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, 2002

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 EAST, 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. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [ ]

The aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant was approximately $1,205,061,000 as of June
30, 2002 (based on the last sale price of such stock as quoted on the New York
Stock Exchange).

As of March 14, 2003, there were 52,049,875 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 1,
2003, which is incorporated by reference 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

We are 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 primary areas of operation now include the
U.S. onshore Gulf Coast, West Texas, the Anadarko Basin and offshore northwest
Australia. Over the last two years, we have acquired significant onshore assets.
Today, more than half of our reserves are located onshore in the U.S.

General information about us can be found at www.newfld.com. Our Annual
Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form
8-K, as well as any amendments and exhibits to those reports, are available free
of charge through our website as soon as reasonably practicable after we file or
furnish them to the SEC.

At year-end 2002, we had proved reserves of 1.2 Tcfe. Of those reserves:

- 81% were natural gas;

- 93% were proved developed;

- 44% were located in the Gulf of Mexico;

- 54% were located onshore in the U.S.; and

- 2% were located offshore Australia.

STRATEGY

The elements of our growth strategy have remained substantially unchanged
since our founding and consist of:

- balancing our efforts among exploration, the acquisition of proved
reserves and the development of proved properties;

- growing reserves through the drilling of a balanced risk/reward
portfolio;

- 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.

BALANCE. We actively pursue the acquisition of proved oil and gas
properties in our existing focus areas and other select geographic areas. The
potential to add reserves through the drillbit is a critical consideration in
our acquisition screening process. Each year we invest a significant portion of
our capital budget in exploration. We also actively look for new drilling ideas
on our existing property base and on properties that may be acquired at federal
lease sales or by farm-in. Our recent large acquisitions and drilling success
provide us with significant development potential.

DRILLING PROGRAM. The reserves targeted by our drilling program are
distributed throughout the risk/reward spectrum. In an effort to manage the
risks associated with our strategy to grow our reserves through the drillbit,
each year we drill a greater number of lower risk, low to moderate potential
prospects and a lesser number of higher risk, higher potential prospects. We
have recently complemented our traditional drilling activities on the Gulf of
Mexico shelf with two higher potential plays in the Gulf of Mexico -- the deep
shelf and deepwater.

GEOGRAPHIC FOCUS. We believe that our long-term success requires extensive
knowledge of the 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 and have a significant
influence on operations. We also believe that geographic focus allows us to make
the most efficient use of our capital and personnel.

CONTROL OF OPERATIONS AND COSTS. In general, 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 2002, we
operated about 80% 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,
2003, 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 1,000 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, 350 square kilometers covering the
area where we are active offshore China and 17,280 square kilometers in the
North Sea. We are planning to shoot 200 square kilometers of seismic on our
license area offshore Brazil in late 2003.

EQUITY OWNERSHIP AND INCENTIVE COMPENSATION. We want our employees to act
like owners. To achieve this, we reward and encourage them through equity
ownership and incentive compensation based on performance and profitability. A
significant portion of our employees' compensation is discretionary and
performance-based. As of February 28, 2003, our employees owned or had options
to acquire no less than 10% of our outstanding common stock on a fully diluted
basis.

EEX ACQUISITION

Our most significant event in 2002 was the acquisition of EEX Corporation,
which closed in late November 2002. At closing, we booked 288 Bcfe of proved
reserves as a result of the acquisition. These reserves are concentrated in
South Texas. The EEX properties are very complementary to our previously
existing South Texas property base. The acquisition tripled our acreage position
in South Texas and we now rank as one of the largest producers in the area. We
also acquired interests in approximately 60,000 gross mineral acres in southern
Louisiana, about 60 lease blocks in the deepwater Gulf of Mexico and 26 lease
blocks in shallow water associated with an "ultra-deep" (greater than 20,000
feet) exploration concept known as "Treasure Island."

FOCUS AREAS

GULF OF MEXICO. We have extensive experience in the Gulf of Mexico and it
is where we continue to invest the largest portion of our capital program. The
Gulf of Mexico 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.

We expect to remain one of the most active drillers in the traditional
shallow water plays of the Gulf of Mexico. Our activities here will be
complemented by higher risk, higher potential plays in two areas -- the

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deep shelf and deepwater. We also are evaluating the Treasure Island concept.
The ultra-deep targets of this concept are high risk but the potential reserve
impact could be significant.

Traditional Shelf. We consider the traditional shelf generally to be
horizons at depths of less than 13,000-15,000 feet located in water depths of
generally less than 1,000 feet. We operate about 150 production platforms and
utilize this infrastructure to our advantage. Although prospects in the
traditional shelf usually offer modest reserve potential, the risks associated
with these prospects generally are lower.

Deep Shelf. We are exploring deeper horizons on the shelf with recent
wells drilled to depths of 15,000-20,000 feet. We have drilled five successful
deep shelf wells out of eight attempts to date. Our early success in this play
is encouraging; however the risk profile of these wells is significantly
different than our traditional shelf drilling. Deeper targets are more difficult
to detect with traditional seismic processing. Drilling expense and the risk of
mechanical failure for these wells are likely to be significantly higher because
of the additional drilling depth and conditions such as high temperature and
pressure.

Deepwater. We established a deepwater team in 2001. The risks associated
with deepwater operations can be significantly greater than traditional shelf
operations. Drilling and development costs may be materially higher and lead
times to first production may be much longer. We are focusing on projects near
infrastructure and in water depths where development technology is proven. As
our knowledge and experience base advances, we will consider moving into deeper
waters, toward larger targets and into more remote regions where infrastructure
may not exist. Following our acquisition of EEX, we now own an interest in more
than 60 deepwater lease blocks in the Gulf of Mexico. We also have made some
personnel additions to give us additional expertise in this new effort.

ONSHORE GULF COAST. We established onshore Gulf Coast operations in 1995.
The onshore Gulf Coast is a major focus area for us today, representing about
one-third of our total proved reserves and daily production. Our operations are
concentrated in South Texas, South Louisiana and the Val Verde Basin in West
Texas. Because much of the onshore Gulf Coast has geologic features similar to
the Gulf of Mexico, our onshore program benefits from our significant expertise
and knowledge base in the Gulf. Over the last two years, we have made
significant investments in seismic data. We continue to screen for attractive
acquisitions to further expand this focus area.

MID-CONTINENT. Through an acquisition in January 2001, we added the
Mid-Continent as a focus area. About 90% of our proved reserves in the
Mid-Continent are located in the Anadarko Basin of Oklahoma. These assets are
typically longer-lived and offset our shorter reserve life properties in the
Gulf Coast region. We believe that the Anadarko Basin provides an opportunity
for future growth. It is a gas-rich province characterized by multiple
productive zones and relatively low drilling costs. Like the Gulf of Mexico, it
is a mature basin, offering the potential to consolidate properties. We manage
our Mid-Continent assets from our Tulsa, Oklahoma office.

INTERNATIONAL. In the mid-1990s, we began to consider investment in select
international areas to provide additional or alternative opportunities and to
gain exposure to high potential prospects. We currently own an interest in two
undeveloped fields offshore China and two producing oil fields offshore
Australia. Our Australian operations are managed by our Perth, Australia office.
In 2002, we opened an office in London, England, to pursue opportunities in the
North Sea and were the successful bidder on a lease block offshore Brazil. We
continue to evaluate and pursue opportunities for expansion in select
international areas, particularly in the North Sea.

PLANS FOR 2003

Our capital budget for 2003 is $450 million, excluding acquisitions. We
expect that 55-60% of the budget will be invested in the Gulf of Mexico
(including deepwater), 35-40% in the onshore U.S. and the balance in
international projects. We plan to drill 100-150 wells in 2003, about half of
which will be exploratory.

GULF OF MEXICO. We plan to remain one of the most active drillers in the
traditional shallow water plays of the Gulf of Mexico. More than half of our
2003 capital budget is allocated to the Gulf of Mexico, where we

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expect to drill 25-35 wells. In addition to 18-25 wells in the traditional
shelf, we expect to drill eight to ten wells in the deep shelf and two or three
in deepwater.

ONSHORE GULF COAST. In 2003, we will balance development drilling of lower
risk opportunities with some higher risk, higher impact exploration tests. We
plan to drill 40-50 wells.

MID-CONTINENT. Our Mid-Continent drilling program is predominantly
comprised of lower risk development wells. In 2003, we expect to drill
approximately 40-60 wells.

INTERNATIONAL. We anticipate that the operator will elect in 2003 to drill
one additional appraisal well in each of the CFD 12-1 and CFD 12-1 South Fields
in Bohai Bay, offshore China. During 2003, we will continue to evaluate
development potential for these fields and for the Montara discovery offshore
Australia.

MARKETING

We market nearly all of our oil and gas production from the 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
at current market prices. 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 Note 1, "Organization and Summary of
Significant Accounting Policies -- Major Customers," 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.

EMPLOYEES

At February 28, 2003, we had 488 employees. We believe that our
relationships with our employees are satisfactory.

None of our 368 U.S. and U.K. employees is covered by a collective
bargaining agreement. We regularly utilize independent consultants and
contractors to perform various professional services, particularly in the areas
of acquisition evaluation, 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 120 employees located in Australia. Our Perth, Australia office
employs 25 people to manage our offshore operations. The remaining employees
work offshore on our FPSOs. These offshore employees are covered by collective
bargaining agreements. At February 28, 2003, there were no significant issues
outstanding under our collective bargaining 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.

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ITEM 2. PROPERTIES

CONCENTRATION

We have diversified our asset base over the last several years. About 44%
of our proved reserves are now located in the Gulf of Mexico compared to about
90% just five years ago. In total, 75% of our proved reserves are located in the
Gulf of Mexico and coastal regions. While our ten largest properties accounted
for approximately 32% of our equivalent proved reserves at year-end 2002, no
single property held more than 5% of our proved reserves or more than 4% of the
net present value of our proved reserves.

GULF OF MEXICO

Our properties are in water depths ranging from 45 to more than 6,000 feet.
As of December 31, 2002, we owned interests in more than 200 leases
(approximately 1.2 million gross acres) and about 310 gross wells. We operated
87% of our proved reserves at December 31, 2002.

U.S. ONSHORE GULF COAST

We have a significant acreage position along the Texas and Louisiana
Coasts. As of December 31, 2002, we owned an interest in nearly 375,000 gross
acres and about 435 gross wells. We operated 70% of our proved reserves at
December 31, 2002.

MID-CONTINENT

We have a sizeable presence in the Anadarko Basin, established with an
acquisition in early 2001. As of December 31, 2002, we owned an interest in
approximately 475,000 gross lease acres, 22,000 gross mineral acres and 1,500
gross wells. We operated about 75% of our proved reserves at December 31, 2002.

INTERNATIONAL

AUSTRALIA. In 1999, we acquired a 50% interest in two producing oil fields
(Jabiru and Challis) and two related FPSOs in the Timor Sea, offshore northwest
Australia. Although these fields are on natural decline, they have benefited
from our gas lift optimization program and have performed above our original
expectations. In late 2001, we acquired by farm-in a 50% interest in a license
area about 55 miles southwest of our producing fields. An existing discovery,
known as "Montara," is located on the license area. We drilled an appraisal well
on this discovery in mid-2002 that tested at a rate of 5,000 Bbls of oil per
day. We are evaluating development options for Montara and have not yet booked
any proved reserves to this field. In mid-2003, we expect to relinquish our
remaining exploration permits in Australia.

CHINA. We own a 35% interest in Block 05/36 in Bohai Bay, offshore China.
Our interest is subject to a 51% reversionary interest held by the Chinese
National Offshore Oil Company. The block covers more than 250,000 acres. There
currently is no production on the block. Since 2000, we have discovered two
fields on the block -- the CFD 12-1 and the CFD 12-1 South. We continue to
appraise the fields to determine if commercial oil reserves exist. In 2002, we
drilled two appraisal wells in the CFD 12-1 South Field, one of which was a dry
hole. The election to drill additional appraisal wells, the determination of
commerciality and, if warranted, the development of these non-operated fields,
are not within our complete control. We have not booked any proved reserves on
these fields to date.

5

PROVED RESERVES AND FUTURE NET CASH FLOWS

The following table shows our estimated net proved oil and gas reserves and
the present value of estimated future after-tax net cash flows related to such
reserves as of December 31, 2002. The present value of estimated future
after-tax net cash flows was prepared using year-end oil and gas prices adjusted
for the location and quality of the reserves, discounted at 10% per year.
Application of year-end prices, as adjusted for location and quality, resulted
in weighted average year-end oil and gas prices of $4.74 per Mcf for gas and
$29.90 per Bbl for oil. This calculation does not include the effects of
hedging.

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(1) For a description of how this measure is determined see "Unaudited
Supplementary Oil and Gas Disclosures -- Standardized Measure of Discounted
Future Net Cash Flows Relating to Proved Oil and Gas Reserves."

Actual quantities of recoverable oil and gas reserves and future cash flows
from those reserves most likely will vary from the estimates set forth above.
Reserve and cash flow estimates rely on interpretations of data and require many
economic assumptions that may turn out to be inaccurate. For a discussion of
these interpretations and assumptions, 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 AND DEVELOPMENT COSTS

The following table sets forth certain information regarding the costs
associated with finding, acquiring and developing our proved oil and gas reserve
additions in 2002.

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(1) Includes extensions, discoveries and other additions, revisions of previous
estimates and purchases of properties but excludes sales of properties.

(2) Not meaningful.

(3) Includes $8.3 million of costs associated with the appraisal of the Montara
discovery. Because development options for this discovery are still being
evaluated, no reserves have yet been booked.

(4) Includes $4.9 million of costs associated with our exploration efforts in
the Bohai Bay, offshore China.

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DRILLING ACTIVITY

The following table sets forth our drilling activity for each year in the
three-year period ended December 31, 2002.

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(1) We drilled one gross (0.5 net) appraisal well in Australia during 2002 and
one gross (0.4 net), four gross (1.6 net) and two gross (0.8 net) appraisal
wells in China during 2002, 2001 and 2000, respectively, that are not
included in the table because the commerciality of these wells had not been
determined as of December 31, 2002.

We were in the process of drilling six gross (4.5 net) exploratory wells and
four gross (2.9 net) developmental wells in the U.S. at December 31, 2002.

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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, 2002 and the location of, and
other information with respect to, those 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

We own 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 or licenses that have varying terms.
The following table shows certain information regarding our developed and
undeveloped lease acreage as of December 31, 2002.

The table below summarizes by year and geographic area our undeveloped
lease or license acreage scheduled to expire in the next five years. We own fee
mineral interests in 182,958 gross (77,245 net) undeveloped acres. These
interests do not expire.

10

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, often little
investigation of record title is 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, or affect the value, of the 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 have been named as a defendant in certain lawsuits in the ordinary
course of business. While the outcome of these lawsuits cannot be predicted with
certainty, we do not expect these matters to have a material adverse effect on
our financial position, cash flows or results of operations.

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

There were no matters submitted to a vote of our security holders during
the fourth quarter of 2002.

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth the names and ages (as of February 28, 2003)
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 our company 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.

DAVID F. SCHAIBLE was added to our Board of Directors in 2002.

BRIAN L. RICKMERS has served as Controller and Assistant Secretary since
May 2001. From February 2000 to May 2001, he served as Assistant Controller.
From December 1993, when Mr. Rickmers joined our company, until February 2000,
he served as an Accountant and Financial Analyst.

SUSAN G. RIGGS was named to her present position in August 1999. From May
1997, when Ms. Riggs joined our company, to August 1999, she served as a
Financial Analyst.

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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 each of the periods indicated, the
high and low reported sales price of our common stock on the New York Stock
Exchange.

On March 14, 2003, the last reported sales price of our common stock on the
New York Stock Exchange was $32.10 per share.

As of March 14, 2003, there were approximately 2,100 holders of record of
our common stock.

We have not paid any cash dividends on our common stock and do not intend
to do so 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 our 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 and in the indenture governing our
8 3/8% Senior Subordinated Notes due 2012 could restrict our ability to pay cash
dividends.

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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 Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations," of this report.

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(1) General and administrative expense includes stock compensation charges of
$2,801, $2,751, $3,047, $1,999 and $2,222 for 2002, 2001, 2000, 1999 and
1998, respectively. See Note 13, "Stock-Based Compensation -- Restricted
Shares," to our consolidated financial statements.

(2) 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 our 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 our consolidated
statement of income for the year ended December 31, 2001. On January 1,
2002, we began assessing hedge effectiveness based on the total changes in
cash flows on our collar and floor contracts as described by the Derivative
Implementation Group (DIG) Issue G20, "Cash Flow Hedges: Assessing and
Measuring the Effectiveness of a Purchased Option Used in a Cash Flow
Hedge." Accordingly, we have elected to prospectively record subsequent
changes in the fair value of our collar and floor contracts, including
changes associated with time value, in accumulated other comprehensive
income (loss). Gains or losses on these collar and floor contracts will be
reclassified out of other comprehensive income (loss) and into earnings when
the forecasted sale of production occurs. The expense recorded in 2002 is
associated with the settlement of collar and floor contracts during the year
ended December 31, 2002 and primarily reflects the reversal of time value
gains of approximately $24.7 million recognized in earnings in 2001, prior
to the adoption of DIG Issue G20. Had we applied DIG Issue G20 from the
January 1, 2001 adoption date of SFAS 133, our income statement caption
"Unrealized commodity derivative income (expense)" would have only reflected
$0.5 million and $0.2 million of expense in 2002 and 2001, respectively,
representing the ineffective portion of our hedges. As a result, net income
would have increased by $18.6 million in 2002 and decreased by $16.3 million
in 2001.

(3) 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 the 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 was 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 our consolidated statement of income
for the year ended December 31, 2000.

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

OVERVIEW

Our revenues, profitability and future growth depend substantially on
prevailing prices for oil and gas and on our ability to find, develop and
acquire oil and gas reserves that are economically recoverable. The preparation
of our financial statements in conformity with generally accepted accounting
principles requires us to make estimates and assumptions that affect our
reported results of operations and the amount of reported assets, liabilities
and proved oil and gas reserves. We use the full cost method of accounting for
our oil and gas activities.

OIL AND GAS PRICES. 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 generally hedge a substantial, but varying, portion of our anticipated
future oil and gas production to, among other things, reduce our exposure to
commodity price fluctuations.

RESERVE REPLACEMENT. 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.
Substantial capital expenditures are required to find, develop and acquire oil
and gas reserves.

SIGNIFICANT ESTIMATES. We believe the most difficult, subjective or
complex judgments and estimates we must make in connection with the preparation
of our financial statements are:

- remaining proved oil and gas reserves;

- timing of our future drilling activities;

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

- allocating the purchase price associated with business combinations; and

- the valuation of our derivative positions.

Please see "Critical Accounting Policies and Estimates" and "Other Factors
Affecting Our Business and Financial Results" in this Item 7 for a more detailed
discussion of the foregoing matters.

RESULTS OF OPERATIONS

REVENUES. All of our revenues are derived from the sale of our oil and gas
production and the settlement of hedging contracts associated with our
production. Our revenues may vary significantly from year to year as a result of
changes in commodity prices. Revenues for 2002 were 12% lower than 2001
primarily because of lower natural gas prices, a decrease in oil and condensate
production and downtime in the Gulf of Mexico associated with Tropical Storm
Isidore. The increase in revenues in 2001 when compared to 2000 was primarily
due to a 25% increase in production and higher realized natural gas prices.

16

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

(1) Represents volumes sold regardless of when produced.

(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, $0.03 and $0.04
for the years ended 2002, 2001 and 2000, respectively. The realized price of
oil and condensate was reduced by $0.28, $0.24 and $0.27 for the years ended
2002, 2001 and 2000, respectively. Average realized prices include the
effects of hedging.

PRODUCTION. Our total oil and gas production (stated on a natural gas
equivalent basis) increased 5% in 2002. Production increased because of
acquisitions (including EEX) and successful drilling efforts. These increases
were partially offset by our decision to voluntarily curtail approximately one
Bcf of production in the first quarter of 2002 in response to low prices and by
the shut-in of four Bcfe in the second half of the year in response to storms in
the Gulf of Mexico. Gas production in 2001 increased primarily through our
acquisition of properties in the Mid-Continent, partially offset by our decision
to voluntarily curtail approximately five Bcfe in the fourth quarter of 2001 in
response to low commodity prices.

Natural Gas. Our 2002 natural gas production increased nearly 9% when
compared to 2001. The increase was the result of successful drilling in the Gulf
of Mexico and Mid-Continent and the acquisition of EEX in late 2002. Partially
offsetting this increase was the voluntary curtailment in the first quarter of
2002 in response to low prices and the shut-in during the second half of the
year related to storms in the Gulf of Mexico. Our 2001 natural gas production
increased 26% over 2000. About half of the production increase in 2001 came from
the Mid-Continent acquisition, which closed in January 2001. Our development
drilling programs in South Texas and the Gulf of Mexico also were major
contributors to our production growth. Gains in production were partially offset
by natural declines from other producing properties.

Crude Oil and Condensate. Our 2002 oil production decreased about 6% when
compared to 2001; primarily reflecting natural field declines in Australia and
the U.S. Partially offsetting these declines were increases at High Island 474,
Viosca Knoll 738 and other Gulf of Mexico fields. Our crude oil production in
2001 increased 21% over 2000 levels. This increase primarily related to our
early 2001 acquisition in the Mid-Continent and the success of our drilling
efforts, partially offset by natural declines in Australia.

17

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.

OPERATING EXPENSES. The following table presents information about our
operating expenses for each of the years in the two-year period ended December
31, 2002.

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

(1) Stock compensation charges were $2,801, or $0.02 per Mcfe, for 2002 and
$2,751, or $0.02 per Mcfe, for 2001. Total operating expense inclusive of
these charges was $488,245, or $2.65 per Mcfe, for 2002 and $452,536, or
$2.58 per Mcfe, for 2001.

18

Our total operating expense for 2002, stated on a unit of production basis,
increased 2% over 2001. The increase was primarily related to the following
items.

- Lease operating expense during 2001 included a $5.5 million non-recurring
expense associated with a workover of a well at South Marsh Island 160.
Without the effect of the workover, domestic lease operating expense
would have increased 13%, or $0.04 per unit, as a result of several
non-routine repairs to gathering lines and other offshore facilities in
the Gulf of Mexico and a slight increase in well service costs in the
Mid-Continent.

- Although our domestic production subject to production taxes increased
14% in 2002, our production tax expense decreased because of a 23% drop
in natural gas prices for the year.

- The increase in our DD&A rate was primarily related to the increased cost
of reserve additions. The cost of reserve additions was adversely
affected by the quantity of proved reserves added and increases in the
cost of drilling goods and services and platforms and facilities
construction during the first half of 2001. The increase is partially
offset by our fourth quarter 2001 ceiling test writedown of our oil and
gas properties.

- General and administrative expense increased primarily because of a
growing domestic workforce and the opening of our office in London,
England.

- Maintenance on our FPSOs resulted in higher Australian lease operating
expense during 2001. This $2.1 million decrease from 2001 to 2002 was
partially offset on a per unit basis by the 9% decrease in production in
2002.

- Australian capital expenditures are deductible against production taxes
otherwise payable. Production taxes are due on a June 30 fiscal year. We
accrue production taxes during the tax fiscal year based on our estimate
of revenues and capital expenditures for the fiscal year. The estimate of
such taxes for the current year reflects lower actual and anticipated
future capital expenditures in Australia.

- The increase in the Australian DD&A rate during 2002 was primarily a
result of our unsuccessful exploratory drilling efforts in 2002 and 2001.

- The significant increase in Australian general and administrative expense
for 2002 relates to costs incurred in connection with the relocation of
the previous manager of our Australian operations to our Tulsa, Oklahoma
office and the relocation of the current manager of our Australian
operations from Houston, Texas to Perth, Australia. On a per unit basis,
the increase is magnified by the decline in our production in Australia.

19

The following table presents information about our operating expenses for
each of the years in the two-year period ended December 31, 2001.

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

(1) Stock compensation charges were $2,751, or $0.02 per Mcfe, for 2001 and
$3,047, or $0.02 per Mcfe, for 2000. Total operating expense inclusive of
these charges was $452,536, or $2.58 per Mcfe, for 2001 and $304,910, or
$2.18 per Mcfe, for 2000.

Our total operating expense (exclusive of the ceiling test writedowns in
2000 and 2001) for 2001, stated on a unit of production basis, increased 19%
over 2000 because of higher lease operating, production tax, DD&A and G&A
expenses. The reasons for these increases are described below.

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

- The increase in production and other taxes was primarily related to
higher natural gas prices, our expanding onshore Gulf Coast operations
and the acquisition of our 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 was primarily related to lower
than expected reserve additions from several wells, increases in the cost
of drilling goods and services and platforms and

20

facilities construction and the completion of several higher cost wells.
The increase in the Australian DD&A rate was primarily a result of our
unsuccessful drilling activities in 2000.

- The increase on a unit of production basis in G&A expense primarily was
due to our growing workforce. Performance-based compensation, excluding
stock compensation expense, was negatively impacted by the fourth quarter
2001 ceiling test writedown. 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.

WRITEDOWN OF OIL AND GAS PROPERTIES. We did not writedown any of our oil
and gas properties in 2002. At December 31, 2002, we had $44.6 million of other
international costs that were not subject to amortization. These costs primarily
represent our exploration efforts in China's Bohai Bay. We continue to appraise
the commerciality of our two field discoveries -- CFD 12-1 and CFD 12-1 South.
We have not yet booked any reserves associated with these discoveries. We are
not the operator of and do not own a controlling interest in these fields. As a
result, we do not control the appraisal and determination of commerciality of
these fields. If we determine that one or both of these fields are not
commercially viable, we will likely be required to impair the value of our
assets in this area.

At December 31, 2001, 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). Based on an interim interpretation
from the SEC that is applicable to all companies that use the full cost method
of accounting, the full cost ceiling test impairment calculations took into
account the effects of hedging. This interim interpretation, which is subject to
further consideration by the SEC before it is finalized, requires that certain
conditions be met in order to take into account the effects of hedging in the
calculation of full cost ceiling test impairment, including that the hedges
qualify under SFAS 133 and are documented and designated as such and that the
policy be applied on a consistent basis whether or not the hedged price is
higher than the current market price. The writedown would have been $184 million
($118 million after-tax) if we had not used hedge adjusted prices.

INTEREST EXPENSE. The following table presents information about our
interest expense for each of the years in the three-year period ended December
31, 2002.

In 2002, interest expense increased in part because of higher debt levels
outstanding under our credit arrangements. Interest expense also increased as a
result of debt incurred in connection with EEX acquisition in late November
2002. In August 2002, we issued $250 million principal amount of our 8 3/8%
Senior Subordinated Notes due 2011 to finance a portion of the acquisition.
Interest that accrued prior to the closing of the acquisition was capitalized as
a cost of the transaction. Following the acquisition, EEX retained the
obligations associated with its secured notes (which accrue interest at rate of
7.54% per year) and a forward gas sales contract valued at approximately $60
million with an effective interest rate of 9.5% per year. In 2001, total
interest expense was higher than 2000 due to borrowings related to our
acquisition in the Mid-Continent and the issuance of $175 million principal of
our 7 5/8% Senior Notes in February 2001. In 2000, our interest expense included
interest from borrowings in January 2000 to finance our acquisition of three
producing properties in South Texas for $139 million.

21

UNREALIZED COMMODITY DERIVATIVE INCOME (EXPENSE). 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
reflects the change in the time value of our open hedging contracts. In 2002,
the unrealized expense of $29.1 million represents the settlement of those same
hedging contracts and primarily reflects the reversal of the time value gains
that were previously recognized during 2001.

TAXES. The effective tax rate for the years ended December 31, 2002, 2001
and 2000 was 33%, 35% and 34%, respectively. The effective tax rate in 2002 was
less than the statutory tax rate primarily due to a $3.1 million tax benefit
resulting from revised tax legislation enacted in Australia in 2002. 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

CASH FLOW FROM OPERATIONS.

Our annual capital budget is established at the beginning of each year.
Because of the nature of the properties we own, only a small portion of our
capital budget is nondiscretionary. The size of our budget is driven by expected
cash flow from operations. 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.

Based on current commodity prices and our hedges, we currently anticipate
that our cash flow will exceed our capital budget (which excludes acquisitions)
by more than $100 million in 2003. This excess should allow us to pay down debt
and other obligations or repurchase shares of our common stock during the year.

CREDIT ARRANGEMENTS. We maintain our reserve-based revolving credit
facility with Chase Manhattan Bank, as agent. The banks participating in the
facility have committed to lend us 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
principal amount of outstanding senior notes ($300 million at March 14, 2003),
30% of the principal amount of any outstanding senior subordinated notes (a
reduction of $75 million at March 14, 2003), the outstanding principal amount of
the secured notes ($46 million at March 14, 2003) and an agreed valuation for
the gas sales obligation ($72.5 million at March 14, 2003). The borrowing base
will be redetermined at least semi-annually and, after reduction for the
foregoing items, was $236.5 million at March 14, 2003. 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. We expect to complete an amendment of the
facility during the first quarter of 2003 that would extend the maturity to
January 23, 2005.

We also have money market lines of credit with various banks in an amount
limited by our credit facility to $40 million. At March 14, 2003, we had
outstanding borrowings under our credit facility of $130 million and outstanding
borrowings under our money market lines of $4 million. Consequently, at March
14, 2003, we had approximately $142.5 million of available capacity under our
credit arrangements.

At December 31, 2002 and 2001, the interest rate was 2.737% and 3.25%,
respectively, for LIBOR based loans under our credit facility and 2.615% and
3.00%, respectively, for the loans outstanding under our money market lines of
credit.

22

WORKING CAPITAL. Our working capital balance fluctuates as a result of the
timing and amount of borrowings or repayments under our credit arrangements.
Generally, we use excess cash to pay down borrowings under our credit
arrangements. As a result, we often have a working capital deficit or a
relatively small amount of positive working capital. We had a working capital
deficit of $57.0 million as of December 31, 2002. This compares to a working
capital surplus of $65.6 million at the end of 2001 and $38.5 million at the end
of 2000. Our 2002 working capital deficit included an $11.2 million note payment
due January 2003 and accrued severance costs associated with the EEX
acquisition.

CASH FLOWS FROM OPERATIONS. Our net cash flows from operations in 2002
declined 20% when compared to 2001. The decrease is primarily due to lower gas
prices and higher general and administrative expenses, partially offset by
higher production volumes. Our net cash flows from operations were $502.4
million in 2001 and $316.4 million in 2000. The increase in 2001 over 2000 is
primarily attributable to higher commodity prices and increased production
volumes, offset by increased operating expenses.

CAPITAL EXPENDITURES. Our 2002 capital spending was $908 million, a 6%
increase over the previous year. The largest component of our capital spending
was the $571 million EEX acquisition. In 2002, we also invested $150 in U.S.
development, $106 million in domestic exploration, $53 million in other domestic
acquisitions and $28 million internationally. In 2001, our capital spending
totaled $855 million, including $435 million in acquisitions. The largest
component of acquisition spending was our first quarter acquisition in the
Mid-Continent. 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 budgeted $450 million for capital spending, excluding uncompleted
acquisitions, in 2003. We expect that 55-60% of this budget will be invested in
the Gulf of Mexico (including deepwater), 35-40% in onshore U.S. and the balance
in international projects. We anticipate that our capital expenditure budget for
2003 will be funded from cash flow from operations. To the extent that cash
receipts during the year are slower than capital needs, we will make up the
short fall with borrowings under our credit arrangements. Actual levels of
capital expenditures may vary significantly due to many factors, including the
extent to which proved properties are acquired, drilling results, oil and gas
prices, industry conditions and the prices and availability of goods and
services. We continue to pursue attractive acquisition opportunities; however,
the timing, size and purchase price of acquisitions are unpredictable.
Historically, we have completed several acquisitions of varying sizes each year.
Depending on the timing of an acquisition, we may spend additional capital
during the year of acquisition for drilling and development activities on the
acquired properties.

23

CONTRACTUAL CASH OBLIGATIONS

The table below summarizes our significant contractual cash payment
obligations and commitments, other than hedging contracts, by maturity as of
December 31, 2002. Hedging contracts are excluded because they are sensitive to
future changes in commodity prices and other factors. See "Hedging" below.

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

(1) Our capacity under our credit facility is available to repay current amounts
due under the gas sales obligation and our money market lines of credit and,
therefore, these obligations have been classified as long-term on our
consolidated balance sheet.

(2) The principal payment on the secured notes of $11.2 million due and paid in
January 2003 is classified on our consolidated balance sheet as a current
liability.

(3) See Note 16, "Commitment and Contingencies -- Lease Commitments," to our
consolidated financial statements.

CREDIT ARRANGEMENTS. Please see "Liquidity and Capital Resources -- Credit
Arrangements" in this Item 7 for a description of our bank revolving credit
facility and money market lines of credit.

SENIOR NOTES. In February 2001, we issued $175 million aggregate principal
amount of our 7 5/8% Senior Notes due 2011 priced (at 99.931% of par) with a
yield to maturity of 7.635%. Net proceeds from the offering of $173.1 million
were used to repay outstanding indebtedness under our revolving credit facility
incurred in connection with our January 2001 Mid-Continent acquisition. In
October 1997, we issued $125 million aggregate principal amount of our 7.45%
Senior Notes due 2007. Interest on our senior notes is payable semi-annually.

Our senior notes are unsecured and unsubordinated obligations and rank
equally with all of our other existing and future unsecured and unsubordinated
obligations. We may redeem some or all of our senior notes at any time before
their maturity at a redemption price based on a make-whole amount plus accrued
and unpaid interest to the date of redemption. The indentures governing our
senior notes contain covenants that limit our ability to, among other things:

- incur debt secured by certain liens;

- enter into sale/leaseback transactions; and

- enter into merger or consolidation transactions.

24

The indentures also provide that if any of our subsidiaries guarantee any of our
indebtedness at any time in the future, then we will cause our senior notes to
be equally and ratably guaranteed by that subsidiary.

SENIOR SUBORDINATED NOTES. On August 13, 2002, we sold $250 million
aggregate principal amount of our 8 3/8% Senior Subordinated Notes due 2012
priced with a yield to maturity of 8.50%. The net proceeds from the offering of
approximately $241.8 million were used to repay EEX debt that became due at the
closing of the acquisition and to pay transaction costs. Interest on the notes
is payable semi-annually. Interest accruing prior to the closing of the EEX
acquisition was capitalized as a cost of the transaction. The notes are
unsecured senior subordinated obligations that rank junior in right of payment
to all of our present and future senior indebtedness. We may redeem some or all
of the notes at any time on or after August 15, 2007 at a redemption price
stated in the indenture governing the notes. Prior to August 15, 2007, we may
redeem all but not part of the notes at a redemption price based on a make-whole
amount plus accrued and unpaid interest to the date of redemption. In addition,
before August 15, 2005, we may redeem up to 35% of the original principal amount
of the notes with the net cash proceeds of certain sales of our common stock at
108.375% of the principal amount plus accrued and unpaid interest to the date of
redemption.

The indenture governing our senior subordinated notes limits our ability
to, among other things:

- incur additional debt;

- make restricted payments;

- pay dividends on or redeem our capital stock;

- make certain investments;

- create liens;

- make certain dispositions of assets;

- engage in transactions with affiliates; and

- engage in mergers, consolidations and certain sales of assets.

SECURED NOTES. In the second quarter of 2001, EEX assumed the obligations
under the secured notes in connection with the termination of two leveraged
leasing arrangements. The notes accrue interest at a rate of 7.54% per year and
are secured by the floating production system and pipelines described in Note 4,
"Oil and Gas Assets -- Assets Held for Sale," to our consolidated financial
statements. Redemption of the notes prior to 2006 may require us to pay
make-whole premiums. Principal is payable in annual installments on January 2 of
each year (except 2006) with the final installment due in 2009.

The following is a summary of principal amounts by year of maturity at
December 31, 2002 (in thousands):

2003........................................................ $ 11,215
2004........................................................ 12,093
2005........................................................ 11,366
2006........................................................ --
2007........................................................ 12,067
Thereafter.................................................. 30,437
--------
Total secured notes....................................... $ 77,178
Less current maturities..................................... (11,215)
--------
Total long-term secured notes............................. $ 65,963
========

25

GAS SALES OBLIGATION. In 1999, EEX entered into a gas forward sales
contract with Bob West Treasure L.L.C. (BWT), an affiliate of Enron
Corporation,. Pursuant to the gas sales contract, EEX committed to deliver
approximately 50 Bcfe of production to BWT in exchange for proceeds of $105
million. BWT receives an adjusted market price as the volumes are delivered. EEX
also has an obligation to market the delivered volumes of gas for BWT. Under the
terms of the gas sales contract, EEX is required to make a cash payment if the
committed gas volumes are not delivered. Additionally, BWT holds liens on
certain of EEX's oil and gas properties as security if the committed gas volumes
are not delivered or the cash payments are not made.

Payments under the gas sales contract are amortized as the underlying gas
is delivered under the interest method using an interest rate of 9.5%. As of
December 31, 2002, the unamortized balance was approximately $60 million and the
fair value of the remaining obligation was approximately $64.5 million. The
interest portion of the payment is included as a component of interest expense
in our consolidated income statement.

EEX also guaranteed BWT's performance under certain swap agreements between
BWT and Enron entered into concurrently with the gas sales contract. If BWT
fails to make payments under the swap agreements, EEX must perform under the
guarantee by paying Enron on BWT's behalf. The maximum amount that EEX could be
required to pay under this guarantee is not determinable and would depend on the
settlement value of the swaps at the time of any BWT default. BWT, which is
outside of the Enron bankruptcy proceedings, continues to meet its contractual
obligations under its swap agreements and, therefore, EEX has not been required
to perform under this guarantee.

On March 6, 2003, we reached an agreement with BWT, certain lenders and
insurers of BWT and the unsecured creditors committee of Enron to terminate
EEX's gas sales contract. The agreement, which is subject to the final approval
of the Enron bankruptcy court, provides for the termination of the gas sales
contract, the swaps entered into in connection with the gas sales contract and
any other agreements between EEX, BWT and Enron related to the gas sales
contract, including the guarantee and all liens and other security interests on
EEX's properties, in exchange for a payment to BWT representing:

- the remaining unamortized obligation under the gas sales contract;

- the fair market value of the swaps;

- an agreed upon value of $0.5 million for BWT's limited membership
interest in an EEX subsidiary that BWT acquired in conjunction with the
gas sales contract.

CONVERTIBLE TRUST PREFERRED SECURITIES. In August 1999, a subsidiary of
our company that is a Delaware business trust issued $143.75 million (2.875
million securities having a liquidation preference of $50 each) of 6.5%
Cumulative Quarterly Income Convertible Preferred Securities, Series A. The
proceeds from the issuance of these securities (commonly referred to as trust
preferred securities) were used to purchase $143.75 million of our company's
6.5% Junior Subordinated Convertible Debentures due 2029. The interest terms and
payment dates of the debentures correspond to the distribution terms of the
trust preferred securities. The debentures are eliminated in our 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 of the securities. The trust preferred securities are convertible at
the option of the holder at any time into our common stock at the rate of 1.3646
shares of our common stock per trust preferred security -- the equivalent of a
conversion price of $36.64 per share of our common stock. The trust preferred
securities are mandatorily redeemable upon maturity of the debentures in August
2029, and on a proportionate basis to the extent of any earlier redemption of
the debentures by us. The debentures are redeemable by us at any time. For a
more detailed description of the trust preferred securities, see Note 9,
"Convertible Preferred Securities of Newfield Financial Trust I," to our
consolidated financial statements.

26

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 at an average of $29.97 per share. During 2002,
no shares were purchased under this program. In February 2003, our Board of
Directors authorized the expenditure of up to $50 million from that date forward
to repurchase shares of our common stock. As a result, 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, 2003, no shares had been
purchased during the first quarter of 2003.

HEDGING

We generally hedge a substantial, but varying, portion of our anticipated
oil and gas production for the next 18-24 months as part of our risk management
program. We use hedging to reduce price volatility, help ensure that we have
adequate cash flow to fund our capital programs and manage price risks and
return on some of our acquisitions. Our decision on the quantity and price at
which we choose to hedge our production is based in part on our view of current
and future market conditions. Approximately 84% of our 2002 production was
subject to hedge positions. In 2001, 68% of our production was subject to hedge
positions, compared to 45% in 2000. 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 counterparties will be unable to meet the financial
terms of such transactions. At December 31, 2002, Bank of Montreal, Morgan
Stanley and J Aron & Company were the counterparties with respect to 61% of our
future hedged production. Such contracts are accounted for as derivatives in
accordance with SFAS No. 133. Please see the discussion in Note 5, "Commodity
Derivative Instruments and Hedging Activities" to our consolidated financial
statements appearing in this report.

27

NATURAL GAS. As of December 31, 2002, we held the commodity derivative
instruments set forth in the table below as cash flow hedges of the forecasted
sale of our U.S. natural gas production for 2003 through 2005. This table
includes hedges that were entered into by EEX prior to its acquisition.

Between December 31, 2002 and March 14, 2003, we entered into the
additional natural gas price hedging contracts set forth in the table below. The
addition of these hedges, along with those already in place, resulted in
approximately 77% of our 2003 forecasted natural gas production being hedged. We
continue to evaluate additional hedging transactions.

28

We believe there is no material basis risk with respect to our natural gas
price hedging contracts because substantially all our hedged natural gas
production is sold at market prices that historically have highly correlated to
the settlement price.

OIL AND CONDENSATE. As of December 31, 2002, we held the commodity
derivative instruments set forth in the table below as cash flow hedges of the
forecasted sale of our U.S. Gulf Coast oil production for 2003 through 2005.

Between December 31, 2002 and March 14, 2003 we have entered into
additional oil price hedging contracts with respect to our Gulf Coast oil
production set forth in the table below. The addition of these hedges, along
with those already in place, resulted in approximately 59% of our budgeted
domestic oil production being hedged through December 2003. We continue to
evaluate additional hedging transactions for 2003 and future years.

Because substantially all of our U.S. Gulf Coast oil production is sold at
current market prices that historically have highly correlated to the NYMEX West
Texas Intermediate price, we believe that we have no

29

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. Our
Australian production is not hedged.

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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of our financial statements in conformity with generally
accepted accounting principles requires us to make estimates and assumptions
that affect our reported results of operations and the amount of reported
assets, liabilities and proved oil and gas reserves. Described below are the
most significant policies we apply in preparing our financial statements, some
of which are subject to alternative treatments under generally accepted
accounting principles. We also describe the most significant estimates and
assumptions we make in applying these policies. The accuracy of our estimates
and assumptions are sensitive to material changes in the future due to various
factors, many of which are beyond our control.

For discussion purposes, we have divided our significant policies into
three categories. Set forth below is an overview of each of our significant
accounting policies by category.

- WE ACCOUNT FOR OUR OIL AND GAS ACTIVITIES UNDER THE FULL COST
METHOD. This method of accounting requires the following significant
estimates:

- remaining proved oil and gas reserves;

- costs withheld from amortization; and

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

- ACCOUNTING FOR BUSINESS COMBINATIONS REQUIRES ESTIMATES AND ASSUMPTIONS
regarding the allocation of the purchase price.

- ACCOUNTING FOR HEDGING ACTIVITIES REQUIRES ESTIMATES AND ASSUMPTIONS
regarding the valuation of hedge positions.

OIL AND GAS ACTIVITIES

Accounting for oil and gas activities is subject to special, unique rules.
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 these costs. Both methods generally provide for the
periodic amortization of capitalized costs based on proved reserve quantities.
Impairment of oil and gas properties under the successful efforts method is
based on an evaluation of the carrying value of individual oil and gas
properties against their estimated fair value, while impairment under the full
cost method requires an evaluation of the carrying value of oil and gas
properties included in a cost center against the net present value of future
cash flows from the 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 (the amortization base) 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 our oil and gas activities. Interest costs
related to unproved properties and properties under development also are
capitalized. Costs associated with production and general corporate

30

activities are expensed in the period incurred. 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. Amortization is calculated separately on a
country-by-country basis.

PROVED OIL AND GAS RESERVES. Our engineering estimates of proved oil and
gas reserves directly impact financial accounting estimates, including
depreciation, depletion and amortization expense and the full cost ceiling
limitation. Proved oil and gas reserves are the estimated quantities of natural
gas and crude oil reserves that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under period-end economic and operating conditions. The process of estimating
quantities of proved reserves is very complex, requiring significant subjective
decisions in the evaluation of all geological, engineering and economic data for
each reservoir. The data for a given reservoir may 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. Changes in oil and gas prices,
operating costs and expected performance from a given reservoir also will result
in revisions to the amount of our estimated proved reserves.

Depreciation, Depletion and Amortization. The quantities of estimated
proved oil and gas reserves are a significant component of our calculation of
depletion expense and revisions in such estimates may alter the rate of future
expense. Holding all other factors constant, if reserves are revised upward,
earnings would increase due to lower depletion expense. Likewise, if reserves
are revised downward, earnings would decrease due to higher depletion expense or
due to a ceiling test writedown.

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. 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 represents the component that
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. Based on
an interim interpretation from the SEC, the full cost ceiling test impairment
calculations may take into consideration the effects of hedging if certain
conditions are met. See "Results of Operations -- Writedown of Oil and Gas
Properties" in this Item 7.

COSTS WITHHELD FROM AMORTIZATION. 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 initially
excluded from our amortization base. Leasehold costs are either transferred to
our amortization base with the costs of drilling a well on the lease or are
assessed quarterly for possible impairment or reduction in value. Leasehold
costs are transferred to our amortization base to the extent a reduction in
value has occurred or a charge is made against earnings if the costs were
incurred in a country for which a reserve base has not been established. If a
reserve base for a country in which we are conducting operations has not yet
been established, an impairment

31

requiring a charge to earnings may be indicated through evaluation of drilling
results, relinquishing drilling rights or other information.

Our decision to withhold costs from amortization and the timing of the
transfer of those costs into the amortization base involves a significant amount
of 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. At December 31, 2002, we had
approximately $269 million of costs excluded from our amortization base. Because
the application of the full cost ceiling test at December 31, 2002 resulted in a
significant excess of the cost-center ceiling over the carrying value of our oil
and gas properties, inclusion of some or all of our unevaluated property costs
in our amortization base, without adding any associated reserves, would not have
resulted in a ceiling test writedown. However, our future depletion rate will
increase to the extent such costs are transferred without any associated
reserves.

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 technologies and the future political and regulatory
environment.

ALLOCATION OF PURCHASE PRICE IN BUSINESS COMBINATIONS

As part of our growth strategy, we actively pursue the acquisition of oil
and gas properties. The purchase price in an acquisition is allocated to the
assets acquired and liabilities assumed based on their relative fair values as
of the acquisition date, which may occur many months after the announcement
date. Therefore, while the consideration to be paid may be fixed, the fair value
of the assets acquired and liabilities assumed are subject to change during the
period between the announcement date and the acquisition date. Our most
significant estimates in our allocation typically relate to the value assigned
to future recoverable oil and gas reserves and unproved properties. To the
extent the consideration paid exceeds the fair value of the net assets acquired,
we would be required to record the excess as an asset called goodwill. Goodwill
is not amortized but must be evaluated periodically for impairment. We have not
recorded goodwill in connection with any of our previous acquisitions.

HEDGING ACTIVITIES

Beginning in 2001, the estimated fair values of our derivative instruments
are recorded on our consolidated balance sheet. We have elected to designate all
of our derivative instruments as hedges against the price we will receive for
our future oil and natural gas production. We do not use derivative instruments
for trading purposes. Because our derivatives qualify for hedge accounting, to
the extent that changes in their 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
and sold. 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.

VALUATION OF HEDGE POSITIONS. 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

32

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.

NEW ACCOUNTING STANDARDS

In 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations". This statement changes the method of accounting for costs
associated with the retirement of long-lived assets (e.g. oil & gas production
facilities, etc.) that we are obligated to incur. The statement requires 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 asset
retirement cost be capitalized as part of the carrying amount of the associated
asset. Under our previous accounting method, we recognized the cost to abandon
our oil and gas properties over their productive lives on a unit-of-production
basis.

We adopted SFAS No. 143 effective January 1, 2003. A pre-tax cumulative
effect gain of approximately $8 million will be reported in our consolidated
statement of income on January 1, 2003. We will also report an increase in our
assets of approximately $160 million and an increase in our liabilities of
approximately $152 million. There will be no impact on our reported cash flows
as a result of adopting SFAS No. 143.

In the second quarter of 2002, the FASB issued SFAS No. 145, "Recision of
FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and
Technical Corrections as of April 2002." This statement provides guidance for
income statement classifications of gains and losses on extinguishment of debt
and accounting for certain lease modifications that have economic effects that
are similar to sale-leaseback transactions. Our adoption of SFAS No. 145 on
January 1, 2003 had no effect on our financial statements.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires
that a liability for costs associated with an exit or disposal activity be
recognized when the liability is incurred and establishes that fair value is the
objective for initial measurement of the liability. The provisions of SFAS No.
146 are effective for exit or disposal activities that are initiated after
December 31, 2002. Our adoption of SFAS 146 on January 1, 2003 had no effect on
our financial statements.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure, an amendment of FASB Statement No. 123."
SFAS No. 148 provides alternative methods of accounting for entities that elect
to transition from the intrinsic value method of accounting for stock-based
compensation to the fair value method. In addition, this statement amends the
disclosure requirements of SFAS No. 123 to require disclosures in both annual
and interim financial statements about the method of accounting for stock-based
compensation and the effect of the method used on reported results. We adopted
the disclosure provisions of this statement in our 2002 year-end financial
statements. We continue to apply the intrinsic value method of accounting for
our stock-based compensation plans.

In November 2002, the FASB issued Interpretation No. (FIN) 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." FIN 45 requires certain guarantees to be
recorded at fair value, which is different from the current practice of
recording a liability only when a loss is probable and reasonably estimable, as
those terms are defined in SFAS No. 5, "Accounting for Contingencies." FIN 45
has a dual effective date. The initial recognition and measurement provisions
are applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The disclosure requirements in the interpretation are
effective for financial statements of interim or annual periods ending after
December 15, 2002. We do not expect the adoption of FIN No. 45 to have a
material effect on our financial statements. See Note 7, "Debt -- Gas Sales
Obligation," to our consolidated financial statements, regarding the guarantee
associated with the Gas Sales Obligation.

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In January 2003, the FASB issued FIN 46 "Consolidation of Variable Interest
Entities, an interpretation of ARB 51." The primary objectives of FIN 46 are to
provide guidance on the identification of entities for which control is achieved
through means other than through voting rights (these entities are referred to
as "variable interest entities" or "VIEs") and how to determine if business
enterprise should consolidate the VIE. This new model for consolidation applies
to an entity which either (1) the equity investors (if any) do not have a
controlling financial interest or (2) the equity investment at risk is
insufficient to finance that entity's activities without receiving additional
subordinated financial support from other parties. In addition, FIN 46 requires
that all enterprises with a significant variable interest in a VIE make
additional disclosures regarding their relationship with the VIE. We are
currently evaluating the impact of FIN No. 46 on our financial statements;
however we do not believe that we have any VIEs that will require consolidation
in our financial statements under this interpretation.

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

34

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 and condensate 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.

35

The MMS has issued a final rule that governs 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, permits for the drilling of wells, maintaining bonding
requirements in order to drill or operate wells, and regulating the location of
wells, the method of drilling and casing wells, the surface use and restoration
of properties upon which wells are drilling and the plugging and abandonment of
wells. The laws of these states also govern a number of environmental and
conservation matters, including the handling and disposing of waste materials,
the size of drilling and spacing units or proration units and the density of
wells which may be drilled, 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, the obligation to perform investigatory or remedial
activities 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
strict, joint and several 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 operators in the Gulf of Mexico to demonstrate to the MMS
that they possess available financial resources that are sufficient to pay for
certain costs that may be incurred in responding to an oil spill. Under OPA and
MMS regulations, responsible parties are required to demonstrate that they
possess financial resources sufficient to pay for environmental cleanup and
restoration costs of at least $10 million for an oil spill in state waters and
at least $35 million for an oil spill in federal waters. Since we currently have
extensive operations in federal waters, we currently provide a total of $150
million in financial assurance to MMS. This $150 million in financial assurance
is provided through $35 million in guaranteed net worth and $115 million in
insurance.

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.

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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.

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. Many of these 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 investigate and 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.

Among the factors that can cause fluctuations are:

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

- the price and availability of alternative fuels;

- weather conditions;

- the level of consumer demand;

37

- the price of foreign imports;

- world-wide economic conditions;

- political conditions in oil and gas producing regions; and

- domestic and foreign governmental regulations.

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. 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.

OUR FUTURE SUCCESS DEPENDS ON OUR ABILITY TO FIND, DEVELOP AND ACQUIRE OIL
AND GAS RESERVES. 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. To maintain production levels, we must locate
and develop or acquire new oil and gas reserves to replace those depleted by
production. Without successful exploration or acquisition activities, our
reserves, production and revenues will decline rapidly. We may be able to find
and develop or acquire additional reserves at an acceptable cost. In addition,
substantial capital is required to replace and grow reserves. If 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
arrangements, we may be unable to expend the capital necessary to locate and
develop or acquire new oil and gas reserves.

ACTUAL QUANTITIES OF RECOVERABLE OIL AND GAS RESERVES AND FUTURE CASH FLOWS
FROM THOSE RESERVES MOST LIKELY WILL VARY FROM OUR ESTIMATES. Estimating
accumulations of oil and gas is complex. 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 quantities of recoverable oil and gas reserves, future production,
oil and gas prices, revenues, taxes, development expenditures and operating
expenses 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.

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. We
may 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.

38

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 for 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. 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 or 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 often are 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;

- 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.

39

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;

- investigatory and 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 exploration 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 currently have
international activities and we continue to evaluate and pursue new
opportunities for international expansion in select areas. 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;

40

- 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. 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
that we 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.

In addition, as we carry out our drilling program is deepwater, it is
likely that we will not initially serve as operator of the wells. As a result,
we may have limited ability to exercise influence over operations for these
properties or their associated costs. Our dependence on the operator and other
working interest owners for these deepwater projects and our limited ability to
influence operations and associated costs could prevent the realization of our
targeted returns on capital in drilling or acquisition activities in the
deepwater of the Gulf of Mexico. The success and timing of drilling and
exploitation activities on properties operated by others therefore depend upon a
number of factors that will be largely outside of our control, including:

- the timing and amount of capital expenditures;

- the availability of suitable offshore drilling rigs, drilling equipment,
support vessels, production and transportation infrastructure and
qualified operating personnel;

- the operator's expertise and financial resources;

- approval of other participants in drilling wells; and

- selection of technology.

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 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.

41

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.

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

BCF. Billion cubic feet.

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

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 generally greater than 15,000 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.

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.

EXPLORATION OR 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.

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 we own a
working interest.

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 or condensate.

42

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.

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

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

NYMEX. The New York Mercantile Exchange.

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 or natural gas 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.

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

TCFE. One trillion cubic feet equivalent, determined using the ratio of
six Mcf gas to one Bbl of crude oil or condensate.

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.

43

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

We generally hedge a substantial, but varying, portion of our anticipated
oil and gas production for the next 18-24 months as part of our risk management
program. We use hedging to reduce price volatility, help ensure that we have
adequate cash flow to fund our capital programs and manage price risks and
return on some of our acquisitions. Our decision on the quantity and price at
which we choose to hedge our production is based in part on our view of current
and future market conditions. 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, 2002, we had approximately $616 million in long-term fixed
rate debt. This debt was comprised of:

- $125 million of 7.45% Senior Notes due 2007;

- $175 million of 7 5/8% Senior Notes due 2011;

- $250 million of 8 3/8% Senior Subordinated Notes due 2012; and

- $66 million of secured notes with an interest rate of 7.54%.

Additionally, we had $144 million of convertible trust preferred securities
bearing a fixed distribution rate of 6.5%. At December 31, 2002, we also had $60
million remaining on a gas sales obligation that we assumed with the purchase of
EEX. Payment under this obligation is amortized on the interest method using an
interest rate of 9.5%.

Our year-end 2002 variable rate debt consisted of $28 million borrowed
under our bank revolving credit facility and $8 million borrowed under our money
market lines of credit. The interest rate at December 31, 2002 for our LIBOR
based loans under our credit facility was 2.737% and the interest rate for the
money market lines was 2.615%.

We considered our interest rate exposure at year-end 2002 to be minimal
because the majority, about 86%, of our long-term debt obligations were at fixed
rates. The impact on annual cash flow of a 10% change in the floating rate
applicable to our variable rate debt would be $0.1 million.

At December 31, 2002, we had no open interest rate hedge positions to
affect 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, 2002.

44

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

NEWFIELD EXPLORATION COMPANY
INDEX

CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA

45

MANAGEMENT REPORT ON FINANCIAL STATEMENTS

Our management is responsible for the preparation and integrity of all
information contained in this report. The financial statements are prepared in
accordance with generally accepted accounting principles and, accordingly,
include certain informed judgments and estimates of management. Our independent
public accountants have audited the financial statements as described in their
report that 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.

The Audit Committee of our Board of Directors, consisting of independent
directors, meets periodically with management and our independent public
accountants to monitor the integrity of our financial reporting process and
system of internal controls. The independent accountants have full, free and
separate access to the Audit Committee to discuss all appropriate matters.

We believe that our 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.

[TRICE SIG] [RATHERT SIG]
David A. Trice Terry W. Rathert
President and Chief Executive Officer Vice President and Chief Financial Officer

Houston, Texas
March 14, 2003

46

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, 2002 and 2001, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2002 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 assessing hedge effectiveness of its collar and
floor contracts effective January 1, 2002 and 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.

[PRICEWATERHOUSECOOPERSLLP SIG]

Houston, Texas
March 14, 2003

47

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.

48

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.

49

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.

50

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)

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

51

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

ORGANIZATION AND PRINCIPLES OF CONSOLIDATION

We are 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 include the U.S.
onshore Gulf Coast, West Texas, the Anadarko Basin and offshore northwest
Australia.

Our financial statements include the accounts of Newfield Exploration
Company, a Delaware corporation, and its subsidiaries. All significant
intercompany balances and transactions have been eliminated. Unless otherwise
specified or the context otherwise requires, all references in these notes to
"Newfield," "we," "us" or "our" are to Newfield Exploration Company and its
direct and indirect subsidiaries.

On November 26, 2002, we acquired all of the outstanding capital stock of
EEX Corporation, and EEX and its direct and indirect subsidiaries became direct
or indirect subsidiaries of our company. The acquisition has been accounted for
using the purchase method of accounting. As a result, the assets and liabilities
of EEX and its subsidiaries have been included in our December 31, 2002 balance
sheet and our results of operations and cash flows for 2002 include 35 days
(November 27 to December 31, 2002) of activity for EEX and its subsidiaries.

As is common in the context of acquisitions, in these notes we sometimes
refer to our assumption of liabilities or obligations of EEX or EEX subsidiaries
as a result of the acquisition. Because our balance sheet is prepared on a
consolidated basis that includes all of the subsidiaries of Newfield Exploration
Company, the liabilities and obligations EEX and its subsidiaries are included
in our consolidated balance sheet. However, neither Newfield Exploration Company
nor any of its pre-acquisition subsidiaries legally assumed any liabilities or
obligations of EEX or any of its subsidiaries in connection with the
acquisition. At the time of the acquisition of EEX, we changed EEX's name to
Newfield Exploration Gulf Coast Inc. However, to assist readers' understanding
of these notes, we continue to refer to this entity as EEX.

DEPENDENCE ON OIL AND GAS PRICES

As an independent oil and gas producer, our 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 our 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 our
financial position, results of operations, cash flows and our access to capital
and on the quantities of oil and gas reserves that may be economically produced.

USE OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles requires our management to make estimates and
assumptions that affect the reported amounts of assets and liabilities;
disclosure of contingent assets and liabilities at the date of the financial
statements; the reported amounts of revenues and expenses during the reporting
period; and the reported amounts of proved oil and gas reserves. Actual results
could differ from these estimates. Our most significant financial estimates are
based on remaining proved oil and gas reserves.

RECLASSIFICATIONS

Certain reclassifications have been made to prior year's reported amounts
in order to conform with the current year presentation. These reclassifications
did not impact our net income or stockholders' equity.

52

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

REVENUE RECOGNITION

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

INVENTORIES

Inventories include international oil produced but not sold. Crude oil from
our 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, 2002 and
December 31, 2001 consisted of approximately 138,541 and 170,471 barrels of
crude oil, respectively, valued at $2.7 million and $2.4 million, respectively,
and is carried at the lower of average cost or market. Also included in
inventories are materials and supplies, which also are stated at the lower of
average cost or market.

FOREIGN CURRENCY

The functional currency for Australia is the Australian dollar; the
functional currency for the United Kingdom is the British pound. The functional
currency for all other foreign operations is the U.S. dollar. Translation
adjustments resulting from translating our Australian subsidiary's Australian
dollar financial statements and our United Kingdom subsidiary's British pound
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.

FINANCIAL INSTRUMENTS

Cash equivalents include highly liquid investments with a maturity of three
months or less when acquired. We invest cash in excess of operating requirements
in U.S. Treasury Notes, Eurodollar bonds and investment grade commercial paper.
Cash equivalents are stated at cost, which approximates fair market value.

We have included fair value information in these notes when the fair value
of our financial instruments is different from the book value. Due to the short
maturity of our financial instruments classified as current assets and
liabilities, the book value approximates fair value.

On January 1, 2001, we adopted Statement of Financial Accounting Standards
(SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities."
See Note 5, "Commodity Derivative Instruments and Hedging Activities." For all
years prior to 2001, we accounted for our hedging activities in accordance with
SFAS No. 80. Gains and losses on our commodity derivative contracts were
recognized in revenue in the period in which the underlying production was
delivered. Unrealized gains and losses on our commodity derivative contracts
were not recognized on our balance sheet under SFAS No. 80.

OIL AND GAS PROPERTIES

We use 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 the 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 end of
period oil and gas prices as adjusted for the effects of hedging; 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.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Application of full cost accounting rules did not result in a ceiling test
writedown in 2002. However, we did record a domestic ceiling test writedown of
$106 million ($68 million after-tax) at December 31, 2001. This impairment was
primarily the result of lower commodity prices at year-end 2001. Based on an
interim interpretation from the SEC that is applicable to all companies that use
the full cost method of accounting, the full cost ceiling test impairment
calculations took into account the effects of hedging. This interim
interpretation, which is subject to further consideration by the SEC before it
is finalized, requires that certain conditions be met in order to take into
account the effects of hedging in the calculation of full cost ceiling test
impairment, including that the hedges qualify under SFAS No. 133 and are
documented and designated as such and that the policy be applied on a consistent
basis whether or not the hedged price is higher than the current market price.
The writedown would have been $184 million ($118 million after-tax) if we had
not used hedge adjusted prices. Additionally, we 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.

FURNITURE, FIXTURES AND EQUIPMENT

Furniture, fixtures and equipment are recorded at cost and are depreciated
over their estimated useful lives, which range between three and seven years,
using the straight-line method. At December 31, 2002 and 2001, furniture,
fixtures and equipment of $17.2 million and $12.6 million, respectively, is net
of accumulated depreciation of $9.2 million and $5.7 million, respectively.

ABANDONMENT AND DISMANTLEMENT COSTS

Future abandonment and dismantlement costs include costs to dismantle and
relocate or dispose of our offshore production platforms, FPSOs, gathering
systems, wells and related structures. We develop estimates of our future
abandonment and dismantlement costs for each of our properties based upon the
type of production structure, depth of water, currently available abandonment
procedures and consultations with construction and engineering consultants. Such
estimates are re-evaluated at least annually by our engineers.

Total estimated future abandonment and dismantlement costs associated with
our properties were $127.7 million, $125.6 million and $120.4 million as of
December 31, 2002, 2001 and 2000, respectively.

Estimated future abandonment and dismantlement costs are accrued on a
unit-of-production method based on proved reserves. Our accounting for these
costs changed effective January 1, 2003, see "New Accounting Standards" below.
The portion of future abandonment and dismantlement costs that has been accrued
is included in accumulated depreciation, depletion and amortization and was
$79.7 million, $68.4 million and $56.9 million as of December 31, 2002, 2001 and
2000, respectively.

INCOME TAXES

We use 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.

STOCK-BASED COMPENSATION

We account for our employee stock options using the intrinsic value method
prescribed by Accounting Principles Board (APB) Opinion No. 25.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

If the fair value based method of accounting under SFAS No. 123,
"Accounting for Stock-Based Compensation," had been applied, our net income and
earnings per common share for 2002, 2001 and 2000 would have approximated the
pro forma amounts below:

CONCENTRATION OF CREDIT RISK

We operate a substantial portion of our oil and gas properties. As the
operator of a property, we make full payment for costs associated with the
property and seek reimbursement from the other working interest owners in the
property for their share of those costs. Our joint interest partners consist
primarily of independent oil and gas producers. If the oil and gas exploration
and production industry in general was adversely affected, the ability of our
joint interest partners to reimburse us could be adversely affected.

Our oil and gas production purchasers consist primarily of independent
marketers, major oil and gas companies and gas pipeline companies. We perform
credit evaluations of, and monitor on a ongoing basis, the financial condition
of the purchasers of our production. Based on our evaluation, we obtain cash
escrows, letters of credit and parental guarantees from selected purchasers.
Over the past several years, we have sold a substantial portion of our oil and
gas production to two purchasers (see " -- Major Customers" below). The
remaining portion of our production is sold to a number of major oil and gas
companies and smaller marketing companies. We have not experienced any
significant losses from uncollectible accounts.

All of our hedging transactions have been carried out in the
over-the-counter market. The use of hedging transactions involves the risk that
the counterparties may be unable to meet the financial terms of these
transactions. The counterparties for all of our hedging transactions have an
"investment grade" credit rating. We monitor on an ongoing basis the credit
ratings of our hedging counterparties. At December 31, 2002, Bank of Montreal,
Morgan Stanley and J Aron & Company were the counterparties with respect to 61%
of our hedged future production.

MAJOR CUSTOMERS

We sold oil and gas production representing more than 10% of our revenues
before the effects of hedging for the year ended December 31, 2002 to Superior
Natural Gas Corporation (25%) and ConocoPhillips Inc. (23%); for the year ended
December 31, 2001 to Conoco Inc. (28%) and Superior Natural Gas Corporation
(25%); and for the year ended December 31, 2000 to Conoco Inc. (35%) and
Superior Natural Gas Corporation (16%). Because alternative purchasers of oil
and gas are readily available, we believe that the loss of either or both of
these purchasers would not have a material adverse effect on us.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

ACCOUNTING CHANGES

We 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, we recorded a cumulative effect
adjustment 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.

On January 1, 2002, we began assessing hedge effectiveness based on the
total changes in cash flows on our collar and floor contracts as described by
the Derivative Implementation Group (DIG) Issue G20, "Cash Flow Hedges:
Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash
Flow Hedge." Accordingly, we have elected to prospectively record subsequent
changes in the fair value of our collar and floor contracts, including changes
associated with time value, in accumulated other comprehensive income (loss).
Gains or losses on these collar and floor contracts will be reclassified out of
other comprehensive income (loss) and into earnings when the forecasted sale of
production occurs. For the year ended December 31, 2002, we recorded $29.1
million of expense under the income statement caption "Unrealized commodity
derivative income (expense)." This expense is associated with the settlement of
collar and floor contracts during the twelve-month period ended December 31,
2002 and primarily reflects the reversal of time value gains of approximately
$24.7 million recognized in earnings in 2001, prior to the adoption of DIG Issue
G20. Had we applied DIG Issue G20 from the January 1, 2001 adoption date of SFAS
133, our income statement caption "Unrealized commodity derivative income
(expense)" would have only reflected $0.5 million and $0.2 million of expense in
2002 and 2001, respectively, representing the ineffective portion of our hedges.
As a result, net income would have increased by $18.6 million in 2002 and
decreased by $16.3 million in 2001.

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 the 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 was 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 accounting principle on the consolidated
statement of income for the year ended December 31, 2000.

NEW ACCOUNTING STANDARDS

In 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations". This statement changes the method of accounting for costs
associated with the retirement of long-lived assets (e.g. oil and gas production
facilities, etc.) that we are obligated to incur. The statement requires 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 asset
retirement cost be capitalized as part of the carrying amount of the associated
asset. Under our previous accounting method, we recognized the cost to abandon
our oil and gas properties over their productive lives on a unit-of-production
basis.

We adopted SFAS No. 143 effective January 1, 2003. A pre-tax cumulative
effect gain of approximately $8 million will be reported in our consolidated
statement of income on January 1, 2003. We will also report an increase in our
assets of approximately $160 million and an increase in our liabilities of
approximately $152 million. There will be no impact on our reported cash flows
as a result of adopting SFAS No. 143.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In the second quarter of 2002, the FASB issued SFAS No. 145, "Recision of
FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and
Technical Corrections as of April 2002." This statement provides guidance for
income statement classifications of gains and losses on extinguishment of debt
and accounting for certain lease modifications that have economic effects that
are similar to sale-leaseback transactions. Our adoption of SFAS No. 145 on
January 1, 2003 had no effect on our financial statements.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires
that a liability for costs associated with an exit or disposal activity be
recognized when the liability is incurred and establishes that fair value is the
objective for initial measurement of the liability. The provisions of SFAS No.
146 are effective for exit or disposal activities that are initiated after
December 31, 2002. Our adoption of SFAS 146 on January 1, 2003 had no effect on
our financial statements.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure, an amendment of FASB Statement No. 123."
SFAS No. 148 provides alternative methods of accounting for entities that elect
to transition from the intrinsic value method of accounting for stock-based
compensation to the fair value method. In addition, this statement amends the
disclosure requirements of SFAS No. 123 to require disclosures in both annual
and interim financial statements about the method of accounting for stock-based
compensation and the effect of the method used on reported results. We adopted
the disclosure provisions of this statement in our year-end 2002 financial
statements. We continue to apply the intrinsic value method of accounting for
our stock-based compensation plans.

In November 2002, the FASB issued Interpretation No. (FIN) 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." FIN 45 requires certain guarantees to be
recorded at fair value, which is different from the current practice of
recording a liability only when a loss is probable and reasonably estimable, as
those terms are defined in SFAS No. 5, "Accounting for Contingencies." FIN 45
has a dual effective date. The initial recognition and measurement provisions
are applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The disclosure requirements in the interpretation are
effective for financial statements for interim or annual periods ending after
December 15, 2002. We do not expect the adoption of FIN 45 to have a material
effect on our financial statements. See Note 7, "Debt -- Gas Sales Obligation,"
regarding the guarantee by one of our subsidiaries associated with the Gas Sales
Obligation.

In January 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities, an interpretation of ARB 51." The primary objectives of FIN
46 are to provide guidance on the identification of entities for which control
is achieved through means other than through voting rights (these entities are
referred to as "variable interest entities" or "VIEs") and how to determine if a
business enterprise should consolidate the VIE. This new model for consolidation
applies to an entity for which either (1) the equity investors (if any) do not
have a controlling financial interest or (2) the equity investment at risk is
insufficient to finance that entity's activities without receiving additional
subordinated financial support from other parties. In addition, FIN 46 requires
that all enterprises with a significant variable interest in a VIE make
additional disclosures regarding their relationship with the VIE. We are
currently evaluating the impact of FIN 46 on our financial statements; however
we do not believe that we have any VIEs that will require consolidation in our
financial statements under this interpretation.

2. EARNINGS PER SHARE

Basic earnings per common share (EPS) is computed by dividing net income
(the numerator) by the weighted average number of common shares outstanding for
the period (the denominator). Diluted EPS is

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

similarly calculated using the treasury stock method except that the denominator
is increased to reflect the potential dilution that could occur if outstanding
stock options and convertible securities were exercised for or converted into
common stock. See Note 9, "Convertible Preferred Securities of Newfield
Financial Trust I" and Note 13, "Stock-Based Compensation -- Stock Options."

The following is the calculation of basic and diluted weighted average
shares outstanding for each of the years in the three-year period ended December
31, 2002:

The calculation of shares outstanding for diluted EPS for the years ended
December 31, 2002, 2001 and 2000 does not include the effect of outstanding
stock options to purchase 1,087,850, 907,300 and 127,000 shares, respectively,
because to do so would have been antidilutive.

3. ACQUISITIONS:

On November 26, 2002, we acquired all of the outstanding capital stock of
EEX Corporation and EEX became a wholly owned subsidiary of Newfield Exploration
Company. We acquired EEX primarily to further our efforts to expand our onshore
operations. The EEX properties are very complementary to our previously existing
South Texas property base. The acquisition also accelerated our expansion into
deepwater.

58

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Set forth below is the calculation of the EEX purchase price and the
allocation of the purchase price to the assets acquired and liabilities assumed
based on their relative fair values.

CALCULATION OF PURCHASE PRICE (IN THOUSANDS):
Shares of common stock issued............................... 7,104
Stock price(1)............................................ $ 36.348
--------
Fair value of stock issued................................ $258,216
Debt repaid at closing(2)................................... 222,250
Transaction costs(3)........................................ 47,190
Fair value of liabilities at closing:
Debt(4)................................................... 162,441
Other liabilities......................................... 52,792
--------
Total purchase price for assets acquired.................... $742,889
========
ALLOCATION OF PURCHASE PRICE (IN THOUSANDS):
Oil and gas properties(5)................................. $571,502
Assets held for sale(6)................................... 35,000
Deferred tax asset(7)..................................... 84,255
Other assets.............................................. 52,132
--------
Total....................................................... $742,889
========

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

(1) Represents the average of the closing sales prices for our common stock on
five day trading days around the public announcement date of the
acquisition.

(2) Represents EEX debt that became due and was repaid at the closing of the
acquisition.

(3) Consists primarily of severance costs ($29.7 million), bankers' fees ($7.0
million) and other direct transaction costs ($10.5 million). The severance
costs result from change in control provisions in employment contracts and
employee plans.

(4) Represents $100 million principal amount of secured notes ($23.6 million
principal amount of which we purchased in December 2002) and $62 million
related to a forward gas sales contract. See Note 7, "Debt."

(5) Proved properties were valued at $483,000 and unproved properties were
valued at $88,502.

(6) See Note 4, "Oil and Gas Assets -- Assets Held for Sale."

(7) Represents certain tax benefits acquired with EEX primarily consisting of
net operating loss carryforwards that we expect to be able to utilize. We
have not recognized benefits that are in excess of the annual limitations
prescribed by the Internal Revenue Code following a change in corporate
ownership.

Our unaudited pro forma results are presented below for the years ended
December 31, 2002 and December 31, 2001. The unaudited pro forma results have
been prepared to illustrate the effects of the EEX acquisition on our results of
operations under the purchase method of accounting as if we had acquired EEX on
January 1, 2001.

The unaudited pro forma results also give effect to our January 23, 2001
acquisition of Lariat Petroleum, Inc. as if the acquisition had occurred on
January 1, 2001. 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 our common stock

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

valued at $68 million. For financial accounting purposes, we allocated $438
million to oil and gas properties, which included a $105 million step-up
associated with deferred income taxes.

The unaudited pro forma results do not purport to represent what the
results of operations would actually have been if the acquisitions had in fact
occurred on such date or to project our results of operations for any future
date or period.

4. OIL AND GAS ASSETS:

OIL AND GAS PROPERTIES

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

60

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

We believe that substantially all of the costs not currently subject to
amortization will be evaluated within four years.

ASSETS HELD FOR SALE

In connection with the EEX acquisition, we obtained a 60% interest in a
floating production system (FPS) and pipelines. The FPS is a combination
deepwater drilling rig and processing facility capable of simultaneous drilling
and production operations. In addition to the FPS and pipelines, we also
obtained a 60% interest in a processing facility located at the end of the
pipelines in shallow water.

Because these infrastructure assets are not currently in service and we do
not have a specific use for them in our offshore operations, in late 2002 we set
about actively marketing them for sale. Based on our assessment of the market
for these assets in a third party sale, we estimated their fair value to be $35
million at the acquisition date and at December 31, 2002. However, as there is
no established third party market for these unique assets, it is difficult to
accurately estimate what a sale would bring. An immediate sale or a sale under
distressed circumstances might realize less than the current carrying value of
the assets. The costs associated with maintaining these assets are included as
an operating expense in our consolidated income statement. Such costs were not
significant in 2002.

5. COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

We maintain 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 our 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.

With respect to any particular swap transaction, the counterparty 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 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 us if the
settlement price for any settlement period is below the floor price for such
transaction, and we are 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 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 contract.

As of January 1, 2001, all derivatives are recognized on the balance sheet
at their fair value. 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. On the date that we enter into a
derivative contract, we designate the derivative as a hedge of the variability
in cash flows associated with the forecasted sale of our oil or 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 the sale of
the hedged oil or gas production. Gains or losses on our hedging transactions
are reported in oil and gas revenues on the consolidated statement of income.

We expect that within the next twelve months we will reclassify to earnings
$33.2 million in after tax losses out of the net $27.3 million in after tax
losses recorded in accumulated other comprehensive income at December 31, 2002.

61

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Any hedge ineffectiveness (which represents the amount by which the change
in the fair value of the derivative differs from the change in the cash flows of
the forecasted sale of production) is recorded in current-period earnings. On
January 1, 2002, we began assessing hedge effectiveness based on the total
changes in cash flows on our collar and floor contracts as described by DIG
Issue G20, "Cash Flow Hedges: Assessing and Measuring the Effectiveness of a
Purchased Option Used in a Cash Flow Hedge." Accordingly, we have elected to
prospectively record subsequent changes in the fair value, including changes
associated with time value, in accumulated other comprehensive income (loss).
Gains or losses on these collar and floor contracts will be reclassified out of
other comprehensive income (loss) and into earnings when the forecasted sale of
production occurs. For the year ended December 31, 2002, we recorded expense of
$29.1 million under the income statement caption "Unrealized commodity
derivative income (expense)." This expense is associated with the settlement of
collar and floor contracts during the twelve-month period ended December 31,
2002 and primarily reflects the reversal of time value gains previously
recognized in earnings during 2001, prior to the adoption of DIG Issue G20.

We formally document all relationships between hedging instruments and
hedged items, as well as our 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. We also formally assess (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, we 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, we 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 periods presented for any hedging instruments.

62

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NATURAL GAS

As of December 31, 2002, we held the commodity derivative instruments set
forth in the table below as cash flow hedges of the forecasted sale of our U.S.
natural gas production for 2003 through 2005. This table includes hedges that
were entered into by EEX prior to its acquisition.

OIL

As of December 31, 2002, we held the commodity derivative instruments set
forth in the table below as cash flow hedges of the forecasted sale of our U.S.
Gulf Coast oil production for 2003 through 2005.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

6. ACCRUED LIABILITIES:

As of the indicated dates, our accrued liabilities consisted of the
following:

7. DEBT:

As of the indicated dates, our long-term debt consisted of the following:

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

(1) Our capacity under our credit facility is available to repay current amounts
due under the gas sales obligation and our money market lines of credit and,
therefore, these obligations have been classified as long-term.

CREDIT ARRANGEMENTS

At December 31, 2002, we maintained our reserve-based revolving credit
facility with Chase Manhattan Bank, as agent. The banks participating in the
facility have committed to lend us up to $425 million. The amount available
under the facility is subject to a calculated borrowing base determined by banks
holding 75%

64

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of the aggregate commitments. The borrowing base is reduced by the principal
amount of any outstanding senior notes ($300 million at December 31, 2002), 30%
of the principal amount of any outstanding senior subordinated notes ($250
million at December 31, 2002), the outstanding principal amount of the secured
notes ($77 million at December 31, 2002) and an agreed valuation for the gas
sales obligation ($60 million at December 31, 2002). The borrowing base will be
redetermined at least semi-annually and, after reduction for the foregoing
items, was $218 million at December 31, 2002 and $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.

We also have money market lines of credit with various banks in an amount
limited by the revolving credit facility to $40 million. At December 31, 2002,
we had approximately $222 million of available capacity under our credit
arrangements.

At December 31, 2002 and 2001, the interest rate was 2.737% and 3.25%,
respectively, for LIBOR based loans under our credit facility and 2.615% and
3.00%, respectively, for the loans outstanding under our money market lines of
credit. Borrowings outstanding under our credit facility and money market lines
of credit are stated at cost, which approximates fair market value.

Our current and previous credit facilities provide or provided for the
payment of a commitment fee and a standby fee. We paid fees of approximately
$447,000, $397,000 and $315,000 for the years ended December 31, 2002, 2001 and
2000, respectively.

SENIOR NOTES

On February 22, 2001, we issued $175 million aggregate principal amount of
our 7 5/8% Senior Notes due 2011 priced (at 99.931% of par) with a yield to
maturity of 7.635%. Net proceeds from the offering of $173.1 million were used
to repay outstanding indebtedness under our revolving credit facility incurred
in connection with our January 2001 acquisition of Lariat Petroleum. Interest is
payable on each March 1 and September 1, commencing September 1, 2001.

The estimated fair market value of our 7.45% Senior Notes due 2007, based
on quoted market prices at December 31, 2002 and 2001, was $130.1 million and
$126.3 million, respectively. The estimated fair market value of our 7 5/8%
Senior Notes due 2011, based on quoted market prices at December 31, 2002 and
2001, was $183.6 million and $173.0 million, respectively.

Our senior notes are unsecured and unsubordinated obligations and rank
equally with all of our other existing and future unsecured and unsubordinated
obligations. We may redeem some or all of our senior notes at any time before
their maturity at a redemption price based on a make-whole amount plus accrued
and unpaid interest to the date of redemption. The indentures governing our
senior notes contain covenants that limit our ability to, among other things
incur debt secured by certain liens, enter into sale/leaseback transactions and
enter into merger or consolidation transactions. The indentures also provide
that if any of our subsidiaries guarantee any of our indebtedness at any time in
the future, then we will cause our senior notes to be equally and ratably
guaranteed by that subsidiary.

SENIOR SUBORDINATED NOTES

On August 13, 2002, we sold $250 million principal amount of our 8 3/8%
Senior Subordinated Notes due 2012 priced with a yield to maturity of 8.50%. The
net proceeds from the offering of approximately $241.8 million were used to
repay EEX debt that became due at the closing of the EEX acquisition and to pay
transaction costs. Interest accruing prior to the closing of the EEX acquisition
was capitalized as a cost of the transaction. The estimated fair market value of
the 8 3/8% Senior Subordinated Notes due 2012, based on quoted market prices at
December 31, 2002, was $245.0 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The notes are unsecured senior subordinated obligations that rank junior in
right of payment to all of our present and future senior indebtedness. We may
redeem some or all of the notes at any time on or after August 15, 2007 at a
redemption price stated in the indenture governing the notes. Prior to August
15, 2007, we may redeem all but not part of the notes at a redemption price
based on a make-whole amount plus accrued and unpaid interest to the date of
redemption. In addition, before August 15, 2005, we may redeem up to 35% of the
original principal amount of the notes with the net cash proceeds of certain
sales of our common stock at 108.375% of the principal amount plus accrued and
unpaid interest to the date of redemption. The indenture governing the notes
limits our ability to incur additional debt, make restricted payments, pay
dividends on or redeem our capital stock, make certain investments, create
liens, make certain dispositions of assets, engage in transactions with
affiliates and engage in mergers, consolidations and certain sales of assets.

SECURED NOTES

In the second quarter of 2001, EEX assumed the obligations under the
secured notes in connection with the termination of two leveraged leasing
arrangements. The notes accrue interest at a rate of 7.54% per year and are
secured by the floating production system and pipelines described in Note 4,
"Oil and Gas Assets -- Assets Held for Sale." Redemption of the notes prior to
2006 may require us to pay make-whole premiums. Principal is payable in annual
installments on January 2 of each year (except 2006) with the final installment
due in 2009.

The following is a summary of principal amounts by year of maturity at
December 31, 2002 (in thousands):

2003........................................................ $ 11,215
2004........................................................ 12,093
2005........................................................ 11,366
2006........................................................ --
2007........................................................ 12,067
Thereafter.................................................. 30,437
--------
Total secured notes....................................... 77,178
Less current maturities..................................... (11,215)
--------
Total long-term secured notes............................. $ 65,963
========

GAS SALES OBLIGATION

In 1999, EEX entered into a gas forward sales contract with Bob West
Treasure L.L.C. (BWT), an affiliate of Enron Corporation. Pursuant to the gas
sales contract, EEX committed to deliver approximately 50 Bcfe of production to
BWT in exchange for proceeds of $105 million. BWT receives an adjusted market
price as the volumes are delivered. EEX also has an obligation to market the
delivered volumes of gas for BWT. Under the terms of the gas sales contract, EEX
is required to make a cash payment if the committed gas volumes are not
delivered. Additionally, BWT holds liens on certain of EEX's oil and gas
properties as security if the committed gas volumes are not delivered or the
cash payments are not made.

As of the date of our acquisition of EEX, we recorded a liability of
approximately $62 million, which represented the current market value of the
approximate 16 Bcfe of reserves remaining under the gas sales

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contract. We have accounted for the obligations under the gas sales contract as
debt in our consolidated balance sheet because:

- the transaction is cancellable by EEX prior to maturity via a lump sum
payment;

- BWT has recourse against EEX if the committed volumes are not delivered;
and

- EEX has significant continuing involvement via their obligation to
produce the subject reserves and market them on behalf of BWT.

Payments under the gas sales contract are amortized as the underlying gas
is delivered under the interest method using an interest rate of 9.5%. As of
December 31, 2002, the unamortized balance was approximately $60 million and the
fair value of the remaining obligation was approximately $64.5 million. The
interest portion of the payment is included as a component of interest expense
in our consolidated income statement.

EEX also guaranteed BWT's performance under certain swap agreements between
BWT and Enron entered into concurrently with the gas sales contract. If BWT
fails to make payments under the swap agreements, EEX must perform under the
guarantee by paying Enron on BWT's behalf. The maximum amount that EEX could be
required to pay under this guarantee is not determinable and would depend on the
settlement value of the swaps at the time of any BWT default. BWT, which is
outside of the Enron bankruptcy proceedings, continues to meet its contractual
obligations under its swap agreements and, therefore, EEX has not been required
to perform under this guarantee.

8. MINORITY INTEREST:

In conjunction with EEX entering into the gas sales obligation (see Note 7,
"Debt -- Gas Sales Obligation"), BWT acquired a limited membership interest in
an EEX subsidiary that owns a substantial portion of EEX's consolidated
reserves, a portion of which are subject to the gas sales obligation. We have
reported this limited membership interest as a "minority" interest on our
consolidated balance sheet based on our estimated price to re-acquire the
interest. BWT's limited membership interest is not allocated any earnings and is
not entitled to cash distributions.

9. CONVERTIBLE PREFERRED SECURITIES OF NEWFIELD FINANCIAL TRUST I:

In August 1999, Newfield Financial Trust I, a Delaware business trust and a
100% owned, finance subsidiary (in each case, as defined in Rule 3-10 of
Regulation S-X) of Newfield Exploration Company, issued, in an underwritten
public offering, $143.75 million (2.875 million securities having a liquidation
preference of $50 each) of 6.5% Cumulative Quarterly Income Convertible
Preferred Securities, Series A. The proceeds from the issuance of these
securities (commonly referred to as trust preferred securities) were used to
purchase $143.75 million of Newfield Exploration Company's 6.5% Junior
Subordinated Convertible Debentures due 2029. The interest terms and payment
dates of the debentures correspond to the distribution terms of the trust
preferred securities. Newfield Exploration 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 our 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 prior to the
distribution payment date. We 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
deferral period, the trust will defer the payment of distributions, but accrued
distributions on the trust preferred securities will compound quarterly and we
will generally not be permitted to declare or pay any

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

dividends or distributions on, or redeem or acquire, any of our 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 our common stock at the rate of 1.3646 shares of our common
stock per trust preferred security. The conversion rate is subject to adjustment
for certain dilutive events and is currently equivalent to a conversion price of
$36.64 per share of our 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
debentures by us. The debentures are redeemable by us at any time.

The estimated fair market value of the trust preferred securities at
December 31, 2002 and 2001, based on quoted market prices, was $159.0 million
and $155.3 million, respectively.

10. 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 Newfield
Exploration Company, 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 would
provide a bundle of rights that together place the holder in the same position
as if Newfield Exploration Company had fully and unconditionally guaranteed the
trust's payment obligations on its trust preferred securities. To date, no
preferred securities of the trust have been issued.

11. INCOME TAXES:

Income before income taxes consists of the following:

The total provision (benefit) for income taxes consists of the following:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The provision for income tax for each of the years in the three-year period
ended December 31, 2002 was different than the amount computed using the federal
statutory rate (35%) for the following reasons:

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

1) We realized a one-time tax benefit resulting from a change in Australian tax
law enacted in 2002 enabling us to file our tax return on a consolidated
basis. As a result, we realized the benefit of certain tax losses previously
stranded in certain of our Australian subsidiaries.

2) We reduced the valuation allowance on our Australian net operating loss
carryforward in 2000 primarily as a result of a substantial increase in
estimated taxable income in Australia.

The components of the deferred tax asset and the deferred tax liability are as
follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2002, we had net operating loss (NOL) carryforwards for
federal income tax purposes of approximately $231.6 million that may be used in
future years to offset taxable income. Utilization of the NOL carryforwards is
subject to annual limitations due to certain stock ownership changes. To the
extent not utilized, the NOL carryforwards will begin to expire during the years
2003 through 2022 with a majority expiring in 2019 through 2022.

U.S. deferred taxes have not been provided on foreign income of $44.2
million that is permanently reinvested internationally. We currently do not have
any foreign tax credits available to reduce U.S. taxes on this income if it was
repatriated.

12. TREASURY STOCK:

In May 2001, our Board of Directors authorized the expenditure of up to $50
million to repurchase shares of our common stock. We repurchased 823,000 shares
in late 2001 for total consideration of $24.7 million at an average of $29.97
per share. In February 2003, our Board of Directors authorized the expenditure
of up to $50 million from that date forward to repurchase shares of our common
stock. No limit was placed on the duration of the repurchase program. Subject to
applicable securities laws, we may purchase stock at times and in amounts that
we deem appropriate. We also repurchase stock in conjunction with our
stock-based compensation plans. Such repurchases have not been significant.

13. STOCK-BASED COMPENSATION:

We have several stock-based compensation plans, which are described below.
We apply the intrinsic value method prescribed by APB Opinion No. 25 and related
interpretations in accounting for our stock-based compensation plans.

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STOCK OPTIONS

We have granted stock options under several stock option and omnibus stock
plans.

The following is a summary of all stock option activity for 2000, 2001 and
2002:

Options 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
our existing plans, the exercise price will not be less than the fair market
value per share of our common stock on the date of grant.

The weighted average fair value of an option to purchase one share of
common stock granted during 2002, 2001 and 2000 was $14.74, $16.08 and $15.41,
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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table summarizes information about stock options outstanding
and exercisable at December 31, 2002:

Common stock issued through the exercise of non-qualified stock options
results in a tax deduction for us equivalent to the compensation income
recognized by the option holder. For financial reporting 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 2002, 2001 and 2000 resulted in a tax benefit to us of
approximately $2.5 million, $2.1 million and $6.6 million, respectively.

At December 31, 2002, we had approximately 1,931,000 additional shares
available for issuance pursuant to the existing plans. As discussed below, our
omnibus stock plans also provide for the issuance of restricted shares. Any such
issuance would reduce the number of shares available for stock option grants. Of
the additional shares available at December 31, 2002, only 305,089 may be
granted as restricted shares.

RESTRICTED SHARES

At December 31, 2002, there were 176,000 shares of our common stock
outstanding that remain subject to forfeiture. These restricted shares fully
vest on the ninth anniversary of the date of grant, but vesting may be
accelerated if certain performance criteria are met. For a discussion of the
number of shares of common stock available for grant as restricted shares,
please see the immediately preceding paragraph.

Under our non-employee director restricted stock plan, immediately after
each annual meeting of our stockholders each of our directors then in office who
has not been an employee of our company at any time since the beginning of the
calendar year preceding the calendar year in which the annual meeting is held
receives a number of restricted shares determined by dividing $30,000 by the
fair market value on the date of the annual meeting. The forfeiture restrictions
lapse on the day before the first annual meeting of stockholders following the
date of issuance of the shares if the holder remains a director until that time.
At December 31, 2002, 31,086 shares remain available for grants under this plan.

In accordance with APB Opinion No. 25, we recognize unearned compensation
in connection with the grant of restricted shares equal to the fair value of the
shares on the date of grant. As the restricted shares vest, we reduce unearned
compensation and recognize compensation expense. The table below sets forth

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information about our restricted share grants and compensation expense relating
to restricted share grants for each of the years in the three-year period ended
December 31, 2002.

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

(1) Eight directors received grants in each of 2002 and 2001 and seven directors
received grants in 2000.

(2) Represents expense for grants made in current and prior periods based on
applicable vesting provisions.

EMPLOYEE STOCK PURCHASE PLAN

Pursuant to our 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 our common stock for a purchase price
equal to 85% of the lesser of the fair market value of our 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.
Employees of our Australian and United Kingdom subsidiaries are not eligible to
participate.

At December 31, 2002, 141,649 shares of common stock were available for
issuance pursuant to our stock purchase plan. Under the plan, we sold 29,410
shares in 2002 at a weighted average price of $30.27; 28,941 shares in 2001 at a
weighted average price of $27.16; and 22,180 shares in 2000 at a weighted
average price of $26.75. In accordance with APB Opinion No. 25 and related
interpretations, we have not recognized any compensation expense with respect to
the plan.

The weighted average fair value of the option to purchase stock during 2002
was $9.85; during 2001 was $9.86; and during 2000 was $8.87. The fair value of
each option granted under the stock purchase plan is estimated on the date of
grant using the Black-Scholes option-pricing model with the following weighted
average assumptions for grants in 2002, 2001 and 2000:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

14. PENSION PLAN OBLIGATION:

Prior to our acquisition of EEX, EEX established and maintained a defined
benefit pension plan. Only a few EEX employees who have continued their
employment with us are eligible for further accrual of benefits under this plan.
Accrued retirement costs are funded based upon applicable requirements of
federal law and deductibility for federal income tax purposes.

The weighted average assumptions for the pension plan as of December 31,
2002 were:

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15. EMPLOYEE BENEFIT PLANS:

INCENTIVE COMPENSATION PLAN

With respect to calendar years ended prior to January 1, 2003, we granted
incentive compensation awards to our employees pursuant to our 1993 incentive
compensation plan. The incentive plan provided for the creation each calendar
year of an award pool that, in general, equalled 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 our interest and the interests of certain investors that
participated in our activities in such properties. If, for a particular year,
the portion of the pool that related to our interests was in excess of 5% of our
adjusted net income (as defined in the plan) for that year, such excess could
not be awarded to employees. The incentive plan is administered by the
Compensation Committee of our Board of Directors with award amounts recommended
by our chief executive officer. All employees were eligible for awards if
employed on both October 1 and December 31 of the performance period. Awards
could (and generally did) have both a current and a deferred component. Eligible
employees could elect for all or a portion of deferred awards to be paid in our
common stock instead of cash. In such case, the number of shares of common stock
to be awarded was determined by using the fair market value of our 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 incentive plan for the years ended
December 31, 2002, 2001 and 2000 was $10.1 million, $11.6 million and $12.8
million, respectively.

401(K) PLAN

We sponsor a 401(k) profit sharing plan under Section 401(k) of the
Internal Revenue Code. This plan covers all of our employees other than
employees of our Australian and United Kingdom subsidiaries. We match $1.00 for
each $1.00 of employee deferral, with our contribution not to exceed 8% of an
employee's salary, subject to limitations imposed by the Internal Revenue
Service. Our contributions to the 401(k) plan totaled $1.5 million, $1.3 million
and $0.7 million for the years ended December 31, 2002, 2001 and 2000,
respectively.

DEFERRED COMPENSATION PLAN

During 1997, we implemented a highly compensated employee deferred
compensation plan. This non-qualified plan allows an eligible employee to defer
a portion of the employee's salary or bonus on an annual basis. We match $1.00
for each $1.00 of employee deferral, with our contribution not to exceed 8% of
an employee's salary, subject to limitations imposed by the plan. Our
contribution with respect to each participant in the deferred compensation plan
is reduced by the amount of contribution made by us to our 401(k) plan for that
participant. Our contributions to the deferred compensation plan totaled $32,000
in 2002, $32,000 in 2001 and $29,000 in 2000.

POST-RETIREMENT MEDICAL PLAN

We also sponsor a post-retirement medical plan that covers retired
employees until they attain the age of 65. Our accrued benefit obligation under
this plan was approximately $2.2 million at December 31, 2002. For measurement
purposes, we assumed a discount rate of 6.5% and an 11% annual rate of increase
in the per capita cost of covered health care benefits. The rate of increase in
cost of benefits is assumed to gradually decrease to a 5% ultimate rate by 2008.
Our periodic benefit cost for this plan is not significant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

16. COMMITMENTS AND CONTINGENCIES:

LEASE COMMITMENTS

We have entered into non-cancellable operating leases for office space in
Houston and San Antonio, Texas, Tulsa, Oklahoma and Perth, Australia. Rent
expense for office space for the years ended December 31, 2002, 2001 and 2000
was $4.8 million, $4.1 million and $3.2 million, respectively. Future minimum
payments required under our office and other material leases as of December 31,
2002 are as follows (in thousands):

LITIGATION

We have 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, we do not expect these matters to have a material
adverse effect on our financial position, cash flows or results of operations.

17. STOCKHOLDER RIGHTS PLAN:

In 1999, we adopted a stockholder rights plan. The plan is designed to
ensure that all of our stockholders receive fair and equal treatment if a
takeover of our company is proposed. 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 our common stock. The rights will become exercisable only if a person or
group acquires 20% or more of our outstanding voting stock or announces a tender
or exchange offer that would result in ownership of 20% or more of our 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 our common stock. Our 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 our outstanding voting stock by a person or group.

If a person or group acquires 20% or more of our outstanding voting stock,
each right will entitle holders, other than the acquiring party, to purchase
shares of our common stock 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 our outstanding voting stock, our Board of
Directors may, at its option, exchange the rights in whole or part for shares of
our common stock. Under this option, we would issue one share of our common
stock, or one one-thousandth of a share of new preferred stock, for each two
shares of our 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 our
voting stock.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

If, after the rights have become exercisable, we merge or otherwise combine
with another entity, or sell assets constituting more than 50% of our assets or
producing more than 50% of our 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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

18. GEOGRAPHIC INFORMATION:

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) General and administrative expense includes non-cash stock compensation
charges of $2,801, $2,751 and $3,047 for 2002, 2001 and 2000, respectively.

19. SUPPLEMENTAL CASH FLOW INFORMATION:

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

20. RELATED PARTY TRANSACTIONS:

Prior to our acquisition of Lariat Petroleum in January 2001, Warburg,
Pincus Ventures, L.P. (WPV) owned approximately 88% of the outstanding capital
stock of Lariat on a fully diluted basis. WPV received cash proceeds for its
stock of approximately $78.6 million and 1,864,735 shares of our common stock in
the acquisition. WPV also received approximately $39.1 million as repayment in
full of notes payable by Lariat to WPV. In connection with the acquisition, we
entered into a registration rights agreement with the former stockholders of
Lariat that received our common stock in the acquisition, including WPV.
Pursuant this agreement, we filed a shelf registration statement under the
Securities Act to register the reoffer and resale of these shares of common
stock. We are required to maintain the effectiveness of the registration
statement for the shorter of two years and the date upon which all of the shares
covered by the registration statement have been sold. In addition, we agreed to
provide customary indemnification and contribution for the benefit of the other
parties to the registration rights agreement, including WPV.

The sole general partner of WPV is Warburg, Pincus & Co. (WP & Co.).
Warburg Pincus LLC (WP LLC) manages WPV. Howard H. Newman, one of our directors,
is a general partner of WP & Co and a Vice Chairman, Managing Director and
member of WP LLC.

Three private equity funds (the WP funds) managed by WP LLC held all of the
outstanding preferred stock of EEX prior to our acquisition of EEX and received
an aggregate of 4,700,000 shares of our common stock in exchange for their EEX
preferred stock in the acquisition. Concurrently with the execution of the
merger agreement to acquire EEX, we entered into a registration rights agreement
and a voting agreement with the WP funds. Pursuant to the registration rights
agreement, we filed a shelf registration statement under the Securities Act to
register the reoffer and resale of the shares of our common stock received by
the WP funds in the acquisition. We are required to maintain the effectiveness
of the registration statement until all of the shares of our common stock
received by the WP funds in the acquisition have been sold or until such time as
such shares are eligible for resale under Rule 144(k) under the Securities Act.
In addition, if we propose to file a registration statement or a prospectus
supplement to an already effective shelf registration statement with respect to
an underwritten public offering of our common stock, the WP funds have the right
to include their shares of our commons stock in the registration, subject to
certain limitations. We also agreed to provide customary indemnification and
contribution for the benefit of the WP funds. Pursuant to the voting agreement,
we paid the WP funds $62,500, representing 50% of the filing fee paid by the WP
funds in connection with antitrust filings they made in connection with the
acquisition.

WP & Co is the sole general partner of the WP funds and Mr. Newman was a
director of EEX prior to its acquisition.

Terry Huffington, one of our directors, is a principal owner of Huffco
International L.L.C. and David A. Trice, our President and Chief Executive
Officer, is a minority owner of Huffco. In May 1997, prior to Ms. Huffington and
Mr. Trice becoming affiliated with us, we acquired from Huffco an entity now
known as Newfield China, LDC, the owner of a 35% interest (subject to a 51%
reversionary interest held by the Chinese government) in a production sharing
contract area, referred to as "Block 05/36," in the Bohai Bay, offshore 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, plus the cash purchase price we paid
Huffco for Newfield China ($6.2 million). At December 31, 2002, Newfield China
had approximately $36 million in unrecovered costs, no reserves and no revenue
and, as a result, no dividends have been paid to date on its preferred shares.

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21. SUBSEQUENT EVENT:

On March 6, 2003, we reached an agreement with BWT, certain lenders and
insurers of BWT and the unsecured creditors committee of Enron to terminate
EEX's gas forward sales contract. (See Note 7, "Debt -- Gas Sales Obligation").
The agreement, which is subject to the final approval of the Enron bankruptcy
court, provides for the termination of the gas sales contract, the swaps entered
into in connection with the gas sales contract and any other agreements between
EEX, BWT and Enron related to the gas sales contract, including the guarantee
and all liens and other security interests on EEX's properties, in exchange for
a payment to BWT representing:

- the remaining unamortized obligation under the gas sales contract;

- the fair market value of certain swaps entered into by BWT in conjunction
with the gas sales contract;

- an agreed upon value of $0.5 million for BWT's limited membership
interest in an EEX subsidiary that BWT acquired in conjunction with the
gas sales contract.

22. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):

The results of operations by quarter for the years ended December 31, 2002
and 2001 are as follows:

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

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

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NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED

Costs incurred for oil and gas property acquisition, exploration and
development activities for each of the years in the three-year period ended
December 31, 2002 are as follows:

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NEWFIELD EXPLORATION COMPANY

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

Capitalized costs for our oil and gas producing activities consist of the
following at the end of each of the years in the three-year period ended
December 31, 2002:

84

NEWFIELD EXPLORATION COMPANY

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

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.

ESTIMATED NET QUANTITIES OF PROVED OIL AND GAS RESERVES

The following table sets forth our net proved reserves, including the
changes therein, and proved developed reserves at the end of each year in the
three-year period ended December 31, 2002, as estimated by our petroleum
engineering staff:

85

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." The
information is based on estimates prepared by our petroleum engineering staff.
It may be useful for certain comparative purposes, but should not be solely
relied upon in evaluating us or our performance. Further, information contained
in the following tables 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 our current
value.

We believe that in reviewing the information that follows the following
factors should be taken into account:

- future costs and selling prices will probably differ from those required
to be used in these calculations;

- 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;

- 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

- 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
flows before tax. Future income tax expense has been computed by applying
year-end statutory tax rates to aggregate future pre-tax net cash flows 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.

86

NEWFIELD EXPLORATION COMPANY

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

The standardized measure of discounted future net cash flows from our
estimated proved oil and gas reserves is as follows:

87

NEWFIELD EXPLORATION COMPANY

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

88

NEWFIELD EXPLORATION COMPANY

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

Set forth in the table below is a summary of the changes in the
standardized measure of discounted future net cash flows for our proved oil and
gas reserves for each of the years in the three-year period ended December 31,
2002:

89

NEWFIELD EXPLORATION COMPANY

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

90

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required by Item 10 is incorporated herein by reference to
such information as set forth in our definitive Proxy Statement for our 2003
Annual Meeting of Stockholders to be held on May 1, 2003 and to the information
set forth in Item 4A, "Executive Officers," in this report.

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated herein by reference to
such information as set forth in our definitive Proxy Statement for our 2003
Annual Meeting of Stockholders to be held on May 1, 2003.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

The information required by Item 12 is incorporated herein by reference to
such information as set forth in our definitive Proxy Statement for our 2003
Annual Meeting of Stockholders to be held on May 1, 2003.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by Item 13 is incorporated herein by reference to
such information as set forth in our definitive Proxy Statement for our 2003
Annual Meeting of Stockholders to be held on May 1, 2003.

ITEM 14. CONTROLS AND PROCEDURES

On February 10, 2003, our chief executive officer and chief financial
officer performed an evaluation of our disclosure controls and procedures, which
have been designed to permit us to effectively identify and timely disclose
important information. They concluded that the controls and procedures were
effective. We have made no significant changes in our internal controls or in
other factors that could significantly affect our internal controls since
February 10, 2003.

Pursuant to Section 906 of The Sarbanes-Oxley Act of 2002, our chief
executive officer and chief financial officer have provided certain
certifications to the SEC. These certifications accompanied this report when
filed with the SEC, but are not set forth herein.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) Financial Statements, Financial Statement Schedules and Exhibits

(1) Financial Statements: Reference is made to the index set forth on
page 45 of this Annual Report on Form 10-K.

(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 our consolidated financial statements.

(3) Index of Exhibits: See "Index of Exhibits" below for a list of
those exhibits filed herewith or incorporated herein by reference.

91

(b) Reports on Form 8-K.

On October 2, 2002, we filed a Current Report on Form 8-K announcing the
shut-in of production in the Gulf of Mexico as a result of Hurricane Lili.

On October 16, 2002, we filed a Current Report on Form 8-K announcing an
update to estimated 2002 production as a result of storms in the Gulf of Mexico.

On November 1, 2002, we filed a Current Report on Form 8-K in connection
with the announcement of our financial and operating results for the third
quarter of 2002 and furnished our operating estimates for the fourth quarter of
2002.

On November 27, 2002, we filed a Current Report on Form 8-K reporting that
we had acquired EEX Corporation on November 26, 2002.

On December 5, 2002, we filed a Current Report on Form 8-K reporting an
amendment of our credit facility and filing a copy of the amendment as an
exhibit.

On December 20, 2002, we filed a Current Report on Form 8-K furnishing
updated operational and financial guidance for the fourth quarter of 2002
following the recent acquisition of EEX Corporation.

(c) Index of Exhibits

3. EXHIBITS

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

* Filed herewith.

+ Identifies management contracts and compensatory plans or arrangements.

95

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 14th day of
March, 2003.

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 and in the capacities indicated and on the 14th day of March, 2003.

96

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, David A. Trice, certify that:

1. I have reviewed this Annual Report on Form 10-K of Newfield Exploration
Company (the "Registrant");

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
Registrant as of, and for, the periods presented in this annual report;

4. The Registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:

a. designed such disclosure controls and procedures to ensure that
material information relating to the Registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

b. evaluated the effectiveness of the Registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and

c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date.

5. The Registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the Registrant's auditors and the audit committee
of Registrant's Board of Directors (or persons performing the equivalent
functions):

a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the Registrant's ability to record,
process, summarize and report financial data and have identified for the
Registrant's auditors any material weaknesses in internal controls; and

b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the Registrant's internal
controls; and

6. The Registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to the significant deficiencies and material weaknesses.

By: /s/ DAVID A. TRICE
------------------------------------
David A. Trice
President and Chief Executive
Officer

Date: March 14, 2003

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Terry W. Rathert, certify that:

1. I have reviewed this Annual Report on Form 10-K of Newfield Exploration
Company (the "Registrant");

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
Registrant as of, and for, the periods presented in this annual report;

4. The Registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:

a. designed such disclosure controls and procedures to ensure that
material information relating to the Registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

b. evaluated the effectiveness of the Registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and

c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date.

5. The Registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the Registrant's auditors and the audit committee
of Registrant's Board of Directors (or persons performing the equivalent
functions):

a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the Registrant's ability to record,
process, summarize and report financial data and have identified for the
Registrant's auditors any material weaknesses in internal controls; and

b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the Registrant's internal
controls; and

6. The Registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to the significant deficiencies and material weaknesses.

By: /s/ TERRY W. RATHERT
------------------------------------
Terry W. Rathert
Vice President and Chief Financial
Officer

Date: March 14, 2003

INDEX TO EXHIBITS

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

* Filed herewith.

+ Identifies management contracts and compensatory plans or arrangements.