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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, 1996

( ) 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, 1996:
$6,292,799,462

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, 1996, Shares Outstanding: 124,918,699

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.... 9

Executive Officers of the Registrant and Principal
Subsidiary............................................ 10

PART II

Item Five

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

Item Six

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

Item Seven

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

Item Eight

Financial Statements and Supplementary Financial
Information........................................... 18

Item Nine

Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................... 37

PART III

Items Ten and Eleven

Directors and Executive Officers of the Registrant and
Executive Compensation................................ 37

Item Twelve

Security Ownership of Certain Beneficial Owners and
Management............................................ 37

Item Thirteen

Certain Relationships and Related Transactions......... 37

PART IV

Item Fourteen

Exhibits, Financial Statement Schedules and Reports on
Form 8-K.............................................. 37

PART I

ITEMS ONE AND TWO

BUSINESS AND PROPERTIES

Burlington Resources Inc. ("BR") is a holding company engaged, through its
principal subsidiary, Burlington Resources Oil & Gas Company (formerly known as
Meridian Oil Inc.) and its affiliated companies (together the "Company"), in the
exploration, development, production and marketing of oil and gas. The Company
is the largest independent (nonintegrated) oil and gas company in the United
States in terms of total domestic proved equivalent reserves which were
estimated at 6.4 TCFE at December 31, 1996.

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
primarily by increasing its focus on high potential, high margin exploration and
development projects. The Company will continue to pursue acquisitions that
complement its core area focus and provide future growth potential.

On July 11, 1996, the Company announced the acceleration of its on-going
divestiture program. The Company sold over 9,500 working interest wells from
January 1, 1994 to December 31, 1996, including its working interest in
approximately 4,000 wells sold during 1996. By July 31, 1997, the Company
expects to sell its working interest in approximately 9,200 additional wells,
thus reducing its pre-1994 working interest well count over 50 percent. The net
book value of the wells to be sold is approximately $350 million at December 31,
1996 and the related net production represented about 12 percent of the
Company's average daily produced volumes at December 31, 1996.

This accelerated divestiture program allowed the Company to reorganize and
reduce the number of its operating divisions from five to three. The accelerated
divestiture program and reorganization is expected to result in more than a 20
percent reduction in the Company's 1995 level of production expenses per MCFE.
It will also result in a reduction of approximately 425 employees or 20 percent
of total employees and a reduction of over 10 percent of the Company's 1995
corporate administrative expenses per MCFE. All levels of personnel within the
Company were included in the employee reduction. As a result of the divestiture
program and reorganization, the Company recorded a pretax charge of
approximately $30 million for severance and other related exit costs in the
third quarter of 1996. Since December 31, 1995, headcount has been reduced by
373 employees, of which 334 employees have been terminated under the
restructuring program. Approximately $7 million of accrued unpaid benefits
remain on the consolidated balance sheet as of December 31, 1996. The Company
expects that substantially all benefits will be paid by July 31, 1997.

The Company's operations are now conducted from three division offices
located in Farmington, New Mexico, Midland, Texas and Houston, Texas. 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 in each division.

SAN JUAN DIVISION. The San Juan Division ("San Juan"), located in
Farmington, New Mexico is the most prolific operating area of the Company in
terms of reserves and production. San Juan's

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activities are centered in the San Juan Basin in northwest New Mexico and
southwest Colorado. The San Juan Basin 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 million net
acres under its control. The Company has an interest in approximately 9,500
wells and currently operates approximately 6,300 of these wells. San Juan has
approximately 60 percent of the Company's reserves.

There are four significant gas producing horizons in the San Juan Basin.
These horizons, 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.

San Juan's net coal seam production averaged 385 MMCF of gas per day during
1996 from approximately 1,300 wells. During 1996, San Juan participated in 103
new wells and 297 mechanical workovers on existing wells. San Juan's capital
investment for 1996 was $98 million. The Company has continued to grow its
production in what is considered one of the most mature basins in the United
States. Net production from San Juan averaged 717 MMCF of gas per day and 1.7
MBbls of oil per day. San Juan's average daily net production represented
approximately 59 percent of the Company's total average daily gas production and
3 percent of the Company's total average daily oil production.

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 13 compressor stations to gather and treat coal seam gas in the San
Juan Basin.

GULF COAST DIVISION. The Gulf Coast Division ("Gulf Coast"), located in
Houston, Texas, explores for and produces oil and gas offshore in the Gulf of
Mexico and onshore, primarily in south Louisiana and south Texas. The complex
geologic conditions and multiple prospective oil and gas formations, encountered
as deep as 25,000 feet, make the Gulf Coast Basin an attractive area for the
application of advanced technologies such as three dimensional ("3-D") seismic.
The application of 3-D seismic technology has been instrumental in the
exploration and development of Gulf Coast's assets with over 800 square miles of
3-D seismic data acquired in 1996.

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. In 1996, the Company acquired
additional offshore assets from Gulfstream Resources, Inc. The principal assets
purchased were three fields; Eugene Island Block 205, Eugene Island Block 89 and
West Cameron Block 2. The properties are located from 2 miles to 50 miles off
the Louisiana coast in water depths ranging from 10 feet to 120 feet. The
Company currently has interests in 131 offshore federal and state waters' lease
blocks, 63 of which are operated by the Company. The Company currently has
interests in 16 deeper water blocks in water depths greater than 600 feet.

During 1996, Gulf Coast invested approximately $150 million in offshore
operations including the drilling of 47 new wells and 23 mechanical workovers.
The most notable new field brought on to production in 1996 for the Gulf Coast
was High Island Block A-371, an exploration discovery made in late 1994, located
off the coast of Texas in 400 feet of water. The platform began initial
production in the second quarter of 1996, with simultaneous drilling and
production activities taking place during the second half of 1996. The field was
producing 93 MMCF of gas per day net to the Company at year end 1996. Since
establishing an asset position in the offshore Gulf of Mexico in 1994, the
Company has grown natural gas production from approximately 100 MMCF per day to
approximately 240 MMCF per day at year end 1996.

Gulf Coast's onshore activities in 1996 were primarily in the south
Louisiana fields of Garden City, Lake Arthur and Sulphur Mines. In 1996, Gulf
Coast invested a total of approximately $20 million in south Louisiana which
included investments for the drilling of 10 new wells and 19 mechanical

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workovers. The Garden City Field properties were acquired in February 1995.
Since that time, the Company has more than tripled its net oil and gas volumes
from 7 MMCFE to over 23 MMCFE per day at year end 1996.

Total capital investments in Gulf Coast's areas of activity in 1996 were
$179 million. Net production from Gulf Coast averaged 235 MMCF of gas per day
and 13.7 MBbls of oil per day. Gulf Coast's average daily net production
represented approximately 19 percent of the Company's total average daily gas
production and 27 percent of the Company's total average daily oil production.
Gulf Coast has approximately 12 percent of the Company's reserves.

MID-CONTINENT DIVISION. The Mid-Continent Division ("Mid-Continent"),
located in Midland, Texas operates primarily in three basins; the Permian Basin
in west Texas, the Anadarko Basin in western Oklahoma and the Williston Basin in
western North Dakota, northwest South Dakota and northeast Montana.

The Permian Basin 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 8,300 Permian Basin wells, of which over 3,900
are operated.

The most productive structural feature in the Permian Basin is the Central
Basin Platform in which the Company controls over 150,000 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 1,500 wells on the Waddell Ranch
with a combined average net production in 1996 of 4.6 MBbls of oil per day and
22 MMCF of gas per day.

Due to the complex geologic nature of the Permian Basin, 3-D seismic
technology has been an effective exploration and production tool in this area.
In 1996, approximately 280 square miles of 3-D seismic were acquired for a total
investment of approximately $5 million. The utilization of 3-D data resulted in
the drilling of 35 wells in 1996, including 7 horizontal wells.

The Anadarko Basin 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 350,000 net acres principally located in the
Anadarko Basin in western Oklahoma. The Company operates over 300 wells in this
basin with total net production during 1996 averaging 121 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 3-D 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 1996, the Company participated
in the drilling of 38 new wells to these formations at a net cost of
approximately $20 million.

The Williston Basin encompasses approximately 225,000 square miles and has
18 producing horizons ranging in depth from 4,500 feet to over 15,000 feet. The
Company controls over 3.6 million net acres in the basin through both mineral
and leasehold interest. Mid-Continent's activities have been focused on the use
of advanced technologies such as 3-D seismic and horizontal drilling to increase
the value of its assets. In 1996, Mid-Continent was very active in exploration
programs in the Red River "B" and Lodgepole horizons. In total, Mid-Continent
participated in the completion of 89 horizontal wells in 1996 throughout the
Williston Basin at a net cost of approximately $50 million. During 1996,
Mid-Continent's net oil production from the Williston Basin averaged 18 MBbls of
oil per day.

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Capital investments in Mid-Continent totaled $178 million in 1996. Net
production averaged 273 MMCF of gas per day and 35.7 MBbls of oil per day.
Mid-Continent's average daily net production represented approximately 22
percent of the Company's total average daily gas production and 70 percent of
the Company's total average daily oil production. Mid-Continent has
approximately 28 percent of the Company's reserves.

SECTION 29 TAX CREDITS

A number of formations located within the Company's producing areas have
wells that 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 and
tight sands formations. The Company estimates that the tax credit rate will
range from $.52 to $1.02 per MMBTU depending on fuel source. The Company earned
approximately $59 million of tax credits in 1996.

CAPITAL EXPENDITURES AND MAJOR PROJECTS

Following are the Company's capital expenditures.

YEAR ENDED DECEMBER 31,
------------------------
1996 1995 1994
---- ---- ----
(IN MILLIONS)

Oil and Gas Activities................................ $519 $547 $810
Plants and Pipelines.................................. 26 28 36
Administrative........................................ 9 14 36
---- ---- ----
Total....................................... $554 $589 $882
==== ==== ====

Capital expenditures for oil and gas activities in 1996 of $519 million
include 17 percent for proved property acquisitions, 63 percent for development
and 20 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 1996 was principally in the San
Juan, Gulf Coast, Permian, Anadarko and Williston basins. Lower net drilling
activity levels, as seen in the table below, are a result of the Company's
increased focus on higher potential exploration and development projects. Larger
expenditures in fewer projects, particularly in the Gulf Coast, reflect the
Company's continued focus on increasing its operating and capital efficiencies.

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

YEAR ENDED DECEMBER 31,
----------------------------------
1996 1995 1994
---- ---- ----

Productive wells
Exploratory..................................... 16.3 18.1 15.9
Development..................................... 186.1 291.7 342.2
---- ---- ----
202.4 309.8 358.1
---- ---- ----
Dry wells
Exploratory..................................... 11.5 15.8 3.7
Development..................................... 5.9 37.8 13.3
---- ---- ----
17.4 53.6 17.0
---- ---- ----
Total net wells......................... 219.8 363.4 375.1
==== ==== ====

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7

As of December 31, 1996, 52 gross wells, representing approximately 24 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 107
BCFE of producing oil and gas properties at a cost of approximately $87 million
during 1996. Approximately 87 percent of the reserves acquired during the year
were located in the prolific Gulf Coast Basin. The most notable acquisition in
1996 was the purchase of Gulfstream Resources, Inc. for $77 million. This
acquired asset consisted of 3 offshore Louisiana oil and gas properties. 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 non-strategic oil and gas assets. On July 11, 1996, the Company
announced the acceleration of its on-going divestiture program. During 1996, the
Company divested its working interest in approximately 4,000 wells and related
facilities. Gross proceeds from all 1996 asset divestitures were approximately
$160 million.

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.

PRODUCTIVE WELLS, DEVELOPED AND UNDEVELOPED ACREAGE

Working interests in productive wells, developed acreage and undeveloped
leasehold acreage at December 31, 1996 follow.

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

10,486 4,667 12,634 7,267 4,905,000 2,704,000 2,708,000 1,428,000

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.

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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,
---------------------------------------------
1996 1995 1994
---- ---- ----

Production
Gas (MMCF per day)................................. 1,225 1,165 1,052
Oil (MBbls per day)................................ 51.1 48.0 45.6
Average sales prices
Gas per MCF........................................ $ 1.91 $ 1.25 $ 1.65
Oil per barrel..................................... 20.69 16.69 15.66
Average production costs per MCFE.................... .53 .51 .54
Depreciation, depletion and amortization rates per
MCFE............................................... $ .55 $ .63 $ .62

In 1996, 1995 and 1994, approximately 55 percent, 58 percent and 66
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, 1996. These reserves
have been reduced for royalty interests owned by others.

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

Proved Developed Reserves...................... 4,314 174.2 5,359
Proved Undeveloped Reserves.................... 900 29.4 1,076
----- ----- -----
Total Proved Reserves................ 5,214 203.6 6,435
===== ===== =====

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."

MARKETING

Marketing Strategy. In pursuit of its objective to build long-term
shareholder value, 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
Burlington Resources Trading Inc. ("BRTI"), a wholly-owned marketing subsidiary
of the Company. However, most of the Company's crude oil production is sold at
the wellhead to third parties.

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NGL Marketing. 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 15.4 MMBbls, 13.3 MMBbls and 12.7 MMBbls,
for the years ended December 31, 1996, 1995 and 1994, respectively.

Transportation. The Company enters into contracts which provide firm
transportation capacity rights on interstate and intrastate pipeline systems.
Currently, approximately one-half of the Company's demand charges are for
eastward transportation from the San Juan Basin. The cost of such transportation
is expected to continue to be more than offset by (i) the proceeds received from
the sale of gas at locations east of the San Juan Basin and (ii) increases in
realized San Juan Basin prices which occur as a result of less supply competing
for California demand.

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. All of the Company's sales
of gas are deregulated.

The Company operates various gathering systems. The United States
Department of Transportation and comparable state agencies regulate, under
various enabling statutes, the safety aspects of the transportation and storage
activities of these facilities by prescribing safety and operating standards.
The FERC has implemented orders deregulating the field area services of
affiliates of interstate pipeline companies. These orders, while subject to
review by the Supreme Court, have caused state agencies and legislatures to
reexamine the regulation of all gathering systems within their jurisdiction,
including the Company's. The Company does not expect these actions to materially
affect its gathering system operations or revenues.

The FERC has instituted proceedings concerning offshore and interstate
pipeline companies' incentive and/or deregulated ratemaking. These proceedings
are still 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

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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 1996, the Company
filed estimates of oil and gas reserves for the year 1995 with the Department of
Energy. These estimates were not materially different from the reserve data
presented herein.

CERTAIN DEFINITIONS

Gas volumes are stated at the legal pressure base of the state or area in
which the reserves are located and at 60 degrees Fahrenheit. As used in this
Form 10-K, "MCF" means thousand cubic feet, "MMCF" means million cubic feet,
"BCF" means billion cubic feet, "MBbls" means thousands of barrels, "MMBbls"
means millions of barrels, "MCFE" means thousand cubic feet of gas equivalent,
"MMBTU" means million British thermal units, "MMCFE" means million cubic feet of
gas equivalent, "BCFE" means billion cubic feet of gas equivalent and "TCFE"
means trillion cubic feet of gas equivalent. Oil is converted into cubic feet of
gas equivalent based on 6 MCF of gas to one barrel of oil. "NGL" means natural
gas liquids. Proved reserves represent estimated quantities of oil and gas which
geological and engineering data demonstrate with reasonable certainty can be
recovered in future years from known reservoirs under existing economic and
operating conditions. Reservoirs are considered proved if shown to be
economically producible by either actual production or conclusive formation
tests. Reserves which require the use of improved recovery techniques for
production are included in proved reserves if supported by a successful pilot
project or the operation of an installed program. Proved developed reserves are
the portion of proved reserves which can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved undeveloped
reserves are the portion of proved reserves which can be expected to be
recovered from new wells on undrilled proved acreage, or from existing wells
where a relatively major expenditure is required for completion. With respect to
information on working interests in acreage and wells, "net" acreage and "net"
oil and gas wells are obtained by multiplying "gross" acreage and "gross" oil
and gas wells by the Company's working interest percentage in the properties.

EMPLOYEES

The Company had 1,423 and 1,796 employees at December 31, 1996 and 1995,
respectively.

ITEM THREE
LEGAL PROCEEDINGS

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perfected an interlocutory appeal of the class certification order on May 30,
1995. Oral argument on the interlocutory appeal of the class certification order
was heard February 28, 1996. Following the argument, but in advance of a
decision by the appellate court, the parties executed a settlement agreement
dated August 6, 1996, which the trial court preliminarily approved on August 12,
1996. After notice to the class members, the court conducted a hearing on
November 8, 1996, and gave final approval to the terms of the parties'
settlement agreement in its Judgment signed on November 12, 1996. Four class
members who appeared through counsel at the November 8, 1996 hearing to object
to the settlement filed a motion for a new trial or, in the alternative, to
modify, alter or amend judgment, which motion was denied by Order signed
December 16, 1996. Thereafter, the four objectors filed a Notice of Appeal. The
Company intends to defend any appeals vigorously.

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 1996, no matters were submitted to a vote of
security holders.

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EXECUTIVE OFFICERS OF THE REGISTRANT AND PRINCIPAL SUBSIDIARY

THOMAS H. O'LEARY, 62

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, 46

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

President and Chief Executive Officer, Burlington Resources Oil & Gas
Company, 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.

JOHN E. HAGALE, 40

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

Executive Vice President and Chief Financial Officer, Burlington Resources
Oil & Gas Company, 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.

RANDOLPH P. MUNDT, 46

Executive Vice President, Marketing
Burlington Resources
Oil & Gas Company
March 1995 to Present

Senior Vice President, Operations, Burlington Resources Oil & Gas Company,
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, 51

Executive Vice President and Chief
Operating Officer
Burlington Resources
Oil & Gas Company
October 1994 to Present

Senior Vice President, Operations, Burlington Resources Oil & Gas Company,
March 1993 to October 1994; Vice President, Regional Operations, Meridian Oil
Inc., December 1990 to March 1993.

GERALD J. SCHISSLER, 52

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

Executive Vice President, Law and Corporate Affairs, Burlington Resources
Oil and Gas Company, July 1993 to Present; Senior Vice President, Law,
Burlington Resources Inc., December 1993 to December 1995; Consultant, June 1991
to July 1993.

10
13

PART II

ITEM FIVE

MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS

The Company's common stock is traded on the New York Stock Exchange under
the symbol "BR." At December 31, 1996, the number of common stockholders was
20,073.

Information on common stock prices and quarterly dividends is shown on page
36.

ITEM SIX

SELECTED FINANCIAL DATA

The selected financial data for the Company set forth below for the five
years ended December 31, 1996 should be read in conjunction with the
consolidated financial statements.

1996 1995 1994 1993 1992
---- ---- ---- ---- ----
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

CONTINUING OPERATIONS FOR THE YEAR ENDED
Revenues.................................... $1,293 $ 873 $1,055 $1,043 $ 943
Operating Income (Loss)..................... 418 (467) 175 256 240
Income (Loss)............................... 255 (280) 154 256 190
Earnings (Loss) per Common Share(a)......... 2.02 (2.20) 1.20 1.96 1.44
Cash Dividends Declared per Common
Share(b)................................. $ .55 $ .55 $ .55 $ .55 $ .60
AT YEAR END
Total Assets(c)............................. $4,316 $4,142 $4,809 $4,448 $4,470
Long-term Debt.............................. 1,347 1,350 1,309 819 1,003
Stockholders' Equity(c)..................... $2,333 $2,220 $2,568 $2,608 $2,406
Common Shares Outstanding................... 125 127 127 130 129

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

(a) Excluding the charge related to the divestiture program and reorganization
for severance and other related exit costs totaling $.15 per share, Earnings
per Common Share would have been $2.17 in 1996. Excluding non-recurring
items totaling $2.39, $.47 and $.24 per share, Earnings per Common Share
would have been $.19, $1.49 and $1.20 in 1995, 1993 and 1992, 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 from
$.175 per share 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).

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14

ITEM SEVEN

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

FINANCIAL CONDITION AND LIQUIDITY

The Company's total long-term debt to capital (long-term debt and
stockholders' equity) ratio at December 31, 1996 and 1995 was 37 percent and 38
percent, respectively. In February 1996, the Company issued $150 million of
6.875% Debentures due February 15, 2026. 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.

During 1996, the Company repurchased approximately 2.7 million shares of
its common stock for $112 million. Since December 1988, the Company has
repurchased approximately 30 million shares and currently has the Board of
Directors' approval to repurchase an additional 10 million shares.

Net cash provided by operating activities for 1996 was $652 million
compared to $452 million and $498 million in 1995 and 1994, respectively. The
increase in 1996 compared to 1995 was primarily due to significantly higher
operating income and $108 million in proceeds received from a prepaid premium,
partially offset by other changes in working capital. The prepaid premium
related to an obligation to deliver gas from certain coal seam wells through
December 31, 2002. Net cash provided by operating activities in 1995 included
the sale of a receivable related to a claim resulting from the breach of a
take-or-pay gas contract and the sale of gas-in-storage inventory for
approximately $39 million and $20 million, respectively.

The Company is involved in certain environmental proceedings and other
related matters. Although it is possible that new information or future
developments could require the Company to reassess its potential exposure
related to these matters, the Company believes, based upon available
information, the resolution of these issues will not have a materially adverse
effect on the consolidated financial position or results of operations of the
Company.

The Company has certain commitments and uncertainties related to its normal
operations. Management believes that there are no commitments, uncertainties or
contingent liabilities that will have a materially adverse effect on the
consolidated financial position or results of operations of the Company.

CAPITAL EXPENDITURES AND RESOURCES

Capital expenditures during 1996 totaled $554 million compared to $589
million and $882 million in 1995 and 1994, respectively. The Company spent $111
million for property acquisitions in 1996 compared to $143 million and $501
million in 1995 and 1994, respectively. The Company spent $408 million on
internal development and exploration during 1996 compared to $404 million and
$309 million in 1995 and 1994, respectively.

12
15

Capital expenditures for 1997, projected to be approximately $650 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 gas production is expected to 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

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
Burlington Resources Trading Inc., a wholly-owned marketing subsidiary of the
Company. However, most of the Company's crude oil production is sold at the
wellhead to third parties.

DIVIDENDS

On January 16, 1997, the Board of Directors declared a common stock
quarterly dividend of $.1375 per share, payable April 1, 1997. 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 $69 million during 1996.

RESULTS OF OPERATIONS

Year Ended December 31, 1996 Compared With Year Ended December 31, 1995

The Company reported net income of $255 million or $2.02 per share in 1996
compared to a net loss of $280 million or $2.20 per share in 1995. 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 $1,293 million in 1996 compared to $873 million in 1995.
Average gas sales prices increased 53 percent in 1996 to $1.91 per MCF and
average oil prices increased 24 percent to $20.69 per barrel which increased
revenues $296 million and $75 million, respectively. Oil and gas sales

13
16

volumes increased primarily due to continued development and exploration of the
Company's oil and gas properties and producing property acquisitions. Gas sales
volumes improved 5 percent to 1,225 MMCF per day and oil sales volumes improved
6 percent to 51.1 MBbls per day which increased revenues $27 million and $19
million, respectively.

Costs and Expenses were $875 million in 1996 compared to $1,340 million in
1995. Costs and expenses in 1995 included a $490 million non-cash charge related
to the impairment of oil and gas properties which resulted from the Company's
adoption of SFAS No. 121, effective September 30, 1995. Excluding the $490
million non-cash charge, costs and expenses for 1996 increased $25 million
compared to 1995. The increase was primarily due to an approximate $30 million
reorganization charge for severance and other related exit costs, a $21 million
increase in production and processing expenses resulting from a 6 percent
increase in 1996 production levels and a $10 million increase in exploration
costs. These increases were partially offset by a $24 million decrease in
depreciation, depletion and amortization primarily due to the adoption of SFAS
No. 121, a $9 million decrease in general and administrative expenses and a $3
million decrease in intrastate natural gas purchases.

Interest Expense was $113 million in 1996 compared to $109 million in 1995.
The increase was due to additional fixed-rate debt issued in February 1996
partially offset by lower outstanding commercial paper balances.

The effective income tax rate was an expense of 17 percent in 1996 compared
to a benefit of 52 percent in 1995. The increased tax expense in 1996 was due to
higher pretax income and a decline in non-conventional fuel tax credits earned.
The beneficial tax rate in 1995 was due to a pretax loss and the effect of
non-conventional fuel tax credits.

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 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 $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 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 fixed-rate debt issued in March
1995 and May 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 was due to a
pretax loss and non-conventional fuel tax credits earned. The beneficial tax
rate in 1994 was due to low pretax income relative to the amount of
non-conventional fuel tax credits earned.

14
17

OTHER MATTERS

In September 1996, the Company received cash proceeds of $108 million for a
transaction in which it conveyed a working interest in certain coal seam gas
wells and retained a volumetric production payment. The cash proceeds
represented a prepaid premium related to an obligation to deliver gas from the
wells through December 31, 2002. The prepaid premium was recorded as deferred
revenue and is being amortized into revenues as the gas is produced.
Approximately $13 million of the deferred revenue was recognized in 1996.

FORWARD-LOOKING STATEMENTS

The Company may, in discussions of its future plans, objectives and
expected performance in periodic reports filed by the Company with the
Securities and Exchange Commission (or documents incorporated by reference
therein) and in written and oral presentations made by the Company, include
projections or other forward-looking statements within the meaning of Section
27A of the Securities Act of 1933 or Section 21E of the Securities Exchange Act
of 1934, as amended. Such projections and forward-looking statements are based
on assumptions which the Company believes are reasonable, but are by their
nature inherently uncertain. In all cases, there can be no assurance that such
assumptions will prove correct or that projected events will occur, and actual
results could differ materially from those projected. Some of the important
factors that could cause actual results to differ from any such projections or
other forward-looking statements follow.

Commodity Pricing and Demand. Substantially all of the Company's crude oil
and natural gas production is sold on the spot market or under short-term
contracts at market sensitive prices. Spot market prices for natural gas are
subject to volatile trading patterns in the commodity futures markets, including
among others, the New York Mercantile Exchange ("NYMEX"), because of seasonal
weather patterns, national supply and demand factors and general economic
conditions. Although the futures markets provide some indication of crude oil
and natural gas prices for the subsequent 12 to 18 months, prices in the futures
markets are subject to substantial changes in relatively short periods of time.

There is also a difference between the NYMEX futures contract price for a
particular month and the actual cash price received for that month in a
producing basin or at a market hub, which is referred to as the "basis
differential." Basis differentials, like the underlying commodity prices, can be
volatile because of regional supply and demand factors, including seasonal
factors and the availability and

15
18

price of transportation to consuming areas. Crude oil prices are affected by
similar factors, by quality differentials, by worldwide political developments,
and by actions of the Organization of Petroleum Exporting Countries.

In the ordinary course and conduct of its business, the Company utilizes
futures contracts traded on NYMEX and the Kansas City Board of Trade, and
over-the-counter price and basis swaps with major crude oil and natural gas
merchants and financial institutions to hedge its price risk exposure related to
the Company's production and to fixed price commitments to sell crude oil and
natural gas. Losses incurred as a result of derivatives transactions would
reduce the realized price the Company receives for its crude oil and natural gas
production.

Changes in crude oil and natural gas prices (including basis differentials)
from those assumed in preparing projections and forward-looking statements could
cause the Company's actual financial results to differ materially from projected
financial results and can also impact the Company's determination of proved
reserves and the standardized measure of discounted future net cash flows
relative to crude oil and natural gas reserves. In addition, periods of sharply
lower commodity prices could affect the Company's production levels and/or cause
it to curtail capital spending projects and delay or defer exploration,
exploitation or development projects.

Projections relating to the price received by the Company for natural gas
also rely on assumptions regarding the availability and pricing of
transportation to the Company's key markets. In particular, the Company has
contractual arrangements for the transportation of natural gas from the San Juan
Basin eastward to Eastern and Midwestern markets or to market hubs in Texas,
Oklahoma and Louisiana. The natural gas price received by the Company could be
adversely affected by any constraints in pipeline capacity to serve these
markets.

Exploration and Production Risks. The Company's business is subject to all
of the risks and uncertainties normally associated with the exploration for and
development and production of crude oil and natural gas.

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. The process of estimating
quantities of proved reserves is inherently uncertain and involves subjective
engineering and economic determinations. In this regard, changes in the economic
conditions (including commodity prices) or operating conditions (including,
without limitation, exploration, development and production costs and expenses
and drilling results from exploration and development activity) could cause the
Company's estimated proved reserves or production to differ from those included
in any such forward-looking statements or projections.

Projecting future crude oil and natural gas production is imprecise.
Producing oil and gas reservoirs eventually have declining production rates.
Projections of production rates rely on certain assumptions regarding historical
production patterns in the area or formation tests for a particular producing
horizon. Actual production rates could differ materially from such projections.
Production rates depend on a number of additional factors, including commodity
prices, market demand and the political, economic and regulatory climate.

Another major factor affecting the Company's production is its ability to
replace depleting reservoirs with new reserves through acquisition, exploration
or development programs. Exploration success is extremely difficult to predict
with certainty, particularly over the short term where the timing and extent of
successful results vary widely. Over the long term, the ability to replace
reserves depends not only on the Company's ability to locate crude oil and
natural gas reserves, but on the cost of finding and developing such reserves.
Moreover, development of any particular exploration or development project may
not be justified because of the commodity price environment at the time or
because of the Company's finding and development costs for such project. No
assurances can be given as to the level or timing of success that the Company
will be able to achieve in acquiring or finding and developing additional
reserves.

16
19

Projections relating to the Company's production and financial results rely
on certain assumptions about the Company's continued success in its acquisition
and asset rationalization programs and in its cost management efforts.

The Company's drilling operations are subject to various hazards common to
the oil and gas industry, including explosions, fires, and blowouts, which could
result in damage to or destruction of oil and gas wells or formations,
production facilities and other property and injury to people. They are also
subject to the additional hazards of marine operations, such as capsizing,
collision and damage or loss from severe weather conditions.

Development Risk. A significant portion of the Company's development plans
involve large projects in the Gulf of Mexico and other areas. A variety of
factors affect the timing and outcome of such projects including, without
limitation, approval by the other parties owning working interests in the
project, receipt of necessary permits and approvals by applicable governmental
agencies, the availability of the necessary drilling equipment, delivery
schedules for critical equipment and arrangements for the gathering and
transportation of the produced hydrocarbons.

Asset Rationalization Program. In July 1996, the Company announced the
acceleration of its on-going divestiture program. The failure to complete this
accelerated divestiture program, or any delay in this process, could have an
adverse effect on the Company's ability to realize planned cost reductions and
on its financial results.

Competition. The Company actively competes for property acquisitions,
exploration leases and sales of crude oil and natural 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 natural gas and natural gas liquids
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.

Political and Regulatory Risk. The Company's operations are affected by
federal, state and local laws and regulations such as restrictions on
production, changes in taxes, royalties and other amounts payable to governments
or governmental agencies, price or gathering rate controls and environmental
protection regulations. Changes in such laws and regulations, or interpretations
thereof, could have a significant effect on the Company's operations or
financial results.

Potential Environmental Liabilities. The Company's operations are subject
to various federal, state and local laws and regulations covering the discharge
of material into, and protection of, the environment. Such regulations affect
the costs of planning, designing, operating and abandoning facilities. The
Company expends considerable resources, both financial and managerial, to comply
with environmental regulations and permitting requirements. Although the Company
believes that its operations and facilities are in general compliance with
applicable environmental laws and regulations, risks of substantial costs and
liabilities are inherent in crude oil and natural gas operations. Moreover, it
is possible that other developments, such as increasingly strict environmental
laws, regulations and enforcement, and claims for damage to property or persons
resulting from the Company's current or discontinued operations, could result in
substantial costs and liabilities in the future.

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20

ITEM EIGHT

FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF INCOME

YEAR ENDED DECEMBER 31,
-----------------------------------------
1996 1995 1994
--------- --------- ---------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

Revenues................................................... $1,293 $ 873 $1,055
Costs and Expenses......................................... 875 1,340 880
------ ------ ------
Operating Income (Loss).................................... 418 (467) 175
Interest Expense........................................... 113 109 90
Other Expense (Income) -- Net.............................. (2) 1 (5)
------ ------ ------
Income (Loss) Before Income Taxes.......................... 307 (577) 90
Income Tax Expense (Benefit)............................... 52 (297) (64)
------ ------ ------
Net Income (Loss).......................................... $ 255 $ (280) $ 154
====== ====== ======
Earnings (Loss) per Common Share........................... $ 2.02 $(2.20) $ 1.20
====== ====== ======

See accompanying Notes to Consolidated Financial Statements.

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21

BURLINGTON RESOURCES INC.

CONSOLIDATED BALANCE SHEET

DECEMBER 31,
----------------------
1996 1995
-------- --------
(IN MILLIONS, EXCEPT
SHARE DATA)

ASSETS

Current Assets
Cash and Short-term Investments........................... $ 68 $ 20
Accounts Receivable....................................... 338 210
Inventories............................................... 18 18
Other Current Assets...................................... 18 17
------ ------
442 265
------ ------
Oil and Gas Properties (Successful Efforts Method).......... 5,843 5,870
Other Properties............................................ 485 499
------ ------
6,328 6,369
Accumulated Depreciation, Depletion and Amortization...... 2,548 2,602
------ ------
Properties -- Net...................................... 3,780 3,767
------ ------
Other Assets................................................ 94 110
------ ------
Total Assets...................................... $4,316 $4,142
====== ======

LIABILITIES

Current Liabilities
Accounts Payable.......................................... $ 217 $ 214
Taxes Payable............................................. 62 59
Accrued Interest.......................................... 23 20
Dividends Payable......................................... 17 17
Deferred Revenue.......................................... 20 -
Other Current Liabilities................................. 29 12
------ ------
368 322
------ ------
Long-term Debt.............................................. 1,347 1,350
------ ------
Deferred Income Taxes....................................... 85 87
------ ------
Deferred Revenue............................................ 75 -
------ ------
Other Liabilities and Deferred Credits...................... 108 163
------ ------
Commitments and Contingent Liabilities
STOCKHOLDERS' EQUITY

Common Stock, Par Value $.01 Per Share (Authorized
325,000,000 Shares; Issued 150,000,000 Shares)............ 2 2
Paid-in Capital............................................. 2,932 2,935
Retained Earnings........................................... 388 202
------ ------
3,322 3,139
Cost of Treasury Stock (25,081,301 and 23,425,621 Shares for
1996 and 1995, respectively).............................. 989 919
------ ------
Common Stockholders' Equity................................. 2,333 2,220
------ ------
Total Liabilities and Common Stockholders'
Equity........................................... $4,316 $4,142
====== ======

See accompanying Notes to Consolidated Financial Statements.

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22

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31,
------------------------------------
1996 1995 1994
-------- -------- --------
(IN MILLIONS)

Cash Flows From Operating Activities
Net Income (Loss)......................................... $ 255 $(280) $ 154
Adjustments to Reconcile Net Income (Loss) to Net Cash
Provided By Operating Activities
Depreciation, Depletion and Amortization............... 346 373 337
Deferred Income Taxes.................................. (2) (371) (86)
Exploration Costs...................................... 62 51 33
Impairment of Oil and Gas Properties................... - 490 -
Working Capital Changes
Accounts Receivable.................................... (128) (16) 25
Inventories............................................ - 17 (11)
Other Current Assets................................... (1) 1 (3)
Accounts Payable....................................... 3 36 (13)
Taxes Payable.......................................... 3 12 (11)
Accrued Interest....................................... 3 4 4
Other Current Liabilities.............................. 37 9 (18)
Other..................................................... 74 126 87
----- ----- -----
Net Cash Provided By Operating Activities......... 652 452 498
----- ----- -----
Cash Flows From Investing Activities
Additions to Properties................................... (554) (589) (882)
Proceeds from Sales and Other............................. 131 183 83
----- ----- -----
Net Cash Used In Investing Activities............. (423) (406) (799)
----- ----- -----
Cash Flows From Financing Activities
Proceeds from Long-term Financing......................... 150 150 489
Reduction in Long-term Debt............................... (152) (108) -
Dividends Paid............................................ (69) (70) (71)
Common Stock Purchases.................................... (112) (5) (122)
Other..................................................... 2 (12) 5
----- ----- -----
Net Cash Provided By (Used In) Financing
Activities...................................... (181) (45) 301
----- ----- -----
Increase in Cash and Short-term Investments................. 48 1 -
Cash and Short-term Investments
Beginning of Year......................................... 20 19 19
----- ----- -----
End of Year............................................... $ 68 $ 20 $ 19
===== ===== =====

See accompanying Notes to Consolidated Financial Statements.

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23

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY

COST OF COMMON
COMMON PAID-IN RETAINED TREASURY STOCKHOLDERS'
STOCK CAPITAL EARNINGS STOCK EQUITY
------ ------- -------- -------- -------------
(IN MILLIONS, EXCEPT SHARE DATA)

Balance, December 31, 1993................. $2 $2,937 $468 $(798) $2,609
Net Income............................... 154 154
Cash Dividends ($.55 per Share).......... (71) (71)
Stock Purchases (3,139,600 Shares)....... (122) (122)
Stock Option Activity and Other.......... (1) (1) (2)
-- ------ ---- ----- ------
Balance, December 31, 1994................. 2 2,936 551 (921) 2,568
Net Loss................................. (280) (280)
Cash Dividends ($.55 per Share).......... (69) (69)
Stock Purchases (132,900 Shares)......... (5) (5)
Stock Option Activity and Other.......... (1) 7 6
-- ------ ---- ----- ------
Balance, December 31, 1995................. 2 2,935 202 (919) 2,220
Net Income............................... 255 255
Cash Dividends ($.55 per Share).......... (69) (69)
Stock Purchases (2,706,000 Shares)....... (112) (112)
Stock Option Activity and Other.......... (3) 42 39
-- ------ ---- ----- ------
Balance, December 31, 1996................. $2 $2,932 $388 $(989) $2,333
== ====== ==== ===== ======

See accompanying Notes to Consolidated Financial Statements.

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24

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. Actual results could differ
from estimates. The financial statements for previous periods include certain
reclassifications that were made to conform to current presentation. Such
reclassifications have no impact on previously reported net income or
stockholders' equity.

Cash and Short-term Investments

All short-term investments purchased with a maturity of three months or
less are considered cash equivalents. Cash equivalents are stated at cost, which
approximates market value.

Inventories

Inventories of materials, supplies and products are valued at the lower of
average cost or market.

Properties

Oil and gas properties are accounted for using the successful efforts
method. Under this method, all development costs and acquisition costs of proved
properties are capitalized and amortized on a units-of-production basis over the
remaining life of proved developed reserves and proved reserves, respectively.
Costs of drilling exploratory wells are initially capitalized, but charged to
expense if and when a well is determined to be unsuccessful. In addition,
unamortized capital costs at a field level are reduced to fair value if the sum
of expected undiscounted future cash flows 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, oil and gas
futures and options transactions may be entered into as hedges of the Company's
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 swap agreements to hedge oil
or gas and 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.

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25

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 including common shares equivalents when
dilutive. The weighted average number of common shares outstanding was 126
million, 127 million and 129 million for the years 1996, 1995 and 1994,
respectively.

2. DIVESTITURE PROGRAM AND REORGANIZATION

3. SALE OF COAL SEAM GAS WELLS

23
26

4. 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.

1996 1995 1994
---- ---- ----

Oil (MBbls per day)..................................... 58 272 467
Gas (MMCF per day)...................................... 567 604 549
NGLs (MBbls per day).................................... 14 12 11

Hedging and Related Transactions

In 1993, the Company entered into a gas swap agreement to offset the
effects of a long-term fixed-price contract for 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 Company expects that there will be no gain or loss on these
transactions.

The Company is a fixed-price payor on approximately 5.6 BCF (which
approximates 1 percent of the Company's 1996 gas production) at prices ranging
from $1.38 to $2.40 per MMBTU for production through December 31, 1997. These
transactions convert fixed-price contracts to market-sensitive contracts. The
Company is a fixed-price receivor on approximately 16.3 BCF (which approximates
4 percent of the Company's 1996 gas production) at prices ranging from $1.80 to
$3.67 per MMBTU for production through December 31, 1997. These transactions are
a hedge of the Company's underlying production. The deferred loss on these types
of transactions as of December 31, 1996 was $9.8 million. This opportunity loss
will be substantially offset in the cash market when the hedged commodity is
delivered in 1997, which has the effect of fixing the price at which the
commodity is sold.

The Company sells oil and gas futures contracts on the New York Mercantile
Exchange ("NYMEX") and sells gas futures contracts on the Kansas City Board of
Trade ("KBOT"). 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, 1996 totaled 2,930 MBbls (which
approximates 16 percent of the Company's 1996 oil production) at NYMEX prices
ranging from $20.50 to $25.10 per barrel for production through November 1997.
The natural gas positions outstanding as of December 31, 1996 totaled 11.5 BCF
(which approximates 3 percent of the Company's 1996 gas production) at NYMEX and
KBOT prices ranging from $2.39 to $3.84 per MMBTU for production through April
1997. The deferred loss on oil and gas futures contracts as of December 31, 1996
was $12.2 million. This opportunity loss will be substantially offset in the
cash market when the hedged commodity is delivered in 1997, which has the effect
of fixing the price at which the commodity is sold.

24
27

5. INCOME TAXES

The provision (benefit) for income taxes follows.

YEAR ENDED DECEMBER 31,
-------------------------
1996 1995 1994
---- ----- ----
(IN MILLIONS)

Current
Federal................................................... $ 48 $ 61 $ 23
State..................................................... 6 12 (1)
---- ----- ----
54 73 22
---- ----- ----
Deferred
Federal................................................... (11) (331) (89)
State..................................................... 9 (39) 3
---- ----- ----
(2) (370) (86)
---- ----- ----
Total............................................. $ 52 $(297) $(64)
==== ===== ====

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

YEAR ENDED DECEMBER 31,
-----------------------------
1996 1995 1994
----- ------ ------

Statutory rate.............................................. 35.0% (35.0)% 35.0%
State income taxes net of federal tax benefit............... 3.2 (3.0) 1.1
Tax credits................................................. (21.1) (14.5) (103.3)
Other....................................................... (.3) 1.0 (3.7)
----- ------ ------
Effective rate.................................... 16.8% (51.5)% (70.9)%
===== ====== ======

Deferred tax liabilities (assets) follow.

DECEMBER 31,
----------------
1996 1995
----- -----
(IN MILLIONS)

Deferred liabilities
Excess of book over tax basis of properties............... $ 285 $ 284
Financial accruals and provisions......................... 5 -
----- -----
290 284
----- -----
Deferred assets
Financial accruals and provisions......................... - (16)
AMT credits carryover..................................... (205) (181)
----- -----
(205) (197)
----- -----
Net deferred liability............................ $ 85 $ 87
===== =====

The above net deferred tax liabilities as of December 31, 1996 and 1995,
include deferred state income tax liabilities of approximately $28 million and
$18 million, respectively.

As of December 31, 1996, the Alternative Minimum Tax ("AMT") credits
carryover of approximately $205 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 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.

25
28

6. LONG-TERM DEBT

Long-term Debt follows.

DECEMBER 31,
------------------
1996 1995
------ ------
(IN MILLIONS)

Commercial Paper............................................ $ - $ 152
Notes, 7.15%, due 1999...................................... 300 300
Notes, 6 7/8%, due 1999..................................... 150 150
Notes, 9 5/8%, due 2000..................................... 150 150
Notes, 8 1/2%, due 2001..................................... 150 150
Debentures, 9 7/8%, due 2010................................ 150 150
Debentures, 9 1/8%, due 2021................................ 150 150
Debentures, 8.20%, due 2025................................. 150 150
Debentures, 6 7/8%, due 2026................................ 150 -
Other, including discounts -- net........................... (3) (2)
------ ------
Total............................................. $1,347 $1,350
====== ======

The Company has debt maturities of $450 million, $150 million and $150
million due in 1999, 2000 and 2001, respectively.

The Company's credit facilities are comprised of a $600 million revolving
credit agreement that expires in July 2001 and a $300 million revolving credit
agreement that expires July 1997. The $300 million revolving credit agreement is
renewable annually by mutual consent and was renewed in July 1996. Annual fees
are .10 and .06 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, 1996, there were no borrowings outstanding under these credit
facilities. In addition, the Company has the capacity to issue $200 million of
debt securities under a shelf registration statement filed with the Securities
and Exchange Commission.

7. TRANSPORTATION ARRANGEMENTS WITH EL PASO NATURAL GAS COMPANY

In 1996, 1995 and 1994, approximately 55 percent, 58 percent and 66
percent, respectively, of the Company's gas production was transported to direct
sale customers through El Paso Natural Gas Company's ("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 10 for demand charges paid
to EPNG which provide the Company with firm and interruptible transportation
capacity rights on interstate and intrastate pipeline systems.

8. CAPITAL STOCK

Stock Options

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

26
29

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 and have a term of ten years. At December 31, 1996, 6,441,190 shares
of options were available for grant under the 1993 Plan.

Stock Appreciation Rights

The Company has granted SARs in connection with certain outstanding options
under the 1988 Plan. SARs are subject to the same terms and conditions as the
related options. A SAR entitles an option holder, in lieu of exercise of an
option, to receive a cash payment equal to the difference between the option
price and the fair market value of the Company's common stock based upon the
plan provisions. To the extent the SAR is exercised, the related option is
cancelled and to the extent the option is exercised the related SAR is
cancelled. The outstanding SARs are exercisable only under certain circumstances
related to significant changes in the ownership of the Company or its holdings,
or certain changes in the constitution of its Board of Directors. At December
31, 1996, there were 406,633 SARs outstanding related to stock options with a
weighted average exercise price of $27.19 per share.

Activity in the Company's stock option plans follows.

WEIGHTED AVERAGE
OPTIONS EXERCISE PRICE
------- ----------------

Balance, December 31, 1993.................................. 2,933,173 $32.57
Granted................................................... 430,200 34.04
Exercised................................................. (62,631) 44.26
Cancelled................................................. (154,407) 35.47
----------
Balance, December 31, 1994.................................. 3,146,335 32.69
Granted................................................... 415,600 39.93
Exercised................................................. (177,365) 29.66
Cancelled................................................. (31,300) 34.01
----------
Balance, December 31, 1995.................................. 3,353,270 33.74
Granted................................................... 2,430,900 50.76
Exercised................................................. (1,038,864) 30.82
Cancelled................................................. (67,642) 39.76
----------
Balance, December 31, 1996.................................. 4,677,664 $43.15
==========

The following table summarizes information related to stock options
outstanding and exercisable at December 31, 1996.

WEIGHTED
WEIGHTED AVERAGE WEIGHTED
AVERAGE REMAINING AVERAGE
SHARES RANGE OF EXERCISE EXERCISE CONTRACTUAL SHARES EXERCISE
OUTSTANDING PRICES PRICE LIFE EXERCISABLE PRICE
- ----------- ----------------- -------- ----------- ----------- --------

1,015,646 $21.54 to $31.83 $29.48 4.1 years 1,015,646 $29.48
3,662,018 33.88 to 50.81 46.94 9.1 years 1,243,118 39.40
--------- ---------
4,677,664 $21.54 to $50.81 $43.15 8.0 years 2,258,764 $34.94
========= =========

In October 1995, the Financial Accounting Standards Board issued SFAS No.
123, Accounting for Stock-Based Compensation, which is effective for the
Company's fiscal year beginning January 1, 1996.

SFAS No. 123 establishes financial accounting and reporting standards for
stock-based employee compensation plans. It 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

27
30

employee stock compensation plans and include the cost in the income statement
as compensation expense. 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. The Company accounts for compensation
cost for stock option plans in accordance with APB Opinion No. 25.

The weighted average fair values of options granted during the years 1996
and 1995 were $13.15 and $9.38, respectively. The fair values of employee stock
options were calculated using a variation of the Black-Scholes stock option
valuation model with the following weighted average assumptions for grants in
1996 and 1995: stock price volatility of 17.94 percent; risk free rate of return
ranging from 5.45 percent to 6.90 percent; dividend rate of $.55 per year; and
an expected term of 5 years. If the fair value based method of accounting in
SFAS 123 had been applied, the Company's net income and earnings per share would
have been reduced to the pro forma amounts indicated below.

YEAR ENDED
DECEMBER 31,
1996
--------------------
(IN MILLIONS, EXCEPT
PER SHARE AMOUNTS)

Net Income -- as reported................................... $ 255
Net Income -- pro forma..................................... 252
Earnings per Common Share -- as reported.................... 2.02
Earnings per Common Share -- pro forma...................... $1.99

The fair value of stock options for year 1995 did not result in a change to
reported Net Income or Earnings per Common Share and, therefore, no pro forma
disclosures for that period are included. The fair value of stock options
included in the pro forma amounts for year 1996 is not necessarily indicative of
future effects on net income and earnings 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, 1996 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 $.05
per Right.

28
31

9. 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.

The following information relates to the Company plans.

DECEMBER 31,
----------------------
1996 1995
-------- --------
(IN MILLIONS)

Actuarial present value of benefit obligations
Accumulated benefit obligation, including vested
benefits of $98 and $101............................... $ 101 $ 104
======== ========

Projected benefit obligation for service to date.......... $ 129 $ 145
Plan assets, primarily marketable equity and debt
securities, at fair value................................. (119) (113)
-------- --------
Funded status of projected benefit obligation............... 10 32
Unrecognized net loss....................................... (20) (44)
Unamortized net transition obligation....................... (2) (3)
-------- --------
Net prepaid pension asset................................... $ (12) $ (15)
======== ========

YEAR ENDED DECEMBER 31,
------------------------
1996 1995 1994
---- ---- ----
(IN MILLIONS)

Pension cost for the plans includes the following components
Service cost -- benefits earned during the period......... $ 6 $ 6 $ 7
Interest cost on projected benefit obligation............. 10 9 9
Actual (return) loss on plan assets....................... (15) (18) 1
Net amortization and deferred amounts..................... 9 12 (5)
---- ---- ----
Net pension cost.......................................... $ 10 $ 9 $ 12
==== ==== ====

The projected benefit obligation was determined using a weighted average
discount rate of 7.75 percent in 1996 and 7.50 percent in 1995, 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 1996 and 1995.

During 1996, the Company recognized a curtailment expense of approximately
$500 thousand related to the employee reduction associated with the
reorganization.

10. COMMITMENTS AND CONTINGENT LIABILITIES

Demand Charges

The Company has entered into contracts which provide firm transportation
capacity rights on interstate and intrastate pipeline systems. The remaining
terms on these contracts range in terms from 1 to 11 years and require the
Company to pay transportation demand charges regardless of the amount of
pipeline capacity utilized by the Company. The Company paid $61 million, $53
million and $48 million of demand charges of which $47 million, $40 million and
$37 million was paid to EPNG for the years ended December 31, 1996, 1995 and
1994, respectively.

Currently, approximately one-half of the Company's demand charges are for
eastward transportation from the San Juan Basin. This transportation cost was
more than offset by (i) the proceeds

29
32

received from the sale of gas at locations east of the San Juan Basin and (ii)
increases in realized San Juan Basin prices which occurred as a result of less
supply competing for California market demand.

Future transportation demand charge commitments at December 31, 1996
follow.

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

1997........................................................ $ 63
1998........................................................ 63
1999........................................................ 63
2000........................................................ 45
2001........................................................ 39
Thereafter.................................................. 201
--------
Total.................................................. $ 474
========

Lease Obligations

The Company has operating leases for office space and other property and
equipment. The Company incurred lease rental expense of $14 million, $14 million
and $17 million for the years ended December 31, 1996, 1995 and 1994,
respectively.

Future minimum annual rental commitments at December 31, 1996 follow.

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

1997........................................................ $ 15
1998........................................................ 14
1999........................................................ 12
2000........................................................ 9
2001........................................................ 9
Thereafter.................................................. 70
--------
Total.................................................. $ 129
========

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. (now known as Burlington Resources Oil & Gas Company), et al., which
allowed the suit to be maintained as a class action on behalf of all royalty and
overriding royalty interest owners in all Burlington Resources Oil & Gas Company
("BROG") properties and all working interest owners in properties operated by
BROG who received payments from BROG at any time from and after December 1, 1986
based upon wellhead sales of natural gas to Burlington Resources Trading Inc.
("BRTI"). 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 corporate affiliates to gather, treat and market natural gas. The
plaintiffs allege that BROG's gas producing affiliates have sold natural gas to
marketing affiliates at lower inter-affiliate settlement prices which were then
used as the basis for accounting to interest owners. Plaintiffs also allege that
BROG's pricing includes inappropriate deductions of inflated gathering and
transportation costs. BROG has consistently denied liability and perfected an
interlocutory appeal of the class certification order on May 30, 1995. Oral
argument on the interlocutory appeal of the class certification order was heard
February 28, 1996. Following the argument, but in advance of a decision by the
appellate court, the parties executed a settlement agreement dated August 6,
1996, which the trial court preliminarily approved on August 12, 1996. After
notice to the class members, the court conducted a hearing on November 8, 1996,
and gave final approval to the terms of the parties' settlement agreement in its

30
33

Judgment signed on November 12, 1996. Four class members who appeared through
counsel at the November 8, 1996 hearing to object to the settlement filed a
motion for a new trial or, in the alternative, to modify, alter or amend
judgment, which motion was denied by Order signed December 16, 1996. Thereafter,
the four objectors filed a Notice of Appeal. The Company intends to defend any
appeals vigorously.

11. IMPAIRMENT OF OIL AND GAS PROPERTIES

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.

Under SFAS No. 121, the Company evaluates impairment of its oil and gas
properties on a field-by-field basis rather than in the aggregate. Based upon
this evaluation, in 1995, 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 in September 1995, combined with a
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.

12. OTHER INFORMATION

Supplemental Cash Flow Information

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

YEAR ENDED DECEMBER 31,
------------------------
1996 1995 1994
---- ---- ----
(IN MILLIONS)

Interest Paid...................................... $108 $104 $86
Income Taxes Paid--Net............................. $ 56 $ 61 $41

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34

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, 1996 and 1995, 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, 1996. 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, 1996 and 1995, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1996, in conformity with generally accepted accounting
principles.

As discussed in Note 11 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 15, 1997

32
35

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,
------------------
1996 1995
------ ------
(IN MILLIONS)

Proved properties........................................... $5,795 $5,830
Unproved properties......................................... 48 40
------ ------
5,843 5,870
Accumulated depreciation, depletion and amortization........ 2,350 2,410
------ ------
Net capitalized costs............................. $3,493 $3,460
====== ======

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

YEAR ENDED DECEMBER 31,
------------------------------------
1996 1995 1994
-------- -------- --------
(IN MILLIONS)

Property acquisition
Unproved.................................................. $ 24 $ 39 $ 22
Proved.................................................... 87 104 479
Exploration................................................. 81 80 31
Development................................................. 327 324 278
-------- -------- --------
Total costs incurred.............................. $ 519 $ 547 $ 810
======== ======== ========

Results of operations for oil and gas producing activities follow.

YEAR ENDED DECEMBER 31,
----------------------------------
1996 1995 1994
-------- -------- ------
(IN MILLIONS)

Net revenues................................................ $1,250 $ 826 $ 905
------ ------ ------
Production costs............................................ 295 270 261
Exploration and leasehold impairment costs.................. 62 51 33
Operating expenses.......................................... 180 154 146
Depreciation, depletion and amortization.................... 309 332 300
Impairment of oil and gas properties........................ - 490 -
------ ------ ------
846 1,297 740
------ ------ ------
Operating income (loss)..................................... 404 (471) 165
Income tax provision........................................ 88 (261) (39)
------ ------ ------
Results of operations for oil and gas producing
activities................................................ $ 316 $ (210) $ 204
====== ====== ======

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36

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, 1994........................................... 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(a)...................... 19.7 379
Sales of reserves in place(b).......................... (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(b).......................... (3.9) (200)
----- -----
December 31, 1995......................................... 196.9 5,507
Revision of previous estimates......................... (3.3) (59)
Extensions, discoveries and other additions............ 26.9 416
Production............................................. (18.7) (448)
Purchases of reserves in place......................... 6.0 72
Sales of reserves in place(b).......................... (4.2) (274)
----- -----
December 31, 1996......................................... 203.6 5,214
===== =====
PROVED DEVELOPED RESERVES
January 1, 1994........................................... 149.8 4,381
December 31, 1994......................................... 161.9 4,584
December 31, 1995......................................... 168.1 4,543
December 31, 1996......................................... 174.2 4,314

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

(a) Includes the reserves attributable to the purchase of Diamond Shamrock
Offshore Partners Limited Partnership.

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

34
37

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,
----------------------
1996 1995
-------- --------
(IN MILLIONS)

Future cash inflows......................................... $ 20,816 $ 11,609
Less related future
Production costs....................................... 4,343 3,451
Development costs...................................... 513 529
Income taxes........................................... 4,441 1,401
-------- --------
Future net cash flows............................. 11,519 6,228
10% annual discount for estimated timing of cash flows.... 5,724 3,044
-------- --------
Standardized measure of discounted future net cash
flows................................................. $ 5,795 $ 3,184
======== ========

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,
------------------------------
1996 1995 1994
------ ------ ------
(IN MILLIONS)

January 1................................................... $3,184 $2,998 $3,124
------ ------ ------
Revisions of previous estimates
Changes in prices and costs............................... 4,326 (33) (350)
Changes in quantities..................................... (39) (22) (20)
Changes in rate of production............................. (77) 189 129
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related costs..... 578 250 195
Purchases of reserves in place.............................. 119 99 251
Sales of reserves in place.................................. (176) (124) (67)
Accretion of discount....................................... 376 358 363
Sales of oil and gas, net of production costs............... (955) (556) (644)
Net change in income taxes.................................. (1,333) 11 (80)
Other....................................................... (208) 14 97
------ ------ ------
Net change.................................................. 2,611 186 (126)
------ ------ ------
December 31................................................. $5,795 $3,184 $2,998
====== ====== ======

35
38

BURLINGTON RESOURCES INC.

QUARTERLY FINANCIAL DATA--UNAUDITED

1996 1995
---------------------------------- -----------------------------------------------------
4TH 3RD 2ND 1ST 4TH 3RD 2ND 1ST
------ ------ ------ ------ ----------- ----------- ----------- -----------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

Revenues......................... $ 399 $ 344 $ 295 $ 255 $ 237 $ 210 $ 211 $ 215
Operating Income (Loss)(a)....... 169 90 96 63 20 (489) - 2
Net Income (Loss)................ 110 59 48 38 23 (300) 2 (5)
Earnings (Loss) per Common
Share.......................... .87 .47 .38 .30 .18 (2.36) .02 (.04)
Dividends Declared per Common
Share.......................... .1375 .1375 .1375 .1375 .1375 .1375 .1375 .1375
Common Stock Price Range
High........................... 53 1/2 47 1/8 43 1/4 40 1/4 41 1/4 42 41 1/2 40 3/4
Low............................ $44 1/8 $41 5/8 $35 1/8 $35 5/8 $ 35 1/8 $ 36 7/8 $ 36 3/4 $ 33 7/8

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

(a) As a result of the divestiture program and reorganization, during the third
quarter of 1996, the Company recorded a pretax charge of approximately $30
million. 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.

36
39

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 1997 Annual Meeting of Stockholders of
Burlington Resources Inc. will be filed no later than 120 days after the end of
the fiscal year with the Securities and Exchange Commission. The information set
forth therein under "Election of Directors" and "Executive Compensation" is
incorporated herein by reference. Executive Officers of the Company are listed
on page 10 of this Form 10-K.

ITEM TWELVE

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information required is set forth under the caption "Election of Directors"
in the Proxy Statement for the 1997 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 1997 Annual Meeting of Stockholders and is
incorporated herein by reference.

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.......................... 18
Consolidated Balance Sheet................................ 19
Consolidated Statement of Cash Flows...................... 20
Consolidated Statement of Common Stockholders' Equity..... 21
Notes to Consolidated Financial Statements................ 22
Report of Independent Accountants......................... 32
Supplemental Oil and Gas Disclosures -- Unaudited......... 33
Quarterly Financial Data -- Unaudited..................... 36

AMENDED EXHIBIT INDEX....................................... *

REPORTS ON FORM 8-K

The Company filed no reports on Form 8-K in the fourth quarter.

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

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

37
40

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 16, 1997
----------------------------------------------------- Executive Officer, and
Bobby S. Shackouls Director

JOHN E. HAGALE Executive Vice President and January 16, 1997
- -------------------------------------------------------- Chief Financial Officer
John E. Hagale

HAYS R. WARDEN Senior Vice President, January 16, 1997
- -------------------------------------------------------- Controller and Chief
Hays R. Warden Accounting Officer

THOMAS H. O'LEARY Chairman of the Board January 16, 1997
- --------------------------------------------------------
Thomas H. O'Leary

JOHN V. BYRNE Director January 16, 1997
- --------------------------------------------------------
John V. Byrne

S. PARKER GILBERT Director January 16, 1997
- --------------------------------------------------------
S. Parker Gilbert

LAIRD I. GRANT Director January 16, 1997
- --------------------------------------------------------
Laird I. Grant

JOHN T. LAMACCHIA Director January 16, 1997
- --------------------------------------------------------
John T. LaMacchia

JAMES F. MCDONALD Director January 16, 1997
- --------------------------------------------------------
James F. McDonald

DONALD M. ROBERTS Director January 16, 1997
- --------------------------------------------------------
Donald M. Roberts

WALTER SCOTT, JR. Director January 16, 1997
- --------------------------------------------------------
Walter Scott, Jr.

WILLIAM E. WALL Director January 16, 1997
- --------------------------------------------------------
William E. Wall

38
41

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.

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

/s/ HAYS R. WARDEN
Hays R. Warden
Senior Vice President, Controller and
Chief Accounting Officer

39
42

DIRECTORS OF BURLINGTON RESOURCES INC.
John V. Byrne(1)
President Emeritus
Oregon State University
S. Parker Gilbert(2)
Retired Chairman and
Managing Director
Morgan Stanley Group Inc.
Laird I. Grant(1)
President, Chief Executive
Officer and Chief
Investment Officer
Rockefeller & Co., Inc.
John T. LaMacchia(2)
President and Chief
Executive Officer

Cincinnati Bell Inc.
James F. McDonald(1)
President and Chief
Executive Officer
Scientific-Atlanta, Inc.

Thomas H. O'Leary
Chairman of the Board
Burlington Resources Inc.

Donald M. Roberts(1)
Retired Vice Chairman and
Treasurer
United States Trust
Company of New York and
U.S. Trust Corporation

Walter Scott, Jr.(2)
Chairman and President
Peter Kiewit Sons', Inc.

Bobby S. Shackouls
President and
Chief Executive Officer
Burlington Resources Inc.

William E. Wall(2)
Of Counsel
Siderius Lonergan

(1) Audit Committee
(2) Compensation and
Nominating Committee

CORPORATE INFORMATION

PRINCIPAL CORPORATE OFFICE
Burlington Resources Inc.
5051 Westheimer, Suite 1400
Houston, Texas 77056
(713) 624-9500
STOCK TRANSFER AGENT AND REGISTRAR
Boston EquiServe, L.P.
Shareholder Services
Mail Stop: 45-02-09
P.O. Box 644
Boston, Massachusetts 02102
(617) 575-2900
STOCK EXCHANGE LISTINGS
New York Stock Exchange
Symbol: BR
ANNUAL MEETING
The Annual Meeting of Stockholders will be in Houston, Texas, on March 27, 1997.
Formal notice of the meeting will be mailed in advance.
Additional copies of this Annual Report are available, without charge, by
writing or calling:
Corporate Secretary
Burlington Resources Inc.
P.O. Box 4239
Houston, Texas 77210
(713) 624-9500
43

BURLINGTON RESOURCES INC.

AMENDED EXHIBIT INDEX

The following exhibits are filed as part of this report.

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

3.1 Certificate of Incorporation of Burlington Resources Inc.,
as amended (Exhibit 3.1 to Form 8, filed March 1990)........ *
3.2 By-Laws of Burlington Resources Inc. as amended (Exhibit 3.2
to Form 10-K, filed February 1996).......................... *
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)................................. *
Amendment No. 2 to Form of Rights Agreement (Exhibit 5 to
Form 8-A/A, filed October 1996)............................. *
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 9, 1996........................
+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 9, 1996........................
+10.5 Burlington Resources Inc. Supplemental Benefits Plan as
amended and restated October 9, 1996........................
+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).................................. *

A-1
44

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

Amendment to Employment Contract between Burlington Resources Inc. and Thomas H. O'Leary
(Exhibit 10.6 to Form 10-K, filed February 1996)............................................. *
+10.7 Employment Contract between Burlington Resources Inc. and Bobby S. Shackouls (Exhibit 10.7 to
Form 10-K, filed February 1996).............................................................. *
+10.8 Burlington Resources Inc. Compensation Plan for Non-Employee Directors as amended and
restated October 9, 1996.....................................................................
+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 as amended (Exhibits to Form S-8, No.
2-97533, filed December 1989)................................................................ *
Amendment No. 1 to Burlington Resources Inc. Retirement Savings Plan (Exhibit 10.15 to Form
8, filed March 1993)......................................................................... *
Amendment No. 2 to Burlington Resources Inc. Retirement Savings Plan (Exhibit 10.21 to Form
8, filed February 1992)...................................................................... *
Amendment No. 3 to Burlington Resources Inc. Retirement Savings Plan (Exhibit 10.15 to Form
8, filed March 1993)......................................................................... *
Amendment No. 4 to Burlington Resources Inc. Retirement Savings Plan (Exhibit 10.10 to Form
10-K, filed February 1996)................................................................... *
+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 (Exhibit 10.12 to Form 10-K, filed February 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 as amended and restated October 9,
1996.........................................................................................
+10.18 Burlington Resources Inc. 1993 Stock Incentive Plan (Exhibit 10.22 to Form 10-K, filed
February 1994)............................................................................... *
+10.19 Petrotech Long Term Incentive Plan (Exhibit 10.22 to Form 10-K, filed February 1995)......... *
+10.20 Burlington Resources Inc. 1994 Restricted Stock Exchange Plan (Exhibit 10.23 to Form 10-K,
filed February 1995)......................................................................... *

A-2
45

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

+10.21 Burlington Resources Inc. 1997 Performance Share Unit Plan, effective December 1996..........
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 10.22 to Form 10-K, filed
February 1996)............................................................................... *
First Amendment to Short-term Revolving Credit Agreement, dated as of July 14, 1995..........
Second Amendment to Short-term Revolving Credit Agreement, dated as of July 12, 1996.........
10.23 Second Amended and Restated $600 million Long-term Revolving Credit Agreement, dated as of
July 12, 1996, 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.

+Exhibit constitutes a management contract or compensatory plan or arrangement
required to be filed as an exhibit to this report pursuant to Item 14(c) of
Form 10-K.

A-3