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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, 1995

( ) 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, SUITE 1400, 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,
1995: $4,968,044,376

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, 1995, Shares Outstanding: 126,574,379

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....................................................................... 8
Item Three
Legal Proceedings............................................................... 8
Item Four
Submission of Matters to a Vote of Security Holders............................. 8
Executive Officers of the Registrant and Principal Subsidiary................... 9

PART II
Item Five
Market for Registrant's Common Equity and Related Stockholder Matters........... 10
Item Six
Selected Financial Data......................................................... 10
Item Seven
Management's Discussion and Analysis of Financial Condition and Results of
Operations.................................................................... 11
Item Eight
Financial Statements and Supplementary Financial Information.................... 15
Item Nine
Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.................................................................... 33

PART III
Items Ten and Eleven
Directors and Executive Officers of the Registrant and Executive Compensation... 33
Item Twelve
Security Ownership of Certain Beneficial Owners and Management.................. 33
Item Thirteen
Certain Relationships and Related Transactions.................................. 33

PART IV
Item Fourteen
Exhibits, Financial Statement Schedules and Reports on Form 8-K................. 34

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. 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 6.7 TCFE at December
31, 1995.

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 8.

GENERAL INFORMATION

The Company's objective is to build long-term shareholder value through
value-added growth and effective cost management by increasing production,
reserves, earnings and cash flow. The Company intends to achieve this objective
by increasing its focus on high potential exploration and development projects,
acquisitions and the application of advanced technologies.

The Company's operations are located principally in the San Juan Basin, the
Gulf Coast Basin, the Permian Basin, the Anadarko 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 leasehold acreage in this area with over 1.1
million net acres under its control. The Company has an interest in over 10,500
wells and currently operates approximately 7,000 of these wells. Approximately
60 percent of the Company's reserves are located in this basin. During 1995, the
Company's daily net production in this basin averaged 700 MMCF of gas per day,
representing approximately 60 percent of the Company's total daily gas
production.

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
natural gas which is adsorbed to the surface of coal seams. The Company
continues to be an industry leader in the development of the Fruitland Coal
formation. The Company's net coal seam production from approximately 1,700 wells
averaged 350 MMCF of gas per day during 1995.

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 420 miles of gathering
lines and ten compressor stations to gather and treat coal seam gas in the San
Juan Basin.

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

1
4

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 three dimensional ("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. Subsequent acquisitions of
producing properties as well as successful lease acquisitions have expanded the
Company's interest to 115 blocks, of which 51 are operated, in offshore Federal
and State waters. During 1995, the Company invested nearly $90 million in
offshore operations including the participation in 23 drill wells and 12
workovers and has begun the planning or construction of 5 new platforms. The
most notable platform project underway is a 100 MMCF of gas per day platform and
processing facilities which will be installed in 400 feet of water in High
Island Block A-371 as the result of an exploratory discovery made in late 1994.
This operated project, in which the Company owns a 100% working interest, will
be installed in early 1996, with simultaneous drilling and production activities
taking place during the second half of 1996. The Company's investments in its
offshore assets have resulted in the offset of the extensive decline rates
characteristic of Gulf Coast Basin production. As a result, the Company's 1995
production volumes averaged 111 MMCF of gas per day. At year end 1995, the
Company had a combined initial productive capacity of 75 MMCF of gas per day and
2,000 Bbls of oil per day from wells awaiting the necessary production
facilities, a portion of which is associated with the High Island Block A-371
project.

Onshore

The Company's onshore activities in the Gulf Coast Basin are primarily
concentrated in Luling, Darst Creek and the West Ranch area in south Texas as
well as the Garden City, Lake Arthur, and Sulphur Mines Fields in south
Louisiana. 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 1995, 16 horizontal wells were drilled
in these fields at a net cost of approximately $6 million. During 1995, net
production from the Luling and Darst Creek Fields averaged 4 MBbls of oil per
day, with 56 percent of this production attributable to horizontal wells drilled
since these properties were acquired in 1989.

The application of 3D seismic technology has been instrumental for the
exploitation of the south Louisiana fields due to the complex structural nature
of the stacked pay intervals. In 1995, the Company invested $15 million in south
Louisiana which included over 40 square miles of seismic data and the drilling
of 6 wells. During 1995, net production from south Louisiana fields averaged 23
MMCF of gas per day and 1 MBbls of oil per day.

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 11,400 Permian Basin wells and operates over 3,300 of these
wells resulting in average net production during 1995 of 17 MBbls of oil per day
and 142 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 largest consolidated block of acreage in this basin
in which the Company has an interest is the Waddell Ranch, located 40 miles west
of Midland, Texas. The Company operates over 1,300 wells on the Waddell Ranch
resulting in average net production of 5 MBbls of oil per day and 22 MMCF of gas
per day during 1995.

2
5

Due to the complex geologic nature of the Permian Basin, 3D seismic
technology has been an effective exploitation tool in this area. In 1995, over
300 additional square miles were surveyed for a total investment of
approximately $5 million. The utilization of 3D data resulted in the drilling of
33 wells in 1995, including 6 horizontal wells. This drilling program led to the
discovery of 4 new fields in the Permian Basin.

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 500,000 net acres
principally located in the Anadarko Basin of western Oklahoma. The Company
operates 788 wells in this basin and total net production during 1995 averaged
125 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 1995,
the Company participated in the drilling of 41 wells to these formations at a
net cost of approximately $35 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
3.2 million net acres, primarily in the U.S. portion of the basin, through both
mineral and leasehold interests.

The Company continues its activity in the Williston Basin of North Dakota
and Montana through the use of advanced technologies such as 3D seismic and
horizontal drilling. In 1995, the Company was very active in exploration
programs such as the Lodgepole and River Run plays of North Dakota. The Company
also continues to use horizontal drilling to exploit reserves along the Cedar
Creek anticline in Montana. In total, the Company participated in the completion
of 44 horizontal wells in 1995 throughout the Williston Basin at a net cost of
approximately $33 million. During 1995, net oil production from the Williston
Basin averaged 13 MBbls of oil per day.

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 $1.03 per million British Thermal Unit depending on fuel
source. The Company earned approximately $82 million of tax credits in 1995.

CAPITAL EXPENDITURES AND MAJOR PROJECTS

Following are the Company's capital expenditures.

YEAR ENDED DECEMBER 31,
----------------------------------
1995 1994 1993
-------- -------- --------
(IN THOUSANDS)

Oil and Gas Activities........................... $547,113 $810,466 $501,191
Plants and Pipelines............................. 27,979 36,026 33,327
Administrative................................... 13,703 35,153 18,866
-------- -------- --------
Total.................................. $588,795 $881,645 $553,384
======== ======== ========

3
6

Capital expenditures for oil and gas activities in 1995 of $547 million
include 19 percent for proved property acquisitions, 59 percent for
developmental drilling and 22 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 1995 was principally in the San Juan, Gulf Coast,
Permian, Anadarko and Williston basins. Total drilling activity levels are
consistent with those reported at year end 1994. Additionally, 1995 activity
includes a 50 percent increase in workover activity and an increased focus on
higher potential exploration and development projects with commensurately higher
risk.

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

YEAR ENDED DECEMBER 31,
---------------------------
1995 1994 1993
----- ----- -----

Productive wells:
Exploratory..................................... 18.1 15.9 7.2
Development..................................... 291.7 342.2 243.7
----- ----- -----
309.8 358.1 250.9
----- ----- -----
Dry wells:
Exploratory..................................... 15.8 3.7 9.0
Development..................................... 37.8 13.3 11.6
----- ----- -----
53.6 17.0 20.6
----- ----- -----
Total net wells......................... 363.4 375.1 271.5
===== ===== =====

As of December 31, 1995, 20 gross wells, representing approximately 13 net
wells, were being drilled.

Asset Rationalization

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 reserves as well as
properties having upside potential that can be developed by the utilization of
both conventional and advanced technologies.

As a component of its overall growth strategy, the Company acquired 187
BCFE of producing oil and gas properties at a cost of approximately $104 million
during 1995. Approximately 45 percent of the reserves acquired during the year
were located in the prolific Gulf Coast Basin. The Company will continue to
pursue transactions which enable the consolidation of assets and increase
operating efficiencies.

In an effort to maintain its high quality asset base, the Company continues
to divest marginal and non-strategic assets. During 1995, the Company divested
over 4,300 working interest wells comprising approximately 14 percent of the
Company's working interest well inventory. In addition, the Company conveyed its
working interests in certain coal seam gas wells in August 1995. In February
1995, the Company completed the sale of its intrastate natural gas pipeline
systems and its underground natural gas storage facility, including gas
inventory, for approximately $80 million. The net proceeds after tax from all
1995 asset divestitures were approximately $146 million. The Company expects to
continue divesting marginal and non-strategic assets in 1996.

4
7

PRODUCTIVE WELLS, DEVELOPED AND UNDEVELOPED ACREAGE

Working interests in productive wells, developed acreage and undeveloped
leasehold acreage at December 31, 1995 follow.

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

12,728 4,832 14,552 8,672 5,824,000 3,065,000 2,760,000 1,582,000

Included in the productive wells data are 777 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. Following
are production and prices.

YEAR ENDED DECEMBER 31,
--------------------------------
1995 1994 1993
------ ------ ------

Production:
Gas (MMCF per day)................................. 1,165 1,052 920
Oil (MBbls per day)................................ 48.0 45.6 41.9
Average sales prices:
Gas per MCF........................................ $ 1.25 $ 1.65 $ 1.87
Oil per barrel..................................... 16.69 15.66 16.71
Average production costs per MCFE.................... .51 .54 .56
Depreciation, depletion and amortization rates per
MCFE............................................... .63 .62 .58

In 1995, 1994 and 1993, approximately 58 percent, 66 percent and 69
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
continue to transport a substantial portion of its future gas production through
EPNG's pipeline system.

RESERVES

The following table sets forth estimates by the Company's petroleum
engineers of proved oil and gas reserves at December 31, 1995. These reserves
have been reduced for royalty interests owned by others.

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

Proved Developed Reserves...................... 4,543 168.1 5,552
Proved Undeveloped Reserves.................... 964 28.8 1,137
----- ----- -----
Total Proved Reserves................ 5,507 196.9 6,689
===== ===== =====

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."

5
8

INTRASTATE PIPELINES AND NGLS

The Company owns and operates gathering systems in several states. In
February 1995, the Company completed the sale of its intrastate natural gas
pipeline systems and its underground gas storage facility, including gas
inventory, for approximately $80 million.

YEAR ENDED DECEMBER 31,
---------------------------
1995 1994 1993
---- ----- ----
(BCF)

Annual intrastate natural gas throughput:
Company-owned production.................... 1 16 19
Third party production...................... 1 49 41
Third party gas transportation and gathering..... 107 132 139
--- --- ---
Total.................................. 109 197 199
=== === ===

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 13.3 MMBbls, 12.7 MMBbls and 14.9 MMBbls, for the years
ended December 31, 1995, 1994 and 1993, respectively.

MARKETING

Marketing Strategy. In pursuit of its strategy to build long-term
shareholder value 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, exchanging and transporting
hydrocarbons for both itself and third parties. Financial instruments and
fixed-price gas sales contracts are used from time to time in order to hedge the
price of a portion of the Company's production.

Wellhead Marketing. Substantially all of the Company's oil and gas
production is sold on the spot market and under short-term contracts at market
sensitive prices. Substantially all of the Company's gas production is sold to
Meridian Oil Trading Inc. ("MOTI"), a wholly-owned marketing subsidiary of the
Company. A majority of the Company's crude oil production is sold at the
wellhead 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 oil, gas 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 and federal 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 gathering systems and NGL pipelines. The
United States Department of Transportation and comparable state agencies
regulate, under various enabling statutes, the

6
9

safety aspects of the transportation and storage activities of these 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 fully implemented its Order No. 636 series which fundamentally
restructured the rates and operations of interstate pipeline companies.
Additionally, the FERC has implemented new policies deregulating the field area
services of affiliates of interstate pipeline companies. Both of these orders
have been appealed.

The FERC has instituted proceedings concerning offshore and interstate
pipeline companies' incentive ratemaking. These proceedings are in their early
stages. The Company does not expect that these proceedings will 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.

Offshore oil and gas operations are subject to regulations of the U.S.
Department of the Interior which currently imposes absolute liability upon the
lessee under a federal lease for the cost of pollution cleanup resulting from
the lessee's operations, and could subject the lessee to possible liability for
pollution damages. In the event of a serious incident of pollution, the U.S.
Department of the Interior may require a lessee under a federal lease to suspend
or cease operations in the affected area.

The Company 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.

Filings of Reserve Estimates With Other Agencies. During 1995, the Company
filed estimates of oil and gas reserves for the year 1994 with the Department of
Energy. These estimates were not materially different from the reserve data
presented herein.

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10

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(++)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, "MMBTU"
means million British thermal units, "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 1,796 and 1,846 employees at December 31, 1995 and 1994,
respectively.

ITEM THREE

LEGAL PROCEEDINGS

On May 25, 1995, the 270th Judicial District Court of Harris County, Texas
entered an order in a lawsuit styled Caroline Altheide, et al. v. Meridian Oil
Inc., et al. which allows the suit to be maintained as a class action on behalf
of all royalty and overriding royalty interest owners in all Meridian properties
and all working interest owners in properties operated by Meridian who have
received payments from Meridian at any time from and after December 1, 1986
based upon wellhead sales of natural gas to MOTI. The lawsuit involves claims
for unspecified actual and punitive damages based upon alleged breaches of
duties owed to interest owners because of the use of Meridian corporate
affiliates to gather, treat and market natural gas. The plaintiffs allege that
Meridian's gas producing affiliates have sold natural gas to marketing
affiliates at low inter-affiliate settlement prices which are then used as the
basis for accounting to interest owners. Plaintiffs also allege that Meridian's
pricing includes inappropriate deductions of inflated gathering and
transportation costs. Meridian is vigorously defending this litigation and
perfected an interlocutory appeal of the class certification order on May 30,
1995. This appeal effectively stays class action proceedings in the trial court
until the appeal is completed. Oral argument in this appeal has been set for
February 28, 1996.

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 and other proceedings cannot
be predicted with certainty, management expects these matters, including the
above-described Altheide litigation, 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 1995, no matters were submitted to a vote of
security holders.

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11

EXECUTIVE OFFICERS OF THE REGISTRANT AND PRINCIPAL SUBSIDIARY

THOMAS H. O'LEARY, 61

Chairman of the Board
Burlington Resources Inc.
December 1995 to Present

Chairman of the Board, President and Chief Executive Officer, February 1993
to December 1995; 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.

BOBBY S. SHACKOULS, 45

President and Chief Executive Officer
Burlington Resources Inc.
December 1995 to Present

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, 39

Executive Vice President and Chief Financial
Officer
Burlington Resources Inc.
December 1995 to Present

Executive Vice President and Chief Financial Officer, Meridian Oil Inc.,
March 1993 to Present; Senior Vice President and Chief Financial Officer,
Burlington Resources Inc., April 1994 to December 1995; Vice President, Finance,
Burlington Resources Inc., March 1992 to February 1993; Vice President, Taxes,
Burlington Resources Inc., December 1990 to March 1992.

HAROLD E. HAUNSCHILD, 45

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 June 1992.

RANDOLPH P. MUNDT, 45

Executive Vice President, Marketing
Meridian Oil Inc.
March 1995 to Present

Senior Vice President, Operations, Meridian Oil Inc., October 1994 to March
1995; Senior Vice President, Acquisitions and Land, Meridian Oil Inc., July 1993
to October 1994; Senior Vice President, Strategic Planning and Asset Management,
Meridian Oil Inc., December 1990 to July 1993.

C. RAY OWEN, 50

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.

GERALD J. SCHISSLER, 51

Executive Vice President, Law
Burlington Resources Inc.
December 1995 to Present

Executive Vice President, Law and Corporate Affairs, Meridian Oil Inc.,
July 1993 to Present; Senior Vice President, Law, Burlington Resources Inc.,
December 1993 to December 1995; Consultant, June 1991 to July 1993; Senior Vice
President, Law, Meridian Minerals Company, a subsidiary of Burlington Resources
Inc., November 1987 to June 1991.

9
12

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, 1995, the number of common stockholders was
22,380.

Information on common stock prices and quarterly dividends is shown on page
32.

ITEM SIX

SELECTED FINANCIAL DATA

The selected financial data for the Company set forth below for the five
years ended December 31, 1995 should be read in conjunction with the
Consolidated Financial Statements.

1995 1994 1993 1992 1991
------ ------ ------ ------ ------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

CONTINUING OPERATIONS FOR THE YEAR ENDED:
Revenues.................................... $ 873 $1,055 $1,043 $ 943 $ 813
Operating Income (Loss)..................... (467) 175 256 240 177
Income (Loss)............................... (280) 154 256 190 100
Earnings (Loss) per Common Share(a)......... (2.20) 1.20 1.96 1.44 .75
Cash Dividends Declared per Common
Share(b)................................. .55 .55 .55 .60 .70
AT YEAR END:
Total Assets(c)............................. $4,165 $4,809 $4,448 $4,470 $5,480
Long-term Debt.............................. 1,350 1,309 819 1,003 1,298
Stockholders' Equity(c)..................... 2,220 2,568 2,608 2,406 2,907
Common Shares Outstanding................... 127 127 130 129 131

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

(a) Excluding the non-cash charge related to the adoption of Statement of
Financial Accounting Standard No. 121, Accounting for the Impairment of
Long-lived Assets and for Long-lived Assets to Be Disposed Of ("SFAS No.
121") totaling $(2.39) per share, Earnings (Loss) per Common Share would
have been $.19 in 1995. Excluding non-recurring items totaling $.47, $.24,
and $.08 per share, Earnings (Loss) per Common Share would have been $1.49,
$1.20 and $.67 in 1993, 1992, and 1991, respectively.

(b) 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.

(c) In 1995, as a result of the impairment of oil and gas assets related to the
adoption of SFAS No. 121, the Company recognized a non-cash, pretax charge
of $490 million ($304 million after tax). On June 30, 1992, the Company
distributed its EPNG common stock to the Company's stockholders of record as
of June 15, 1992. The distribution was accounted for as a $575 million
non-cash dividend.

10
13

ITEM SEVEN

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FINANCIAL CONDITION AND LIQUIDITY

The Company's total long-term debt to capital (long-term debt and
stockholders' equity) ratio at December 31, 1995 and 1994 was 38 and 34 percent,
respectively. In March 1995, the Company issued $150 million of 8.20% Notes due
March 15, 2025. The net proceeds were used for general corporate purposes,
including acquisition of oil and gas properties, repayment of commercial paper,
capital expenditures and repurchases of the Company's common stock.

The Company's credit facilities are comprised of a $600 million revolving
credit agreement that expires in July 2000 and a $300 million revolving credit
agreement that expires July 1996. The $300 million revolving credit agreement is
renewable annually by mutual consent and was renewed in July 1995. As of
December 31, 1995, there were no borrowings outstanding under the credit
facilities, although borrowing capacity is reduced by outstanding commercial
paper. At December 31, 1995, the Company had outstanding commercial paper
borrowings of $152 million at an average interest rate of 6.15 percent. The
Company had the capacity to borrow approximately $748 million under the credit
facilities at December 31, 1995. In addition, the Company has $350 million of
capacity under shelf registration statements filed with the Securities and
Exchange Commission.

During 1995, the Company repurchased 133 thousand shares of its common
stock for $5 million. Since December 1988, the Company has repurchased 27.3
million shares under three 10 million share repurchase authorizations.

Net cash provided by operating activities for 1995 was $452 million
compared to $498 million and $455 million in 1994 and 1993, respectively. The
decrease in 1995 compared to 1994 is primarily due to lower operating income
partially offset by $39 million received in June 1995 from the sale of a
receivable related to a claim resulting from the breach of a take-or-pay gas
contract and other working capital changes. The increase in 1994 compared to
1993 is primarily due to working capital changes partially offset by decreased
operating income.

The Company continues to divest marginal and non-strategic assets to
maintain its high quality asset base. During 1995, the Company divested over
4,300 working interest wells comprising approximately 14 percent of the
Company's working interest well inventory. In addition, the Company conveyed its
working interests in certain coal seam gas wells in August 1995. In February
1995, the Company completed the sale of its intrastate natural gas pipeline
systems and its underground natural gas storage facility, including gas
inventory, for approximately $80 million. The net proceeds after tax, from all
1995 asset divestitures were approximately $146 million. The Company expects to
continue divesting marginal and non-strategic assets in 1996.

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.

11
14

CAPITAL EXPENDITURES AND RESOURCES

Capital expenditures during 1995 totaled $589 million compared to $882
million and $553 million in 1994 and 1993, respectively. The Company spent $104
million for producing property acquisitions in 1995 compared to $479 million and
$270 million in 1994 and 1993, respectively. The Company spent $443 million on
internal development and exploration during 1995 compared to $331 million and
$231 million in 1994 and 1993, respectively.

Capital expenditures for 1996, projected to be approximately $530 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, if 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, the East Coast and its
traditional California market.

MARKETING

DIVIDENDS

On January 10, 1996, the Board of Directors declared a common stock
quarterly dividend of $.1375 per share, payable April 1, 1996. 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 $70 million during 1995.

RESULTS OF OPERATIONS

Year Ended December 31, 1995 Compared With Year Ended December 31, 1994

The Company reported a net loss of $280 million or $2.20 per share in 1995
compared to net income of $154 million or $1.20 per share in 1994. The 1995
results include a $2.39 per share non-cash charge resulting from the Company's
adoption of Statement of Financial Accounting Standards No. 121, Accounting for
the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of
("SFAS No. 121").

Revenues were $873 million in 1995 compared to $1,055 million in 1994. Gas
sales volumes improved 11 percent to 1,165 MMCF per day and oil sales volumes
improved 5 percent to 48 MBbls per day which increased revenues $68 million and
$14 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. Average oil prices increased by 7 percent
to $16.69 per barrel which increased revenues by $18 million. The revenue
increases were more than offset by a 24 percent decline in 1995 average gas
sales prices to $1.25 per MCF which decreased revenues

12
15

$170 million. Additionally, intrastate natural gas sales declined $96 million
due to the sale of the intrastate pipeline systems in February 1995 and other
revenues declined $9 million.

Costs and Expenses were $1,340 million in 1995 compared to $880 million in
1994. The increase was primarily due to a non-cash charge of $490 million
related to the impairment of oil and gas properties, a $38 million increase in
production related expenses and an $18 million increase in exploration costs.
The non-cash charge resulted from the Company's adoption of SFAS No. 121
effective as of September 30, 1995. The increases were partially offset by a $85
million reduction in intrastate natural gas purchases primarily due to the
February 1995 sale of the intrastate pipeline systems.

Interest Expense was $109 million in 1995 compared to $90 million in 1994.
The increase was primarily due to additional long-term debt issued in March 1995
and May 1994.

Other Income (Expense) -- Net was $700 thousand expense in 1995 compared to
$6 million income in 1994.

The effective income tax rate was a benefit of 52 percent in 1995 compared
to a benefit of 71 percent in 1994. The beneficial tax rate in 1995 is due to a
pretax loss and non-conventional fuel tax credits earned. The beneficial tax
rate in 1994 is due to low pretax income relative to the amount of
non-conventional fuel tax credits earned.

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

The Company reported net income in 1994 of $154 million or $1.20 per share
compared to $256 million or $1.96 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, 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.

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 $126 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.

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 credit earned.

13
16

OTHER MATTERS

Effective September 30, 1995, the Company adopted SFAS No. 121 which
requires that long-lived assets held and used by an entity be reviewed for
impairment whenever events or changes indicate that the net book value of the
asset may not be recoverable. An impairment loss is recognized if the sum of
expected future cash flows from the use of the asset is less than the net book
value of the asset.

The primary change under SFAS No. 121 is that the Company will now evaluate
impairment of its oil and gas properties on a field-by-field basis rather than
in the aggregate. Based upon this evaluation, certain properties were deemed to
be impaired. For those properties, the Company adjusted the net book value of
the properties to their fair value based upon expected future discounted cash
flows. As a result of the Company's adoption of SFAS No. 121, combined with the
current weak gas market, the Company recognized a non-cash, pretax charge of
$490 million ($304 million after tax) related to its oil and gas properties.

In October 1995, the Financial Accounting Standards Board issued SFAS No.
123, Accounting for Stock-Based Compensation, which is effective for fiscal
years beginning after December 15, 1995.

SFAS No. 123 establishes financial accounting and reporting standards for
stock-based employee compensation plans. The pronouncement defines a fair value
based method of accounting for an employee stock option or similar equity
instrument and encourages all entities to adopt that method of accounting for
all of their employee stock compensation plans. However, it also allows an
entity to continue to measure compensation cost for those plans using the
intrinsic value based method of accounting prescribed by Accounting Principles
Board ("APB") Opinion No. 25, Accounting for Stock Issued to Employees. Entities
electing to continue using the accounting methods prescribed by APB Opinion No.
25 must make pro forma disclosures of net income and earnings per share as if
the fair value based method of accounting defined in SFAS No. 123 had been
applied. The Company is currently evaluating the impact SFAS No. 123 will have
on its financial position and results of operations and has not determined which
accounting method will be applied.

14
17

ITEM EIGHT

FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF INCOME

YEAR ENDED DECEMBER 31,
--------------------------------------------
1995 1994 1993
---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

Revenues........................................... $ 872,514 $1,054,847 $1,043,232
Costs and Expenses................................. 1,339,740 879,810 787,427
---------- ---------- ----------
Operating Income (Loss)............................ (467,226) 175,037 255,805
Interest Expense................................... 108,865 90,291 72,799
Other Income (Expense) -- Net...................... (656) 5,523 125,570
---------- ---------- ----------
Income (Loss) Before Income Taxes.................. (576,747) 90,269 308,576
Income Tax Expense (Benefit)....................... (297,102) (63,977) 52,264
---------- ---------- ----------
Net Income (Loss).................................. $ (279,645) $ 154,246 $ 256,312
========== ========== ==========
Earnings (Loss) per Common Share................... $ (2.20) $ 1.20 $ 1.96
========== ========== ==========

See accompanying Notes to Consolidated Financial Statements.

15
18

BURLINGTON RESOURCES INC.

CONSOLIDATED BALANCE SHEET

DECEMBER 31,
-------------------------
1995 1994
---------- ----------
(IN THOUSANDS)

ASSETS
Current Assets
Cash and Short-term Investments................................... $ 20,473 $ 19,898
Accounts Receivable............................................... 209,669 193,825
Inventories....................................................... 18,317 35,188
Other Current Assets.............................................. 16,528 17,191
---------- ----------
264,987 266,102
---------- ----------
Oil and Gas Properties (Successful Efforts Method).................. 5,870,344 5,689,135
Other Properties.................................................... 498,853 572,490
---------- ----------
6,369,197 6,261,625
Accumulated Depreciation, Depletion and Amortization.............. 2,602,014 1,904,212
---------- ----------
Properties -- Net.............................................. 3,767,183 4,357,413
---------- ----------
Other Assets........................................................ 132,590 185,095
---------- ----------
Total Assets.............................................. $4,164,760 $4,808,610
========== ==========
LIABILITIES
Current Liabilities
Accounts Payable.................................................. $ 213,598 $ 177,956
Taxes Payable..................................................... 59,055 47,080
Accrued Interest.................................................. 19,453 15,863
Dividends Payable................................................. 17,407 17,434
Other Current Liabilities......................................... 12,420 3,688
---------- ----------
321,933 262,021
---------- ----------
Long-term Debt...................................................... 1,350,319 1,309,137
---------- ----------
Deferred Income Taxes............................................... 110,075 480,648
---------- ----------
Other Liabilities and Deferred Credits.............................. 162,011 188,763
---------- ----------
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..................................................... 2,935,285 2,936,374
Retained Earnings................................................... 202,141 551,385
---------- ----------
3,138,926 3,489,259
Cost of Treasury Stock (1995, 23,425,621 Shares;
1994, 23,491,040 Shares).......................................... 918,504 921,218
---------- ----------
Common Stockholders' Equity......................................... 2,220,422 2,568,041
---------- ----------
Total Liabilities and Common Stockholders' Equity......... $4,164,760 $4,808,610
========== ==========

See accompanying Notes to Consolidated Financial Statements.

16
19

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31,
----------------------------------------
1995 1994 1993
---------- ---------- ----------
(IN THOUSANDS)

Cash Flows From Operating Activities
Net Income (Loss)................................. $(279,645) $ 154,246 $ 255,174
Adjustments to Reconcile Net Income (Loss) to Net
Cash Provided By Operating Activities
Depreciation, Depletion and Amortization....... 372,602 337,421 285,258
Deferred Income Taxes.......................... (370,573) (86,118) 2,438
Exploration Costs.............................. 51,382 32,983 28,173
Impairment of Oil and Gas Properties........... 490,000 -- --
Working Capital Changes
Accounts Receivable.......................... (15,844) 24,536 17,294
Inventories.................................. 16,871 (11,234) (4,940)
Other Current Assets......................... 663 (2,619) 69,165
Accounts Payable............................. 35,642 (12,533) (24,649)
Taxes Payable................................ 11,975 (11,292) (1,761)
Accrued Interest............................. 3,590 3,787 (4,549)
Other Current Liabilities.................... 8,705 (17,558) (19,062)
Gain on Sales and Other........................... 126,630 86,632 (147,130)
--------- --------- ---------
Net Cash Provided By Operating
Activities.............................. 451,998 498,251 455,411
--------- --------- ---------
Cash Flows From Investing Activities
Additions to Properties........................... (588,795) (881,645) (553,384)
Proceeds from Sales and Other..................... 182,453 82,831 222,556
--------- --------- ---------
Net Cash Used In Investing Activities..... (406,342) (798,814) (330,828)
--------- --------- ---------
Cash Flows From Financing Activities
Proceeds from Long-term Financing................. 150,000 488,596 --
Reduction in Long-term Debt....................... (107,994) -- (183,610)
Dividends Paid.................................... (69,644) (71,010) (69,711)
Treasury Stock Transactions -- Net................ 2,714 (123,175) 30,999
Other............................................. (20,157) 6,266 85,794
--------- --------- ---------
Net Cash Provided By (Used In) Financing
Activities.............................. (45,081) 300,677 (136,528)
--------- --------- ---------
Increase (Decrease) in Cash and Short-term
Investments....................................... 575 114 (11,945)
Cash and Short-term Investments
Beginning of Year................................. 19,898 19,784 31,729
--------- --------- ---------
End of Year....................................... $ 20,473 $ 19,898 $ 19,784
========= ========= =========

See accompanying Notes to Consolidated Financial Statements.

17
20

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, 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 ($.55 per share)... (70,528) (70,528)
Stock Purchases (3,139,600
shares)........................ (122,007) (122,007)
Stock Option Activity and Other... (560) (1,168) (1,728)
------ ---------- -------- --------- ----------
Balance, December 31, 1994.......... 1,500 2,936,374 551,385 (921,218) 2,568,041
Net Loss.......................... (279,645) (279,645)
Cash Dividends ($.55 per share)... (69,599) (69,599)
Stock Purchases (132,900
shares)........................ (4,791) (4,791)
Stock Option Activity and Other... (1,089) 7,505 6,416
------ ---------- -------- --------- ----------
Balance, December 31, 1995.......... $1,500 $2,935,285 $202,141 $(918,504) $2,220,422
====== ========== ======== ========= ==========

See accompanying Notes to Consolidated Financial Statements.

18
21

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ACCOUNTING POLICIES

Principles of Consolidation and Reporting

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. Due
to the nature of financial reporting, management makes estimates and assumptions
in preparing the consolidated financial statements. 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.

Prior to the adoption of Statement of Financial Accounting Standard No.
121, Accounting for the Impairment of Long-lived Assets and for Long-lived
Assets to be Disposed Of ("SFAS" No. 121") as of September 30, 1995, the Company
limited the total amount of unamortized capitalized costs to the aggregate value
of future net revenues, based on current prices and costs. Under SFAS No. 121,
the unamortized capital costs at a field level are reduced to fair value if the
sum of expected future cash flows generated is less than net book value.

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.

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 the Company's oil and gas
production. 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 also enters into gas swap agreements to hedge
oil or gas and from time to time to convert fixed price gas sales contracts to
market-sensitive contracts. Gains or losses resulting from these transactions
are recognized in the Company's Consolidated Statement of Income as the related
physical production is delivered.

19
22

Credit and Market Risks

The Company manages and controls market and counterparty credit risk
through established formal internal control procedures which are reviewed on an
ongoing basis. The Company attempts to minimize credit-risk exposure to
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.

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 are earned.

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 127 million, 129 million, and 131 million for the years 1995,
1994, and 1993, 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 volumes of
third party oil, gas and NGLs marketed follow.

1995 1994 1993
---- ---- ----

Oil (MBbls per day)..................................... 272 467 405
Gas (MMCF per day)...................................... 604 549 526
NGLs (MBbls per day).................................... 12 11 20

Hedging and Related Transactions

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 Company enters into swap contracts to hedge
the Company's underlying production. Additionally, the Company utilizes swap
contracts as a risk management tool for fixed-price contracts entered into to
accommodate the needs of its customers, which results in the Company effectively
selling its production at market-sensitive prices.

In 1993, the Company entered into a gas swap agreement to offset the
effects of a long-term fixed-price contract of natural gas. When taking into
account the gas swap and the original fixed-price contract, the Company is a
fixed-price payor and receivor on substantially the same volume of gas at the
same price. The financial result is that there will be no gain or loss on these
transactions.

The Company is a fixed-price payor on approximately 4 BCF of gas at prices
ranging from $1.36 to $2.04 per MMBTU. These transactions convert fixed-price
contracts to market-sensitive contracts. The Company is a fixed-price receivor
on approximately 7 BCF of gas at prices ranging from $1.86 to $2.08 per MMBTU.
These transactions are a hedge of the Company's underlying production. The
deferred loss on these types of transactions as of December 31, 1995 was $5.2
million. This opportunity loss will be substantially offset in the cash market
when the hedged commodity is delivered in 1996, which has the effect of fixing
the price at which the commodity is sold.

20
23

Futures Contracts Sold -- The Company sells oil and gas futures contracts
on the New York Mercantile Exchange ("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 crude oil positions outstanding as of December 31, 1995 totaled
740 MBbls (which approximates 4 percent of the Company's 1995 production) at
NYMEX prices ranging from $17.50 to $18.50 per Bbl for production through April
1996. The natural gas positions outstanding as of December 31, 1995 totaled 6
BCF (which approximates 1 percent of the Company's 1995 production) at NYMEX
prices ranging from $2.10 to $2.74 per MMBTU for production through March 1996.
The deferred loss on futures contracts as of December 31, 1995 was $5.9 million.
This opportunity loss will be substantially offset in the cash market when the
hedged commodity is delivered in 1996, which has the effect of fixing the price
at which the commodity is sold.

3. INCOME TAXES

The provision (benefit) for income taxes follows.

YEAR ENDED DECEMBER 31,
-----------------------------------------
1995 1994 1993
--------- -------- --------
(IN THOUSANDS)

Current:
Federal............................................ $ 61,168 $ 23,320 $ 39,424
State.............................................. 12,303 (1,179) 10,402
-------- -------- --------
73,471 22,141 49,826
-------- -------- --------
Deferred:
Federal............................................ (331,286) (88,772) (14,934)
Enacted federal tax rate change.................... -- -- 15,558
State.............................................. (39,287) 2,654 1,814
-------- -------- --------
(370,573) (86,118) 2,438
-------- -------- --------
Total...................................... $(297,102) $(63,977) $ 52,264
======== ======== ========

Reconciliation of the federal statutory income tax rate to the effective
income tax rate follows.

YEAR ENDED DECEMBER 31,
------------------------------
1995 1994 1993
----- ------ -----

Statutory rate................................................. (35.0)% 35.0% 35.0%
State income taxes net of federal tax benefit.................. (3.0) 1.1 2.6
Tax credits.................................................... (14.5) (103.3) (25.0)
Enacted federal tax rate change................................ -- -- 5.1
Other.......................................................... 1.0 (3.7) (.8)
------ ------ -----
Effective rate....................................... (51.5)% (70.9)% 16.9%
====== ====== =====

21
24

Deferred tax liabilities (assets) follow.

DECEMBER 31,
------------------------
1995 1994
--------- ---------
(IN THOUSANDS)

Deferred liabilities
Excess of book over tax basis of properties...................... $ 275,060 $ 600,253
Financial accruals and provisions................................ 15,861 30,769
--------- ---------
290,921 631,022
Deferred assets
AMT credits carryover............................................ (180,846) (150,374)
--------- ---------
Net deferred liability................................... $ 110,075 $ 480,648
========= =========

The above net deferred tax liabilities as of December 31, 1995 and 1994,
include deferred state income tax liabilities of approximately $18 million and
$57 million, respectively.

As of December 31, 1995, the Alternative Minimum Tax ("AMT") credits
carryover of approximately $181 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 net income (loss) 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 follows.

DECEMBER 31,
--------------------------
1995 1994
---------- ----------
(IN THOUSANDS)

Commercial Paper.................................................. $ 151,596 $ 259,590
Notes, 7.15%, due 1999............................................ 300,000 300,000
Debentures, 8.20%, due 2025....................................... 150,000 --
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................................. (1,277) (453)
---------- ----------
Total................................................... $1,350,319 $1,309,137
========== ==========

Excluding commercial paper, the Company has debt maturities of $450 million
and $150 million due in 1999 and 2000, respectively. The Company's commercial
paper borrowings at December 31, 1995 had an average interest rate of 6.15
percent.

The Company's credit facilities are comprised of a $600 million revolving
credit agreement that expires in July 2000 and a $300 million revolving credit
agreement that expires July 1996. The $300 million revolving credit agreement is
renewable annually by mutual consent and was renewed in July 1995. 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, 1995, there were no borrowings outstanding under these credit
facilities although borrowing capacity is reduced by outstanding

22
25

commercial paper. The Company had the capacity to borrow approximately $748
million under the credit facilities as of December 31, 1995. In addition, the
Company has $350 million of capacity under shelf registration statements filed
with the Securities and Exchange Commission.

5. TRANSPORTATION ARRANGEMENTS WITH EL PASO NATURAL GAS COMPANY

In 1995, 1994 and 1993, approximately 58 percent, 66 percent and 69
percent, respectively, of the Company's gas production was transported to direct
sale customers through El Paso Natural Gas Company ("EPNG") pipeline facilities.
These transportation arrangements are pursuant to EPNG's approved Federal Energy
Regulatory Commission tariffs applicable to all shippers. The Company expects to
continue to transport a substantial portion of its future gas production through
EPNG's pipeline system. See Note 8 for demand charges paid to EPNG which provide
the Company with firm and interruptible transportation capacity rights on
interstate and intrastate pipeline systems.

6. CAPITAL STOCK

The Company's 1993 Stock Incentive Plan (the "1993 Plan") succeeds the
Company's 1988 Stock Option 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 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
----------
Granted..................................................... 415,600 39.63 to 39.94
Exercised................................................... (177,365) 16.14 to 38.00
Cancelled................................................... (31,300) 33.88 to 38.00
----------
Balance, December 31, 1995.................................... 3,353,270 $ 21.54 to $47.56
==========

At December 31, 1995, 2,943,670 options were exercisable at prices of
$21.54 to $47.56 per share. At December 31, 1995, 8,806,746 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

23
26

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, 1995, there were 647,148
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, 1995 there were no shares
issued. On December 15, 1988, the Company's Board of Directors designated
3,250,000 of the authorized preferred shares as Series A Preferred Stock. Upon
issuance each one-hundredth of a share of Series A Preferred Stock will have
dividend and voting rights approximately equal to those of one share of Common
Stock of the Company. In addition, on December 15, 1988, the Board of Directors
declared a dividend distribution of one Right for each outstanding share of
Common Stock of the Company. The Rights were amended on February 23, 1989. The
Rights become exercisable if, without the Company's prior consent, a person or
group acquires securities having 15 percent or more of the voting power of all
of the Company's voting securities (an "Acquiring Person") or ten days following
the announcement of a tender offer which would result in such ownership. Each
Right, when exercisable, entitles the registered holder to purchase from the
Company one-hundredth of a share of Series A Preferred Stock at a price of $95
per one-hundredth of a share, subject to adjustment. If, after the Rights become
exercisable, the Company were to be involved in a merger or other business
combination in which its Common Stock was exchanged or changed or 50% or more of
the Company's assets or earning power were sold, each Right would permit the
holder to purchase, for the exercise price, stock of the acquiring company
having a value of twice the exercise price (the "Merger Right"). In addition,
except for certain permitted offers, if any person or group becomes an Acquiring
Person, each Right would permit the purchase, for the exercise price, of Common
Stock of the Company having a value of twice the exercise price (the
"Subscription Right"). Rights owned by an Acquiring Person are void as they
relate to the Subscription Right or the Merger Right. The Rights may be redeemed
by the Company under certain circumstances until their expiration date for $0.05
per Right.

7. PENSION PLANS

The Company's pension plans are non-contributory defined benefit plans
covering substantially all employees. The benefits are based on years of
credited service and highest five-year average compensation levels.
Contributions to the plans are based upon the Projected Unit Credit actuarial
funding method and are limited to amounts that are currently deductible for tax
purposes. Contributions are intended to provide not only for benefits attributed
to service to date but also for those expected to be earned in the future.

DECEMBER 31,
----------------------
1995 1994
-------- --------
(IN THOUSANDS)

Actuarial present value of benefit obligations
Accumulated benefit obligation, including vested
benefits of $101,084 and $85,599................................ $104,152 $ 88,060
======= =======
Projected benefit obligation for service to date................... $145,369 $116,839
Plan assets, primarily marketable equity and debt
securities, at fair value.......................................... (112,739) (92,935)
------- -------
Funded status of projected benefit obligation........................ 32,630 23,904
Unrecognized net loss................................................ (44,483) (34,712)
Unamortized net transition obligation................................ (3,456) (4,038)
------- -------
Net prepaid pension asset............................................ $(15,309) $(14,846)
======= =======

24
27

The following information relates to the consolidated Company plans.

YEAR ENDED DECEMBER 31,
----------------------------------
1995 1994 1993
------- ------- --------
(IN THOUSANDS)

Pension cost for the plans includes the following
components
Service cost -- benefits earned during the period........ $ 5,808 $ 6,633 $ 5,503
Interest cost on projected benefit obligation............ 9,311 9,395 8,926
Actual (return)/loss on plan assets...................... (17,864) 409 (7,857)
Net amortization and deferred amounts.................... 11,781 (4,640) 3,851
------- ------- -------
Net pension cost......................................... $ 9,036 $11,797 $ 10,423
======= ======= =======

The projected benefit obligation was determined using a weighted average
discount rate of 7.50 percent in 1995 and 8.75 percent in 1994, 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 1995 and 1994.

8. 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.
The remaining terms on these contracts range in terms from 1 to 12 years and
require the Company to pay transportation demand charges regardless of the
amount of pipeline capacity utilized by the Company. The Company paid $56
million, $51 million and $48 million of demand charges of which $43 million, $40
million and $40 million was paid to EPNG for the years ended December 31, 1995,
1994 and 1993, respectively.

Future transportation demand charge commitments at December 31, 1995
follows.

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

1996.......................................................... $ 58,211
1997.......................................................... 63,147
1998.......................................................... 56,669
1999.......................................................... 57,089
2000.......................................................... 42,596
Thereafter.................................................... 221,018
--------
Total.................................................... $498,730
========

Lease Obligations

The Company has operating leases for office space and other property and
equipment. The Company incurred lease rental expense of $14 million, $17 million
and $13 million for the years ended December 31, 1995, 1994, and 1993,
respectively.

25
28

Future minimum annual rental commitments at December 31, 1995 follow.

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

1996.......................................................... $ 15,032
1997.......................................................... 13,667
1998.......................................................... 12,798
1999.......................................................... 9,643
2000.......................................................... 8,921
Thereafter.................................................... 78,644
--------
Total.................................................... $138,705
========

Legal Proceedings

On May 25, 1995, the 270th Judicial District Court of Harris County, Texas
entered an order in a lawsuit styled Caroline Altheide, et al. v. Meridian Oil
Inc., et al. which allows the suit to be maintained as a class action on behalf
of all royalty and overriding royalty interest owners in all Meridian properties
and all working interest owners in properties operated by Meridian who have
received payments from Meridian at any time from and after December 1, 1986
based upon wellhead sales of natural gas to Meridian Oil Trading Inc. The
lawsuit involves claims for unspecified actual and punitive damages based upon
alleged breaches of duties owed to interest owners because of the use of
Meridian corporate affiliates to gather, treat and market natural gas. The
plaintiffs allege that Meridian's gas producing affiliates have sold natural gas
to marketing affiliates at low inter-affiliate settlement prices which are then
used as the basis for accounting to interest owners. Plaintiffs also allege that
Meridian's pricing includes inappropriate deductions of inflated gathering and
transportation costs. Meridian is vigorously defending this litigation and
perfected an interlocutory appeal of the class certification order on May 30,
1995. This appeal effectively stays class action proceedings in the trial court
until the appeal is completed. Oral argument in this appeal has been set for
February 28, 1996.

9. IMPAIRMENT OF OIL AND GAS PROPERTIES

26
29

10. STOCK-BASED COMPENSATION

In October 1995, the Financial Accounting Standards Board issued SFAS No.
123, Accounting for Stock-Based Compensation, which is effective for fiscal
years beginning after December 15, 1995.

SFAS No. 123 establishes financial accounting and reporting standards for
stock-based employee compensation plans. The pronouncement defines a fair value
based method of accounting for an employee stock option or similar equity
instrument and encourages all entities to adopt that method of accounting for
all of their employee stock compensation plans. However, it also allows an
entity to continue to measure compensation cost for those plans using the
intrinsic value based method of accounting prescribed by Accounting Principles
Board ("APB") Opinion No. 25, Accounting for Stock Issued to Employees. Entities
electing to remain with the accounting in APB Opinion No. 25 must make pro forma
disclosures of net income and earnings per share as if the fair value based
method of accounting defined in SFAS No. 123 had been applied. The Company is
currently evaluating the impact SFAS No. 123 will have on its financial position
and results of operations and has not determined which accounting method will be
applied.

11. OTHER INFORMATION

Other Income (Expense) -- Net

During 1995 and 1994, there were no single significant items included in
Other Income (Expense)--Net. A summary of significant items included in Other
Income (Expense) -- Net in 1993 follows.

Gain on sale of Trust units....................................... $107,800
Gain on conversion of debt........................................ 19,108
Other -- net...................................................... (1,338)
--------
$125,570
========

Supplemental Cash Flow Information

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

YEAR ENDED DECEMBER 31,
--------------------------------
1995 1994 1993
-------- ------- -------
(IN THOUSANDS)

Interest Paid................................ $104,379 $85,599 $77,351
Income Taxes Paid--Net....................... 60,518 40,966 39,948

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.

27
30

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, 1995 and 1994, 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, 1995. 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, 1995 and 1994, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1995, in conformity with generally accepted accounting
principles.

As discussed in Note 9 to the consolidated financial statements, the
Company changed its method of accounting for the impairment of long-lived assets
in 1995.

/s/ COOPERS & LYBRAND L.L.P.
Houston, Texas
January 10, 1996

28
31

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 follow.

DECEMBER 31,
----------------------------
1995 1994
---------- ----------
(IN THOUSANDS)

Proved properties............................................... $5,830,201 $5,671,033
Unproved properties............................................. 40,143 18,102
---------- ----------
5,870,344 5,689,135
Accumulated depreciation, depletion and amortization............ 2,410,428 1,714,098
---------- ----------
Net capitalized costs................................. $3,459,916 $3,975,037
========= =========

Costs incurred for oil and gas property acquisition, exploration and
development activities follow.

YEAR ENDED DECEMBER 31,
-----------------------------------
1995 1994 1993
--------- --------- ---------
(IN THOUSANDS)

Property acquisition
Unproved................................................. $ 38,348 $ 21,679 $ 10,816
Proved................................................... 104,115 479,466 270,235
Exploration................................................ 80,339 30,978 17,159
Development................................................ 324,311 278,343 202,981
--------- --------- ---------
Total costs incurred............................. $ 547,113 $ 810,466 $ 501,191
======== ======== ========

Results of operations for oil and gas producing activities follow.

YEAR ENDED DECEMBER 31,
-----------------------------------
1995 1994 1993
--------- -------- --------
(IN THOUSANDS)

Net revenues............................................. $ 826,190 $905,465 $897,927
--------- -------- --------
Production costs......................................... 269,710 261,453 240,220
Exploration and impairment costs......................... 51,382 32,983 28,173
Operating expenses....................................... 154,319 145,649 135,550
Depreciation, depletion and amortization................. 331,600 299,763 248,505
Impairment of oil and gas properties..................... 490,000 -- --
--------- -------- --------
1,297,011 739,848 652,448
--------- -------- --------
Operating income (loss).................................. (470,821) 165,617 245,479
Income tax provision..................................... (260,873) (38,799) 26,582
--------- -------- --------
Results of operations for oil and gas producing
activities............................................. $(209,948) $204,416 $218,897
========= ======== ========

29
32

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, 1993......................................................... 155.5 5,071
Revision of previous estimates....................................... (.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)........................................ (.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
Revision of previous estimates....................................... 1.5 (33)
Extensions, discoveries and other additions.......................... 23.4 533
Production........................................................... (17.5) (425)
Purchases of reserves in place....................................... 9.3 131
Sales of reserves in place(e)........................................ (3.9) (200)
----- -----
December 31, 1995....................................................... 196.9 5,507
===== =====
PROVED DEVELOPED RESERVES
January 1, 1993......................................................... 141.8 4,204
December 31, 1993....................................................... 149.8 4,381
December 31, 1994....................................................... 161.9 4,584
December 31, 1995....................................................... 168.1 4,543

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

(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.

(e) Includes the reserves associated with the August 1995 conveyance of working
interests in coal seam gas wells.

30
33

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.

DECEMBER 31,
---------------------------
1995 1994
----------- -----------
(IN THOUSANDS)

Future cash inflows.............................................. $11,609,000 $11,628,000
Less related future
Production costs............................................ 3,451,000 3,505,000
Development costs........................................... 529,000 466,000
Income taxes................................................ 1,401,000 1,320,000
----------- -----------
Future net cash flows.................................. 6,228,000 6,337,000
10% annual discount for estimated timing of cash flows......... 3,044,000 3,339,000
----------- -----------
Standardized measure of discounted future net cash flows.... $ 3,184,000 $ 2,998,000
=========== ===========

A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil and gas reserves follows.

YEAR ENDED DECEMBER 31,
----------------------------------------
1995 1994 1993
---------- ---------- ----------
(IN THOUSANDS)

January 1.............................................. $2,998,000 $3,124,000 $3,138,000
---------- ---------- ----------
Revisions of previous estimates
Changes in prices and costs.......................... (33,000) (350,000) (208,000)
Changes in quantities................................ (22,000) (20,000) 9,000
Changes in rate of production........................ 189,000 129,000 (105,000)
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related
costs................................................ 250,000 195,000 180,000
Purchases of reserves in place......................... 99,000 251,000 260,000
Sales of reserves in place............................. (124,000) (67,000) (107,000)
Accretion of discount.................................. 358,000 363,000 375,000
Sales of oil and gas, net of production costs.......... (556,000) (644,000) (578,000)
Net change in income taxes............................. 11,000 (80,000) 91,000
Other.................................................. 14,000 97,000 69,000
---------- ---------- ----------
Net change............................................. 186,000 (126,000) (14,000)
---------- ---------- ----------
December 31............................................ $3,184,000 $2,998,000 $3,124,000
========== ========== ==========

31
34

BURLINGTON RESOURCES INC.

QUARTERLY FINANCIAL DATA--UNAUDITED

1995 1994
-------------------------------------- -------------------------------------
4TH 3RD 2ND 1ST 4TH 3RD 2ND 1ST
------- ------ ------ ------- ------- ------- ------ -------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

Revenues........................ $ 237 $ 210 $ 211 $ 215 $ 241 $ 273 $ 266 $ 275
Operating Income (Loss)(b)...... $ 20 $ (489) $ -- $ 2 $ 21 $ 39 $ 46 $ 69
Net Income (Loss)(a)............ $ 23 $ (300) $ 2 $ (5) $ 52 $ 21 $ 33 $ 48
Earnings (Loss) per Common
Share......................... $ .18 $(2.36) $ .02 $ (.04) $ .42 $ .16 $ .25 $ .37
Dividends Declared per Common
Share......................... $ .1375 $.1375 $.1375 $ .1375 $ .1375 $ .1375 $.1375 $ .1375
Common Stock Price Range:
High.......................... 41 1/4 42 41 1/2 40 3/4 42 5/8 41 7/8 45 5/8 49 5/8
Low........................... 35 1/8 36 7/8 36 3/4 33 7/8 33 1/8 37 1/4 40 7/8 41 1/2

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

(a) The beneficial effective tax rates for the fourth quarters of 1995 and 1994
are primarily due to non-conventional fuel tax credits earned. The 1994
benefit included increased tax credits due to higher taxable income
resulting from additional tax gains in the fourth quarter of 1994.

(b) In 1995, as a result of the Company's adoption of SFAS No. 121, the Company
recognized a non-cash, pretax charge of $490 million.

32
35

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 1996 Annual Meeting of Stockholders of
Burlington Resources Inc. will be filed no later than 120 days after the end of
the fiscal year with the Securities and Exchange Commission. The information set
forth therein under "Election of Directors" and "Executive Compensation" is
incorporated herein by reference. Executive Officers of the Company are listed
on page 9 of this Form 10-K.

ITEM TWELVE

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information required is set forth under the caption "Election of Directors"
in the Proxy Statement for the 1996 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 1996 Annual Meeting of Stockholders and is
incorporated herein by reference.

33
36

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................................................. 15
Consolidated Balance Sheet....................................................... 16
Consolidated Statement of Cash Flows............................................. 17
Consolidated Statement of Common Stockholders' Equity............................ 18
Notes to Consolidated Financial Statements....................................... 19
Report of Independent Accountants................................................ 28
Supplemental Oil and Gas Disclosures -- Unaudited................................ 29
Quarterly Financial Data -- Unaudited............................................ 32
AMENDED EXHIBIT INDEX.............................................................. *

REPORTS ON FORM 8-K

The Company filed a Form 8-K dated March 21, 1995, which included as
an exhibit the form of underwriting agreement in connection with its
offering of $150 million of 8.20% Debentures due 2025.
- ---------------

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

34
37

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 BOBBY S. SHACKOULS
-----------------------------------
Bobby S. Shackouls
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 BOBBY S. SHACKOULS President and Chief January 10, 1996
------------------------------- Executive Officer, and
Bobby S. Shackouls Director

JOHN E. HAGALE Executive Vice President and January 10, 1996
------------------------------- Chief Financial Officer
John E. Hagale

HAYS R. WARDEN Vice President, Controller January 10, 1996
------------------------------- and Chief Accounting Officer
Hays R. Warden

THOMAS H. O'LEARY Chairman of the Board January 10, 1996
-------------------------------
Thomas H. O'Leary

JOHN V. BYRNE Director January 10, 1996
-------------------------------
John V. Byrne

S. PARKER GILBERT Director January 10, 1996
-------------------------------
S. Parker Gilbert

JAMES F. McDONALD Director January 10, 1996
-------------------------------
James F. McDonald

DONALD M. ROBERTS Director January 10, 1996
-------------------------------
Donald M. Roberts

WALTER SCOTT, JR. Director January 10, 1996
-------------------------------
Walter Scott, Jr.

WILLIAM E. WALL Director January 10, 1996
-------------------------------
William E. Wall

35
38

REPORT OF MANAGEMENT

To the Stockholders and Directors of Burlington Resources Inc.:

The accompanying financial statements have been prepared by management in
conformity with generally accepted accounting principles. The fairness and
integrity of these financial statements, including any judgments, estimates and
selection of appropriate generally accepted accounting principles, are the
responsibility of management, as is all other information presented in this
Annual Report.

In the opinion of management, the financial statements are fairly stated,
and, to that end, the Company maintains a system of internal controls which:
provides reasonable assurance that transactions are recorded properly for the
preparation of financial statements; safeguards assets against loss or
unauthorized use; maintains accountability for assets; and requires proper
authorization and accounting for all transactions. Management is responsible for
the effectiveness of internal controls. This is accomplished through established
codes of conduct, accounting and other control systems, policies and procedures,
employee selection and training, appropriate delegation of authority and
segregation of responsibilities. To further ensure compliance with established
standards and related control procedures, the Company conducts a substantial
corporate audit program.

Our independent certified public accountants provide an objective
independent review by their audit of the Company's financial statements. Their
audit is conducted in accordance with generally accepted auditing standards and
includes a review of internal accounting controls to the extent deemed necessary
for the purposes of their audit.

The Audit Committee of the Board of Directors meets regularly with the
independent certified public accountants, management, and corporate audit to
review the work of each and to ensure that each is properly discharging its
financial reporting and internal control responsibilities. To ensure complete
independence, the certified public accountants and corporate audit have full and
free access to the Audit Committee to discuss the results of their audits, the
adequacy of internal accounting controls and the quality of financial reporting.

January 10, 1996

/s/ John E. Hagale
-----------------------------
John E. Hagale
Executive Vice President and
Chief Financial Officer

/s/ Hays R. Warden
-----------------------------
Hays R. Warden
Vice President, Controller and
Chief Accounting Officer

36
39

UNDERTAKINGS

For the purposes of complying with the amendments to the rules governing
Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the
registrant hereby undertakes as follows, which undertaking shall be incorporated
by reference into the registrant's Registration Statements on Form S-8, Nos.
33-22493 (filed June 15, 1988), 33-25807 (filed December 1, 1988), 33-26024
(filed December 12, 1988), 2-97533 (filed December 29, 1989), 33-33626 (filed
March 1, 1990), 33-46518 (filed March 19, 1992) and 33-53973 (filed June 3,
1994):

Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
registrant pursuant to the foregoing provisions, or otherwise, the registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities Act
of 1933 and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
registrant of expenses incurred or paid by a director, officer or controlling
person of the registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the registrant will, unless in
the opinion of its counsel the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in the Securities
Act of 1933 and will be governed by the final adjudication of such issue.
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...........................
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 and
restated October 1, 1994 (Exhibit 10.3 to Form 10-K, filed February
1995)..................................................................... *
10.3 Burlington Resources Inc. Senior Executive Survivor Benefit Plan dated as
of January 1, 1989 (Exhibit 10.11 to Form 8, filed February 1989)......... *
10.4 Burlington Resources Inc. Deferred Compensation Plan as amended and
restated October 1, 1994 (Exhibit 10.6 to Form 10-K, filed February
1995)..................................................................... *
10.5 Burlington Resources Inc. Supplemental Benefits Plan as amended and
restated October 1, 1994 (Exhibit 10.8 to Form 10-K, filed February
1995)..................................................................... *
10.6 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)............. *
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)........ *
Amendment to Employment Contract between Burlington Resources Inc. and
Thomas H. O'Leary (Exhibit 10.10 to Form 10-K, filed February 1995)....... *
Amendment to Employment Contract between Burlington Resources Inc. and
Thomas H. O'Leary.........................................................
10.7 Employment Contract between Burlington Resources Inc. and Bobby S.
Shackouls.................................................................

A-1
41

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

10.8 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)......... *
10.9 Burlington Resources Inc. Key Executive Severance Protection Plan as
amended June 8, 1989 (Exhibit 10.20 to Form 8, filed February 1992)....... *
10.10 Burlington Resources Inc. Retirement Savings Plan (Exhibits to Form S-8,
No. 2-97533, filed December 1989)......................................... *
Amendment No. 1 to Burlington Resources Inc. Retirement Savings Plan (Ex-
hibit 10.15 to Form 8, filed March 1993).................................. *
Amendment No. 2 to Burlington Resources Inc. Retirement Savings Plan (Ex-
hibit 10.21 to Form 8, filed February 1992)............................... *
Amendment No. 3 to Burlington Resources Inc. Retirement Savings Plan (Ex-
hibit 10.15 to Form 8, filed March 1993).................................. *
Amendment No. 4 to Burlington Resources Inc. Retirement Savings Plan......
10.11 Burlington Resources Inc. Retirement Income Plan for Directors (Exhibit
10.21 to Form 8, filed February 1991)..................................... *
10.12 Burlington Resources Inc. Phantom Stock Plan for Non-Employee Directors,
Effective March 21, 1996..................................................
10.13 Burlington Resources Inc. 1991 Director Charitable Award Plan, dated as of
January 16, 1991 (Exhibit 10.22 to Form 8, filed February 1991)........... *
10.14 Master Separation Agreement and documents related thereto dated January
15, 1992 by and among Burlington Resources Inc., El Paso Natural Gas
Company and Meridian Oil Holding Inc., including exhibits (Exhibit 10.24
to Form 8, filed February 1992)........................................... *
10.15 Burlington Resources Inc. 1992 Stock Option Plan for Non-employee
Directors (Exhibit 28.1 of Form S-8, No. 33-46518, filed March 1992)...... *
10.16 Burlington Resources Inc. Key Executive Retention Plan and Amendments No.
1 and 2 (Exhibit 10.20 to Form 8, filed March 1993)....................... *
Amendments No. 3 and 4 to the Burlington Resources Inc. Key Executive
Retention Plan (Exhibit 10.17 to Form 10-K, filed February 1994).......... *
10.17 Burlington Resources Inc. 1992 Performance Share Unit Plan (Exhibit 10.21
to Form 8, filed March 1993).............................................. *
10.18 Burlington Resources Inc. Severance Plan and Amendments No. 1 and 2 (Ex-
hibit 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)......................... *
10.19 Burlington Resources Inc. 1993 Stock Incentive Plan (Exhibit 10.22 to Form
10-K, filed February 1994)................................................ *
10.20 Petrotech Long Term Incentive Plan (Exhibit 10.22 to Form 10-K, filed
February 1995)............................................................ *
10.21 Burlington Resources Inc. 1994 Restricted Stock Exchange Plan (Exhibit
10.23 to Form 10-K, filed February 1995).................................. *

A-2
42

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

10.22 $300 million Short-term Revolving Credit Agreement, dated as of July 20,
1994, between Burlington Resources Inc. and Citibank, N.A., as agent
(Exhibit 10.24 to Form 10-K, filed February 1995)......................... *
10.23 Amended and Restated $600 million Long-term Revolving Credit Agreement,
dated as of July 14, 1995, between Burlington Resources Inc. and Citibank,
N.A. as agent.............................................................
11.1 Earnings (Loss) Per Share.................................................
12.1 Ratio of Earnings to Fixed Charges........................................
21.1 Subsidiaries of the Registrant............................................
23.1 Consent of Independent Accountants........................................
27.1 Financial Data Schedule................................................... **

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

*Exhibit incorporated by reference as indicated.

**Exhibit required only for filings made electronically using the Securities and
Exchange Commission's EDGAR System.

A-3