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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, 1997

( ) 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. [ ]

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, 1997:
$7,918,749,701

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, 1997, Shares Outstanding: 176,708,501

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.............................................. 10

Item Three

Legal Proceedings...................................... 11

Item Four

Submission of Matters to a Vote of Security Holders.... 11

Executive Officers of the Registrant................... 12

PART II

Item Five

Market for Registrant's Common Equity and Related
Stockholder Matters................................... 13

Item Six

Selected Financial Data................................ 13

Item Seven

Management's Discussion and Analysis of Financial
Condition and Results of Operations................... 14

Item Eight

Financial Statements and Supplementary Financial
Information........................................... 21

Item Nine

Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................... 44

PART III

Items Ten and Eleven

Directors and Executive Officers of the Registrant and
Executive Compensation................................ 44

Item Twelve

Security Ownership of Certain Beneficial Owners and
Management............................................ 44

Item Thirteen

Certain Relationships and Related Transactions......... 44

PART IV

Item Fourteen

Exhibits, Financial Statement Schedules and Reports on
Form 8-K.............................................. 44

PART I

ITEMS ONE AND TWO

BUSINESS AND PROPERTIES

Burlington Resources Inc. ("BR") is a holding company engaged, through its
principal subsidiaries, Burlington Resources Oil & Gas Company and The Louisiana
Land and Exploration Company ("LL&E") and their affiliated companies
(collectively the "Company"), in the exploration, development, production and
marketing of oil and gas. The Company is the largest independent oil and gas
company in the United States ("U.S.") based on total proved domestic reserves,
and the second largest U.S. based independent oil and gas company based on total
proved worldwide reserves which were estimated at 7.9 TCFE at December 31, 1997.

On July 17, 1997, BR and LL&E announced that they had entered into an
Agreement and Plan of Merger (the "Merger"). On October 22, 1997, the Merger was
completed and LL&E became a wholly-owned subsidiary of the Company. Pursuant to
the Merger, BR issued 52,795,635 shares of its Common Stock based on an exchange
ratio of 1.525 for each outstanding share of LL&E stock. The Merger was
accounted for as a pooling of interests and qualified as a tax-free
reorganization. The transaction was valued at approximately $3 billion based on
BR's closing stock price on October 22, 1997. All operational and financial
information contained herein includes the combined business activities for BR
and LL&E for all periods presented.

The Company's operations are conducted by five divisions from four offices
located in Farmington, New Mexico, Midland, Texas and two locations in Houston,
Texas. The majority 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. For definitions of certain oil and gas terms
used herein, see "Certain Definitions" on page 10.

SAN JUAN DIVISION

The San Juan Division ("San Juan"), located in Farmington, New Mexico,
exploits and produces oil and gas primarily in the San Juan Basin, which is
located in northwest New Mexico and southwest Colorado. In 1997, San Juan
capital expenditures, excluding proved property acquisitions, were $93 million
which included investments for over 140 wells and approximately 300 mechanical
workovers. Over 110 of the wells and 200 of the workovers were Company operated.
Net production from San Juan averaged 809 MMCF of gas per day and 1.4 MBbls of
oil per day. San Juan provided 49 percent of the Company's net gas production
and one percent of the Company's net oil production. As of December 31, 1997,
San Juan controlled 44 percent of the Company's reserves.

The four major gas producing horizons in the San Juan Basin are the
Fruitland Coal, the Pictured Cliffs, the Mesaverde, and the Dakota Formations.
These horizons range in depth from approximately 1,000 feet to 8,500 feet. The
Fruitland Coal is the primary producing horizon for San Juan, and the Company
continues to be an industry leader in coal bed methane production. Net
production from the Fruitland Coal averaged a record 430 MMCF of gas per day
during 1997 from approximately 1,200 wells.

A significant portion of the gas production growth in 1997 is associated
with the optimization of the Val Verde gathering system including the activation
of the Antler and Jackrabbit plants and the processing of volumes by third party
processors. The Company owns and operates the Val Verde plant and gathering
system which includes approximately 420 miles of gathering lines and 13
compressor stations. The Val Verde plant continues to operate at full capacity.
The Antler and Jackrabbit plants allow the Company to process and sell
additional volumes which would otherwise be curtailed. This, along with the
processing of volumes by third party processors, enables the Company to optimize
its coal seam gas volumes. Fifty well optimization projects in the Fruitland
Coal, primarily recavitations and wellsite compression, have added to the growth
in coal seam gas volumes during 1997.

1
4

Development of the Mesaverde Formation continues to be a major focus for
San Juan. Net production from the Mesaverde Formation in 1997 averaged 200 MMCF
of gas per day from 3,300 wells. Capital investments in over 100 new wells in
1997 contributed to incremental gas volumes in San Juan. During 1997, an eight
well pilot project was initiated to determine the effect of increasing the well
density in the Mesaverde Formation.

MID-CONTINENT DIVISION

The Mid-Continent Division ("Mid-Continent"), located in Midland, Texas,
explores for and produces oil and gas primarily in the Permian Basin in west
Texas, the Anadarko Basin in western Oklahoma, the Wind River Basin in central
Wyoming and the Williston Basin in western North Dakota, northwest South Dakota
and northeast Montana. In 1997, Mid-Continent capital expenditures, excluding
proved property acquisitions, were $252 million which included investments for
approximately 300 wells and over 320 mechanical workovers. Approximately 200 of
the wells and 275 of the workovers were Company operated. Net production from
Mid-Continent averaged 258 MMCF of gas per day and 34.7 MBbls of oil per day.
Mid-Continent represented 15 percent of the Company's net gas production and 40
percent of the Company's net oil production. As of December 31, 1997,
Mid-Continent controlled 31 percent of the Company's reserves.

In the Permian Basin, the Company's average net production for 1997 was
approximately 13 MBbls of oil per day and 90 MMCF of gas per day. The Company
invested $60 million for 145 new wells in the basin during 1997. The most
productive structural feature in the Permian Basin is the Central Basin Platform
on which the Company controls over 140,000 net acres of mineral interests. Over
20 different formations, ranging in depth from 2,000 feet to over 12,000 feet,
produce oil and gas in the Central Basin Platform. A key component of
Mid-Continent's Permian Basin operations is enhanced oil recovery projects. The
Company operates several waterflood projects on the Waddell Ranch, located 40
miles west of Midland, Texas. The Company operates over 1,500 wells on the
Waddell Ranch with combined average net production of 4.8 MBbls of oil per day
and 22 MMCF of gas per day in 1997 and continues to acquire three dimensional
("3-D") seismic which has proven to be an effective tool for exploration and
development. In 1997, approximately 800 square miles of 3-D seismic data were
acquired in this area.

In the Anadarko Basin, the Company's average net gas production for 1997
was 110 MMCF of gas per day. This basin encompasses over 30,000 square miles and
contains some of the deepest producing formations in the world. The basin
produces from multiple horizons ranging in depth from less than 1,000 feet to
over 26,000 feet. The Company controls over 250,000 net acres principally
located in western Oklahoma. The Company has been concentrating its Anadarko
Basin activity in the Elk City and Strong City Fields where the application of
3-D seismic, computerized modeling and advanced reservoir stimulation continue
to enhance the value of these assets. The primary producing horizons in these
fields are the Morrow, Springer and Cherokee Red Fork Formations. During 1997,
the Company invested $34 million for 54 new wells in this basin.

In the Wind River Basin, the Company's average net gas production for 1997
was 31 MMCF of gas per day. This basin encompasses approximately 4,000 square
miles and produces from multiple horizons ranging in depth from 1,000 feet to
over 25,000 feet. All of the Company's Wind River Basin production comes from
the Madden Field. During 1997, the Company completed the Big Horn 4-36 in the
Madison Formation at a measured depth of 24,600 feet. This well tested 44 gross
MMCF of gas per day and was the third well in the Madison Formation. A 10
percent working interest in the Madden Deep Unit was purchased by the Company in
1997 which resulted in a 45 percent working interest in the Deep Madden Unit in
the Madison Formation. All of the sour gas that is produced from the Madison
Formation is processed at the Lost Cabin Gas Plant, which currently has a
constrained inlet capacity of 55 MMCF of gas per day. The plant is currently
being modified to increase its inlet capacity to approximately 65 MMCF of gas
per day later this year. BR recently began an expansion of this facility to
double its inlet capacity to 130 MMCF of gas per day in the second half of 1999.
The three Madison wells will fully utilize this expanded processing capacity. BR
owns a 47 percent working interest in the plant. Additionally, two wells are
currently testing on the 950,000 gross acre Wind River
2
5

Indian Reservation exploration license area. This license area includes a highly
prospective, undeveloped portion of the Wind River Basin, which with the use of
seismic could offer significant growth potential for Mid-Continent.

In the Williston Basin, the Company's average net oil production for 1997
was 20 MBbls of oil per day. This 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 interests. Mid-Continent's activities have
been focused on the use of advanced technologies such as 3-D seismic and
horizontal drilling to continue increasing the value of its assets. The Company
invested over $50 million in the drilling of over 70 horizontal wells in this
basin during 1997. Large waterflood projects in the Eland Unit and East Lookout
Butte Unit are currently being fully implemented. The Cedar Hills Field should
be fully delineated in 1998 and is planned for initial waterflood operations in
1999. The Company acquired over 800 square miles of 3-D seismic data in this
area during 1997.

GULF OF MEXICO DIVISION

The Gulf of Mexico Division ("Gulf of Mexico"), located in Houston, Texas,
explores for and produces oil and gas in the Gulf of Mexico. In 1997, Gulf of
Mexico capital expenditures, excluding proved property acquisitions, were $442
million which included investments for approximately 70 wells and 22 mechanical
workovers. Thirty-seven of the wells and nine of the workovers were Company
operated. Net production from Gulf of Mexico averaged 362 MMCF of gas per day
and 16.6 MBbls of oil per day. Gulf of Mexico represented 22 percent of the
Company's net gas production and 19 percent of the Company's net oil production.
As of December 31, 1997, Gulf of Mexico controlled 10 percent of the Company's
reserves.

Gulf of Mexico produces hydrocarbons from multiple horizons ranging from
2,000 feet to over 17,000 feet. The Company currently has interests in over 370
offshore federal lease blocks with over 145 of these in water depths greater
than 600 feet ("deep water"). The Company continued to strategically increase
its acreage position in the Gulf of Mexico in 1997 by acquiring, through federal
lease sales, 15 blocks on the Outer Continental Shelf (the "Shelf") and
approximately 100 blocks in deep water. Deep water prospects expose the Company
to high potential and high risk prospects which complement the moderate
potential and lower risk prospects being pursued on the Shelf. The complex
geologic conditions and multiple horizons make the Gulf of Mexico an attractive
area for the application of advanced technologies such as 3-D seismic. The
application of 3-D seismic will continue to be instrumental in the exploration
and development of Gulf of Mexico's assets with approximately 9,500 square miles
of data acquired in 1997.

A key component of the Company's overall Gulf of Mexico Shelf strategy is
to fully exploit areas around existing fields using 3-D seismic technology. This
strategy yields beneficial results because the cost to drill these wells is
lower and existing infrastructure can be used to immediately produce the
hydrocarbons discovered. This has resulted in significant discoveries, such as
in the Eugene Island 205 and the South Timbalier 148 Fields.

Undeveloped potential in the non-operated South Timbalier 148 Field was
recognized by the Company in late 1995 after acquiring 3-D seismic data over the
area. Prior to drilling, the Company acquired an additional working interest of
15 percent resulting in a 40 percent working interest in the block. A total of
four successful wells have been drilled and completed subsequent to this
acquisition, increasing the Company's net production from 2 MMCF of gas per day
to a peak production of 34 MMCF of gas per day. Capital investments are
currently being made to increase the pipeline capacity for this increased
deliverability.

In 1996, the Company acquired a 100 percent working interest in the Eugene
Island 205 Field. In December 1996, the Company began an aggressive development
drilling program which resulted in the drilling of eleven wells and the
recompletion of three wells. Prior to the initiation of this development
program, the Company's net production from this field was 5 MMCF of gas per day.
By year-end 1997, the net production had increased to nearly 50 MMCF of gas per
day.

3
6

During 1996, the Company participated in a deep water discovery, known as
the Cinnamon Discovery, which was drilled at Green Canyon 45/89. Located in 690
feet of water, the well encountered high quality reservoirs and pay zones
between 9,500 feet and 10,225 feet. During the first quarter of 1997, the first
delineation well, the Green Canyon 89 No. 2, was drilled which verified the
commercial potential of the prospect. Facility design and fabrication have been
initiated.

GULF COAST DIVISION

The Gulf Coast Division ("Gulf Coast"), located in Houston, Texas, explores
for and produces oil and gas primarily in south Louisiana, south and east Texas
and the panhandle of Florida. In 1997, Gulf Coast capital expenditures,
excluding proved property acquisitions, were $126 million which included
investments for 45 wells and 26 mechanical workovers. Seventeen of the wells and
six of the workovers were Company operated. Net production from Gulf Coast
averaged 167 MMCF of gas per day and 15.5 MBbls of oil per day. Gulf Coast
represented 10 percent of the Company's net gas production and 18 percent of the
Company's net oil production. As of December 31, 1997, Gulf Coast controlled
seven percent of the Company's reserves.

In south Louisiana, the Company's average net production was approximately
130 MMCF of gas per day and 8 MBbls of oil per day. Production is from multiple
zones ranging in depth from less than 2,900 feet to over 18,000 feet. The
Company owns approximately 600,000 acres of fee land in this area. Gulf Coast
actively pursued the acquisition of 3-D seismic surveys over these fee lands and
the surrounding areas in 1997 with the acquisition of over 1,100 square miles.
At present, the Company has 50 different south Louisiana 3-D seismic surveys in
varying stages of acquisition, processing or interpretation. The Company owns in
excess of 20 percent of all 3-D seismic acquired by the industry in south
Louisiana. Approximately 80 percent of the Louisiana fee lands have been covered
by 3-D seismic surveys. In south Louisiana, the Company invested over $100
million in 19 operated wells.

INTERNATIONAL DIVISION

The International Division ("International"), headquartered in Houston,
Texas, explores for and produces oil and gas in areas outside the United States.
In addition to Houston, divisional offices are located in London, England and
Caracas, Venezuela. International operates primarily in the East Irish Sea,
Algeria and Venezuela. In addition, the Company owns non-operated interests in
the United Kingdom ("U.K.") and Dutch sectors of the North Sea, Colombia,
Tunisia, Papua New Guinea and Indonesia. In 1997, International capital
expenditures, excluding proved property acquisitions, were $78 million which
included investments for 26 wells, of which five were operated by the Company.
Net production from International averaged 73 MMCF of gas per day and 19 MBbls
of oil per day. International represented 4 percent of the Company's net gas
production and 22 percent of the Company's net oil production. International
controlled eight percent of the Company's reserves.

In the North Sea, the Company's average net production was 73 MMCF of gas
per day and 14.5 MBbls of oil per day. This production comes from two primary
areas in the North Sea, the U.K. sector and the Dutch sector. In the U.K.
sector, production was initiated from the Thelma Field in the T-Block complex in
late 1996. The field is a subsea tie-back to the Tiffany platform. At the Brae
complex, the Plan of Development for the West Brae Field was approved by the
U.K. government in 1996. This sixth development in the field was placed on
production in late 1997 using subsea completions tied-back to the South Brae
platform. In the Dutch sector of the North Sea, the Company participates in
natural gas exploration and production. Net production averaged 42 MMCF of gas
per day in the Dutch sector of the North Sea.

In December 1997, the Company acquired acreage in the East Irish Sea for
$159 million. These properties are located 25 miles off the coast of England in
approximately 100 feet of water. This acquisition included a 99 percent working
interest in seven operated undeveloped natural gas fields. The timing of the
field development will depend on a number of factors, including the receipt of
appropriate regulatory approvals for the development plan and negotiation of gas
sales contracts and

4
7

processing agreements. Ten licenses encompass approximately 460 square miles and
are covered by high quality 3-D seismic surveys. The Company contemplates
development opportunities on the acquired acreage that will utilize the latest
offshore technology. Development is expected to commence in 1998.

In Algeria, the Company's primary focus has been exploration for
hydrocarbons in Blocks 405 and 215. The Company owns a 65 percent working
interest in these blocks and is the operator. Block 405 comprises nearly 713,000
gross acres and is located in the Berkine Basin of eastern Algeria. Block 215
comprises nearly 840,000 gross acres and is located 65 miles west of Block 405.
As required by the Production Sharing Agreement, the Company will relinquish a
portion of its acreage in 1998. To date, the Company has drilled eight wells and
all but one have been successful.

In late 1997, the delineation well MLN-4 successfully tested with the
highest flow rate on Block 405. The well flowed at a gross rate of 22.7 MBbls of
oil per day and 58 MMCF of gas per day from two Triassic TAG intervals and from
a newly discovered reservoir in a deeper Devonian interval. No formation water
was recovered during any of these tests.

In 1997, the Company drilled its second successful well to confirm the
extension of the Qoubba Field onto the northeastern portion of Block 405. The
Company will participate in the development of this field, of which
approximately six percent extends onto Block 405.

In 1998, the Company's drilling focus will be the delineation of the MLN
Field, participation in the development of the Qoubba Field and exploration for
new structures. In addition to this drilling activity, a 270 square mile 3-D
seismic survey is currently being acquired in Block 405. Information derived
from this survey will assist in the further appraisal of the Triassic TAG
reservoir, provide the basis for additional Devonian delineation drilling and
firm-up additional exploration prospects for drilling during 1998. An
Exploitation License Application, providing for the development of the MLN
Field, will be submitted during 1998. Sonatrach, the national oil and gas
enterprise of Algeria, has the option to participate in the development of
commercial discoveries. The Company is entitled to recover exploration costs out
of production during the exploitation phase.

In Venezuela, the Company completed an acquisition of 217 square miles of
3-D and 230 miles of 2-D seismic data over the 526,000 gross acre Delta Centro
Block in eastern Venezuela in 1997. This highly prospective exploration block is
located in Venezuela's Orinoco River Delta and is on geologic trend with oil
discoveries in surrounding blocks. Early analysis of the 3-D seismic data has
revealed promising leads and preparations are underway to drill the first
exploration well during 1998. Under the terms of its work commitment, the
Company will drill three exploratory wells over a primary term ending in the
year 2001 with the option to extend the exploratory period for an additional
four years. The Company owns a 35 percent working interest in the block and is
the operator.

In Colombia, the Company's average net production was 1.4 MBbls of oil per
day. The Company has a non-operated working interest in 36 wells in the Casanare
Association Contract Area. The Company also holds a 25 percent working interest
in a 280,000 gross acre association contract located in the San Jacinto
Association Contract Area. The contract is located in the Upper Magdalena Valley
Basin. A recent discovery to the north, in the Guadauas Field, lies in a similar
setting with the same reservoir targets which are the Guadalupe and Caballos
Formations. The acquisition of 93 miles of 2-D seismic is planned for 1998.

In Indonesia, the Company's average net production was 3.1 MBbls of oil per
day. The Company has a 15 percent working interest in the KAKAP Production
Sharing Contract. In 1997, the Company completed the tie-back of three subsea
completions. In addition to the activity in the KAKAP Field, exploration success
at Nelayan proved an exploration concept which has led to a renewed exploration
effort for 1998.

The Company and its partners in the KAKAP Field are in the process of
negotiating gas sales agreements to sell gas to Singapore. The gas will be sold
via a pipeline that is scheduled to be completed in the year 2000.
5
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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 $1.04 per MMBTU depending on fuel source. The Company earned
approximately $51 million of Section 29 tax credits in 1997.

CAPITAL EXPENDITURES AND MAJOR PROJECTS

Following are the Company's capital expenditures.

YEAR ENDED DECEMBER 31,
--------------------------
1997 1996 1995
------ ---- ----
(IN MILLIONS)

Oil and Gas Activities.................................. $1,155 $738 $686
Plants and Pipelines.................................... 50 54 79
Administrative.......................................... 40 12 22
------ ---- ----
Total......................................... $1,245 $804 $787
====== ==== ====

Capital expenditures for oil and gas activities in 1997 of $1,155 million
include 19 percent for proved property acquisitions, 48 percent for development
and 33 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 1997 was principally in the San
Juan, Gulf Coast, Permian, Anadarko and Williston Basins. Increased net drilling
activity levels, as seen in the table below, are a result of the Company's
expanded development and exploration programs.

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

YEAR ENDED DECEMBER 31,
----------------------------------
1997 1996 1995
---- ---- ----

Productive wells
Exploratory..................................... 31.4 25.3 26.4
Development..................................... 248.8 191.7 297.5
---- ---- ----
280.2 217.0 323.9
---- ---- ----
Dry wells
Exploratory..................................... 27.8 18.1 20.0
Development..................................... 8.6 5.9 37.8
---- ---- ----
36.4 24.0 57.8
---- ---- ----
Total net wells......................... 316.6 241.0 381.7
==== ==== ====

As of December 31, 1997, 55 gross wells, representing approximately 29 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
using both conventional and advanced technologies.

6
9

In December 1997, the Company acquired working interests in the East Irish
Sea of the U.K. for $159 million. The Company will continue to pursue
transactions which enable the consolidation of assets and increase operating
efficiencies.

In June 1997, the Company completed its non-strategic divestiture program
which was announced in July 1996. As planned, the Company sold approximately
27,000 wells and related facilities. Before closing adjustments, gross proceeds
for 1997 from sales of oil and gas properties related to this divestiture
program were approximately $450 million (approximately $418 million, net of
closing adjustments). A portion of the net proceeds from asset divestitures were
reinvested in domestic and international oil and gas properties.

On July 31, 1996, the Company completed the sale of its crude oil refinery
and terminal, including crude oil and refined product inventories, for
approximately $70 million. The net book value of refinery property, plant and
equipment and inventory at that date was approximately $68 million.

PRODUCTIVE WELLS, DEVELOPED AND UNDEVELOPED ACREAGE

Working interests in productive wells, developed acreage and undeveloped
acreage at December 31, 1997 follow.

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

5,791 2,857 10,829 6,026 5,314,000 2,580,000 16,674,000 11,870,000

Included in the acreage data are approximately 7.5 million undeveloped
acres of Company-owned oil and gas mineral rights, of which approximately 4
million acres are considered to have potential for oil and gas exploration.

OIL AND GAS PRODUCTION, PRICES AND PRODUCTION COSTS

The Company's average daily production represents its net ownership after
deduction of all royalty interests held by others but includes royalty interests
and net profits interests owned by the Company. The Company's average natural
gas price includes amounts from the sale of NGLs, less the actual costs incurred
to gather, treat, process and transport the hydrocarbons to market. Following
are production and prices.

YEAR ENDED DECEMBER 31,
---------------------------------------------
1997 1996 1995
---- ---- ----

Production
Gas (MMCF per day)................................. 1,669 1,603 1,496
Oil (MBbls per day)................................ 87.2 91.1 90.9
Average sales prices
Gas per MCF........................................ $ 2.18 $ 2.05 $ 1.40
Oil per barrel..................................... 19.24 20.39 17.04
Average production costs per MCFE.................... .51 .54 .54
Depreciation, depletion and amortization rates
per MCFE........................................... $ .62 $ .62 $ .67

In 1997, 1996 and 1995, approximately 41 percent, 43 percent and 47
percent, respectively, of the Company's gas production was transported to direct
sale customers through El Paso Natural Gas Company's ("EPNG") pipeline systems.
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 systems.

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RESERVES

The following table sets forth estimates by the Company's petroleum
engineers of proved oil and gas reserves at December 31, 1997. These reserves
have been reduced for royalty interests owned by others.

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

Proved Developed Reserves...................... 4,874 219.5 6,191
Proved Undeveloped Reserves.................... 1,544 34.2 1,749
----- ----- -----
Total Proved Reserves................ 6,418 253.7 7,940
===== ===== =====

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

Natural Gas. In pursuit of the Company's mission to build long-term
shareholder value, the Company's marketing strategy is to maximize the value of
its production by developing marketing flexibility from the wellhead to the
burnertip. The Company's gas production is gathered, processed, exchanged and
transported utilizing various firm and interruptible contracts and routes to
access the highest value market hubs. The Company's customers include local
distribution companies, electric utilities and a diverse portfolio of industrial
users. The Company maintains the capacity to ensure its production can be
marketed either at the wellhead or downstream at market sensitive prices.

Crude Oil and NGLs. All of the Company's crude oil production is sold to
third parties at the wellhead or transported to market hubs where it is sold or
exchanged. NGLs are typically transported to market hubs, primarily in the
Houston area, and sold to third parties.

International. The Company's international oil and gas is produced from
non-operated properties. These products are sold to third party markets either
directly by the Company or by the operator of the property.

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 the sale of oil, gas and NGLs.
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. The oil
and gas industry is subject to regulation by numerous national, state and local
governmental agencies and departments in the countries in which the Company
operates, compliance with which is often difficult and costly and some of which
carry substantial noncompliance penalties and risks. Statutes, rules,
regulations or guidelines require drilling permits, drilling bonds and operating
reports. Most jurisdictions in which the Company operates also have statutes,
rules, regulations or guidelines 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 jurisdictions also
limit production to the market demand for oil and gas. Such statutes, rules,
regulations or guidelines 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 its domestic gas are deregulated.

The Company operates various gathering systems. The United States
Department of Transportation and certain state agencies regulate, under various
statutes, rules or regulations, the safety and

8
11

operating aspects of the transportation and storage activities of these
facilities by prescribing standards.

The FERC has implemented policies, subject to court review, allowing
interstate pipeline companies to negotiate their rates with individual shippers.
The FERC is also considering allowing the interstate pipeline companies to
negotiate tariffed terms and conditions of service. The Company will monitor the
effects of these programs on its marketing efforts but does not expect that
these actions 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 relating to the protection of the environment, including the
discharge of materials into the environment, may affect the Company's domestic
operations and costs as a result of their effect on oil and gas exploration,
development and production operations. In addition, certain of the Company's
international operations are subject to environmental regulations administered
by foreign governments, including political subdivisions thereof, or by
international organizations.

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

The Company believes it is in substantial compliance with applicable
environmental laws and regulations. The Company does not anticipate that it will
be required under current 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 1997, the Company
filed estimates of oil and gas reserves for the year 1996 with the Department of
Energy. These estimates were not materially different from the reserve data
presented herein.

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CERTAIN DEFINITIONS

Below are certain definitions of key terms used in this Form 10-K.

BCF means billion cubic feet.

BCFE means billion cubic feet of gas equivalent.

MBbls means thousands of barrels.

MCF means thousand cubic feet.

MCFE means thousand cubic feet of gas equivalent.

MMBbls means millions of barrels.

MMBTU means million British Thermal units.

MMCF means million cubic feet.

MMCFE means million cubic feet of gas equivalent.

NGLs mean natural gas liquids.

TCFE means trillion cubic feet of gas equivalent.

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.

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.

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.

Oil is converted into cubic feet of gas equivalent based on 6 MCF of gas to
one barrel of oil.
- ---------------

EMPLOYEES

The Company had 1,819 and 2,004 employees at December 31, 1997 and 1996,
respectively. Currently, the Company has no union employees.

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13

ITEM THREE

LEGAL PROCEEDINGS

On May 25, 1995, the 270th Judicial District Court of Harris County, Texas
entered an order in a lawsuit styled Caroline Altheide, et al. v. Meridian Oil
Inc. (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.
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
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. The
objectors purported to perfect an appeal of the Judgment on February 7, 1997. On
July 24, 1997, the Fourteenth Court of Appeals dismissed the appeal. On October
17, 1997, the objectors filed a Petition for Review with The Supreme Court of
Texas. The Company and the Plaintiffs intend to defend this appeal 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

At a special meeting of stockholders of the Company held on October 22,
1997, the stockholders voted to approve the issuance of the Company's Common
Stock pursuant to the Agreement and Plan of Merger dated July 16, 1997 among the
Company, BR Acquisition Corporation (a wholly-owned subsidiary of the Company)
and LL&E.

Approval of the issuance of shares of the Company's Common Stock pursuant
to the Merger was as follows.

FOR AGAINST ABSTENTIONS
- ---------- ------- -----------

94,752,530 308,225 517,354

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14

EXECUTIVE OFFICERS OF THE REGISTRANT

BOBBY S. SHACKOULS, 47 H. LEIGHTON STEWARD, 63
Chairman of the Board, President and Chief Vice Chairman of the Board
Executive Officer Burlington Resources Inc.
Burlington Resources Inc. October 1997 to Present
July 1997 to Present Chairman of the Board, President and Chief Ex-
President and Chief Executive Officer, ecutive Officer, The Louisiana Land and
Burlington Resources Inc., December 1995 to July Exploration Company, November 1996 to October
1997; President and Chief Executive Officer, 1997; Chairman of the Board and Chief Executive
Burlington Resources Oil & Gas Company, October Officer, The Louisiana Land and Exploration
1994 to Present; Executive Vice President and Company, September 1995 to November 1996; and
Chief Operating Officer, Burlington Resources Chairman of the Board, President and Chief
Oil & Gas Company, June 1993 to October 1994; Executive Officer, The Louisiana Land and
President and Chief Operating Officer, Torch Exploration Company, January 1989 to September
Energy Advisors, Inc., July 1991 to May 1993. 1995.
JOHN E. HAGALE, 41 RANDOLPH P. MUNDT, 47
Executive Vice President and Chief Executive Vice President, Marketing
Financial Burlington Resources Inc.
Officer April 1997 to Present
Burlington Resources Inc.
December 1995 to Present Executive Vice President, Marketing, Burlington
Resources Oil & Gas Company, March 1995 to Pres-
Executive Vice President and Chief ent; Senior Vice President, Operations,
Financial Officer, Burlington Resources Oil & Burlington Resources Oil & Gas Company, October
Gas Company, March 1993 to Present; Senior 1994 to March 1995; Senior Vice President,
Vice President and Chief Financial Officer, Acquisitions and Land, Burlington Resources Oil
Burlington Resources Inc., April 1994 to & Gas Company, July 1993 to October 1994; Senior
December 1995; Vice President, Finance, Vice President, Strategic Planning and Asset
Burlington Resources Inc., March 1992 to Management, Burlington Resources Oil & Gas
February 1993. Company, December 1990 to July 1993.
C. RAY OWEN, 52 LOUIS A. RASPINO, 45
Executive Vice President and Chief Senior Vice President, Strategic Planning
Operating Officer and Business Development
Burlington Resources Inc. Burlington Resources Inc.
April 1997 to Present October 1997 to Present
Executive Vice President and Chief Senior Vice President, Chief Financial Officer,
Operating Officer, Burlington Resources Oil & The Louisiana Land and Exploration Company, Sep-
Gas Company, October 1994 to Present; Senior tember 1995 to October 1997; Treasurer, The
Vice President, Operations, Burlington Louisiana Land and Exploration Company, May 1992
Resources Oil & Gas Company, March 1993 to to September 1995.
October 1994; Vice President, Regional
Operations, Burlington Resources Oil & Gas
Company, December 1990 to March 1993.
GERALD J. SCHISSLER, 53 JOHN A. WILLIAMS, 53
Executive Vice President, Law Senior Vice President, Exploration
and Administration Burlington Resources Inc.
Burlington Resources Inc. October 1997 to Present
April 1997 to Present
Senior Vice President, Exploration and
Executive Vice President, Law and Production, The Louisiana Land and Exploration
Corporate Affairs, Burlington Resources Inc. Company, September 1995 to October 1997; Vice
December 1995 to April 1997; Senior Vice President, The Louisiana Land and Exploration
President, Law, Burlington Resources Inc., Company, March 1988 to September 1995.
December 1993 to December 1995; Consultant,
June 1991 to July 1993.

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15

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, 1997, the number of common stockholders was
23,695.

Information on common stock prices and quarterly dividends is shown on page
43.

ITEM SIX

SELECTED FINANCIAL DATA

The selected financial data for the Company set forth below for the five
years ended December 31, 1997 should be read in conjunction with the
consolidated financial statements. Prior year amounts have been restated to
combine BR and LL&E.

1997 1996 1995 1994 1993
---- ---- ---- ---- ----
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

INCOME STATEMENT DATA
Revenues.................................... $2,000 $2,200 $1,734 $1,871 $1,865
Operating Income (Loss)..................... 503 580 (397) (159) 298
Net Income (Loss)........................... 319 335 (261) (73) 266
Basic Earnings (Loss) per Common Share...... 1.80 1.89 (1.47) (.41) 1.52
Diluted Earnings (Loss) per Common Share.... 1.79 1.88 (1.47) (.41) 1.51
BALANCE SHEET DATA
Total Assets................................ 5,821 5,683 5,608 6,285 6,285
Long-term Debt.............................. 1,748 1,853 2,042 2,049 1,554
Stockholders' Equity........................ 3,016 2,808 2,591 2,920 3,208
Cash Dividends Declared per Common Share.... $ .46 $ .44 $ .44 $ .58 $ .58
Common Shares Outstanding................... 177 177 178 177 180

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16

ITEM SEVEN

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

THE MERGER

On July 17, 1997, Burlington Resources Inc. ("BR") and The Louisiana Land
and Exploration Company ("LL&E") announced that they had entered into an
Agreement and Plan of Merger (the "Merger"). On October 22, 1997, the Merger was
completed and LL&E became a wholly-owned subsidiary of the Company. Pursuant to
the Merger, BR issued 52,795,635 shares of its Common Stock based on an exchange
ratio of 1.525 for each outstanding share of LL&E stock. The Merger was
accounted for as a pooling of interests and qualified as a tax-free
reorganization. The transaction was valued at approximately $3 billion based on
BR's closing stock price on October 22, 1997. All operational and financial
information contained herein includes the combined business activities for BR
and LL&E for all periods presented.

FINANCIAL CONDITION AND LIQUIDITY

The Company's total long-term debt to capital (long-term debt and
stockholders' equity) ratio at December 31, 1997 and 1996 was 37 percent and 40
percent, 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 in July 1998. The $300 million revolving credit agreement
is renewable annually by mutual consent and was renewed in July 1997. In June
1997, LL&E refinanced its existing $350 million revolving credit facility with a
revolving credit facility of a like amount. However, as a result of the Merger
of LL&E and BR, the revolving credit facility was terminated on October 23,
1997. Further, LL&E's commercial paper program was also terminated on that date
and outstanding commercial paper totaling approximately $83 million was retired
by the Company. As of December 31, 1997, there were no borrowings outstanding
under the credit facilities. In April 1997, the Company increased the capacity
under its shelf registration statements from $200 million to $500 million.
Effective November 7, 1997, LL&E withdrew its shelf registration statement of
$500 million.

Effective July 16, 1997, the Company rescinded its stock repurchase
program. From January 1, 1997 through May 31, 1997, the Company repurchased
approximately 1.3 million shares of its Common Stock for $58 million. Since
December 1988, the Company has repurchased approximately 31 million shares. In
conjunction with the Company's stock repurchase program, the Company sold put
options ("options") during the first quarter of 1997. The options entitled the
holders, upon exercise of the options on the expiration dates, to sell shares of
BR Common Stock to the Company at specified prices. Alternatively, the Company
retained the ability to settle the options in cash. In total, options on 500
thousand shares were issued with an average strike price of $44.50 per share. An
average premium of $2.63 per option was received for the option sales. All
options expired without being exercised.

Net cash provided by operating activities for 1997 was $1,122 million
compared to $995 million and $687 million in 1996 and 1995, respectively. The
increase in 1997 compared to 1996 was primarily due to higher operating income,
excluding non-cash items, and working capital changes. Net cash provided by
operating activities in 1996 also included proceeds of $108 million relating to
an obligation to deliver gas from certain coal seam wells through December 31,
2002. The increase in 1996 compared to 1995 was primarily due to significantly
higher operating income and $108 million in proceeds received relating to an
obligation to deliver gas from certain coal seam wells through December 31,
2002. These increases were partially offset by other working capital changes.
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.

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17

The Company is involved in certain legal and environmental proceedings as
well as 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 1997 totaled $1,245 million compared to $804
million and $787 million in 1996 and 1995, respectively. The Company invested
$214 million for proved property acquisitions in 1997 compared to $92 million
and $103 million in 1996 and 1995, respectively. The Company invested $941
million on internal development and exploration during 1997 compared to $646
million and $583 million in 1996 and 1995, respectively.

Capital expenditures for 1998, excluding proved property acquisitions, are
projected to be approximately $1.15 billion. Capital expenditures are expected
to be primarily for internal development and exploration of oil and gas
properties and plant and pipeline expenditures. Capital expenditures will be
funded from existing cash balances and cash flows, 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 the traditional California markets.

MARKETING

Natural gas. In pursuit of the Company's mission to build long-term
shareholder value, the Company's marketing strategy is to maximize the value of
its production by developing marketing flexibility from the wellhead to the
burnertip. The Company's gas production is gathered, processed, exchanged and
transported utilizing various firm and interruptible contracts and routes to
access the highest value market hubs. The Company's customers include local
distribution companies, electric utilities and a diverse portfolio of industrial
users. The Company maintains the capacity to ensure its production can be
marketed either at the wellhead or downstream at market sensitive prices.

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18

DIVIDENDS

On January 14, 1998, the Board of Directors declared a common stock
quarterly dividend of $.1375 per share, payable April 1, 1998. 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 $82 million during 1997.

RESULTS OF OPERATIONS

Year Ended December 31, 1997 Compared With Year Ended December 31, 1996

The Company reported net income of $319 million or $1.80 basic earnings per
share in 1997 compared to net income of $335 million or $1.89 basic earnings per
share in 1996. The 1997 results include a $.40 per share charge related to the
Merger for severance and related exit costs and transaction costs. The results
also include an $.18 per share gain related to the sales of oil and gas
properties. The 1996 results include an $.11 per share charge related to the
divestiture program and reorganization for severance and other related exit
costs.

Revenues were $2,000 million in 1997 compared to $2,200 million in 1996.
Revenues decreased $264 million as a result of the sale of the refinery on July
31, 1996. Oil sales volumes decreased 4 percent to 87.2 MBbls per day and
average oil prices decreased 6 percent to $19.24 per barrel which decreased
revenues $31 million and $37 million, respectively. These decreases were
partially offset by increases in gas sales volumes of 4 percent to 1,669 MMCF
per day and an average gas price increase of 6 percent to $2.18 per MCF which
increased revenues $46 million and $82 million, respectively. Gas volumes
increased due to continued development of gas properties. Oil volumes were down
primarily due to the divestiture program.

Costs and Expenses were $1,497 million in 1997 compared to $1,620 million
in 1996. Costs and expenses in 1997 included an $80 million charge related to
the Merger for severance and related exit costs and transaction costs. Costs and
expenses in 1996 included a $30 million reorganization charge for severance and
other related exit costs. Excluding the $80 million charge in 1997 and the $30
million charge in 1996, costs and expenses in 1997 decreased $173 million from
1996. The decrease is primarily due to a $254 million decrease in refinery costs
resulting from the sale of the refinery and a $23 million decrease in production
and processing expenses. These decreases were partially offset by a $100 million
increase in exploration costs and a $5 million increase in depreciation,
depletion and amortization.

Interest Expense was $142 million in 1997 compared to $147 million in 1996.
The decrease was primarily due to lower outstanding commercial paper balances
during 1997.

Other Income -- Net was $50 million in 1997 due to a gain related to the
sales of oil and gas properties associated with the divestiture program.

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

The Company reported net income of $335 million or $1.89 basic earnings per
share in 1996 compared to a net loss of $261 million or $1.47 basic loss per
share in 1995. The 1996 results include an $.11 per share charge related to the
divestiture program and reorganization for severance and other related exit
costs. The 1995 results include a $1.71 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 $2,200 million in 1996 compared to $1,734 million in 1995.
Average gas sales prices increased 46 percent in 1996 to $2.05 per MCF and
average oil prices increased 20 percent to $20.39 per barrel which increased
revenues $381 million and $112 million, respectively. Oil and gas

16
19

sales 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 7 percent to 1,603 MMCF per day and oil sales volumes
increased slightly to 91.1 MBbls per day which increased revenues $57 million
and $2 million, respectively. The increases in oil and gas revenue were
partially offset by a $92 million decrease in refinery revenue due to the sale
of the Company's crude oil refinery on July 31, 1996.

Costs and Expenses were $1,620 million in 1996 compared to $2,131 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 in 1996 decreased $21 million
compared to 1995. The decrease was primarily due to a $91 million decrease in
refinery costs as a result of the sale of the Company's crude oil refinery and a
$9 million decrease in depreciation, depletion and amortization. These decreases
were partially offset by a $48 million increase in exploration costs, a $20
million increase in administrative expenses and a $14 million increase in
production and processing expenses resulting from a 5 percent increase in 1996
production levels. Administrative expenses increased due to a $30 million
reorganization charge for severance and other related exit costs partially
offset by a $9 million decrease in salary expense resulting from employee
reductions.

The effective income tax rate was an expense of 22.5 percent in 1996
compared to a benefit of 51.9 percent in 1995. The higher effective tax rate in
1996 was primarily due to pretax income in 1996 versus a pretax loss in 1995.
Each year includes a beneficial rate of approximately 15 percent due to the
effect of non-conventional fuel tax credits.

OTHER MATTERS

Since 1996, the Company has been in the process of implementing new
financial and operating computer systems. The first phase of implementation was
completed in the first quarter of 1997 for certain operating areas within the
Company. The remaining operating and financial systems are scheduled for
implementation in phases, with project completion scheduled for the fourth
quarter of 1998. These new systems are year 2000 compliant. Additionally, the
Company is in the process of identifying suppliers and business partners who are
not prepared to offer assurance that their systems will be year 2000 compliant.
The cost of achieving year 2000 compliance is not expected to have a materially
adverse effect on the consolidated financial position or results of operations
of the Company.

In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 130, Reporting
Comprehensive Income, which is effective for fiscal years beginning after
December 15, 1997.

SFAS No. 130 establishes standards for reporting and display of
comprehensive income and its components (revenues, expenses, gains and losses)
in a full set of general-purpose financial statements. It requires (a)
classification of items of other comprehensive income by their nature in a
financial statement and (b) display of the accumulated balance of other
comprehensive income separate from retained earnings and additional paid-in
capital in the equity section of a statement of financial position. The Company
plans to adopt SFAS No. 130 for the quarter ended March 31, 1998.

In June 1997, the FASB also issued SFAS No. 131, Disclosures about Segments
of an Enterprise and Related Information, which is effective for fiscal years
beginning after December 15, 1997.

SFAS No. 131 establishes standards for reporting information about
operating segments in annual financial statements and requires selected
information about operating segments in interim financial reports issued to
shareholders. It also establishes standards for related disclosures about
products and services, geographic areas and major customers. This Statement
supersedes SFAS No. 14, Financial Reporting for Segments of a Business
Enterprise, but retains the requirement to report information about major
customers. The Company plans to adopt SFAS No. 131 for the year ended December
31, 1998.

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20

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 domestic crude oil
and 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. Crude oil prices are also affected by
quality differentials, by worldwide political developments and by actions of the
Organization of Petroleum Exporting Countries. 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 U.S.
producing basin or at a U.S. 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 price of transportation to consuming areas.

In the ordinary course and conduct of its business, the Company utilizes
futures contracts traded on the NYMEX and the Kansas City Board of Trade, and
over-the-counter price and basis swaps and options with major crude oil and
natural gas merchants and financial institutions to hedge its price risk
exposure related to the Company's U.S. production. The gains and losses realized
as a result of these derivatives transactions are substantially offset in the
cash market when the hedged commodity is delivered. In order to accommodate the
needs of its customers, the Company also uses price swaps to convert gas sold
under fixed price contracts to market prices.

The Company uses a sensitivity analysis technique to evaluate the
hypothetical effect that changes in the market value of crude oil and natural
gas may have on the fair value of the Company's derivative instruments. At
December 31, 1997, the potential decrease in fair value of commodity derivative
instruments assuming a 10 percent adverse movement in the underlying commodities
prices does not have a materially adverse effect on the consolidated financial
position or results of operations of the Company.

For purposes of calculating the hypothetical change in fair value, the
relevant variables are the type of commodity (crude oil or natural gas), the
commodity futures prices, the volatility of commodity prices and the basis and
quality differentials. Due to the short duration of the derivative contracts,
time value of money is ignored. The hypothetical change in fair value is
calculated by multiplying the difference between the hypothetical price
(adjusted for any basis or quality differentials) and the contractual price by
the contractual volumes.

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

18
21

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.

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.

19
22

Foreign Operations Risk. The Company's operations outside of the U.S. are
subject to risks inherent in foreign operations, including, without limitation,
the loss of revenue, property and equipment from hazards such as expropriation,
nationalization, war, insurrection and other political risks, increases in taxes
and governmental royalties, renegotiation of contracts with governmental
entities, changes in laws and policies governing operations of foreign-based
companies, currency restrictions and exchange rate fluctuations and other
uncertainties arising out of foreign government sovereignty over the Company's
international operations. Laws and policies of the U.S. affecting foreign trade
and taxation may also adversely affect the Company's international operations.

The Company's ability to market oil and natural gas discovered or produced
in its foreign operations, and the price the Company could obtain for such
production, depends on many factors beyond the Company's control, including
ready markets for oil and natural gas, the proximity and capacity of pipelines
and other transportation facilities, fluctuating demand for oil and natural gas,
the availability and cost of competing fuels, and the effects of foreign
governmental regulation of oil and gas production and sales. Pipeline and
processing facilities do not exist in certain areas of exploration and,
therefore, any actual sales of the Company's production could be delayed for
extended periods of time until such facilities are constructed.

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
national, 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 national, 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.

20
23

ITEM EIGHT

FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF INCOME

(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

YEAR ENDED DECEMBER 31,
--------------------------------------
1997 1996 1995
-------- -------- --------

Revenues................................................... $2,000 $2,200 $1,734
Costs and Expenses......................................... 1,497 1,620 2,131
------ ------ ------
Operating Income (Loss).................................... 503 580 (397)
Interest Expense........................................... 142 147 147
Other Income -- Net........................................ 50 - 1
------ ------ ------
Income (Loss) Before Income Taxes.......................... 411 433 (543)
Income Tax Expense (Benefit)............................... 92 98 (282)
------ ------ ------
Net Income (Loss).......................................... $ 319 $ 335 $ (261)
====== ====== ======
Basic Earnings (Loss) per Common Share..................... $ 1.80 $ 1.89 $(1.47)
====== ====== ======
Diluted Earnings (Loss) per Common Share................... $ 1.79 $ 1.88 $(1.47)
====== ====== ======

See accompanying Notes to Consolidated Financial Statements.

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24

BURLINGTON RESOURCES INC.

CONSOLIDATED BALANCE SHEET

(IN MILLIONS, EXCEPT SHARE DATA)

DECEMBER 31,
----------------------
1997 1996
-------- --------

ASSETS

Current Assets
Cash and Cash Equivalents................................. $ 152 $ 77
Short-term Investments.................................... 83 -
Accounts Receivable....................................... 376 484
Inventories............................................... 39 35
Other Current Assets...................................... 28 28
------ ------
678 624
------ ------
Oil and Gas Properties (Successful Efforts Method).......... 8,740 8,863
Other Properties............................................ 615 554
------ ------
9,355 9,417
Accumulated Depreciation, Depletion and Amortization...... 4,315 4,489
------ ------
Properties -- Net...................................... 5,040 4,928
------ ------
Other Assets................................................ 103 131
------ ------
Total Assets...................................... $5,821 $5,683
====== ======
LIABILITIES

Current Liabilities
Accounts Payable.......................................... $ 395 $ 348
Taxes Payable............................................. 71 74
Accrued Interest.......................................... 28 28
Dividends Payable......................................... 24 17
Deferred Revenue.......................................... 19 20
Other Current Liabilities................................. 1 29
------ ------
538 516
------ ------
Long-term Debt.............................................. 1,748 1,853
------ ------
Deferred Income Taxes....................................... 203 162
------ ------
Deferred Revenue............................................ 56 75
------ ------
Other Liabilities and Deferred Credits...................... 260 269
------ ------
Commitments and Contingent Liabilities
STOCKHOLDERS' EQUITY

Preferred Stock, Par Value $.01 Per Share (Authorized
75,000,000 Shares;
No Shares Issued)......................................... - -
Common Stock, Par Value $.01 Per Share (Authorized
325,000,000 Shares; Issued 202,795,635 and 202,202,891
Shares for 1997 and 1996, respectively)................... 2 2
Paid-in Capital............................................. 3,001 2,982
Retained Earnings........................................... 1,051 813
------ ------
4,054 3,797
Cost of Treasury Stock (26,087,134 and 25,081,301 Shares for
1997 and 1996, respectively).............................. 1,038 989
------ ------
Stockholders' Equity........................................ 3,016 2,808
------ ------
Total Liabilities and Stockholders' Equity........ $5,821 $5,683
====== ======

See accompanying Notes to Consolidated Financial Statements.

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25

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(IN MILLIONS)

YEAR ENDED DECEMBER 31,
------------------------------------
1997 1996 1995
-------- -------- --------

Cash Flows From Operating Activities
Net Income (Loss)......................................... $ 319 $ 335 $(261)
Adjustments to Reconcile Net Income (Loss) to Net Cash
Provided By Operating Activities
Depreciation, Depletion and Amortization............... 538 534 545
Deferred Income Taxes.................................. 36 32 (359)
Exploration Costs...................................... 259 159 111
Gain on Sales of Oil and Gas Properties................ (50) - -
Impairment of Oil and Gas Properties................... - - 490
Working Capital Changes
Accounts Receivable.................................... 108 (135) (28)
Inventories............................................ (4) 39 5
Other Current Assets................................... - 1 (5)
Accounts Payable....................................... 47 (57) 45
Taxes Payable.......................................... (3) 11 12
Accrued Interest....................................... - 2 -
Other Current Liabilities.............................. (22) 37 8
Other..................................................... (106) 37 124
------- ----- -----
Net Cash Provided By Operating Activities......... 1,122 995 687
------- ----- -----
Cash Flows From Investing Activities
Additions to Properties................................... (1,245) (804) (787)
Short-term Investments.................................... (83) - -
Proceeds from Sales and Other............................. 494 193 192
------- ----- -----
Net Cash Used In Investing Activities............. (834) (611) (595)
------- ----- -----
Cash Flows From Financing Activities
Proceeds from Long-term Debt.............................. - 150 178
Reduction in Long-term Debt............................... (105) (337) (184)
Dividends Paid............................................ (74) (77) (78)
Common Stock Purchases.................................... (58) (112) (5)
Other..................................................... 24 38 (4)
------- ----- -----
Net Cash Used In Financing Activities............. (213) (338) (93)
------- ----- -----
Increase (Decrease) in Cash and Cash Equivalents............ 75 46 (1)
Cash and Cash Equivalents
Beginning of Year......................................... 77 31 32
------- ----- -----
End of Year............................................... $ 152 $ 77 $ 31
======= ===== =====

See accompanying Notes to Consolidated Financial Statements.

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26

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(IN MILLIONS, EXCEPT SHARE DATA)

COST OF
COMMON PAID-IN RETAINED TREASURY STOCKHOLDERS'
STOCK CAPITAL EARNINGS OTHER STOCK EQUITY
------ ------- -------- ----- -------- -------------

Balance, December 31, 1994................... $2 $2,951 $ 893 $(5) $ (921) $2,920
Net Loss................................... (261) (261)
Cash Dividends ($.44 per Share)............ (77) (77)
Stock Purchases (132,900 Shares)........... (5) (5)
Stock Option Activity and Other............ 4 3 7 14
-- ------ ------ --- ------- ------
Balance, December 31, 1995................... 2 2,955 555 (2) (919) 2,591
Net Income................................. 335 335
Cash Dividends ($.44 per Share)............ (77) (77)
Stock Purchases (2,706,000 Shares)......... (112) (112)
Stock Option Activity and Other............ 27 2 42 71
-- ------ ------ --- ------- ------
Balance, December 31, 1996................... 2 2,982 813 - (989) 2,808
Net Income................................. 319 319
Cash Dividends ($.46 per Share)............ (82) (82)
Stock Purchases (1,312,500 Shares)......... (58) (58)
Stock Option Activity and Other............ 19 1 9 29
-- ------ ------ --- ------- ------
Balance, December 31, 1997................... $2 $3,001 $1,051 $ - $(1,038) $3,016
== ====== ====== === ======= ======

See accompanying Notes to Consolidated Financial Statements.

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27

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. ("BR") 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 consolidated financial statements include certain
reclassifications that were made to conform to current presentation. Such
reclassifications have no impact on net income or stockholders' equity. All
operational and financial information contained herein includes the combined
business activities for BR and LL&E for all periods presented.

Cash and Cash Equivalents

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.

Short-term Investments

Short-term investments consist of highly-liquid debt securities with a
maturity of more than three months. The securities are available for sale and
are carried at fair value based on quoted market prices. As of December 31,
1997, the fair value of these investments approximated amortized cost.
Unrealized gains and losses, net of tax, are included as a component of
stockholders' equity until realized. Realized gains and losses are based on
specific identification of the securities sold.

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 interest.

Functional Currency

Foreign exploration and production operations are considered an extension
of the Company's operations. The assets, liabilities and operations of foreign
locations are therefore measured using the

25
28

United States dollar as the functional currency. Foreign currency transaction
adjustments, which were not material, are included in net income.

Hedging and Related Activities

In order to mitigate the risk of market price fluctuations, oil and gas
futures, swaps and options contracts may be entered into as hedges of the
Company's production. Changes in the market value of these contracts are
deferred until the gain or loss is recognized on the hedged commodity. To
qualify as a hedge, these transactions must be designated as a hedge and changes
in their fair value must correlate with changes in the price of anticipated
future production such that the Company's exposure to the effects of commodity
price changes is reduced. The Company also enters into swap agreements to
convert fixed price gas sales contracts to market-sensitive contracts. Gains or
losses resulting from these transactions are included in revenue as the related
physical production is delivered.

These instruments are measured for effectiveness on an enterprise basis
both at the inception of the contract and on an ongoing basis. If these
instruments are terminated prior to maturity, resulting gains or losses continue
to be deferred until the hedged item is recognized in income.

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 to reflect the tax consequences in future years of
differences between the financial statement and tax basis of assets and
liabilities. 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. A
valuation allowance is established to reduce deferred tax assets if it is more
likely than not that the related tax benefits will not be realized.

Stock-Based Compensation

The Company uses the intrinsic value based method of accounting for
stock-based compensation. Under this method, the Company records no compensation
expense for stock options granted when the exercise price for options granted is
equal to the fair market value of the Company's stock on the date of the grant.

Earnings per Common Share

Basic earnings per common share ("EPS") is computed by dividing income
available to common stockholders by the weighted-average number of common shares
outstanding for the period. The weighted average number of common shares
outstanding for computing basic EPS was 177 million, 177 million and 178 million
for the years ended December 31, 1997, 1996 and 1995, respectively. Diluted EPS
reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised or converted into common stock.
The weighted average number of common shares outstanding for computing diluted
EPS, including dilutive stock options, was 178 million for the years ended
December 31, 1997, 1996 and 1995. No adjustments were made to reported net
income (loss) in the computation of EPS.

26
29

2. MERGER

On July 17, 1997, Burlington Resources Inc. and The Louisiana Land and
Exploration Company announced that they had entered into an Agreement and Plan
of Merger (the "Merger"). On October 22, 1997, the Merger was completed and LL&E
became a wholly-owned subsidiary of the Company. Pursuant to the Merger, BR
issued 52,795,635 shares of its Common Stock based on an exchange ratio of 1.525
for each outstanding share of LL&E stock. The Merger was accounted for as a
pooling of interests and qualified as a tax-free reorganization. The transaction
was valued at approximately $3 billion based on BR's closing stock price on
October 22, 1997. During the fourth quarter of 1997, the Company recorded a
pretax charge of $80 million ($71 million after tax) for direct costs associated
with the Merger. These costs primarily consist of $44 million for severance and
related exit costs and $36 million for direct transaction costs. Approximately
$44 million of accrued unpaid costs remained on the consolidated balance sheet
as of December 31, 1997.

The separate results of operations of BR and LL&E are as follows. Certain
reclassifications were made to the results of LL&E to conform to the
presentation used by BR.

(UNAUDITED)
NINE MONTHS YEAR ENDED
ENDED DECEMBER 31,
SEPTEMBER 30, -----------------
1997 1996 1995
------------- ------- -------
(IN MILLIONS)

Revenues
BR...................................................... $ 987 $ 1,293 $ 873
LL&E.................................................... 441 863 822
Conforming reclassifications............................ 31 44 39
------ ------- -------
Combined................................................ $1,459 $ 2,200 $ 1,734
====== ======= =======
Net Income (Loss)
BR...................................................... $ 249 $ 255 $ (280)
LL&E.................................................... 33 80 19
------ ------- -------
Combined................................................ $ 282 $ 335 $ (261)
====== ======= =======

3. HEDGING ACTIVITIES

Gas Swaps

The Company enters into gas swap agreements to offset the effects of
long-term fixed-price contracts for natural gas. The Company also enters into
gas swap agreements to fix the price of natural gas in the short-term.

The Company is a fixed-price payor on approximately 2.9 BCF (which is less
than 1 percent of the Company's 1997 gas production) at prices ranging from
$2.02 to $2.21 per MMBTU for production through March 31, 1999. These
transactions convert fixed-price contracts to market-sensitive contracts. The
Company is a fixed-price receivor on approximately 18.5 BCF (which approximates
3 percent of the Company's 1997 gas production) at prices ranging from $1.82 to
$3.36 per MMBTU for production through October 31, 1998. These transactions are
a hedge of the Company's underlying production. The deferred gain on these types
of transactions as of December 31, 1997 was approximately $7 million.

Futures Contracts

The Company sells crude oil and natural gas futures contracts on the New
York Mercantile Exchange ("NYMEX") and sells natural gas futures contracts on
the Kansas City Board of Trade ("KBOT"). These contracts allow the Company to
sell crude oil and natural gas at a future date for a specified price.
Outstanding crude oil futures contracts as of December 31, 1997 totaled 1.7
MMBbls (which approximates 5 percent of the Company's 1997 oil production) at
NYMEX prices ranging from $20.50 to $22.00 per bbl for production through
November 30, 1998. Outstanding natural gas futures contracts as of December 31,
1997 totaled 16.4 BCF (which approximates 3 percent of the Company's

27
30

1997 gas production) at NYMEX and KBOT prices ranging from $1.95 to $3.73 per
MMBTU for production through October 31, 1998. The deferred gain on crude oil
and natural gas futures contracts as of December 31, 1997 was approximately $11
million.

Options Contracts

The Company utilizes options and swaps which set a floor price for
anticipated future crude oil and natural gas production and allow the Company to
participate in market price increases which exceed specific non-participation
ranges and floor prices. At December 31, 1997, the Company had approximately 57
BCF of 1998 gas production (which approximates 9 percent of the Company's 1997
gas production) hedged at an average floor price of $1.80 per MMBTU and a
non-participation range in market price increases limited to $.24 per MMBTU. At
December 31, 1997, the Company had approximately 38 BCF of 1999 gas production
(which approximates 6 percent of the Company's 1997 gas production) hedged at an
average floor price of $1.79 per MMBTU and non-participation range in market
price increases limited to $.23 per MMBTU. At December 31, 1997, these
transactions had a deferred loss of approximately $3 million for 1998 gas
production and a deferred gain of $300 thousand for 1999 gas production. At
December 31, 1997, the Company had approximately 2 MMBbls of 1998 oil production
(which approximates 6 percent of 1997 oil production) hedged at an average floor
price of $19.38 per barrel and a non-participation range in market price
increases limited to $2.25 per barrel. The deferred gain on these transactions,
as of December 31, 1997, was approximately $4 million.

4. INCOME TAXES

The jurisdictional components of income (loss) before income taxes follow.

YEAR ENDED DECEMBER 31,
-------------------------
1997 1996 1995
---- ---- -----
(IN MILLIONS)

Domestic.................................................... $369 $400 $(594)
Foreign..................................................... 42 33 51
---- ---- -----
Total............................................. $411 $433 $(543)
==== ==== =====

The provision (benefit) for income taxes follows.

YEAR ENDED DECEMBER 31,
-------------------------
1997 1996 1995
---- ---- -----
(IN MILLIONS)

Current
Federal................................................... $44 $53 $ 62
State..................................................... 2 11 12
Foreign................................................... 10 2 3
--- --- -----
56 66 77
--- --- -----
Deferred
Federal................................................... 30 18 (321)
State..................................................... 11 9 (39)
Foreign................................................... (5) 5 1
--- --- -----
36 32 (359)
--- --- -----
Total............................................. $92 $98 $(282)
=== === =====

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31

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

YEAR ENDED DECEMBER 31,
---------------------------
1997 1996 1995
----- ----- -----

Statutory rate.............................................. 35.0% 35.0% (35.0)%
State income taxes net of federal tax benefit............... 2.1 3.0 (3.2)
Foreign income taxes net of federal tax benefit............. 2.1 .2 .6
Tax credits................................................. (18.5) (15.0) (15.4)
Merger costs................................................ 4.6 -- --
Other....................................................... (2.8) (.7) 1.1
----- ----- -----
Effective rate.................................... 22.5% 22.5% (51.9)%
===== ===== =====

Deferred income tax liabilities (assets) follow.

DECEMBER 31,
----------------
1997 1996
----- -----
(IN MILLIONS)

Deferred income tax liabilities
Excess of book over tax basis of properties............... $ 548 $ 426
----- -----
Deferred income tax assets
AMT credit carryforward................................... (255) (213)
Deferred foreign tax credits.............................. (66) (61)
Net operating loss carryforward........................... (4) (14)
Foreign tax credit carryforward........................... (2) (4)
Financial accruals and other.............................. (51) (6)
----- -----
(378) (298)
Less valuation allowance.......................... 33 34
----- -----
Net deferred income tax liabilities....................... $ 203 $ 162
===== =====

The above net deferred tax liabilities as of December 31, 1997 and 1996,
include deferred state income tax liabilities of approximately $39 million and
$28 million, respectively.

The Alternative Minimum Tax ("AMT") credit carryforward, related primarily
to nonconventional fuel tax credits, is available to offset future federal
income tax liabilities. The AMT credit carryforward has no expiration. The
benefit of these 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.

The foreign tax credit carryforward is available through the year 2001 to
offset future federal income taxes. The federal income tax net operating loss
carryforward is available through the year 2009 to offset future federal taxable
income, subject to the separate return limitation provisions of the federal
income tax regulations.

A valuation allowance is provided for uncertainties surrounding the
realization of certain foreign tax credit carryforwards and certain deferred
foreign tax credits.

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32

5. LONG-TERM DEBT

Long-term Debt follows.

DECEMBER 31,
------------------
1997 1996
------ ------
(IN MILLIONS)

Commercial Paper............................................ $ - $ 105
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
Notes, 8 1/4%, due 2002..................................... 100 100
Debentures, 9 7/8%, due 2010................................ 150 150
Debentures, 7 5/8%, due 2013................................ 100 100
Debentures, 9 1/8%, due 2021................................ 150 150
Debentures, 7.65%, due 2023................................. 200 200
Debentures, 8.20%, due 2025................................. 150 150
Debentures, 6 7/8%, due 2026................................ 150 150
Other, including discounts -- net........................... (2) (2)
------ ------
Total............................................. $1,748 $1,853
====== ======

The Company has debt maturities of $450 million, $150 million, $150 and
$100 million, due in 1999, 2000, 2001 and 2002, 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 in July 1998. The $300 million revolving credit agreement
is renewable annually by mutual consent and was renewed in July 1997. 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, 1997, there were no borrowings outstanding under these credit
facilities. In addition, the Company has the capacity to issue $500 million of
debt securities under shelf registration statements filed with the Securities
and Exchange Commission.

6. TRANSPORTATION ARRANGEMENTS WITH EL PASO NATURAL GAS COMPANY

In 1997, 1996 and 1995, approximately 41 percent, 43 percent and 47
percent, respectively, of the Company's gas production was transported to direct
sale customers through El Paso Natural Gas Company's ("EPNG") pipeline systems.
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 9 for demand charges paid to EPNG which provide
the Company with firm and interruptible transportation capacity rights on
interstate and intrastate pipeline systems.

7. CAPITAL STOCK

Stock Options

The Company's 1993 Stock Incentive Plan (the "1993 Plan") succeeds its 1988
Stock Option Plan which expired by its terms in May 1993 but remains in effect
for options granted prior to May 1993. The

30
33

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").

Under the 1993 Plan, options may be granted to officers and key employees
at fair market value on 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, 1997, 5,711,034 shares
of options were available for grant under the 1993 Plan. Under the 1997 Employee
Stock Incentive Plan (the "1997 Plan"), stock options and restricted stock
("Awards") may be granted to employees who are not eligible to participate in
the 1993 Plan. The options are granted at fair market value on the grant date,
become exercisable in whole after the completion of at least one year of
continuous employment and have a term of ten years. The 1997 Plan limits Awards,
in aggregate, to a maximum of one million annually.

Activity in the Company's stock option plans follows.

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

Balance, December 31, 1994.................................. 5,503,248 $28.85
Granted................................................... 1,128,843 29.47
Exercised................................................. (298,984) 26.31
Cancelled................................................. (49,448) 30.88
----------
Balance, December 31, 1995.................................. 6,283,659 29.07
Granted................................................... 2,896,483 47.35
Exercised................................................. (2,288,458) 26.91
Cancelled................................................. (105,615) 34.74
----------
Balance, December 31, 1996.................................. 6,786,069 37.51
Granted................................................... 2,253,627 40.99
Exercised................................................. (886,009) 27.09
Cancelled................................................. (210,613) 47.82
----------
Balance, December 31, 1997.................................. 7,943,074 $39.39
==========

The following table summarizes information related to stock options
outstanding and exercisable at December 31, 1997.

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

3,328,674 $19.51 to $38.00 $28.95 5.9 years 2,683,181 $28.25
4,614,400 39.93 to 52.03 46.92 9.1 years 1,234,150 46.27
--------- ---------
7,943,074 $19.51 to $52.03 $39.39 7.7 years 3,917,331 $33.93
========= =========

Exercisable stock options and weighted average exercise prices at December
31, 1996 and 1995 follow.

WEIGHTED
AVERAGE
SHARES EXERCISE
EXERCISABLE PRICE
----------- --------

December 31, 1996........................................... 3,593,423 $30.79
========= ======
December 31, 1995........................................... 5,021,203 $29.13
========= ======

31
34

The weighted average fair values of options granted during the years 1997,
1996 and 1995 were $10.45, $12.45 and $8.24, 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 1997, 1996 and 1995: stock price volatility of 18.35 percent, 18.62
percent and 20.63 percent, respectively; risk free rate of return ranging from
5.91 percent to 6.53 percent; dividend yield of 1.07 percent, 1 percent and .93
percent, respectively; and an expected term of 5 years. If the fair value based
method of accounting had been applied, the Company's net income and EPS would
have been reduced to the pro forma amounts indicated below. The fair value of
stock options included in the pro forma amounts is not necessarily indicative of
future effects on net income and EPS.

YEAR ENDED DECEMBER 31,
-------------------------
1997 1996 1995
------ ------ -------
(IN MILLIONS, EXCEPT
PER SHARE AMOUNTS)

Net Income (Loss) -- as reported............................ $ 319 $ 335 $ (261)
Net Income (Loss) -- pro forma.............................. 308 329 (262)
Basic Earnings (Loss) per Common Share -- as reported....... 1.80 1.89 (1.47)
Basic Earnings (Loss) per Common Share -- pro forma......... 1.74 1.86 (1.47)
Diluted Earnings (Loss) per Common Share -- as reported..... 1.79 1.88 (1.47)
Diluted Earnings (Loss) per Common Share -- pro forma....... $1.73 $1.85 $(1.47)

Stock Appreciation Rights

The Company has granted SARs in connection with certain outstanding options
under the 1988 Stock Option 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, 1997, there were 391,267 SARs outstanding related to stock options with a
weighted average exercise price of $27.09 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, 1997 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

32
35

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.

8. RETIREMENT BENEFITS

Pension

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 final average compensation. Contributions to the plans 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 tables set forth the amounts recognized in the Consolidated
Balance Sheet and Statement of Income.

DECEMBER 31,
----------------------
1997 1996
-------- --------
(IN MILLIONS)

Actuarial present value of benefit obligations
Accumulated benefit obligation, including vested
benefits of $127 and $120.............................. $ 131 $ 124
======== ========

Projected benefit obligation for service to date.......... $ 178 $ 161
Plan assets, primarily marketable equity and debt
securities, at fair value................................. (161) (144)
-------- --------
Funded status of projected benefit obligation............... 17 17
Unrecognized net loss....................................... (26) (27)
Unamortized net transition obligation....................... (2) (2)
-------- --------
Net prepaid pension asset................................... $ (11) $ (12)
======== ========

YEAR ENDED DECEMBER 31,
------------------------
1997 1996 1995
---- ---- ----
(IN MILLIONS)

Pension cost for the plans includes the following components
Service cost -- benefits earned during the period......... $ 9 $ 9 $ 8
Interest cost on projected benefit obligation............. 12 12 11
Actual return on plan assets.............................. (28) (19) (23)
Net amortization and deferred amounts..................... 18 12 16
---- ---- ----
Net pension cost.......................................... $ 11 $ 14 $ 12
==== ==== ====

The projected benefit obligation was determined using a weighted average
discount rate of 7.25 percent in 1997 and 7.75 percent in 1996, 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 1997 and 1996.

Postretirement

The Company has postretirement medical and dental care plans for a closed
group of retirees and their dependents and certain employees who retire by the
end of 1999. The Company also maintains a

33
36

Medicare Part B reimbursement plan and life insurance coverage for a closed
group of retirees of a former subsidiary.

The postretirement benefit plans are unfunded and the Company funds claims
on a cash basis. The following tables set forth the amounts recognized in the
Consolidated Balance Sheet and Statement of Income.

DECEMBER 31,
--------------
1997 1996
---- ----
(IN MILLIONS)

Accumulated postretirement benefit obligation
Retirees.................................................. $22 $22
Employees eligible to retire.............................. 4 4
Other employees........................................... 7 5
--- ---
33 31
Unrecognized net loss....................................... (3) (2)
--- ---
Accrued postretirement benefit cost......................... $30 $29
=== ===

YEAR ENDED DECEMBER 31,
------------------------
1997 1996 1995
---- ---- ----
(IN MILLIONS)

Service cost................................................ $1 $1 $1
Interest cost............................................... 3 3 2
-- -- --
Net postretirement benefit cost............................. $4 $4 $3
== == ==

Assumptions utilized to measure the accumulated postretirement obligation
at December 31, 1997 and 1996 were: discount rates of 7.25 percent and 7.5
percent, respectively; health care cost trend rates of: 1997 -- 5 percent
declining to 4 percent in the year 2002; 1996 -- 8 percent declining to 4
percent in the year 2002 and held constant thereafter. A one percent increase in
the assumed trend rates would have resulted in increases in the accumulated
postretirement benefit obligation at December 31, 1997 and 1996 of approximately
$3 million for both years. The aggregate of service cost and interest cost for
the years ended December 31, 1997 and 1996 would have increased by $400 thousand
and $500 thousand, respectively.

9. 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 from 1 to 10 years and require the Company to pay
transportation demand charges regardless of the amount of pipeline capacity
utilized by the Company. The Company paid $49 million, $61 million and $53
million of demand charges of which $34 million, $47 million and $40 million was
paid to EPNG for the years ended December 31, 1997, 1996 and 1995, respectively.

34
37

Future transportation demand charge commitments at December 31, 1997
follow.

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

1998........................................................ $ 60
1999........................................................ 61
2000........................................................ 49
2001........................................................ 43
2002........................................................ 43
Thereafter.................................................. 168
----
Total.................................................. $424
====

Lease Obligations

The Company has operating leases for office space and other property and
equipment. The Company incurred lease rental expense of $18 million, $20 million
and $19 million for the years ended December 31, 1997, 1996 and 1995,
respectively.

Future minimum annual rental commitments at December 31, 1997 follow.

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

1998........................................................ $ 18
1999........................................................ 18
2000........................................................ 15
2001........................................................ 14
2002........................................................ 14
Thereafter.................................................. 79
----
Total.................................................. $158
====

Legal Proceedings

35
38

alternative, to modify, alter or amend judgment, which motion was denied by
Order signed December 16, 1996. The objectors purported to perfect an appeal of
the Judgment on February 7, 1997. On July 24, 1997, the Fourteenth Court of
Appeals dismissed the appeal. On October 17, 1997, the objectors filed a
Petition for Review with The Supreme Court of Texas. The Company and the
Plaintiffs intend to defend this appeal vigorously.

10. DIVESTITURE PROGRAM AND REORGANIZATION

In June 1997, the Company completed its non-strategic divestiture program
which was announced in July 1996. As planned, the Company sold approximately
27,000 wells and related facilities. Before closing adjustments, gross proceeds
for 1997 from the sales of oil and gas properties related to this divestiture
program were approximately $450 million (approximately $418 million, net of
closing adjustments). During the second quarter of 1997, the Company recorded a
pretax gain of approximately $50 million related to the sales of oil and gas
properties. This program allowed the Company to reorganize and resulted in a
reduction of 456 employees. As of December 31, 1997, this program was complete.

11. DEFERRED REVENUE

In September 1996, the Company received cash proceeds of $108 million for a
transaction in which it is obligated to deliver gas through December 31, 2002.
The proceeds were recorded as deferred revenue and are being amortized into
revenues as the gas is delivered. Approximately $20 million and $13 million of
deferred revenue was recognized in 1997 and 1996, respectively.

12. IMPAIRMENT OF OIL AND GAS PROPERTIES

Effective September 30, 1995, the Company adopted Statement of Financial
Accounting Standards ("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 undiscounted 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.

13. RECENT ACCOUNTING PRONOUNCEMENTS

In June 1997, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 130, Reporting Comprehensive Income, which is effective for fiscal years
beginning after December 15, 1997.

36
39

In June 1997, the FASB also issued SFAS No. 131, Disclosures about Segments
of an Enterprise and Related Information, which is effective for fiscal years
beginning after December 15, 1997.

14. SUPPLEMENTAL CASH FLOW INFORMATION

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

YEAR ENDED DECEMBER 31,
------------------------
1997 1996 1995
---- ---- ----
(IN MILLIONS)

Interest Paid..................................... $149 $154 $158
Income Taxes Paid--Net............................ $ 56 $ 60 $ 62

15. SEGMENT INFORMATION

The Company's operations are primarily related to oil and gas exploration
and production. Accordingly, such operations are classified as one business
segment. Financial information by geographic area follows.

YEAR ENDED DECEMBER 31,
------------------------------
1997 1996 1995
------ ------ ------
(IN MILLIONS)

Revenues
Domestic................................ $1,795 $1,989 $1,532
Foreign................................. 205 211 202
------ ------ ------
Total Revenues..................... $2,000 $2,200 $1,734
====== ====== ======

Operating Income (Loss)
Domestic................................ $ 450 $ 526 $ (428)
Foreign................................. 53 54 31
------ ------ ------
Total Operating Income (Loss)...... $ 503 $ 580 $ (397)
====== ====== ======

DECEMBER 31,
------------------
1997 1996
------ ------
(IN MILLIONS)

Total Assets
Domestic............................................ $5,184 $5,129
Foreign............................................. 637 554
------ ------
$5,821 $5,683
====== ======

37
40

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholders of
Burlington Resources Inc.

We have audited the accompanying consolidated balance sheet of Burlington
Resources Inc. as of December 31, 1997 and 1996, and the related consolidated
statements of income, cash flows and stockholders' equity for each of the three
years in the period ended December 31, 1997. 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, 1997 and 1996, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1997, in conformity with generally accepted accounting
principles.

As discussed in Note 12 to the consolidated financial statements, the
Company changed its method of accounting for the impairment of long-lived assets
in 1995.

Coopers & Lybrand L.L.P.

Houston, Texas
January 14, 1998

38
41

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,
------------------
1997 1996
------ ------
(IN MILLIONS)

Proved properties........................................... $8,590 $8,678
Unproved properties......................................... 150 185
------ ------
8,740 8,863
Accumulated depreciation, depletion and amortization........ 4,003 4,300
------ ------
Net capitalized costs............................. $4,737 $4,563
====== ======

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

YEAR ENDED DECEMBER 31, 1997
-----------------------------
DOMESTIC FOREIGN TOTAL
-------- ------- ------
(IN MILLIONS)

Property acquisition
Unproved................................................. $ 93 $ 5 $ 98
Proved................................................... 54 160 214
Exploration................................................ 241 48 289
Development................................................ 539 15 554
---- ---- ------
Total costs incurred............................. $927 $228 $1,155
==== ==== ======

YEAR ENDED DECEMBER 31, 1996
----------------------------
DOMESTIC FOREIGN TOTAL
-------- ------- -----
(IN MILLIONS)

Property acquisition
Unproved.................................................. $ 48 $ 9 $ 57
Proved.................................................... 92 - 92
Exploration................................................. 134 29 163
Development................................................. 402 24 426
---- --- ----
Total costs incurred.............................. $676 $62 $738
==== === ====

YEAR ENDED DECEMBER 31, 1995
----------------------------
DOMESTIC FOREIGN TOTAL
-------- ------- -----
(IN MILLIONS)

Property acquisition
Unproved.................................................. $ 49 $11 $ 60
Proved.................................................... 103 - 103
Exploration................................................. 119 20 139
Development................................................. 356 28 384
---- --- ----
Total costs incurred.............................. $627 $59 $686
==== === ====

39
42

Results of operations for oil and gas producing activities follow.

YEAR ENDED DECEMBER 31, 1997
----------------------------
DOMESTIC FOREIGN TOTAL
-------- ------- ------
(IN MILLIONS)

Net revenues................................................ $1,747 $ 205 $1,952
------ ------ ------
Production costs............................................ 363 42 405
Exploration and leasehold impairment costs.................. 234 25 259
Operating expenses.......................................... 220 10 230
Depreciation, depletion and amortization.................... 422 75 497
------ ------ ------
1,239 152 1,391
------ ------ ------
Operating income............................................ 508 53 561
Income tax provision........................................ 103 27 130
------ ------ ------
Results of operations for oil and gas producing
activities................................................ $ 405 $ 26 $ 431
====== ====== ======

YEAR ENDED DECEMBER 31, 1996
----------------------------
DOMESTIC FOREIGN TOTAL
-------- ------- ------
(IN MILLIONS)

Net revenues................................................ $1,682 $ 211 $1,893
------ ------ ------
Production costs............................................ 372 51 423
Exploration and leasehold impairment costs.................. 145 14 159
Operating expenses.......................................... 224 11 235
Depreciation, depletion and amortization.................... 408 81 489
------ ------ ------
1,149 157 1,306
------ ------ ------
Operating income............................................ 533 54 587
Income tax provision........................................ 131 20 151
------ ------ ------
Results of operations for oil and gas producing
activities................................................ $ 402 $ 34 $ 436
====== ====== ======

YEAR ENDED DECEMBER 31, 1995
----------------------------
DOMESTIC FOREIGN TOTAL
-------- ------- ------
(IN MILLIONS)

Net revenues................................................ $1,129 $ 201 $1,330
------ ------ ------
Production costs............................................ 351 53 404
Exploration and leasehold impairment costs.................. 89 22 111
Operating expenses.......................................... 224 14 238
Depreciation, depletion and amortization.................... 415 81 496
Impairment of oil and gas properties........................ 490 - 490
------ ------ ------
1,569 170 1,739
------ ------ ------
Operating income (loss)..................................... (440) 31 (409)
Income tax provision (benefit).............................. (253) 14 (239)
------ ------ ------
Results of operations for oil and gas producing
activities................................................ $ (187) $ 17 $ (170)
====== ====== ======

40
43

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 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 (MMBBLS) GAS (BCF)
-------------------------- --------------------------
DOMESTIC FOREIGN TOTAL DOMESTIC FOREIGN TOTAL
-------- ------- ----- -------- ------- -----

PROVED DEVELOPED AND UNDEVELOPED RESERVES
December 31, 1994............................ 236.6 44.6 281.2 6,175 310 6,485
Revision of previous estimates............ 4.9 (3.8) 1.1 18 8 26
Extensions, discoveries and other
additions............................... 36.2 5.3 41.5 582 15 597
Production................................ (24.8) (8.4) (33.2) (520) (26) (546)
Purchases of reserves in place............ 9.5 - 9.5 147 - 147
Sales of reserves in place................ (4.8) (1.6) (6.4) (205) (18) (223)
----- ---- ----- ----- --- -----
December 31, 1995............................ 257.6 36.1 293.7 6,197 289 6,486
Revision of previous estimates............ 6.6 (.4) 6.2 (8) 28 20
Extensions, discoveries and other
additions............................... 33.1 2.3 35.4 474 34 508
Production................................ (26.1) (7.2) (33.3) (559) (28) (587)
Purchases of reserves in place............ 8.0 - 8.0 78 - 78
Sales of reserves in place................ (4.2) - (4.2) (274) - (274)
----- ---- ----- ----- --- -----
December 31, 1996............................ 275.0 30.8 305.8 5,908 323 6,231
Revisions of previous estimates........... (15.6) (2.6) (18.2) 68 (4) 64
Extensions, discoveries and other
additions............................... 44.9 .3 45.2 913 1 914
Production................................ (24.6) (7.2) (31.8) (583) (26) (609)
Purchases of reserves in place............ 1.4 - 1.4 116 240 356
Sales of reserves in place................ (48.7) - (48.7) (538) - (538)
----- ---- ----- ----- --- -----
December 31, 1997............................ 232.4 21.3 253.7 5,884 534 6,418
===== ==== ===== ===== === =====
PROVED DEVELOPED RESERVES
January 1, 1995.............................. 210.0 37.3 247.3 5,078 272 5,350
December 31, 1995............................ 224.8 30.3 255.1 5,064 271 5,335
December 31, 1996............................ 242.0 25.4 267.4 4,870 265 5,135
December 31, 1997............................ 203.9 15.6 219.5 4,641 233 4,874

41
44

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, 1997
------------------------------
DOMESTIC FOREIGN TOTAL
-------- ------- -----
(IN MILLIONS)

Future cash inflows......................................... $15,934 $ 1,800 $17,734
Less related future
Production costs....................................... 4,076 702 4,778
Development costs...................................... 736 214 950
Income taxes........................................... 2,767 200 2,967
------- ------- -------
Future net cash flows............................. 8,355 684 9,039
10% annual discount for estimated timing of cash flows.... 3,960 234 4,194
------- ------- -------
Standardized measure of discounted future net cash
flows................................................ $ 4,395 $ 450 $ 4,845
======= ======= =======

DECEMBER 31, 1996
------------------------------
DOMESTIC FOREIGN TOTAL
-------- ------- -----
(IN MILLIONS)

Future cash inflows......................................... $25,089 $ 1,261 $26,350
Less related future
Production costs....................................... 5,514 216 5,730
Development costs...................................... 702 74 776
Income taxes........................................... 5,295 319 5,614
------- ------- -------
Future net cash flows............................. 13,578 652 14,230
10% annual discount for estimated timing of cash flows.... 6,513 212 6,725
------- ------- -------
Standardized measure of discounted future net cash
flows................................................ $ 7,065 $ 440 $ 7,505
======= ======= =======

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,
-----------------------------
1997 1996 1995
------- ------- -------
(IN MILLIONS)

January 1................................................... $ 7,505 $ 4,393 $ 3,967
------- ------- -------
Revisions of previous estimates
Changes in prices and costs............................... (4,167) 4,981 284
Changes in quantities..................................... (23) 119 16
Changes in rate of production............................. (436) (77) 189
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related costs..... 655 782 461
Purchases of reserves in place.............................. 246 148 120
Sales of reserves in place.................................. (667) (177) (162)
Accretion of discount....................................... 1,048 529 471
Sales of oil and gas, net of production costs............... (1,547) (1,470) (926)
Net change in income taxes.................................. 1,697 (1,652) (128)
Other....................................................... 534 (71) 101
------- ------- -------
Net change.................................................. (2,660) 3,112 426
------- ------- -------
December 31................................................. $ 4,845 $ 7,505 $ 4,393
======= ======= =======

42
45

BURLINGTON RESOURCES INC.

QUARTERLY FINANCIAL DATA--UNAUDITED

1997(C) 1996(C)
------------------------------------ ------------------------------------
4TH 3RD 2ND 1ST 4TH 3RD 2ND 1ST
------ ------ ------ ------ ------ ------ ------ ------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

Revenues................... $ 541 $ 464 $ 427 $ 568 $ 589 $ 526 $ 552 $ 533

Operating Income(a)........ 87 116 93 207 222 116 133 109

Net Income(a)(b)........... 37 65 86 131 139 73 65 58

Basic Earnings per Common
Share.................... .20 .37 .49 .74 .78 .41 .37 .33

Diluted Earnings per Common
Share.................... .20 .37 .49 .73 .78 .41 .36 .33

Dividends Declared per
Common Share............. .14 .10 .11 .11 .11 .11 .11 .11

Common Stock Price Range
High..................... 53 5/8 53 3/16 48 5/8 54 1/2 53 1/2 47 1/8 43 1/4 40 1/4
Low...................... $42 1/2 $43 5/8 $39 3/4 $42 5/8 $44 1/8 $41 5/8 $35 1/8 $35 5/8

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

(a) During the fourth quarter of 1997, as a result of the Merger, the Company
recorded a pretax charge of $80 million($71 million after tax). During the
third quarter of 1996, as a result of the divestiture program and
reorganization, the Company recorded a pretax charge of approximately $30
million($19 million after tax).

(b) During the second quarter of 1997, as a result of the divestiture program,
the Company recorded a pretax gain of $50 million($31 million after tax).

43
46

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 1998 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 12 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 1998 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 1998 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.......................... 21
Consolidated Balance Sheet................................ 22
Consolidated Statement of Cash Flows...................... 23
Consolidated Statement of Stockholders' Equity............ 24
Notes to Consolidated Financial Statements................ 25
Report of Independent Accountants......................... 38
Supplemental Oil and Gas Disclosures -- Unaudited......... 39
Quarterly Financial Data -- Unaudited..................... 43

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

REPORTS ON FORM 8-K

The Company filed a Form 8-K dated November 6, 1997, which included as an
exhibit a Press Release dated October 22, 1997, announcing that an Agreement and
Plan of Merger with The Louisiana Land and Exploration Company was consummated
following the favorable votes of each company's stockholders.

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

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

44
47

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
Chairman of the Board, President and
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of Burlington
Resources Inc. and in the capacities and on the dates indicated.

By BOBBY S. SHACKOULS Chairman of the Board, January 14, 1998
----------------------------------------------------- President and Chief
Bobby S. Shackouls Executive Officer

JOHN E. HAGALE Executive Vice President and January 14, 1998
- -------------------------------------------------------- Chief Financial Officer
John E. Hagale

PHILIP W. COOK Vice President, January 14, 1998
- -------------------------------------------------------- Controller and Chief
Philip W. Cook Accounting Officer

H. LEIGHTON STEWARD Vice Chairman of the Board January 14, 1998
- --------------------------------------------------------
H. Leighton Steward

JOHN V. BYRNE Director January 14, 1998
- --------------------------------------------------------
John V. Byrne

S. PARKER GILBERT Director January 14, 1998
- --------------------------------------------------------
S. Parker Gilbert

LAIRD I. GRANT Director January 14, 1998
- --------------------------------------------------------
Laird I. Grant

JOHN T. LAMACCHIA Director January 14, 1998
- --------------------------------------------------------
John T. LaMacchia

JAMES F. MCDONALD Director January 14, 1998
- --------------------------------------------------------
James F. McDonald

KENNETH W. ORCE Director January 14, 1998
- --------------------------------------------------------
Kenneth W. Orce

DONALD M. ROBERTS Director January 14, 1998
- --------------------------------------------------------
Donald M. Roberts

JOHN F. SCHWARZ Director January 14, 1998
- --------------------------------------------------------
John F. Schwarz

WALTER SCOTT, JR. Director January 14, 1998
- --------------------------------------------------------
Walter Scott, Jr.

WILLIAM E. WALL Director January 14, 1998
- --------------------------------------------------------
William E. Wall

45
48

REPORT OF MANAGEMENT

The management of Burlington Resources is responsible for the preparation
and integrity of all information contained in this Annual Report. The
accompanying financial statements have been prepared in conformity with
generally accepted accounting principles. The financial statements include
amounts that are management's best estimates and judgments.

BR maintains a system of internal control and a program of internal
auditing that provides management with reasonable assurance that BR's assets are
protected and that published financial statements are reliable and free of
material misstatement. 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.

The Audit Committee of the Board of Directors, composed solely of directors
who are not officers or employees, meets regularly with the independent
certified public accountants, financial management, counsel and corporate audit.
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 controls and the quality of financial
reporting.

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.

John E. Hagale Philip W. Cook
Executive Vice President and Vice President, Controller and
Chief Financial Officer Chief Accounting Officer

CORPORATE INFORMATION

PRINCIPAL CORPORATE OFFICE STOCK EXCHANGE LISTING Additional copies of this Annual
Burlington Resources Inc. New York Stock Exchange Report are available, without charge,
5051 Westheimer, Suite 1400 Symbol: BR by writing or calling:
Houston, Texas 77056
(713) 624-9500

ANNUAL MEETING STOCK TRANSFER AGENT AND Corporate Secretary
The Annual Meeting of Stockholders REGISTRAR Burlington Resources Inc.
will be in Houston, Texas, on March Bank Boston, N.A. P.O. Box 4239
26, 1998. Formal notice of the c/o Boston EquiServe, L.P. Houston, Texas 77210
meeting will be mailed in advance. Investor Relations Department (713) 624-9500
P.O. Box 8040/MS 45-02-64
Boston, Massachusetts 02266
1 (800) 736-3001
http: //www.equiserve.com

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49

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. amended and restated as
of October 22, 1997.........................................
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)................... *
4.5 Indenture dated as of June 15, 1992 among the Registrant and
Texas Commerce Bank National Association (as Trustee)
(Exhibit 4.1 LL&E's Form S-3, as amended, filed November
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 (Exhibit 10.2 to Form 10-K, filed
February 1997).............................................. *
+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 (Exhibit 10.4 to Form 10-K, filed
February 1997).............................................. *
+10.5 Burlington Resources Inc. Supplemental Benefits Plan as
amended and restated (Exhibit 10.5 to Form 10-K, filed
February 1997).............................................. *
+10.6 Employment Contract between Burlington Resources Inc. and
Bobby S. Shackouls (Exhibit 10.7 to Form 10-K, filed
February 1996).............................................. *
Amendment to Employment Contract between Burlington
Resources Inc. and Bobby S. Shackouls, dated July 9, 1997...
+10.7 Employment Contract between Burlington Resources Inc. and H.
Leighton Steward, dated October 22, 1997....................
+10.8 Burlington Resources Inc. Compensation Plan for Non-Employee
Directors as amended and restated (Exhibit 10.8 to Form
10-K, filed February 1997).................................. *

A-1
50

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

+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)........... *
Amendment No. 5 to Burlington Resources Inc. Retirement
Savings Plan................................................
+10.11 Burlington Resources Inc. Retirement Income Plan for
Directors (Exhibit 10.21 to Form 8, filed February 1991).... *
+10.12 Burlington Resources Inc. Phantom Stock Plan for
Non-Employee Directors, effective March 21, 1996 (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 (Exhibit 10.17 to Form 10-K, filed
February 1997).............................................. *
+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)...... *
+10.21 Burlington Resources Inc. 1997 Performance Share Unit Plan,
(Exhibit 10.21 to Form 10-K, filed February 1997)........... *
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 (Exhibit 10.22 to Form 10-K, filed
February 1997).............................................. *

A-2
51

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

Second Amendment to Short-term Revolving Credit Agreement,
dated as of July 12, 1996 (Exhibit 10.22 to Form 10-K, filed
February 1997).............................................. *
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
(Exhibit 10.23 to Form 10-K, filed February 1997)........... *
+10.24 Form of Termination Agreement with Certain Senior Management
Personnel as amended (Exhibit 10(a)(i) to LL&E's Form 10-K,
filed March 1996)........................................... *
+10.25 Pension Agreement, dated as of December 27, 1994 (Exhibit
10(e) to LL&E's Form 10-K filed March 1995)................. *
+10.26 Form of The Louisiana Land and Exploration Company Deferred
Compensation Arrangement for Selected Key Employees (Exhibit
10(g) to LL&E's Form 10-K filed March 1991)................. *
+10.27 The LL&E Supplemental Excess Plan (Exhibit 10(j) to LL&E's
Form 10-K filed March 1993)................................. *
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