NEWFIELD EXPLORATION CO /DE/ - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER: 1-12534
NEWFIELD EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)

DELAWARE 72-1133047
(State of incorporation) (I.R.S. Employer Identification No.)

363 NORTH SAM HOUSTON PARKWAY, 77060
SUITE 2020, (Zip Code)
HOUSTON, TEXAS
(Address of principal executive offices)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
281-847-6000

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

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 the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]

The aggregate market value of the voting stock held by non-affiliates of
the registrant was approximately $1,166,200,000 as of March 5, 2002 (based on
the last sale price of such stock as quoted on the New York Stock Exchange).

As of March 5, 2002 there were 44,275,828 shares of the registrant's common
stock, par value $0.01 per share, outstanding.

Documents incorporated by reference: Proxy Statement of Newfield
Exploration Company for the Annual Meeting of Stockholders to be held May 2,
2002, which is incorporated into Part III of this Form 10-K.
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TABLE OF CONTENTS

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Unless the context otherwise requires, all references in this report to
"Newfield," "we," "us" or "our" are to Newfield Exploration Company and its
subsidiaries. Unless otherwise noted, all information in this report relating to
oil and gas reserves and the estimated future net cash flows attributable to
those reserves are based on estimates we prepared and are net to our interest.
If you are not familiar with the oil and gas terms used in this report, please
refer to the explanations of such terms under the caption "Commonly Used Oil and
Gas Terms" at the end of Item 7 of this report.

PART I

ITEM 1. BUSINESS

Newfield is an independent oil and gas company engaged in the exploration,
development and acquisition of crude oil and natural gas properties. Our company
was founded in 1989 and we acquired our first property in 1990. Our initial
focus area was the Gulf of Mexico. In the mid-1990s, we began to expand our
operations to other select areas. Our areas of operation now also include the
U.S. onshore Gulf Coast, the Anadarko Basin, offshore northwest Australia and
the Bohai Bay, offshore China.

At year-end 2001, we had proved reserves of 936.4 Bcfe. Of those reserves,

- 77% were natural gas;

- 93% were proved developed;

- 58% were located in the Gulf of Mexico;

- 39% were located onshore in the U.S.; and

- 3% were located offshore Australia.

STRATEGY

Our growth strategy has remained unchanged and is based on the following
elements:

- growing reserves through the drilling of a balanced portfolio;

- balancing exploration with the acquisition and exploitation of proved
properties;

- focusing on select geographic areas;

- controlling operations and costs;

- using 3-D seismic data and other advanced technologies; and

- attracting and retaining a quality workforce through equity ownership and
other performance-based incentives.

DRILLING PROGRAM. We have an active, technology-driven drilling program.
We continuously evaluate opportunities and have a substantial inventory of
prospects. The reserves targeted by our drilling program are balanced between a
smaller number of higher risk, higher potential prospects and a greater number
of lower risk, low and moderate potential prospects. We are planning to drill a
greater number of higher potential exploration wells in 2002, including eight to
ten Deep Shelf wells in the Gulf of Mexico. Our exploration budget for 2002 is
$135 million -- a record level.

BALANCE. Our total proved reserves reflect a balance of acquisitions and
drillbit success. Balance is one of our founding and continuing business
principles. Our exploration, acquisition and exploitation and development
activities are complimentary and often overlap. We actively pursue the
acquisition of proved oil and gas properties in select geographic areas.
Acquired properties usually have exploration or exploitation potential. In
addition, our initial entry into a new focus area typically has been
accomplished by an acquisition. Acquisitions also may help create infrastructure
that will facilitate our ability to capture other opportunities on a more
attractive basis. In addition to acquisitions, we develop or acquire exploration
prospects through the

continuous review of our existing property base, farm-ins from other operators
and federal and state lease sales. A successful exploratory prospect may reveal
similar untested reserve potential on an adjacent property, making its purchase
attractive. Our extensive seismic, land and production databases, along with
regional geological interpretations, are critical to our acquisition and
exploration efforts.

GEOGRAPHIC FOCUS. Focus also is a founding and continuing business
principle. We believe that our long-term success requires extensive knowledge of
geologic and operating conditions in the areas where we operate. Because of this
belief, we focus our efforts on a limited number of geographic areas where we
can use our core competencies, such as geological and geophysical analyses
through the application of 3-D seismic data and other advanced technologies,
expertise in marine operations and significant influence on operations. We also
believe that geographic focus allows us to make the most efficient use of our
capital and personnel because we can manage a large asset base with a relatively
small number of employees and add successful wells and proved property
acquisitions at relatively low incremental costs.

Gulf of Mexico. We have extensive experience in our largest focus
area -- the Gulf of Mexico. It is a prolific oil and gas province, accounting
for approximately 25% of domestic natural gas production. It has substantial
existing infrastructure, including gathering systems, platforms and pipelines,
facilitating cost effective operations and timely development of discoveries. We
believe that the Gulf of Mexico has significant remaining undiscovered reserve
potential. In addition to our traditional drilling activities on the shelf, we
are active in two emerging plays -- the shallow water Offshore Texas Frio and
the Deep Shelf. We also are working to enter the deepwater of the U.S. Gulf of
Mexico. This play is a logical extension of our traditional efforts in the Gulf
of Mexico and will help balance the weighting of risk and reward in our
exploratory programs.

Onshore Gulf Coast. As a natural extension of our offshore efforts, we
established onshore Gulf Coast operations in 1995. With similar geologic
features, our onshore program benefits from our core competencies. Over the last
three years, we have added more than 25 experienced professionals to our onshore
Gulf Coast team.

Mid-Continent. In January 2001, we added the Mid-Continent as a focus area
with the acquisition of Lariat Petroleum. About 90% of our proved reserves in
the Mid-Continent are located in the Anadarko Basin of Oklahoma. By acquiring a
going concern, we added a team of professionals with extensive experience in the
area and a proven track record of profitably growing production and reserves. We
believe that the Anadarko Basin provides an opportunity for future growth. It is
a gas-rich province characterized by multiple productive zones, relatively low
drilling costs and long life reserves. Like the Gulf of Mexico, it is a mature
basin, offering the potential to consolidate properties.

International. In the mid-1990s we began to consider investment in select
international areas where we could use our core competencies under an attractive
fiscal regime to provide additional or alternative opportunities and to gain
exposure to high potential prospects. In 1997, we acquired a 35% interest in a
production-sharing license in the Bohai Bay, offshore China. In mid-1999, we
acquired interests in two producing oil fields, Jabiru and Challis, and 10
exploration and production licenses in the Timor Sea, offshore Australia. We
continue to evaluate and pursue opportunities for international expansion in
Australia and surrounding regions, China, South America and the United Kingdom's
Southern Gas Basin of the North Sea.

CONTROL OF OPERATIONS AND COSTS. We prefer to operate our properties. By
controlling operations, we can better manage production performance, control
operating expenses and capital expenditures, consider the application of
technologies and influence timing. At the end of 2001, we operated about 85% of
our total production. In an effort to control costs, we also use independent
contractors for much of our domestic offshore operating activities.

TECHNOLOGY. We use advanced technologies in our exploration and
development activities to help reduce risks and lower costs. At February 28,
2002, we held licenses or otherwise had access to 3-D seismic surveys covering
approximately 3,500 blocks (about 17 million acres) in the Gulf of Mexico's
shallow waters, access to about 300 blocks in the deepwater of the Gulf of
Mexico, more than 2,500 square miles in southern Louisiana and South Texas,
2,400 square miles in the Anadarko Basin, 5,000 square kilometers offshore

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Australia, including coverage of the two producing fields we operate, and 350
square kilometers covering the area where we are currently active offshore
China.

EQUITY OWNERSHIP AND INCENTIVE COMPENSATION. Another of our founding and
continuing business principles is both to reward and encourage our employees
through equity ownership and incentive compensation based on performance and
profitability. As of February 28, 2002, our employees owned or had options to
acquire an aggregate of approximately 10% of our outstanding common stock on a
fully diluted basis.

2001 OPERATING HIGHLIGHTS

We were very active in 2001. We drilled 145 wells, completed our
largest-ever acquisition to establish a new focus area in the Mid-Continent and
completed an additional acquisition to enter a new play in the Gulf of Mexico.

During 2001, we invested $97 million in exploration activities. The largest
component of that expenditure was in the Gulf of Mexico. Our domestic
exploration/exploitation drilling program resulted in 81 successful wells.
Internationally, we drilled 10 wells in 2001. In China's Bohai Bay, we drilled
two wells to the south of our CFD 12-1 Field in a new field discovery called CFD
12-1 South. We continued to appraise our CFD 12-1 Field, drilling two appraisal
wells that found hydrocarbons and one dry hole. In Australia, we drilled five
exploratory dry holes in 2001.

Inclusive of the $333 million acquisition of Lariat Petroleum in January
2001, we invested $435 million in acquisitions. We entered the Offshore Texas
Frio play through a 2001 acquisition. Our spending on development projects in
2001 was $303 million, including exploitation and development drilling and well
recompletions. During 2001, we completed five major Gulf of Mexico development
projects and a three well development drilling campaign in South Texas.

PLANS FOR 2002

We are planning to drill a greater number of higher potential exploration
wells in 2002, including eight to ten Deep Shelf wells. Inclusive of the Deep
Shelf wells, we plan to drill at least 28 wells in the Gulf of Mexico. We expect
to drill about 80 wells onshore. Internationally, we plan to drill at least one
appraisal well in Bohai Bay, offshore China and at least two wells offshore
Australia -- one exploratory well and an appraisal well on a license area
farm-in.

GULF OF MEXICO. In addition to our traditional drilling activities on the
Shelf, we are active in two emerging plays -- the Offshore Texas Frio and the
Deep Shelf. Over the last three years, 200 - 400 Bcfe of reserves have been
discovered in water depths of less than 100 feet offshore Texas. Although the
industry has drilled more than 55,000 wells on the Shelf, less than 1,000 have
been drilled beneath 17,000 feet. These targets are higher risk but the reserve
impact can be significant. We also are working to enter select deepwater plays
in the Gulf of Mexico.

Offshore Texas Frio. We the entered the Offshore Texas Frio play through
an acquisition in 2001 and are actively exploring in the region. The geology is
similar to our onshore South Texas producing fields and our expertise in these
areas is applicable to our new efforts.

Deep Shelf. We also are exploring deeper horizons on the Shelf with recent
wells being drilled to more than 15,000 feet. Our first Deep Shelf success came
in early 2001 when we discovered the West Cameron 294 Field, which is now
producing. In early 2002, we drilled two additional Deep Shelf
discoveries -- West Delta 21 and Eugene Island 163. We are encouraged by our
early success in this play, however the risk profile of these wells is
significantly different than our traditional Shelf drilling. Deeper targets are
characterized by subtle amplitudes not easily detected with traditional seismic
processing. Drilling expense and the risk of mechanical failure are likely to be
significantly higher due to planned total depths and difficult drilling
conditions because of bottomhole temperatures and pressures. Although
infrastructure exists on the Shelf to facilitate the timely development of
discoveries, the fabrication and installation of new structures could require
additional time and expense prior to initial production.

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Deepwater. This play is a logical extension of our traditional efforts in
the Gulf of Mexico and will help balance the weighting of risk and reward in our
exploratory programs. In 2001, we developed a three phase strategy to enter this
play. Under Phase I, we will focus on finding projects near infrastructure in
water depths of less than 5,000 feet. As our knowledge and experience base
advances, Phases II and III of our strategy will gradually move us into deeper
waters, toward larger targets and into more remote regions where infrastructure
may not exist. At this time, we do not have any deepwater properties but we have
purchased both 2-D and 3-D seismic data to aid our exploration efforts. Our
efforts to enter the deepwater play could be expedited through an acquisition of
producing properties or an inventory of drilling prospects. We have made some
personnel additions to give us additional expertise in this new effort. In 2001,
we had one active deepwater team working the play and we have plans to add a
second team in 2002.

The risks associated with deepwater can be significantly greater than those
in the more traditional Shelf operations. Drilling and development costs may be
materially higher and lead times to first production may be much longer. For
more information on the risks associated with our deepwater plans, please see
"Other Factors Affecting Our Business and Financial Results" under Item 7 of
this report.

ONSHORE GULF COAST. Our production from this relatively new focus area has
grown rapidly over the last three years, reflecting both acquisitions and
drilling success. In 2002, our efforts will focus on exploration. We plan to
drill approximately 20 wells. We recently acquired new seismic data in Texas and
Louisiana and have new 3-D seismic acquisition programs planned in both states
in 2002. We also will continue to screen for attractive acquisitions to help us
expand this focus area.

MID-CONTINENT. We expect to drill approximately 60 wells in 2002,
predominantly in the Anadarko Basin. We believe that the Anadarko Basin provides
an opportunity for future growth. Like the Gulf of Mexico, it is a mature basin,
offering the potential to consolidate properties. We will continue to actively
screen acquisition opportunities.

INTERNATIONAL. During the first half of 2002, we expect to drill at least
one additional appraisal well in the CFD 12-1 South Field in Bohai Bay, offshore
China. Well results will help determine commerciality of the CFD 12-1 and 12-1
South Fields. In mid-2002, we plan to drill an appraisal well on an existing
discovery known as Montara on the AC/RL 3 license area offshore Australia. We
also have one additional exploration commitment well offshore Australia, which
we expect to drill in late 2002. We will continue to evaluate and pursue
opportunities for international expansion in Australia and surrounding regions,
China, South America and the United Kingdom's Southern Gas Basin of the North
Sea.

MARKETING

We market nearly all of the crude oil, hydrocarbon condensate and natural
gas production from properties we operate for both our account and the account
of the other working interest owners in these properties. Substantially all of
our natural gas production is sold to a variety of purchasers under short-term
(less than 12 months) contracts or 30-day spot gas purchase contracts. Oil sales
contracts are short-term and are based upon posted prices plus negotiated
bonuses. For a list of purchasers of our oil and gas production that accounted
for 10% or more of consolidated revenue for the three preceding calendar years,
please see "Major Customers" in Note 1 to our consolidated financial statements.
Because alternative purchasers of oil and gas are readily available, we believe
that the loss of any of these purchasers would not have a material adverse
effect on us.

COMPETITION

Competition in the oil and gas industry is intense, particularly with
respect to the acquisition of producing properties and proved undeveloped
acreage. For a further discussion of this competitive environment, please see
the information set forth under the caption "Other Factors Affecting Our
Business and Financial Results" in Item 7 of this report.

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EMPLOYEES

At February 28, 2002, we had 410 employees. We believe that our
relationships with our employees are satisfactory.

None of our 273 U.S. employees are covered by a collective bargaining
agreement. From time to time, we utilize the services of independent consultants
and contractors to perform various professional services, particularly in the
areas of construction, design, well site surveillance, permitting and
environmental assessment. U.S. offshore field and on-site production operation
services, such as pumping, maintenance, dispatching, inspection and testing, are
generally provided by independent contractors.

We have 137 employees located in Australia. Our Perth, Australia office
employs 31 people to manage our offshore operations. The remaining employees
work offshore on our FPSOs. These employees are covered by collective bargaining
agreements. At February 28, 2002, there were no significant issues outstanding
under those agreements.

REGULATION AND OTHER FACTORS AFFECTING OUR BUSINESS AND FINANCIAL RESULTS

For a discussion of the significant governmental regulations to which our
business is subject and other significant factors that may affect our business,
please see the information set forth under the captions "Regulation" and "Other
Factors Affecting Our Business and Financial Results" in Item 7 of this report.

ITEM 2. PROPERTIES

CONCENTRATION

The majority of our proved reserves (58%) are located in the Gulf of
Mexico. In total, 70% of our proved reserves are located in the Gulf of Mexico
and coastal regions. While our 10 largest properties accounted for approximately
36% of our equivalent proved reserves at year-end 2001, no single property held
more than 6% of our proved reserves or more than 7% of the net present value of
our proved reserves.

GULF OF MEXICO

Our properties are in water depths ranging from 45 to more than 800 feet.
As of December 31, 2001, we owned interests in 171 leases (750,000 gross acres)
and operated 142 platforms. During 2001, we drilled or participated in 35 wells
in the Gulf of Mexico, 27 of which were successful. We also completed nine major
development projects associated with discoveries made during 2000.

U.S. ONSHORE GULF COAST

We currently own an interest in approximately 65,000 gross acres in the
U.S. onshore regions of South Texas and southern Louisiana and expect to
continue expanding our operations in these areas. During 2001, we drilled or
participated in 18 wells onshore Gulf Coast, of which 15 were successful. Our
net production from the Gulf Coast region was approximately 80 MMcfe/d as of
February 26, 2002, including about 12 MMcfe/d that was voluntarily curtailed in
response to low gas prices.

ANADARKO BASIN

We have a significant presence in the Mid-Continent. This focus area was
established with a first quarter 2001 acquisition. We operate 75% of our proved
reserves. At year-end 2001, our production in the Mid-Continent was
approximately 68 MMcfe/d, 80% of which was natural gas. As of December 31, 2001,
we owned an interest in 1,497 wells, 493 of which are company-operated. Our
acreage position is also significant. We have an interest in 440,000 gross lease
acres (230,000 net) and 70,000 gross mineral acres (18,000 net).

INTERNATIONAL

AUSTRALIA. We own a 50% interest in two producing oil fields offshore
Australia and two related floating production, storage and off-loading vessels
(commonly referred to as FPSOs). In addition, we have

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exploration permits on about 2.4 million gross acres. Through relinquishments in
2001, our acreage position has been reduced from the original amount of about
2.5 million gross acres. With planned relinquishments, we expect our gross
acreage position will be about 433,000 acres by mid-2002. Our production during
2001 averaged 4,043 BOPD. Although these fields are on a natural decline, they
have benefited from our gas lift optimization program. This program helped
increase both production and ultimate oil recovery from the Jabiru and Challis
Fields and we recorded a positive reserve revision of about 1.5 MMBbls during
the year. Our drilling results to date in Australia have been disappointing.
During 2001, we participated in five dry holes (one company-operated). All of
these were high risk, high potential wildcat wells. We have one additional
exploration commitment well that we expect to drill in late 2002. In 2001, we
became operator of the AC/RL 3 license area where we plan to drill an appraisal
well in mid-2002 on the Montara oil discovery. If successful, we plan to develop
oil reserves associated with this project. We have a 50% interest in the
venture.

CHINA. We own a 35% interest in Block 05/36 in Bohai Bay, offshore China.
Our interest is subject to a 51% back in by the Chinese National Offshore Oil
Company. The block covers more than 300,000 acres. There currently is no
production on the block. We discovered the CFD 12-1 Field in 2000. Since that
time, we have been appraising the field to determine if commercial oil reserves
exist. In 2001, we drilled two wells to the south of our CFD 12-1 Field in a new
field discovery called CFD 12-1 South. We continued to appraise our CFD 12-1
Field, drilling two appraisal wells that found hydrocarbons and one dry hole. In
the first half of 2002, we expect to drill at least one additional appraisal
well in the CFD 12-1 South Field. Well results will help determine commerciality
of the CFD 12-1 and 12-1 South Fields. We have not booked any proved reserves on
these fields to date.

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PROVED RESERVES AND FUTURE NET CASH FLOWS

The following table shows our estimated net proved oil and gas reserves,
the standardized measure of future after-tax net cash flows before 10% annual
discount and the present value of estimated future after-tax net cash flows
related to such reserves as of December 31, 2001. The present value of estimated
future pre-tax and after-tax net cash flows was prepared using year-end oil and
gas prices, discounted at 10% per year.

There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting future rates of production and
timing of development expenditures. For a discussion of these uncertainties, see
"Other Factors Affecting Our Business and Financial Results" and "Forward
Looking Statements" under Item 7 of this report.

As an operator of domestic oil and gas properties, we have filed Department
of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by
Public Law 93-275. There are differences between the reserves as reported on
Form EIA-23 and as reported above. The differences are attributable to the fact
that Form EIA-23 requires that an operator report on the total reserves
attributable to wells that are operated by it, without regard to ownership
(i.e., reserves are reported on a gross operated basis, rather than on a net
interest basis).

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FINDING COSTS

The following table sets forth certain information regarding the costs
associated with finding, acquiring and developing our proved oil and gas
reserves.

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(1) Capitalized costs represent our capitalized expenditures as shown in the
immediately following table except that acquisition and exploration costs
relating to foreign locations other than Australia and interest capitalized
are not included.

(2) The cost to find and develop per Mcfe for 2001 and the five-year period
ended December 31, 2001 would have been $2.02 and $1.67, respectively, if we
had included all capitalized expenditures as shown in the immediately
following table.

DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES

The following table sets forth certain information regarding the
capitalized costs we incurred in the purchase of proved and unproved properties
and in our development and exploration activities.

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(1) Proved acquisition costs in 2001 do not include a $105,081 purchase price
step-up for accounting purposes resulting from deferred federal income tax
associated with the Lariat acquisition.

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DRILLING ACTIVITY

The following table sets forth our drilling activity for each year of the
three-years in the period ended December 31, 2001.(1)

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(1) We were in the process of drilling four gross (2.4 net) exploratory wells
and one gross (one net) developmental well in the U.S. at December 31, 2001.

(2) We drilled four gross (1.6 net) and two gross (0.8 net) appraisal wells in
China during 2001 and 2000, respectively. Because the commerciality of these
wells had not been determined as of December 31, 2001, they are not included
in the table.

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PRODUCTIVE WELLS

The following table sets forth the number of productive oil and gas wells
in which we owned an interest as of December 31, 2001 and the location of, and
other information with respect to, those wells. "Gross wells" refers to the
total number of wells in which we own an interest and "net wells" refers to the
sum of the fractional working interests we own in the gross wells.

The day-to-day operations of oil and gas properties are the responsibility
of an operator designated under pooling or operating agreements. The operator
supervises production, maintains production records, employs or contracts for
field personnel and performs other functions. The charges under operating
agreements customarily vary with the depth and location of the well being
operated. An operator receives reimbursement for direct expenses incurred in the
performance of its duties as well as monthly per-well producing and drilling
overhead reimbursement at rates customarily charged in the area by unaffiliated
third parties.

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ACREAGE DATA

The Company owns interests in developed and undeveloped oil and gas acreage
in various parts of the world. These ownership interests generally take the form
of "working interests" in oil and gas leases that have varying terms. The
following table shows certain information regarding our developed and
undeveloped lease acreage as of December 31, 2001.

Leases covering approximately 1,818,910 (688,270 net), 44,822 (36,505 net),
284,586 (127,685 net), 377,726 (154,642 net) and 261,867 (148,430 net)
undeveloped acres are scheduled to expire in 2002, 2003, 2004, 2005 and 2006,
respectively.

TITLE TO PROPERTIES

We believe that we have satisfactory title to all of our producing
properties in accordance with generally accepted industry standards. As is
customary in the industry in the case of undeveloped properties, little
investigation of record title may made at the time of acquisition.
Investigations are made prior to the consummation of an acquisition of producing
properties and before commencement of drilling operations on undeveloped
properties. Individual properties may be subject to burdens that we believe do
not materially interfere with the use of or affect the value of such properties.
Burdens on properties may include:

- customary royalty interests;

- liens incident to operating agreements and for current taxes;

- obligations or duties under applicable laws,

- development obligations under oil and gas leases; and

- burdens such as net profits interests.

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ITEM 3. LEGAL PROCEEDINGS

We are not aware of any material pending legal proceedings with respect to
our company.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the
fourth quarter of 2001.

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth the names and ages (as of March 1, 2002) of
and positions held by our executive officers. Our executive officers serve at
the discretion of the Board of Directors.

Each of the executive officers has held the above positions for the past
five years, with the exception of the following:

DAVID A. TRICE was one of our founders. From 1991 to 1997 he served as
President and Chief Executive Officer and a Director of Huffco Group, Inc. He
rejoined Newfield in May 1997 as Vice President -- Finance and International. He
was appointed President and Chief Operating Officer in May 1999 and to his
present position on February 1, 2000. He has served as a director since February
2000.

ELLIOTT PEW has served as Vice President -- Exploration since January 1998.
Prior to joining us, he served as Senior Vice President of Louis Dreyfus Natural
Gas Company's Gulf Coast Region and, prior to Louis Dreyfus' merger with
American Exploration Company in October 1997, as Senior Vice President of
Exploration for American Exploration Company from March 1997 to the date of such
merger.

WILLIAM D. SCHNEIDER, one of our founders, has served us as a Vice
President since January 1998. From 1992 to January 1998 he served as
Manager-Exploration.

BRIAN L. RICKMERS has served as Controller and Assistant Secretary since
May 2001. From February 2000 to May 2001 he served as Assistant Controller. Mr.
Rickmers joined Newfield in December 1993.

SUSAN G. RIGGS was named to her present position in August 1999. From May
1997 to August 1999, she served us as a Financial Analyst. Mrs. Riggs was
Treasurer/Controller of Huffco Group, Inc. from 1995 to May 1997.

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Our common stock is listed on the New York Stock Exchange under the symbol
"NFX." The following table sets forth, for the periods indicated, the range of
the high and low sales prices of our common stock as reported by the New York
Stock Exchange.

On March 11, 2002 the last reported sale price of our common stock on the
New York Stock Exchange Composite Tape was $36.35 per share.

As of March 5, 2002 there were approximately 300 holders of record of our
common stock.

We have not paid any cash dividends in the past on our common stock and do
not intend to pay cash dividends in the foreseeable future. We intend to retain
earnings for the future operation and development of our business. Any future
cash dividends to holders of common stock would depend on future earnings,
capital requirements, our financial condition and other factors determined by
our Board of Directors. The covenants contained in our credit facility could
restrict our ability to pay cash dividends.

On January 21, 2001, we issued 1,951,530 shares of our common stock in
transactions not involving any public offering that were exempt from the
provisions of Section 5 of the Securities Act pursuant to Section 4(2) of such
act. All of these shares were issued in connection with our acquisition of
Lariat Petroleum. As part of the consideration in the acquisition, we issued
1,906,530 shares of our common stock to the stockholders of Lariat. These
stockholders consisted of a private equity fund (1,864,735 shares) the
President, Chief Executive Officer and Chairman of the Board of Lariat (26,158
shares) and seven other individuals who were executive officers or directors of
or investors in Lariat (15,637 shares). In addition, in connection with
acquisition and in consideration of their continued employment, three executive
officers of Lariat were granted a total of 45,000 restricted shares of our
common stock pursuant to our 2000 Omnibus Stock Plan.

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ITEM 6. SELECTED FINANCIAL DATA

SELECTED FIVE-YEAR FINANCIAL AND RESERVE DATA

The following table shows selected consolidated financial data derived from
our consolidated financial statements and reserve data derived from our
supplementary oil and gas disclosures set forth in Item 8 of this report. The
data should be read in conjunction with the information under the caption
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in Item 7 of this report.

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

(1) General and administrative expense includes non-cash stock compensation
charges of $2,751; $3,047; $1,999; $2,222 and $1,177 for 2001, 2000, 1999,
1998 and 1997, respectively. See Note 10 to our consolidated financial
statements.

(2) We adopted SEC Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition
in Financial Statements," effective January 1, 2000. The adoption of SAB No.
101 requires us to report crude oil inventory associated with our Australian
offshore operations at lower of cost or market, which was a change from our
historical policy of recording such inventory at market value on the balance
sheet date, net of estimated costs to sell. The cumulative effect of the
change from the acquisition date of our Australian operations in July 1999
through December 31, 1999 is a reduction in net income of $2.36 million, or
$0.05 per diluted share, and is shown as the cumulative effect of change in
accounting principle on the consolidated statement of income for the year
ended December 31, 2000. The pro forma effect had SAB No. 101 been applied
retroactively to 1999 would have reduced net income by $2.36 million, or
$0.06 per diluted share. SAB No. 101 would not have effected periods prior
to the acquisition of our Australian operations in July 1999.

(3) We adopted Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities" on January 1,
2001. SFAS No. 133 requires us to record all derivative instruments as
either assets or liabilities on the balance sheet and measure those
instruments at fair value. For all periods prior to January 1, 2001, we
accounted for commodity price hedging instruments in accordance with SFAS
No. 80. The cumulative effective of the adoption is a reduction in net
income of $4.8 million, or $0.10 per diluted share, and is shown as the
cumulative effect of change in accounting principle on the consolidated
statement of income for the year ended December 31, 2001.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

Our revenues, profitability and future growth depend substantially on
prevailing prices for oil and gas. Prices for oil and gas fluctuate widely. Oil
and gas prices affect:

- the amount of cash flow available for capital expenditures;

- our ability to borrow and raise additional capital;

- the amount of oil and gas that we can economically produce; and

- the accounting for our oil and gas activities.

We use hedging transactions with respect to a portion of our oil and gas
production to achieve more predictable cash flow and to reduce our exposure to
price fluctuations.

Our future success depends on our ability to find, develop and acquire oil
and gas reserves that are economically recoverable. As is generally the case,
our producing properties in the Gulf of Mexico and the onshore Gulf Coast often
have high initial production rates, followed by steep declines. As a result, we
must

15

locate and develop or acquire new oil and gas reserves to replace those being
depleted by production. Substantial capital expenditures are required to find,
develop, acquire and produce oil and gas reserves. We believe that our working
capital and cash flow from operations will be sufficient to fund planned capital
expenditures in 2002.

Accounting for oil and gas activities is subject to special rules that are
unique to the oil and gas business. These rules require us to make several
difficult, subjective or complex judgments or estimates. These judgments or
estimates primarily relate to the capitalization and amortization of costs and
the valuation of oil and gas price hedging activities. Our judgments and
estimates have a significant effect on our reported results of operations and
financial condition.

CRITICAL ACCOUNTING POLICIES

We believe that the policies described below are critical to the reporting
of our financial position and operating results, and require management's most
difficult, subjective or complex judgments. Our most significant estimates are:

- remaining proved oil and gas reserves;

- timing of our future drilling activities;

- future costs to develop and abandon our oil and gas properties; and

- the value of derivative positions.

For additional risks associated with these items see "Other Factors Affecting
Our Business and Financial Results" in this Item 7.

ACCOUNTING FOR OIL AND GAS ACTIVITIES. Accounting for oil and gas
activities is subject to special rules that are unique to the oil and gas
business. Two generally accepted methods for accounting for oil and gas
activities are available -- successful efforts and full cost. The most
significant differences between these two methods are the treatment of
exploration costs and the manner in which the carrying value of oil and gas
properties are amortized and evaluated for impairment. The successful efforts
method requires exploration costs to be expensed as they are incurred while the
full cost method provides for the capitalization of such costs. Both methods
generally provide for the periodic amortization of capitalized costs based on
proved reserves. Impairment of oil and gas properties under the successful
efforts method provides for a comparison of the carrying value of individual oil
and gas properties against their estimated fair value, while impairment under
the full cost method requires a comparison of the carrying value of oil and gas
properties included in a cost center against the net present value of future
cash flows of related proved reserves, using period end prices and costs and a
10% discount rate.

Full Cost Method. We use the full cost method of accounting for our oil
and gas activities. Under this method, all costs incurred in the acquisition,
exploration and development of oil and gas properties are capitalized into cost
centers that are established on a country-by-country basis. Such amounts include
the cost of drilling and equipping productive wells, dry hole costs, lease
acquisition costs and delay rentals. Capitalized costs also include salaries,
employee benefits, costs of consulting services and other expenses that are
directly related to exploration activities. Interest costs related to unproved
properties and properties under development also are capitalized. Costs
associated with production and general corporate activities are expensed in the
period incurred.

Depreciation, Depletion and Amortization. The capitalized costs of our oil
and gas properties, plus an estimate of our future development and abandonment
costs, are amortized on a unit-of-production method based on our estimate of
total proved reserves. The quantities of estimated proved oil and gas reserves
is a significant component of amortization and revisions in such estimates may
alter the rate of future expense. Generally, if reserve volumes increase or
decrease, then the amortization rate per unit of production will change
inversely. However, when capitalized costs change, the amortization rate moves
in the same direction. The per unit rate is not affected by production volumes.
Amortization is calculated separately on a country-by-country basis.

16

Future Development and Abandonment Costs. Future development costs include
costs incurred to obtain access to proved reserves, including drilling costs and
the installation of production equipment. Future abandonment costs include costs
to dismantle and relocate or dispose of our offshore production platforms,
FPSOs, gathering systems, wells and related structures and restoration costs of
land and seabed. We develop estimates of these costs for each of our properties
based upon the type of production structure, depth of water, reservoir
characteristics, depth of the reservoir, market demand for equipment, currently
available procedures and consultations with construction and engineering
consultants. Because these costs typically occur many years in the future,
estimating these future costs is difficult and requires management to make
estimates and judgments that are subject to future revisions based upon numerous
factors, including changing technology and the political and regulatory
environment.

Full Cost Ceiling Limitation. Under the full cost method, we are subject
to quarterly calculations of a "ceiling" or limitation on the amount of our oil
and gas properties that can be capitalized on our balance sheet. If the net
capitalized costs of our oil and gas properties exceed the cost center ceiling,
we are subject to a ceiling test writedown to the extent of such excess. A
ceiling test writedown is a non-cash charge to earnings. If required, it would
reduce earnings and impact stockholders' equity in the period of occurrence and
result in lower amortization expense in future periods. The ceiling limitation
is applied separately for each country in which we have oil and gas properties.
The discounted present value of our proved reserves is a major component of the
ceiling calculation and requires the most subjective judgments. Given the
volatility of natural gas and oil prices, it is reasonably possible that our
estimate of discounted future net cash flows from proved reserves will change in
the near term. If natural gas and oil prices decline, even if for only a short
period of time, or if we have downward revisions to our estimated proved
reserves, it is possible that writedowns of our oil and gas properties could
occur in the future.

While the quantities of proved reserves require substantial judgment, the
associated prices of oil and natural gas reserves that are included in the
discounted present value of the reserves do not require judgment. The future net
revenues associated with our estimated proved reserves are not based on our
assessment of future prices or costs. The ceiling calculation dictates that
prices and costs in effect as of the last day of the quarter are held constant.
However, we may not be subject to a writedown if prices increase subsequent to
the end of a quarter in which a writedown might otherwise be required. With the
concurrence of the Securities and Exchange Commission, our impairment
calculation uses a hedge adjusted price (net realized price after considering
cash flow hedges) applied to the quantity of proved reserves covered by our
hedges.

Unevaluated Costs. Unevaluated costs are excluded from our amortization
base until we have evaluated the properties associated with these costs. The
costs associated with unevaluated leasehold acreage, unamortized seismic data,
wells currently drilling and capitalized interest are not initially included in
our amortization base. Leasehold and seismic costs are either transferred to our
amortization base with the costs of drilling the related well or are assessed
quarterly for possible impairment or reduction in value. Leasehold costs are
transferred to our amortization base if a reduction in value has occurred. The
decision to withhold costs from amortization and the timing of transferring such
costs into the amortization base involves a significant amount of management
judgment and may be subject to changes over time based on several factors,
including our drilling plans, availability of capital, project economics and
results of drilling on adjacent acreage.

FAIR VALUE OF DERIVATIVE INSTRUMENTS. Beginning in 2001, the estimated
fair values of our derivative instruments are recorded on our consolidated
balance sheet. All of our derivative instruments represent hedges against the
price we will receive for our future oil and natural gas production. We do not
use derivative instruments for trading purposes. Although our derivatives are
reported on the balance sheet at fair value, to the extent that changes in those
fair values offset changes in the expected cash flows from our forecasted
production, such amounts are not included in our consolidated results of
operations. Instead, they are recorded directly to stockholders' equity until
the hedged oil or natural gas quantities are produced. To the extent the change
in the fair value of the derivative exceeds the change in the expected cash
flows from the forecasted production, the change is recorded in income in the
period it occurs. We also record the periodic change in the time value component
of the option contracts used in our hedging strategy in income in the period the
change occurs.

17

In determining the amounts to be recorded, we are required to estimate the
fair values of both the derivative and the associated hedged production at its
physical location. Where necessary, we adjust NYMEX prices to other regional
delivery points using our own estimates of future regional prices. Our estimates
are based upon various factors that include closing prices on the NYMEX,
over-the-counter quotations, volatility and the time value of options. The
calculation of the fair value of our option contracts requires the use of the
Black-Scholes option pricing model. The estimated future prices are compared to
the prices fixed by the hedge agreements and the resulting estimated future cash
inflows or outflows over the lives of the hedges are discounted to calculate the
fair value of the derivative contracts. These pricing and discounting variables
are sensitive to market volatility as well as changes in future price forecasts,
regional price differences and interest rates. We periodically validate our
valuations using independent third parties quotations.

WRITEDOWN OF OIL AND GAS PROPERTIES

Based on oil and gas prices in effect on December 31, 2001 ($2.65 per MMBtu
for gas and $19.84 per barrel for oil), the unamortized cost of our domestic oil
and gas properties exceeded the cost center ceiling. In accordance with full
cost accounting rules, we recorded a domestic ceiling test writedown at December
31, 2001 of $106 million ($68 million after-tax). With the concurrence of the
Securities and Exchange Commission, the impairment was calculated using a hedge
adjusted price. The writedown would have been $184 million ($118 million
after-tax) if we had not used hedge adjusted prices. Because of the volatility
of oil and gas prices, no assurance can be given that we will not experience a
ceiling test writedown in future periods.

RESULTS OF OPERATIONS

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

(1) Excludes Australian volumes produced but not sold.

(2) For purposes of this table, average realized prices for natural gas and oil
and condensate are presented net of all applicable transportation expenses,
which reduced the realized price of natural gas by $0.03, $0.04 and $0.05
for the years ended 2001, 2000 and 1999, respectively. The realized price of
oil and condensate is reduced by $0.24, $0.27 and $0.32 for the years ended
2001, 2000 and 1999, respectively. Average realized prices include the
effect of hedges.

18

PRODUCTION. Our total oil and gas production (stated on a natural gas
equivalent basis) increased 25% in 2001 and 23.3% in 2000. Gas production in
2001 was impacted by our decision to voluntarily curtail approximately five Bcfe
in the fourth quarter of 2001 in response to low commodity prices. Without the
curtailment, our production would have increased 29% over 2000 levels.

Natural Gas. Our 2001 natural gas production increased 26% over 2000. The
significant increase was attributable to a balance between acquisitions and
drilling. About half of the production increase in 2001 came from the
Mid-Continent acquisition, which closed in January 2001. Our development
drilling program in South Texas was also a major contributor to our production
growth. Following the drilling of six development wells in the East Sarita Field
of South Texas, net production increased from about 25 MMcfe/d to a peak of
nearly 80 MMcfe/d in the third quarter of 2001. Our onshore Gulf Coast
production averaged about 81 MMcfe/d in 2001, a 25% increase over the 65 MMcfe/d
we averaged in 2000. The following Gulf of Mexico development projects were also
major contributors: West Cameron 294, West Cameron 240 A and High Island A-521.
Gains in production were partially offset by natural declines from other
producing properties. In 2000, our natural gas volumes increased 21% over 1999.
Our acquisition of three producing gas fields in South Texas in early 2000 added
about nine Bcfe of production. Development projects in the Gulf of Mexico at
Eugene Island 198/199/202, West Cameron 522 and Main Pass 264 also contributed
to the production increase.

Crude Oil and Condensate. Our crude oil production in 2001 increased 21%
over 2000 levels. The increase in 2001 oil production primarily relates to our
early 2001 acquisition in the Mid-Continent and the success of our drilling
efforts. During 2001, our oil production in Australia averaged 4,043 BOPD and
accounted for about 21% of our total oil production. Major development projects
in the Gulf of Mexico that increased our 2001 oil production were Viosca Knoll
738/739, Eugene Island 182 and Main Pass 138. The increase in 2000 oil
production primarily relates to the full-year affect of our acquisition of two
producing oil fields in Australia and development projects in the Gulf of
Mexico. During 2000, our Australian oil production averaged about 4,573 BOPD and
accounted for 29% of our total oil production. Major development projects in the
Gulf of Mexico that contributed to our increased oil production in 2000 were
Vermilion 215, Eugene Island 198/199/202, High Island 474 and Main Pass 138 and
264. Our crude oil and condensate production in 2000 was 32% more than our crude
oil production in 1999.

EFFECT OF HEDGING ON REALIZED PRICES. The following table presents
information about the effect of our hedging program on realized prices.

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

(1) The ratio is determined by dividing the realized price (which includes the
effects of hedging) by the price that otherwise would have been realized
without hedging activities.

NET INCOME AND REVENUES. For 2001, we had net income of $119.0 million, or
$2.56 per diluted share. These results include an impairment charge of $106
million, or $1.39 per diluted share, and a loss of $4.8 million, or $0.10 per
diluted share, reflecting the cumulative effect of change in accounting
principle related to hedging transactions (FAS 133). This compares to 2000 net
income of $132.3 million (which includes a charge for the cumulative effect of a
change in accounting principle of $2.4 million, or $0.05 per diluted share), or
$2.93 per diluted share, and 1999 net income of $33.2 million, or $0.79 cents
per diluted

19

share. Revenues for 2001 were $749.4 million, 42% above 2000 revenues of $526.6
million. Revenues in 1999 were $287.9 million. The increase in revenues in 2001
was primarily due to a 25% increase in production volumes and higher realized
natural gas prices.

OPERATING EXPENSES. The following table presents information about our
operating expenses for the two years ended December 31, 2001.

Our operating expenses for 2001, exclusive of the ceiling test writedown,
on a unit of production basis increased 19% over 2000 as the result of higher
lease operating, production tax, DD&A and G&A expense. The reasons for these
increases are described below.

- The increased lease operating expense per Mcfe reflects higher oilfield
service costs in all our domestic focus areas, and relatively higher
Australian lease operating expenses associated with the operations and
maintenance of our two FPSOs.

- The increase in production and other taxes is primarily related to higher
natural gas prices, our expanding onshore Gulf Coast operations and the
acquisition of Mid-Continent properties in early 2001. The increase was
partly offset by resource rent tax in Australia, which was 33% lower in
2001 compared to 2000 due to unsuccessful drilling efforts.

- The increase in the domestic DD&A rate is primarily related to lower than
expected reserve additions from several of our recently completed wells,
increases in the cost of drilling goods and services and platforms and
facilities construction and the completion of several higher cost wells.
The increase in the Australian DD&A rate is primarily a result of our
unsuccessful drilling activities in 2000.

20

- The increase on a unit of production basis in G&A expense primarily is
due to our growing workforce. Performance-based compensation, excluding
stock compensation expense, was negatively impacted by the fourth quarter
2001 ceiling test write-down. Performance-based compensation, a component
of general and administrative expense, was $11.6 million, or $0.07 per
Mcfe, in 2001 compared to $12.8 million, or $0.09 per Mcfe, in 2000.

The following table presents information about our operating expenses for
the two years ended December 31, 2000.

Our operating expenses for 2000 on a unit of production basis increased 11%
over 1999 as the result of higher lease operating, production tax and G&A
expense. The reasons for these increases are described below.

- Higher lease operating expense per Mcfe reflects increased oilfield
service costs in the Gulf of Mexico, relatively higher Australian lease
operating expenses associated with the operation and maintenance of our
two FPSOs and production downtime due to in-fill drilling operations
during the year in Australia.

- We experienced higher production and other taxes on a unit of production
basis due to increased production onshore, including the acquisition of
three producing gas fields in South Texas during early 2000. Australian
production and other taxes increased primarily due to higher commodity
prices.

- The increase in our domestic DD&A rate is due to several factors,
including increases in the cost of drilling goods and services, platforms
and facilities construction, industry transportation costs and the
completion of several higher cost wells. The Australian DD&A rate
increased as a result of our unsuccessful drilling activities in 2000.

21

- The increase in G&A expense on a per Mcfe basis is primarily the result
of an increase in performance-based pay, some non-recurring expenses
associated with a transition to more sophisticated business systems and
our growing workforce. Performance-based compensation, excluding stock
compensation expense, a component of general and administrative expense,
increased from $3.9 million in 1999, or $0.03 per Mcfe, to $12.8 million
in 2000, or $0.09 per Mcfe. The increase in performance-based
compensation is a result of our higher earnings. Performance-based pay is
limited by profitability.

INTEREST EXPENSE. We incur interest expense on our $125 million principal
amount 7.45% Senior Notes due 2007, our $175 million principal amount 7 5/8%
Senior Notes due 2011 and on borrowings under our reserve-based revolving credit
facility and money market credit lines. Outstanding borrowings under our credit
arrangements may vary significantly from period to period. Distributions are
paid on our 6.5% convertible trust preferred securities we issued in August
1999.

In 2001, our higher total interest expense was the result of borrowings
related to the Lariat acquisition and the issuance of our 7 5/8% Senior Notes in
February 2001. In 2000, our higher total interest expense was the result of
borrowings in January 2000 to finance our acquisition of three producing
properties in South Texas for $139 million.

UNREALIZED COMMODITY DERIVATIVE INCOME. As a result of our adoption of
SFAS No. 133 effective January 1, 2001, we are now required to record all
derivative instruments on the balance sheet at fair value. The $24.8 million of
unrealized income for the year ended December 31, 2001 primarily represents the
change in the time value component of the option contracts used in our hedging
strategy.

TAXES. The effective tax rate for the years ended December 31, 2001, 2000
and 1999 was 35%, 34% and 36%, respectively. The effective tax rate was less
than the statutory tax rate in 2000 because the valuation allowance on our
Australian net operating loss carryforwards was reduced by $2.3 million
primarily as a result of a substantial increase in estimated taxable income.
Estimates of future taxable income can be significantly affected by changes in
oil and natural gas prices, estimates of the timing and amount of future
production and estimates of future operating and capital costs.

LIQUIDITY AND CAPITAL RESOURCES

WORKING CAPITAL. Our working capital balance is not a good indicator of
our liquidity because it fluctuates as a result of the timing and amount of
borrowings or repayments under our credit arrangements. We had working capital
of $65.6 million as of December 31, 2001. This compares to $38.5 million at the
end of 2000 and $35.2 million at the end of 1999. Historically, we have funded
our oil and gas activities through cash flow from operations, equity capital,
public debt and bank borrowings.

DEBT. In association with our acquisition of Lariat Petroleum in early
2001, we borrowed $265 million through our reserve-based revolving credit
facility. At year-end 2001, we had $120 million outstanding under the credit
facility and an additional $9 million outstanding under our money market lines
of credit. At year-end 2001, our long-term debt was $428.6 million, which
includes our 7.45% Senior Notes due 2007 of $125 million and our 7 5/8% Senior
Notes due 2011 of $175 million.

On January 23, 2001, we acquired Lariat Petroleum for total consideration
of approximately $333 million, inclusive of the assumption of debt and certain
other obligations of Lariat. The consideration included

22

1.9 million shares of our common stock. We financed the cash portion of the
consideration under a new $425 million reserve-based revolving credit facility
obtained on January 23, 2001 with The Chase Manhattan Bank, as agent.

On February 22, 2001, we placed $175 million of 7 5/8% Senior Notes due
2011. The offering was done under an existing shelf registration statement. Net
proceeds from the sale of the notes were used to repay outstanding indebtedness
under our revolving credit facility. The notes were issued at 99.931% of par to
yield 7.635%, with interest payable on each March 1 and September 1, commencing
September 1, 2001.

The amount available under our credit facility is subject to a calculated
borrowing base determined by banks holding 75% of the aggregate commitments. The
borrowing base is reduced by the aggregate outstanding principal amount of our
senior notes ($300 million). The borrowing base is currently $510 million and is
redetermined at least semi-annually. No assurances can be given that the banks
will not elect to redetermine the borrowing base in the future. The facility
contains restrictions on the payment of dividends and the incurrence of debt as
well as other customary covenants and restrictions. The facility matures on
January 23, 2004. At February 28, 2002 we had $102 million available under our
credit facility and had outstanding borrowings of $108 million.

We also have money market lines of credit with various banks in an amount
limited by the credit facility to $40 million. As of February 28, 2002, there
were no borrowings outstanding under these lines of credit.

Our credit arrangements are not subject to any debt rating or similar
triggers or conditions. However, applicable commitment fees and interest rates
under our credit facility vary based on our credit rating.

CASH FLOW FROM OPERATIONS. Our net cash flow from operations in 2001
increased 59% over 2000 to $502.4 million. The increase is due to significantly
higher commodity prices and increased production, partially offset by higher
operating expenses. This compares to cash flow from operations in 2000 of $316.4
million. Net cash flow from operations before changes in operating assets and
liabilities for 2001 was $526.8 million compared to $383.5 million in 2000. The
increase is primarily attributable to higher commodity prices and increased
production, offset by increased operating expenses.

CAPITAL EXPENDITURES. In 2001, our capital spending totaled $855 million,
including $435 million in acquisitions. The largest component of acquisition
spending was our first quarter acquisition of Lariat Petroleum. In 2001, we
invested $302 million in development, $97 million in domestic exploration and
$21 million internationally. Total spending in 2000 was $379 million. Our 2000
capital spending program included $139 million for acquisitions, $129 million
for development, $91 million for domestic exploration and $20 million for
international activities.

We have budgeted $360 million for capital spending in 2002. The lower
budget reflects our anticipation of lower cash flows due to weak commodity
prices in early 2002. Approximately $200 million has been budgeted for
development, $135 million for domestic exploration and $25 million for
international projects. The 2002 estimated exploratory budget is the largest
exploration budget in our history. Acquisitions are opportunistic and are not
budgeted under our capital program. We continue to pursue attractive acquisition
opportunities; however, the timing, size and purchase price of acquisitions are
unpredictable. We anticipate that our capital expenditure budget for 2002 will
be funded principally from cash flow from operations and working capital. We do
not anticipate additional borrowings under our credit facility or money market
lines of credit during 2002 unless we make another significant acquisition.
Actual levels of capital expenditures may vary significantly due to many
factors, including drilling results, oil and gas prices, industry conditions,
the prices and availability of goods and services and the extent to which proved
properties are acquired.

23

CONTRACTUAL OBLIGATIONS AND OTHER COMMITMENTS

The table below summarizes our significant contractual obligations and
commitments, other than hedging contracts, by maturity as of December 31, 2001.

STOCK REPURCHASE PROGRAM

On May 4, 2001, we announced that our Board of Directors authorized the
expenditure of up to $50 million to repurchase shares of our common stock.
Through December 31, 2001, we had purchased 823,000 shares for total
consideration of $24.7 million, an average of $29.97 per share. Additional
repurchases may be effected from time to time in accordance with applicable
securities laws through solicited or unsolicited transactions in the market or
in privately negotiated transactions. No limit was placed on the duration of the
repurchase program. Subject to applicable securities laws, purchases will be at
times and in amounts as we deem appropriate. As of February 28, 2002, no shares
had been purchased during the first quarter of 2002.

HEDGING

We enter into various commodity price hedging contracts with respect to a
portion of our anticipated future natural gas and crude oil production. During
2000, approximately 45% of our production was subject to hedge positions.
Approximately 68% of our production in 2001 was subject to hedge positions.
While the use of these hedging arrangements limits the downside risk of adverse
price movements, they may also limit future revenues from favorable price
movements. The use of hedging transactions also involves the risk that the
counter parties will be unable to meet the financial terms of such transactions.
At December 31, 2001, Bank of Montreal, J Aron & Company and Barclays Bank PLC
were the counterparties with respect to 77% of our future hedged production.
Such contracts are accounted for as derivatives in accordance with SFAS No. 133.
Please see the discussion in Note 3 -- "Commodity Derivative Instruments and
Hedging Activities" to our consolidated financial statements appearing in this
report.

24

NATURAL GAS. At December 31, 2001, we had outstanding the commodity price
hedging contracts set forth in the table below with respect to our U.S. Gulf
Coast natural gas production.

In connection with our acquisition of Lariat in January 2001, we assumed
natural gas price hedging contracts with respect to our production in Oklahoma.
The table below sets forth those contracts that remained outstanding at December
31, 2001.

Since December 31, 2001, we have entered into the additional natural gas
price hedging contracts with respect to our Gulf Coast natural gas production
set forth in the table below. We continue to evaluate additional hedging
transactions for 2002 and future years.

We believe there is no material basis risk with respect to our natural gas
price hedging contracts because substantially all our Gulf Coast natural gas
production is sold under spot contracts that have historically correlated to the
settlement price, and because all of the hedging contracts assumed from Lariat
are settled against the same pipelines into which our production in Oklahoma is
sold.

25

OIL AND CONDENSATE. As of December 31, 2001, we had outstanding the
commodity price hedging contracts set forth in the table below with respect to
our U.S. Gulf Coast oil production.

Because substantially all of our U.S. Gulf Coast oil production is sold
under spot contracts that have historically correlated to the NYMEX West Texas
Intermediate price, we believe that we have no material basis risk with respect
to these transactions. The actual cash price we receive, however, generally is
about $2.00 per barrel less than the NYMEX West Texas Intermediate price when
adjusted for location and quality differences.

Substantially all of our hedging transactions are settled based upon
reported settlement prices on the NYMEX. The estimated fair value of these
transactions is based upon various factors that include closing exchange prices
on the NYMEX, over-the-counter quotations, volatility and the time value of
options. The calculation of the fair value of collars and floors requires the
use of the Black-Scholes option pricing model.

With respect to any particular swap transaction, the counter party is
required to make a payment to us if the settlement price for any settlement
period is less than the swap price for such transaction, and we are required to
make a payment to the counter party if the settlement price for any settlement
period is greater than the swap price for such transaction. For any particular
collar transaction, the counter party is required to make a payment to us if the
settlement price for any settlement period is below the floor price for such
transaction, and we are required to make a payment to the counter party if the
settlement price for any settlement period is above the ceiling price of such
transaction. For any particular floor transaction, the counter party is required
to make a payment to us if the settlement price for any settlement period is
below the floor price for such transaction. We are not required to make any
payment in connection with the settlement of a floor transaction.

NEW ACCOUNTING STANDARDS

On June 29, 2001, the Financial Accounting Standards Board (FASB) approved
its proposed SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill
and Other Intangible Assets." Under SFAS No. 141, all business combinations
should be accounted for using the purchase method of accounting; use of the
pooling-of-interests method is prohibited. This statement will apply to all
business combinations initiated after June 30, 2001 and to all acquired
intangible assets. This statement generally will supersede Accounting Principles
Board (APB) Opinion No. 17, "Intangible Assets." Adoption of SFAS No. 142 will

26

result in ceasing amortization of goodwill. This statement should be applied in
fiscal years beginning after December 15, 2001 to all goodwill and other
intangible assets recognized in an entity's statement of financial position at
that date, regardless of when those assets were initially recognized. The
adoption of this statement will have no effect on our consolidated financial
statements.

The FASB recently issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This statement changes the method of accruing for costs associated
with the retirement of fixed assets (e.g. oil & gas production facilities,
etc.). It will require that the fair value of the obligation be recognized in
the period in which it is incurred if a reasonable estimate of fair value can be
made, and that the associated asset retirement costs be capitalized as part of
the carrying amount of the asset. Implementation of this standard is required no
later than January 1, 2003, with earlier application encouraged. We are
currently assessing the impact of this standard.

REGULATION

WE ARE SUBJECT TO COMPLEX LAWS THAT CAN AFFECT THE COST, MANNER OR
FEASIBILITY OF DOING BUSINESS. Exploration, development, production and sale of
oil and gas are subject to extensive federal, state, local and international
regulation. We may be required to make large expenditures to comply with
environmental and other governmental regulations. Matters subject to regulation
include:

- discharge permits for drilling operations;

- drilling bonds;

- reports concerning operations;

- the spacing of wells;

- unitization and pooling of properties; and

- taxation.

Under these laws, we could be liable for personal injuries, property
damage, oil spills, discharge of hazardous materials, remediation and clean-up
costs and other environmental damages. Failure to comply with these laws also
may result in the suspension or termination of our operations and subject us to
administrative, civil and criminal penalties. Moreover, these laws could change
in ways that substantially increase our costs. Any such liabilities, penalties,
suspensions, terminations or regulatory changes could have a material adverse
effect on our financial condition and results of operations.

FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL
GAS. Historically, the transportation and sale for resale of natural gas in
interstate commerce has been regulated pursuant to several laws enacted by
Congress and the regulations promulgated under these laws by the FERC. In the
past, the federal government has regulated the prices at which gas could be
sold. Congress removed all price and non-price controls affecting wellhead sales
of natural gas effective January 1, 1993. Congress could, however, reenact price
controls in the future.

Our sales of natural gas are affected by the availability, terms and cost
of transportation. The price and terms for access to pipeline transportation are
subject to extensive federal and state regulation. From 1985 to the present,
several major regulatory changes have been implemented by Congress and the FERC
that affect the economics of natural gas production, transportation and sales.
In addition, the FERC is continually proposing and implementing new rules and
regulations affecting those segments of the natural gas industry, most notably
interstate natural gas transmission companies, that remain subject to the FERC's
jurisdiction. These initiatives may also affect the intrastate transportation of
gas under certain circumstances. The stated purpose of many of these regulatory
changes is to promote competition among the various sectors of the natural gas
industry and these initiatives generally reflect more light-handed regulation.

The ultimate impact of the complex rules and regulations issued by the FERC
since 1985 cannot be predicted. In addition, many aspects of these regulatory
developments have not become final but are still pending judicial and FERC final
decisions. We cannot predict what further action the FERC will take on

27

these matters. Some of the FERC's more recent proposals may, however, adversely
affect the availability and reliability of interruptible transportation service
on interstate pipelines. We do not believe that we will be affected by any
action taken materially differently than other natural gas producers, gatherers
and marketers with which we compete.

The Outer Continental Shelf Lands Act, or OCSLA, requires that all
pipelines operating on or across the Outer Continental Shelf, or the Shelf,
provide open-access, non-discriminatory service. Historically, the FERC has
opted not to impose regulatory requirements under its OCSLA authority on
gatherers and other entities outside the reach of its Natural Gas Act
jurisdiction. However, the FERC has issued Order No. 639, requiring that
virtually all non-proprietary pipeline transporters of natural gas on the Shelf
report information on their affiliations, rates and conditions of service. These
reporting requirements apply, in certain circumstances, to operators of
production platforms and other facilities on the Shelf with respect to gas
movements across such facilities. In a recent decision, the U.S. District Court
for the District of Columbia permanently enjoined the FERC from enforcing Order
No. 639, on the basis that the FERC did not possess the requisite rule-making
authority under the OCSLA for issuing Order No. 639. The FERC's appeal of the
court's decision is pending in the U. S. Court of Appeals for the District of
Columbia Circuit. We cannot predict the outcome of this appeal, nor can we
predict what further action the FERC will take with respect to this matter. In
addition, the FERC retains authority under OCSLA to exercise jurisdiction over
entities outside the reach of its Natural Gas Act jurisdiction if necessary to
ensure non-discriminatory access to service on the Shelf. We do not believe that
any FERC action taken under OCSLA will affect us in a way that materially
differs from the way it affects other natural gas producers, gatherers and
marketers with which we compete.

Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC and the courts. The natural gas
industry historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.

FEDERAL REGULATION OF SALES AND TRANSPORTATION OF CRUDE OIL. Our sales of
crude oil, condensate and natural gas liquids are currently not regulated and
are made at market prices. In a number of instances, however, the ability to
transport and sell such products are dependent on pipelines whose rates, terms
and conditions of service are subject to FERC jurisdiction under the Interstate
Commerce Act. Certain regulations implemented by the FERC in recent years could
result in an increase in the cost of transportation service on certain petroleum
products pipelines. However, we do not believe that these regulations affect us
any differently than other natural gas producers.

FEDERAL LEASES. The majority of our U.S. operations are located on federal
oil and gas leases, which are administered by the MMS. These leases are issued
through competitive bidding, contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to OCSLA (which are
subject to change by the MMS). For offshore operations, lessees must obtain MMS
approval for exploration plans and development and production plans prior to the
commencement of such operations. In addition to permits required from other
agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS has promulgated regulations
requiring offshore production facilities located on the Shelf to meet stringent
engineering and construction specifications. The MMS also has regulations
restricting the flaring or venting of natural gas, and has proposed to amend
such regulations to prohibit the flaring of liquid hydrocarbons and oil without
prior authorization. Similarly, the MMS has promulgated other regulations
governing the plugging and abandonment of wells located offshore and the removal
of all production facilities. To cover the various obligations of lessees on the
Shelf, the MMS generally requires that lessees have substantial net worth or
post bonds or other acceptable assurances that such obligations will be met. The
cost of such bonds or other surety can be substantial and there is no assurance
that bonds or other surety can be obtained in all cases. We are currently exempt
from the supplemental bonding requirements of the MMS. Under certain
circumstances, the MMS may require that our operations on federal leases be
suspended or terminated. Any such suspension or termination could materially and
adversely affect our financial condition, cash flows and results of operations.

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The MMS has issued a rule that amended its regulations governing the
calculation of royalties and the valuation of crude oil produced from federal
leases. This rule provides that the MMS will collect royalties based upon the
market value of oil produced from federal leases. The lawfulness of the new rule
has been challenged in federal court. We cannot predict what action the MMS will
take on this matter. We believe that these rules will not have a material effect
on our financial position, cash flows or results of operations.

STATE AND LOCAL REGULATION OF DRILLING AND PRODUCTION. We own interests in
properties located onshore Louisiana, Texas, New Mexico and Oklahoma. We also
own interests in properties in the state waters offshore Texas and Louisiana.
These states regulate drilling and operating activities by requiring, among
other things, drilling permits, bonds and reports concerning operations. The
laws of these states also govern a number of environmental and conservation
matters, including the handling and disposing of waste materials, unitization
and pooling of oil and gas properties and establishment of maximum rates of
production from oil and gas wells. Some states prorate production to the market
demand for oil and gas.

ENVIRONMENTAL REGULATIONS. Our operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Failure to comply with these
laws and regulations may result in the assessment of administrative, civil and
criminal penalties or the imposition of injunctive relief. Environmental laws
and regulations are complex, change frequently and have tended to become more
stringent over time. Both onshore and offshore drilling in certain areas has
been opposed by environmental groups and, in certain areas, has been restricted.
To the extent laws are enacted or other governmental action is taken that
prohibits or restricts onshore or offshore drilling or imposes environmental
protection requirements that result in increased costs to the oil and gas
industry in general, our business and prospects could be adversely affected.

The Oil Pollution Act of 1990, or OPA, imposes regulations on "responsible
parties" related to the prevention of oil spills and liability for damages
resulting from spills in U.S. waters. A "responsible party" includes the owner
or operator of an onshore facility, vessel or pipeline, or the lessee or
permittee of the area in which an offshore facility is located. OPA assigns
liability to each responsible party for oil removal costs and a variety of
public and private damages. While liability limits apply in some circumstances,
a party cannot take advantage of liability limits if the spill was caused by
gross negligence or willful misconduct or resulted from violation of a federal
safety, construction or operating regulation, or if the party fails to report a
spill or to cooperate fully in the cleanup. Even if applicable, the liability
limits for offshore facilities require the responsible party to pay all removal
costs, plus up to $75 million in other damages for offshore facilities and up to
$350 million for onshore facilities. Few defenses exist to the liability imposed
by OPA. Failure to comply with ongoing requirements or inadequate cooperation
during a spill event may subject a responsible party to administrative, civil or
criminal enforcement actions.

OPA also requires responsible parties to demonstrate proof of financial
responsibility to cover environmental cleanup and restoration costs. Under OPA
and a MMS rule, responsible parties of covered offshore facilities that have a
worst case oil spill of more than 1,000 barrels must demonstrate financial
assurance in amounts ranging from at least $10 million in state waters to at
least $35 million in federal waters, with higher amounts of up to $150 million
in certain limited circumstances where the MMS believes the additional coverage
is warranted, based on the risk of covered operations or the size of a
worst-case oil spill.

In addition to OPA, our discharges to waters of the U.S. are further
limited by the federal Clean Water Act, or CWA, and analogous state laws. CWA
prohibits any discharge into waters of the United States except in compliance
with permits issued by federal and state governmental agencies. Failure to
comply with CWA, including discharge limits on permits issued pursuant to CWA,
may also result in administrative, civil or criminal enforcement actions. OPA
and CWA also require the preparation of oil spill response plans.

OCSLA authorizes regulations relating to safety and environmental
protection applicable to lessees and permittees operating on the Shelf. Specific
design and operational standards may apply to vessels, rigs, platforms, vehicles
and structures operating or located on the Shelf. Violations of lease conditions
or regulations issued pursuant to OCSLA can result in substantial
administrative, civil and criminal penalties, as well as potential court
injunctions curtailing operations and the cancellation of leases.

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The Resource Conservation and Recovery Act, or RCRA, generally regulates
the disposal of solid and hazardous wastes. Although RCRA specifically excludes
from the definition of hazardous waste "drilling fluids, produced waters and
other wastes associated with the exploration, development or production of crude
oil, natural gas or geothermal energy," legislation has been proposed in
Congress from time to time that would reclassify certain oil and gas exploration
and production wastes as "hazardous wastes," which would make the reclassified
wastes subject to much more stringent handling, disposal and clean-up
requirements. If such legislation were to be enacted, it could increase our
operating costs, as well as those of the oil and gas industry in general.
Moreover, ordinary industrial wastes, such as paint wastes, waste solvents,
laboratory wastes and waste oils, may be regulated as hazardous waste.

The Comprehensive Environmental Response, Compensation, and Liability Act,
also known as the "Superfund" law, imposes liability, without regard to fault or
the legality of the original conduct, on certain classes of persons that are
considered to have contributed to the release of a "hazardous substance" into
the environment. Persons who are or were responsible for releases of hazardous
substances under the Superfund law may be subject to joint and several liability
for the costs of cleaning up the hazardous substances that have been released
into the environment and for damages to natural resources, and it is not
uncommon for neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the hazardous substances
released into the environment. We currently own or lease onshore properties that
have been used for the exploration and production of oil and gas for a number of
years. These recently acquired onshore properties have been operated by third
parties whose treatment and disposal or release of hydrocarbons or other wastes
was not under our control. These properties and any wastes that may have been
disposed or released on them may be subject to the Superfund law, RCRA and
analogous state laws, and we potentially could be required to remediate such
properties.

We believe that we are in substantial compliance with current applicable
U.S. federal, state and local environmental laws and regulations and that
continued compliance with existing requirements will not have a material adverse
effect on our financial position, cash flows or results of operations. Our
foreign operations are potentially subject to similar governmental controls and
restrictions relating to the environment. We believe that we are in substantial
compliance with any such foreign requirements pertaining to the environment.
There can be no assurance, however, that current regulatory requirements will
not change, currently unforeseen environmental incidents will not occur or past
non-compliance with environmental laws or regulations will not be discovered.

OTHER FACTORS AFFECTING OUR BUSINESS AND FINANCIAL RESULTS

OIL AND GAS PRICES FLUCTUATE WIDELY, AND LOW PRICES FOR AN EXTENDED PERIOD
OF TIME ARE LIKELY TO HAVE A MATERIAL ADVERSE IMPACT ON OUR BUSINESS. Our
revenues, profitability and future growth depend substantially on prevailing
prices for oil and gas. These prices also affect the amount of cash flow
available for capital expenditures and our ability to borrow and raise
additional capital. The amount we can borrow under our credit facility is
subject to periodic redeterminations based in part on changing expectations of
future prices. Lower prices may also reduce the amount of oil and gas that we
can economically produce.

Prices for oil and gas fluctuate widely. Among the factors that can cause
fluctuations are:

- the domestic and foreign supply of oil and natural gas;

- weather conditions;

- the price of foreign imports;

- world-wide economic conditions;

- political conditions in oil and gas producing regions;

- the level of consumer demand;

- domestic and foreign governmental regulations; and

- the price and availability of alternative fuels.

30

OUR USE OF OIL AND GAS PRICE HEDGING CONTRACTS INVOLVES CREDIT RISK AND MAY
LIMIT FUTURE REVENUES FROM PRICE INCREASES AND RESULT IN SIGNIFICANT
FLUCTUATIONS IN OUR NET INCOME AND STOCKHOLDERS' EQUITY. We use hedging
transactions with respect to a portion of our oil and gas production to achieve
more predictable cash flow and to reduce our exposure to price fluctuations.
While the use of hedging transactions limits the downside risk of price
declines, their use may also limit future revenues from price increases. Hedging
transactions also involve the risk that the counterparty may be unable to
satisfy its obligations.

We adopted Statement of Financial Accounting Standards (SFAS) No. 133 on
January 1, 2001. SFAS No. 133 generally requires us to record each hedging
transaction as an asset or liability measured at its fair value. Each quarter we
must record changes in the value of our hedges, which could result in
significant fluctuations in net income and stockholders' equity from period to
period. See Note 3 -- "Commodity Derivative Instruments and Hedging Activities"
to our consolidated financial statements.

OUR FUTURE SUCCESS DEPENDS ON OUR ABILITY TO REPLACE THE RESERVES THAT WE
PRODUCE. Our future success depends on our ability to find, develop and acquire
oil and gas reserves that are economically recoverable. As is generally the
case, our producing properties in the Gulf of Mexico and the onshore Gulf Coast
often have high initial production rates, followed by steep declines. As a
result, we must locate and develop or acquire new oil and gas reserves to
replace those being depleted by production. We must do this even during periods
of low oil and gas prices when it may be difficult to raise the capital
necessary to finance these activities. Without successful exploration or
acquisition activities, our reserves, production and revenues will decline
rapidly. We cannot assure you that we will be able to find and develop or
acquire additional reserves at an acceptable cost.

SUBSTANTIAL CAPITAL IS REQUIRED TO REPLACE AND GROW RESERVES. We make, and
will continue to make, substantial expenditures to find, develop, acquire and
produce oil and gas reserves. We believe that we will have sufficient cash
provided by operating activities and available borrowings under our credit
arrangements to fund planned capital expenditures in 2002. If, however, lower
oil and gas prices or operating difficulties result in our cash flow from
operations being less than expected or limit our ability to borrow under our
credit facility, we may be unable to expend the capital necessary to undertake
or complete our drilling program unless we raise additional funds through debt
or equity financings. We cannot assure you that debt or equity financing, cash
generated by operations or borrowing capacity will be available to meet these
requirements.

RESERVE ESTIMATES ARE INHERENTLY UNCERTAIN AND DEPEND ON MANY ASSUMPTIONS
THAT MAY TURN OUT TO BE INACCURATE. Estimating accumulations of oil and gas is
complex and is not exact because of the numerous uncertainties inherent in the
process. The process relies on interpretations of available geologic, geophysic,
engineering and production data. The extent, quality and reliability of this
data can vary. The process also requires certain economic assumptions, some of
which are mandated by the SEC, such as oil and gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. The
accuracy of a reserve estimate is a function of:

- the quality and quantity of available data;

- the interpretation of that data;

- the accuracy of various mandated economic assumptions; and

- the judgment of the persons preparing the estimate.

The proved reserve information set forth in this report is based on
estimates we prepared. Estimates prepared by others might differ materially from
our estimates.

Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from our estimates. Any significant variance
could materially affect the quantities and present value of our reserves. In
addition, we may adjust estimates of proved reserves to reflect production
history, results of exploration and development and prevailing oil and gas
prices. Our reserves may also be susceptible to drainage by operators on
adjacent properties.

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You should not assume that the present value of future net cash flows is
the current market value of our estimated proved oil and gas reserves. In
accordance with SEC requirements, we generally base the estimated discounted
future net cash flows from proved reserves on prices and costs on the date of
the estimate. Actual future prices and costs may be materially higher or lower
than the prices and costs as of the date of the estimate.

IF OIL AND GAS PRICES DECREASE, WE MAY BE REQUIRED TO TAKE
WRITEDOWNS. There is a risk that we will be required to writedown the carrying
value of our oil and gas properties when oil and gas prices are low or if we
have substantial downward adjustments to our estimated proved reserves,
increases in our estimates of development costs or deterioration in our
exploration results.

We capitalize the costs to acquire, find and develop our oil and gas
properties. Under the full cost accounting method, the net capitalized costs of
our oil and gas properties may not exceed the present value of estimated future
net cash flows from proved reserves, using period end oil and gas prices and a
10% discount factor, plus the lower of cost or fair market value of unproved
properties. If net capitalized costs of our oil and gas properties exceed this
limit, we must charge the amount of the excess to earnings. This type of charge
will not affect our cash flow from operating activities, but it will reduce the
book value of our stockholders' equity. We review the carrying value of our
properties quarterly, based on prices in effect (including the value of our
hedge positions) as of the end of each quarter or as of the time of reporting
our results. The carrying value of oil and gas properties is computed on a
country-by-country basis. Therefore, while our properties in one country may be
subject to a writedown, our properties in other countries could be unaffected.
Once incurred, a writedown of oil and gas properties is not reversible at a
later date even if oil and gas prices increase.

WE MAY BE SUBJECT TO RISKS IN CONNECTION WITH ACQUISITIONS. The successful
acquisition of producing properties requires an assessment of several factors,
including:

- recoverable reserves;

- future oil and gas prices;

- operating costs; and

- potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection
with these assessments, we perform a review of the subject properties that we
believe to be generally consistent with industry practices. Our review will not
reveal all existing or potential problems nor will it permit us to become
sufficiently familiar with the properties to fully assess their deficiencies and
capabilities. Inspections may not always be performed on every platform or well,
and structural and environmental problems are not necessarily observable even
when an inspection is undertaken. Even when problems are identified, the seller
may be unwilling or unable to provide effective contractual protection against
all or part of the problems. We are often not entitled to contractual
indemnification for environmental liabilities and acquire properties on an "as
is" basis.

COMPETITIVE INDUSTRY CONDITIONS MAY NEGATIVELY AFFECT OUR ABILITY TO
CONDUCT OPERATIONS. Competition in the oil and gas industry is intense,
particularly with respect to the acquisition of producing properties and proved
undeveloped acreage. Major and independent oil and gas companies actively bid
for desirable oil and gas properties, as well as for the equipment and labor
required to operate and develop their properties. Many of our competitors have
financial resources that are substantially greater than ours, which may
adversely affect our ability to compete with these companies.

DRILLING IS A HIGH-RISK ACTIVITY. Our future success will depend on the
success of our drilling program. In addition to the numerous operating risks
described in more detail below, these activities involve the risk that no
commercially productive oil or gas reservoirs will be discovered. In addition,
we often are uncertain as to the future cost or timing of drilling, completing
and producing wells. Furthermore, our drilling operations may be curtailed,
delayed or canceled as a result of a variety of factors, including:

- unexpected drilling conditions;

- pressure or irregularities in formations;

32

- equipment failures or accidents;

- adverse weather conditions;

- compliance with governmental requirements; and

- shortages or delays in the availability of drilling rigs and the delivery
of equipment.

THE OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS THAT CAN CAUSE
SUBSTANTIAL LOSSES; INSURANCE MAY NOT PROTECT US AGAINST ALL THESE RISKS.
These risks include:

- fires;

- explosions;

- blow-outs;

- uncontrollable flows of oil, gas, formation water or drilling fluids;

- natural disasters;

- pipe or cement failures;

- casing collapses;

- embedded oilfield drilling and service tools;

- abnormally pressured formations; and

- environmental hazards such as oil spills, natural gas leaks, pipeline
ruptures and discharges of toxic gases.

If any of these events occur, we could incur substantial losses as a result
of:

- injury or loss of life;

- severe damage or destruction of property, natural resources and
equipment;

- pollution and other environmental damage;

- clean-up responsibilities;

- regulatory investigation and penalties;

- suspension of our operations; and

- repairs to resume operations.

If we experience any of these problems, our ability to conduct operations
could be adversely affected.

Offshore operations are subject to a variety of operating risks peculiar to
the marine environment, such as capsizing, collisions and damage or loss from
hurricanes or other adverse weather conditions. These conditions can cause
substantial damage to facilities and interrupt production. As a result, we could
incur substantial liabilities that could reduce or eliminate the funds available
for our drilling and development programs and acquisitions, or result in loss of
properties.

We maintain insurance against some, but not all, of these potential risks
and losses. We may elect not to obtain insurance if we believe that the cost of
available insurance is excessive relative to the risks presented. In addition,
pollution and environmental risks generally are not fully insurable. If a
significant accident or other event occurs and is not fully covered by
insurance, it could adversely affect us.

WE HAVE RISKS ASSOCIATED WITH OUR FOREIGN OPERATIONS. We continue to
evaluate and pursue new opportunities for international expansion in areas where
we can use our core competencies. To date, we have expanded our operations to
Australia and China.

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Ownership of property interests and production operations in areas outside
the United States is subject to the various risks inherent in foreign
operations. These risks may include:

- currency restrictions and exchange rate fluctuations;

- loss of revenue, property and equipment as a result of expropriation,
nationalization, war or insurrection;

- increases in taxes and governmental royalties;

- renegotiation of contracts with governmental entities and
quasi-governmental agencies;

- changes in laws and policies governing operations of foreign-based
companies;

- labor problems; and

- other uncertainties arising out of foreign government sovereignty over
our international operations.

Our international operations may also be adversely affected by laws and
policies of the United States affecting foreign trade, taxation and investment.
In addition, if a dispute arises with respect to our foreign operations, we may
be subject to the exclusive jurisdiction of foreign courts or may not be
successful in subjecting foreign persons to the jurisdiction of the courts of
the United States.

EXPLORATION IN DEEPWATER INVOLVES GREATER OPERATING AND FINANCIAL RISKS
THAN EXPLORATION AT SHALLOWER DEPTHS. THESE RISKS COULD RESULT IN SUBSTANTIAL
LOSSES. We have developed a three phase strategy to enter the deepwater play.
Deepwater drilling and operations require the application of recently developed
technologies and involve a higher risk of mechanical failure. We will likely
experience significantly higher drilling costs for any deepwater wells we may
drill. In addition, much of the deepwater play lacks the physical and oilfield
service infrastructure present in shallower waters. As a result, development of
a deepwater discovery may be a lengthy process and require substantial capital
investment, resulting in significant financial and operating risks.

OTHER INDEPENDENT OIL AND GAS COMPANIES' LIMITED ACCESS TO CAPITAL MAY
CHANGE OUR EXPLORATION AND DEVELOPMENT PLANS. Many independent oil and gas
companies have limited access to the capital necessary to finance their
activities. As a result, some of the other working interest owners of our wells
may be unwilling or unable to pay their share of the costs of projects as they
become due. These problems could cause us to change, suspend or terminate our
drilling and development plans with respect to the affected project.

FORWARD-LOOKING INFORMATION

This report contains information that is forward-looking or relates to
anticipated future events or results such as production targets, anticipated
production rates, planned capital expenditures, the availability of capital
resources to fund capital expenditures, estimates of proved reserves and the
estimated present value of such reserves, wells planned to be drilled in the
future, our financial position, business strategy and other plans and objectives
for future operations. Although we believe that the expectations reflected in
this information are reasonable, this information is based upon assumptions and
anticipated results that are subject to numerous uncertainties. Actual results
may vary significantly from those anticipated due to many factors, including
drilling results, oil and gas prices, industry conditions, the prices of goods
and services, the availability of drilling rigs and other support services the
availability of capital resources and other factors affecting our business
described above under the captions "Regulation" and "Other Factors Affecting Our
Business." All written and oral forward-looking statements attributable to us or
persons acting on our behalf are expressly qualified in their entirety by such
factors.

COMMONLY USED OIL AND GAS TERMS

Below are explanations of some commonly used terms in the oil and gas
business.

BASIS RISK. The risk associated with the sales point price for oil or gas
production varying from the reference (or settlement) price for a particular
hedging transaction.

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BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.

BCF. Billion cubic feet.

BCFE. Billion cubic feet equivalent, determined using the ratio of six Mcf
gas to one Bbl of crude oil, condensate or natural gas liquids.

BOPD. Barrels of crude oil or other liquid hydrocarbons per day.

BTU. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

COMPLETION. The installation of permanent equipment for the production of
oil or natural gas, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.

DEEP SHELF. We consider the Deep Shelf to be structures located on the
Shelf at depths greater than 13,000 feet in areas where there has been limited
or no production from deeper stratigraphic zones.

DEEPWATER. Generally considered to be water depths in excess of 1,000
feet.

DEVELOPED ACREAGE. The number of acres that are allocated or assignable to
producing wells or wells capable of production.

DEVELOPMENT WELL. A well drilled within the proved area of an oil or
natural gas field to the depth of a stratigraphic horizon known to be
productive, including a well drilled to find and produce probable reserves (an
EXPLOITATION WELL).

DRY HOLE OR WELL. A well found to be incapable of producing hydrocarbons
in sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.

EXPLORATORY WELL. A well drilled to find and produce oil or natural gas
reserves that is not a development well.

FARM-IN OR FARM-OUT. An agreement whereunder the owner of a working
interest in an oil and gas lease assigns the working interest or a portion
thereof to another party who desires to drill on the leased acreage. Generally,
the assignee is required to drill one or more wells in order to earn its
interest in the acreage. The assignor usually retains a royalty or reversionary
interest in the lease. The interest received by an assignee is a "farm-in,"
while the interest transferred by the assignor is a "farm-out."

FERC. The Federal Energy Regulatory Commission.

FPSO. A floating production, storage and off-loading vessel, commonly used
overseas to produce oil locations where pipeline infrastructure may not exist.

FIELD. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature or
stratigraphic condition.

FINDING COSTS. Costs associated with acquiring and developing proved oil
and gas reserves that are capitalized by the Company under generally accepted
accounting principles.

GAS LIFT. The process of injecting natural gas into the wellbore to
facilitate the flow of produced fluids from the reservoir to the production
train.

GROSS ACRES OR GROSS WELLS. The total acres or wells in which a working
interest is owned.

LIQUIDS. Crude oil, condensate and natural gas liquids.

MBBLS. One thousand barrels of crude oil or other liquid hydrocarbons.

MCF. One thousand cubic feet.

MCFE. One thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.

35

MMS. The Minerals Management Service of the United States Department of
the Interior.

MMBBLS. One million barrels of crude oil or other liquid hydrocarbons.

MMCF. One million cubic feet.

MMCF/D. One million cubic feet per day.

MMCFE. One million cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.

NET ACRES OR NET WELLS. The sum of the fractional working interests owned
in gross acres or gross wells, as the case may be.

NYMEX. The New York Mercantile Exchange.

POSSIBLE RESERVES. Reserves similar to probable reserves but that are less
likely to be recovered than not.

PRESENT VALUE. When used with respect to oil and natural gas reserves, the
estimated value of future gross revenues (estimated in accordance with the
requirements of the SEC) to be generated from the production of proved reserves,
net of estimated production and future development costs, using prices and costs
in effect as of the date indicated, without giving effect to nonproperty related
expenses such as general and administrative expenses, debt service and future
income tax expenses or to depreciation, depletion and amortization, discounted
using an annual discount rate of 10%.

PROBABLE RESERVES. Reserves which analysis of drilling, geological,
geophysical and engineering data does not demonstrate to be proved under current
technology and existing economic conditions, but where such analysis suggests
the likelihood of their existence and future recovery.

PRODUCTIVE WELL. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

PROVED DEVELOPED PRODUCING RESERVES. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.

PROVED DEVELOPED RESERVES. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.

PROVED DEVELOPED NONPRODUCING RESERVES. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.

PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

PROVED UNDEVELOPED RESERVES. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.

TURNKEY DRILLING CONTRACT. A fixed rate contract pursuant to which the
drilling contractor generally bears the risk of loss for unbudgeted
contingencies.

SHELF. The Continental Shelf of the Gulf of Mexico. Water depths generally
range from 50 feet to 1,000 feet.

UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.

WORKING INTEREST. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.

WORKOVER. Operations on a producing well to restore or increase
production.

36

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk from changes in oil and gas prices, interest
rates and foreign currency exchange rates as discussed below.

OIL AND GAS PRICES

As independent oil and gas producer, our revenue, profitability, access to
capital and future rate of growth are substantially dependent upon the
prevailing prices of natural gas, crude oil and hydrocarbon condensate.
Prevailing prices for such commodities are subject to wide fluctuation in
response to relatively minor changes in supply and demand and a variety of
additional factors beyond our control. We utilize and expect to continue to
utilize hedging transaction with respect to a portion of our oil and gas
production to achieve more predictable cash flow, as well as to reduce our
exposure to price fluctuations. While hedging limits the downside risk of
adverse price movements, it may also limit future revenues from favorable price
movements. For a further discussion of our hedging activities, see the
information under the caption "Hedging" in Item 7 of this report.

INTEREST RATES

At December 31, 2001, we had approximately $300 million of outstanding
long-term debt ($125 million of 7.45% Senior Notes due 2007 and $175 million of
7 5/8% Senior Notes due 2011) subject to a fixed rate of interest. Additionally,
we had $144 million of convertible trust preferred securities bearing a fixed
distribution rate of 6.5%. However, the $129 million outstanding under our
reserve-based credit facility and money market lines of credit are subject to a
rate of interest that fluctuates based on short-term interest rates. Because the
majority of our long term obligations were at fixed rates, approximately 70% of
our total debt at December 31, 2001, we consider our interest rate exposure at
such date to be minimal. The impact on annual cash flow of a 25% change (up or
down) in the floating rate (approximately 80 basis points) applicable to our
borrowings under our credit facility and money market lines of credit would be
$1.1 million. At December 31, 2001, we had no open interest rate hedge positions
to reduce our exposure to changes in interest rates.

FOREIGN CURRENCY EXCHANGE RATES

Our cash flow from certain international operations is based on the U.S.
dollar equivalent of cash flows measured in foreign currencies. We consider our
current risk exposure to exchange rate movements, based on net cash flows, to be
immaterial. We did not have any open derivative contracts relating to foreign
currencies at December 31, 2001.

37

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

NEWFIELD EXPLORATION COMPANY

INDEX

CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA

38

MANAGEMENT REPORT ON FINANCIAL STATEMENTS

The Management of Newfield Exploration Company is responsible for the
preparation and integrity of all information contained in this Annual Report on
Form 10-K for the year ended December 31, 2001. The financial statements are
prepared in accordance with generally accepted accounting principles and,
accordingly, include certain informed judgments and estimates of management.
Newfield's independent public accountants have audited the financial statements
as described in their report which follows.

Management maintains a system of internal accounting and managerial
controls that are designed to provide reasonable assurance that assets are
safeguarded, transactions are executed in accordance with management's
authorization and accounting records are reliable for financial statement
preparation.

An Audit Committee of the Board of Directors, consisting of directors who
are not employees of the Company, meets periodically with management and the
independent public accountants to obtain assurances as to the integrity of
Newfield's accounting and financial reporting and to affirm the adequacy of the
system of accounting and managerial controls in place. The independent
accountants have full, free and separate access to the Audit Committee to
discuss all appropriate matters.

We believe that Newfield's policies and system of accounting and managerial
controls reasonably assure the integrity of the information in the financial
statements and in the other sections of this report.

/s/ DAVID A. TRICE /s/ TERRY W. RATHERT
David A. Trice Terry W. Rathert
President and Chief Executive Officer Vice President and Chief Financial Officer

Houston, Texas
March 5, 2002

39

REPORT OF INDEPENDENT ACCOUNTANTS

To the Stockholders and Board of Directors of Newfield Exploration Company:

In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, of stockholders' equity and of cash flows
present fairly, in all material respects, the financial position of Newfield
Exploration Company and its subsidiaries at December 31, 2001 and 2000, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States of America. 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 of these statements in accordance with auditing standards
generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

As described in Note 1 to the consolidated financial statements, the
Company changed its method of accounting for derivative instruments and hedging
activities effective January 1, 2001. Additionally, as described in Note 1 to
the consolidated financial statements, the Company changed its method of
accounting for its crude oil inventories in connection with its adoption of SEC
Staff Accounting Bulletin 101, "Revenue Recognition in Financial Statements"
effective January 1, 2000.

/s/ PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 5, 2002

40

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT SHARE DATA)

The accompanying notes to consolidated financial statements are an integral part
of this statement.

41

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA)

The accompanying notes to consolidated financial statements are an integral part
of this statement.

42

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE DATA)

The accompanying notes to consolidated financial statements are an integral part
of this statement.

43

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)

The accompanying notes to consolidated financial statements are an integral part
of this statement.

44

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

ORGANIZATION AND PRINCIPLES OF CONSOLIDATION

These financial statements include the accounts of Newfield Exploration
Company, a Delaware corporation, and its subsidiaries (collectively, the
"Company"). All significant intercompany balances and transactions have been
eliminated.

DEPENDANCE ON OIL AND GAS PRICES

As an independent oil and gas producer, the Company's revenue,
profitability and future rate of growth are substantially dependent upon
prevailing prices for natural gas, oil and condensate, which are dependent upon
numerous factors beyond the Company's control, such as economic, political and
regulatory developments and competition from other sources of energy. The energy
markets have historically been very volatile, and there can be no assurance that
oil and gas prices will not be subject to wide fluctuations in the future. A
substantial or extended decline in oil and gas prices could have a material
adverse effect on the Company's financial position, results of operations, cash
flows and access to capital and on the quantities of oil and gas reserves that
may be economically produced.

USE OF ESTIMATES AND RECLASSIFICATIONS

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates. The
Company's most significant financial estimates are based on remaining proved oil
and gas reserves. Certain reclassifications have been made to prior years
reported amounts in order to conform with the current year presentation.

ACCOUNTING CHANGES

The Company adopted SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities," as amended by SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities -- Deferral of the Effective Date of FASB
Statement No. 133, an amendment of FASB Statement No. 133," and SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities,
an amendment of FASB Statement No. 133," on January 1, 2001. In accordance with
the transition provisions of SFAS No. 133, on January 1, 2001, the Company
recorded as cumulative effect adjustments a loss of $74.2 million (net of tax of
$40.0 million) in accumulated other comprehensive loss and a loss of $4.8
million (net of tax of $2.6 million) in 2001 earnings. In addition, the adoption
resulted in the recognition of $17.7 million of derivative assets and $139.3
million of derivative liabilities on the balance sheet on January 1, 2001. See
Note 3, "Commodity Derivative Instruments and Hedging Activities."

The Company adopted SEC Staff Accounting Bulletin (SAB) No. 101, "Revenue
Recognition in Financial Statements," effective January 1, 2000. The adoption of
SAB No. 101 requires the Company to report crude oil inventory associated with
its Australian offshore operations at lower of cost or market, which was a
change from the historical policy of recording such inventory at market value on
the balance sheet date, net of estimated costs to sell. The cumulative effect of
the change from the acquisition date of the Company's Australian operations in
July 1999 through December 31, 1999 is a reduction in net income of $2.36
million, (net of tax of $1.3 million) or $0.05 per diluted share, and is shown
as the cumulative effect of change in

45

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

accounting principle on the consolidated statement of income for the year ended
December 31, 2000. The pro forma effect had SAB No. 101 been applied
retroactively in 1999 would have been as follows:

SAB No. 101 would not have effected periods prior to the acquisition of the
Company's Australian operations in July 1999.

NEW ACCOUNTING STANDARDS

On June 29, 2001, the Financial Accounting Standards Board (FASB) approved
its proposed SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill
and Other Intangible Assets." Under SFAS No. 141, all business combinations will
be accounted for using the purchase method of accounting; use of the
pooling-of-interests method is prohibited. SFAS No. 142 will apply to all
acquired intangible assets whether acquired singly, as part of a group or in a
business combination. The statement will supersede Accounting Principles Board
(APB) Opinion No. 17, "Intangible Assets," but continues APB Opinion No. 17 with
respect to internally developed intangible assets. Adoption of SFAS No. 142 will
result in ceasing amortization of goodwill. All of the provisions of the
statement are applicable to fiscal years beginning after December 15, 2001 to
all goodwill and other intangible assets recognized in an entity's statement of
financial position at that date, regardless of when those assets were initially
recognized. The adoption of these standards will have no effect on the Company's
consolidated financial statements.

The FASB recently issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This statement changes the method of accruing for costs associated
with the retirement of fixed assets (e.g. oil & gas production facilities, etc.)
that an entity is legally obligated to incur. This statement will require that
the fair value of the obligation be recognized in the period in which it is
incurred if a reasonable estimate of fair value can be made, and that the
associated asset retirement costs be capitalized as part of the carrying amount
of the asset. Implementation of this standard is required no later than January
1, 2003, with earlier application encouraged. The Company is currently assessing
the impact of this standard.

REVENUE RECOGNITION

Revenues are recorded when title passes to the customer. Revenues from the
production of oil and gas from properties in which the Company has an interest
with other companies are recorded on the basis of sales to customers.
Differences between these sales and the Company's share of production are not
significant.

INVENTORIES

Inventories consist of international oil produced but not sold. Crude oil
from the Company's operations located offshore Australia is produced into two
floating production, storage and off-loading vessels (FPSOs) and sold
periodically as a barge quantity is accumulated. The product inventory at
December 31, 2001 and December 31, 2000 consisted of approximately 170,471 and
252,450 barrels of crude oil, valued at $2.4 million and $3.3 million,
respectively, and is carried at lower of average cost or market. Also included
in inventories are materials and supplies, stated at lower of cost or market.

46

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

FOREIGN CURRENCY

The functional currency for all foreign operations, except Australia, is
the U.S. dollar. Translation adjustments resulting from translating the
Australian subsidiary's Australian dollar financial statements into U.S. dollars
are included as other comprehensive income in the consolidated statement of
stockholders' equity. Gains and losses incurred on currency transactions in
other than a country's functional currency are included in the consolidated
statement of income.

EARNINGS PER SHARE

Basic earnings per common share (EPS) is computed by dividing net income by
the weighted average number of common shares outstanding for the period. Diluted
EPS reflects the potential dilution that could occur if outstanding stock
options and convertible securities were exercised for or converted into common
stock.

The following is a calculation of basic and diluted weighted average shares
outstanding for each of the three years in the period ended December 31, 2001:

The calculation of shares outstanding for diluted EPS for the years ended
December 31, 2001, 2000 and 1999 does not include the effect of outstanding
stock options to purchase 907,300, 127,000 and 270,000 shares, respectively,
because to do so would have been antidilutive. Additionally, the calculation of
diluted EPS for 1999 does not include the effect of 3,923,225 shares underlying
the 6.5% quarterly income convertible trust preferred securities because to do
so would have been antidilutive.

FINANCIAL INSTRUMENTS

Cash equivalents include highly-liquid investments with a maturity of three
months or less when acquired. The Company invests cash in excess of operating
requirements in U.S. Treasury Notes, Eurodollar

47

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

bonds and investment grade commercial paper. Cash equivalents are stated at
cost, which approximates fair market value.

The Company includes fair value information in the notes to financial
statements when the fair value of its financial instruments is different from
the book value. The book value of those financial instruments that are
classified as current assets or liabilities approximate fair value because of
the short maturity of those instruments.

On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133, as amended,
requires enterprises to recognize all derivatives as either assets or
liabilities on their balance sheet and measure those instruments at fair value.
See Note 3 -- "Commodity Derivative Instruments and Hedging Activities." For all
years prior to 2001, the Company accounted for its hedging activities in
accordance with SFAS No. 80. Gains and losses on these contracts were recognized
in revenue in the period in which the underlying production was delivered. The
unrealized gains or losses on these contracts were not recognized in the
financial statements prior to the adoption of SFAS No. 133.

OIL AND GAS PROPERTIES

The Company uses the full cost method of accounting. Under this method,
all costs incurred in the acquisition, exploration and development of oil and
gas properties are capitalized into cost centers that are established on a
country-by-country basis. Such capitalized costs and estimated future
development and dismantlement costs are amortized on a unit-of-production method
based on proved reserves. For each cost center, the net capitalized costs of oil
and gas properties are limited to the lower of unamortized cost or the cost
center ceiling, defined as the sum of the present value (10% per annum discount
rate) of estimated future net revenues from proved reserves, based on year-end
oil and gas prices; plus the cost of properties not being amortized, if any;
plus the lower of cost or estimated fair value of unproved properties included
in the costs being amortized, if any; less related income tax effects.

In accordance with full cost accounting rules we recorded a domestic
ceiling test writedown at December 31, 2001. The $106 million ($68 million
after-tax) impairment was primarily the result of lower commodity prices at year
end 2001. With the concurrence of the Securities and Exchange Commission, the
impairment at December 31, 2001 was calculated using a hedge adjusted price (net
realized price after considering cash flow hedges) applied to the quantity of
proved reserves covered by the Company's hedges. The writedown would have been
$184 million ($118 million after-tax) if we had not included our hedge adjusted
price at December 31, 2001. Additionally, the Company recorded a charge of $0.5
million in 2000 related to abandoned prospect costs in foreign locations other
than Australia and China.

Proceeds from the sale of oil and gas properties are applied to reduce the
costs in the cost center unless the sale involves a significant quantity of
reserves in relation to the cost center, in which case a gain or loss is
recognized.

Other property and equipment are recorded at cost and are depreciated over
their estimated useful lives of three to seven years using the straight-line
method. At December 31, 2001 and 2000, furniture, fixtures and equipment is net
of accumulated depreciation of $5.7 million and $3.5 million, respectively.

ABANDONMENT AND DISMANTLEMENT COSTS

Future abandonment and dismantlement costs include costs to dismantle and
relocate or dispose of the Company's offshore production platforms, FPSOs,
gathering systems, wells and related structures. The Company develops estimates
of its future abandonment and dismantlement costs for each of its offshore
properties based upon the type of production structure, depth of water,
currently available abandonment procedures and consultations with construction
and engineering consultants. The Company does not currently

48

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

anticipate additional abandonment and dismantlement costs will be incurred
beyond such estimates. Such estimates are re-evaluated at least annually by the
Company's engineers.

Total estimated future abandonment and dismantlement costs associated with
the Company's developed and acquired properties were $125.6 million, $120.4
million and $133.1 million as of December 31, 2001, 2000 and 1999, respectively.

Estimated future abandonment and dismantlement costs are accrued on a
unit-of-production method based on proved reserves. The portion of future
abandonment and dismantlement costs that has been accrued is included in
accumulated depreciation, depletion and amortization and was $68.4 million,
$56.9 million and $43.1 million as of December 31, 2001, 2000 and 1999,
respectively.

INCOME TAXES

The Company uses the liability method of accounting for income taxes. Under
this method, deferred tax assets and liabilities are determined by applying tax
regulations existing at the end of a reporting period to the cumulative
temporary differences between the tax bases of assets and liabilities and their
reported amounts in the financial statements.

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.

CONCENTRATION OF CREDIT RISK

The Company maintains cash balances with several banks that frequently
exceed federally insured limits and invests its cash in investment grade
commercial and U.S. Government-backed securities. The Company's joint interest
partners consist primarily of independent oil and gas producers. The Company's
oil and gas production purchasers consist primarily of independent marketers,
major oil and gas companies and gas pipeline companies. The Company performs
credit evaluations of its customers' financial condition and obtains letters of
credit and parental guarantees from selected customers. The Company has not
experienced any significant losses from uncollectible accounts. All of the
Company's hedging transactions have been carried out in the over-the-counter
market. The use of hedging transactions involves the risk that counter parties
may be unable to meet the financial terms of such transactions. At December 31,
2001, Bank of Montreal, J Aron & Company and Barclays Bank PLC were the
counterparties with respect to 77% of the Company's hedged future production.

MAJOR CUSTOMERS

The Company sold oil and gas production representing more than 10% of its
oil and gas revenues for the year ended December 31, 2001 to Conoco Inc. (28%)
and Superior Natural Gas Corporation (25%); for the year ended December 31, 2000
to Conoco Inc. (35%) and Superior Natural Gas Corporation (16%); and for the
year ended December 31, 1999 to Conoco Inc. (18%) and Superior Natural Gas
Corporation (10%). Because alternative purchasers of oil and gas are readily
available, the Company believes that the loss of either or both of these
purchasers would not have a material adverse effect on the Company.

49

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

2. OIL AND GAS PROPERTIES:

Oil and gas properties consisted of the following at December 31:

Of the $149.7 million, $106.8 million and $79.2 million of costs not
subject to amortization at December 31, 2001, 2000 and 1999, respectively, 32%,
37% and 50%, respectively, were related to offshore properties. The Company
believes that all costs not currently subject to amortization will be evaluated
within four years.

3. COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

The Company maintains a commodity-price risk management strategy that
utilizes derivative instruments, primarily swaps, collars and floor contracts,
in order to hedge against the variability in cash flows associated with the
forecasted sale of its oil and gas production. While the use of these derivative
instruments limits the downside risk of adverse price movements, they may also
limit future revenues from favorable price movements. The use of derivatives
also involves the risk that the counter parties to such instruments will be
unable to meet the financial terms of such contracts. At December 31, 2001, Bank
of Montreal, J Aron & Company and Barclays Bank PLC were the counterparties with
respect to 77% of the Company's hedged future production.

With respect to any particular swap transaction, the counterparty is
required to make a payment to the Company if the settlement price for any
settlement period is less than the swap price for such transaction, and the
Company is required to make payment to the counterparty if the settlement price
for any settlement period is greater than the swap price for such transaction.
For any particular collar transaction, the counterparty is required to make a
payment to the Company if the settlement price for any settlement period is
below the floor price for such transaction, and the Company is required to make
payment to the counterparty if the settlement price for any settlement period is
above the ceiling price of such transaction. For any particular floor contract,
the counterparty is required to make a payment to the Company if the settlement
price for any settlement period is below the floor price for such transaction.
The Company is not required to make any payment in connection with the
settlement of a floor contract.

As of January 1, 2001, all derivatives are recognized on the balance sheet
at their fair value. Substantially all of the Company's hedging transactions are
settled based upon reported settlement prices on the NYMEX.

50

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The estimated fair value of these transactions is based upon various factors
that include closing exchange prices on the NYMEX, over-the-counter quotations,
volatility and the time value of options. The calculation of the fair value of
collars and floors requires the use of the Black-Scholes option-pricing model.
On the date that the Company enters into a derivative contract, it designates
the derivative as a hedge of the variability in cash flows associated with the
forecasted sale of its oil and gas production. Changes in the fair value of a
derivative that is highly effective and is designated and qualifies as a cash
flow hedge, to the extent that the hedge is effective, are recorded in other
comprehensive income (loss), until earnings are affected by the variability of
cash flows of the hedged transaction (e.g., until the sale of the Company's oil
and gas production is recorded in earnings). Such gains or losses are reported
in oil and gas revenues on the consolidated statement of income.

The Company expects that within the next twelve months it will reclassify
to earnings $48.6 million in after tax gains out of the net $24.9 million in
after tax gains recorded in accumulated other comprehensive income at December
31, 2001.

Any hedge ineffectiveness (which represents the amount by which the change
in the fair value of the derivative exceeds the change in the cash flows of the
forecasted transaction) is recorded in current-period earnings. For the year
ended December 31, 2001, the Company recorded an unrealized gain of $24.8
million under the income statement caption "Unrealized commodity derivative
income," which primarily represents the change in the time value component of
the option contracts used in the Company's hedging strategy.

The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk-management objective and
strategy for undertaking various hedge transactions. This process includes
linking all derivatives that are designated as cash flow hedges to the specific
forecasted sale of oil or gas at its physical location. The Company also
formally assesses (both at the hedge's inception and on an ongoing basis)
whether the derivatives that are used in hedging transactions have been highly
effective in offsetting changes in the cash flows of hedged items and whether
those derivatives may be expected to remain highly effective in future periods.
If it is determined that a derivative is not (or has ceased to be) highly
effective as a hedge, the Company will discontinue hedge accounting
prospectively. The gain or loss on the derivative will remain in accumulated
other comprehensive income or loss and will be reclassified into earnings when
the forecasted transaction affects earnings. If hedge accounting is discontinued
and the derivative remains outstanding, the Company will carry the derivative at
its fair value on the balance sheet, recognizing all subsequent changes in the
fair value in current-period earnings. Hedge accounting was not discontinued
during the period for any hedging instruments.

51

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NATURAL GAS

As of December 31, 2001, the Company held the commodity derivative
instruments set forth in the table below as a cash flow hedges of the forecasted
sale of its U.S. Gulf Coast natural gas production for 2002 and 2003.

In connection with the acquisition of Lariat in January 2001, the Company
assumed certain commodity derivative instruments and designated them as cash
flow hedges of the forecasted natural gas sales of its production in Oklahoma.
The table below presents the outstanding derivative instruments relating to
Oklahoma production as of December 31, 2001.

52

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2000, the Company held the commodity derivative
instruments set forth in the table below as a cash flow hedges of the forecasted
sale of its U.S. Gulf Coast natural gas production for 2001 and 2002.

OIL

As of December 31, 2001, the Company held the commodity derivative
instruments set forth in the table below as a cash flow hedges of the forecasted
sale of its U.S. Gulf Coast oil production for 2002 and 2003.

53

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2000, the Company held the commodity derivative
instruments set forth in the table below as a cash flow hedges of the forecasted
sale of its U.S. Gulf Coast oil production for 2001 and 2002.

4. ACCRUED LIABILITIES:

Accrued liabilities consisted of the following:

54

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

5. DEBT:

Long-term debt consisted of the following:

At December 31, 2001 and 2000, the interest rate was 3.25% and 7.22%,
respectively, for LIBOR based loans and 3.00% and 7.31%, respectively, for the
loans outstanding under the money market lines of credit.

On February 22, 2001, the Company placed $175 million of 7 5/8% Senior
Notes due 2011. The offering was done under an existing shelf registration
statement. Net proceeds from the sale of the senior notes were used to repay
outstanding indebtedness under the Company's revolving credit facility. The
notes were issued at 99.931% of par to yield 7.635%, with interest payable on
each March 1 and September 1, commencing September 1, 2001. The estimated fair
market value of the 7 5/8% Senior Notes due 2011, based on quoted market prices
at December 31, 2001 was $173.0 million.

The estimated fair market value of the 7.45% Senior Notes due 2007, based
on quoted market prices at December 31, 2001 and 2000, was $126.3 million and
$114.0 million, respectively. Debt outstanding under the bank revolving credit
facility and money market lines of credit are stated at cost, which approximates
fair market value.

At December 31, 2001, the Company maintained its reserve-based revolving
credit facility with Chase Manhattan Bank, as agent. The banks participating in
the facility have committed to lend the Company up to $425 million. The amount
available under the facility is subject to a calculated borrowing base
determined by banks holding 75% of the aggregate commitments. The borrowing base
is reduced by the aggregate outstanding principal amount of any senior notes
issued by the Company (currently $300 million). The borrowing base will be
redetermined at least semi-annually and, after reduction for the outstanding
senior notes, was $210 million at December 31, 2001. No assurances can be given
that the banks will not elect to redetermine the borrowing base in the future.
The facility contains restrictions on the payment of dividends and the
incurrence of debt as well as other customary covenants and restrictions. The
facility matures on January 23, 2004.

The Company also has money market lines of credit with various banks in an
amount limited by the revolving credit facility to $40 million. At December 31,
2001, the Company had outstanding borrowings under the revolving credit facility
of $120 million and $9 million of outstanding borrowings under the money market
lines of credit. Consequently, at December 31, 2001, the Company had
approximately $81 million of available capacity under its credit arrangements.

55

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company's current and previous credit facilities provide or provided
for the payment of a commitment fee and a standby fee. The Company paid fees of
approximately $397,000, $315,000 and $336,000 for the years ended December 31,
2001, 2000 and 1999, respectively.

6. CONVERTIBLE PREFERRED SECURITIES OF NEWFIELD FINANCIAL TRUST I:

In August 1999, Newfield Financial Trust I, a Delaware business trust and
wholly owned subsidiary of the Company (the "Trust"), issued, in an underwritten
public offering, $143,750,000 (2,875,000 securities having a liquidation
preference of $50 each) of 6.5% Cumulative Quarterly Income Convertible
Securities, Series A (the "Trust Preferred Securities"). The proceeds of the
issuance of the Trust Preferred Securities were used to purchase $143,750,000 of
the Company's 6.5% Junior Subordinated Convertible Debentures, due 2029 (the
"Debentures"). The interest terms and payment dates of the Debentures correspond
to those of the Trust Preferred Securities. The Company's obligations under the
Debentures and related agreements, when taken together, constitute a full and
unconditional guarantee of payments due on the Trust Preferred Securities. The
sole asset of the Trust is the Debentures. The Trust has no independent
operations. The Debentures are eliminated in the consolidated financial
statements.

The Trust Preferred Securities accrue and pay distributions quarterly in
arrears at a rate of 6.5% per annum on the stated liquidation amount of $50 per
Trust Preferred Security on February 15, May 15, August 15, and November 15 of
each year to holders of record 15 business days immediately preceding the
distribution payment date. The Company may on one or more occasions defer the
payment of interest on the Debentures for up to 20 consecutive quarterly periods
unless an event of default on the Debentures has occurred and is continuing.
During any such deferral period, the Trust will defer the payment of
distributions, but accrued distributions on the Trust Preferred Securities will
compound quarterly and the Company will generally not be permitted to declare or
pay any dividends or distributions on, or redeem or acquire, any of its capital
stock or make any payment of principal or interest on any debt securities that
rank equal or junior to the Debentures.

The Trust Preferred Securities are convertible at the option of the holder
at any time into common stock of the Company at the rate of 1.3646 shares of
Company common stock per Trust Preferred Security. This conversion rate is
subject to adjustment for certain dilutive events and is currently equivalent to
a conversion price of $36.64 per share of Company common stock. The Trust
Preferred Securities are mandatorily redeemable upon maturity of the Debentures
on August 15, 2029, and on a proportionate basis to the extent of any earlier
redemption of any Debenture by the Company. The Debentures are redeemable by the
Company at any time after August 15, 2002.

The estimated fair market value of the Trust Preferred Securities at
December 31, 2001 and 2000, based on quoted market prices, was $155.3 million
and $207.0 million, respectively.

7. INCOME TAXES:

Income before income taxes is composed of the following:

56

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The total provision for income taxes consists of the following:

The components of deferred tax assets and liabilities are as follows:

U.S. deferred taxes have not been provided on foreign income of $41.3
million that is permanently reinvested in Australia. The Company currently does
not have any foreign tax credits available to reduce U.S. taxes on such income
if it was repatriated.

As of December 31, 2001, the Company had net operating loss ("NOL")
carryforwards for federal income tax purposes of approximately $40.7 million
that may be used in future years to offset taxable income. Utilization of the
Company's NOL carryforwards are subject to annual limitations due to certain
stock ownership changes. To the extent not utilized, the NOL carryforwards will
begin to expire in 2021.

8. TREASURY STOCK:

On May 4, 2001, the Company announced that its Board of Directors
authorized the expenditure of up to $50 million to repurchase shares of the
Company's common stock. As of December 31, 2001, the Company had repurchased
823,000 shares of its common stock under this program for total consideration of
$24.7 million, an average of $29.97 per share. Additional repurchases may be
effected from time to time in accordance with applicable securities laws through
solicited or unsolicited transactions in the market or in

57

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

privately negotiated transactions. No limit was placed on the duration of the
repurchase program. Subject to applicable securities laws, such purchases will
be at times and in amounts as the Company deems appropriate.

9. COMMITMENTS AND CONTINGENCIES:

The Company has entered into a non-cancellable operating leases for office
space in Houston, Texas, Tulsa, Oklahoma and Perth, Australia. In addition, the
Company enters into various other equipment leases as part of its operations.

Future minimum lease payments required as of December 31, 2001 related to
these operating leases are as follows:

Rent expense for the years ended December 31, 2001, 2000 and 1999 was $4.1
million, $3.2 million and $2.8 million, respectively.

The Company has been named as a defendant in certain lawsuits arising in
the ordinary course of business. While the outcome of these lawsuits cannot be
predicted with certainty, management does not expect that these matters will
have a material adverse effect on the financial position, cash flows or results
of operations of the Company.

10. STOCK-BASED COMPENSATION:

The Company has several stock-based compensation plans, each of which is
described below. The Company applies APB Opinion No. 25 and related
interpretations in accounting for its stock-based compensation plans.

OMNIBUS STOCK PLANS

The Company has granted stock options and shares of restricted stock under
its several stock option and omnibus stock plans (collectively, the "Omnibus
Stock Plans").

58

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following is a summary of all stock option activity for 1999, 2000 and
2001:

Options that have been granted and are outstanding generally expire 10
years from the date of grant and become exercisable at the rate of 20% per year.
If additional options are granted under the Omnibus Stock Plans, the exercise
price will not be less than the fair market value per share of the Company's
common stock on the date of grant. The weighted average fair value of an option
to purchase one share of common stock granted during 2001, 2000 and 1999 was
$16.08, $15.41 and $12.68, respectively.

The fair value of each stock option granted is estimated as of the date of
grant using the Black-Scholes option-pricing model with the following weighted
average assumptions for grants in 2001, 2000 and 1999: no dividend yield for all
years; expected volatility of 34.20%, 34.87% and 33.77%, respectively; risk-free
interest rates of 5.0%, 6.76% and 5.97%, respectively; and an expected option
life of 6.5 years for all years.

The following table summarizes information about stock options outstanding
and exercisable at December 31, 2001:

Common stock issued through the exercise of non-qualified stock options
results in a tax deduction for the Company equivalent to the compensation income
recognized by the option holder. For financial reporting

59

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

purposes, the tax effect of this deduction is accounted for as a credit to
additional paid-in capital rather than as a reduction of income tax expense. The
exercise of stock options during 2001, 2000 and 1999 resulted in a deferred tax
benefit to the Company of approximately $2.1 million, $6.6 million and $8.0
million, respectively.

Pursuant to the Omnibus Plans, the Company granted 111,100, 93,506, and
29,000 restricted shares of common stock in 2001, 2000 and 1999, respectively.
The restricted shares fully vest after nine years, but vesting may be
accelerated if certain performance-based criteria are met. At December 31, 2001,
there were 236,700 shares of common stock outstanding that were subject to
restrictions. In addition to the foregoing grants of restricted shares, the
Company grants restricted shares of its common stock to non-employee directors
pursuant to the plan described below. In accordance with APB Opinion No. 25, the
Company recognized unearned compensation for the fair value of restricted shares
of common stock granted pursuant to the Omnibus Plans and the Non-Employee
Director Plan in the amount of $4.3 million for 2001, $3.0 million for 2000 and
$1.0 million for 1999. This amount is charged to stockholders' equity and
recognized as compensation expense over the applicable vesting period, in the
amount of $2.1 million for 2001, $1.8 million for 2000 and $0.9 million for
1999. The weighted average price for 118,468 shares of restricted common stock
issued in 2001 is $36.29. The weighted average price for 98,756 shares of
restricted common stock issued in 2000 is $30.56. The weighted average price for
37,211 shares of restricted common stock issued in 1999 is $27.75.

At December 31, 2001, the Company had an additional 716,764 shares
available for issuance pursuant to the Omnibus Stock Plans. Of such shares, only
99,739 may be granted as restricted stock.

NON-EMPLOYEE DIRECTOR RESTRICTED STOCK PLAN

Under the Newfield Exploration Company 2000 Non-Employee Director
Restricted Stock Plan (the "Non-Employee Director Plan"), subject to a maximum
of 50,000 shares, each non-employee director who is in office immediately after
each annual meeting of stockholders of the Company shall, unless electing to not
participate, receive a number of restricted shares determined by dividing
$30,000 by the fair market value on the date of the annual meeting of
stockholders, subject to the terms of the plan. The forfeiture restrictions with
respect to all restricted shares granted since the last annual meeting of
stockholders lapse on the day before the first annual meeting of stockholders
following the date of issuance of such shares, provided that the holder remains
a director until such time. The Company issued 7,368 shares to eight
non-employee directors in 2001 pursuant the Non-Employee Director Plan. The
Company issued 5,250 shares to seven non-employee directors in 2000 and 8,211
shares to seven non-employee directors in 1999 pursuant to a predecessor plan
with terms substantially similar to the current plan.

EMPLOYEE STOCK PURCHASE PLAN

Pursuant to the Company's employee stock purchase plan, for each six month
period beginning on January 1 or July 1 during the term of the plan, each
eligible employee has the opportunity to purchase common stock for a purchase
price equal to 85% of the lesser of the fair market value of the common stock on
the first day of the period or the last day of the period. No employee may
purchase common stock under the plan valued at more than $25,000 in any calendar
year.

At December 31, 2001, 171,059 shares of common stock were available for
issuance pursuant to the stock purchase plan. Under the plan, the Company has
sold 28,941 shares, 22,180 shares and 24,945 shares to employees in 2001, 2000
and 1999, respectively, at weighted average prices of $27.16, $26.75 and $19.73,
respectively. In accordance with APB Opinion No. 25 and related interpretations,
the Company has not recognized any compensation expense with respect to the
plan.

The weighted average fair value of the option to purchase stock during
2001, 2000 and 1999 was $9.86, $8.87 and $6.34, respectively. The fair value of
each option granted under the stock purchase plan is estimated

60

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

on the date of grant using the Black-Scholes option-pricing model with the
following weighted average assumptions for grants in 2001, 2000 and 1999: no
dividend yield for all years; expected volatility of 25.02%, 37.86% and 33.77%,
respectively; risk-free interest rates of 4.36%, 5.73% and 4.78%, respectively;
and an expected option life of six months for all years.

PRO FORMA NET INCOME AND NET INCOME PER COMMON SHARE

If the fair value based method of accounting in SFAS No. 123, "Accounting
for Stock-Based Compensation," had been applied, the Company's net income and
earnings per common share for 2001, 2000 and 1999 would have approximated the
pro forma amounts below:

The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. The Company anticipates making awards in the
future under its stock-based compensation plans.

11. EMPLOYEE BENEFIT PLANS:

The Company sponsors a 401(k) Profit Sharing Plan (the "401(k) Plan") under
Section 401(k) of the Internal Revenue Code. This plan covers all employees of
the Company other than employees of the Company's Australian subsidiaries. The
Company matches $1.00 for each $1.00 of employee deferral, with the Company's
contribution not to exceed 8% of an employee's salary, subject to limitations
imposed by the Internal Revenue Service. The Company's contributions to the
401(k) Plan totaled $1,278,000, $714,000 and $605,000 for the years ended
December 31, 2001, 2000 and 1999, respectively.

The Company also sponsors the Newfield Employee 1993 Incentive Compensation
Plan (the "Incentive Plan"), a non-qualified plan. The Incentive Plan provides
for the creation each calendar year of an award pool that, in general, is equal
to the revenues that would be attributable to a 1% overriding royalty interest
on acquired producing properties and a 2% overriding royalty interest on
exploration properties, bearing on both the interest of the Company and certain
investors that participated in the Company's activities in such properties. If,
for a particular year, the portion of the pool that relates to the Company's
interests is in excess of 5% of the Company's adjusted net income (as defined in
the plan) for that year, such excess may not be awarded to employees. The
Incentive Plan is administered by the Compensation Committee of the Board of
Directors with award amounts recommended by the Chief Executive Officer of the
Company. All employees of the Company are eligible for awards if employed on
both October 1 and December 31 of the performance period. Awards may have both a
current and a deferred component of compensation. Eligible employees may elect
for all or a portion of deferred awards to be paid in common stock instead of
cash. In such case, the number of shares of common stock to be awarded is
determined by using the fair market value of common stock on the date of the
award. Deferred Awards are paid in four annual installments, each installment
consisting of 25% of the deferred award, plus interest on awards paid in cash.
Total expense under the

61

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Incentive Plan for the years ended December 31, 2001, 2000 and 1999 was $11.6
million, $12.8 million and $3.9 million, respectively.

During 1997, the Company implemented a highly compensated employee Deferred
Compensation Plan (the "Deferred Plan"). This non-qualified plan allows an
eligible employee to defer a portion of the employee's salary or bonus on an
annual basis. The Company matches $1.00 for each $1.00 of employee deferral,
with the Company's contribution not to exceed 8% of an employee's salary,
subject to limitations imposed by the Deferred Plan. The Company's contribution
is reduced by the amount of contribution made by the Company to the 401(k) Plan
for each participant. The Company's contributions to the Deferred Plan totaled
$37,000, $29,000 and $34,000 for the years ended December 31, 2001, 2000 and
1999, respectively.

12. STOCKHOLDER RIGHTS PLAN:

In 1999, the Company adopted a stockholder rights plan. The plan is
designed to ensure that all stockholders of the Company receive fair and equal
treatment in the event of a proposed takeover of the Company. It includes
safeguards against partial or two-tiered tender offers, squeeze-out mergers and
other abusive takeover tactics.

The plan provides for the issuance of one right for each outstanding share
of the Company's common stock. The rights will become exercisable only if a
person or group acquires 20% or more of the Company's outstanding voting stock
or announces a tender or exchange offer that would result in ownership of 20% or
more of the Company's voting stock.

Each right will entitle the holder to buy one one-thousandth (1/1000) of a
share of a new series of junior participating preferred stock at an exercise
price of $85 per right, subject to antidilution adjustments. Each one
one-thousandth of a share of this new preferred stock has the dividend and
voting rights of, and is designed to be substantially equivalent to, one share
of common stock. The Company's Board of Directors may, at its option, redeem all
rights for $0.01 per right at any time prior to the acquisition of 20% or more
of the Company's stock by a person or group.

If a person or group acquires 20% or more of the Company's outstanding
voting stock, each right will entitle holders, other than the acquiring party,
to purchase common stock of the Company having a market value of $170 for a
purchase price of $85, subject to antidilution adjustments.

The plan also includes an exchange option. If a person or group acquires
20% or more, but less than 50% of the outstanding voting stock, the Board of
Directors may at its option exchange the rights in whole or part for shares of
common stock of the Company. Under this option, the Company would issue one
share of common stock, or one one-thousandth of a share of new preferred stock,
for each two shares of common stock for which a right is then exercisable. This
exchange would not apply to rights held by the person or group holding 20% or
more of the Company's voting stock.

If, after the rights have become exercisable, the Company merges or
otherwise combines with another entity, or sells assets constituting more than
50% of its assets or producing more than 50% of its earning power or cash flow,
each right then outstanding will entitle its holder to purchase for $85, subject
to antidilution adjustments, a number of the acquiring party's common shares
having a market value of twice that amount.

This plan will not prevent, nor is it intended to prevent, a takeover of
the Company. Since the rights may be redeemed by the Board under certain
circumstances, they should not interfere with any merger or other business
combination approved by the Board. The issuance of the rights does not in any
way diminish the financial strength of the Company or interfere with its
business plans. The issuance of the rights has no dilutive effect, does not
affect reported earnings per share or change the way the common stock of the
Company is currently traded.

62

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. PROPERTY ACQUISITIONS:

On January 23, 2001, the Company acquired all of the outstanding capital
stock of Lariat Petroleum, Inc. ("Lariat") by merging Lariat with and into
Newfield Exploration Mid-Continent Inc., a wholly owned subsidiary of the
Company. The total consideration for the acquisition was approximately $333
million, inclusive of the assumption of debt and certain other obligations of
Lariat. The consideration included the issuance of approximately 1.9 million
shares of the Company's common stock valued at $68 million. For financial
accounting purposes, the Company allocated $438 million to oil and gas
properties which included a $105 million step-up associated with deferred income
taxes.

In February 2000, the Company acquired interests in three producing gas
fields in South Texas for approximately $139 million in cash.

The acquisitions have been accounted for as purchases and, accordingly,
income and expenses for Lariat and from the South Texas properties have been
included in the Company's statement of income from the date of purchase.

The unaudited pro forma results of operations assuming that such
acquisitions had occurred on January 1, 2000 are as follow (in thousands, except
per share amounts):

The pro forma financial information does not purport to be indicative of
the results of operations that would have occurred had the acquisitions taken
place at January 1, 2000 or future results of operations.

63

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

14. GEOGRAPHIC INFORMATION:

64

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

65

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) General and administrative expense includes non-cash stock compensation
charges of $2,751, $3,047 and $1,999 for 2001, 2000 and 1999, respectively.

15. SUPPLEMENTAL CASH FLOW INFORMATION:

16. RELATED PARTY TRANSACTIONS:

Prior to the acquisition of Lariat in January of 2001, Warburg, Pincus
Ventures, L.P. ("WPV") owned approximately 88% of the outstanding capital stock
of Lariat on a fully diluted basis. In conjunction with the acquisition of
Lariat by Newfield, WPV received cash proceeds of approximately $78.6 million
and 1,864,735

66

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

shares of common stock of the Company in the merger. In addition,
contemporaneously with the merger, WPV received approximately $39.1 million as
repayment in full of notes payable by Lariat to WPV. Pursuant to the merger
agreement, the Company is entitled, subject to certain limitations, to
indemnification for certain customary matters from the former stockholders of
Lariat, including WPV. The sole general partner of WPV is Warburg, Pincus & Co.
("WP & Co."). E.M. Warburg, Pincus & Co. ("EMW LLC"), manages WPV. Howard H.
Newman, a director of the Company, is a managing director and a member of EMW
LLC and a general partner of WP & Co.

Terry Huffington, a director of the Company, is a principal owner of Huffco
International L.L.C. ("Huffco") and David A. Trice, President and Chief
Executive Officer of the Company, is a minority owner of Huffco. In May 1997,
prior to Ms. Huffington and Mr. Trice becoming affiliated with the Company, the
Company acquired substantially all of the assets of Huffco. The acquired assets
included all of the outstanding common stock of Huffco China, LDC, now known as
Newfield China, LDC ("Newfield China"), the owner of an undivided 35% interest
in a production sharing contract area in Bohai Bay, offshore the People's
Republic of China. Huffco retained preferred shares of Newfield China that
provide for an aggregate dividend equal to 10% of the excess of proceeds
received by Newfield China from the sale of oil, gas and other minerals over all
costs incurred with respect to exploration and production in Block 05/36, Bohai
Bay, plus an allocated portion of the cash purchase price paid by the Company to
Huffco at the closing of the Huffco Transaction. At December 31, 2001, Newfield
China had approximately $31 million in unrecovered costs, no reserves and no
revenue and, as a result, no dividends have been paid to date on the preferred
shares. Huffco also has the right to further payments upon the occurrence of
certain events. If the Company acquires an interest in two particular blocks
offshore Cote de Ivoire on or before May 15, 2002, the Company will pay Huffco
$2,620,000, subject to certain adjustments if the Company sells such interest to
a third party under certain circumstances. The Company has not acquired an
interest in either of the two blocks. In addition, if the Company commits to a
development program in the Federal Republic of Nigeria on or before May 15,
2002, the Company will pay Huffco $1,000,000. The Company has not committed to a
development program nor any other project in Nigeria.

In the normal course of business, the Company purchases oil field goods,
equipment and services from companies that have one or two common board members
with the Company. The Company believes that the charges and fees that it pays
for such goods, equipment and services are competitive with the charges and fees
of other companies providing such items.

17. NEWFIELD FINANCIAL TRUST II:

Pursuant to a Form S-3 registration statement filed with the SEC under the
Securities Act of 1933, Newfield Financial Trust II, a "100% owned," "finance
subsidiary" (in each case, as defined in Rule 3-10 of Regulation S-X) of the
Company ("Trust II"), may offer and sell its preferred securities to the public.
If issued and sold, the holders of the trust preferred securities would be
entitled to receive periodic payments that are cumulative if unpaid, would be
entitled to receive a fixed liquidation amount and the backup undertakings will
provide a bundle of rights that together place the holder in the same position
as if the Company had fully and unconditionally guaranteed Trust II's payment
obligations on the trust preferred securities.

67

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

18. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):

The results of operations by quarter for the years ended December 31, 2001
and 2000 are as follows:

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

(1) In the fourth quarter of 2001, the Company recorded an impairment in
accordance with the full cost accounting rules of $106 million ($68 million
after-tax).

68

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED

See Note 14 to the consolidated financial statements for disclosure of the
Company's results of operations from oil and gas producing activities. Costs
incurred for oil and gas property acquisition, exploration and development
activities for each of the three years in the period ended December 31, 2001 are
as follows:

69

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)

Capitalized costs for oil and gas producing activities consist of the
following at the end of each of the three years in the period ended December 31,
2001:

Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including additional development activity, evolving
production history and continual reassessment of the viability of production
under varying economic conditions. Consequently, material revisions to existing
reserve estimates occur from time to time. Although every reasonable effort is
made to ensure that reported reserve estimates represent the most accurate
assessments possible, the significance of the subjective decisions required and
variances in available data for various reservoirs make these estimates
generally less precise than other estimates presented in connection with
financial statement disclosures.

70

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)

ESTIMATED NET QUANTITIES OF OIL AND GAS RESERVES

The following table sets forth the Company's net proved reserves (at 14.73
pounds per square inch absolute), including the changes therein, and proved
developed reserves at the end of each of the three years in the period ended
December 31, 2001, as estimated by the Company's petroleum engineering staff:

71

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES

The following information was developed utilizing procedures prescribed by
SFAS No. 69, "Disclosures about Oil and Gas Producing Activities," and is based
on natural gas and crude oil reserve and production volumes estimated by the
Company's petroleum engineering staff. It may be useful for certain comparative
purposes, but should not be solely relied upon in evaluating the Company or its
performance. Further, information contained in the following table should not be
considered as representative of realistic assessments of future cash flows, nor
should the Standardized Measure of Discounted Future Net Cash Flows be viewed as
representative of the current value of the Company.

The Company believes that in reviewing the information that follows the
following factors should be taken into account: (1) future costs and selling
prices will probably differ from those required to be used in these
calculations; (2) due to future market conditions and governmental regulations,
actual rates of production achieved in future years may vary significantly from
the rates of production assumed in the calculations; (3) a 10% discount rate may
not be reasonable as a measure of the relative risk inherent in realizing future
net oil and gas revenues; and (4) future net revenues may be subject to
different rates of income taxation.

Under the Standardized Measure, future cash inflows were estimated by
applying year-end oil and gas prices, adjusted for location and quality
differences, to the estimated future production of year-end proved reserves.
Future cash inflows were reduced by estimated future development, abandonment
and production costs based on year-end costs in order to arrive at net cash flow
before tax. Future income tax expense has been computed by applying year-end
statutory tax rates to aggregate future pre-tax net cash flows, for each year
reduced by the tax basis of the properties involved and tax carryforwards. Use
of a 10% discount rate and year-end prices and costs are required by SFAS 69.

In general management does not rely on the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as proved reserves and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.

72

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)

The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows:

73

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)

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

74

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)

75

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

PART III

For information concerning Item 10 -- Directors and Executive Officers of
the Registrant, Item 11 -- Executive Compensation, Item 12 -- Security Ownership
of Certain Beneficial Owners and Management and Item 13 -- Certain Relationships
and Related Transactions, please see our definitive Proxy Statement for our
Annual Meeting of Stockholders to be held on May 2, 2002 which has been filed
with the SEC and is incorporated herein by reference, and "Part I -- Item 4A.
Executive Officers."

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(A) 1. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following financial statements and the report of our management and
independent accountants thereon are included in this report:

Management Report on Financial Statements

Report of Independent Accountants

Consolidated Balance Sheet as of the fiscal years ended December 31, 2001
and 2000

Consolidated Statement of Income for each of the three years in the period
ended December 31, 2001

Consolidated Statement of Stockholders' Equity for each of the three years
in the period ended December 31, 2001

Consolidated Statement of Cash Flows for each of the three years in the
period ended December 31, 2001

Notes to the Consolidated Financial Statements

Unaudited Supplementary Oil and Gas Disclosures

2. FINANCIAL STATEMENT SCHEDULES

Financial statement schedules listed under SEC rules but not included in
this report are omitted because they are not applicable or the required
information is provided in the notes to the financial statements.

76

3. EXHIBITS

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

* Filed herewith.

+ Identifies management contracts and compensatory plans or arrangements.

(b) Reports on Form 8-K

On October 4, 2001, we filed a Current Report on Form 8-K to file the
financial statements of Lariat Petroleum for the year ended December 31, 2000
and the pro forma combined financial statements of Lariat Petroleum and Newfield
for the year ended December 31, 2000 and the six months in the period ended June
30, 2001 and to re-file Newfield's audited consolidated financial statements as
of December 31, 2000 and 1999 and for each of the three years in the period
ended December 31, 2000 for the sole purpose of adding a new Note 16.

On October 9, 2001, we filed a current report on Form 8-K announcing the
curtailment of a small portion of our fourth quarter 2001 natural gas production
and the deferral of some capital projects.

79

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 7th day of
March, 2002.

NEWFIELD EXPLORATION COMPANY

By: /s/ DAVID A. TRICE
------------------------------------
David A. Trice
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 the
registrant in the capacities indicated and on the 7th day of March, 2002.

81

INDEX TO EXHIBITS

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

* Filed herewith.

+ Identifies management contracts and compensatory plans or arrangements.