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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1993
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-9971
BURLINGTON RESOURCES INC.
5051 WESTHEIMER, HOUSTON, TEXAS 77056
TELEPHONE: (713) 831-1600
INCORPORATED IN THE STATE OF DELAWARE EMPLOYER IDENTIFICATION NO. 91-1413284
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
COMMON STOCK, PAR VALUE $.01 PER SHARE
PREFERRED STOCK PURCHASE RIGHTS
THE ABOVE SECURITIES ARE REGISTERED ON THE NEW YORK 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 (or for such shorter period that the
registrant was required to file such reports), 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. /X/
State the aggregate market value of the voting stock held by non-affiliates
of the registrant: Common Stock aggregate market value as of December 31,
1993: $5,495,337,423.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date. Class: Common Stock,
par value $.01 per share, on December 31, 1993, Shares Outstanding: 129,683,479.
DOCUMENTS INCORPORATED BY REFERENCE
List hereunder the following documents if incorporated by reference and the
Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated:
Burlington Resources Inc. definitive proxy statement, to be filed not later
than 120 days after the end of the fiscal year covered by this report, is
incorporated by reference into Part III.
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BURLINGTON RESOURCES INC.
TABLE OF CONTENTS
PAGE
PART I
Items One and Two
Business and Properties......................................................... 1
Employees....................................................................... 8
Item Three
Legal Proceedings............................................................... 8
Item Four
Submission of Matters to a Vote of Security Holders............................. 8
Executive Officers of the Registrant............................................ 9
PART II
Item Five
Market for Registrant's Common Equity and Related Stockholder Matters........... 10
Item Six
Selected Financial Data......................................................... 10
Item Seven
Management's Discussion and Analysis of Financial Condition and Results of
Operations..................................................................... 11
Item Eight
Financial Statements and Supplementary Financial Information.................... 14
Item Nine
Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure........................................................... 30
PART III
Items Ten and Eleven
Directors and Executive Officers of the Registrant and Executive Compensation... 30
Item Twelve
Security Ownership of Certain Beneficial Owners and Management.................. 30
Item Thirteen
Certain Relationships and Related Transactions.................................. 30
PART IV
Item Fourteen
Exhibits, Financial Statement Schedules and Reports on Form 8-K................. 31
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PART I
ITEMS ONE AND TWO
BUSINESS AND PROPERTIES
Burlington Resources Inc. ("BR") is a holding company engaged, through its
principal subsidiary, Meridian Oil Holding Inc. and its subsidiaries (together
the "Company"), in the exploration, development and production of oil and gas,
and related marketing activities, which include aggregation and resale of third
party oil and gas. The Company also owns and operates natural gas gathering
systems, intrastate natural gas pipelines and has an interest in a crude oil
pipeline. The Company is the largest independent (nonintegrated) oil and gas
company in the United States in terms of total domestic proved equivalent
reserves which were estimated at 6.2 TCFE at December 31, 1993. BR was formed in
1988 to function as a holding company for Burlington Northern Inc.'s ("BNI")
natural resource operations. In July 1988, BR completed an initial public
offering of 13 percent of its common stock and on December 31, 1988, BNI
distributed its remaining 87 percent interest in the Company's common stock to
the holders of BNI common stock.
In March 1992, BR's then wholly owned subsidiary, El Paso Natural Gas
Company ("EPNG"), completed an initial public offering of approximately 15
percent of its common stock. On June 30, 1992, BR distributed its remaining 85
percent interest in EPNG common stock to its stockholders of record as of June
15, 1992.
Since its inception, the Company has been selling its nonstrategic real
estate, minerals and forest products assets and reinvesting the net proceeds in
domestic oil and gas reserves and in the repurchase of its common stock. The
Company has completed the sale of virtually all of its nonstrategic assets as of
December 31, 1993. Since 1988, proceeds from such sales total approximately $1.4
billion.
For definitions of certain oil and gas terms used herein, see "Certain
Definitions" on page 7.
GENERAL INFORMATION
The Company's strategy is to continue building stockholder value through
the growth and development of its asset base. The Company increases production,
reserves, earnings and cash flow through opportunistic acquisitions,
exploitation of properties with high potential and application of advanced
technologies.
The Company is engaged in oil and gas operations located principally in the
San Juan Basin, the Permian Basin, the Williston Basin, the Gulf Coast Basin,
the Anadarko Basin and the Black Warrior Basin. Virtually all of the Company's
oil and gas production is from onshore properties located in the United States.
Following is a description of the Company's major areas of activity.
SAN JUAN BASIN. The San Juan Basin is the Company's most prolific
operating area in terms of reserves and production. The San Juan Basin, located
in northwest New Mexico and southwest Colorado, encompasses nearly 7,500 square
miles, or approximately 4.8 million acres, with the major portion located in the
New Mexico counties of Rio Arriba and San Juan. The Company is the largest
private holder of productive acreage in this area with over one million net
acres under its control, has an interest in approximately 10,800 wells and
currently operates approximately 7,000 of these wells. Approximately 4 TCFE, or
64 percent of the Company reserves, are located in this basin. The Company's
daily net gas production at year end 1993 in this basin exceeded 600 MMCF per
day, representing approximately 65 percent of the Company's total daily gas
production at year end 1993.
The four significant gas producing horizons in the San Juan Basin, which
range in depth from approximately 1,000 feet to 8,500 feet, are the Fruitland
Coal, the Pictured Cliffs, the Mesaverde and the Dakota. The Pictured Cliffs,
Mesaverde and Dakota are sandstone formations while the Fruitland Coal produces
gas which is adsorbed to the surface of coal seams. The Company has been an
industry leader in the development of the Fruitland Coal formation which was
proven commercial in a pilot program initiated in 1986. The Company participated
in 92 coal seam gas wells completed in 1993 at a
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net cost of approximately $17 million. The Company's net coal seam gas
production was over 300 MMCF per day at year end 1993.
In order to manage production more effectively and improve recovery of
reserves, the Company owns and operates the Val Verde plant and gathering system
which includes approximately 400 miles of gathering lines, seven compressor
stations and a processing plant to gather and process coal seam gas in the San
Juan Basin. The Company expended over $27 million for the continued expansion of
the Val Verde system during 1993. The 1993 expenditures increased processing
capacity at the Val Verde plant by 110 MMCF per day bringing the total
processing capacity of coal seam gas to 780 MMCF per day. The Company also owns
and operates a fractionation plant located in McKinley County, New Mexico.
PERMIAN BASIN. The Company is an active operator in the Permian Basin,
which includes essentially all of west Texas and southeast New Mexico and
encompasses approximately 68,000 square miles. The Company's reserve base in the
Permian Basin has more than doubled since 1988 from internal development
projects and through the acquisition of producing properties. The Company has an
interest in over 12,000 Permian Basin wells and operates over 3,000 of those
wells resulting in a daily net production at year end 1993 of approximately 15
MBbls of oil per day and 128 MMCF of gas per day.
The most productive structural feature in the Permian Basin is the Central
Basin Platform in which the Company owns over 158,000 net acres of mineral
interests. This area is about 170 miles long and 50 miles wide trending
northwest from west Texas to southeast New Mexico. Over 20 different formations,
ranging in depth from 2,000 feet to over 12,000 feet, produce oil and gas on the
Central Basin Platform. The Waddell Ranch, located 40 miles west of Midland,
Texas, is the largest consolidated block of acreage in this basin in which the
Company has an interest. During 1993, the Company acquired a 59 percent interest
in the Permian Basin Royalty Trust. The Company estimates approximately 80
percent of the reserves attributable to the Permian Basin Royalty Trust are
located on the Waddell Ranch.
The Val Verde Basin is a 7,000 square mile sub basin of the Permian Basin
located about 125 miles southeast of Midland, Texas. The Company has utilized
advanced reservoir stimulation technology which primarily consists of modern
hydraulic fracturing techniques in the Canyon Sand trend of this basin. During
1993, the Company participated in 31 wells at a net cost of approximately $9
million. As of year end, the Company operated over 440 wells in the Canyon Sand
trend with net gas production of approximately 40 MMCF per day.
Another producing area in the Permian Basin is the Delaware Sand trend
located in southeast New Mexico covering approximately 2,300 square miles. The
Company owns approximately 63,000 net acres within this trend. Wells in this
trend typically produce from multiple horizons and the area is prospective for
both oil and gas. Productive zones range in depth from 3,000 feet to 22,000
feet. The Company's 1993 activity focused on the development of oil from the
Delaware Sand trend at a depth of approximately 8,500 feet. The Company
participated in 15 Delaware Sand wells drilled in 1993 at a net cost of
approximately $9 million.
The application of three dimensional ("3D") seismic technology has become
an effective exploitation tool in the Permian Basin due to the complex geologic
nature of this area. The Company foresees continued opportunities in this mature
hydrocarbon province and is currently obtaining a considerable volume of new 3D
seismic data to help exploit the many oil and gas formations and reservoirs in
the Permian Basin.
WILLISTON BASIN. The Williston Basin encompasses approximately 225,000
square miles in western North Dakota, northwest South Dakota, northeast Montana
and Saskatchewan Province, Canada. The Williston Basin has 18 producing horizons
ranging in depth from 4,500 feet to over 15,000 feet. The Company controls over
3.7 million net acres, primarily in the U.S. portion of the basin, through both
mineral and leasehold interests.
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The Company's primary area of activity in the Williston Basin over the past
several years has been the development of the Bakken Shale trend in North Dakota
through horizontal drilling technology. During 1993, the Company participated in
the completion of 21 horizontal wells in the Bakken Shale trend at a net cost of
approximately $18 million. As of year end 1993, production in the Williston
Basin was approximately 11 Mbls per day. Approximately 35 percent of this
production is attributable to Bakken Shale wells drilled horizontally.
GULF COAST BASIN. The Gulf Coast Basin includes offshore and onshore oil
and gas deposits along virtually all of the states bordering the Gulf of Mexico.
The area encompasses about 250,000 square miles and is one of the most heavily
explored oil and gas basins in the world. The complex geologic conditions and
multiple prospective oil and gas formations, encountered as deep as 25,000 feet,
make this an attractive area for the application of advanced technologies such
as 3D seismic, computerized modeling and horizontal drilling.
The Company's activities in the Gulf Coast Basin are primarily onshore and
are concentrated in the Luling and Darst Creek Fields and the West Ranch area
located in south Texas. The Company has been actively applying horizontal
drilling technology in the Edwards formation of the Luling and Darst Creek
Fields to enhance production from this mature area. During 1993, 15 horizontal
wells were drilled in these fields at a net cost of approximately $6 million. As
of year end 1993, the Luling and Darst Creek Fields were producing approximately
3 MBbls per day. Approximately 47 percent of this production is attributable to
horizontal wells drilled since these properties were acquired in 1989.
ANADARKO BASIN. The Anadarko Basin, located in the western portion of
Oklahoma, the Texas panhandle and southwestern Kansas, encompasses over 30,000
square miles and contains some of the deepest producing formations in the world.
The basin produces oil and gas from multiple zones ranging in depth from less
than 1,000 feet to over 26,000 feet. The Company has over 460,000 net acres in
this primarily gas producing basin with the majority located in western
Oklahoma. As of year end 1993, the Company operated approximately 820 wells in
this basin and total daily net gas production was over 123 MMCF per day. The
Company has been concentrating its Anadarko Basin activity in the Elk City Field
and the Strong City Field. The primary producing horizons in these fields are
the Red Fork, Cherokee and Prue formations. During 1993, the Company
participated in the drilling of 45 wells to these formations at a net cost of
approximately $15 million.
BLACK WARRIOR BASIN. The Black Warrior Basin covers approximately 35,000
square miles extending across northwest Alabama and northeast Mississippi. The
basin produces from both conventional and coal seam gas formations. The
Company's recent operations are primarily concentrated on developing coal seam
gas reserves. The Company has over 180,000 net acres in the coal seam gas play
near Tuscaloosa, Alabama and currently has approximately 14,000 net acres
developed with 85 wells producing over 10 MMCF per day net at year end 1993.
During 1993, the Company participated in 40 coal seam wells in the Black Warrior
Basin at a net cost of approximately $21 million. The Company owns and operates
approximately 75 miles of gas gathering systems in the Black Warrior Basin.
SECTION 29 TAX CREDITS
A number of formations located within the Company's producing areas have
wells that may qualify for tax credits under Section 29 of the Internal Revenue
Code of 1954, as amended ("IRC"). IRC Section 29 provides for a tax credit from
non-conventional fuel sources such as oil produced from shale and tar sands and
natural gas produced from geopressured brine, Devonian shale, coal seams, or
tight sands formations. The Company estimates that the tax credit rate will
range from $0.52 to $0.99 per million British Thermal Unit depending on fuel
source and generated approximately $75 million of tax credits in 1993.
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CAPITAL EXPENDITURES AND MAJOR PROJECTS
The Company's capital expenditures were as follows:
YEAR ENDED DECEMBER 31,
----------------------------------
1993 1992 1991
-------- -------- --------
(IN THOUSANDS)
Oil and Gas Activities........................... $501,191 $253,658 $434,740
Plants and Pipelines............................. 33,327 49,423 55,476
Administrative................................... 18,866 12,366 9,940
-------- -------- --------
Total.................................. $553,384 $315,447 $500,156
-------- -------- --------
-------- -------- --------
Capital expenditures for oil and gas activities in 1993 of $501 million
include 54 percent for proved property acquisitions, 40 percent for
developmental drilling and 6 percent for exploration. Capital expenditures for
oil and gas activities include exploration costs expensed under the successful
efforts method of accounting and capitalized interest.
Drilling Activity
Drilling activity in 1993 was principally in the San Juan, Permian,
Williston, Gulf Coast, Anadarko and Black Warrior basins.
The following table sets forth the Company's net productive and dry wells.
YEAR ENDED DECEMBER 31,
--------------------------------
1993 1992 1991
------ ------ ------
Productive wells:
Exploratory.............................. 7.2 5.6 11.5
Development.............................. 243.7 107.3 179.5
------ ------ ------
250.9 112.9 191.0
------ ------ ------
Dry wells:
Exploratory.............................. 9.0 9.9 4.6
Development.............................. 11.6 8.1 17.9
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20.6 18.0 22.5
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Total net wells.................. 271.5 130.9 213.5
------ ------ ------
------ ------ ------
As of December 31, 1993, 13 gross wells, representing approximately 9.5 net
wells, were being drilled.
Acquisitions
As a component of its overall growth strategy, the Company continued to
make acquisitions of producing properties during 1993. A total of 411 BCFE of
oil and gas reserves was acquired by the Company at a cost of approximately $270
million. Approximately 60 percent and 30 percent of the reserves acquired during
the year were in the San Juan and Permian basins, respectively. Year end 1993
production associated with the properties acquired was approximately 45 MMCF of
gas per day and 4 MBbls of oil per day.
The Company focuses its acquisition activity in areas where it has
production in order to maximize the efficiencies gained in combining operations
or in new areas where the Company can transfer its technological expertise or
take advantage of premium markets. In addition, the Company uses a selective
acquisition process that emphasizes the purchase of both proved reserves as well
as properties having upside potential that can be exploited by the utilization
of both conventional and advanced technologies.
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PRODUCTIVE WELLS, DEVELOPED AND UNDEVELOPED ACREAGE
Working interests in productive wells, developed acreage and undeveloped
leasehold acreage at December 31, 1993 were as follows:
PRODUCTIVE WELLS
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OIL GAS DEVELOPED ACRES UNDEVELOPED ACRES
- ----------------- ----------------- ------------------------ ------------------------
GROSS NET GROSS NET GROSS NET GROSS NET
- ------- ------ ------- ------ ---------- ---------- ---------- ----------
16,614 4,305 15,117 8,453 5,908,000 3,073,000 2,884,000 1,779,000
Included in the productive wells data are 1,121 multiple completions.
Excluded from the acreage data are approximately 7 million undeveloped acres of
Company-owned oil and gas mineral rights, of which approximately 3 to 4 million
acres are considered to have potential for oil and gas exploration.
OIL AND GAS PRODUCTION, PRICES AND PRODUCTION COSTS
The Company's average daily production, which represents its net ownership
after deduction of all royalty interests held by others but includes royalty
interests and net profits interests owned by the Company, was as follows:
YEAR ENDED DECEMBER 31,
--------------------------------
1993 1992 1991
------ ------ ------
Production:
Gas (MMCF per day)................................. 920 818 710
Oil (MBbls per day)................................ 41.9 40.6 36.1
Average sales prices:
Gas per MCF........................................ $ 1.72 $ 1.49 $ 1.35
Oil per barrel..................................... 16.69 18.82 20.13
Average production costs per MCFE.................... 0.56 0.55 0.57
Depreciation, depletion and amortization rates per
MCFE............................................... 0.58 0.58 0.59
In 1993, 1992 and 1991, approximately 69 percent, 70 percent and 62
percent, respectively, of the Company's gas production was transported to direct
sale customers through EPNG's pipeline facilities. These transportation
arrangements are pursuant to EPNG's approved Federal Energy Regulatory
Commission ("FERC") tariffs applicable to all shippers. The Company expects to
transport a substantial portion of its future gas production through EPNG's
pipeline system.
RESERVES
The following table sets forth estimates by the Company's petroleum
engineers of proved oil and gas reserves at December 31, 1993. These reserves
have been reduced for royalty interests owned by others.
GAS OIL TOTAL
(BCF) (MMBBLS) (BCFE)
------ -------- ------
Proved Developed Reserves................... 4,381 149.8 5,280
Proved Undeveloped Reserves................. 840 18.4 950
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Total Proved Reserves............. 5,221 168.2 6,230
------ -------- ------
------ -------- ------
For further information on reserves, including information on future net
cash flows and the standardized measure of discounted future net cash flows, see
"Financial Statements and Supplementary Financial Information--Supplemental Oil
and Gas Disclosures."
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INTRASTATE PIPELINES AND NGL
The Company owns and operates two intrastate natural gas pipeline systems
in west Texas totaling 426 miles and seven gathering systems in several states.
Natural gas is sold from the Company's intrastate systems to industrial
customers, electric and gas utilities, and other intrastate pipeline companies.
YEAR ENDED DECEMBER 31,
---------------------------
1993 1992 1991
---- ----- ----
(BCF)
Annual intrastate natural gas throughput:
Sales:
Company owned production................ 19 25 21
Third party production.................. 41 45 44
Third party gas transportation and
gathering............................... 319 255 196
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Total.............................. 379 325 261
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---- ----- ----
The Company is engaged in the fractionation, transportation and marketing
of NGL which are sold to a variety of distributors, refiners and petrochemical
users. NGL sales were 14.9 MMBbls, 14.5 MMBbls and 15.7 MMBbls, for the years
ended December 31, 1993, 1992 and 1991, respectively.
OTHER MATTERS
Competition. The Company actively competes for reserve acquisitions and
exploration leases and sales of natural gas, frequently against companies with
substantially larger financial and other resources. In its NGL business, the
Company competes with numerous companies for gas purchasing and processing
contracts and for gas liquids, natural gas and crude oil at several steps in the
distribution chain. Competitive factors in the Company's business include price,
contract terms, quality of service, pipeline access, transportation discounts
and distribution efficiencies.
Regulation of Oil and Gas Production, Sales and Transportation. Numerous
departments and agencies, both federal and state, have issued rules and
regulations governing the oil and gas industry and its individual members,
compliance with which is often difficult and costly and some of which carry
substantial noncompliance penalties. State statutes and regulations require
permits for drilling operations, drilling bonds and reports concerning
operations. Most states in which the Company operates also have statutes and
regulations governing conservation matters, including the unitization or pooling
of oil and gas properties and the establishment of maximum rates of production
from oil and gas wells. Many states also restrict production to the market
demand for oil and gas. Such statutes and regulations may limit the rate at
which oil and gas could otherwise be produced from the Company's properties.
The Company operates a number of intrastate natural gas pipelines,
gathering systems and NGL pipelines. The United States Department of
Transportation regulates, under various enabling statutes, the safety aspects of
the transportation and storage activities of these pipeline facilities by
prescribing safety and operating standards.
The transportation of natural gas in interstate commerce is regulated by
the FERC pursuant to the Natural Gas Act of 1938. All of the Company's sales of
natural gas are "deregulated".
The FERC has adopted wide-ranging pipeline regulations promulgated under a
rulemaking, the Order No. 636 series. These regulations are intended by the FERC
to fundamentally restructure the interstate pipeline industry, and, as a result,
they will have a significant impact on the transportation, marketing and,
consequently, pricing of natural gas. These regulations are currently being
implemented on individual pipelines and are subject to many court challenges.
Notably, these new regulations implement, on an industry-wide basis,
"straight fixed-variable" rate design, thus increasing all pipelines' demand
charges for firm transportation service. The straight fixed-variable rate design
methodology allows all of a pipeline's fixed costs, including an equity return
and related income taxes, to be eligible for demand or reservation charge
collection. The regulations permit firm shippers the opportunity to mitigate
demand charge impacts by relinquishing to others, on
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either a permanent or temporary basis, their firm transportation entitlements at
times when these firm shippers do not need some or all of their capacity for
their own use. In addition, these regulations also permit the interstate
pipeline companies, or their marketing affiliates, to sell gas in interstate
commerce substantially free from regulation, thereby increasing the competition
for gas purchasers. These regulations also allow interstate pipeline companies
to collect from their customers certain significant transition costs via (i)
direct billings or (ii) demand and/or usage surcharges on their transportation
rates.
The Company currently holds firm and interruptible transportation capacity
rights on EPNG's pipeline system, as well as the systems of other interstate and
intrastate pipelines including EPNG's wholly owned subsidiary Mojave Pipeline
Company. The contracts providing firm transportation services to the Company
require the payment of substantial transportation demand charges. These demand
charges are paid monthly by the Company regardless of the level of utilization
thereunder. The Company paid $48 million of demand charges in 1993 under
transportation agreements with terms ranging from 1 to 13 years. While the
Company expects higher charges on these pipelines as a result of the
implementation of straight fixed-variable rate design, overall, the Company does
not expect a materially adverse effect from the Order 636 series of regulations
on the consolidated financial position or results of operations of the Company.
Environmental Regulation. Various federal, state and local laws and
regulations covering the discharge of materials into the environment, or
otherwise relating to the protection of the environment, may affect the
Company's operations and costs as a result of their effect on oil and gas
exploration, development and production operations. The Company believes it is
in substantial compliance with applicable environmental laws and regulations.
The Company does not anticipate that it will be required under environmental
laws and regulations to expend amounts that will have a materially adverse
effect on the consolidated financial position or results of operations of the
Company.
Offshore oil and gas operations are subject to regulations of the U.S.
Department of the Interior which currently imposes absolute liability upon the
lessee under a federal lease for the cost of pollution cleanup resulting from
the lessee's operations, and could subject the lessee to possible liability for
pollution damages. In the event of a serious incident of pollution, the U.S.
Department of the Interior may require a lessee under a federal lease to suspend
or cease operations in the affected area. The Company has no substantial
offshore activity.
Filings of Reserve Estimates With Other Agencies. During 1993, the Company
filed estimates of oil and gas reserves for the year 1992 with the Department of
Energy. These estimates were not materially different from the reserve data
presented herein.
CERTAIN DEFINITIONS
Gas volumes are stated at the legal pressure base of the state or area
in which the reserves are located and at 60 degrees Fahrenheit. As used in this
Form 10-K, "MCF" means thousand cubic feet, "MMCF" means million cubic feet,
"BCF" means billion cubic feet, "MBbls" means thousands of barrels, "MMBbls"
means millions of barrels, "MCFE" means thousand cubic feet of gas equivalent,
"BCFE" means billion cubic feet of gas equivalent and "TCFE" means trillion
cubic feet of gas equivalent. Oil is converted into cubic feet of gas
equivalent based on 6 MCF of gas to one barrel of oil. "NGL" means natural gas
liquids. Proved reserves represent estimated quantities of oil and gas which
geological and engineering data demonstrate with reasonable certainty can be
recovered in future years from known reservoirs under existing economic and
operating conditions. Reservoirs are considered proved if shown to be
economically producible by either actual production or conclusive formation
tests. Reserves which require the use of improved recovery techniques for
production are included in proved reserves if supported by a successful pilot
project or the operation of an installed program. Proved developed reserves are
the portion of proved reserves which can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved
undeveloped reserves are the portion of proved reserves which can be expected
to be recovered from new wells on undrilled
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proved acreage, or from existing wells where a relatively major expenditure is
required for completion. With respect to information on working interests in
acreage and wells, "net" acreage and "net" oil and gas wells are obtained by
multiplying "gross" acreage and "gross" oil and gas wells by the Company's
working interest percentage in the properties.
EMPLOYEES
The Company had 1,729 and 1,705 employees at December 31, 1993 and 1992,
respectively.
ITEM THREE
LEGAL PROCEEDINGS
The Company and its subsidiaries are named defendants in numerous lawsuits
and named parties in numerous governmental proceedings arising in the ordinary
course of business. While the outcome of lawsuits or other proceedings cannot be
predicted with certainty, management expects these matters will not have a
materially adverse effect on the consolidated financial position or results of
operations of the Company.
ITEM FOUR
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of 1993 no matters were submitted to a vote of
security holders.
The Company has prepared a report addressing its environmental compliance
policies and practices. To secure a copy of the report, write Corporate
Secretary, Burlington Resources Inc., 5051 Westheimer, Suite 1400, P.O. Box
4239, Houston, Texas 77056.
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EXECUTIVE OFFICERS OF THE REGISTRANT
THOMAS H. O'LEARY, 59
Chairman of the Board, President and Chief Executive Officer
Burlington Resources Inc.
February 1993 to Present
Chairman of the Board and Chief Executive Officer, July 1992 to February
1993; Chairman of the Board, President and Chief Executive Officer, October 1990
to July 1992; President and Chief Executive Officer, January 1989 to October
1990. Mr. O'Leary has been a director of Burlington Resources Inc. since 1988.
GEORGE E. HOWISON, 49
Senior Vice President and Chief Financial Officer
Burlington Resources Inc.
November 1990 to Present
President and Chief Executive Officer
Meridian Oil Inc.
May 1993 to Present
Vice President, Planning and Treasurer, Burlington Resources Inc., August
1988 to October 1990.
GERALD J. SCHISSLER, 49
Senior Vice President, Law
Burlington Resources Inc.
December, 1993 to Present
Executive Vice President, Law and Corporate
Affairs
Meridian Oil Inc.
July 1993 to Present
Consultant, June 1991 to July 1993; Senior Vice President, Law, Meridian
Minerals Company, a subsidiary of Burlington Resources Inc., November 1987 to
June 1991.
JOHN E. HAGALE, 37
Executive Vice President and Chief Financial Officer
Meridian Oil Inc.
March 1993 to Present
Vice President, Finance, Burlington Resources Inc., March 1992 to February
1993; Vice President, Taxes, Burlington Resources Inc., December 1990 to March
1992; Assistant Vice President, Taxes, Burlington Resources Inc., January 1989
to November 1990.
HAROLD E. HAUNSCHILD, 43
Vice President, Human Resources
Burlington Resources Inc.
July 1992 to Present
Executive Vice President, Human Resources and Administration
Meridian Oil Inc.
May 1993 to Present
Assistant Vice President, Compensation and Benefits, Burlington Resources
Inc., May 1988 to July 1992.
L. EDWARD PARKER, 47
Executive Vice President, Marketing
Meridian Oil Inc.
February 1993 to Present
Senior Vice President, Marketing, Meridian Oil Inc., December 1990 to
February 1993; Vice President, Marketing, Meridian Oil Inc., August 1988 to
November 1990.
BOBBY S. SHACKOULS, 43
Executive Vice President and Chief Operating Officer
Meridian Oil Inc.
June 1993 to Present
President and Chief Operating Officer, Torch Energy Advisors, Inc., July
1991 to June 1993; Executive Vice President, Torch Energy Advisors, Inc.,
September 1988 to June 1991.
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PART II
ITEM FIVE
MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The Company's common stock is traded on the New York Stock Exchange under
the symbol "BR." At December 31, 1993, the number of common stockholders was
26,976.
Information on common stock prices and quarterly dividends is shown on page
29.
ITEM SIX
SELECTED FINANCIAL DATA
The selected financial data for the Company set forth below for the five
years ended December 31, 1993 should be read in conjunction with the
Consolidated Financial Statements.
1993 1992 1991 1990 1989
------ ------ ------ ------ ------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
CONTINUING OPERATIONS FOR THE YEAR ENDED:
Revenues.................................... $1,249 $1,141 $1,036 $1,025 $ 797
Operating Income............................ 256 240 177 216 90
Income from Continuing Operations........... 255 190 100 124 77
Earnings per Common Share(a)................ 1.95 1.44 0.75 0.87 0.52
Cash Dividends Declared per Common
Share(b)................................. 0.55 0.60 0.70 0.70 0.61
AT YEAR END:
Total Assets(c)............................. $4,448 $4,470 $5,480 $5,250 $4,625
Long-term Debt.............................. 819 1,003 1,298 529 87
Stockholders' Equity(c)..................... 2,608 2,406 2,907 3,024 3,223
Common Shares Outstanding................... 129.7 128.9 131.4 137.9 146.0
- ------------
(a) Excluding non-recurring items totaling $0.45, $0.24, and $0.08 per share,
Earnings per Common Share from Continuing Operations would have been $1.50,
$1.20 and $0.67 in 1993, 1992, and 1991, respectively.
(b) On January 13, 1993, the Company increased its quarterly dividend rate to
$0.1375 per share. In July 1992, the quarterly dividend rate was reduced to
$0.125 per share to reflect the June 30, 1992 spin-off of EPNG to the
Company's stockholders.
(c) On June 30, 1992, the Company distributed its EPNG common stock to the
Company's stockholders of record as of June 15, 1992. The distribution was
accounted for as a $575 million non-cash dividend.
10
13
ITEM SEVEN
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
The Company's total long-term debt to capital (long-term debt and
stockholders' equity) ratio at December 31, 1993 and 1992 was 24 and 29 percent,
respectively. In April 1993, the Company redeemed all of its outstanding 7%
Subordinated Debentures. Virtually all of the debentures, approximately $80
million principal amount plus accrued interest, were surrendered in exchange for
2,520,527 shares of Anadarko Petroleum Corporation ("Anadarko") common stock
owned by the Company. The Anadarko stock had a cost of approximately $59
million.
The Company had outstanding commercial paper borrowings at December 31,
1993 of $71 million at an average interest rate of 3.53 percent.
The Company has a $900 million revolving credit facility that expires in
June 1996. As of December 31, 1993, there were no borrowings outstanding under
this facility, although borrowing capacity is reduced by outstanding commercial
paper. The Company had the capacity to borrow approximately $829 million under
the revolving credit facility as of December 31, 1993. The Company also has $500
million of capacity under a shelf registration statement filed with the
Securities and Exchange Commission.
During 1993, the Company repurchased 1.1 million shares of its common stock
for $45 million. Since December 1988, the Company has repurchased 24 million
shares under three 10 million share repurchase authorizations.
In June 1993, the Company, as sponsor of the Burlington Resources Coal Seam
Gas Royalty Trust (the "Trust"), completed the public offering of 8.8 million
Trust units priced at $20.50 per unit. The Trust received a net profits interest
(the "NPI") in certain of the Company's coal seam gas reserves in exchange for
the Trust units. The proved gas reserves attributable to the NPI as of December
31, 1992, were estimated to be 135.5 BCF. The net proceeds were used for general
corporate purposes, including acquisition of oil and gas properties, repayment
of commercial paper obligations, and other capital expenditures.
Net cash provided by continuing operating activities for 1993 was $455
million compared to $433 million and $375 million in 1992 and 1991,
respectively. The increase in 1993 compared to 1992 is primarily due to higher
operating income and increased current utilization of nonconventional fuel tax
credits. The increase in 1992 compared to 1991 is primarily due to increased
operating income partially offset by decreased sources of cash from working
capital.
The Company is involved in certain environmental proceedings and other
related matters. Although it is possible that new information or future
developments could require the Company to reassess its potential exposure
related to these matters, the Company believes, based upon available
information, the resolution of these issues will not have a materially adverse
effect on the consolidated financial position or results of operations of the
Company.
The Company has certain commitments and uncertainties related to its normal
operations. Management believes that there are no commitments, uncertainties or
contingent liabilities that will have a materially adverse effect on the
consolidated financial position or results of operations of the Company.
CAPITAL EXPENDITURES AND RESOURCES
Capital expenditures during 1993 totaled $553 million compared to $315
million and $500 million in 1992 and 1991, respectively. The Company spent $270
million for producing property acquisitions
11
14
during 1993 compared to $122 million in 1992. During 1993, the Company acquired
a 59 percent interest in the Permian Basin Royalty Trust for approximately $134
million. The decrease in capital expenditures in 1992 from 1991 was primarily
due to lower expenditures for the acquisition of producing properties and
developmental drilling.
Capital expenditures for 1994, projected to be approximately $470 million,
is expected to be primarily for development of oil and gas properties, reserve
acquisitions, and processing plant and pipeline expenditures. Capital
expenditures will be funded from internal cash flow supplemented, as needed, by
external financing.
DIVIDENDS
On January 12, 1994, the Board of Directors declared a common stock
quarterly dividend of $0.1375 per share, payable April 1, 1994. Dividend levels
are determined by the Board of Directors based on profitability, capital
expenditures, financing and other factors. The Company declared cash dividends
on common stock totaling approximately $71 million during 1993.
On June 30, 1992, the Company distributed all the shares of EPNG common
stock it owned to its stockholders of record as of June 15, 1992. The
distribution was accounted for as a $575 million non-cash dividend of the
Company's investment in EPNG common stock.
RESULTS OF OPERATIONS
Year Ended December 31, 1993 Compared With Year Ended December 31, 1992
Income from Continuing Operations in 1993 was $255 million, $1.95 per
share, compared to $190 million, $1.44 per share, in 1992. The 1993 results
include a total of $0.45 per share from gains on the sale of the Trust units and
the exchange of Company debt for Anadarko common stock, and a charge to reflect
the increase in the corporate income tax rate. The 1992 results include a $0.24
per share gain on the sale of the Company's interests in Plum Creek Timber
Company, L.P. Operating Income increased to $256 million in 1993 compared to
$240 million in 1992. The increase was primarily due to higher natural gas sales
prices and volumes partially offset by lower oil prices and higher operating
expenses.
Revenues were $1,249 million in 1993 compared to $1,141 million in 1992.
The increase was primarily due to higher natural gas prices and improved natural
gas and crude oil sales volumes, partially offset by lower crude oil prices and
a decrease in natural gas contract recoveries. Average natural gas sales prices
increased 15 percent in 1993 to an average of $1.72 per MCF which increased
revenues $77 million. Natural gas sales volumes improved 12 percent to 920 MMCF
per day which increased revenues $55 million. Oil sales volumes improved 3
percent to 41.9 MBbls per day which increased revenues $9 million. Natural gas
and oil sales volumes increased primarily due to continued development of the
Company's oil and gas properties, the impact of producing property acquisitions,
and operational efficiencies resulting from reduced gas gathering system
pressures in the San Juan Basin. Intrastate natural gas sales, NGL revenues and
processing revenues increased $17 million, principally as a result of higher
sales prices. These revenue increases were partially offset by lower oil sales
prices which declined 11 percent in 1993 to $16.69 per barrel and decreased
revenues $33 million. In addition, there were no natural gas contract recoveries
in 1993. The revenues for 1992 include $7 million of non-recurring natural gas
contract recoveries.
Costs and Expenses were $993 million in 1993 compared to $901 million in
1992. The increase was primarily due to higher 1993 production which increased
production related expenses $69 million or 13 percent. Intrastate natural gas
and NGL product purchases increased $2 million and administrative expenses
increased $13 million.
The Company anticipates continued increases in natural gas production. The
increased availability of natural gas will be a result of the continuing
development of the Company's gas reserves and the Company's aggressive producing
property acquisition program. The Company expects to market the additional gas
production in the Gulf Coast, the Midwest and the East Coast and by increasing
its traditional California market share.
12
15
Interest Expense was $73 million in 1993 compared to $79 million in 1992.
The decrease was primarily due to the April 1993 conversion of approximately $80
million in Company debt for Anadarko common stock and lower commercial paper
borrowings.
Other Income -- Net was $124 million income in 1993 compared to $57 million
income in 1992. The 1993 amount includes a $108 million gain on the sale of the
Trust units and a $19 million gain from the exchange of Company debt for
Anadarko common stock. The 1992 amount includes a $50 million gain on the sale
of the Company's interests in Plum Creek Timber Company, L.P.
Income Taxes -- The effective income tax rate was 17 percent in 1993
compared to 13 percent in 1992. The increase is primarily due to $16 million in
additional income tax expense recognized to adjust the cumulative deferred tax
liability for the new corporate income tax rate.
Year Ended December 31, 1992 Compared With Year Ended December 31, 1991
Income from Continuing Operations in 1992 was $190 million, $1.44 per
share, compared to $100 million, $0.75 per share, in 1991. The 1992 results
include a $0.24 per share gain on the sale of the Company's interests in Plum
Creek Timber Company, L.P. The 1991 results included an $0.08 per share
non-recurring gain related to interest on an income tax refund. Operating Income
increased to $240 million in 1992 compared to $177 million in 1991. The increase
was primarily due to improved natural gas and crude oil sales volumes and higher
natural gas prices.
Revenues were $1,141 million in 1992 compared to $1,036 million in 1991.
The increase was primarily due to improved natural gas and crude oil sales
volumes and higher natural gas prices partially offset by lower crude oil prices
and a decrease in natural gas contract recoveries. Natural gas sales volumes
improved 15 percent to 818 MMCF per day which increased revenues $54 million.
Oil sales volumes improved 12 percent to 40.6 MBbls per day which increased
revenues $34 million. Gas and oil sales volumes increased primarily due to
continued development of the Company's oil and gas properties and producing
property acquisitions in the second half of 1991. Average natural gas sales
prices increased 10 percent in 1992 to an average of $1.49 per MCF which
increased revenues $42 million. The revenue increases were partially offset by
lower oil sales prices which declined 7 percent in 1992 to $18.82 per barrel and
decreased revenues $19 million. In addition, natural gas contract recoveries
decreased $9 million in 1992.
Costs and Expenses were $901 million in 1992 compared to $860 million in
1991. The increase was primarily due to a $47 million, or 12 percent, increase
in production related expenses due principally to a 15 percent increase in
production levels.
Interest Expense was $79 million in 1992 compared to $90 million in 1991.
The decrease was primarily due to lower borrowings in 1992 and lower interest
rates on commercial paper. The Company's 1991 borrowings included amounts
borrowed from EPNG.
Other Income -- Net was $57 million income in 1992 compared to $17 million
income in 1991. The 1992 amount includes a $50 million gain on the sale of the
Company's interests in Plum Creek Timber Company, L.P. The 1991 amount includes
$18 million of interest income related to a cash refund of prior period income
taxes.
Income Taxes -- The tax rate was 13 percent in 1992 compared to 3 percent
in 1991. The increase was due primarily to 1992 pretax income being higher
relative to the nonconventional fuel tax credits generated.
OTHER MATTERS
The Company encounters competition in its business. See "Business and
Properties -- Other Matters" for further discussion of competition.
13
16
ITEM EIGHT
FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31,
--------------------------------------------
1993 1992 1991
---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues........................................... $1,248,957 $1,141,381 $1,036,295
Costs and Expenses................................. 993,152 901,033 859,646
---------- ---------- ----------
Operating Income................................... 255,805 240,348 176,649
Interest Expense................................... 72,799 79,196 90,344
Other Income -- Net................................ 124,432 56,887 16,813
---------- ---------- ----------
Income from Continuing Operations Before
Income Taxes..................................... 307,438 218,039 103,118
Provision for Income Taxes......................... 52,264 28,352 2,753
---------- ---------- ----------
Income from Continuing Operations.................. 255,174 189,687 100,365
Income from Discontinued Operations -- Net of
Income Taxes..................................... 1,138 68,141 105,016
---------- ---------- ----------
Net Income......................................... $ 256,312 $ 257,828 $ 205,381
---------- ---------- ----------
---------- ---------- ----------
Earnings per Common Share:
Continuing Operations............................ $ 1.95 $ 1.44 $ 0.75
Discontinued Operations.......................... 0.01 0.51 0.79
---------- ---------- ----------
Total............................................ $ 1.96 $ 1.95 $ 1.54
---------- ---------- ----------
---------- ---------- ----------
See accompanying Notes to Consolidated Financial Statements.
14
17
BURLINGTON RESOURCES INC.
CONSOLIDATED BALANCE SHEET
DECEMBER 31,
-----------------------
1993 1992
---------- ----------
(IN THOUSANDS)
ASSETS
Current Assets:
Cash and Short-term Investments..................................... $ 19,784 $ 31,729
Accounts Receivable................................................. 218,361 235,655
Inventories......................................................... 23,954 19,014
Other Current Assets................................................ 14,572 83,737
---------- ----------
276,671 370,135
---------- ----------
Oil and Gas Properties (Successful Efforts Method).................... 5,027,312 4,594,242
Other Properties...................................................... 540,342 566,769
---------- ----------
5,567,654 5,161,011
Accumulated Depreciation, Depletion and Amortization................ 1,631,941 1,416,731
---------- ----------
Properties -- Net................................................ 3,935,713 3,744,280
---------- ----------
Other Assets.......................................................... 235,336 355,328
---------- ----------
Total Assets................................................ $4,447,720 $4,469,743
---------- ----------
---------- ----------
LIABILITIES
Current Liabilities:
Accounts Payable.................................................... $ 202,565 $ 231,763
Taxes Payable....................................................... 58,372 60,133
Other Current Liabilities........................................... 38,680 57,742
---------- ----------
299,617 349,638
---------- ----------
Long-term Debt........................................................ 819,071 1,002,506
---------- ----------
Deferred Income Taxes................................................. 566,758 565,619
---------- ----------
Other Liabilities and Deferred Credits................................ 154,216 146,190
---------- ----------
Commitments and Contingent Liabilities
STOCKHOLDERS' EQUITY
Common Stock, Par Value $.01 Per Share (Authorized 325,000,000 Shares;
Issued 150,000,000 Shares).......................................... 1,500 1,500
Paid-in Capital....................................................... 2,936,934 2,950,722
Retained Earnings..................................................... 467,667 282,610
---------- ----------
3,406,101 3,234,832
Cost of Treasury Stock (1993, 20,316,521 Shares; 1992, 21,118,718
Shares)............................................................. 798,043 829,042
---------- ----------
Common Stockholders' Equity........................................... 2,608,058 2,405,790
---------- ----------
Total Liabilities and Common Stockholders' Equity........... $4,447,720 $4,469,743
---------- ----------
---------- ----------
See accompanying Notes to Consolidated Financial Statements.
15
18
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31,
--------------------------------------
1993 1992 1991
---------- ---------- ----------
(IN THOUSANDS)
Cash Flows From Continuing Operating Activities:
Income from Continuing Operations.................. $ 255,174 $ 189,687 $ 100,365
Adjustments to Reconcile Income to Net Cash
Provided
By Continuing Operating Activities:
Depreciation, Depletion and Amortization........ 285,258 256,003 223,974
Deferred Income Taxes........................... 2,438 19,041 32,159
Exploration Costs............................... 28,173 19,501 30,752
Working Capital Changes:
Accounts Receivable........................... 17,294 4,788 40,324
Inventories................................... (4,940) 12,800 12,504
Other Current Assets.......................... 69,165 (66,339) (5,145)
Accounts Payable.............................. (29,198) (69,300) (23,382)
Taxes Payable................................. (1,761) 46,197 (52,574)
Other Current Liabilities..................... (19,062) (11,038) 2,603
Gain on Sales and Other......................... (147,130) 31,227 13,669
--------- --------- ---------
Net Cash Provided By Continuing
Operating Activities..................... 455,411 432,567 375,249
--------- --------- ---------
Cash Flows From Continuing Investing Activities:
Additions to Properties............................ (553,384) (315,447) (500,156)
Proceeds from Sales and Property Dispositions...... 173,305 23,386 16,681
Other.............................................. (4,462) (62,224) (661)
--------- --------- ---------
Net Cash Used In Continuing Investing
Activities............................... (384,541) (354,285) (484,136)
--------- --------- ---------
Cash Flows From Continuing Financing Activities:
Proceeds from Long-term Financing.................. -- 150,000 970,247
Reduction in Long-term Debt........................ (183,610) (645,225) --
Dividends Paid..................................... (69,711) (85,489) (94,137)
Treasury Stock Transactions -- Net................. 30,999 (100,285) (229,428)
Financing Activities with EPNG -- Net.............. -- 525,361 (650,864)
Other.............................................. 85,794 (20,032) (4,550)
--------- --------- ---------
Net Cash Used In Continuing
Financing Activities..................... (136,528) (175,670) (8,732)
--------- --------- ---------
Decrease in Cash and Short-term Investments
from Continuing Operations......................... (65,658) (97,388) (117,619)
Cash Provided By Discontinued Operations............. 53,713 93,618 110,828
Cash and Short-term Investments:
Beginning of Year.................................. 31,729 35,499 42,290
--------- --------- ---------
End of Year........................................ $ 19,784 $ 31,729 $ 35,499
--------- --------- ---------
--------- --------- ---------
See accompanying Notes to Consolidated Financial Statements.
16
19
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY
COST OF COMMON
COMMON PAID-IN RETAINED TREASURY STOCKHOLDERS'
STOCK CAPITAL EARNINGS STOCK EQUITY
------ --------- -------- --------- -------------
(IN THOUSANDS)
Balance, January 1, 1991............ $1,500 $2,956,594 $565,519 $(499,329) $3,024,284
Net Income........................ 205,381 205,381
Cash Dividends ($.70 per share)... (92,851) (92,851)
Stock Purchases (6,743,300
shares)........................ (238,561) (238,561)
Stock Option Activity and Other... (871) 9,133 8,262
------ ---------- -------- --------- ----------
Balance, December 31, 1991.......... 1,500 2,955,723 678,049 (728,757) 2,906,515
Net Income........................ 257,828 257,828
Cash Dividends ($.60 per share)... (78,657) (78,657)
Distribution of EPNG Stock........ (574,610) (574,610)
Stock Purchases (3,484,200
shares)........................ (136,379) (136,379)
Stock Option Activity and Other... (5,001) 36,094 31,093
------ ---------- -------- --------- ----------
Balance, December 31, 1992.......... 1,500 2,950,722 282,610 (829,042) 2,405,790
Net Income........................ 256,312 256,312
Cash Dividends ($.55 per share)... (71,255) (71,255)
Stock Purchases (1,139,900
shares)........................ (45,280) (45,280)
Stock Option Activity and Other... (13,788) 76,279 62,491
------ ---------- -------- --------- ----------
Balance, December 31, 1993.......... $1,500 $2,936,934 $467,667 $(798,043) $2,608,058
------ ---------- -------- --------- ----------
------ ---------- -------- --------- ----------
See accompanying Notes to Consolidated Financial Statements.
17
20
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of Burlington
Resources Inc. and its majority owned subsidiaries (the "Company"). All
significant intercompany transactions have been eliminated in consolidation. The
financial statements for previous periods include certain reclassifications that
were made to conform to current presentation. Such reclassifications have no
impact on previously reported net income or stockholders' equity.
Cash and Short-term Investments
All short-term investments purchased with a maturity of three months or
less are considered cash equivalents. Cash equivalents are stated at cost, which
approximates market value.
Inventories
Inventories of materials, supplies and products are valued at the lower of
average cost or market.
Properties
Oil and gas properties are accounted for using the successful efforts
method. Under this method, all development costs and acquisition costs of proved
properties are capitalized and amortized on a units-of-production basis over the
remaining life of proved developed reserves and proved reserves, respectively.
Costs of drilling exploratory wells are initially capitalized, but charged to
expense if and when a well is determined to be unsuccessful. In addition, the
Company limits the total amount of unamortized capitalized costs to the value of
future net revenues, based on current prices and costs.
Costs of retired, sold or abandoned properties that constitute a part of an
amortization base are charged or credited, net of proceeds, to accumulated
depreciation, depletion and amortization. Gains or losses from the disposal of
other properties are recognized currently. Expenditures for maintenance, repairs
and minor renewals necessary to maintain properties in operating condition are
expensed as incurred. Major replacements and renewals are capitalized. All
properties are stated at cost.
Revenue Recognition
Gas revenues from field production are recorded on the entitlement method.
Under the entitlement method, revenue is recorded based on the Company's net
working interest in field production.
The Company's marketing activities include the purchase and resale of crude
oil and natural gas, in addition to the marketing of its own oil and gas
production. The costs and expenses of third party product marketing consist
primarily of the cost of product purchased and transportation costs. These costs
are netted against the related marketing revenues for financial reporting
purposes. The Consolidated Statement of Income includes net revenues related to
the marketing of third party oil and natural gas of $9 million, $17 million and
$18 million for 1993, 1992 and 1991, respectively. The volumes of third party
oil and gas marketed in those years are as follows:
1993 1992 1991
---- ---- ----
Oil (MBbls per day)..................................... 405 274 182
Gas (MMCF per day)...................................... 526 448 518
18
21
Income Taxes
In January 1993, the Company implemented Statement of Financial Accounting
Standard No. 109, Accounting for Income Taxes which did not have a material
impact on the Company's consolidated financial position or results of
operations. Income taxes are provided based on earnings reported for tax return
purposes in addition to a provision for deferred income taxes. Deferred income
taxes are provided in order to reflect the tax consequences in future years of
differences between the financial statement and tax basis of assets and
liabilities at each year end. Tax credits are accounted for under the
"flow-through" method, which reduces the provision for income taxes in the year
the tax credits first become available.
Earnings per Common Share
Earnings per common share is based on the weighted average number of common
shares outstanding during the year. The weighted average number of common shares
outstanding was 131 million, 132 million, and 134 million for the years 1993,
1992, and 1991, respectively.
2. RESTRUCTURING
Since its inception, the Company has been monetizing its nonstrategic
assets and reinvesting the net proceeds in domestic oil and gas reserves and in
the repurchase of its common stock.
In March 1992, the Company's wholly owned subsidiary, El Paso Natural Gas
Company ("EPNG"), completed an initial public offering of approximately 15
percent of its common stock and on May 13, 1992, the Company's Board of
Directors approved the June 30, 1992 distribution of the EPNG common stock owned
by the Company to its stockholders of record as of June 15, 1992. The
distribution was accounted for as a $575 million non-cash dividend of the
Company's investment in EPNG common stock.
In October 1989, the Company announced plans to sell the real estate assets
held by its subsidiary, Glacier Park Company. Proceeds from sales of real estate
assets through December 31, 1993 totaled approximately $429 million. In October
1992, the Company sold substantially all of its coal properties for $80 million.
In December 1993, the Company sold its majority interest in Burlington
Environmental Inc. for $28 million. The Company has disposed of virtually all of
its nonstrategic assets as of December 31, 1993.
Discontinued Operations
Discontinued operations revenues for the years ended December 31, 1992 and
1991 totaled $362 million and $735 million, respectively. There were no revenues
from discontinued operations in 1993. Proceeds from dispositions for the years
ended December 31, 1993, 1992 and 1991 totaled $62 million, $144 million and
$165 million, respectively. The Company realized $1 million, $68 million, and
$105 million of after-tax income net of $4 million, $49 million, and $66 million
of income taxes, from the discontinued operations and sales during 1993, 1992,
and 1991, respectively. The effective tax rates for the discontinued operations
differ from federal statutory rates primarily due to the effects of state and
foreign income taxes and adjustments to prior year estimates.
19
22
3. INCOME TAXES
The provision (benefit) for income taxes is as follows:
YEAR ENDED DECEMBER 31,
----------------------------------------
1993 1992 1991
-------- -------- --------
(IN THOUSANDS)
Current:
Federal............................................. $ 39,424 $ (1,985) $(32,938)
State............................................... 10,402 11,296 3,532
-------- -------- --------
49,826 9,311 (29,406)
-------- -------- --------
Deferred:
Federal............................................. (14,934) 12,375 19,591
Enacted federal tax rate change..................... 15,558 - -
State............................................... 1,814 6,666 12,568
-------- -------- --------
2,438 19,041 32,159
-------- -------- --------
Total....................................... $ 52,264 $ 28,352 $ 2,753
-------- -------- --------
-------- -------- --------
Reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
YEAR ENDED DECEMBER 31,
-------------------------------------
1993 1992 1991
----- ----- -----
Statutory rate.......................................... 35.0% 34.0% 34.0%
State income taxes net of federal tax benefit........... 2.6 5.4 10.3
Tax credits............................................. (25.0) (26.2) (44.9)
Enacted federal tax rate change......................... 5.1 -- --
Other................................................... (0.7) (0.2) 3.3
----- ----- ----
Effective rate................................ 17.0% 13.0% 2.7%
----- ----- ----
----- ----- ----
Deferred tax liabilities (assets) consist of the following:
YEAR ENDED DECEMBER 31,
---------------------------
1993 1992
--------- ----------
(IN THOUSANDS)
Deferred liabilities:
Excess of book over tax basis of properties.................... $ 696,351 $ 660,657
Deferred gains................................................. -- 17,085
Other.......................................................... 25,862 10,107
--------- ----------
722,213 687,849
--------- ----------
Deferred assets:
AMT credits carryover.......................................... (110,117) (59,280)
Financial accruals and provisions.............................. (29,057) (48,798)
Other.......................................................... (16,281) (14,152)
--------- ----------
(155,455) (122,230)
--------- ----------
Total.................................................. $ 566,758 $ 565,619
--------- ----------
--------- ----------
The above net deferred tax liabilities as of December 31, 1993 and 1992,
include deferred state income tax liabilities of approximately $78 million for
each of the years.
As of December 31, 1993, the Alternative Minimum Tax ("AMT") credits
carryover of approximately $110 million, related primarily to nonconventional
fuel tax credits, is available to offset future regular tax liabilities. The AMT
credits carryover has no expiration date. The benefit of the tax credits is
recognized in continuing operations for accounting purposes. The benefit is
reflected in the current tax provision to the extent the Company is able to
utilize the credits for tax return purposes.
20
23
4. LONG-TERM DEBT
Long-term Debt outstanding is as follows:
DECEMBER 31,
------------------------
1993 1992
-------- ----------
(IN THOUSANDS)
Commercial Paper.................................................... $ 70,994 $ 174,632
Notes, 6 7/8%, due 1999............................................. 150,000 150,000
Notes, 8 1/2%, due 2001............................................. 150,000 150,000
Debentures, 9 1/8%, due 2021........................................ 150,000 150,000
Notes, 9 5/8%, due 2000............................................. 150,000 150,000
Debentures, 9 7/8%, due 2010........................................ 150,000 150,000
Subordinated Debentures, 7%, due 2004............................... - 79,973
Other, including discounts -- net................................... (1,923) (2,099)
-------- ----------
Total..................................................... $819,071 $1,002,506
-------- ----------
-------- ----------
Excluding commercial paper, the Company has no debt maturities through
1998. The Company's commercial paper borrowings at December 31, 1993 had an
average interest rate of 3.53 percent.
In April 1993, the Subordinated Debentures were exchanged for shares of
Anadarko Petroleum Corporation common stock owned by the Company.
The Company and a group of banks have a $900 million Revolving Credit
Facility which expires in June 1996. Annual fees are 0.1875 percent of the
unused portion of the commitment. At the Company's option, interest on
borrowings is based on prime rates, domestic money market rates or Eurodollar
rates. The unused commitment under this agreement is available to cover certain
debt due within one year; therefore, commercial paper is classified as long-term
debt. Under the covenants of this agreement, debt cannot exceed 52.5 percent of
the sum of debt and tangible net worth (as defined in the agreement).
Additionally, tangible net worth cannot be less than $1.3 billion. As of
December 31, 1993, there were no borrowings outstanding under this facility
although borrowing capacity is reduced by outstanding commercial paper. The
Company had the capacity to borrow approximately $829 million under such credit
facility as of December 31, 1993. In addition, the Company has $500 million of
capacity under a shelf registration statement filed with the Securities and
Exchange Commission.
Lease Obligations
Lease rental expense was $13 million, $10 million and $13 million for the
years ended December 31, 1993, 1992 and 1991, respectively. Minimum annual
rental commitments are less than $15 million in any year and total approximately
$154 million at December 31, 1993.
5. ARRANGEMENTS WITH EPNG
Transportation
In 1993, 1992 and 1991, approximately 69 percent, 70 percent and 62
percent, respectively, of the Company's gas production was transported to direct
sale customers through EPNG's pipeline facilities. These transportation
arrangements are pursuant to EPNG's approved Federal Energy Regulatory
Commission tariffs applicable to all shippers. The Company expects to transport
a substantial portion of its future gas production through EPNG's pipeline
system.
Demand Charges
Contracts providing firm transportation services to the Company require the
payment of transportation demand charges. The Company paid $48 million of demand
charges in 1993 under transportation agreements with terms ranging from 1 to 13
years. Of these demand charges, approximately $40 million was paid to EPNG.
21
24
Other Transactions
Prior to the separation from EPNG in 1992, the Company maintained a
Commitment Agreement and Loan Agreements with EPNG. EPNG also participated in an
intercorporate cash management arrangement with the Company. Balances under
these facilities accrued interest at rates approximating short-term market
rates. Interest income on borrowings has been netted against interest expense on
excess cash advanced to the Company; the net amounts are included in Interest
Expense and totaled $169,000 and $37 million for the years 1992 and 1991,
respectively.
6. CAPITAL STOCK
On December 8, 1993, the Board of Directors approved the Company's 1993
Stock Incentive Plan (the "1993 Plan") and approved its submission to the
stockholders for their approval. The 1993 Plan succeeds the Company's 1988 Stock
Option Plan (the "1988 Plan"), which expired by its terms in May 1993, but
remains in effect for options granted prior to May 1993. The 1993 Plan provides
for the grant of stock options and stock appreciation rights or limited stock
appreciation rights (together "SARs").
Under the 1993 Plan and the 1988 Plan, options may be granted to officers
and key employees at fair market value at the date of grant, exercisable in
whole or part by the optionee after completion of one to three years of
continuous employment from the grant date.
Activity in the Company's stock option plans was as follows:
EXERCISE
OPTIONS PRICE PER SHARE
----------
Balance, December 31, 1991........................... 5,842,971 $ 12.92 to $48.31
Granted............................................ 325,600 35.88 to 38.00
Exercised.......................................... (934,182) 10.91 to 37.19
Cancelled.......................................... (330,481) 21.23 to 44.75
Adjusted for EPNG Disposition...................... 484,631 10.91 to 34.68
Converted to EPNG Options.......................... (754,710) 25.50 to 44.75
----------
Balance, December 31, 1992........................... 4,633,829 10.91 to 38.00
Granted............................................ 489,000 44.00 to 47.56
Exercised.......................................... (1,984,383) 10.91 to 34.68
Cancelled.......................................... (205,273) 31.83 to 46.44
----------
Balance, December 31, 1993........................... 2,933,173 $ 16.14 to $47.56
----------
----------
At December 31, 1993, 2,108,192 options were exercisable at prices of
$16.14 to $47.56 per share. At December 31, 1993, 9,597,600 shares are available
for additional grant under the 1993 Plan.
Stock Appreciation Rights
The Company has granted SARS in connection with certain outstanding
options. SARs are subject to the same terms and conditions as the related
options. A SAR entitles an option holder, in lieu of exercise of an option, to
receive a cash payment equal to the difference between the option price and the
fair market value of the Company's common stock based upon the plan provisions.
To the extent the SAR is exercised, the related option is cancelled and to the
extent the option is exercised the related SAR is cancelled. The outstanding
SARs are exercisable only under certain circumstances related to significant
changes in the ownership of the Company or its holdings, or certain changes in
the constitution of its Board of Directors. At December 31, 1993, there were
687,662 SARs outstanding related to stock options with exercise prices ranging
from $21.54 to $34.68 per share.
Preferred Stock and Preferred Stock Purchase Rights
The Company is authorized to issue 75,000,000 shares of preferred stock,
par value $.01 per share, and as of December 31, 1993 there were no shares
issued. On December 15, 1988, the Company's Board of Directors designated
3,250,000 of the authorized preferred shares as Series A Preferred Stock. Upon
issuance each one-hundredth of a share of Series A Preferred Stock will have
dividend and voting rights approximately equal to those of one share of Common
Stock of the Company. In addition, on
22
25
December 15, 1988, the Board of Directors declared a dividend distribution of
one Right for each outstanding share of Common Stock of the Company. The Rights
were amended on February 23, 1989. The Rights become exercisable if, without the
Company's prior consent, a person or group acquires securities having 15 percent
or more of the voting power of all of the Company's voting securities (an
"Acquiring Person") or ten days following the announcement of a tender offer
which would result in such ownership. Each Right, when exercisable, entitles the
registered holder to purchase from the Company one-hundredth of a share of
Series A Preferred Stock at a price of $95 per one-hundredth of a share, subject
to adjustment. If, after the Rights become exercisable, the Company were to be
involved in a merger or other business combination in which its Common Stock was
exchanged or changed or 50% or more of the Company's assets or earning power
were sold, each Right would permit the holder to purchase, for the exercise
price, stock of the acquiring company having a value of twice the exercise price
(the "Merger Right"). In addition, except for certain permitted offers, if any
person or group becomes an Acquiring Person, each Right would permit the
purchase, for the exercise price, of Common Stock of the Company having a value
of twice the exercise price (the "Subscription Right"). Rights owned by an
Acquiring Person are void as they relate to the Subscription Right or the Merger
Right. The Rights may be redeemed by the Company under certain circumstances
until their expiration date for $0.05 per Right.
7. PENSION PLANS
The Company's pension plans are non-contributory defined benefit plans
covering substantially all employees. The benefits are based on years of
credited service and highest five-year average compensation levels.
Contributions to the plans are based upon the Projected Unit Credit actuarial
funding method and are limited to amounts that are currently deductible for tax
purposes. Contributions are intended to provide not only for benefits attributed
to service to date but also for those expected to be earned in the future.
DECEMBER 31,
-----------------------
1993 1992
-------- --------
(IN THOUSANDS)
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested
benefits of $89,524 and $84,694................................ $ 91,349 $ 86,179
-------- --------
-------- --------
Projected benefit obligation for service to date.................. $127,403 $104,869
Plan assets, primarily marketable equity and debt
securities, at fair value......................................... (91,467) (87,867)
-------- --------
Funded status of projected benefit obligation....................... 35,936 17,002
Unrecognized net loss............................................... (47,006) (40,121)
Unamortized net transition obligation............................... (4,621) (7,730)
-------- --------
Net prepaid pension asset........................................... $(15,691) $(30,849)
-------- --------
-------- --------
The following information relates to the consolidated Company plans and
includes amounts related to EPNG for the first six months of 1992 and the full
year of 1991.
YEAR ENDED DECEMBER 31,
----------------------------------
1993 1992 1991
-------- -------- --------
(IN THOUSANDS)
Pension cost for the plans includes the following
components:
Service cost--benefits earned during the period......... $ 5,503 $ 9,817 $ 11,618
Interest cost on projected benefit obligation........... 8,926 28,757 47,393
Actual (return)/loss on plan assets..................... (7,857) 7,397 (85,958)
Net amortization and deferred amounts................... 3,851 (33,225) 45,029
-------- -------- --------
Net pension cost........................................ $ 10,423 $ 12,746 $ 18,082
-------- -------- --------
-------- -------- --------
The projected benefit obligation was determined using a weighted average
discount rate of 7.5 percent in 1993 and 8.5 percent in 1992, and a rate of
increase in future compensation levels of
23
26
5 percent. The expected long-term rate of return on plan assets was 9 percent in
1993 and 10 percent in 1992.
The Company's continuing operations pension expense was $10 million, $7
million, and $7 million in 1993, 1992 and 1991, respectively.
8. COMMITMENTS AND CONTINGENT LIABILITIES
The Company has certain commitments and uncertainties related to its normal
operations. Management believes that there are no commitments, uncertainties or
contingent liabilities that will have a materially adverse effect on the
consolidated financial position or results of operations of the Company.
9. OTHER INFORMATION
Other Income -- Net
A summary of significant items included in Other Income -- Net is as
follows:
YEAR ENDED DECEMBER 31,
--------------------------------
1993 1992 1991
-------- ------- -------
(IN THOUSANDS)
Gain on sale of Trust units.................. $107,800 $ - $ -
Sale of Plum Creek interests................. - 50,500 -
Gain on conversion of debt................... 19,108 - -
Interest on tax refund....................... - - 18,203
Other -- net................................. (2,476) 6,387 (1,390)
-------- ------- -------
$124,432 $56,887 $16,813
-------- ------- -------
-------- ------- -------
Other Current Assets
The December 31, 1992 balance of Other Current Assets includes $70 million
of notes receivable related to the December 1992 sale of the Company's interests
in Plum Creek Timber Company, L.P. The notes were collected in January 1993.
Supplemental Cash Flow Information
The following is additional information concerning supplemental disclosures
of cash flow activities:
YEAR ENDED DECEMBER 31,
--------------------------------
1993 1992 1991
-------- ------- -------
(IN THOUSANDS)
Interest Paid................................ $ 77,351 $73,702 $84,847
Income Taxes Paid (Received)--Net............ 39,948 (44,931) 28,560
In April 1993, holders of the Subordinated Debentures exchanged their
Debentures with a carrying value of approximately $80 million for shares of
Anadarko Petroleum Corporation common stock owned by the Company. This non-cash
exchange is reflected as such in the Statement of Cash Flows.
24
27
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of
Burlington Resources Inc.
We have audited the accompanying consolidated balance sheets of Burlington
Resources Inc. as of December 31, 1993 and 1992, and the related consolidated
statements of income, cash flows and common stockholders' equity for each of the
three years in the period ended December 31, 1993. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these 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 financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Burlington
Resources Inc. at December 31, 1993 and 1992, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1993, in conformity with generally accepted accounting
principles.
COOPERS & LYBRAND
Houston, Texas
January 12, 1994
25
28
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTAL OIL AND GAS DISCLOSURES--UNAUDITED
The supplemental data presented herein reflects information for all of the
Company's oil and gas producing activities.
Capitalized costs for oil and gas producing activities consist of the
following:
DECEMBER 31,
----------------------------
1993 1992
---------- ----------
(IN THOUSANDS)
Proved properties............................................... $4,985,501 $4,525,440
Unproved properties............................................. 41,811 68,802
---------- ----------
5,027,312 4,594,242
Accumulated depreciation, depletion and amortization............ 1,455,910 1,241,910
---------- ----------
Net capitalized costs................................. $3,571,402 $3,352,332
---------- ----------
---------- ----------
Costs incurred for oil and gas property acquisition, exploration and
development activities are as follows:
YEAR ENDED DECEMBER 31,
-----------------------------------
1993 1992 1991
--------- --------- ---------
(IN THOUSANDS)
Property acquisition:
Unproved................................................. $ 10,816 $ 10,266 $ 13,148
Proved................................................... 270,235 121,949 214,110
Exploration................................................ 17,159 11,872 25,563
Development................................................ 202,981 109,571 181,919
--------- --------- ---------
Total costs incurred............................. $ 501,191 $ 253,658 $ 434,740
--------- --------- ---------
--------- --------- ---------
Due to the completion of the Company's restructuring, all corporate
overhead is now allocated to operations. The results of operations for prior
years have been restated to conform to the current presentation of overhead
allocation. The restatements have no effect on consolidated results of
operations. Results of operations for oil and gas producing activities are as
follows:
YEAR ENDED DECEMBER 31,
----------------------------------
1993 1992 1991
-------- -------- --------
(IN THOUSANDS)
Net revenues............................................... $846,172 $756,005 $644,766
-------- -------- --------
Production costs........................................... 240,220 214,816 193,623
Exploration and impairment costs........................... 28,173 19,501 30,752
Operating expenses......................................... 119,603 104,549 97,975
Depreciation, depletion and amortization................... 248,505 223,495 197,899
-------- -------- --------
636,501 562,361 520,249
-------- -------- --------
Operating income........................................... 209,671 193,644 124,517
Income tax provision....................................... 12,858 14,622 (545)
-------- -------- --------
Results of operations for oil and gas producing
activities............................................... $196,813 $179,022 $125,062
-------- -------- --------
-------- -------- --------
26
29
The following table reflects estimated quantities of proved oil and gas
reserves. These reserves have been reduced for royalty interests owned by
others. These reserves, virtually all located in the United States, have been
estimated by the Company's petroleum engineers. The Company considers such
estimates to be reasonable, however due to inherent uncertainties estimates of
underground reserves are imprecise and subject to change over time as additional
information becomes available.
OIL GAS
(MMBBLS) (BCF)
-------- -----
PROVED DEVELOPED AND UNDEVELOPED RESERVES
January 1, 1991......................................................... 109.6 4,703
Revision of previous estimates....................................... 2.2 (51)
Extensions, discoveries and other additions.......................... 17.9 322
Production........................................................... (13.2) (259)
Purchases of reserves in place(a).................................... 25.7 351
Sales of reserves in place........................................... (1.1) (179)
-------- -----
December 31, 1991....................................................... 141.1 4,887
Revision of previous estimates....................................... 0.5 (24)
Extensions, discoveries and other additions.......................... 11.4 344
Production........................................................... (14.8) (299)
Purchases of reserves in place....................................... 17.7 165
Sales of reserves in place........................................... (0.4) (2)
-------- -----
December 31, 1992....................................................... 155.5 5,071
Revision of previous estimates....................................... (0.9) (30)
Extensions, discoveries and other additions.......................... 12.0 361
Production........................................................... (15.3) (336)
Purchases of reserves in place(b).................................... 17.5 306
Sales of reserves in place(c)........................................ (0.6) (151)
-------- -----
December 31, 1993....................................................... 168.2 5,221
-------- -----
-------- -----
PROVED DEVELOPED RESERVES
January 1, 1991......................................................... 101.5 3,558
December 31, 1991....................................................... 128.1 3,951
December 31, 1992....................................................... 141.8 4,204
December 31, 1993....................................................... 149.8 4,381
- ------------
(a) Includes 1.3 MMBbls and 185 BCF related to production properties
transferred to the Company from EPNG. These were cost-of-service properties
and the transfer was authorized by FERC in August 1991.
(b) Includes the reserves attributable to the purchase of 59 percent of the
Permian Basin Royalty Trust.
(c) Primarily the Burlington Resources Coal Seam Gas Royalty Trust transaction.
27
30
A summary of the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves is shown below. Future net cash flows
are computed using year-end sales prices, costs and statutory tax rates
(adjusted for tax credits and other items) that relate to the Company's existing
proved oil and gas reserves.
YEAR ENDED DECEMBER 31,
--------------------------
1993 1992
----------- -----------
(IN THOUSANDS)
Future cash inflows.......................................... $11,788,000 $11,714,000
Less related future:
Production costs........................................ 3,380,000 3,207,000
Development costs....................................... 377,000 455,000
Income taxes............................................ 1,403,000 1,494,000
----------- -----------
Future net cash flows.............................. 6,628,000 6,558,000
10% annual discount for estimated timing of cash flows..... 3,504,000 3,420,000
----------- -----------
Standardized measure of discounted future net cash
flows................................................. $ 3,124,000 $ 3,138,000
----------- -----------
----------- -----------
A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil and gas reserves is as follows:
1993 1992 1991
---------- ---------- ----------
(IN THOUSANDS)
January 1.............................................. $3,138,000 $2,616,000 $2,777,000
---------- ---------- ----------
Revisions of previous estimates:
Changes in prices and costs.......................... (208,000) 265,000 (604,000)
Changes in quantities................................ 9,000 (8,000) (9,000)
Changes in rate of production........................ (105,000) 104,000 (15,000)
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related
costs................................................ 180,000 186,000 188,000
Purchases of reserves in place......................... 260,000 183,000 278,000
Sales of reserves in place............................. (107,000) (4,000) (109,000)
Accretion of discount.................................. 375,000 323,000 357,000
Sales of oil and gas, net of production costs.......... (578,000) (522,000) (422,000)
Net change in income taxes............................. 91,000 (55,000) 184,000
Other.................................................. 69,000 50,000 (9,000)
---------- ---------- ----------
Net change............................................. (14,000) 522,000 (161,000)
---------- ---------- ----------
December 31............................................ $3,124,000 $3,138,000 $2,616,000
---------- ---------- ----------
---------- ---------- ----------
28
31
BURLINGTON RESOURCES INC.
QUARTERLY FINANCIAL DATA--UNAUDITED
1993 1992
----------------------------------------- ------------------------------------
4TH 3RD 2ND 1ST 4TH 3RD 2ND 1ST
-------- -------- ------- -------- ------- ------- ------ -------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues......................... $ 312 $ 309 $ 312 $ 316 $ 337 $ 284 $ 250 $ 270
Operating Income................. $ 64 $ 57 $ 69 $ 66 $ 90 $ 57 $ 40 $ 53
Income from Continuing
Operations(a).................. $ 52 $ 24 $ 134 $ 45 $ 96 $ 33 $ 31 $ 30
Discontinued Operations.......... -- -- -- 1 17 4 13 34
-------- -------- ------- -------- ------- ------- ------ -------
Net Income....................... $ 52 $ 24 $ 134 $ 46 $ 113 $ 37 $ 44 $ 64
-------- -------- ------- -------- ------- ------- ------ -------
-------- -------- ------- -------- ------- ------- ------ -------
Earnings per Common Share:
Continuing Operations.......... $ 0.40 $ 0.18 $ 1.02 $ 0.35 $ 0.73 $ 0.25 $ 0.23 $ 0.23
Discontinued Operations........ -- -- 0.01 -- 0.13 0.03 0.10 0.25
-------- -------- ------- -------- ------- ------- ------ -------
Earnings per Common Share........ $ 0.40 $ 0.18 $ 1.03 $ 0.35 $ 0.86 $ 0.28 $ 0.33 $ 0.48
-------- -------- ------- -------- ------- ------- ------ -------
-------- -------- ------- -------- ------- ------- ------ -------
Dividends Declared per Common
Share.......................... $ 0.1375 $ 0.1375 $0.1375 $ 0.1375 $ 0.125 $ 0.125 $0.175 $ 0.175
-------- -------- ------- -------- ------- ------- ------ -------
-------- -------- ------- -------- ------- ------- ------ -------
Common Stock Price Range(b):
High........................... 52 3/8 53 7/8 51 5/8 47 1/4 43 1/8 43 5/8 42 7/8 37 5/8
Low............................ 40 1/4 46 45 36 1/2 37 1/4 34 35 7/8 33
- ---------------
(a) The effective tax rate for the fourth quarter of 1993 generated an income
tax benefit primarily due to adjustments of prior year estimates. In
addition, the second and third quarter effective tax rates were higher than
the fourth quarter rate primarily due to income taxes recorded at a 39%
combined Federal and State marginal rate on non-recurring second quarter
gains and the effect of the third quarter enactment of a Federal income tax
rate increase.
(b) Common stock prices subsequent to the second quarter of 1992 reflect the
June 30, 1992 distribution of EPNG's common stock to the Company's
stockholders.
29
32
ITEM NINE
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None
PART III
ITEMS TEN AND ELEVEN
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND EXECUTIVE COMPENSATION
A definitive proxy statement to the 1994 Annual Meeting of Stockholders of
Burlington Resources Inc. will be filed no later than 120 days after the end of
the fiscal year with the Securities and Exchange Commission. The information set
forth therein under "Election of Directors" and "Executive Compensation" is
incorporated herein by reference. Executive Officers of the Company are listed
on page 9 of this Form 10-K.
ITEM TWELVE
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required is set forth under the caption "Election of Directors"
in the Proxy Statement for the 1994 Annual Meeting of Stockholders and is
incorporated herein by reference.
ITEM THIRTEEN
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required is set forth under the caption "Election of Directors"
in the Proxy Statement for the 1994 Annual Meeting of Stockholders and is
incorporated herein by reference.
30
33
PART IV
ITEM FOURTEEN
EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
PAGE
-----
FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION
Consolidated Statement of Income................................................. 14
Consolidated Balance Sheet....................................................... 15
Consolidated Statement of Cash Flows............................................. 16
Consolidated Statement of Common Stockholders' Equity............................ 17
Notes to Consolidated Financial Statements....................................... 18
Report of Independent Accountants................................................ 25
Supplemental Oil and Gas Disclosures............................................. 26
Quarterly Financial Data......................................................... 29
FINANCIAL STATEMENT SCHEDULES
Report of Independent Accountants............................................. A-1
V Property, Plant and Equipment................................................. A-2
VI Accumulated Depreciation, Depletion and Amortization of Property, Plant and
Equipment..................................................................... A-3
X Supplementary Income Statement Information.................................... A-4
AMENDED EXHIBIT INDEX................................................................. A-6
REPORTS ON FORM 8-K
The Company filed no reports on Form 8-K in the fourth quarter.
31
34
SIGNATURES REQUIRED FOR FORM 10-K
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Burlington Resources Inc. has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.
BURLINGTON RESOURCES INC.
By THOMAS H. O'LEARY
---------------------------------
Thomas H. O'Leary
Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of Burlington
Resources Inc. and in the capacities and on the dates indicated.
By THOMAS H. O'LEARY Chairman of the Board, January 12, 1994
------------------------------ President and Chief
Thomas H. O'Leary Executive Officer
GEORGE E. HOWISON Senior Vice President and January 12, 1994
------------------------------ Chief Financial Officer
George E. Howison
HAYS R. WARDEN Vice President, Controller January 12, 1994
------------------------------ and Chief Accounting
Hays R. Warden Officer
JOHN V. BYRNE Director January 12, 1994
------------------------------
John V. Byrne
JOHN C. CUSHMAN, III Director January 12, 1994
------------------------------
John C. Cushman, III
S. PARKER GILBERT Director January 12, 1994
------------------------------
S. Parker Gilbert
JAMES F. McDONALD Director January 12, 1994
------------------------------
James F. McDonald
DONALD M. ROBERTS Director January 12, 1994
------------------------------
Donald M. Roberts
WALTER SCOTT, JR. Director January 12, 1994
------------------------------
Walter Scott, Jr.
WILLIAM E. WALL Director January 12, 1994
------------------------------
William E. Wall
32
35
REPORT OF MANAGEMENT
To the Stockholders and Directors of Burlington Resources Inc.:
The accompanying financial statements have been prepared by management in
conformity with generally accepted accounting principles. The fairness and
integrity of these financial statements, including any judgments, estimates and
selection of appropriate generally accepted accounting principles, are the
responsibility of management, as is all other information presented in this
Annual Report.
In the opinion of management, the financial statements are fairly stated,
and, to that end, the Company maintains a system of internal control which:
provides reasonable assurance that transactions are recorded properly for the
preparation of financial statements; safeguards assets against loss or
unauthorized use; maintains accountability for assets; and requires proper
authorization and accounting for all transactions. Management is responsible for
the effectiveness of internal control. This is accomplished through established
codes of conduct, accounting and other control systems, policies and procedures,
employee selection and training, appropriate delegation of authority and
segregation of responsibilities. To further ensure compliance with established
standards and related control procedures, the Company conducts a substantial
corporate audit program.
Our independent certified public accountants provide an objective
independent review by their audit of the Company's financial statements. Their
audit is conducted in accordance with generally accepted auditing standards and
includes a review of internal accounting control to the extent deemed necessary
for the purposes of their audit.
The Audit Committee of the Board of Directors meets regularly with the
independent certified public accountants, management, and corporate audit to
review the work of each and to ensure that each is properly discharging its
financial reporting and internal control responsibilities. To ensure complete
independence, the certified public accountants and corporate audit have full and
free access to the Audit Committee to discuss the results of their audits, the
adequacy of internal accounting controls and the quality of financial reporting.
January 12, 1994
George E. Howison
Senior Vice President and
Chief Financial Officer
Hays R. Warden
Vice President, Controller and
Chief Accounting Officer
33
36
DIRECTORS OF BURLINGTON RESOURCES INC.
John V. Byrne(1) James F. McDonald(1) Walter Scott, Jr.(2)
President President and Chief Chairman and President
Oregon State University Executive Officer Peter Kiewit Sons', Inc.
Scientific-Atlanta, Inc.
William E. Wall(2)
John C. Cushman, III(1) Thomas H. O'Leary Of Counsel, Siderius Lonergan
President and Chief Chairman of the Board,
Executive Officer President and (1) Audit Committee
Cushman Realty Corporation Chief Executive Officer (2) Compensation and
Burlington Resources Inc. Nominating Committee
S. Parker Gilbert(2)
Retired Chairman and Donald M. Roberts(1)
Managing Director Vice Chairman and Treasurer
Morgan Stanley Group Inc. United States Trust
Company of New York and
U.S. Trust Corporation
CORPORATE INFORMATION
PRINCIPAL CORPORATE OFFICE STOCK EXCHANGE LISTINGS Additional copies of this Annual Report
Burlington Resources Inc. New York Stock Exchange are available, without charge, by
5051 Westheimer, Suite 1400 Symbol: BR writing or calling:
P.O. Box 4239
Houston, Texas 77056 ANNUAL MEETING Corporate Secretary
(713) 831-1600 The Annual Meeting of Burlington Resources Inc.
Stockholders will be in 5051 Westheimer, Suite 1400
STOCK TRANSFER AGENT AND REGISTRAR Seattle, Washington, P.O. Box 4239
The First National Bank on March 17, 1994. Houston, Texas 77056
of Boston Formal notice of the (713) 831-1600
Shareholder Services meeting will be mailed
Mail Stop: 45-02-09 in advance.
P.O. Box 644
Boston, Massachusetts 02102
(617) 575-2900
34
37
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Directors of
Burlington Resources Inc.
Our report on the consolidated financial statements of Burlington Resources
Inc. as of December 31, 1993 and 1992, and for each of the three years in the
period ended December 31, 1993, is included on page 25 of this 1993 Annual
Report on Form 10-K. In connection with our audits of such financial statements,
we have also audited the related financial statement schedules listed on Page 31
of this Annual Report on Form 10-K.
In our opinion, the financial statement schedules referred to above, when
considered in relation to the basic financial statements taken as a whole,
present fairly, in all material respects, the information required to be
included therein.
COOPERS & LYBRAND
Houston, Texas
January 12, 1994
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38
SCHEDULE V
BURLINGTON RESOURCES INC.
PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991
(IN THOUSANDS)
OTHER
BALANCE AT CHANGES BALANCE
BEGINNING ADDITIONS ADD AT END
CLASSIFICATION OF PERIOD AT COST RETIREMENTS (DEDUCT) OF PERIOD
- --------------------------- ----------- --------- ----------- --------- ----------
1993:
Oil and Gas Properties... $ 4,594,242 $ 501,191 $ 93,085 $ (14,343)(1) $5,027,312
39,307(2)
Plants and Pipelines..... 408,437 33,327 536 (39,307)(2) 401,921
Other.................... 158,332 18,866 38,777 138,421
----------- --------- ----------- --------- ----------
Total............ $ 5,161,011 $ 553,384 $ 132,398 $ (14,343) $5,567,654
----------- --------- ----------- --------- ----------
----------- --------- ----------- --------- ----------
1992:
Oil and Gas Properties... $ 4,416,155 $ 253,658 $ 75,902 $ (8,509)(1) $4,594,242
8,840
Plants and Pipelines..... 380,876 49,423 21,862 408,437
Other.................... 145,757 12,366 3,788 3,997 158,332
----------- --------- ----------- --------- ----------
Total............ $ 4,942,788 $ 315,447 $ 101,552 $ 4,328 $5,161,011
----------- --------- ----------- --------- ----------
----------- --------- ----------- --------- ----------
1991:
Oil and Gas Properties... $ 3,650,571 $ 434,740 $ 59,118 $ (12,452)(1) $4,416,155
402,414(3)
Plants and Pipelines..... 335,525 55,476 3,449 (6,676) 380,876
Other.................... 550,776 9,940 71,982 6,455 145,757
(349,432)(3)
----------- --------- ----------- --------- ----------
Total............ $ 4,536,872 $ 500,156 $ 134,549 $ 40,309 $4,942,788
----------- --------- ----------- --------- ----------
----------- --------- ----------- --------- ----------
- ---------------
(1) Exploration costs.
(2) Transfers.
(3) Primarily transfers from El Paso Natural Gas Company.
See accompanying Notes to Consolidated Financial Statements
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39
SCHEDULE VI
BURLINGTON RESOURCES INC.
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991
(IN THOUSANDS)
ADDITIONS OTHER
BALANCE AT CHARGED TO CHANGES BALANCE
BEGINNING COSTS AND ADD AT END
CLASSIFICATION OF PERIOD EXPENSES RETIREMENTS (DEDUCT) OF PERIOD
- ---------------------------- ----------- ------------ ------------- --------- -----------
1993:
Oil and Gas Properties.... $ 1,241,910 $248,505 $63,150 $13,830(1) $ 1,455,910
14,815(2)
Plants and Pipelines...... 102,483 19,488 617 (14,815)(2) 106,539
Other..................... 72,338 17,265 20,111 69,492
----------- ------------ ------------- --------- -----------
Total............. $ 1,416,731 $285,258 $83,878 $13,830 $ 1,631,941
----------- ------------ ------------- --------- -----------
----------- ------------ ------------- --------- -----------
1992:
Oil and Gas Properties.... $ 1,066,695 $223,495 $65,500 $10,992(1) $ 1,241,910
6,228
Plants and Pipelines...... 105,101 15,772 18,024 (366) 102,483
Other..................... 59,365 16,736 3,726 (37) 72,338
----------- ------------ ------------- --------- -----------
Total............. $ 1,231,161 $256,003 $87,250 $16,817 $ 1,416,731
----------- ------------ ------------- --------- -----------
----------- ------------ ------------- --------- -----------
1991:
Oil and Gas Properties.... $ 840,154 $197,899 $43,502 $18,300(1) $ 1,066,695
53,844(3)
Plants and Pipelines...... 94,111 13,471 2,481 105,101
Other..................... 120,590 12,604 22,127 (51,702)(3) 59,365
----------- ------------ ------------- --------- -----------
Total............. $ 1,054,855 $223,974 $68,110 $20,442 $ 1,231,161
----------- ------------ ------------- --------- -----------
----------- ------------ ------------- --------- -----------
- ---------------
(1) Exploration costs.
(2) Transfers.
(3) Primarily transfers from El Paso Natural Gas Company.
See accompanying Notes to Consolidated Financial Statements
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40
SCHEDULE X
BURLINGTON RESOURCES INC.
SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS)
CHARGED TO
COSTS AND
ITEM EXPENSES
- ---------------------------------------------------------------------------------- ----------
1993
Maintenance and repairs......................................................... $ 6,168
Taxes, other than payroll and income taxes:
Property..................................................................... 19,438
Production and other......................................................... 58,872
1992
Maintenance and repairs......................................................... $ 5,265
Taxes, other than payroll and income taxes:
Property..................................................................... 18,463
Production and other......................................................... 51,895
1991
Maintenance and repairs......................................................... $ 4,120
Taxes, other than payroll and income taxes:
Property..................................................................... 15,192
Production and other......................................................... 39,816
- ---------------
Note: Items omitted are either less than 1 percent of consolidated revenues
or disclosed in the Consolidated Financial Statements or notes
thereto.
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41
UNDERTAKINGS
For the purposes of complying with the amendments to the rules governing
Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the
registrant hereby undertakes as follows, which undertaking shall be incorporated
by reference into the registrant's Registration Statements on Form S-8, Nos.
33-22493 (filed June 15, 1988), 33-25807 (filed December 1, 1988), 33-26024
(filed December 12, 1988), 2-97533 (filed December 29, 1989), 33-33626 (filed
March 1, 1990), and 33-46518 (filed March 19, 1992):
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
registrant pursuant to the foregoing provisions, or otherwise, the registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities Act
of 1933 and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
registrant of expenses incurred or paid by a director, officer or controlling
person of the registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the registrant will, unless in
the opinion of its counsel the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in the Securities
Act of 1933 and will be governed by the final adjudication of such issue.
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42
BURLINGTON RESOURCES INC.
AMENDED EXHIBIT INDEX
The following exhibits are filed as part of this report.
EXHIBIT PAGE
NUMBER DESCRIPTION NUMBER
- ------- -------------------------------------------------------------------------- ------
3.1 Certificate of Incorporation of Burlington Resources Inc., as amended
(Exhibit 3.1 to Form 8, filed March 1990)................................. *
3.2 By-Laws of Burlington Resources Inc. as amended (Exhibit 3.2 to Form 8,
filed March 1993)......................................................... *
4.1 Form of Rights Agreement dated as of December 16, 1988, between Burlington
Resources Inc. and The First National Bank of Boston which includes, as
Exhibit A thereto, the form of Certificate of Designation specifying terms
of the Series A Preferred Stock and, as Exhibit B thereto, the form of
Rights Certificate (Exhibit 1 to Form 8-A, filed December 1988)........... *
Amendment No. 1 to Form of Rights Agreement (Exhibit 2 to Form 8-K, filed
March 1989)............................................................... *
4.2 Indenture, dated as of June 15, 1990, between the registrant and Citibank,
N.A., including Form of Debt Securities (Exhibit 4.2 to Form 8, filed
February 1992)............................................................ *
4.3 Indenture, dated as of October 1, 1991, between the registrant and
Citibank, N.A., including Form of Debt Securities (Exhibit 4.3 to Form 8,
filed February 1992)...................................................... *
4.4 Indenture, dated as of April 1, 1992, between the registrant and Citibank,
N.A., including Form of Debt Securities (Exhibit 4.4 to Form 8, filed
March 1993)............................................................... *
10.1 Tax Sharing Agreement between the registrant and BNI, dated as of May 26,
1988 (Exhibit 10.1 to Form S-1, No. 33-22267, filed June 1988)............ *
10.2 The 1988 Burlington Resources Inc. Stock Option Incentive Plan as amended
(Exhibit 10.4 to Form 8, filed March 1993)................................ *
10.3 Burlington Resources Inc. Incentive Compensation Plan as amended (Exhibit
10.5 to Form 8, filed March 1993)......................................... *
10.4 Burlington Resources Inc. Senior Executive Survivor Benefit Plan dated as
of January 1, 1989 (Exhibit 10.11 to Form 8, filed February 1989)......... *
10.5 Burlington Resources Inc. Deferred Compensation Plan dated as of January
1, 1989 (Exhibit 10.12 to Form 8, filed February 1989).................... *
Amendment No. 1 to Burlington Resources Inc. Deferred Compensation Plan
(Exhibit 10.12 to Form 8, filed February 1991)............................ *
10.6 Burlington Resources Inc. Supplemental Benefits Plan as amended and
restated January 1, 1990 (Exhibit 10.14 to Form 8, filed February 1992)... *
10.7 Employment Contracts between Burlington Resources Inc. and Richard M.
Bressler, Thomas H. O'Leary, Travis H. Petty and Donald W. Clayton
(Exhibit 10.14 to Form 8, filed February 1989)............................ *
Amendments to Employment Contracts between Burlington Resources Inc. and
Thomas H. O'Leary and Travis H. Petty (Exhibit 10.14 to Form 8, filed
March 1990)............................................................... *
Amendments to Employment Contracts between Burlington Resources Inc. and
Thomas H. O'Leary and Donald W. Clayton (Exhibit 10.15 to Form 8, filed
February 1992)............................................................ *
10.8 Employment Contracts between Meridian Oil Inc. and George E. Howison and
Bobby S. Shackouls........................................................
Amendment to Employment Contract between Burlington Resources Inc. and
Thomas H. O'Leary.........................................................
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43
EXHIBIT PAGE
NUMBER DESCRIPTION NUMBER
- ------- ------
10.9 Burlington Resources Inc. Compensation Plan for Non-Employee Directors
(Exhibit 10.18 to Form S-8, No. 33-33626, filed March 1990)............... *
Amendment No. 1 to Burlington Resources Inc. Compensation Plan for Non-
Employee Directors (Exhibit 10.19 to Form 8, filed February 1992)......... *
10.10 Burlington Resources Inc. Key Executive Severance Protection Plan as
amended June 8, 1989 (Exhibit 10.20 to Form 8, filed February 1992)....... *
10.11 Burlington Resources Inc. Retirement Savings Plan (Exhibit Amendment No. 1
to Form S-8, No. 2-97533, filed December 1989)............................ *
Amendment No. 1 to Burlington Resources Inc. Retirement Savings Plan (Ex-
hibit 10.15 to Form 8, filed March 1993).................................. *
Amendment No. 2 to Burlington Resources Inc. Retirement Savings Plan (Ex-
hibit 10.21 to Form 8, filed February 1992)............................... *
Amendment No. 3 to Burlington Resources Inc. Retirement Savings Plan (Ex-
hibit 10.15 to Form 8, filed March 1993).................................. *
10.12 Burlington Resources Inc. Retirement Income Plan for Directors (Exhibit
10.21 to Form 8, filed February 1991)..................................... *
10.13 Burlington Resources Inc. 1991 Director Charitable Award Plan, dated as of
January 16, 1991 (Exhibit 10.22 to Form 8, filed February 1991)........... *
10.14 Master Separation Agreement and documents related thereto dated January
15, 1992 by and among Burlington Resources Inc., El Paso Natural Gas
Company and Meridian Oil Holding Inc., including exhibits (Exhibit 10.24
to Form 8, filed February 1992)........................................... *
10.15 Burlington Resources Inc. 1992 Stock Option Plan for Non-employee
Directors (Exhibit 28.1 of Form S-8, No. 33-46518, filed March 1992)...... *
10.16 Burlington Resources Inc. Key Executive Retention Plan and Amendments No.
1 and 2 (Exhibit 10.20 to Form 8, filed March 1993)....................... *
10.17 Amendments No. 3 and 4 to the Burlington Resources Inc. Key Executive
Retention Plan............................................................
10.18 Burlington Resources Inc. 1992 Performance Share Unit Plan (Exhibit 10.21
to Form 8, filed March 1993).............................................. *
10.19 Burlington Resources Inc. Severance Plan and Amendments No. 1 and 2 (Ex-
hibit 10.22 to Form 8, filed March 1993).................................. *
10.20 Amendments No. 3, 4 and 5 to the Burlington Resources Inc. Severance
Plan......................................................................
10.21 $900 million Revolving Credit Agreement, dated as of April 21, 1992,
between Burlington Resources Inc. and Citibank, N.A., as agent (Exhibit
10.23 to Form 8, filed March 1993)........................................ *
10.22 Burlington Resources Inc. 1993 Stock Incentive Plan.......................
11.1 Earnings Per Share Computation............................................
12.1 Ratio of Earnings to Fixed Charges........................................
21.1 Subsidiaries of Registrant................................................
23.1 Consent of Coopers & Lybrand..............................................
- ---------------
*Exhibit incorporated by reference as indicated.
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