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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, 1994

( ) 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) 624-9500

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,
1994: $4,427,813,600

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, 1994, Shares Outstanding: 126,508,960

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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2

BURLINGTON RESOURCES INC.

TABLE OF CONTENTS

PAGE
----

PART I
Items One and Two

Business and Properties......................................................... 1

Employees....................................................................... 9

Item Three

Legal Proceedings............................................................... 9

Item Four

Submission of Matters to a Vote of Security Holders............................. 9

Executive Officers of the Registrant............................................ 10

PART II

Item Five

Market for Registrant's Common Equity and Related Stockholder Matters........... 11

Item Six

Selected Financial Data......................................................... 11

Item Seven

Management's Discussion and Analysis of Financial Condition and Results of
Operations.................................................................... 12

Item Eight

Financial Statements and Supplementary Financial Information.................... 16

Item Nine

Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.................................................................... 35

PART III

Items Ten and Eleven

Directors and Executive Officers of the Registrant and Executive Compensation... 35

Item Twelve

Security Ownership of Certain Beneficial Owners and Management.................. 35

Item Thirteen

Certain Relationships and Related Transactions.................................. 35

PART IV

Item Fourteen

Exhibits, Financial Statement Schedules and Reports on Form 8-K................. 36

PART I

ITEMS ONE AND TWO

BUSINESS AND PROPERTIES

Burlington Resources Inc. ("BR") is a holding company engaged, through its
principal subsidiary, Meridian Oil Inc. and its affiliated companies (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 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 6.6 TCFE at December 31, 1994.

From its inception in 1988 through 1993, BR restructured its assets to
become solely an oil and gas exploration and production company. The
restructuring included the sale of non-strategic assets (real estate, minerals
and forest products) resulting in cumulative gross proceeds of $1.4 billion and
the 1992 spin-off of El Paso Natural Gas Company ("EPNG"). The net proceeds from
non-strategic asset sales were reinvested in domestic oil and gas reserves and
in the repurchase of the Company's common stock.

For definitions of certain oil and gas terms used herein, see "Certain
Definitions" on page 9.

GENERAL INFORMATION

The Company's objective is to build long-term shareholder value by
continuing to grow and enhance its asset base. To achieve this objective, the
Company's strategy is to increase production, reserves, earnings and cash flow
through acquisitions, development and exploration of high potential properties
and application of advanced technologies.

The Company is engaged in oil and gas operations located principally in the
San Juan Basin, the Gulf Coast Basin, the Permian Basin, the Anadarko Basin, the
Black Warrior Basin and the Williston Basin. Virtually all of the Company's oil
and gas production is from 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 mineral acreage in this area with over 1 million
net acres under its control. The Company has an interest in over 11,000 wells
and currently operates approximately 7,200 of these wells. Approximately 61
percent of the Company's reserves are located in this basin. The Company's daily
net production at year end 1994 in this basin exceeded 650 MMCF of gas per day,
representing approximately 60 percent of the Company's total daily gas
production at year end 1994.

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. The
Company's net coal seam production from approximately 1,200 wells exceeded 350
MMCF of gas per day at year end 1994.

In order to manage production more effectively, improve recovery of
reserves and remove impurities, the Company owns and operates the Val Verde
plant and gathering system which includes approximately 400 miles of gathering
lines and eight compressor stations to gather and treat coal seam gas in the San
Juan Basin. The Company also owns and operates a fractionation plant located in
McKinley County, New Mexico.

1
4

GULF COAST BASIN. The Gulf Coast Basin includes onshore and offshore 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.

Offshore

In 1994, the Company established an operating position in the shallow
offshore waters of the Gulf of Mexico through its acquisition of Diamond
Shamrock Offshore Partners Limited Partnership. The Company has an interest in
99 leases in offshore Federal and State waters and operates 40 of these leases.
As of year end 1994, total net production attributable to offshore properties
was over 110 MMCF of gas per day and 5 MBbls of oil per day.

Onshore

The Company's onshore activities in the Gulf Coast Basin are primarily
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 1994, 11 horizontal
wells were drilled in these fields at a net cost of approximately $3 million. As
of year end 1994, net production from the Luling and Darst Creek Fields was
approximately 4 MBbls of oil per day, with 43 percent of this production
attributable to horizontal wells drilled since these properties were acquired in
1989.

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 these
wells resulting in net production at year end 1994 of approximately 17 MBbls of
oil per day and 140 MMCF of gas per day.

The most productive structural feature in the Permian Basin is the Central
Basin Platform in which the Company controls 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. The Company operates over 1,600 wells in the Waddell
Ranch resulting in net production of approximately 4 MBbls of oil per day and 21
MMCF of gas per day at year end 1994.

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
1994, the Company participated in the drilling of 50 wells at a net cost of
approximately $17 million. As of year end 1994, the Company operated over 480
wells in the Canyon Sand trend with net production of approximately 50 MMCF of
gas 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 controls approximately 74,000 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 1994 activity focused on the development of oil from the
Delaware Sand trend at a depth of approximately 8,500 feet. During 1994, the
Company participated in the drilling of 30 Delaware Sand wells at a net cost of
approximately $18 million.

2
5

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. In 1994, over 170 square miles were surveyed for a total
investment of approximately $5 million. The analysis of this data has resulted
in the drilling of 10 wells including 2 horizontal wells. Additional 3D seismic
data is continually being acquired in order to exploit new and existing oil and
gas opportunities.

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 controls over 520,000 net acres
with the majority located in western Oklahoma. As of year end 1994, the Company
operated 828 wells in this basin and total net production was over 130 MMCF of
gas per day. The Company has been concentrating its Anadarko Basin activity in
the Elk City and Strong City Fields where the application of 3D seismic
technology, computerized modeling and advanced reservoir stimulation are
enhancing the value of these assets. The primary producing horizons in these
fields are the Morrow, Springer and Cherokee Red Fork formations. During 1994,
the Company participated in the drilling of 40 wells to these formations at a
net cost of approximately $23 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. In 1994, the
Company divested nearly all of its wells and gathering systems associated with
conventional producing formations in this basin. The Company's current
operations are primarily concentrated on developing coal seam gas reserves. The
Company controls over 138,000 net acres in the coal seam gas play near
Tuscaloosa, Alabama and currently has approximately 20,000 net acres developed
with 128 wells producing over 14 MMCF of gas per day at year end 1994. During
1994, the Company participated in the drilling of 52 coal seam wells in the
Black Warrior Basin at a net cost of approximately $20 million.

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 million net acres, primarily in the U.S. portion of the basin, through both
mineral and leasehold interests.

The Company continues its development activity in the Williston Basin of
North Dakota and the adjacent Cedar Creek anticline of Montana through the use
of horizontal drilling technology. During 1994, the Company participated in the
completion of 34 horizontal wells in the two trends at a net cost of
approximately $27 million.

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 $.52 to $1.01 per million British Thermal Unit depending on fuel
source. The Company earned approximately $84 million of tax credits in 1994.

3
6

CAPITAL EXPENDITURES AND MAJOR PROJECTS

The Company's capital expenditures were as follows:

YEAR ENDED DECEMBER 31,
----------------------------------
1994 1993 1992
-------- -------- --------
(IN THOUSANDS)

Oil and Gas Activities........................... $810,466 $501,191 $253,658
Plants and Pipelines............................. 36,026 33,327 49,423
Administrative................................... 35,153 18,866 12,366
-------- -------- --------
Total.................................. $881,645 $553,384 $315,447
======== ======== ========

Capital expenditures for oil and gas activities in 1994 of $810 million
include 59 percent for proved property acquisitions, 34 percent for
developmental drilling and 7 percent for exploration. Included in capital
expenditures for oil and gas activities are exploration costs expensed under the
successful efforts method of accounting and capitalized interest.

Drilling Activity

Drilling activity in 1994 was principally in the San Juan, Gulf Coast,
Permian, Anadarko, Black Warrior and Williston basins.

The following table sets forth the Company's net productive and dry wells.

YEAR ENDED DECEMBER 31,
--------------------------------
1994 1993 1992
------ ------ ------

Productive wells:
Exploratory.............................. 15.9 7.2 5.6
Development.............................. 342.2 243.7 107.3
----- ----- -----
358.1 250.9 112.9
----- ----- -----
Dry wells:
Exploratory.............................. 3.7 9.0 9.9
Development.............................. 13.3 11.6 8.1
----- ----- -----
17.0 20.6 18.0
----- ----- -----
Total net wells.................. 375.1 271.5 130.9
===== ===== =====

As of December 31, 1994, 18 gross wells, representing approximately 10.3
net wells, were being drilled.

Acquisitions

As a component of its overall growth strategy, the Company continued making
acquisitions of producing properties during 1994. A total of 497 BCFE of oil and
gas reserves was acquired by the Company at a cost of approximately $479
million. Approximately 50 percent of the reserves acquired during the year were
in the Gulf Coast basin. Production associated with the properties acquired was
approximately 125 MMCF of gas per day and 6 MBbls of oil per day at year end
1994.

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 developed by the utilization
of both conventional and advanced technologies.

4
7

Asset Rationalization

In an effort to maintain its high quality asset base, the Company continues
to divest marginal and non-strategic oil and gas properties. During 1994, the
Company divested over 1,350 working interest wells comprising approximately 4
percent of the Company's working interest well inventory. In addition, the
Company conveyed its working interests in certain coal seam gas wells in
November 1994. The net proceeds after tax from all 1994 property divestitures
were approximately $89 million.

PRODUCTIVE WELLS, DEVELOPED AND UNDEVELOPED ACREAGE

Working interests in productive wells, developed acreage and undeveloped
leasehold acreage at December 31, 1994 were as follows:

PRODUCTIVE WELLS
- --------------------------------------
OIL GAS DEVELOPED ACRES UNDEVELOPED ACRES
- ----------------- ----------------- ------------------------ ------------------------
GROSS NET GROSS NET GROSS NET GROSS NET
- ------- ------ ------- ------ ---------- ---------- ---------- ----------

15,795 4,823 15,732 9,498 6,015,000 3,151,000 2,838,000 1,760,000

Included in the productive wells data are 1,221 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 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. The Company's average natural
gas price includes amounts from the sale of NGLs, less the actual costs incurred
to gather, treat, process and transport the hydrocarbons to market. Production
and prices were as follows:

YEAR ENDED DECEMBER 31,
--------------------------------
1994 1993 1992
------ ------ ------

Production:
Gas (MMCF per day)................................. 1,052 920 818
Oil (MBbls per day)................................ 45.6 41.9 40.6
Average sales prices:
Gas per MCF........................................ $ 1.65 $ 1.87 $ 1.64
Oil per barrel..................................... 15.66 16.71 18.83
Average production costs per MCFE.................... .54 .56 .55
Depreciation, depletion and amortization rates per
MCFE............................................... .62 .58 .58

In 1994, 1993 and 1992, approximately 66 percent, 69 percent and 70
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.

5
8

RESERVES

The following table sets forth estimates by the Company's petroleum
engineers of proved oil and gas reserves at December 31, 1994. These reserves
have been reduced for royalty interests owned by others.

GAS OIL TOTAL
(BCF) (MMBBLS) (BCFE)
------ -------- ------

Proved Developed Reserves................... 4,584 161.9 5,556
Proved Undeveloped Reserves................. 917 22.2 1,050
----- ----- -----
Total Proved Reserves............. 5,501 184.1 6,606
===== ===== =====

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."

INTRASTATE PIPELINES AND NGLS

The Company owns and operates two intrastate natural gas pipeline systems
in west Texas totaling 426 miles and gathering systems in several states. 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,
---------------------------
1994 1993 1992
---- ----- ----

(BCF)
Annual intrastate natural gas throughput:
Company-owned production................ 16 19 25
Third party production.................. 49 41 45
Third party gas transportation and
gathering.................................. 132 139 104
--- --- ---
Total.............................. 197 199 174
=== ==== ===

The Company is engaged in the fractionation, transportation and marketing
of NGLs which are sold to a variety of distributors, refiners and petrochemical
users. NGL sales were 12.7 MMBbls, 14.9 MMBbls and 14.5 MMBbls, for the years
ended December 31, 1994, 1993 and 1992, respectively.

MARKETING

Marketing Strategy. In pursuit of its strategy to build long-term
shareholder value in a volatile product pricing environment for domestic
hydrocarbons, the Company will continue to develop premium markets for its
production. In addition, the Company adds value through such activities as
processing, gathering, trucking, trading, storing and transporting hydrocarbons
for both itself and third parties. Financial instruments may be used from time
to time in order to hedge the price of a portion of the Company's production.

Wellhead Marketing. The Company's oil and gas production is sold on the
spot market and under short-term contracts at market responsive prices.
Substantially all of the Company's oil and gas production is sold to Meridian
Oil Trading Inc. ("MOTI"), a wholly-owned marketing subsidiary of the Company.

6
9

Other Marketing. MOTI engages in various activities including the
marketing of the Company's production as well as the purchase and resale of
third party oil, gas and NGLs. MOTI contracts to provide oil and gas to various
customers and aggregates supplies from various sources including third-party
producers, marketing companies, pipelines, financial institutions and from the
Company's underlying production. MOTI utilizes other hedging and trading
strategies including sales in the futures market, options trading, time trades,
fixed price oil and gas swaps, and the outright purchase and sale of oil and gas
to third parties.

OTHER MATTERS

Competition. The Company actively competes for reserve acquisitions,
exploration leases and sales of oil and gas, frequently against companies with
substantially larger financial and other resources. In its marketing activities,
the Company competes with numerous companies for gas purchasing and processing
contracts and for gas, oil and NGLs 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
drilling permits, drilling bonds and operating reports. 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 limit 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 various intrastate natural gas pipelines, gathering
systems and NGL pipelines. The United States Department of Transportation and
comparable state agencies regulate, 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 gas in interstate commerce is regulated by the FERC
pursuant to the Natural Gas Act of 1938. All of the Company's sales of 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 gas. These regulations have been implemented on
individual pipelines but are still subject to many court challenges.

These new regulations implement, on an industry-wide basis, a "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 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.

7
10

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 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.

The FERC recently issued new orders which generally deregulate the field
area service activities of interstate pipeline companies. The new orders have
been appealed and are subject to many court challenges. While the eventual
effect of this deregulation on the Company's production cannot be predicted at
this time, the Company does not expect the deregulation to have a materially
adverse effect 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.

Filings of Reserve Estimates With Other Agencies. During 1994, the Company
filed estimates of oil and gas reserves for the year 1993 with the Department of
Energy. These estimates were not materially different from the reserve data
presented herein.

8
11

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 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 1,846 and 1,729 employees at December 31, 1994 and 1993,
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 1994 no matters were submitted to a vote of
security holders.

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12

EXECUTIVE OFFICERS OF THE REGISTRANT AND PRINCIPAL SUBSIDIARY

THOMAS H. O'LEARY, 60
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.

BOBBY S. SHACKOULS, 44
President and Chief Executive Officer
Meridian Oil Inc.
October 1994 to Present

Executive Vice President and Chief Operating Officer, Meridian Oil Inc.,
June 1993 to October 1994; President and Chief Operating Officer, Torch Energy
Advisors, Inc., July 1991 to May 1993; Executive Vice President, Torch Energy
Advisors, Inc., September 1988 to July 1991.

JOHN E. HAGALE, 38
Senior Vice President and Chief Financial
Officer
Burlington Resources Inc.
April 1994 to Present
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.

GERALD J. SCHISSLER, 50
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.

HAROLD E. HAUNSCHILD, 44
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.

C. RAY OWEN, 49
Executive Vice President and Chief
Operating Officer Meridian Oil Inc.
October 1994 to Present

Senior Vice President, Operations, Meridian Oil, Inc., March 1993 to
October 1994; Vice President, Regional Operations, Meridian Oil Inc., December
1990 to March 1993; Manager, Regional Operations, Meridian Oil Inc., July 1985
to December 1990.

L. EDWARD PARKER, 48
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.

10
13

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, 1994, the number of common stockholders was
24,745.

Information on common stock prices and quarterly dividends is shown on page
34.

ITEM SIX

SELECTED FINANCIAL DATA

The selected financial data for the Company set forth below for the five
years ended December 31, 1994 should be read in conjunction with the
Consolidated Financial Statements.

1994 1993 1992 1991 1990
------ ------ ------ ------ ------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

CONTINUING OPERATIONS FOR THE YEAR ENDED:
Revenues(a)................................. $1,055 $1,043 $ 943 $ 813 $ 829
Operating Income............................ 175 256 240 177 216
Income from Continuing Operations........... 154 255 190 100 124
Earnings per Common Share(b)................ 1.20 1.95 1.44 .75 .87
Cash Dividends Declared per Common
Share(c)................................. .55 .55 .60 .70 .70
AT YEAR END:
Total Assets(d)............................. $4,809 $4,448 $4,470 $5,480 $5,250
Long-term Debt.............................. 1,309 819 1,003 1,298 529
Stockholders' Equity(d)..................... 2,568 2,608 2,406 2,907 3,024
Common Shares Outstanding................... 126.5 129.7 128.9 131.4 137.9

- ---------------

(a) Revenues in 1994 include net amounts from the sale and marketing of NGLs.
Prior year amounts have been reclassified to conform to current year
presentation.

(b) Excluding non-recurring items totaling $.47, $.24, and $.08 per share,
Earnings per Common Share from Continuing Operations would have been $1.48,
$1.20 and $.67 in 1993, 1992, and 1991, respectively.

(c) On January 13, 1993, the Company increased its quarterly dividend rate to
$.1375 per share. In July 1992, the quarterly dividend rate was reduced to
$.125 per share to reflect the June 30, 1992 spin-off of EPNG to the
Company's stockholders.

(d) 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.

11
14

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, 1994 and 1993 was 34 and 24 percent,
respectively. In May 1994, the Company issued $300 million of 7.15% Notes due
May 1, 1999. The net proceeds were used for general corporate purposes,
including acquisition of oil and gas properties, repayment of commercial paper
and other capital expenditures. The Company had outstanding commercial paper
borrowings at December 31, 1994 of $260 million at an average interest rate of
6.28 percent.

In July 1994, the Company established new revolving credit facilities to
replace the previous $900 million facility that was due to expire in June 1996.
The new credit facilities are comprised of a $600 million revolving credit
agreement that expires in July 1999 and a $300 million revolving credit
agreement that expires July 1995, but is renewable annually by mutual consent.
As of December 31, 1994, there were no borrowings outstanding under the credit
facilities, although borrowing capacity is reduced by outstanding commercial
paper. The Company had the capacity to borrow approximately $640 million under
the credit facilities at December 31, 1994. In addition, the Company has $500
million of capacity under shelf registration statements filed with the
Securities and Exchange Commission.

During 1994, the Company repurchased 3.1 million shares of its common stock
for $122 million. Since December 1988, the Company has repurchased 27.2 million
shares under three 10 million share repurchase authorizations.

Net cash provided by continuing operating activities for 1994 was $498
million compared to $455 million and $433 million in 1993 and 1992,
respectively. The increase in 1994 compared to 1993 is primarily due to working
capital changes partially offset by decreased operating income. The increase in
1993 compared to 1992 is primarily due to higher operating income and increased
current utilization of non-conventional fuel tax credits.

In an effort to maintain its high quality asset base, the Company continues
to divest marginal and non-strategic oil and gas properties. During 1994, the
Company divested 1,350 working interest wells comprising approximately 4 percent
of the Company's working interest well inventory. In addition, the Company
conveyed its working interests in certain coal seam gas wells in November 1994.
The net proceeds after tax, from all 1994 property divestitures were
approximately $89 million. The Company expects to continue divesting marginal
and non-strategic properties in 1995.

In January 1995, the Company entered into a definitive agreement, subject
to certain conditions, to sell its intrastate natural gas pipeline systems in
west Texas and its underground gas storage facility for approximately $80
million. The assets being sold contributed less than 5 percent of the Company's
consolidated operating income in each of the years ended December 31, 1994, 1993
and 1992. The Company expects this transaction to be completed in the first
quarter of 1995.

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.

12
15

CAPITAL EXPENDITURES AND RESOURCES

Capital expenditures during 1994 totaled $882 million compared to $553
million and $315 million in 1993 and 1992, respectively. The Company spent $479
million for producing property acquisitions and $331 million on internal
development and exploration during 1994 compared to $270 million and $231
million, respectively, in 1993.

Capital expenditures for 1995, projected to be approximately $580 million,
are expected to be primarily for development and exploration of oil and gas
properties, reserve acquisitions, and plant and pipeline expenditures. Capital
expenditures will be funded from internal cash flow supplemented, as needed, by
external financing.

The Company anticipates continued increases in gas production. The
increased availability of gas will be a result of the continuing development of
the Company's gas reserves, exploration of undeveloped acreage and the Company's
producing property acquisition program. The Company expects to market its
additional gas production in the Gulf Coast, the Midwest and the East Coast and
by increasing its traditional California market share.

MARKETING

Wellhead Marketing. The Company's oil and gas production is sold on the
spot market and under short-term contracts at market responsive prices.
Substantially all of the Company's oil and gas production is sold to MOTI, a
wholly-owned marketing subsidiary of the Company.

DIVIDENDS

On January 11, 1995, the Board of Directors declared a common stock
quarterly dividend of $.1375 per share, payable April 3, 1995. 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 1994.

RESULTS OF OPERATIONS

Year Ended December 31, 1994 Compared With Year Ended December 31, 1993

Income from Continuing Operations in 1994 was $154 million or $1.20 per
share compared to $255 million or $1.95 per share in 1993. The 1993 results
include a total of $.47 per share from gains on the sale of the Burlington
Resources Coal Seam Gas Royalty Trust (the "Trust") units and the exchange of
Company debt for Anadarko Petroleum Corporation ("Anadarko") common stock, and a
charge to reflect the increase in the corporate income tax rate.

13
16

Revenues were $1,055 million in 1994 compared to $1,043 million in 1993.
Gas sales volumes improved 14 percent to 1,052 MMCF per day and oil sales
volumes improved 9 percent to 45.6 MBbls per day which increased revenues $90
million and $23 million, respectively. Gas and oil sales volumes increased
primarily due to continued development and exploration of the Company's oil and
gas properties and producing property acquisitions. The revenue increases were
offset by a 12 percent decline in 1994 average gas sales prices to $1.65 per MCF
and a 6 percent decline in 1994 average oil sales prices to $15.66 per barrel
which decreased revenues $84 million and $17 million, respectively.

Costs and Expenses were $880 million in 1994 compared to $787 million in
1993. The increase was primarily due to a 13 percent improvement in 1994
production levels which increased production related expenses $84 million and a
$5 million increase in exploration costs.

Interest Expense was $90 million in 1994 compared to $73 million in 1993.
The increase was primarily due to additional long-term debt issued in May 1994
and higher outstanding commercial paper borrowings during 1994.

Other Income -- Net was $6 million in 1994 compared to $124 million in
1993. 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.

Income Taxes -- The effective income tax rate was a benefit of 71 percent
in 1994 compared to an expense of 17 percent in 1993. Without the additional tax
expense associated with the non-recurring 1993 gains from the sale of the Trust
units and the exchange of Company debt for Anadarko common stock and the
non-recurring portion of the 1993 tax rate increase, the 1993 effective tax rate
was a benefit of 7 percent. The higher 1994 beneficial tax rate is primarily due
to lower 1994 pretax income relative to the non-conventional fuel tax credits
earned.

Year Ended December 31, 1993 Compared With Year Ended December 31, 1992

Income from Continuing Operations in 1993 was $255 million or $1.95 per
share compared to $190 million or $1.44 per share in 1992. The 1993 results
include a total of $.47 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 $.24
per share gain on the sale of the Company's interests in Plum Creek Timber
Company, L.P.

Revenues were $1,043 million in 1993 compared to $943 million in 1992.
Average gas sales prices increased 14 percent in 1993 to $1.87 per MCF which
increased revenues $76 million. Gas sales volumes improved 12 percent to 920
MMCF per day which increased revenues $60 million. Oil sales volumes improved 3
percent to 41.9 MBbls per day which increased revenues $8 million. Gas and oil
sales volumes increased primarily due to continued development and exploration
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. These revenue increases were partially
offset by lower oil sales prices which declined 11 percent in 1993 to $16.71 per
barrel and decreased revenues $33 million. In addition, there were no gas
contract recoveries in 1993. The revenues for 1992 include $7 million of
non-recurring gas contract recoveries.

Costs and Expenses were $787 million in 1993 compared to $702 million in
1992. The increase was primarily due to a 10 percent improvement in 1993
production levels which increased production related expenses $64 million, a $13
million increase in administrative expenses and a $9 million increase in
exploration costs.

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.

14
17

Other Income -- Net was $124 million in 1993 compared to $57 million 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.

OTHER MATTERS

The Company encounters competition in its business. See "Business and
Properties -- Other Matters" for further discussion of competition.

15
18

ITEM EIGHT

FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF INCOME

YEAR ENDED DECEMBER 31,
--------------------------------------------
1994 1993 1992
---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

Revenues........................................... $1,054,847 $1,043,232 $ 942,647
Costs and Expenses................................. 879,810 787,427 702,299
---------- ---------- ----------
Operating Income................................... 175,037 255,805 240,348
Interest Expense................................... 90,291 72,799 79,196
Other Income -- Net................................ 5,523 124,432 56,887
---------- ---------- ----------
Income from Continuing Operations Before
Income Taxes..................................... 90,269 307,438 218,039
Income Tax Expense (Benefit)....................... (63,977) 52,264 28,352
---------- ---------- ----------
Income from Continuing Operations.................. 154,246 255,174 189,687
Income from Discontinued Operations -- Net of
Income Taxes..................................... -- 1,138 68,141
---------- ---------- ----------
Net Income......................................... $ 154,246 $ 256,312 $ 257,828
========== ========== ==========
Earnings per Common Share:
Continuing Operations............................ $ 1.20 $ 1.95 $ 1.44
Discontinued Operations.......................... -- .01 .51
---------- ---------- ----------
Total............................................ $ 1.20 $ 1.96 $ 1.95
========== ========== ==========

See accompanying Notes to Consolidated Financial Statements.

16
19

BURLINGTON RESOURCES INC.

CONSOLIDATED BALANCE SHEET

DECEMBER 31,
-------------------------
1994 1993
---------- ----------

(IN THOUSANDS)
ASSETS

Current Assets:
Cash and Short-term Investments................................... $ 19,898 $ 19,784
Accounts Receivable............................................... 193,825 218,361
Inventories....................................................... 35,188 23,954
Other Current Assets.............................................. 17,191 14,572
---------- ----------
266,102 276,671
---------- ----------
Oil and Gas Properties (Successful Efforts Method).................. 5,689,135 5,027,312
Other Properties.................................................... 572,490 540,342
---------- ----------
6,261,625 5,567,654
Accumulated Depreciation, Depletion and Amortization.............. 1,904,212 1,631,941
---------- ----------
Properties -- Net.............................................. 4,357,413 3,935,713
---------- ----------
Other Assets........................................................ 185,095 235,336
---------- ----------
Total Assets.............................................. $4,808,610 $4,447,720
========= =========

LIABILITIES

Current Liabilities:
Accounts Payable.................................................. $ 193,819 $ 202,565
Taxes Payable..................................................... 47,080 58,372
Dividends Payable................................................. 17,434 17,916
Other Current Liabilities......................................... 3,688 20,764
---------- ----------
262,021 299,617
---------- ----------
Long-term Debt...................................................... 1,309,137 819,071
---------- ----------
Deferred Income Taxes............................................... 480,648 566,758
---------- ----------
Other Liabilities and Deferred Credits.............................. 188,763 154,216
---------- ----------
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..................................................... 2,936,374 2,936,934
Retained Earnings................................................... 551,385 467,667
---------- ----------
3,489,259 3,406,101
Cost of Treasury Stock (1994, 23,491,040 Shares; 1993,
20,316,521 Shares)................................................ 921,218 798,043
---------- ----------
Common Stockholders' Equity......................................... 2,568,041 2,608,058
---------- ----------
Total Liabilities and Common Stockholders' Equity......... $4,808,610 $4,447,720
========= =========

See accompanying Notes to Consolidated Financial Statements.

17
20

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31,
----------------------------------------
1994 1993 1992
---------- ---------- ----------
(IN THOUSANDS)

Cash Flows From Continuing Operating Activities:
Income from Continuing Operations.................. $ 154,246 $ 255,174 $ 189,687
Adjustments to Reconcile Income to Net Cash
Provided
By Continuing Operating Activities:
Depreciation, Depletion and Amortization........ 337,421 285,258 256,003
Deferred Income Taxes........................... (86,118) 2,438 19,041
Exploration Costs............................... 32,983 28,173 19,501
Working Capital Changes:
Accounts Receivable........................... 24,536 17,294 4,788
Inventories................................... (11,234) (4,940) 12,800
Other Current Assets.......................... (2,619) 69,165 (66,339)
Accounts Payable.............................. (8,746) (29,198) (69,300)
Taxes Payable................................. (11,292) (1,761) 46,197
Other Current Liabilities..................... (17,558) (19,062) (11,038)
Gain on Sales and Other......................... 86,632 (147,130) 31,227
--------- --------- ---------
Net Cash Provided By Continuing
Operating Activities..................... 498,251 455,411 432,567
--------- --------- ---------
Cash Flows From Continuing Investing Activities:
Additions to Properties............................ (881,645) (553,384) (315,447)
Proceeds from Sales and Property Dispositions...... 134,629 173,305 23,386
Other.............................................. (66,289) (4,462) (62,224)
--------- --------- ---------
Net Cash Used In Continuing
Investing Activities..................... (813,305) (384,541) (354,285)
--------- --------- ---------
Cash Flows From Continuing Financing Activities:
Proceeds from Long-term Financing.................. 488,596 -- 150,000
Reduction in Long-term Debt........................ -- (183,610) (645,225)
Dividends Paid..................................... (71,010) (69,711) (85,489)
Treasury Stock Transactions -- Net................. (123,175) 30,999 (100,285)
Financing Activities with EPNG -- Net.............. -- -- 525,361
Other.............................................. 6,266 85,794 (20,032)
--------- --------- ---------
Net Cash Provided By (Used In) Continuing
Financing Activities..................... 300,677 (136,528) (175,670)
--------- --------- ---------
Decrease in Cash and Short-term Investments
from Continuing Operations......................... (14,377) (65,658) (97,388)
Cash Provided By Discontinued Operations............. 14,491 53,713 93,618
Cash and Short-term Investments:
Beginning of Year.................................. 19,784 31,729 35,499
--------- --------- ---------
End of Year........................................ $ 19,898 $ 19,784 $ 31,729
========= ========= =========

See accompanying Notes to Consolidated Financial Statements.

18
21

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, 1992............ $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 ($.55 per share)... (71,255) (71,255)
Stock Purchases (1,139,900
shares)........................ (45,280) (45,280)
Stock Option Activity and Other... (13,788) 76,279 62,491
------ --------- --------- --------- -------------
Balance, December 31, 1993.......... 1,500 2,936,934 467,667 (798,043) 2,608,058
Net Income........................ 154,246 154,246
Cash Dividends ($.55 per share)... (70,528) (70,528)
Stock Purchases (3,139,600
shares)........................ (122,007) (122,007)
Stock Option Activity and Other... (560) (1,168) (1,728)
------ --------- --------- --------- -------------
Balance, December 31, 1994.......... $1,500 $2,936,374 $ 551,385 $(921,218) $2,568,041
========= ========= ========= ========= ============

See accompanying Notes to Consolidated Financial Statements.

19
22

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 are recorded on the entitlement method. Under the entitlement
method, revenue is recorded based on the Company's net working interest.

Price Management Activities

The Company uses energy-related financial instruments and physical
inventory for commodity price management purposes. All of these transactions are
recorded utilizing a mark-to-market methodology. The resulting change in
unrealized market gains and losses is recognized currently in the Consolidated
Statement of Income. Management estimates the fair value of these transactions
based on independent market valuations and valuation pricing models.

Hedging and Related Activities

In order to mitigate the risk of market price fluctuations, futures and
options transactions may be entered into as hedges of commodity prices
associated with the sales and purchases of gas and oil. Changes in the market
value of futures and options transactions entered into as hedges are deferred
until the gain or loss is recognized on the hedged transactions. The Company
enters into gas swap agreements in order to convert fixed price gas sales
contracts to market-sensitive contracts. Gains or

20
23

losses resulting from these transactions are realized in the Company's
Consolidated Statement of Income as the related physical production is
delivered.

Income Taxes

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.

Reclassification

The Company's 1994 revenues include amounts from the sale of NGLs, less the
actual costs incurred to gather, treat, process and transport the hydrocarbons
to market. To conform to current presentation, the Company reclassified $206
million and $199 million of costs and expenses to revenues for the years ended
1993 and 1992, respectively. The reclassification had no effect on operating
income.

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 129 million, 131 million, and 132 million for the years 1994,
1993, and 1992, respectively.

2. MARKETING ACTIVITIES

The Company's marketing activities include the purchase and resale of oil,
gas and NGLs in addition to the marketing of its own 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 marketing of third party
oil, gas, NGLs and downstream trading activities of Company-owned production of
approximately $32 million, $15 million and $32 million for years ended 1994,
1993 and 1992, respectively. The volumes of third party oil, gas and NGLs
marketed in those years are as follows:

1994 1993 1992
---- ---- ----

Oil (MBbls per day)..................................... 467 405 274
Gas (MMCF per day)...................................... 549 526 448
NGLs (MBbls per day).................................... 8 20 20

Price Management Activities

The Company enters into contracts in the physical delivery and financial
markets for oil and gas for commodity price management purposes and to allow the
Company to remain at market-sensitive prices on certain contracts. Physical and
financial instruments used include gas and oil futures, forwards, swaps, and
option contracts as described below. These contracts may be settled with
physical delivery or cash payments. These trading activities are
marked-to-market and the resulting gains and losses are recognized in the
Consolidated Statement of Income. The mark-to-market as of December 31, 1994 was
a net loss of approximately $250,000.

21
24

Following is a summary of the financial and physical delivery instruments
utilized that have been marked-to-market.

VOLUMES MARK-TO-MARKET
INSTRUMENT (MBBLS) GAIN (LOSS)
- -------------------------------------------------------------------- ------- --------------
(IN THOUSANDS)

Variable Priced Forward Oil Purchase Contracts...................... 34,928 $ 25,361
Variable Priced Forward Oil Sales Contracts......................... (40,010) (11,331)
Oil Put Options Sold................................................ 18,190 (13,413)
Oil Call Options Sold............................................... (3,470) (867)
------- ---------
Total Activity............................................ 9,638 $ (250)
======= =========

A description of the market risks and nature of the Company's price management
activities are as follows:

Variable Priced Forward Oil Purchase and Oil Sales Contracts -- The Company
enters into forward purchase and sales commitments in order to recognize
locational price differences in marketing the Company's and third parties' oil.
At December 31, 1994, the Company had purchase and sales commitments on oil of
35 million and 40 million barrels, respectively. These contracts are for periods
of up to 5 years and have a notional contract amount of approximately $1.3
billion at December 31, 1994. While notional contract amounts are used to
express the volume of transactions, the amounts at risk are substantially
smaller since the pricing of these contracts is essentially at market-sensitive
prices. The mark-to-market on these third party purchase and sales commitments
was a net gain of approximately $14 million as of December 31, 1994. Income from
these transactions for the year ended December 31, 1994, excluding the effect of
the mark-to-market, was a gain of approximately $13.3 million.

Oil Put Options Sold -- The Company sells oil put options and receives
premiums. Oil put options give the purchaser of the put options the right to
require the Company to purchase oil at various prices. At December 31, 1994, the
put options had exercise prices based upon the New York Mercantile Exchange
("NYMEX") oil prices from 12 to 18 months (the "Out Month") from the date the
contracts settle. These contracts settle on a monthly basis from January 1995
through May 1996. The Company is exposed to market risk to the extent that NYMEX
oil Out Month prices are higher than the settlement month NYMEX prices. The
spread between the put option exercise prices and current market prices ranged
from $.45 per barrel to $1.14 per barrel as of December 31, 1994. The
mark-to-market on these contracts as of December 31, 1994, was a net loss of
$13.4 million. Income from these transactions for the year ended December 31,
1994, excluding the effect of the mark-to-market, was a loss of approximately
$760,000.

Oil Call Options Sold -- The Company sells oil call options and receives
premiums. Oil call options give the purchaser of the call options the right to
require the Company to sell oil at various prices. At December 31, 1994, the
call options had exercise prices based upon the NYMEX oil prices up to 12 months
from the date the contracts settle. Additionally, the Company has sold call
options at market-sensitive prices with fixed locational and basis
differentials. These contracts settle on a monthly basis from January 1995
through October 1995. The Company is exposed to market risk to the extent that
NYMEX oil Out Month prices are lower than the settlement month NYMEX prices or
when locational and basis differentials change due to market conditions. The
spread between the call option exercise price and current market prices ranged
from $.05 per barrel to $.35 per barrel as of December 31, 1994. The
mark-to-market on these contracts as of December 31, 1994, was a net loss of
approximately $870,000. Income from these transactions for the year ended
December 31, 1994, excluding the effect of the mark-to-market, was a gain of
approximately $1.7 million.

Hedging and Related Activities

Gas Swap Agreements -- These agreements require the Company and its
counterparties to exchange payment streams based on the difference between fixed
and market-sensitive gas prices. The

22
25

Company enters into fixed price contracts to accommodate the needs of its
customers. The Company enters into gas swap agreements in order to convert some
of these fixed price gas sales contracts to market-sensitive contracts,
resulting in the Company effectively selling its production at market-sensitive
prices. As of December 31, 1994, the Company is the fixed price payor and fixed
price receiver on 52 BCF and 38 BCF of gas, respectively. These contracts are
for periods of up to 6 years and all volumes are matched with the physical
delivery of the Company's production. Gains and losses from these transactions
are realized in the Company's Consolidated Statement of Income as physical
production is delivered under the related sales contracts.

Futures Contracts Sold -- The Company sells oil and gas futures contracts
on the NYMEX. These contracts allow the Company to sell oil and gas at a future
date for a specified price. Futures contracts which are sold are accounted for
as hedges of the Company's underlying production. The realized income on futures
transactions was a gain of approximately $1.5 million during 1994. All futures
contracts were closed as of December 31, 1994.

Credit and Market Risks

The Company manages and controls market and counterparty risk related to
its trading and price management activities through established formal internal
control procedures which are reviewed on an ongoing basis. Net open positions
often result from the timing of the origination of new transactions. Market risk
is minimized by making various commitments which balance the risks associated
with price management and trading activities. Consequently, price movements can
result in losses on certain contracts which may be offset by gains on other
contracts. The counterparties to these transactions consist primarily of major
financial institutions, independent oil and gas producers, and independent power
producers. The Company attempts to minimize credit-risk exposure to trading
counterparties through formal credit policies, monitoring procedures and through
establishment of valuation reserves related to counterparty credit risk. In the
normal course of business, collateral is not required for financial instruments
with credit risk.

3. INCOME TAXES

The provision (benefit) for income taxes is as follows:

YEAR ENDED DECEMBER 31,
-----------------------------------------
1994 1993 1992
--------- -------- --------
(IN THOUSANDS)

Current:
Federal............................................ $ 23,320 $ 39,424 $ (1,985)
State.............................................. (1,179) 10,402 11,296
--------- -------- --------
22,141 49,826 9,311
--------- -------- --------
Deferred:
Federal............................................ (88,772) (14,934) 12,375
Enacted federal tax rate change.................... -- 15,558 --
State.............................................. 2,654 1,814 6,666
--------- -------- --------
(86,118) 2,438 19,041
--------- -------- --------
Total...................................... $ (63,977) $ 52,264 $ 28,352
========= ======== ========

23
26

Reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

YEAR ENDED DECEMBER 31,
--------------------------------------
1994 1993 1992
------ ----- -----

Statutory rate......................................... 35.0% 35.0% 34.0%
State income taxes net of federal tax benefit.......... 1.1 2.6 5.4
Tax credits............................................ (103.3) (25.0) (26.2)
Enacted federal tax rate change........................ -- 5.1 --
Other.................................................. (3.7) (0.7) (0.2)
------ ----- -----
Effective rate............................... (70.9)% 17.0% 13.0%
====== ===== =====

Deferred tax liabilities (assets) consist of the following:

YEAR ENDED DECEMBER 31,
--------------------------
1994 1993
--------- ---------
(IN THOUSANDS)

Deferred liabilities:
Excess of book over tax basis of properties..................... $ 619,908 $ 696,351
Other........................................................... 35,330 25,862
--------- ---------
655,238 722,213
--------- ---------
Deferred assets:
AMT credits carryover........................................... (150,374) (110,117)
Financial accruals and provisions............................... (2,600) (29,057)
Other........................................................... (21,616) (16,281)
--------- ---------
(174,590) (155,455)
--------- ---------
Total................................................... $ 480,648 $ 566,758
========= =========

The above net deferred tax liabilities as of December 31, 1994 and 1993,
include deferred state income tax liabilities of approximately $57 million and
$54 million, respectively.

As of December 31, 1994, the Alternative Minimum Tax ("AMT") credits
carryover of approximately $150 million, related primarily to non-conventional
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.

4. LONG-TERM DEBT

Long-term Debt outstanding is as follows:

DECEMBER 31,
--------------------------
1994 1993
---------- ----------
(IN THOUSANDS)

Commercial Paper................................................... $ 259,590 $ 70,994
Notes, 7.15%, due 1999............................................. 300,000 --
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
Other, including discounts -- net.................................. (453) (1,923)
---------- ----------
Total.................................................... $1,309,137 $ 819,071
========== ==========

24
27

Excluding commercial paper, the Company has no debt maturities through
1998, however, $450 million is due in 1999. The Company's commercial paper
borrowings at December 31, 1994 had an average interest rate of 6.28 percent.

The Company and a group of banks have $600 million and $300 million
Revolving Credit Facilities which expire in July 1999 and July 1995,
respectively. However, the $300 million Revolving Credit Facility is renewable
annually by mutual consent. Annual fees are .12 and .08 percent, respectively,
of the commitments. At the Company's option, interest on borrowings is based on
the prime rate or Eurodollar rates. The unused commitment under these agreements
is available to cover certain debt due within one year; therefore, commercial
paper is classified as long-term debt. Under the covenants of these agreements,
debt cannot exceed 52.5 percent of the sum of debt and tangible net worth (as
defined in the agreements). Additionally, tangible net worth cannot be less than
$1.3 billion. As of December 31, 1994, there were no borrowings outstanding
under these credit facilities although borrowing capacity is reduced by
outstanding commercial paper. The Company had the capacity to borrow
approximately $640 million under the credit facilities as of December 31, 1994.
In addition, the Company has $500 million of capacity under shelf registration
statements filed with the Securities and Exchange Commission.

5. RESTRUCTURING

From its inception in 1988 through 1993, the Company restructured its
assets to become solely an oil and gas exploration and production company. The
restructuring included the sale of non-strategic assets (real estate, minerals
and forest products).

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 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 had disposed of
virtually all of its non-strategic assets as of December 31, 1993.

Discontinued Operations

Proceeds from dispositions of discontinued operations assets for the years
ended December 31, 1994, 1993 and 1992 totaled $2 million, $62 million and $101
million, respectively. The Company realized no income from dispositions during
1994. The Company realized $1 million and $25 million of after-tax income net of
$4 million and $23 million of income taxes from discontinued asset sales during
1993 and 1992, respectively. In addition, the discontinued operations of EPNG
generated $43 million of after-tax income, net of $26 million of income taxes,
in 1992. 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.

6. ARRANGEMENTS WITH EPNG

Transportation

In 1994, 1993 and 1992, approximately 66 percent, 69 percent and 70
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.

25
28

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 amount is included in Interest
Expense and totaled $169,000 for the year 1992.

7. CAPITAL STOCK

The Company's 1993 Stock Incentive Plan (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 restricted stock, stock options and stock
appreciation rights or limited stock appreciation rights (together "SARs").

Under the 1993 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 at least one year 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, 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
----------
Granted............................................ 430,200 33.88 to 45.69
Exercised.......................................... (62,631) 21.54 to 38.00
Cancelled.......................................... (154,407) 31.83 to 44.00
----------
Balance, December 31, 1994........................... 3,146,335 $ 16.14 to $47.56
==========

At December 31, 1994, 2,722,135 options were exercisable at prices of
$16.14 to $47.56 per share. At December 31, 1994, 9,209,900 shares are available
for grant under the 1993 Plan.

Stock Appreciation Rights

The Company has granted SARs in connection with certain outstanding options
under the 1988 Plan. 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, 1994, there were 680,896 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, 1994 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

26
29

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 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.

8. 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,
-----------------------
1994 1993
-------- --------
(IN THOUSANDS)

Actuarial present value of benefit obligations:

Accumulated benefit obligation, including vested
benefits of $85,599 and $89,524................................ $ 88,060 $ 91,349
======== ========

Projected benefit obligation for service to date.................. $116,839 $127,403
Plan assets, primarily marketable equity and debt
securities, at fair value......................................... (92,935) (91,467)
-------- --------
Funded status of projected benefit obligation....................... 23,904 35,936
Unrecognized net loss............................................... (34,712) (47,006)
Unamortized net transition obligation............................... (4,038) (4,621)
-------- --------
Net prepaid pension asset........................................... $(14,846) $(15,691)
======== ========

The following information relates to the consolidated Company plans and
includes amounts related to EPNG for the first six months of 1992. The Company's
continuing operations pension expense was $7 million in 1992.

YEAR ENDED DECEMBER 31,
--------------------------------
1994 1993 1992
------- ------- --------
(IN THOUSANDS)

Pension cost for the plans includes the following
components:
Service cost--benefits earned during the period........... $ 6,633 $ 5,503 $ 9,817
Interest cost on projected benefit obligation............. 9,395 8,926 28,757
Actual (return)/loss on plan assets....................... 409 (7,857) 7,397
Net amortization and deferred amounts..................... (4,640) 3,851 (33,225)
------- ------- --------
Net pension cost.......................................... $11,797 $10,423 $ 12,746
======= ======= ========

27
30

The projected benefit obligation was determined using a weighted average
discount rate of 8.75 percent in 1994 and 7.5 percent in 1993, and a rate of
increase in future compensation levels of 5 percent. The expected long-term rate
of return on plan assets was 9 percent in both 1994 and 1993.

9. COMMITMENTS AND CONTINGENT LIABILITIES

Demand Charges

The Company has entered into contracts which provide firm and interruptible
transportation capacity rights on interstate and intrastate pipeline systems.
These contracts, ranging in terms from 1 to 13 years, require the Company to pay
transportation demand charges regardless of the amount of pipeline capacity
utilized by the Company. The Company paid $51 million, $48 million and $32
million of demand charges of which $40 million, $40 million and $25 million was
paid to EPNG for the years ended December 31, 1994, 1993 and 1992, respectively.

Future transportation demand charge commitments at December 31, 1994, are
as follows:

DEMAND
YEAR ENDING DECEMBER 31, CHARGES
------------------------ --------------
(IN THOUSANDS)

1995.......................................................... $ 52,240
1996.......................................................... 46,023
1997.......................................................... 46,375
1998.......................................................... 45,058
1999.......................................................... 45,150
Thereafter.................................................... 216,809
-----------
Total.................................................... $ 451,655
===========

Lease Obligations

The Company has operating leases for office space and other property and
equipment. The Company incurred lease rental expense of $17 million, $13 million
and $10 million for the years ended December 31, 1994, 1993, and 1992,
respectively.

Future minimum annual rental commitments at December 31, 1994, are as
follows:

OPERATING
YEAR ENDING DECEMBER 31, LEASES
------------------------ --------------
(IN THOUSANDS)

1995.......................................................... $ 14,485
1996.......................................................... 13,845
1997.......................................................... 11,426
1998.......................................................... 10,635
1999.......................................................... 9,353
Thereafter.................................................... 88,576
-----------
Total.................................................... $ 148,320
===========

28
31

10. OTHER INFORMATION

Other Income -- Net

A summary of significant items included in Other Income -- Net is as
follows:

YEAR ENDED DECEMBER 31,
------------------------
1993 1992
-------- -------
(IN THOUSANDS)

Gain on sale of Trust units......................... $107,800 $ -
Sale of Plum Creek interests........................ - 50,500
Gain on conversion of debt.......................... 19,108 -
Other -- net........................................ (2,476) 6,387
-------- -------
$124,432 $56,887
======== =======

During 1994, there were no single significant items included in Other
Income--Net.

Supplemental Cash Flow Information

The following is additional information concerning supplemental disclosures
of cash flow activities:

YEAR ENDED DECEMBER 31,
---------------------------------
1994 1993 1992
-------- ------- --------
(IN THOUSANDS)

Interest Paid............................... $ 85,599 $77,351 $ 73,702
Income Taxes Paid (Received)--Net........... 40,966 39,948 (44,931)

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.

In December 1992, the Company sold its interests in Plum Creek Timber
Company, L.P. The proceeds included notes receivable of $70 million which were
classified as Other Current Assets at December 1992 and were subsequently
collected in January 1993.

29
32

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, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1994, in conformity with generally accepted accounting
principles.

/s/ COOPERS & LYBRAND L.L.P.
- ----------------------------
COOPERS & LYBRAND L.L.P.

Houston, Texas
January 11, 1995

30
33

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,
----------------------------
1994 1993
---------- ----------
(IN THOUSANDS)

Proved properties............................................... $5,671,033 $4,985,501
Unproved properties............................................. 18,102 41,811
---------- ----------
5,689,135 5,027,312
Accumulated depreciation, depletion and amortization............ 1,714,098 1,455,910
---------- ----------
Net capitalized costs................................. $3,975,037 $3,571,402
========== ==========

Costs incurred for oil and gas property acquisition, exploration and
development activities are as follows:

YEAR ENDED DECEMBER 31,
-----------------------------------
1994 1993 1992
--------- --------- ---------
(IN THOUSANDS)

Property acquisition:
Unproved................................................. $ 21,679 $ 10,816 $ 10,266
Proved................................................... 479,466 270,235 121,949
Exploration................................................ 30,978 17,159 11,872
Development................................................ 278,343 202,981 109,571
--------- --------- ---------
Total costs incurred............................. $ 810,466 $ 501,191 $ 253,658
========= ========= =========

The Company's 1994 net revenues from oil and gas producing activities
include amounts from the sale of NGLs, less the actual costs incurred to gather,
treat, process and transport the hydrocarbons to market. With respect to gas
gathered and treated by affiliates, the actual costs incurred are calculated
using the capital investment of the facility depreciated by its expected life,
plus operating costs. Prior year amounts for 1993 and 1992 have been
reclassified to conform to current year presentation.

YEAR ENDED DECEMBER 31,
----------------------------------
1994 1993 1992
-------- -------- --------
(IN THOUSANDS)

Net revenues............................................... $905,465 $897,927 $800,532
-------- -------- --------
Production costs........................................... 261,453 240,220 214,816
Exploration and impairment costs........................... 32,983 28,173 19,501
Operating expenses......................................... 145,649 135,550 118,499
Depreciation, depletion and amortization................... 299,763 248,505 223,495
-------- -------- --------
739,848 652,448 576,311
-------- -------- --------
Operating income........................................... 165,617 245,479 224,221
Income tax provision....................................... (38,799) 26,582 26,124
-------- -------- --------
Results of operations for oil and gas producing
activities............................................... $204,416 $218,897 $198,097
======== ======== ========

31
34

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, 1992......................................................... 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(a).................................... 17.5 306
Sales of reserves in place(b)........................................ (0.6) (151)
------- -----
December 31, 1993....................................................... 168.2 5,221
Revisions of previous estimates...................................... (1.4) (44)
Extensions, discoveries and other additions.......................... 20.5 407
Production........................................................... (16.6) (384)
Purchases of reserves in place(c).................................... 19.7 379
Sales of reserves in place(d)........................................ (6.3) (78)
------- -----
December 31, 1994....................................................... 184.1 5,501
======= =====
PROVED DEVELOPED RESERVES
January 1, 1992......................................................... 128.1 3,951
December 31, 1992....................................................... 141.8 4,204
December 31, 1993....................................................... 149.8 4,381
December 31, 1994....................................................... 161.9 4,584

- ---------------

(a) Includes the reserves attributable to the purchase of 59 percent of the
Permian Basin Royalty Trust.

(b) Primarily the Burlington Resources Coal Seam Gas Royalty Trust transaction.

(d) Includes the reserves associated with the November 1994 conveyance of
working interests in coal seam gas wells.

32
35

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,
---------------------------
1994 1993
----------- -----------
(IN THOUSANDS)

Future cash inflows.............................................. $11,628,000 $11,788,000
Less related future:
Production costs............................................ 3,505,000 3,380,000
Development costs........................................... 466,000 377,000
Income taxes................................................ 1,320,000 1,403,000
----------- -----------
Future net cash flows.................................. 6,337,000 6,628,000
10% annual discount for estimated timing of cash flows......... 3,339,000 3,504,000
----------- -----------
Standardized measure of discounted future net cash flows.... $ 2,998,000 $ 3,124,000
=========== ===========

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:

1994 1993 1992
---------- ---------- ----------
(IN THOUSANDS)

January 1.............................................. $3,124,000 $3,138,000 $2,616,000
---------- ---------- ----------
Revisions of previous estimates:
Changes in prices and costs.......................... (350,000) (208,000) 265,000
Changes in quantities................................ (20,000) 9,000 (8,000)
Changes in rate of production........................ 129,000 (105,000) 104,000
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related
costs................................................ 195,000 180,000 186,000
Purchases of reserves in place......................... 251,000 260,000 183,000
Sales of reserves in place............................. (67,000) (107,000) (4,000)
Accretion of discount.................................. 363,000 375,000 323,000
Sales of oil and gas, net of production costs.......... (644,000) (578,000) (522,000)
Net change in income taxes............................. (80,000) 91,000 (55,000)
Other.................................................. 97,000 69,000 50,000
---------- ---------- ----------
Net change............................................. (126,000) (14,000) 522,000
---------- ---------- ----------
December 31............................................ $2,998,000 $3,124,000 $3,138,000
========== ========== ==========

33
36

BURLINGTON RESOURCES INC.

QUARTERLY FINANCIAL DATA--UNAUDITED

1994 1993
------------------------------------- ------------------------------------
4TH 3RD 2ND 1ST 4TH 3RD 2ND 1ST
------- ------- ------ ------- ------- ------- ------ -------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

Revenues(a).......................... $ 241 $ 273 $ 266 $ 275 $ 262 $ 263 $ 267 $ 251
Operating Income..................... $ 21 $ 39 $ 46 $ 69 $ 64 $ 57 $ 69 $ 66

Income from Continuing
Operations(b)...................... $ 52 $ 21 $ 33 $ 48 $ 52 $ 24 $ 134 $ 45
Discontinued Operations.............. -- -- -- -- -- -- -- 1
------- ------- ------ ------- ------- ------- ------ -------
Net Income........................... $ 52 $ 21 $ 33 $ 48 $ 52 $ 24 $ 134 $ 46
======= ======= ====== ======= ======= ======= ====== =======
Earnings per Common Share:
Continuing Operations.............. $ .42 $ .16 $ .25 $ .37 $ .40 $ .18 $ 1.02 $ .35
Discontinued Operations............ -- -- -- -- -- -- .01 --
------- ------- ------ ------- ------- ------- ------ -------
Earnings per Common Share............ $ .42 $ .16 $ .25 $ .37 $ .40 $ .18 $ 1.03 $ .35
======= ======= ====== ======= ======= ======= ====== =======
Dividends Declared per Common Share.. $ .1375 $ .1375 $.1375 $ .1375 $ .1375 $ .1375 $.1375 $ .1375
======= ======= ====== ======= ======= ======= ====== =======
Common Stock Price Range:
High............................... 42 5/8 41 7/8 45 5/8 49 5/8 52 3/8 53 7/8 51 5/8 47 1/4
Low................................ 33 1/8 37 1/4 40 7/8 41 1/2 40 1/4 46 45 36 1/2

- ---------------

(a) Revenues in 1994 include net amounts from the sale and marketing of NGLs.
Prior year amounts have been reclassified to conform to current year
presentation.

(b) The effective tax rate for the fourth quarter of 1994 generated an income
tax benefit primarily due to an increase in the estimated amount of
non-conventional fuel tax credits earned in 1994. The increase was due to
higher taxable income resulting from additional tax gains in the fourth
quarter of 1994.

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.

34
37

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 for the 1995 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 10 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 1995 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 1995 Annual Meeting of Stockholders and is
incorporated herein by reference.

35
38

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................................................. 16
Consolidated Balance Sheet....................................................... 17
Consolidated Statement of Cash Flows............................................. 18
Consolidated Statement of Common Stockholders' Equity............................ 19
Notes to Consolidated Financial Statements....................................... 20
Report of Independent Accountants................................................ 30
Supplemental Oil and Gas Disclosures............................................. 31
Quarterly Financial Data......................................................... 34
AMENDED EXHIBIT INDEX................................................................. *

REPORTS ON FORM 8-K

The Company filed a Form 8-K dated October 10, 1994 which announced
the promotion of Bobby S. Shackouls to the office of President and Chief
Executive Officer of Meridian Oil Inc., a wholly-owned subsidiary of the
Company.
- ---------------

* Included in Form 10-K filed with the Securities and Exchange Commission.

36
39

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 /s/ 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 /s/ THOMAS H. O'LEARY Chairman of the Board, January 11, 1995
------------------------------------------ President and Chief
Thomas H. O'Leary Executive Officer

/s/ JOHN E. HAGALE Senior Vice President and January 11, 1995
------------------------------------------ Chief Financial Officer
John E. Hagale

/s/ HAYS R. WARDEN Vice President, Controller January 11, 1995
------------------------------------------ and Chief Accounting
Hays R. Warden Officer

/s/ JOHN V. BYRNE Director January 11, 1995
------------------------------------------
John V. Byrne

/s/ S. PARKER GILBERT Director January 11, 1995
------------------------------------------
S. Parker Gilbert

/s/ JAMES F. McDONALD Director January 11, 1995
------------------------------------------
James F. McDonald

/s/ DONALD M. ROBERTS Director January 11, 1995
------------------------------------------
Donald M. Roberts

/s/ WALTER SCOTT, JR. Director January 11, 1995
------------------------------------------
Walter Scott, Jr.

/s/ WILLIAM E. WALL Director January 11, 1995
------------------------------------------
William E. Wall

37
40

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 The 1988 Burlington Resources Inc. Stock Option Incentive Plan as amended
(Exhibit 10.4 to Form 8, filed March 1993)................................ *
10.2 Burlington Resources Inc. Incentive Compensation Plan as amended (Exhibit
10.5 to Form 8, filed March 1993)......................................... *
10.3 Burlington Resources Inc. Incentive Compensation Plan as amended and
restated October 1, 1994..................................................
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. Deferred Compensation Plan as amended and
restated October 1, 1994..................................................
10.7 Burlington Resources Inc. Supplemental Benefits Plan as amended and
restated January 1, 1990 (Exhibit 10.14 to Form 8, filed February 1992)... *
10.8 Burlington Resources Inc. Supplemental Benefits Plan as amended and
restated October 1, 1994..................................................
10.9 Employment Contract between Burlington Resources Inc. and Thomas H.
O'Leary (Exhibit 10.14 to Form 8, filed February 1989).................... *
Amendment to Employment Contract between Burlington Resources Inc. and
Thomas H. O'Leary (Exhibit 10.14 to Form 8, filed March 1990)............. *

A-1
41

EXHIBIT PAGE
NUMBER DESCRIPTION NUMBER
- ------- -------------------------------------------------------------------------- ------

Amendment to Employment Contract between Burlington Resources Inc. and
Thomas H. O'Leary (Exhibit 10.15 to Form 8, filed February 1992).......... *
Amendment to Employment Contract between Burlington Resources Inc. and
Thomas H. O'Leary (Exhibit 10.8 to Form 10-K, filed February 1994)........ *
Employment Contracts between Meridian Oil Inc. and George E. Howison and
Bobby S. Shackouls (Exhibit 10.8 to Form 10-K, filed February 1994)....... *
10.10 Amendment to Employment Contract between Burlington Resources Inc. and
Thomas H. O'Leary.........................................................
Amendment to Employment Contract between Meridian Oil Inc. and Bobby S.
Shackouls.................................................................
10.11 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)......... *
10.12 Burlington Resources Inc. Key Executive Severance Protection Plan as
amended June 8, 1989 (Exhibit 10.20 to Form 8, filed February 1992)....... *
10.13 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
(Exhibit 10.15 to Form 8, filed March 1993)............................... *
Amendment No. 2 to Burlington Resources Inc. Retirement Savings Plan
(Exhibit 10.21 to Form 8, filed February 1992)............................ *
Amendment No. 3 to Burlington Resources Inc. Retirement Savings Plan
(Exhibit 10.15 to Form 8, filed March 1993)............................... *
10.14 Burlington Resources Inc. Retirement Income Plan for Directors (Exhibit
10.21 to Form 8, filed February 1991)..................................... *
10.15 Burlington Resources Inc. 1991 Director Charitable Award Plan, dated as of
January 16, 1991 (Exhibit 10.22 to Form 8, filed February 1991)........... *
10.16 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)........................................... *
10.17 Burlington Resources Inc. 1992 Stock Option Plan for Non-employee
Directors (Exhibit 28.1 of Form S-8, No. 33-46518, filed March 1992)...... *
10.18 Burlington Resources Inc. Key Executive Retention Plan and Amendments No.
1 and 2 (Exhibit 10.20 to Form 8, filed March 1993)....................... *
Amendments No. 3 and 4 to the Burlington Resources Inc. Key Executive
Retention Plan (Exhibit 10.17 to Form 10-K, filed February 1994).......... *
10.19 Burlington Resources Inc. 1992 Performance Share Unit Plan (Exhibit 10.21
to Form 8, filed March 1993).............................................. *
10.20 Burlington Resources Inc. Severance Plan and Amendments No. 1 and 2
(Exhibit 10.22 to Form 8, filed March 1993)............................... *
Amendments No. 3, 4 and 5 to the Burlington Resources Inc. Severance Plan
(Exhibit 10.20 to Form 10-K, filed February 1994)......................... *

A-2
42

EXHIBIT PAGE
NUMBER DESCRIPTION NUMBER
- ------- -------------------------------------------------------------------------- ------

10.21 Burlington Resources Inc. 1993 Stock Incentive Plan (Exhibit 10.22 to Form
10-K, filed February 1994)................................................ *
10.22 Petrotech Long Term Incentive Plan........................................
10.23 Burlington Resources Inc. 1994 Restricted Stock Exchange Plan.............
10.24 $300 million Short-term Revolving Credit Agreement, dated as of July 20,
1994, between Burlington Resources Inc. and Citibank, N.A., as agent......
10.25 $600 million Long-term Revolving Credit Agreement, dated as of July 20,
1994, between Burlington Resources Inc. and Citibank, N.A. as agent.......
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..............................................
27.1 Financial Data Schedule...................................................

- ---------------

*Exhibit incorporated by reference as indicated.

A-3