRPs or indications of additional responsibility by the Company.
Following a 1998 compliance inspection of the Superior, Wisconsin refinery, the
EPA gave the Company notices of violation of environmental laws. Although the
penalty amounts were not listed, the statutes involved provide for rates of up
to $27,500 per day of violation. The EPA has referred the matter to the U.S.
Department of Justice for enforcement. The Superior refinery also received a
notice of violation from the Wisconsin Department of Natural Resources for
alleged failure to meet new source performance emission standards for the sulfur
plant at the refinery. This item has been referred to the Wisconsin Department
of Justice for enforcement. The Company believes it has valid defenses to these
allegations and plans vigorous defenses. While the enforcement actions are in
their preliminary stages and no assurance can be given, the Company does not
believe that these 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.
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, 1999.
The Company's refineries also incur costs to handle and dispose of hazardous
wastes and other chemical substances. These costs are expensed as incurred and
amounted to $2.9 million in 1999. In addition to these expenses, Murphy
allocates a
15
portion of its capital expenditure program to comply with environmental laws and
regulations. Such capital expenditures were approximately $25 million in 1999
and are projected to be $28 million in 2000.
YEAR 2000 ISSUES
The Year 2000 issues related to the possibility that computer programs and
embedded computer chips might be unable to accurately process data with year
dates of 2000 and beyond. Murphy devoted significant internal and external
resources to address Year 2000 compliance. The Company's Year 2000 project
(Project) was successful, as the Company experienced no operational disruptions
attributable to Year 2000. The total amount expended on the Project was $4.9
million, including $3.3 million in 1999. Of the total expended, $2.3 million was
included in expense, including $.7 million in 1999, and costs of $2.6 million
have been capitalized as improvements in business system functionality beyond
Year 2000 compliance.
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 prices, which strengthened during 1999, remain strong, the Company
believes that future prices for oil field goods and services could be adversely
affected. Lower commodity prices in 1998 led to a softening of prices for goods
and services during the prior year.
ACCOUNTING MATTERS - The Financial Accounting Standards Board issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," in 1998.
This statement establishes accounting and reporting standards for derivative
instruments and hedging activities. 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. Any transition adjustments
resulting from adopting this statement will be reported in net income or other
comprehensive income, as appropriate, as the cumulative effect of a change in
accounting principle. As described in Note A to the consolidated financial
statements, the Company makes limited use of derivative instruments to hedge
specific market risks. The Company has not yet determined the effects that SFAS
No. 133 will have on its future consolidated financial statements or the amount
of the cumulative adjustment that will be made upon adopting this new standard.
OUTLOOK
Prices for the Company's primary products are often quite volatile. Entering
1999, oil prices were under extreme pressure, but due to increased worldwide
demand and disciplined management of supply by the world's producers --
primarily by members of OPEC -- oil prices rebounded significantly and the price
of West Texas Intermediate crude oil was more than $25 a barrel at the end of
1999. Despite the fact that crude oil prices have continued to strengthen in
early 2000 due to low crude oil inventories caused by supplies not fully meeting
demands, the Company can make no assurance that the price of oil will remain at
this high level in the future. Due to milder than normal winter weather across
much of North America, the price of natural gas has remained under pressure in
early 2000. The Company was experiencing losses in its U.S. refining and
marketing operations in early 2000, and U.K. margins had weakend considerably.
In such an environment, constant reassessment of spending plans is required. The
Company's capital expenditure budget for 2000 was prepared during the fall of
1999 and provides for expenditures of $457 million. Of this amount, $335 million
or 73% is allocated for exploration and production. Geographically, 41% of the
exploration and production budget is allocated to the United States; another 41%
is allocated to Canada, including $58 million for continued development of the
Terra Nova oil field, offshore Newfoundland, that is currently scheduled for an
early 2001 start-up; 9% is allocated to the United Kingdom; 3% is allocated to
Ecuador; and 6% is allocated to other foreign operations, which primarily
pertain to Malaysia. Planned refining, marketing and transportation capital
expenditures for 2000 are $120 million, including $104 million in the United
States, $13 million in the United Kingdom and $3 million in Canada. U.S. amounts
include funds for additional stations at
16
Wal-Mart sites. Capital and other expenditures are under constant review and
planned capital expenditures may be adjusted to reflect changes in estimated
cash flow.
In the United States, the Company is concentrating its exploration and
production capital spending on prospects in the deep waters of the Gulf of
Mexico. Although the Company is pleased with the successes achieved to date in
this exploration program, most of its discoveries in the deep water will take
two years or more to bring on production. Because of the lead time to bring on
this new production, the Company expects that its worldwide oil and natural gas
production will decline in 2000 by approximately 3% to 4% on a barrel-equivalent
basis when compared to 1999 production levels.
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, foreign
currency exchange rates, and prices of crude oil, natural gas and petroleum
products. As described in Note A to the consolidated financial statements,
Murphy makes limited use of derivative financial and commodity instruments to
manage certain risks associated with existing or anticipated transactions.
At December 31, 1999, 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, 1999, the interest rate to be
received by the Company averaged 6.19%. 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. The estimated fair value of these interest rate swaps was a gain of $.3
million at December 31, 1999.
At December 31, 1999, 29% of the Company's long-term debt had variable interest
rates and 19% was denominated in Canadian dollars. Based on debt outstanding at
December 31, 1999, a 10% increase in variable interest rates would not change
the Company's interest expense in 2000 after a $.6 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 vs. the
U.S. dollar would increase interest expense in 2000 by $.3 million on debt
denominated in Canadian dollars.
At December 31, 1999, the Company was a party to crude oil swap agreements for a
total notional volume of 2.3 million barrels that reduce a portion of the
financial exposure of Murphy's U.S. refineries to crude oil price movements. The
agreements mature in 2001 and 2002. At termination, the swaps require Murphy to
pay an average crude oil price of $16.76 a barrel and to receive the average of
the near-month NYMEX West Texas Intermediate (WTI) crude oil prices during the
respective contractual maturity periods. At December 31, 1999, the estimated
fair value of these crude oil swaps was a gain of $2.7 million; a 10%
fluctuation in the price of WTI crude oil would have changed the estimated fair
value of these swaps by $3.5 million.
At December 31, 1999, Murphy was also 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. The agreements are
to be settled equally over the 12 months of 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, 1999, the estimated fair value of these
agreements was a loss of $.1 million; a 10% fluctuation in the average NYMEX
Henry Hub price of natural gas would have changed the estimated fair value of
these swaps by $1.3 million.
17
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information required by this item appears on pages F-1 through F-28 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 10, 2000 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 10, 2000 under the captions "Compensation of Directors," "Executive
Compensation," "Option Exercises and Fiscal Year-End Values," "Option Grants,"
"Compensation Committee Report for 1999," "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 10, 2000 under the captions "Security Ownership of Certain Beneficial
Owners" and "Security Ownership of Management."
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 10, 2000 under the caption "Compensation Committee Interlocks and Insider
Participation."
18
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-22
Supplemental Quarterly Information (unaudited) F-28
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 Exhibit 3.1 of Murphy's Form 10-K report for the year
Corporation as of September 25, 1986 ended December 31, 1996
*3.2 By-laws of Murphy Oil Corporation as amended
December 1, 1999
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 Exhibit 4.1 of Murphy's Form 10-K report for the year
certain subsidiaries and the Chase Manhattan Bank et al as ended December 31, 1997
of November 13, 1997
4.2 Form of Indenture and Form of Supplemental Exhibits 4.1 and 4.2 of Murphy's Form 8-K report filed
Indenture between Murphy Oil Corporation and SunTrust Bank, April 29, 1999 under the Securities Exchange Act of 1934
Nashville, N.A., as Trustee
19
*4.3 Rights Agreement dated as of December 6, 1989
between Murphy Oil Corporation and Harris Trust Company of
New York, as Rights Agent
4.4 Amendment No. 1 dated as of April 6, 1998 to Exhibit 3 of Murphy's Form 8-A/A, Amendment No. 1, filed
Rights Agreement dated as of December 6, 1989 between Murphy April 14, 1998 under the Securities Exchange Act of 1934
Oil Corporation and Harris Trust Company of New York, as
Rights Agent
4.5 Amendment No. 2 dated as of April 15, 1999 to Exhibit 4 of Murphy's Form 8-A/A, Amendment No. 2, filed
Rights Agreement dated as of December 6, 1989 between Murphy April 19, 1999 under the Securities Exchange Act of 1934
Oil Corporation and Harris Trust Company of New York, as
Rights Agent
*10.1 1987 Management Incentive Plan as amended February
7, 1990 retroactive to February 3, 1988
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 Exhibit 99.01 of Murphy's Form S-8 Registration
Statement filed May 19, 1997 under the Securities Act of
1993
*13 1999 Annual Report to Security Holders including
Narrative to Graphic and Image Material as an appendix
*21 Subsidiaries of the Registrant
*23 Independent Auditors' Consent
*27 Financial Data Schedule for 1999
*99.1 Undertakings
#99.2 Form 11-K, Annual Report for the fiscal year ended To be filed as an amendment to this Form 10-K report not
December 31, 1999 covering the Thrift Plan for Employees of later than 180 days after December 31,1999
Murphy Oil Corporation
#99.3 Form 11-K, Annual Report for the fiscal year ended To be filed as an amendment to this Form 10-K report not
December 31, 1999 covering the Thrift Plan for later than 180 days after December 31, 1999
Employees of Murphy Oil USA, Inc. Represented by
United Steelworkers of America, AFL-CIO, Local No.
8363
#99.4 Form 11-K, Annual Report for the fiscal year ended To be filed as an amendment to this Form 10-K report not
December 31, 1999 covering the Thrift Plan for Employees of later than 180 days after December 31, 1999
Murphy Oil USA, Inc. Represented by International Union of
Operating Engineers, AFL-CIO, Local No. 305
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the quarter ended December
31, 1999.
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 CLAIBORNE P. DEMING Date: March 23, 2000
-------------------------------- -----------------------
Claiborne P. Deming, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below on March 23, 2000 by the following persons on
behalf of the registrant and in the capacities indicated.
R. MADISON MURPHY C. H. MURPHY JR.
----------------------------------------------- -------------------------------------------
R. Madison Murphy, Chairman and Director C. H. Murphy Jr., Director
CLAIBORNE P. DEMING MICHAEL W. MURPHY
----------------------------------------------- -------------------------------------------
Claiborne P. Deming, President and Chief Michael W. Murphy, Director
Executive Officer and Director
(Principal Executive Officer)
B. R. R. BUTLER WILLIAM C. NOLAN JR.
----------------------------------------------- -------------------------------------------
B. R. R. Butler, Director William C. Nolan Jr., Director
GEORGE S. DEMBROSKI CAROLINE G. THEUS
----------------------------------------------- -------------------------------------------
George S. Dembroski, Director Caroline G. Theus, Director
H. RODES HART LORNE C. WEBSTER
----------------------------------------------- -------------------------------------------
H. Rodes Hart, Director Lorne C. Webster, Director
ROBERT A. HERMES STEVEN A. COSSE'
----------------------------------------------- -------------------------------------------
Robert A. Hermes, Director Steven A. Cosse', Senior Vice President
and General Counsel
(Principal Financial Officer)
VESTER T. HUGHES JR. JOHN W. ECKART
----------------------------------------------- -------------------------------------------
Vester T. Hughes Jr., Director John W. Eckart, Controller
(Principal Accounting Officer)
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 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 generally accepted
auditing standards 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, 1999 and 1998, 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, 1999. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Murphy Oil
Corporation and Consolidated Subsidiaries as of December 31, 1999 and 1998, and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 1999, in conformity with generally
accepted accounting principles.
KPMG LLP
Shreveport, Louisiana
January 31, 2000
F-1
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31 (Thousands of dollars except per share amounts) 1999 1998 1997
----------- ---------- ----------
REVENUES
Crude oil and natural gas sales $ 464,802 312,253 450,785
Petroleum product sales 1,515,537 1,312,727 1,604,379
Other operating revenues 56,501 69,490 78,223
Interest and other nonoperating revenues 4,358 4,378 4,380
----------- ---------- ----------
Total revenues 2,041,198 1,698,848 2,137,767
----------- ---------- ----------
COSTS AND EXPENSES
Crude oil, products and related operating expenses 1,484,089 1,279,619 1,527,301
Exploration expenses, including undeveloped lease amortization 70,557 65,582 94,792
Selling and general expenses 81,817 61,363 65,928
Depreciation, depletion and amortization 204,446 202,695 209,419
Impairment of long-lived assets - 80,127 28,056
Charge resulting from cancellation of a drilling rig contract - 7,255 -
Provision for reduction in force 1,513 - -
Interest expense 28,139 18,090 12,717
Interest capitalized (7,865) (7,606) (12,096)
----------- ---------- ----------
Total costs and expenses 1,862,696 1,707,125 1,926,117
----------- ---------- ----------
Income (loss) before income taxes 178,502 (8,277) 211,650
Federal and state income tax expense 5,808 18,469 49,062
Foreign income tax expense (benefit) 52,987 (12,352) 30,182
----------- ---------- ----------
NET INCOME (LOSS) $ 119,707 (14,394) 132,406
=========== ========== ==========
NET INCOME PER COMMON SHARE - BASIC $ 2.66 (.32) 2.95
NET INCOME PER COMMON SHARE - DILUTED 2.66 (.32) 2.94
Average Common shares outstanding - basic 44,970,457 44,955,679 44,881,225
Average Common shares outstanding - diluted 45,030,225 44,955,679 44,960,907
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Years Ended December 31 (Thousands of dollars) 1999 1998 1997
----------- ---------- ----------
Net income (loss) $ 119,707 (14,394) 132,406
Other comprehensive income (loss) - net gain (loss) from
foreign currency translation 18,536 (24,411) (21,682)
----------- ---------- ----------
COMPREHENSIVE INCOME (LOSS) $ 138,243 (38,805) 110,724
=========== ========== ==========
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) 1999 1998
------ ------
ASSETS
Current assets
Cash and cash equivalents $ 34,132 28,271
Accounts receivable, less allowance for doubtful accounts
of $8,298 in 1999 and $11,048 in 1998 357,472 233,906
Inventories
Crude oil and blend stocks 61,853 41,090
Finished products 50,572 49,714
Materials and supplies 39,218 38,973
Prepaid expenses 28,145 32,292
Deferred income taxes 21,720 13,120
---------- ---------
Total current assets 593,112 437,366
Property, plant and equipment, at cost less accumulated depreciation,
depletion and amortization of $3,007,578 in 1999 and $2,985,854 in 1998 1,782,741 1,662,362
Deferred charges and other assets 69,655 64,691
---------- ---------
Total assets $2,445,508 2,164,419
========== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term debt $ 71 5,951
Notes payable - 1,961
Accounts payable 334,420 248,967
Withholdings and collections due governmental agencies 65,706 51,606
Other accrued liabilities 49,143 49,314
Income taxes 38,295 22,951
---------- ---------
Total current liabilities 487,635 380,750
Notes payable 248,569 189,705
Nonrecourse debt of a subsidiary 144,595 143,768
Deferred income taxes 154,109 124,543
Reserve for dismantlement costs 158,377 154,686
Reserve for major repairs 22,099 43,519
Deferred credits and other liabilities 172,952 149,215
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 512,488 510,116
Retained earnings 601,956 545,199
Accumulated other comprehensive loss - foreign currency translation (4,984) (23,520)
Unamortized restricted stock awards (2,328) (2,361)
Treasury stock (98,735) (99,976)
---------- ---------
Total stockholders' equity 1,057,172 978,233
---------- ---------
Total liabilities and stockholders' equity $2,445,508 2,164,419
========== =========
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) 1999 1998 1997
--------- -------- --------
OPERATING ACTIVITIES
Net income (loss) $ 119,707 (14,394) 132,406
Adjustments to reconcile net income (loss) to net cash provided
by operating activities
Depreciation, depletion and amortization 204,446 202,695 209,419
Impairment of long-lived assets - 80,127 28,056
Provisions for major repairs 18,721 20,420 24,614
Expenditures for major repairs and dismantlement costs (44,096) (24,582) (14,393)
Exploratory expenditures charged against income 59,589 55,128 84,320
Amortization of undeveloped leases 10,968 10,454 10,472
Deferred and noncurrent income tax charges (credits) 38,027 (937) 25,992
Pretax gains from disposition of assets (11,940) (3,857) (29,061)
Other - net 22,643 4,504 7,969
--------- -------- --------
418,065 329,558 479,794
Increase in operating working capital other than cash
and cash equivalents (35,159) (3,810) (72,391)
Other adjustments related to operating activities (14,028) (4,657) (5,560)
--------- -------- --------
Net cash provided by operating activities 368,878 321,091 401,843
--------- -------- --------
INVESTING ACTIVITIES
Capital expenditures requiring cash (386,605) (388,799) (468,031)
Proceeds from sale of property, plant and equipment 40,871 9,463 43,776
Other investing activities - net (3,532) (1,767) 673
--------- -------- --------
Net cash required by investing activities (349,266) (381,103) (423,582)
--------- -------- --------
FINANCING ACTIVITIES
Additions to notes payable 247,776 161,342 9,675
Reductions of notes payable (190,806) (218) (4)
Additions to nonrecourse debt of a subsidiary - 240 6,397
Reductions of nonrecourse debt of a subsidiary (5,120) (34,234) (17,276)
Cash dividends paid (62,950) (62,939) (60,573)
Other financing activities - net (1,742) 552 192
--------- -------- --------
Net cash provided (required) by financing activities (12,842) 64,743 (61,589)
--------- -------- --------
Effect of exchange rate changes on cash and cash equivalents (909) (748) (2,091)
--------- -------- --------
Net increase (decrease) in cash and cash equivalents 5,861 3,983 (85,419)
Cash and cash equivalents at January 1 28,271 24,288 109,707
--------- -------- --------
Cash and cash equivalents at December 31 $ 34,132 28,271 24,288
========== ======== ========
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) 1999 1998 1997
---------- -------- ---------
CUMULATIVE PREFERRED STOCK - par $100, authorized
400,000 shares, none issued $ - - -
---------- -------- ---------
COMMON STOCK - par $1.00, authorized 80,000,000 shares,
issued 48,775,314 shares at beginning and end of year 48,775 48,775 48,775
---------- -------- ---------
CAPITAL IN EXCESS OF PAR VALUE
Balance at beginning of year 510,116 509,615 509,008
Exercise of stock options 797 103 521
Restricted stock transactions 1,344 142 7
Sale of stock under employee stock purchase plan 231 256 79
---------- -------- ---------
Balance at end of year 512,488 510,116 509,615
---------- -------- ---------
RETAINED EARNINGS
Balance at beginning of year 545,199 622,532 550,699
Net income (loss) for the year 119,707 (14,394) 132,406
Cash dividends - $1.40 a share in 1999 and 1998, $1.35 a
share in 1997 (62,950) (62,939) (60,573)
---------- -------- ---------
Balance at end of year 601,956 545,199 622,532
---------- -------- ---------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) -
FOREIGN CURRENCY TRANSLATION
Balance at beginning of year (23,520) 891 22,573
Translation gains (losses) during the year 18,536 (24,411) (21,682)
---------- -------- ---------
Balance at end of year (4,984) (23,520) 891
---------- -------- ---------
UNAMORTIZED RESTRICTED STOCK AWARDS
Balance at beginning of year (2,361) (944) (1,298)
Stock awards - (3,238) -
Amortization, forfeitures and changes in price of Common Stock 33 1,821 354
---------- -------- ---------
Balance at end of year (2,328) (2,361) (944)
---------- -------- ---------
TREASURY STOCK
Balance at beginning of year (99,976) (101,518) (102,279)
Exercise of stock options 704 110 526
Awarded restricted stock, net of forfeitures - 1,136 122
Sale of stock under employee stock purchase plan 537 296 113
---------- -------- ---------
Balance at end of year - 3,777,319 shares of Common
Stock in 1999, 3,824,838 shares in 1998 and
3,883,883 shares in 1997 (98,735) (99,976) (101,518)
---------- -------- ---------
TOTAL STOCKHOLDERS' EQUITY $1,057,172 978,233 1,079,351
========== ======== =========
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 crude oil operation and operates two oil
refineries in the United States and has an effective 30% interest in a U.K.
refinery. Murphy markets petroleum products under various brand names and to
unbranded wholesale customers in the United States, the United Kingdom, and
Canada and transports and trades crude oil in Canada.
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 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, 1999 and 1998, 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
long-lived assets 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. Refining and marketing facilities are depreciated
primarily using the composite straight-line method. 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 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.
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.
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, foreign currency
exchange rates and commodity prices. Instruments that reduce the exposure of
assets, liabilities or anticipated transactions to interest rate, currency or
price risks are accounted for as hedges. Gains or losses on derivatives that
cease to qualify as hedges are recognized in income or expense. 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.
Murphy uses interest swap agreements to convert certain variable rate long-term
debt to fixed rates. Under the accrual/settlement method of accounting, the
Company records the net amount to be received or paid under the swap agreements
as part of "Interest Expense" in the Consolidated Statements of Income. If the
Company should terminate an interest rate swap prior to maturity, any cash paid
or received as settlement would be deferred and recognized as an adjustment to
"Interest Expense" over the shorter of the remaining life of the debt or the
remaining contractual life of the swap.
The Company periodically uses crude oil swap agreements to reduce a portion of
the financial exposure of its U.S. refineries to crude oil price movements.
Unrealized gains or losses on such swap contracts are generally deferred and
recognized in connection with the associated crude oil purchase. If conditions
indicate that the market price of finished products would not allow for recovery
of the costs of the finished products, including any unrealized loss on the
crude oil swap, a liability will be provided for the nonrecoverable portion of
the unrealized swap loss. The Company records pretax operating results
associated with crude oil swaps in "Crude Oil, Products and Related Operating
Expenses" in the Consolidated Statements of Income.
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 future natural gas fuel purchases. Unrealized gains or losses on such
swap contracts are deferred and recognized in connection with the associated
fuel purchases. The Company records the related pretax contract results in
"Crude Oil, Products and Related Operating Expenses" in the Consolidated
Statements of Income.
F-7
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 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 - PROPERTY, PLANT AND EQUIPMENT
Investment Investment
December 31, 1999 December 31, 1998
--------------------- --------------------
(Thousands of dollars) Cost Net Cost Net
---------- --------- --------- ---------
Exploration and production $3,750,077 1,324,685* 3,657,399 1,228,477*
Refining 698,100 259,883 677,245 257,640
Marketing 219,124 140,786 196,362 116,958
Transportation 84,391 38,762 81,307 40,459
Corporate and other 38,627 18,625 35,903 18,828
---------- --------- --------- ---------
$4,790,319 1,782,741 4,648,216 1,662,362
========== ========= ========= =========
*Includes $16,270 in 1999 and $15,766 in 1998 related to administrative assets
and support equipment.
In 1998 and 1997, the Company recorded noncash charges of $80,127,000 and
$28,056,000, respectively, for impairment of certain long-lived assets. After
related income tax benefits, these write-downs reduced net income by $57,573,000
in 1998 and $16,224,000 in 1997. 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 1997 charges
related to certain investments in Canadian heavy oil fields that were not
adequately supported by reserves and three natural gas fields in the Gulf of
Mexico that depleted earlier than anticipated. The carrying values for assets
determined to be impaired were adjusted to the assets' fair values based on
projected future discounted net cash flows, using the Company's estimates of
future commodity prices.
NOTE C - FINANCING ARRANGEMENTS
At December 31, 1999, 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 $112,191,000 at December 31, 1999 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 at
dates ranging from 2000 through 2002. In addition, the Company had unused
uncommitted lines of credit with banks at December 31, 1999 totaling an
equivalent US $186,333,000 for a combination of U.S. dollar and Canadian dollar
borrowings.
During 1999, the Company filed a shelf registration statement with the U.S.
Securities and Exchange Commission that was declared effective and 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, 1999.
F-8
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE D - LONG-TERM DEBT
December 31 (Thousands of dollars) 1999 1998
---- ----
Notes payable
7.05% notes, due 2029 $247,277 -
Notes payable to bank, 10.1%, due 2004 - 20,000
Notes payable to banks, 5.30% to 5.35%, $7,842 payable in
Canadian dollars, due 2002 - 168,842
Other, 6% to 8%, due 2000-2021 1,363 867
-------- -------
Total notes payable 248,640 189,709
-------- -------
Nonrecourse debt of a subsidiary
Guaranteed credit facilities with banks
Commercial paper, 4.93% to 6.15%, $42,791 payable in
Canadian dollars, supported by credit facility, due 2001-2008 112,191 109,786
Bankers' acceptance, 5.27%, payable in Canadian dollars,
supported by credit facility - 5,947
Loan payable to Canadian government, interest free, payable in
Canadian dollars, due 2000-2008 32,404 33,982
-------- -------
Total nonrecourse debt of a subsidiary 144,595 149,715
-------- -------
Total debt including current maturities 393,235 339,424
Current maturities (71) (5,951)
-------- -------
Total long-term debt $393,164 333,473
======== =======
Amounts becoming due for the four years after 2000 are: $76,000 in 2001,
$29,645,000 in 2002, $14,696,000 in 2003, and $16,016,000 in 2004.
During 1999, the Company issued $250 million of 30-year notes in the public
market; these notes mature in May 2029 and are shown in the above table net of
unamortized discount. The proceeds were used primarily to repay amounts
previously borrowed under other financing arrangements, which remain available
to the Company at December 31, 1999 as discussed in Note C.
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. The Company has borrowed the maximum amount available under the
Primary Guarantee Facility at December 31, 1999. The amount guaranteed declines
quarterly beginning in 2001, at which time repayment will begin based on the
greater of 30% of Murphy's after-tax free cash flow from Hibernia or equal
quarterly payments over eight years. The payment for 2001 is planned to be
refinanced under an existing committed credit facility and is thereby reflected
as becoming due in 2002. No guaranteed financing is available after January 1,
2016. 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. Repayment began in 1999, but payments
through 2001 are planned to be refinanced under an existing committed credit
facility and are thereby reflected as becoming due in 2002.
NOTE E - 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 locations. The
voluntary retirements and severances reduced the Company's workforce by 31
employees, and a "Provision for Reduction in Force" of $1,513,000 was recorded
in the Consolidated Statement of Income in 1999. The provision included
additional defined benefit plan expense of $1,041,000 and severance and other
costs of $472,000, the latter of which was essentially all paid during 1999.
F-9
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE F - INCOME TAXES
The components of income (loss) before income taxes for each of the three years
ended December 31, 1999 and income tax expense (benefit) attributable thereto
were as follows.
(Thousands of dollars) 1999 1998 1997
-------- ------- -------
Income (loss) before income taxes
United States $ 15,074 44,600 135,476
Foreign 163,428 (52,877) 76,174
-------- ------- -------
$178,502 (8,277) 211,650
======== ======= =======
Income tax expense (benefit)
Federal - Current/1/ $(13,497) 6,431 31,278
Deferred 1,597 6,232 (1,751)
Noncurrent 16,366 3,785 14,946
-------- ------- -------
4,466 16,448 44,473
-------- ------- -------
State - Current 1,342 2,021 4,589
-------- ------- -------
Foreign - Current 40,726 (3,498) 12,912
Deferred/2/ 11,165 (10,201) 19,423
Noncurrent 1,096 1,347 (2,153)
-------- ------- -------
52,987 (12,352) 30,182
-------- ------- -------
Total income tax expense $ 58,795 6,117 79,244
======== ======= =======
/1/Net of benefits of $12,537 in 1997 for alternative minimum tax credits.
/2/Net of benefits of $609 in 1999 and $1,573 in 1997 for reductions in U.K. tax
rate.
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.
(Thousands of dollars) 1999 1998 1997
-------- ------ ------
Income tax expense (benefit) based on the
U.S. statutory tax rate $62,475 (2,897) 74,078
Foreign income subject to foreign taxes at a rate
different than the U.S. statutory rate 1,988 5,692 11,087
State income taxes 872 1,313 2,983
Settlement of U.S. taxes (5,000) (704) -
Settlement of foreign taxes - (1,410) (3,163)
Foreign asset impairment with no tax benefit - 5,293 -
Other, net (1,540) (1,170) (5,741)
------- ------ ------
Total income tax expense $58,795 6,117 79,244
======= ====== ======
F-10
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, 1999 and 1998 showing the tax effects of significant temporary
differences follows.
(Thousands of dollars) 1999 1998
--------- --------
Deferred tax assets
Property and leasehold costs $ 64,469 75,716
Reserves for dismantlements and major repairs 53,470 63,763
Federal alternative minimum tax credit carryforward 3,177 2,068
Postretirement and other employee benefits 24,637 17,979
Foreign tax operating losses 23,135 15,064
Other deferred tax assets 29,379 24,234
--------- --------
Total gross deferred tax assets 198,267 198,824
Less valuation allowance (57,388) (62,358)
--------- --------
Net deferred tax assets 140,879 136,466
--------- --------
Deferred tax liabilities
Property, plant and equipment (32,985) (34,152)
Accumulated depreciation, depletion and amortization (213,674) (189,082)
Other deferred tax liabilities (27,364) (24,686)
--------- --------
Total gross deferred tax liabilities (274,023) (247,920)
--------- --------
Net deferred tax liabilities $(133,144) (111,454)
========= ========
The Company has tax loss carryforwards of $92,500,000 associated with its
operations in Ecuador. These losses can be carried forward for five years but
are limited to 25% of each year's taxable income. The 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 decreased $4,970,000 in 1999, but
increased $10,762,000 in 1998; 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 $23,640,000 related to
undistributed earnings of certain foreign subsidiaries at December 31, 1999
because the earnings are considered permanently invested.
Tax returns are subject to audit by various taxing authorities. In 1999, 1998
and 1997, the Company recorded benefits to income of $5,000,000, $2,114,000, and
$3,163,000, respectively, from settlements of various U.S. and foreign tax
issues primarily related to prior years. The Company believes that adequate
accruals have been made for unsettled issues.
NOTE G - 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 $13,161,000 in 1999, $(4,646,000) in 1998
and $2,026,000 in 1997; outstanding awards were not significantly modified in
the last three years. 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.
F-11
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Thousands of dollars except per share data) 1999 1998 1997
-------- -------- -------
Net income (loss) - As reported $119,707 (14,394) 132,406
Pro forma 124,543 (18,182) 132,089
Earnings per share - As reported, basic $ 2.66 (.32) 2.95
Pro forma, basic 2.77 (.40) 2.94
As reported, diluted 2.66 (.32) 2.94
Pro forma, diluted 2.76 (.40) 2.94
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. At exercise, a grantee may
pay cash for shares, or alternatively, not remit cash and receive shares equal
to the inherent value of options exercised on that date. On December 31, 1996,
Murphy completed a tax-free spin-off to its stockholders of all the common stock
of its wholly owned subsidiary, Deltic Timber Corporation (Deltic). The number
of outstanding options at January 1, 1997 and the related option prices were
adjusted to preserve the existing economic values of the options at the time of
the Deltic spin-off.
The pro forma net income calculations in the preceding table reflect the
following weighted-average fair values of options granted in 1999, 1998 and
1997; fair values of options have been estimated by using the Black-Scholes
pricing model and the assumptions as shown.
1999 1998 1997 1997
FMV FMV FMV Above FMV
----- ----- ----- ----------
Weighted-average fair value per share at grant date $ 7.76 $ 9.01 $ 9.75 $ 8.25
Weighted-average assumptions
Dividend yield 2.87% 2.91% 3.00% 3.00%
Expected volatility 24.21% 17.27% 17.37% 17.37%
Risk-free interest rate 4.77% 5.46% 6.18% 6.37%
Expected life 5 yrs. 5 yrs. 5 yrs. 7 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, 1996 440,599 $40.77
Deltic spin-off adjustment 17,407 -
Granted at FMV 180,250 50.38
Granted above FMV 231,750 60.45
Exercised (68,022) 36.53
Forfeited (31,295) 49.08
---------
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
=========
Exercisable at December 31, 1997 174,269 $37.79
Exercisable at December 31, 1998 284,529 39.53
Exercisable at December 31, 1999 441,119 45.36
F-12
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Additional information about stock options outstanding at December 31, 1999 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 $39.42 388,919 7.9 $35.80 68,419 $ 36.33
$40.81 to $42.25 180,700 5.7 41.41 180,700 41.41
$49.75 to $50.38 464,250 7.7 49.97 118,500 50.38
$55.41 to $65.49 220,500 7.1 60.45 73,500 55.41
--------- -------
Total outstanding 1,254,369 7.4 46.19 441,119 45.36
========= =======
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 - Beginning in 1992, shares of restricted stock were granted 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 values per share of restricted stock granted in 1998 was $49.50, the market
price of the stock at the date granted. The number of restricted shares
outstanding at January 1, 1997 was adjusted to preserve the existing economic
value of the stock at the time of the Deltic spin-off. 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) 1999 1998 1997
------ ------- -------
Balance at beginning of year 83,364 39,856 36,512
Granted - 59,750 -
Grant adjustment to reflect Deltic spin-off - - 5,977
Awarded - - (1,336)*
Forfeited - (16,242) (1,297)
------ ------- ------
Balance at end of year 83,364 83,364 39,856
====== ======= ======
*Additional shares awarded related to Deltic spin-off.
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 $5,301,000, $518,000 and $3,894,000 was
recorded in 1999, 1998, and 1997, respectively, for these plans.
EMPLOYEE STOCK PURCHASE PLAN (ESPP) - In 1997, the Company's shareholders
approved the ESPP, under which 50,000 shares of the Company's Common Stock could
be purchased by employees. Each quarter, an eligible U.S. 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 50,000 shares or June 30, 2002. Employee stock
purchases under the ESPP were 20,486 shares at an average price of $37.56 a
share in 1999, 11,315 shares at $48.81 a share in 1998 and 4,326 shares at
$44.44 in 1997. At December 31, 1999, 13,873 shares remained available for sale
under the ESPP. Compensation costs related to the ESPP were immaterial.
F-13
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE H - EMPLOYEE AND RETIREE BENEFIT PLANS
PENSION AND POSTRETIREMENT PLANS - The Company has noncontributory defined
benefit pension plans that cover substantially all full-time employees. In
addition, the Company sponsors plans that provide health care and life insurance
benefits 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,
1999 and 1998 and a statement of the funded status as of December 31, 1999 and
1998.
Pension Postretirement
Benefits Benefits
------------------ -----------------
(Thousands of dollars) 1999 1998 1999 1998
-------- ------- ------- -------
CHANGE IN BENEFIT OBLIGATION
Obligation at January 1 $238,022 220,981 36,749 36,255
Service cost 5,791 5,242 712 601
Interest cost 15,516 15,309 2,366 2,474
Plan amendments 225 2,744 - -
Participant contributions - - 531 535
Actuarial (gain) loss (6,167) 8,492 (2,916) 496
Curtailment 226 - - -
Settlements (82) - - -
Special early retirement benefits 1,079 - - -
Exchange rate changes 18 (908) - -
Benefits paid (13,998) (13,838) (3,092) (3,612)
-------- ------- ------- -------
Obligation at December 31 240,630 238,022 34,350 36,749
-------- ------- ------- -------
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1 286,846 269,794 - -
Actual return on plan assets 30,613 30,727 - -
Employer contributions 842 1,373 2,561 3,077
Participant contributions - - 531 535
Settlements (82) - - -
Exchange rate changes 253 (1,210) - -
Benefits paid (13,998) (13,838) (3,092) (3,612)
-------- ------- ------- -------
Fair value of plan assets at December 31 304,474 286,846 - -
-------- ------- ------- -------
RECONCILIATION OF FUNDED STATUS
Funded status at December 31 63,844 48,824 (34,350) (36,749)
Unrecognized actuarial (gain) loss (43,292) (30,410) 3,610 6,730
Unrecognized transition asset (8,729) (10,960) - -
Unrecognized prior service cost 6,391 6,813 - -
-------- ------- ------- -------
Net plan asset (liability) recognized $ 18,214 14,267 (30,740) (30,019)
======== ======= ======= =======
AMOUNTS RECOGNIZED IN THE CONSOLIDATED
BALANCE SHEETS AT DECEMBER 31
Prepaid benefit asset $ 34,200 29,477 - -
Accrued benefit liability (16,300) (16,087) (30,740) (30,019)
Intangible asset 314 877 - -
-------- ------- ------- -------
Net plan asset (liability) recognized $ 18,214 14,267 (30,740) (30,019)
======== ======= ======= =======
F-14
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, 1999 and 1998. The
accumulated benefit obligations of these plans at December 31, 1999 and 1998
were $7,784,000 and $7,486,000, respectively; there were no assets in these
plans. The Company's postretirement benefit plan also had no plan assets; the
benefit obligation for this plan at December 31, 1999 and 1998 was $30,740,000
and $30,019,000, respectively.
The table that follows provides the components of net periodic benefit expense
(credit) for each of the three years ended December 31, 1999.
Pension Benefits Postretirement Benefits
-------------------------- -----------------------
(Thousands of dollars) 1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ----
Service cost $ 5,791 5,242 4,517 712 601 508
Interest cost 15,516 15,309 14,889 2,366 2,474 2,466
Expected return on plan assets (23,105) (22,180) (19,040) - - -
Amortization of prior service cost 622 626 402 - - -
Amortization of transitional asset (2,204) (2,211) (2,216) - - -
Recognized actuarial (gain) loss (766) (758) (965) 203 194 67
-------- -------- ------- ------ ----- -----
Net periodic benefit
expense (credit) (4,146) (3,972) (2,413) 3,281 3,269 3,041
Special early retirement benefits 1,041 - - - - -
-------- -------- ------- ------ ----- -----
Total periodic benefit
expense (credit) $ (3,105) (3,972) (2,413) 3,281 3,269 3,041
======== ======== ======= ====== ===== =====
The preceding tables in Note H include the following amounts related to
foreign benefit plans.
Pension Postretirement
Benefits Benefits
-------------- --------------
(Thousands of dollars) 1999 1998 1999 1998
---- ---- ---- ----
Obligation at December 31 $53,675 47,625 - -
Fair value of plan assets at December 31 61,462 54,348 - -
Net plan liability recognized (3,178) (3,285) - -
Net periodic benefit expense 364 410 - -
The following table provides the weighted-average assumptions used in the
measurement of the Company's benefit obligations at December 31, 1999 and 1998.
Pension Postretirement
Benefits Benefits
-------------- --------------
1999 1998 1999 1998
---- ---- ---- ----
Discount rate 7.26% 6.62% 7.50% 6.75%
Expected return on plan assets 8.34% 8.31% - -
Rate of compensation increase 4.66% 4.67% - -
For purposes of measuring postretirement benefit obligations at December 31,
1999, the future annual rates of increase in the cost of health care were
assumed to be 6.5% for 2000, 5.5% for 2001 and 4.5% for 2002 and beyond.
F-15
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, 1999 $ 221 (211)
Effect on the health care component of the accumulated
postretirement benefit obligation at December 31, 1999 2,124 (2,063)
THRIFT PLANS - Most U.S. and Canadian employees of the Company may participate
in thrift plans by allotting up to a specified percentage of their base pay. The
Company matches contributions at a stated percentage of each employee's
allotment based on years of participation in the plans. Amounts charged to
expense for these plans were $2,523,000 in 1999, $3,333,000 in 1998 and
$3,076,000 in 1997. In early 2000, the Company initiated a profit sharing plan
for its U.K. employees, whereby the Company matches contributions of eligible
employees. The cost of the U.K. plan is projected to be $190,000 in 2000.
NOTE I - 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, 1999 and
1998, 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 6.19% at December 31, 1999.
The variable rate received by the Company under each contact is repriced
quarterly.
The Company periodically uses crude oil swap agreements to reduce a portion of
the financial exposure of its U.S. refineries to crude oil price movements. At
December 31, 1999, the Company was a party to crude oil swap agreements for a
total notional volume of 2.3 million barrels; these swaps mature in 2001 and
2002. At termination, the swaps require Murphy to pay an average crude oil price
of $16.76 a barrel and to receive the average of the near-month NYMEX West
Texas Intermediate (WTI) crude oil prices during the respective contractual
maturity periods. Unrealized gains or losses on such swap contracts are
generally deferred and recognized in connection with the associated crude oil
purchase. If conditions indicate that the market price of finished products
would not allow for recovery of the costs of the finished products, including
any unrealized loss on the crude oil swap, a liability will be provided for the
nonrecoverable portion of the unrealized swap loss. After-tax gains from crude
oil swaps were $5,041,000 in 1997.
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, 1999, Murphy was a
party to natural gas swap agreements for a total notional volume of 7 million
MMBTU. One-twelfth of the notional volume matures each month during 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 in 2004. Unrealized gains or losses on such swap contracts
are deferred and recognized in connection with the associated fuel purchases.
FAIR VALUE - The following table presents the carrying amounts and estimated
fair values of financial instruments held by the Company at December 31, 1999
and 1998. 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.
F-16
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1999 1998
-------------------- --------------------
Carrying Carrying Fair Carrying Fair
(Thousands of dollars) Amount Value Amount Value
--------- -------- -------- ---------
Financial liabilities
Current and long-term debt $(393,235) (373,546) (341,385) (333,905)
Off-balance-sheet exposures -
unrealized gain (loss)
Interest rate swaps - 266 - (5,453)
Crude oil swaps - 2,668 - -
Natural gas swaps - (83) - -
Financial guarantees and letters of credit - - - -
The carrying amounts of financial liabilities 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
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 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.
NOTE J - 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 K - 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, 1999. No difference existed between net income
(loss) used in computing basic and diluted income (loss) per Common share for
these years.
F-17
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Weighted-average shares outstanding) 1999 1998 1997
---- ---- ----
Basic method 44,970,457 44,955,679 44,881,225
Dilutive stock options 59,768 - 79,682
---------- ---------- ----------
Diluted method 45,030,225 44,955,679 44,960,907
========== ========== ==========
The computations of diluted earnings per share in the Consolidated Statements of
Income did not consider outstanding options at year end of 684,750 shares in
1999, 1,053,249 shares in 1998 and 397,000 shares in 1997 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 $53.34, $48.73 and
$55.97, respectively.
NOTE L - OTHER FINANCIAL INFORMATION
INVENTORIES - Inventories accounted for under the LIFO method totaled
$72,452,000 and $65,107,000 at December 31, 1999 and 1998, respectively, and
were $115,236,000 and $14,195,000 less than such inventories would have been
valued using the first-in first-out method. At December 31, 1998, the Company
established an allowance to reduce the carrying value of certain crude oil
inventories to market value, resulting in an after-tax charge to income of
$4,227,000. Based on crude oil prices at December 31, 1999, the Company carried
no such inventory valuation allowance at that date.
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, 1999, components of
the net cumulative loss of $4,984,000 were gains (losses) of $31,218,000 for
pounds sterling, $(36,632,000) for Canadian dollars and $430,000 for other
currencies. Comparability of net income was not significantly affected by
exchange rate fluctuations in 1999, 1998 or 1997. Net gains (losses) from
foreign currency transactions included in the Consolidated Statements of Income
were $(847,000) in 1999, $282,000 in 1998 and $200,000 in 1997.
CASH FLOW DISCLOSURES - Cash income taxes paid (refunded) were $(5,343,000),
$26,227,000 and $86,962,000 in 1999, 1998 and 1997, respectively. Interest paid,
net of amounts capitalized, was $17,140,000, $9,551,000 and $269,000 in 1999,
1998 and 1997, respectively.
Noncash operating working capital (increased) decreased for each of the three
years ended December 31, 1999 as follows.
(Thousands of dollars) 1999 1998 1997
---- ---- ----
Accounts receivable $(123,566) 38,541 47,214
Inventories (21,866) 28,639 (27,061)
Prepaid expenses 4,147 15,031 (17,503)
Deferred income tax assets (8,600) 2,158 4,348
Accounts payable and accrued liabilities 99,382 (85,503) (67,623)
Current income tax liabilities 15,344 (2,676) (11,766)
--------- ------- -------
Net increase in noncash operating working capital $ (35,159) (3,810) (72,391)
========= ======= =======
NOTE M - 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
$256,000,000 at December 31, 1999, including $84,000,000 related to the
Company's share of a multiyear contract for a semisubmersible deepwater drilling
rig and associated support equipment. Certain costs committed under this
contract will be charged to the Company's partners when future deepwater wells
are drilled.
F-18
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE N - 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; restrictions on production; import and
export controls; price controls; currency controls; allocation of supplies of
crude oil and petroleum products and other goods; expropriation of property;
restrictions and preferences affecting 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.
FOREIGN CRUDE OIL CONTRACTS - In August 1996, the Ecuadoran government notified
the Company that its risk service contract for production of crude oil in
Ecuador would be replaced by a production sharing contract effective January 1,
1997 to give the government a larger share of future oil revenues. While the
state oil company, PetroEcuador, acknowledged that amounts were owed under the
former contract and indicated its intention to pay, the Company considered the
circumstances surrounding the contract replacement and recorded an $8,876,000
provision for doubtful accounts in 1996. Based on amounts subsequently
collected, the Company determined that portions of the allowance for doubtful
accounts were no longer required and recognized income of $3,304,000 in 1999,
$2,410,000 in 1998 and $1,642,000 in 1997.
ENVIRONMENTAL MATTERS - 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 letters of credit
that may be drawn upon if the Company fails to perform under those contracts. At
December 31, 1999, the Company had contingent liabilities of $52,400,000 on
outstanding letters of credit and $66,900,000 under certain financial
guarantees.
NOTE O - 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 $898,917,000,
$831,385,000 and $679,953,000 for the years 1999, 1998 and 1997, 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-20, "Certain Long-Lived Assets at December 31"
exclude investments, noncurrent receivables and deferred tax assets.
F-19
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
SEGMENT INFORMATION Exploration and Production
------------------------------------------------------------------
(Millions of dollars) U.S. Canada U.K. Ecuador Other Total
---- ------ ---- ------- ----- -----
YEAR ENDED DECEMBER 31, 1999
Segment income (loss) $ 35.3 47.0 37.2 22.6 (7.7) 134.4
Revenues from external customers 151.1 162.0 119.0 40.1 2.0 474.2
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 50.3 42.8 8.0 .1 166.3
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 146.7 92.5 82.8 21.3 2.7 346.0
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 44.0 42.9 10.2 - 163.1
Impairment of long-lived assets 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
- - - - - --------------------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1997
Segment income (loss) $ 51.6 19.0 16.3 14.5 (16.3) 85.1
Revenues from external customers 210.7 125.1 121.6 36.0 2.5 495.9
Intersegment revenues 64.1 60.5 - - - 124.6
Interest income - - - - - -
Interest expense, net of capitalization - - - - - -
Income of equity companies - - - - - -
Income tax expense (benefit) 27.2 9.8 15.4 (1.1) .1 51.4
Significant noncash charges (credits)
Depreciation, depletion, amortization 79.4 37.9 43.7 11.4 - 172.4
Impairment of long-lived assets 7.7 20.4 - - - 28.1
Provisions for major repairs - 4.6 - - - 4.6
Amortization of undeveloped leases 6.7 3.6 .1 - .1 10.5
Deferred and noncurrent income taxes (9.8) 9.1 (.9) - 1.3 (.3)
Additions to property, plant, equipment 102.5 135.1 80.0 10.4 10.9 338.9
Total assets at year-end 400.7 596.0 319.6 61.5 24.9 1,402.7
- - - - - --------------------------------------------------------------------------------------------------------------------------------
GEOGRAPHIC INFORMATION Certain Long-Lived Assets at December 31
------------------------------------------------------------------
(Millions of dollars) U.S. Canada U.K. Ecuador Other Total
---- ------ ---- ------- ----- -----
1999 $ 725.6 724.5 333.8 53.5 7.7 1,845.1
1998 706.2 600.4 352.8 54.4 8.4 1,722.2
1997 683.8 601.4 354.5 54.4 21.7 1,715.8
F-20
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, 1999
Segment income (loss) $ 1.6 14.0 6.8 22.4 (37.1) 119.7
Revenues from external customers 1,247.8 286.7 28.1 1,562.6 4.4 2,041.2
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 2.7 204.4
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 1,064.9 260.7 22.8 1,348.4 4.4 1,698.8
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 3.2 202.7
Impairment of long-lived assets - - .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
- - - - - --------------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1997
Segment income (loss) $ 41.3 9.2 6.2 56.7 (9.4) 132.4
Revenues from external customers 1,342.8 268.6 26.1 1,637.5 4.4 2,137.8
Intersegment revenues 2.4 - .1 2.5 - 127.1
Interest income - - - - 4.8 4.8
Interest expense, net of capitalization - - - - .6 .6
Income of equity companies 1.1 - - 1.1 - 1.1
Income tax expense (benefit) 23.7 5.9 6.2 35.8 (8.0) 79.2
Significant noncash charges (credits)
Depreciation, depletion, amortization 27.8 4.7 2.0 34.5 2.5 209.4
Impairment of long-lived assets - - - - - 28.1
Provisions for major repairs 18.1 1.8 - 19.9 .1 24.6
Amortization of undeveloped leases - - - - - 10.5
Deferred and noncurrent income taxes (.7) 1.9 .1 1.3 25.0 26.0
Additions to property, plant, equipment 29.2 3.7 4.6 37.5 7.3 383.7
Total assets at year-end 491.4 194.7 64.5 750.6 85.0 2,238.3
- - - - - --------------------------------------------------------------------------------------------------------------------------
GEOGRAPHIC INFORMATION Revenues from External Customers for the Year
------------------------------------------------------------------
(Millions of dollars) U.S. U.K. Canada Ecuador Other Total
---- ---- ------ ------- ----- -----
1999 $1,400.1 408.6 190.4 40.1 2.0 2,041.2
1998 1,212.0 346.9 115.9 21.3 2.7 1,698.8
1997 1,554.7 392.9 151.7 36.0 2.5 2,137.8
F-21
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 and the approved development of the Aurora mine.
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 1999 crude oil prices used for this calculation were
$23.23 a barrel for the United States, $25.68 for Canadian light, $17.25 for
Canadian heavy, $23.85 for Canadian offshore, $24.29 for the United Kingdom and
$17.45 for Ecuador. Average year-end 1999 natural gas prices used were $2.23 an
MCF for the United States, $1.95 for Canada and $2.01 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, 1999.
F-22
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, 1996 18.7 35.2 50.0 27.4 131.3 96.4 227.7
Revisions of previous estimates 1.6 (.4) 6.1 6.6 13.9 10.5 24.4
Improved recovery - .5 - - .5 - .5
Purchases .2 2.1 - - 2.3 - 2.3
Extensions and discoveries 2.5 18.8 6.2 - 27.5 - 27.5
Production (3.9) (5.8) (5.0) (2.9) (17.6) (3.4) (21.0)
Sales - (1.3) - - (1.3) - (1.3)
------ ----- ---- ----- ----- ----- ------
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
====== ===== ==== ===== ===== ===== =====
PROVED DEVELOPED
December 31, 1996 16.3 21.4 16.8 10.1 64.6 66.9 131.5
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
SCHEDULE 2 - ESTIMATED NET PROVED NATURAL GAS RESERVES
United United
(Billions of cubic feet) States Canada Kingdom Total
PROVED ------ ------ ------- -----
December 31, 1996 464.4 151.1 43.9 659.4
Revisions of previous estimates (23.7) (4.9) (2.9) (31.5)
Purchases 11.1 .4 - 11.5
Extensions and discoveries 63.2 17.0 - 80.2
Production (79.4) (16.4) (4.6) (100.4)
Sales (.2) (6.8) - (7.0)
----- ----- ----- ------
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
===== ===== ===== ======
PROVED DEVELOPED
December 31, 1996 291.1 146.0 25.4 462.5
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
F-23
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, 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
====== ===== ==== ===== ===== ===== ==== ======
YEAR ENDED DECEMBER 31, 1997
Property acquisition costs
Unproved $ 20.5 5.9 .2 - - 26.6 - 26.6
Proved 8.2 13.9 .1 - - 22.2 - 22.2
------ ----- ---- ----- ----- ----- ---- ------
Total acquisition costs 28.7 19.8 .3 - - 48.8 - 48.8
Exploration costs 74.4 18.2 14.6 - 28.1 135.3 - 135.3
Development costs 43.9 96.0 76.0 10.4 - 226.3 12.8 239.1
------ ----- ---- ----- ----- ----- ---- ------
Total capital expenditures 147.0 134.0 90.9 10.4 28.1 410.4 12.8 423.2
------ ----- ---- ----- ----- ----- ---- ------
Charged to expense
Dry hole expense 30.9 4.5 5.7 - 7.2 48.3 - 48.3
Geophysical and other costs 13.6 7.2 5.2 - 10.0 36.0 - 36.0
------ ----- ---- ----- ----- ----- ---- ------
Total charged to expense 44.5 11.7 10.9 - 17.2 84.3 - 84.3
------ ----- ---- ----- ----- ----- ---- ------
Expenditures capitalized $102.5 122.3 80.0 10.4 10.9 326.1 12.8 338.9
====== ===== ==== ===== ===== ===== ==== ======
F-24
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, 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 5.3 90.9 111.3 37.2 - 244.7 32.0 276.7
Natural gas
Transfer to consolidated operations 1.8 - - - - 1.8 - 1.8
Sales to unaffiliated enterprises 141.4 38.9 7.7 - - 188.0 - 188.0
------ ----- ----- ---- ----- ----- ---- -----
Total oil and gas revenues 197.3 145.7 142.4 37.2 - 522.6 74.8 597.4
Other operating revenues/1/ 4.4 .2 - 2.9 2.0 9.5 - 9.5
------ ----- ----- ---- ----- ----- ---- -----
Total revenues 201.7 145.9 142.4 40.1 2.0 532.1 74.8 606.9
------ ----- ----- ---- ----- ----- ---- -----
Costs and expenses
Production costs 35.6 39.7 30.8 9.4 - 115.5 36.5 152.0
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 43.2 42.8 8.0 .1 159.2 7.1 166.3
Selling and general expenses 13.5 5.6 3.2 .1 1.1 23.5 - 23.5
------ ----- ----- ---- ----- ----- ---- -----
Total costs and expenses 156.1 105.3 80.7 17.5 9.2 368.8 43.6 412.4
------ ----- ----- ---- ----- ----- ---- -----
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/2/ $ 35.3 26.3 37.2 22.6 (7.7) 113.7 20.7 134.4
====== ===== ===== ==== ===== ===== ==== =====
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 3.2 48.3 58.0 19.1 - 128.6 17.6 146.2
Natural gas
Sales to unaffiliated enterprises 132.1 24.0 10.0 - - 166.1 - 166.1
------ ----- ----- ---- ----- ----- ---- -----
Total oil and gas revenues 167.7 79.4 80.3 19.1 - 346.5 53.0 399.5
Other operating revenues/3/ 11.4 2.7 14.8 2.2 2.7 33.8 (.1) 33.7
------ ----- ----- ---- ----- ----- ---- -----
Total revenues 179.1 82.1 95.1 21.3 2.7 380.3 52.9 433.2
------ ----- ----- ---- ----- ----- ---- -----
Costs and expenses
Production costs 43.6 34.3 35.7 7.0 - 120.6 34.5 155.1
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 37.8 42.9 10.2 - 156.9 6.2 163.1
Impairment of long-lived assets 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 178.5 113.0 110.0 17.3 37.7 456.5 40.8 497.3
------ ----- ----- ---- ----- ----- ---- -----
.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 a gain of $3.3 from recovery on a 1996 contract modification in
Ecuador.
/2/Excludes corporate overhead and interest.
/3/Includes pretax gains of $4 from settlement of a U.K. long-term sales
contract and $2.4 from recovery on a 1996 contract modification in Ecuador.
F-25
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, 1997 ------ ------ ------- ------- ----- -------- ------ -----
Revenues
Crude oil and natural gas liquids
Transfers to consolidated operations $ 64.1 13.7 - - - 77.8 46.8 124.6
Sales to unaffiliated enterprises 10.8 57.9 95.3 34.7 - 198.7 21.1 219.8
Natural gas
Sales to unaffiliated enterprises 196.7 22.1 12.2 - - 231.0 - 231.0
------ ----- ----- ---- ----- ----- ---- -----
Total oil and gas revenues 271.6 93.7 107.5 34.7 - 507.5 67.9 575.4
Other operating revenues/1/ 3.2 24.0 14.1 1.3 2.5 45.1 - 45.1
------ ----- ----- ---- ----- ----- ---- -----
Total revenues 274.8 117.7 121.6 36.0 2.5 552.6 67.9 620.5
------ ----- ----- ---- ----- ----- ---- -----
Costs and expenses
Production costs 43.5 39.2 32.5 11.0 - 126.2 38.6 164.8
Exploration costs charged to expense 44.5 11.7 10.9 - 17.2 84.3 - 84.3
Undeveloped lease amortization 6.7 3.6 .1 - .1 10.5 - 10.5
Depreciation, depletion and amortization 79.4 31.4 43.7 11.4 - 165.9 6.5 172.4
Impairment of long-lived assets 7.7 20.4 - - - 28.1 - 28.1
Selling and general expenses 14.3 5.2 2.7 .2 1.4 23.8 .1 23.9
------ ----- ----- ---- ----- ----- ---- -----
Total costs and expenses 196.1 111.5 89.9 22.6 18.7 438.8 45.2 484.0
------ ----- ----- ---- ----- ----- ---- -----
78.7 6.2 31.7 13.4 (16.2) 113.8 22.7 136.5
Income tax expense (benefit) 27.2 1.4 15.4 (1.1) .1 43.0 8.4 51.4
------ ----- ----- ---- ----- ----- ---- -----
Results of operations/2/ $ 51.5 4.8 16.3 14.5 (16.3) 70.8 14.3 85.1
====== ===== ===== ==== ===== ===== ==== =====
/1/Includes pretax gains of $20.7 from sale of Canadian properties and $1.6 from
recovery on a 1996 contract modification 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, 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/ (1,182.0) (370.0) (609.1) (153.1) - (2,314.2) (31.2) (2,345.4)
--------- -------- ------ ------ ------- -------- ------ --------
Net capitalized costs $ 328.8 548.2/2/ 232.4 53.5 - 1,162.9 145.5 1,308.4
========= ======== ====== ====== ======= ======== ====== ========
DECEMBER 31, 1998
Unproved oil and gas properties $ 102.4 31.8 1.3 - 20.3 155.8 - 155.8
Proved oil and gas properties 1,536.1 755.5 836.0 199.5 - 3,327.1 140.8 3,467.9
--------- -------- ------ ------ ------- -------- ------ --------
Gross capitalized costs 1,638.5 787.3 837.3 199.5 20.3 3,482.9 140.8 3,623.7
Accumulated depreciation,
depletion and amortization
Unproved oil and gas properties (50.7) (18.2) (1.0) - (19.1) (89.0) - (89.0)
Proved oil and gas properties/1/ (1,250.4) (317.8) (585.6) (145.1) - (2,298.9) (23.1) (2,322.0)
--------- -------- ------ ------ ------- -------- ------ --------
Net capitalized costs $ 337.4 451.3/2/ 250.7 54.4 1.2 1,095.0 117.7 1,212.7
========= ======== ====== ====== ======= ======== ====== ========
/1/Does not include reserve for dismantlement costs of $158.4 in 1999 and $154.7
in 1998.
/2/Includes net costs of $365.2 in 1999 and $276.3 in 1998 related to the
Hibernia and Terra Nova oil fields.
F-26
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, 1999 ------ ------- ------- ------- -----
Future cash inflows $1,745.5 1,417.9 1,426.4 645.3 5,235.1
Future development costs (210.6) (90.1) (66.0) (48.1) (414.8)
Future production and abandonment costs (409.9) (339.3) (417.4) (184.5) (1,351.1)
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
======== ======= ======= ======= ========
DECEMBER 31, 1998
Future cash inflows $1,120.5 647.6 667.2 167.2 2,602.5
Future development costs (182.7) (177.5) (64.6) (14.9) (439.7)
Future production and abandonment costs (361.1) (269.9) (372.6) (93.9) (1,097.5)
Future income taxes (139.0) (28.3) (23.6) (.6) (191.5)
-------- ------- ------- ------- --------
Future net cash flows 437.7 171.9 206.4 57.8 873.8
10% annual discount for estimated timing of
cash flows (138.1) (74.3) (56.4) (23.1) (291.9)
-------- ------- ------- ------- --------
Standardized measure of discounted future
net cash flows $ 299.6 97.6 150.0 34.7 581.9
======== ======= ======= ======= ========
*Excludes future net cash flows from synthetic oil of $410.2 at December 31,
1999 and $64.1 at December 31, 1998.
Following are the principal sources of change in the standardized measure of
discounted future net cash flows for the years shown.
(Millions of dollars) 1999 1998 1997
-------- ------ --------
Net changes in prices, production costs and development costs $1,188.2 (894.8) (1,437.3)
Sales and transfers of oil and gas produced, net of production costs (317.9) (132.3) (230.8)
Net change due to extensions and discoveries 250.0 125.4 278.6
Net change due to purchases and sales of proved reserves (2.0) 4.5 17.4
Development costs incurred 163.4 165.4 214.2
Accretion of discount 71.9 129.0 217.6
Revisions of previous quantity estimates 220.7 30.7 55.0
Net change in income taxes (505.2) 191.0 327.3
-------- ------ --------
Net increase (decrease) 1,069.1 (381.1) (558.0)
Standardized measure at January 1 581.9 963.0 1,521.0
-------- ------ --------
Standardized measure at December 31 $1,651.0 581.9 963.0
======== ====== ========
F-27
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, 1999/1/
Sales and other operating revenues $ 302.9 449.9 632.4 651.6 2,036.8
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 5/8 50 15/16 54 5/8 61 9/16 61 9/16
Low 32 7/8 41 3/8 47 11/16 51 1/4 32 7/8
YEAR ENDED DECEMBER 31, 1998/1/
Sales and other operating revenues $ 439.8 447.8 432.2 374.7 1,694.5
Income (loss) before income taxes 24.8 36.9 15.4 (85.4) (8.3)
Net income (loss) 15.5 22.2 9.0 (61.1) (14.4)
Net income (loss) per Common share - basic .35 .49 .20 (1.36) (.32)
Net income (loss) per Common share - diluted .35 .49 .20 (1.36) (.32)
Cash dividends per Common share .35 .35 .35 .35 1.40
Market Price of Common Stock/2/
High 54 7/16 53 11/16 51 15/16 42 5/16 54 7/16
Low 47 7/16 48 1/8 34 1/2 36 3/16 34 1/2
/1/The effect of special gains (losses) on quarterly net income are reviewed in
Management's Discussion and Analysis of Financial Condition and Results of
Operations on pages 12 and 13 of this Form 10-K report. Quarterly totals, in
millions of dollars, and the effect per Common share of these special items
are shown in the following table.
First Second Third Fourth
Quarter Quarter Quarter Quarter Year
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
1998
----
Quarterly totals $ - 4.2 - (62.1) (57.9)
Per Common share - basic - .09 - (1.38) (1.29)
Per Common share - diluted - .09 - (1.38) (1.29)
/2/Prices are as quoted on the New York Stock Exchange.
F-28