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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, 1998
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _________________ to __________
Commission file number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 71-0361522
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number)
200 PEACH STREET, P. O. BOX 7000, EL DORADO, ARKANSAS 71731-7000
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (870) 862-6411
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
COMMON STOCK, $1.00 PAR VALUE NEW YORK STOCK EXCHANGE
THE TORONTO STOCK EXCHANGE
SERIES A PARTICIPATING CUMULATIVE NEW YORK STOCK EXCHANGE
PREFERRED STOCK PURCHASE RIGHTS THE TORONTO STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months, and (2) has been subject to such filing requirements
for the past 90 days. Yes X No ___.
---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [_]
Aggregate market value of the voting stock held by non-affiliates of the
registrant, based on average price at January 29, 1999, as quoted by the New
York Stock Exchange, was approximately $1,220,526,000.
Number of shares of Common Stock, $1.00 Par Value, outstanding at January 29,
1999, was 44,952,042.
Documents incorporated by reference:
Portions of the Registrant's definitive Proxy Statement relating to the Annual
Meeting of Stockholders on May 12, 1999, have been incorporated by reference in
Part III herein.
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MURPHY OIL CORPORATION
TABLE OF CONTENTS - 1998 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 6
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 7
Item 6. Selected Financial Data 7
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations 8
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 19
Item 8. Financial Statements and Supplementary Data 19
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure 19
PART III
Item 10. Directors and Executive Officers of the Registrant 20
Item 11. Executive Compensation 20
Item 12. Security Ownership of Certain Beneficial Owners and Management 20
Item 13. Certain Relationships and Related Transactions 20
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 21
Exhibit Index 21
Signatures 23
i
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
SUMMARY
Murphy Oil Corporation is a worldwide oil and gas exploration and production
company with refining and marketing operations in the United States and the
United Kingdom and pipeline and crude oil 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 1998 Annual Report to Security Holders (1998
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
relative to Murphy's operations, properties and business segments, including
revenues by class of products and financial information by geographic area, are
described on pages 7, F-8, F-19 through F-21, F-24 through F-26, and F-28 of
this Form 10-K report and on pages 6 through 19 of the 1998 Annual Report.
EXPLORATION AND PRODUCTION
During 1998, 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 1998 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 extracts
synthetic crude oil from oil sand deposits in northern Alberta. Subsidiaries of
Murphy Expro conducted exploration activities in various other areas including
the Falkland Islands, China, Ireland, the Faroe Islands, Spain, Philippines,
Peru and Pakistan.
Murphy's estimated net quantities of proved oil and gas reserves and proved
developed oil and gas reserves at December 31, 1995, 1996, 1997 and 1998 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.
1
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, 1998, are shown on page 21 of the 1998 Annual Report.
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, 1998, 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 5 3 39 20 44 23
- Gulf of Mexico 832 482 369 136 1,201 618
- Frontier 117 40 -- -- 117 40
------ ------ ----- --- ------ ------
Total United States 954 525 408 156 1,362 681
------ ------ ----- --- ------ ------
Canada - Onshore 813 582 1,084 155 1,897 737
- Offshore 941 178 5 -- 946 178
- Oil sands 225 54 13 4 238 58
------ ------ ----- --- ------ ------
Total Canada 1,979 814 1,102 159 3,081 973
------ ------ ----- --- ------ ------
United Kingdom 1,439 461 78 11 1,517 472
Ecuador -- -- 494 99 494 99
China 563 253 -- -- 563 253
Falkland Islands 401 100 -- -- 401 100
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 434 136 -- -- 434 136
Tunisia 109 36 -- -- 109 36
------ ------ ----- --- ------ ------
Total 20,763 14,619 2,082 425 22,845 15,044
====== ====== ===== === ====== ======
Oil and gas wells producing or capable of producing at December 31, 1998, are
summarized in the following table. Gross wells are those in which all or part of
the working interest is owned by Murphy. Net wells are the portions of the gross
wells applicable to Murphy's working interest.
OIL WELLS GAS WELLS
-------------------- --------------------
COUNTRY GROSS NET GROSS NET
- - ------- ----- ------ ----- ------
United States 323 143.5 272 106.7
Canada 4,173 827.0 815 286.0
United Kingdom 98 12.3 21 1.5
Ecuador 53 10.6 -- --
----- ----- ----- -----
Total 4,647 993.4 1,108 394.2
===== ===== ===== =====
Wells included above with multiple
completions and counted as one well each 87 41.1 90 64.7
2
Murphy's net wells drilled in the last three years are summarized 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
------- --- ------- --- ------- --- ------- --- ------- --- ------- ---
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
1996
- - ----
Exploratory 13.8 3.9 5.3 4.0 -- 1.1 -- -- .4 -- 19.5 9.0
Development 4.6 -- 70.2 2.5 1.0 .1 2.2 -- -- -- 78.0 2.6
Murphy's drilling wells in progress at December 31, 1998, are summarized below.
EXPLORATORY DEVELOPMENT TOTAL
---------------- -------------- ----------------
COUNTRY GROSS NET GROSS NET GROSS NET
- - ------- ----- --- ----- --- ----- ---
United States 2 .8 1 -- 3 .8
Canada 1 .5 2 .2 3 .7
United Kingdom - - 3 .3 3 .3
Ecuador - - 1 .2 1 .2
-- --- -- --- -- ---
Total 3 1.3 7 .7 10 2.0
== === == === == ===
Additional information about current exploration and production activities is
reported on pages 1 through 15 of the 1998 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, 1998,
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 2,250 4,250
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.
Murphy distributes refined products from 59 terminal locations in the United
States to retail and wholesale accounts in the United States (by MOUSA) and in
Canada (by a MOCL subsidiary) under the brand names SPUR(R) and Murphy USA(R)
and to unbranded wholesale accounts. Eleven of these terminals are wholly owned
and operated by MOUSA, 16 are jointly owned and operated by others, and the
remaining 32 are 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 in exchange for deliveries
from the Company's wholly owned and jointly owned terminals. At the end of 1998,
refined products were marketed at wholesale or retail through 552 branded
stations in 17 states in the Southeast and Upper Midwest and eight branded
stations in the Thunder Bay area of Ontario, Canada.
At the end of 1998, 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 wholly owned terminals, and 389 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 Murphy's marketing area in 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 Inc., which provides deepwater unloading
accommodations off the Louisiana coast for oil tankers and onshore facilities
for storage of crude oil. In addition, Murphy owns 29.4% of a 22-mile crude oil
pipeline, with a capacity of 300,000 barrels a day, that connects LOOP storage
at Clovelly, Louisiana and Alliance, Louisiana and 100% of a 24-mile crude oil
pipeline, with a capacity of 200,000 barrels a day, that connects Alliance to
the Meraux refinery. The pipeline from Alliance to Meraux is also connected to
another company's pipeline system, allowing crude oil transported by that system
to be shipped to the Meraux refinery.
4
At December 31, 1998, 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 (idle) 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, 1998, are reported on pages 2, 3,
5, 16 through 19, and 22 of the 1998 Annual Report.
EMPLOYEES
Murphy had 1,566 full-time and part-time employees at December 31, 1998.
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 occasionally purchases refined
products and may therefore be required to respond to operating and pricing
policies of others, including producing country governments from whom it makes
purchases. Additional information concerning current conditions of the Company's
business is reported under the caption "Outlook" on page 18 of this Form 10-K
report.
The operations and earnings of Murphy have been and continue to be affected by
worldwide political developments. Many governments, including those that are
members of the Organization of Petroleum Exporting Countries (OPEC),
unilaterally intervene at times in the orderly market of crude oil and natural
gas produced in their countries through such actions as setting prices,
determining rates of production, and controlling who may buy and sell the
production. In addition, prices and availability of crude oil, natural gas and
refined products could be influenced by political unrest and by various
governmental policies to restrict or increase petroleum usage and supply. Other
governmental actions that could affect Murphy's operations and earnings include
tax changes and regulations concerning: currency fluctuations, protection and
remediation of the environment (See the caption "Environmental" on page 15 of
this Form 10-K report), preferential and discriminatory awarding of oil and gas
leases, restraints and controls on imports and exports, safety, and
relationships between employers and employees. Because these and other factors
too numerous to list are subject to constant changes dictated 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 policy is to insure against known risks when insurance is available at
costs and terms Murphy considers reasonable. Certain existing risks are insured
by Murphy only through Oil Insurance Limited (OIL), which is operated as a
mutual insurance company by certain participating oil companies including
Murphy. OIL was organized to insure against risks for which commercial insurance
is unavailable or for which the cost of commercial insurance is prohibitive.
5
EXECUTIVE OFFICERS OF THE REGISTRANT
The age at January 1, 1999, 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 41; Chairman of the Board since October 1994. Mr.
Murphy had been Executive Vice President and Chief Financial and
Administrative Officer, Director and Member of the Executive Committee
since 1993. Prior to that, he was Executive Vice President and Chief
Financial Officer from 1992 to 1993; Vice President, Planning/Treasury,
from 1991 to 1992; and Vice President, Planning, from 1988 to 1991, with
additional duties as Treasurer from 1990 until August 1991.
Claiborne P. Deming - Age 44; President and Chief Executive Officer since
October 1994 and Director and Member of the Executive Committee since
1993. In 1992, he became Executive Vice President and Chief Operating
Officer. Mr. Deming was President of MOUSA from 1989 to 1992.
Steven A. Cosse' - Age 51; 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 64; 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 47; Vice President since May 1995, when he joined
the Company. Prior to that, he had held various engineering, planning
and managerial positions, most recently with an engineering consulting
firm.
Odie F. Vaughan - Age 62; Treasurer since August 1991. From 1975 through
July 1991, he was with ODECO as Vice President of Taxes and Treasurer.
Ronald W. Herman - Age 61; Controller since August 1991. He was Controller
of ODECO from 1977 through July 1991.
Walter K. Compton - Age 36; 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
Company received from the U.S. Environmental Protection Agency notices of
violations of the Clean Air Act. Although the penalty amounts were not listed,
the statutes involved provide for rates up to $27,500 per day of violation, and
penalties therefore could exceed $100,000. The Company believes it has valid
defenses to the alleged violations and plans a vigorous defense. While the
notices of violation are preliminary in nature and no assurances can be given,
the Company does not believe that the ultimate resolution of the matter will
have a material adverse effect on the financial condition of the Company.
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.
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 1998.
6
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock is listed on the New York Stock Exchange and The
Toronto Stock Exchange using "MUR" as the trading symbol. There were 3,684
stockholders of record as of December 31, 1998. Information as to high and low
market prices per share and dividends per share by quarter for 1998 and 1997 are
reported on page F-28 of this Form 10-K report.
Item 6. SELECTED FINANCIAL DATA
(THOUSANDS OF DOLLARS EXCEPT PER SHARE DATA) 1998 1997 1996 1995 1994
---- ---- ---- ---- ----
RESULTS OF OPERATIONS FOR THE YEAR/1/
Sales and other operating revenues/2/ $1,694,470 2,133,387 2,009,736 1,613,848 1,582,091
Net cash provided by continuing operations 321,091 401,843 472,480 309,878 312,251
Income (loss) from continuing operations (14,394) 132,406 125,956 (127,919) 89,347
Net income (loss) (14,394) 132,406 137,855 (118,612) 106,628
Per Common share - diluted
Income (loss) from continuing operations (.32) 2.94 2.80 (2.85) 1.99
Net income (loss) (.32) 2.94 3.07 (2.65) 2.38
Cash dividends per Common share 1.40 1.35 1.30 1.30 1.30
Percentage return on
Average stockholders' equity (1.3) 12.7 12.2 (9.3) 8.6
Average borrowed and invested capital (.6) 10.4 10.4 (7.9) 8.0
Average total assets (.6) 6.0 6.2 (5.2) 4.8
CAPITAL EXPENDITURES FOR THE YEAR
Exploration and production $ 331,647 423,181 373,984 231,718 286,348
Refining, marketing and transportation 55,025 37,483 42,880 53,602 94,697
Corporate and other 2,127 7,367 1,192 1,831 4,876
---------- --------- --------- --------- ---------
$ 388,799 468,031 418,056 287,151 385,921
========== ========= ========= ========= =========
FINANCIAL CONDITION AT DECEMBER 31
Current ratio 1.15 1.10 1.10 1.22 1.14
Working capital $ 56,616 48,333 56,128 87,388 61,750
Net property, plant and equipment 1,662,362 1,655,838 1,556,830 1,377,455 1,558,716
Total assets 2,164,419 2,238,319 2,243,786 2,098,466 2,297,459
Long-term debt 333,473 205,853 201,828 193,146 172,289
Stockholders' equity 978,233 1,079,351 1,027,478/3/ 1,101,145 1,270,679
Per share 21.76 24.04 22.90 24.56 28.34
Long-term debt - percent of capital employed 25.4 16.0 16.4 14.9 11.9
/1/Includes effects on income of special items in 1998, 1997 and 1996 that are
detailed in Management's Discussion and Analysis of Financial Condition and
Results of Operations. Also, special items in 1995 and 1994 increased
(decreased) net income by $(152,066), $(3.39) a diluted share, and $20,236,
$.45 a diluted share, respectively.
/2/Amounts prior to 1998 have been restated to conform to 1998 presentation.
/3/Reflects $172,561 charge for distribution of common stock of Deltic Timber
Corporation to stockholders.
7
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
The Company reported a net loss in 1998 of $14.4 million, $.32 a diluted share,
compared to net income in 1997 of $132.4 million, $2.94 a diluted share. In
1996, the Company earned $137.9 million, $3.07 a diluted share. Results of
operations for the three years ended December 31, 1998, included certain special
items that resulted in a net charge of $57.9 million, $1.29 a diluted share, in
1998; a net benefit of $.1 million, with no per share effect, in 1997; and a net
benefit of $22.2 million, $.49 a diluted share, in 1996. 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. Net income for 1996 included earnings from
discontinued operations of $11.9 million, $.27 a diluted share. This amount was
attributable to the activities of the Company's farm, timber and real estate
subsidiary, which was spun off to the Company's shareholders on December 31,
1996, as described in Note B to the consolidated financial statements.
1998 vs. 1997 - Excluding special items, income from continuing operations
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
production 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 activities, which
includes interest income and expense and corporate overhead not allocated to
operating functions, increased $2.1 million in 1998 compared to 1997, primarily
due to higher net interest costs offset in part by lower costs of awards under
the Company's incentive plans.
1997 vs. 1996 - Excluding special items, income from continuing operations in
1997 totaled $132.3 million, $2.94 a diluted share. The results for 1997
represented a $28.5 million improvement compared to income from continuing
operations of $103.8 million, $2.31 a diluted share, in 1996. Earnings from the
Company's exploration and production operations declined $16.8 million in 1997,
primarily due to higher exploration costs. Increases in crude oil production and
natural gas sales led to record hydrocarbon production in 1997 of 102,272
barrels a day on an energy equivalent basis. However, lower worldwide crude oil
sales prices nearly offset the benefit of higher production volumes. Income from
the Company's refining, marketing and transportation segment was up $42.6
million in 1997. The improvement occurred primarily in the United States, where
the effects of lower costs for crude oil and other feedstocks exceeded the
decline in sales realizations for the Company's finished products. An improved
onstream rate helped the Company's U.S. refineries achieve a record level of
crude oil throughputs in 1997. Sales of finished products in the United States
were also higher during 1997. The cost of corporate activities decreased $2.7
million in 1997 compared to 1996, primarily due to lower costs of awards under
the Company's incentive plans.
In the following table, the Company's results of operations for the three years
ended December 31, 1998, 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) 1998 1997 1996
---- ---- ----
Exploration and production
United States $ 20.1 56.5 50.4
Canada 2.6 18.8 27.6
United Kingdom .7 13.1 14.7
Ecuador 2.4 12.9 13.8
Other (20.0) (16.3) (4.7)
-------- ------ -----
5.8 85.0 101.8
-------- ------ -----
Refining, marketing and transportation
United States 27.7 41.3 1.8
United Kingdom 16.8 9.2 6.2
Canada 4.7 6.2 6.1
-------- ------ ------
49.2 56.7 14.1
-------- ------ ------
Corporate (11.5) (9.4) (12.1)
Income from continuing operations before -------- ------ ------
special items 43.5 132.3 103.8
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) -- --
Modification of U.K. long-term sales contract 2.8 -- --
Gain on sale of assets 2.9 11.5 17.7
Net recovery (loss) pertaining to 1996 modifications of
foreign crude oil contracts 2.4 1.6 (.6)
Refund and settlement of income tax matters -- 3.2 5.1
------- ----- -----
Income (loss) from continuing operations (14.4) 132.4 126.0
Income from discontinued operations -- -- 11.9
------- ----- -----
Net income (loss) $ (14.4) 132.4 137.9
======= ===== =====
EXPLORATION AND PRODUCTION - Earnings from exploration and production operations
before special items were $5.8 million in 1998, $85 million in 1997 and $101.8
million in 1996. The decline in 1998 was primarily due to lower worldwide crude
oil sales prices, which averaged $10.81 a barrel in 1998 compared to $16.43 in
1997. Lower U.S. natural gas sales prices and volumes also contributed to the
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, were 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. In 1997, a $24.6 million increase in
exploration costs, primarily in the U.S. Gulf of Mexico and Bohai Bay, China,
accounted for the decline in earnings. While crude oil production increased 8%
and natural gas sales increased 22% in 1997, these favorable production volumes
were mostly offset by a 13% decline in the average worldwide crude oil sales
price.
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 1998 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) 1998 1997 1996
---- ---- ----
United States
Crude oil $ 35.6 74.9 86.1
Natural gas 132.1 196.7 147.1
Canada
Crude oil 55.4 71.6 81.6
Natural gas 24.0 22.1 17.3
Synthetic oil 53.0 67.9 63.3
United Kingdom
Crude oil 70.3 95.3 102.1
Natural gas 10.0 12.2 14.4
Ecuador - crude oil 19.1 34.7 35.0
Spain - natural gas - - 7.8
------ ----- -----
Total oil and gas revenues $399.5 575.4 554.7
====== ===== =====
The Company's crude oil and gas liquids production averaged 59,128 barrels a day
in 1998, 57,494 in 1997 and 53,210 in 1996. Crude oil and liquids production in
the United States declined 28% in 1998, with the reduction primarily due to
declining production at mature oil fields in the Gulf of Mexico. In 1997, U.S.
production was down 8% from 1996, primarily due to the sale of onshore producing
properties effective July 1, 1996. For the second straight year, production in
Canada rose 12%, and in 1998 established a record of 28,199 barrels a day. As a
result of the selective shut-in, production of heavy oil in Canada decreased 16%
in 1998 compared to a 19% increase in 1997. The Company's net interest in
production of synthetic oil in Canada increased 12% in 1998, after a 14%
increase in 1997. The increase in net synthetic oil production in 1998 was due
to a 1% increase in gross production and a decrease in the net profits royalty
rate as a result of lower oil prices. The increase in net production in 1997 was
due to a 3% increase in gross production and a decrease in the net profits
royalty rate. Before royalties, the Company's synthetic oil production was
10,501 barrels a day in 1998, 10,371 in 1997 and 10,036 in 1996. The Company's
Hibernia field, on stream for all of 1998, produced 4,192 barrels a day in 1998
compared to 224 in 1997 after production commenced in the fourth quarter. The
Company's U.K. oil production increased 11% in 1998 after a 5% increase in 1997.
Oil production from the Mungo/Monan and Schiehallion fields commenced in the
third quarter of 1998 and averaged 2,025 and 1,219 barrels a day, respectively.
Production from the "T" Block field in the United Kingdom declined by 18% during
1998. A full year of production from the Thelma field contributed to an 11%
increase in "T" Block production in 1997. Production from Ninian, the Company's
other major North Sea oil field, declined 8% in 1998 after having declined 3% in
1997. Production in Ecuador was essentially unchanged in 1998 after a 30%
increase in 1997. The 1997 increase resulted from new fields being placed on
stream throughout 1996.
Worldwide sales of natural gas averaged 230.9 million cubic feet a day in 1998,
268.7 million in 1997 and 220.6 million in 1996. A 20% decline in U.S. natural
gas sales in 1998 was mainly due to reduced deliverability in certain of the
Company's maturing Gulf of Mexico fields. Sales of natural gas in the United
States increased 36% in 1997 as a number of new fields came on stream in the
Gulf of Mexico. Natural gas sales in Canada in 1998 were at record levels for
the third straight year, as sales increased 9% in 1998 following a 4% increase
in 1997. Natural gas sales in the United Kingdom were down 2% in 1998, compared
to a 17% decrease in 1997. Production of natural gas in Spain ceased at the end
of 1996.
As previously indicated, worldwide crude oil sales prices weakened considerably
throughout 1998. The declining 1998 sales prices followed a previous softening
of prices in 1997 as compared to 1996 prices. In the United States, Murphy's
1998 average monthly sales prices for crude oil and condensate ranged from $9.65
to $15.66 a barrel, and averaged $12.76 for the year, 34% below the average 1997
price. In Canada, the average sales price for light oil was $12.03 a barrel in
1998, a decline of 32%. Heavy oil prices in Canada averaged $6.56 a barrel, down
39% from 1997. The average sales price for synthetic oil in 1998 was $13.73 a
barrel, off 31% from a year earlier. The sales price for crude oil from the
Hibernia field averaged $10.49 a barrel, down 31%. Sales prices in the United
Kingdom were down 34% in 1998 and averaged $12.52 a barrel. Sales prices in
Ecuador averaged $6.76 a barrel in 1998, down 44% compared to a year ago. U.S.
oil prices decreased 4% in 1997 compared to 1996 and averaged $19.43 a barrel
for the year. In Canada, crude oil prices in 1997 declined 11% for light oil,
25% for heavy oil and 6% for synthetic oil. Sales prices in the United Kingdom
were down 10% in 1997 and prices in Ecuador were down 24%. Worldwide crude oil
prices began to decline in the fourth quarter of 1997, and the downward trend
continued throughout 1998. Oil prices remain under extreme pressure in early
1999.
10
Average monthly natural gas sales prices in the United States ranged from $1.73
to $2.51 an MCF during 1998. For the year, U.S. sales prices averaged $2.18 an
MCF compared to $2.57 a year ago. The average price for natural gas sold in
Canada during 1998 was $1.34 an MCF, essentially unchanged from the prior year,
while prices in the United Kingdom declined 16% to $2.23. The decline in average
U.K. sales prices primarily resulted from a modification of a long-term sales
contract effective October 1, 1998. Average U.S. natural gas sales prices in
1997 were essentially unchanged compared to 1996; prices were up in Canada and
the United Kingdom by 23% and 3%, respectively, during the same period. U.S.
natural gas sales prices have declined sharply in early 1999.
Based on 1998 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 $14.4 million and $5.3 million, respectively. The effect
of these price fluctuations on consolidated net income cannot be measured
because operating results of the Company's refining, marketing and
transportation segments could be affected differently.
Production costs were $155.1 million in 1998, $164.8 million in 1997 and $160.5
million in 1996. 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) 1998 1997 1996
---- ---- ----
United States $ 3.32 2.59 3.31
Canada
Excluding synthetic oil 3.64 4.63 3.95
Synthetic oil 8.99 11.32 12.72
United Kingdom 5.60 5.58 6.00
Ecuador 2.48 3.87 4.96
Worldwide - excluding synthetic oil 3.79 3.72 4.09
The increase in U.S. production 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 Canadian synthetic oil unit rate was due to lower maintenance
costs, a decrease in royalty barrels due to a lower sales price 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. The decrease in
the U.S. cost per equivalent barrel in 1997 was attributable to the sale of
high-cost onshore producing properties in 1996. The 1997 increase in Canada,
excluding synthetic oil, was due to an increase in heavy oil production compared
to light oil and to higher costs associated with an expansion of heavy oil
thermal recovery projects. The decrease in the cost for synthetic oil in 1997
was due to higher gross production volumes and a decrease in royalty barrels
caused by lower sales prices. Based on synthetic oil production before
royalties, costs per barrel declined 2% in 1997. A lower unit cost in the United
Kingdom in 1997 was due to a favorable impact from higher production at "T"
Block.
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) 1998 1997 1996
---- ---- ----
Included in capital expenditures
Dry hole costs $ 31.5 48.3 28.5
Geological and geophysical costs 17.0 26.4 24.1
Other costs 6.6 9.6 7.9
------ ---- ----
55.1 84.3 60.5
Undeveloped lease amortization 10.5 10.5 9.7
------ ---- ----
Total exploration expenses $ 65.6 94.8 70.2
====== ==== ====
Depreciation, depletion and amortization for exploration and production
operations totaled $163.1 million in 1998, $172.4 million in 1997 and $147.6
million in 1996. The decrease in 1998 was primarily attributable to lower
worldwide hydrocarbon production, while the increase in 1997 was mainly due to
higher worldwide production.
11
REFINING, MARKETING AND TRANSPORTATION - Earnings from refining, marketing and
transportation operations before special items were $49.2 million in 1998, $56.7
million in 1997 and $14.1 million in 1996. Operations in the United States
earned $27.7 million in 1998 compared to $41.3 million in 1997, as average
product sales realizations declined more than costs of crude oil and other
refinery feedstocks. U.S. operations earned $1.8 million in 1996. Crude oil swap
agreements increased earnings by $5 million in 1997 and $9.2 million in 1996.
U.K. operations earned $16.8 million before special items in 1998, $9.2 million
in 1997 and $6.2 million in 1996. The improvement in the United Kingdom in 1998
was caused by a larger decline for refining feedstock costs than for sales
prices of finished products, coupled with higher finished product sales volumes.
Canadian operations contributed $4.7 million to 1998 earnings compared to $6.2
million in 1997 and $6.1 million in 1996.
Unit margins (sales realizations less costs of crude oil, other feedstocks,
refining and transportation to point of sale) averaged $1.47 a barrel in the
United States in 1998, $1.79 in 1997 and $.27 in 1996. U.S. product sales were
up 3% in 1998 following a 5% increase in 1997. U.S. margins came under pressure
during the second half of 1998, at which time unit margins retreated
substantially. U.S. margins improved considerably in 1997 after being under
pressure throughout 1996. Unit margins were very weak in early 1999 and the
Company was experiencing losses in its U.S. downstream operations.
Unit margins in the United Kingdom averaged $2.81 a barrel in 1998, $2.90 in
1997 and $2.08 in 1996. Sales of petroleum products were up 25% in 1998
following a 14% decline in 1997. Sales in both terminal and cargo markets
increased in 1998. Cargo sales in 1997 were adversely affected by a turnaround
at the Milford Haven refinery early in the year. Although margins remained
relatively strong in 1998, the Company's branded outlets still face stiff
competition from supermarket sales of motor fuels. Sharp declines in unit
margins in the United Kingdom in early 1999 have led to losses in these
operations.
Based on sales volumes for 1998 and deducting taxes at marginal rates, each $.42
a barrel ($.01 a gallon) fluctuation in unit margins would have affected annual
refining and marketing profits by $17 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 1998 was down $1.5 million 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. Income in 1997 was virtually
unchanged from 1996 as higher pipeline throughputs and better margins on crude
oil trucking operations were offset by lower crude trading margins.
SPECIAL ITEMS - Net income for the last three years included the special items
reviewed below; the quarter in which each item occurred is indicated. The
effects of special items on quarterly results for 1998 and 1997 are presented on
page F-28 of this Form 10-K report.
. 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 C to the consolidated financial statements).
. Charge resulting from cancellation of a drilling rig contract - An after-tax
charge of $4.2 million was recorded in the fourth quarter of 1998 resulting
from cancellation of a drilling rig contract for the Terra Nova oil field,
offshore eastern Canada. The contract was cancelled because management
believes that current market conditions will allow a more efficient and
modern rig to be obtained, 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.
. Modification 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 a modification
of a U.K. long-term sales contract.
12
. Gain on sale of assets - After-tax gains on sale of assets included $2.9
million recorded in the fourth quarter of 1998 from sale of a U.K. service
station, $11.5 million recorded in the fourth quarter of 1997 from sale of a
Canadian heavy oil property, and $17.7 million recorded in the third quarter
of 1996 from sale of 48 onshore producing oil and gas properties in the
United States.
. Net recovery (loss) pertaining to 1996 modifications of foreign crude oil
contracts - Gains of $1.4 million, $1 million and $1.6 million were recorded
in 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 to a crude oil production contract in Ecuador. A
net loss of $.6 million was recorded in the fourth quarter of 1996 resulting
from modifications to contracts related to crude oil production in Ecuador
and Gabon (see Note N to the consolidated financial statements).
. Refund and settlement of income tax matters - A gain of $3.2 million for
refund of U.K. income taxes was recorded in the third quarter of 1997. A
gain of $5.1 million for settlement of income tax matters in Canada was
recorded in the fourth quarter of 1996.
The income (loss) effects of special items for the three years ended December
31, 1998, are summarized by segment in the following table.
(MILLIONS OF DOLLARS) 1998 1997 1996
---- ---- ----
Exploration and production
United States $ (19.4) (4.9) 17.7
Canada (10.1) .2 5.1
United Kingdom (14.0) 3.2 --
Ecuador 2.4 1.6 (8.8)
Other (15.1) -- 8.2
---- ---- ----
(56.2) .1 22.2
---- ---- ----
Refining, marketing and transportation
United Kingdom .5 -- --
Canada (2.2) -- --
---- ---- ----
(1.7) -- --
---- ---- ----
Total income (loss) from special items $ (57.9) .1 22.2
==== ==== ====
CAPITAL EXPENDITURES
As shown in the selected financial data on page 7 of this Form 10-K report,
capital expenditures were $388.8 million in 1998 compared to $468 million in
1997 and $418.1 million in 1996. These amounts included $55.1 million, $84.3
million and $60.5 million of exploration expenditures that were expensed.
Capital expenditures for exploration and production activities totaled $331.6
million in 1998, 85% of the Company's total capital expenditures for the year.
Exploration and production capital expenditures in 1998 included $17 million for
acquisition of undeveloped leases, $4.9 million for acquisition of proved oil
and gas properties, $120.4 million for exploration activities and $189.3 million
for development projects. Development expenditures included $11.2 million and
$41.7 million for the Hibernia and Terra Nova oil fields, respectively, offshore
Newfoundland; $27.1 million and $25.2 million for the Schiehallion and
Mungo/Monan fields, respectively, offshore United Kingdom; and $10.2 million for
oil fields in Ecuador. Exploration and production capital expenditures 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.
Refining, marketing and transportation expenditures, detailed in the following
table, were $55 million in 1998, or 14% of total capital expenditures, compared
to $37.5 million in 1997 and $42.9 million in 1996.
13
(MILLIONS OF DOLLARS) 1998 1997 1996
---- ---- ----
Refining
United States $ 27.0 12.5 13.2
United Kingdom .7 1.5 12.2
------- ---- ----
Total refining 27.7 14.0 25.4
------- ---- ----
Marketing
United States 16.7 14.1 7.5
United Kingdom 6.1 2.2 1.3
------- ---- ----
Total marketing 22.8 16.3 8.8
------- ---- ----
Transportation
United States 1.9 2.6 .3
Canada 2.6 4.6 8.4
------- ---- ----
Total transportation 4.5 7.2 8.7
------- ---- ----
Total $ 55.0 37.5 42.9
======= ==== ====
U.S. 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
motor fuel specifications. Marketing expenditures included the costs of new
stations, primarily on land leased in the United States from Wal-Mart Stores,
and improvements and normal replacements at existing stations and terminals.
CASH FLOWS
Cash provided by continuing operations was $321.1 million in 1998, $401.8
million in 1997 and $472.5 million in 1996. Special items reduced cash flow from
operations by $6.3 million in 1998 and $12.8 million in 1996, but increased cash
by $3.8 million in 1997. Changes in operating working capital other than cash
and cash equivalents required cash of $3.8 million and $72.4 million in 1998 and
1997, respectively, but provided cash of $77.1 million in 1996. Cash provided by
continuing operations was further reduced by expenditures for refinery
turnarounds and abandonment of oil and gas properties totaling $24.6 million in
1998, $14.4 million in 1997 and $10.8 million in 1996.
Cash proceeds from property sales were $9.5 million in 1998, $43.8 million in
1997 and $55.5 million in 1996. Borrowings under long-term notes payable
provided $161.3 million of cash in 1998 and $9.7 million in 1997. Additional
borrowings under nonrecourse debt arrangements provided $6.4 million of cash in
1997 and $23.1 million in 1996.
Capital expenditures required $388.8 million of cash in 1998, $468 million in
1997 and $418.1 million in 1996. Other significant cash outlays during the three
years included $34.5 million in 1998, $17.3 million in 1997 and $11.4 million in
1996 for debt repayment. Cash used for dividends to stockholders was $62.9
million in 1998, $60.6 million in 1997 and $58.3 million in 1996.
FINANCIAL CONDITION
Year-end working capital totaled $56.6 million in 1998, $48.3 million in 1997
and $56.1 million in 1996. The current level of working capital does not fully
reflect the Company's liquidity position, as the carrying values assigned to
inventories under LIFO accounting were $14.7 million below current costs at
December 31, 1998. Cash and equivalents at the end of 1998 totaled $28.3 million
compared to $24.3 million a year ago and $109.7 million at the end of 1996.
Long-term debt increased $127.6 million during 1998 to $333.5 million at the end
of the year, 25.4% of total capital employed, and included $143.8 million of
nonrecourse debt incurred in connection with the acquisition and development of
Hibernia. Long-term debt totaled $205.9 million at the end of 1997 compared to
$201.8 million at December 31, 1996. Stockholders' equity was $1 billion at the
end of 1998 compared to $1.1 billion a year ago and $1 billion at the end of
1996. A summary of transactions in the stockholders' equity accounts is
presented on page F-5 of this Form 10-K report.
The primary sources of the Company's liquidity are internally generated funds,
access to outside financing and working capital. The Company relies on
internally generated funds to finance the major portion of its capital and other
14
expenditures, but maintains lines of credit with banks and borrows as necessary
to meet spending requirements. Current financing arrangements are set forth in
Note D to the consolidated financial statements. The Company does not expect any
problem in meeting future requirements for funds.
The Company had commitments of $209 million for capital projects in progress at
December 31, 1998, including $90 million related to one third of a multiyear
contract for a semisubmersible drilling rig capable of drilling in 6,000 feet of
water. Delivery of the rig is scheduled for 1999.
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, a liability for an environmental
obligation 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 years after a liability is recognized.
The Company's reserve for remedial obligations, which is included in "Deferred
Credits and Other Liabilities" in the Consolidated Balance Sheets, contains
certain amounts that are based on anticipated regulatory approval for proposed
remediation of former refinery waste sites. If regulatory authorities require
more costly alternatives than the proposed processes, future expenditures could
exceed the amount reserved by up to an estimated $3 million.
The Company has received notices from the U.S. Environmental Protection Agency
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 compliance inspection in 1998, Murphy's Superior, Wisconsin refinery
received from the U.S. Environmental Protection Agency notices of violations of
the Clean Air Act. Although the penalty amounts were not listed, the statutes
involved provide for rates up to $27,500 per day of violation. The Company
believes it has valid defenses to the allegations and plans a vigorous defense.
The Company does not believe that this or other known environmental matters will
have a material adverse effect on its financial condition. There is the
possibility that additional expenditures could be required at currently
unidentified sites, and new or revised regulatory requirements could necessitate
additional expenditures at known sites. Such expenditures could 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, 1998.
The Company's refineries also incur costs to handle and dispose of hazardous
wastes and other chemical substances on a recurring basis. These costs are
generally expensed as incurred and amounted to $3.8 million in 1998. In addition
to remediation and other recurring expenditures, Murphy commits a portion of its
capital expenditure program for compliance with environmental laws and
regulations. Such capital expenditures were approximately $26 million in 1998
and are expected to be $44 million in 1999.
15
YEAR 2000 ISSUES
GENERAL - The Year 2000 issue affects all companies and relates to the
possibility that computer programs and embedded computer chips may be unable to
accurately process data with year dates of 2000 and beyond. Murphy is devoting
significant internal and external resources to address Year 2000 compliance, and
the Company's Year 2000 project (Project) is proceeding well. In 1993, Murphy
began a worldwide business systems replacement project using systems primarily
from J.D. Edwards & Company (Edwards) in the United States and the United
Kingdom, PricewaterhouseCoopers LLP (PW*Sequel) in Canada, and for exploration
and production operations, Applied Terravision Systems Inc. (Artesia) in the
United States, and EFA Software Services Ltd. (PRISM) in Canada. Certain U.S.
business software systems developed by the Company will not be replaced with
compliant vendor systems by the Year 2000 and have been remedied to be Year 2000
compliant. Remaining hardware, software and facilities are expected to be made
Year 2000 compliant through the Project. None of the Company's other information
technology projects are expected to be significantly delayed due to the
implementation of the Project.
PROJECT - The Company has established an Enterprise Project Office (EPO) and has
engaged KPMG LLP to assist with Project management. The Project is primarily
being managed by major operating location. At each location, the Project is
divided into three major components: Computer Hardware, Applications Software,
and Process Control and Instrumentation (Embedded Technology). The Computer
Hardware component consists of computing equipment and systems software other
than Applications Software. Applications Software includes both internally
developed and vendor software systems. Embedded Technology includes the
hardware, software and associated embedded computer chips (other than computing
equipment) that are used in facilities operated by the Company. The general
phases common to all components are: (1) inventorying Year 2000 items; (2)
assigning priorities to identified items; (3) assessing the Year 2000 compliance
of identified items; (4) repairing or replacing material items that are
determined not to be Year 2000 compliant; (5) evaluating and testing required
material items; and (6) designing and implementing contingency and business
continuation plans as necessary. Material items are those that the Company
believes to have safety, environmental or property damage risks, or that may
adversely affect the Company's ability to process and record revenues if not
properly addressed. The inventorying and priority assessment phases of the
Project were completed during 1998. The remaining four phases of the Project are
in progress and are being performed primarily by employees of the Company, with
assistance from vendors and independent contractors.
A fourth major component of the Project, which involves the review of third
party suppliers, customers and business partners (Third Parties), is being
managed for all locations by the EPO. This includes the process of identifying
and prioritizing critical Third Parties and communicating with them about their
plans and progress in addressing the Year 2000 problem. Detailed evaluations of
the most critical Third Parties began in the second quarter of 1998 and are
scheduled for completion by June 30, 1999, with follow-up reviews scheduled for
the remainder of 1999. The Company estimates that this component was on schedule
at December 31, 1998. Based on the results of evaluations and other available
information, contingency plans will be developed as necessary during 1999 to
address any anticipated Year 2000 problems related to critical Third Parties.
A Year 2000 compliant version of Edwards has been fully implemented in the
United States and is approximately 60% complete in the United Kingdom.
Implementation of Edwards is ongoing in the United Kingdom and final phases are
expected to be completed in October 1999. A contingency plan will be prepared in
early 1999 to address the possibility that the last phases of the U.K.
implementation will not be achieved by the end of 1999. A Year 2000 compliant
version of Artesia was implemented in the United States at the end of 1998 and
testing was completed in January 1999. In Canada, the Company expects to upgrade
and test a Year 2000 compliant version of PRISM during the first quarter of
1999, with a compliant version of PW*Sequel scheduled to be fully implemented in
April 1999. Testing of U.S. offshore production platform systems is scheduled to
be completed by the end of the first quarter of 1999. Exploration system
upgrades were released by the vendor in early 1999 and will be installed and
tested by the third quarter of 1999. Remedy of certain internally developed
downstream accounting, customer invoicing and human resources systems in the
United States had been completed at December 31, 1998. Upgrading and testing of
virtually all significant U.S. refining and marketing systems is scheduled to be
completed by April 30, 1999. The operator at the Company's jointly owned U.K.
refinery is directing that location's Year 2000 action plan; Company employees
are monitoring the operator's progress and believe the work is on schedule.
Systems at U.K. marketing terminals are being upgraded to a Year 2000 compliant
version; this work is scheduled to be completed by March 31, 1999. Supply and
transportation systems in Canada are expected to be essentially compliant by
March 31, 1999.
16
PROJECT SUMMARY - At January 31, 1999, the overall Project is estimated to be
70% complete. Thus far, no material noncompliant Year 2000 issues have been
discovered that were not identified in the completed Year 2000 inventory. The
material components of the Project, except for the final stages of the Edwards
implementation in the United Kingdom, are expected to be nearly complete by June
30, 1999.
The Company does not expect to develop formal contingency plans for Project
issues that are resolved in accordance with the current schedule. Any unresolved
issues that fall significantly behind schedule or that lead to a material risk
of system failure will be addressed by contingency plans during 1999.
COSTS - The Company's total cost to become Year 2000 compliant is not expected
to be material to its financial position. The most likely estimate of the total
cost of the Project is approximately $5 million, of which $2 million is for the
EPO (including assessment of Third Parties), $1 million is for miscellaneous
hardware replacement, $1 million is for noncompliant system renovations and
upgrades and $.6 million is for Embedded Technology issues. It is reasonably
possible that total costs could exceed the most likely estimate by up to $1
million. Funds for the Project are primarily obtained from internally generated
cash flows. This estimate does not include the Company's potential share of Year
2000 costs that may be incurred by partnerships and joint ventures that the
Company does not operate, except for an estimated $.5 million to make Murphy's
jointly owned U.K. refinery Year 2000 compliant. The cost of implementing
Edwards in the United Kingdom, estimated to be $.9 million, is also not included
in the Project cost estimate.
The total amount expended on the Project through December 31, 1998, and recorded
in selling and general expense in 1998 was $1.6 million, most of which related
to the EPO. The remaining cost to complete the Year 2000 Project is estimated to
be approximately $3.4 million.
RISKS - Not correcting material Year 2000 problems could result in interruptions
in, or failures of, certain normal business activities or operations. Such
failures could materially and adversely affect the Company's results of
operations, liquidity or financial condition by impeding the Company's ability
to produce and deliver crude oil, natural gas and finished petroleum products,
and to invoice and collect related revenues from customers. Due to the general
uncertainty inherent in the Year 2000 problem, resulting in part from
uncertainty about the Year 2000 readiness of critical Third Parties, the Company
is unable to determine at this time whether or not the consequences of possible
Year 2000 failures will materially affect its results of operations, liquidity
or financial condition. The Project is expected to significantly reduce the
Company's level of uncertainty about the Year 2000 issue, and in particular,
about the Year 2000 compliance and readiness of the Company's critical Third
Parties. The Company believes that it is taking reasonable steps to address
potentially material Year 2000 failures, and with completion of the Project as
scheduled, the possibility of significant interruptions of normal operations
should be greatly reduced.
Readers are cautioned that forward-looking statements contained in this Year
2000 section should be read in conjunction with Murphy's disclosures under the
heading "Forward-Looking Statements" on page 18 of this Form 10-K report.
OTHER MATTERS
IMPACT OF INFLATION - General inflation was moderate during the last three years
in most countries where the Company operates; however, the Company's revenues
and capital and operating costs are influenced to a larger extent by specific
price changes in the oil and gas and allied industries than by changes in
general inflation. Crude oil and petroleum product prices generally reflect the
balance between supply and demand, with crude oil prices being particularly
sensitive to OPEC production levels and/or attitudes of traders concerning
supply and demand in the near future. Natural gas prices are affected by supply
and demand, which to a significant extent is impacted by the weather, and by the
fact that delivery of supplies is generally restricted to specific geographic
areas. Relatively high crude oil and natural gas prices led to upward pressure
on amounts paid by the Company for goods and services during 1996 and 1997.
Conversely, lower commodity prices in 1998 have caused a softening of prices for
goods and services in recent months.
17
ACCOUNTING MATTERS - The Financial Accounting Standards Board issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," in June
1997. This statement establishes accounting and reporting standards for
derivative instruments and hedging activities. Effective January 1, 2000, 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 under the heading "Quantitative and
Qualitative Disclosures About Market Risk" on page 19 of this Form 10-K report,
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
Planning for 1999 is difficult because prices for the Company's products remain
uncertain. Worldwide crude oil sales prices remain under extreme pressure in
early 1999, primarily caused by soft worldwide crude oil demand due to the weak
Asian economy. In addition, relatively mild winter weather has led to
significantly lower U.S. natural gas sales prices in early 1999. The low oil and
natural gas sales prices, coupled with weak refining and marketing margins,
continue to exert downward pressure on the Company's operating results in early
1999. The Company was experiencing losses in exploration and production and
refining, marketing and transportation operations in early 1999. In such an
environment, constant reassessment of spending plans is required. The Company's
capital expenditure budget for 1999 was prepared during the fall of 1998, but
spending plans have subsequently been revised downward to reflect the effects of
the sharp decline in commodity prices seen in late 1998 and early 1999. The
Company's present plans call for capital expenditures of $400 million in 1999,
of which $290 million or 72% is allocated for exploration and production
activities. Geographically, about 33% of the planned exploration and production
spending is designated for the United States; 45% for Canada, including $75
million for further development of the Terra Nova oil field and $19 million at
Syncrude, primarily for expansion of the Aurora mine; 16% for the United
Kingdom, including $27 million for further development costs related to the
Schiehallion and Mungo/Monan oil fields; 4% for continuing development of oil
fields in Ecuador; and the remaining 2% for other overseas operations. Planned
refining, marketing and transportation capital expenditures for 1999 are $110
million, including $95 million in the United States, $14 million in the United
Kingdom and $1 million in Canada. U.S. amounts include funds for additional
stations at Wal-Mart sites. Capital and other expenditures are under constant
review and planned capital expenditures may be adjusted further to reflect
changes in estimated cash flow as 1999 progresses.
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 on file with the U.S. Securities and Exchange
Commission.
18
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. Murphy makes limited use of derivative financial and commodity
instruments to manage risks associated with existing or anticipated
transactions. All derivatives used for risk management are covered by operating
policies and are closely monitored by the Company's senior management. The
Company does not hold 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.
At December 31, 1998, 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. The 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, 1998, the interest rate to be
received by the Company averaged 5.23%. The variable interest rate received by
the Company under each swap contract is repriced quarterly. The Company
considers these swaps to be a hedge against potentially higher future interest
rates. As described in Note I to the consolidated financial statements, the
estimated fair value of these interest rate swaps was a negative $5.5 million at
December 31, 1998.
At December 31, 1998, 84% of the Company's long-term debt had variable interest
rates and 45% was denominated in Canadian dollars. Certain debt with fixed
interest rates at the end of 1998 is expected to be refinanced through
variable-rate borrowings during 1999. Based on debt outstanding at December 31,
1998, a 10% increase in variable interest rates would increase the Company's
interest expense in 1999 by $1.1 million, net of a $.5 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 1999 interest expense by $.3 million on debt
denominated in Canadian dollars.
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
19
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 12, 1999, 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 12, 1999, under the captions "Compensation of Directors," "Executive
Compensation," "Option Exercises and Fiscal Year-End Values," "Option Grants,"
"Compensation Committee Report for 1998," "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 12, 1999, under the caption "Certain Stock Ownerships."
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by this item is incorporated by reference to the
Registrant's definitive Proxy Statement for the Annual Meeting of Stockholders
on May 12, 1999, under the caption "Certain Relationships and Related
Transactions."
20
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) 1. FINANCIAL STATEMENTS
The consolidated financial statements of Murphy Oil Corporation and
consolidated subsidiaries are located or begin on the pages of this Form
10-K report as indicated below.
Page No.
--------
Report of Management F-1
Independent Auditors' Report F-1
Consolidated Statements of Income F-2
Consolidated 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 (*), are to be filed by an amendment as indicated by pound
sign (#), or are incorporated by reference. Exhibits other than those
listed have been omitted since they either are not required or are not
applicable.
EXHIBIT
NO. INCORPORATED BY REFERENCE TO
------- -----------------------------------------
3.1 Certificate of Incorporation of Murphy Oil Corporation as Exhibit 3.1 of Murphy's Form 10-K for the
of September 25, 1986 year ended December 31, 1996
3.2 Bylaws of Murphy Oil Corporation at January 24, 1996 Exhibit 3.2 of Murphy's Form 10-K for the
year ended December 31, 1997
4 Instruments Defining the Rights of Security Holders.
Murphy is party to several long-term debt instruments in
addition to the one in Exhibit 4.1, none of which authorizes
securities exceeding 10% of the total consolidated assets
of Murphy and its subsidiaries. Pursuant to Regulation S-K,
item 601(b), paragraph 4(iii)(A), Murphy agrees to furnish
a copy of each such instrument to the Securities and
Exchange Commission upon request.
4.1 Credit Agreement among Murphy Oil Corporation and Exhibit 4.1 of Murphy's Form 10-K for the
certain subsidiaries and the Chase Manhattan Bank year ended December 31, 1997
et al as of November 13, 1997
21
4.2 Rights Agreement dated as of December 6, 1989, Exhibit 4.1 of Murphy's Form 10-K for the year ended
between Murphy Oil Corporation and Harris December 31, 1994
Trust Company of New York, as Rights Agent
4.3 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, April 14, 1998, under the Securities Exchange Act of 1934
between Murphy Oil Corporation and Harris
Trust Company of New York, as Rights Agent
10.1 1987 Management Incentive Plan as amended February Exhibit 10.2 of Murphy's Form 10-K for the year ended
7, 1990, retroactive to February 3, 1988 December 31, 1994
10.2 1992 Stock Incentive Plan as amended May 14, 1997 Exhibit 10.2 of Murphy's Form 10-Q 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 1933
* 13 1998 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 1998
* 99.1 Undertakings
# 99.2 Form 11-K, Annual Report for the fiscal year To be filed as an amendment to this Form 10-K not later
ended December 31, 1998, covering the Thrift than 180 days after December 31, 1998
Plan for Employees of Murphy Oil Corporation
# 99.3 Form 11-K, Annual Report for the fiscal year To be filed as an amendment to this Form 10-K not later
ended December 31, 1998, covering the Thrift than 180 days after December 31, 1998
Plan for 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 To be filed as an amendment to this Form 10-K not later
ended December 31, 1998, covering the Thrift than 180 days after December 31, 1998
Plan for Employees of Murphy Oil USA, Inc.
Represented by International Union of Operating
Engineers, AFL-CIO, Local No. 305
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the quarter ended December 31,
1998.
22
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
MURPHY OIL CORPORATION
By CLAIBORNE P. DEMING Date: March 24, 1999
------------------------------------ ----------------------
Claiborne P. Deming, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below on March 24, 1999, by the following persons on behalf of
the registrant and in the capacities indicated.
R. MADISON MURPHY MICHAEL W. MURPHY
---------------------------------------------- ----------------------------------------------
R. Madison Murphy, Chairman and Director Michael W. Murphy, Director
CLAIBORNE P. DEMING WILLIAM C. NOLAN JR.
----------------------------------------------- ----------------------------------------------
Claiborne P. Deming, President and Chief William C. Nolan Jr., Director
Executive Officer and Director
(Principal Executive Officer)
B. R. R. BUTLER CAROLINE G. THEUS
---------------------------------------------- ----------------------------------------------
B. R. R. Butler, Director Caroline G. Theus, Director
GEORGE S. DEMBROSKI LORNE C. WEBSTER
---------------------------------------------- ----------------------------------------------
George S. Dembroski, Director Lorne C. Webster, Director
H. RODES HART STEVEN A. COSSE'
---------------------------------------------- ----------------------------------------------
H. Rodes Hart, Director Steven A. Cosse', Senior Vice President
and General Counsel
(Principal Financial Officer)
VESTER T. HUGHES JR. RONALD W. HERMAN
---------------------------------------------- ----------------------------------------------
Vester T. Hughes Jr., Director Ronald W. Herman, Controller
(Principal Accounting Officer)
C. H. MURPHY JR.
----------------------------------------------
C. H. Murphy Jr., Director
23
REPORT OF MANAGEMENT
The management of Murphy Oil Corporation is responsible for the preparation and
integrity of the accompanying consolidated financial statements and other
financial data. The statements were prepared in conformity with generally
accepted 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, 1998 and 1997, 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, 1998. 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, 1998 and 1997, and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 1998, in conformity with generally
accepted accounting principles.
KPMG LLP
Shreveport, Louisiana
March 1, 1999
F-1
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31 (THOUSANDS OF DOLLARS EXCEPT PER SHARE AMOUNTS) 1998 1997* 1996*
---- ---- ----
REVENUES
Crude oil and natural gas sales $ 312,253 450,785 346,310
Petroleum product sales 1,312,727 1,604,379 1,570,289
Other operating revenues 69,490 78,223 93,137
Interest and other nonoperating revenues 4,378 4,380 12,440
--------- --------- ---------
Total revenues 1,698,848 2,137,767 2,022,176
--------- --------- ---------
COSTS AND EXPENSES
Crude oil, products and related operating expenses 1,279,619 1,527,301 1,483,914
Exploration expenses, including undeveloped lease amortization 65,582 94,792 70,206
Selling and general expenses 61,363 65,928 66,402
Depreciation, depletion and amortization 202,695 209,419 182,381
Impairment of long-lived assets 80,127 28,056 --
Charge resulting from cancellation of a drilling rig contract 7,255 -- --
Interest expense 18,090 12,717 13,120
Interest capitalized (7,606) (12,096) (10,202)
--------- --------- ---------
Total costs and expenses 1,707,125 1,926,117 1,805,821
--------- --------- ---------
Income (loss) from continuing operations before income taxes (8,277) 211,650 216,355
Federal and state income tax expense 18,469 49,062 43,860
Foreign income tax expense (benefit) (12,352) 30,182 46,539
--------- --------- ---------
Income (loss) from continuing operations (14,394) 132,406 125,956
Discontinued farm, timber and real estate operations -- -- 11,899
--------- --------- ---------
NET INCOME (LOSS) $ (14,394) 132,406 137,855
========= ========= =========
PER COMMON SHARE - BASIC
Continuing operations $ (.32) 2.95 2.80
Discontinued operations -- -- .27
--------- --------- ---------
Net income (loss) $ (.32) 2.95 3.07
========= ========= =========
PER COMMON SHARE - DILUTED
Continuing operations $ (.32) 2.94 2.80
Discontinued operations -- -- .27
--------- --------- ---------
Net income (loss) $ (.32) 2.94 3.07
========= ========= =========
Average Common shares outstanding - basic 44,955,679 44,881,225 44,858,115
Average Common shares outstanding - diluted 44,955,679 44,960,907 44,904,636
*Revenues have been reclassified to conform to 1998 presentation.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31 (THOUSANDS OF DOLLARS) 1998 1997 1996
---- ---- ----
Net income (loss) $ (14,394) 132,406 137,855
Other comprehensive income - net gain (loss) from foreign
currency translation (24,411) (21,682) 18,005
--------- --------- ---------
COMPREHENSIVE INCOME (LOSS) $ (38,805) 110,724 155,860
========= ========= =========
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) 1998 1997
---- ----
ASSETS
Current assets
Cash and cash equivalents $ 28,271 24,288
Accounts receivable, less allowance for doubtful accounts
of $11,048 in 1998 and $13,530 in 1997 233,906 272,447
Inventories
Crude oil and blend stocks 41,090 55,075
Finished products 49,714 64,394
Materials and supplies