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

Back to GetFilings.com

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003

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,
SUITE 2020,
HOUSTON, TEXAS 77060
(Address of principal executive offices) (Zip Code)

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 $1,843,394,000 as of June
30, 2003 (based on the last sale price of such stock as quoted on the New York
Stock Exchange).

As of March 10, 2004, there were 56,335,235 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 6,
2004, which is incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

ii

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. 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 Gulf of Mexico, the U.S. onshore Gulf Coast, the
Anadarko and Arkoma Basins, China's Bohai Bay and the North Sea. Over the last
three 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 2003, we had proved reserves of 1.32 Tcfe. Of those reserves:

- 83% were natural gas;

- 87% were proved developed;

- 41% were located in the Gulf of Mexico; and

- 59% were located onshore in the U.S.

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. Over the last three years, the amount of
funds dedicated to exploration spending has increased significantly. We 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. Large acquisitions over
the last few years, recent drilling success and our growing onshore acreage
positions provide us with significant drilling opportunities.

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. Our
traditional shelf plays and low-risk drilling opportunities in the Mid-Continent
are complemented with two higher potential plays in the Gulf of Mexico -- the
deep shelf and deepwater. We may also increase our exposure to high potential
prospects through the addition of new focus areas overseas.

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 2003, we
operated about 72% of our total production.

TECHNOLOGY. By investing in technology, we give our people the tools they
need to succeed. Over the last five years, we have invested about $115 million
in the acquisition of new seismic data. This significant expenditure is related
primarily to the onshore Gulf Coast and the deepwater Gulf of Mexico. At
February 29, 2004, we held licenses or otherwise had access to 3-D seismic
surveys covering approximately 5,100 blocks (about 25 million acres) in the Gulf
of Mexico's shallow waters, 1,450 blocks in the deepwater Gulf of Mexico, 5,600
square miles onshore Texas and Louisiana, 3,300 square miles in the Anadarko
Basin, 400 square kilometers covering the area where we are active offshore
China and 19,100 square kilometers in the Southern Gas Basin of the North Sea.

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 29, 2004, our employees owned or had options
to acquire about 8% of our outstanding common stock on a fully diluted basis.

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
shallow water Gulf has substantial existing infrastructure, including gathering
systems, platforms and pipelines, facilitating cost effective operations and
timely development of discoveries. Although the traditional shelf plays in the
Gulf of Mexico are mature, we believe that significant opportunities remain in
deep shelf and deepwater plays. As a result, we are allocating a larger portion
of our budget to these plays. We also are evaluating a concept we refer to as
"Treasure Project." 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 associated risks
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 twelve successful
deep shelf wells out of 17 attempts to date. The risk profile of these wells is
significantly different than our traditional shelf drilling. These deeper
targets are more difficult to detect with traditional seismic processing and the
cost to drill and the risk of mechanical failure are likely to be significantly
higher because of the drilling depth and high temperature and pressure. These
prospects have dryhole costs of $8-15 million per well.

2

Treasure Project. Through our acquisition of EEX, we gained an interest in
26 blocks associated with an ultra-deep drilling concept in shallow water known
as "Treasure Island." Since the acquisition, the geographic scope of this
concept has been significantly expanded and we now own an interest in 80 lease
blocks associated with it. We now refer to the entire concept, wherever located
within the shallow waters of the Gulf, as "Treasure Project." This high-risk,
high potential concept has targeted depths of 25,000 feet or more. There is no
production from these depths on the Gulf of Mexico shelf today. We are
evaluating this concept and seeking partners to carry all, or a substantial
portion of, the drilling cost on one or more wells. Dry hole costs are expected
to range from $35-70 million per well.

Deepwater. We established a deepwater team in 2001 and made our first
deepwater discovery in 2003. 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 nearer to 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.
We now own an interest in about 85 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
and made major acquisitions in 2000 and 2002 to grow our presence. Today, the
onshore Gulf Coast is a major focus area for us, representing about one-third of
our total proved reserves and daily production. Our operations are concentrated
in South Texas, the Val Verde Basin in southwest Texas, East Texas and southern
Louisiana. 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. We have continued to build our land position and
production in this region through leasing efforts and acquisitions. 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 Mid-Continent
provides an opportunity for future growth. It is a gas-rich province
characterized by multiple productive zones and relatively low drilling costs.
Recent efforts have focused on a new initiative that we call "gas mining."
Through this initiative, we have identified low risk, marginal resource areas
that have been under-exploited. Keys to success include scale, repeatability and
lowering of finding costs through drilling and completion innovations. Our
Mid-Continent assets are managed by 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 in China's Bohai Bay. In 2002, we opened an office in London,
England, to pursue opportunities in the North Sea. We acquired an interest in
one producing field and one undeveloped discovery in the North Sea in December
2003. We expect to drill our first well in the region in the second half of 2004
on a license block awarded in 2003. We also hold two lease blocks offshore
Brazil. We continue to evaluate and pursue other opportunities for expansion in
select international areas. In September 2003, we sold all of our operations in
Australia.

PLANS FOR 2004

Our capital budget for 2004 is $600 million, excluding acquisitions. We
expect that about half of the budget will be invested in the Gulf of Mexico
(including deepwater), 35-40% in the onshore U.S. and the remainder in
international projects. We plan to drill about 250 wells in 2004, over half of
which are expected to be in the Mid-Continent.

GULF OF MEXICO. We plan to remain an active driller in the traditional
shallow water plays of the Gulf of Mexico. About half of our 2004 capital budget
is allocated to the Gulf of Mexico, where we expect to drill 25-35 wells. In
addition to 15-20 wells in the traditional shelf, we expect to drill six to
eight wells in the deep shelf and three to five wells in deepwater.

3

ONSHORE GULF COAST. In 2004, we will balance development drilling of lower
risk opportunities with some higher risk, higher impact exploration tests. We
plan to drill 50-60 wells.

MID-CONTINENT. Our Mid-Continent drilling program is predominantly
comprised of lower risk exploitation wells. In 2004, we expect to drill about
160 wells. The majority of the planned drilling is associated with our gas
mining initiative.

INTERNATIONAL. In the second half of 2004, we expect to drill a well on
our Cumbria Prospect, located on license area 49/4b in the Southern Gas Basin of
the North Sea. In China's Bohai Bay, the operator of our two undeveloped fields
is in the process of filing development plans with the Chinese government during
2004 and field development will begin following government approval.

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

As of March 1, 2004, we had about 375 employees. All but five of our
employees are located in the U.S. We believe that relationships with our
employees are satisfactory. None of our 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.

REGULATION AND OTHER FACTORS AFFECTING OUR BUSINESS AND FINANCIAL RESULTS

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

ITEM 2. PROPERTIES

CONCENTRATION

We have diversified our asset base over the last several years. About 41%
of our proved reserves are now located in the Gulf of Mexico compared to about
94% just five years ago. In total, 74% of our proved reserves are located in the
Gulf of Mexico and along the onshore regions of the Gulf Coast. While our ten
largest properties accounted for approximately 30% of our equivalent proved
reserves at year-end 2003, no single

4

property held more than 5% of our proved reserves or more than 3% 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, 2003, we owned interests in about 250 leases on the Shelf and
85 leases in deepwater (approximately 1.7 million gross acres) and about 330
gross wells. We operated 79% of our proved reserves at December 31, 2003.

ONSHORE GULF COAST

We have a significant acreage position in Texas and Louisiana. As of
December 31, 2003, we owned an interest in about 290,000 gross acres and more
than 400 gross wells. We operated 71% of our proved reserves at December 31,
2003.

MID-CONTINENT

We have a sizeable presence in the Anadarko and Arkoma Basins, established
with an acquisition in early 2001. Since that time, we have added to our acreage
position through subsequent acquisitions and leasing efforts. As of December 31,
2003, we owned an interest in approximately 614,000 gross lease acres, 21,700
gross mineral acres and 1,700 gross wells. We operated 81% of our proved
reserves at December 31, 2003.

INTERNATIONAL

CHINA. We own a 35% interest in a license area located 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 license area
covers more than 230,000 gross 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. Four appraisal wells were drilled in the fields in 2003
and we now believe that commercial oil reserves exist. The operator is in the
process of filing a development plan with the Chinese government. If the plan is
approved, we will begin field development. We have not booked any proved
reserves on these fields to date.

NORTH SEA. In 2003, we acquired an interest in one producing field and one
undeveloped discovery in the North Sea. We expect to drill our first well in the
region in the second half of 2004 on a license block awarded in 2003.

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, 2003. 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 prices of $5.93 per Mcf for gas and $30.79 per Bbl
for oil. This calculation does not include the effects of hedging.

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

(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."

All reserve information in this report is based on estimates prepared by
our petroleum engineering staff. As a requirement of our revolving credit
facility, independent reserve engineers prepare separate reserve reports with
respect to properties holding at least 80% of our proved reserves. For December
31, 2003, the independent reserve engineers' reports covered properties
representing 83% of our proved reserves and for such properties, the reserves
were within 3% of the reserves we reported for such properties. 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 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 file 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).

6

RESERVE REPLACEMENT COST

The table below provides information regarding the costs we incurred for
oil and gas property acquisition, exploration and development activities for the
year ended December 31, 2003 and the proved reserves we added during that
period.

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

(1) Excludes capitalized asset retirement costs of $132.3 million recorded in
compliance with SFAS No. 143, "Accounting for Asset Retirement Obligations,"
adopted on January 1, 2003. See the unaudited supplementary oil and gas
disclosures to our consolidated financial statements.

(2) Includes extensions, discoveries and other additions, revisions of previous
estimates and purchases of properties but excludes sales of properties. See
the unaudited supplementary oil and gas disclosures to our consolidated
financial statements.

(3) Costs incurred divided by reserves added.

(4) Includes $5.0 million of costs associated with our exploration efforts
offshore China.

(5) Not meaningful.

7

DRILLING ACTIVITY

The following table sets forth our drilling activity (other than drilling
activity related to our discontinued operations in Australia) for each year in
the three-year period ended December 31, 2003.

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

(1) We drilled two gross (0.70 net), one gross (0.35 net) and four gross (1.4
net) appraisal wells in China during 2003, 2002 and 2001, respectively, that
are not included in the table because the commerciality of these wells had
not been determined as of December 31, 2003.

We were in the process of drilling one gross (1.0 net) exploratory well and 16
gross (14.2 net) development wells at December 31, 2003, all of which are in the
U.S.

8

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, 2003 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. 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 by unaffiliated third parties. The charges customarily vary with the
depth and location of the well being operated.

9

ACREAGE DATA

We own interests in developed and undeveloped oil and gas acreage in the
locations set forth in the table below. 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 acreage as of December 31, 2003.

On January 1, 2004, our undeveloped acreage position associated with Treasure
Project increased by 70,052 net acres as a result of the termination of an
agreement with BP Exploration & Production Inc.

10

The table below summarizes by year and geographic area our undeveloped
lease or license acreage scheduled to expire in the next five years. In most
cases, the drilling of a commercial well, or the filing and approval of a
development plan, will hold acreage beyond the expiration date. We own fee
mineral interests in 204,914 gross (80,878 net) undeveloped acres. These
interests do not expire.

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.

11

ITEM 3. LEGAL PROCEEDINGS

We have been named as a defendant in a number of lawsuits arising in the
ordinary course of our 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 2003.

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth the names and ages (as of February 29, 2004)
of and positions held by our executive officers. Our executive officers serve at
the discretion of our 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 elected 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.

12

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 10, 2004, the last reported sales price of our common stock on the
New York Stock Exchange was $46.60 per share.

As of March 10, 2004, there were approximately 2,600 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.

13

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 2, "Properties -- Proved Reserves
and Future Net Cash Flows" and Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations," of this report.

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

(1) General and administrative expense includes stock compensation charges of
$3,059, $2,801, $2,751, $3,047 and $1,999 for 2003, 2002, 2001, 2000 and
1999, 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 effect of adoption of SFAS No. 133 is a reduction in
net income of $4.8 million, or $0.10 per diluted share, and is shown as
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 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

15

value of our collar and floor contracts (other than contracts that are part
of three-way collar 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 No. 133, our income statement caption "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.

(4) We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," on
January 1, 2003. This statement changes the method of accounting for
expected future costs associated with our obligation to perform site
reclamation, dismantle facilities and plug and abandon wells. As a result of
the adoption of SFAS No. 143, we recognized an after-tax gain of $5.6
million for the cumulative effect of change in accounting principle. See
Note 1, "Organization and Summary of Significant Accounting Policies --
Accounting for Asset Retirement Obligations," to our consolidated financial
statements.

(5) On September 5, 2003, we sold our wholly owned subsidiary, Newfield
Exploration Australia Ltd., which held all of our Australian assets. As a
result of the sale, the historical results of operations of Newfield
Exploration Australia Ltd. are reflected on our consolidated financial
statements as "discontinued operations." See Note 2, "Discontinued
Operations," to our consolidated financial statements.

16

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

OVERVIEW

We are an independent oil and gas company engaged in the exploration,
development and acquisition of crude oil and natural gas properties. Our areas
of operation include the Gulf of Mexico, the U.S. onshore Gulf Coast, the
Anadarko and Arkoma Basins, China's Bohai Bay and the North Sea.

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. Generally, 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, development and abandonment 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 "Other Factors Affecting Our Business and Financial Results" in
this Item 7 for a more detailed discussion of a number of other factors that
affect our business, financial condition and results of operations.

RESULTS OF OPERATIONS

On September 5, 2003, we sold our wholly owned subsidiary, Newfield
Exploration Australia Ltd., which held all of our Australian assets. As a result
of the sale, the historical results of operations of Newfield Exploration
Australia Ltd. are reflected on our consolidated financial statements as
"discontinued operations." Please see Note 2, "Discontinued Operations," to our
consolidated financial statements appearing later in this report. Except where
noted, discussions in this report relate to our continuing activities.

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 and/or production volumes. Revenues for 2003 reached
a record

17

$1.0 billion, and were 62% higher than 2002 revenues primarily because of higher
natural gas and crude oil prices and a 25% increase in production.

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

(1) 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 $0.02,
$0.03 and $0.03 for the years ended 2003, 2002 and 2001, respectively.
The realized price of oil and condensate was reduced by $0.34, $0.35
and $0.31 for the years ended 2003, 2002 and 2001, respectively.
Average realized prices include the effects of hedging.

PRODUCTION. Our total oil and gas production in 2003 (stated on a natural
gas equivalent basis) increased 25% over 2002 levels. Production increased
primarily because of the acquisition of EEX in November 2002 and other small
acquisitions and successful drilling efforts in 2003. In addition, 2002
production was reduced by our decision to voluntarily curtail approximately one
Bcfe of production in the first quarter of that year in response to low
commodity prices and by the shut-in of four Bcfe of production in the second
half of that year in response to storms in the Gulf of Mexico. Our 2002 total
oil and gas production increased 6% over 2001 primarily as a result of
successful drilling in the Gulf of Mexico and the Mid-Continent and the
acquisition of EEX. These increases were partially offset by our voluntary
curtailment and the weather related shut-ins described above.

NATURAL GAS. Our 2003 natural gas production increased 27% when compared
to 2002. The increase primarily was the result of the EEX acquisition in
November 2002. Our development drilling programs in South Texas, the
Mid-Continent and the Gulf of Mexico also were major contributors to our
production growth. In addition, 2002 production was reduced by our decision to
voluntarily curtail approximately one Bcfe of production in the first quarter of
that year in response to low commodity prices and by the shut-in of four Bcfe of
production in the second half of that year in response to storms in the Gulf of
Mexico. Our 2002 natural gas production was nearly 9% higher than 2001 levels.
The increase was the result of successful drilling in the Gulf of Mexico and the
Mid-Continent and the acquisition of EEX in November 2002. Partially offsetting
this increase was our voluntary curtailment and the weather related shut-ins
described above.

CRUDE OIL AND CONDENSATE. Our 2003 oil and condensate production increased
16% when compared to 2002 levels. Development drilling programs in the U.S. and
the acquisition of EEX in November 2002 were partially offset by natural field
declines in all producing regions. Our 2002 oil production decreased about 6%
when compared to 2001 primarily reflecting natural field declines in the U.S.

18

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. We are a growth-oriented company. As such, our proved
reserves and production have grown steadily since our founding. Naturally, our
operating expenses have increased with our growth. As a result, we believe the
most informative way to analyze changes in our operating expenses from one
period to another is on a unit-of-production, or Mcfe, basis. The following
table presents information about our operating expenses for each of the years in
the two-year period ended December 31, 2003.

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

(1) Stock compensation charges were $3,059, or $0.01 per Mcfe, for 2003 and
$2,801, or $0.02 per Mcfe, for 2002. Total operating expense, inclusive of
these charges but excluding the gas sales obligation settlement and
redemption of our trust preferred securities, was $613,723, or $2.78 per
Mcfe, for 2003 and $459,178, or $2.61 per Mcfe, for 2002.

Our total operating expense (excluding stock compensation) for 2003, stated
on a unit-of-production basis, increased 7% over 2002. The increase was
primarily related to the following items.

- Lease operating expense (LOE) on a unit-of-production basis for 2003
increased 4% over the same period of last year in large part due to the
addition of higher cost onshore properties through the EEX acquisition
and a higher level of workover activity in 2003.

- Production taxes on a unit-of-production basis increased 75% in 2003 due
to higher commodity prices when compared to the prior year. Additionally,
a greater percentage of our production is now onshore and subject to
production taxes.

- Depreciation, depletion and amortization (DD&A) (excluding furniture,
fixtures and equipment) for 2003 was $1.76 per Mcfe versus $1.66 per Mcfe
for 2002. Our adoption of SFAS No. 143 on January 1,

19

2003 (see "-- Cumulative Effect of Change in Accounting
Principle -- Adoption of SFAS No. 143") resulted in $0.03 per Mcfe of the
increase. The remainder of the increase resulted from the increased cost
of reserve additions during the year.

- General and administrative expense (G&A) for 2003, before stock
compensation expense and capitalized direct internal costs, on a
unit-of-production basis, increased $0.05 per Mcfe or 16%, as compared to
the same period of 2002. This increase is primarily due to increased
salaries and benefits related to an increase in the number of employees
due to growth of the company, a payment made to employees located in
EEX's San Antonio, Texas office upon the closing of the office in June
2003, and an increase in incentive compensation expense due to the
significant increase in 2003 earnings. This increase was offset by an
increase in capitalized direct internal costs. During 2003, we
capitalized $26.7 million of direct internal costs, compared to $7.0
million in 2002.

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 but excluding the ceiling test writedown, was $459,178, or
$2.61 per Mcfe, for 2002 and $423,190, or $2.54 per Mcfe, for 2001.

Our total operating expense for 2002 (excluding stock compensation), stated
on a unit-of-production basis, increased 3% over 2001. The increase was
primarily related to the following items.

- Lease operating expense on a unit-of-production basis for 2002 remained
flat compared to the same period of 2001. The earlier period 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, lease
operating expense for 2002 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 production subject to production taxes increased 14% in
2002, our production tax expense decreased because of a 21% 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. During 2002, we capitalized $7.0 million of direct internal
costs, compared to $5.3 million in 2001.

20

WRITEDOWN OF OIL AND GAS PROPERTIES. We did not writedown any of our oil
and gas properties in 2003 or 2002. 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). The full
cost ceiling test impairment calculations took into account the effects of
hedging. The writedown would have been $184 million ($118 million after-tax) if
we had not used hedge adjusted prices for the volumes that were subject to
hedges.

GAS SALES OBLIGATION SETTLEMENT. Pursuant to a gas forward sales contract
entered into in 1999, EEX committed to deliver approximately 50 Bcf of
production to Bob West Treasure L.L.C. (BWT) in exchange for proceeds of $105
million. As of the date of our acquisition of EEX, we recorded a liability of
approximately $62 million, which represented the then current market value of
approximately 16 Bcf of reserves remaining under the gas sales contact. We
accounted for the obligation under the gas sales contract as debt on our
consolidated balance sheet.

On March 31, 2003, pursuant to a settlement agreement with BWT and the
other parties to related transactions, the gas sales contract, the swaps entered
into by BWT in connection with the gas sales contract and all other agreements
related to the gas sales contract, including the guarantee and all liens and
other security interests on EEX's properties, were terminated in exchange for a
payment by us of approximately $73 million. This payment represented:

- the remaining unamortized obligation under the gas sales obligation;

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

- various transactions fees related to the termination; and

- an agreed upon value for BWT's membership interest in an EEX subsidiary.

In connection with the settlement, we recognized a loss of $10 million
under the caption "Gas sales obligation settlement and redemption of securities"
on our consolidated statement of income.

REDEMPTION OF TRUST PREFERRED SECURITIES. We redeemed all of the
outstanding 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities
of Newfield Financial Trust I on June 27, 2003 for an aggregate redemption price
of approximately $148.4 million, or $38.31 on a per share of underlying common
stock basis (excluding in each case accrued but unpaid distributions). The
holders of only a small number of the securities elected to convert their
securities into shares of our common stock prior to the redemption date (a total
of 48,076 shares of common stock were issued). Included in the aggregate
redemption price is $6.5 million of optional redemption premium. Upon
redemption, this premium and $4.0 million of unamortized offering costs (which
were being amortized over the 30-year life of the securities) were expensed
under the caption "Gas sales obligation settlement and redemption of securities"
on our consolidated statement of income.

We financed the redemption with the net proceeds from the issuance and sale
of 3.5 million shares of our common stock on May 27, 2003 (approximately $131.2
million, or $37.49 per share) and borrowings under our revolving credit
facility.

INTEREST EXPENSE. The following table presents information about our
interest expense for each of the years in the three-year period ended December
31, 2003.

21

Our interest expense increased in both 2003 and 2002 as compared to the
prior year because of higher debt levels outstanding under our credit
arrangements and the issuance of our $250 million principal amount 8 3/8% Senior
Subordinated Notes due 2011 in August 2002, the net proceeds of which were used
to repay EEX debt that came due at the closing of the acquisition in November
2002 and transaction costs associated with the acquisition. Because the proceeds
were held in escrow pending closing, interest that accrued prior to the closing
(approximately $1.6 million) was capitalized as a cost of the transaction.

We also assumed $162.4 million of EEX obligations -- $100.8 million
principal amount of secured notes and $61.6 million under a forward gas sales
contract -- that remained outstanding following the closing. The secured notes
accrued interest at a rate of 7.54% per year and the forward gas sales contract
had an effective interest rate of 9.5% per year. In December 2002, we
repurchased $23.6 million principal amount of the secured notes. During 2003, we
repurchased or repaid $74.3 million principal amount of the secured notes.
Premiums paid to the holders of the repurchased notes of $3.9 million were
charged to interest expense in 2003. We also settled the forward gas sales
contract in March 2003. The repurchase of secured notes and the settlement of
the gas sales obligation were financed with borrowings under our credit
arrangements. See Note 8, "Debt -- Secured Notes and -- Gas Sales Obligation
Settlement," to our consolidated financial statements.

Capitalized interest increased during 2003 because of our increased
unproved property base resulting from the EEX acquisition. Distributions on
preferred securities decreased in 2003 due to the redemption of our trust
preferred securities in June 2003. See Note 10, "Redemption of Trust Preferred
Securities," to our consolidated financial statements.

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 unrealized expense of $6.1
million for the year ended 2003 primarily represents the hedge ineffectiveness
associated with our hedging program ($1.1 million) and the fair value adjustment
for our three-way collar contracts that do not qualify for hedge accounting
($5.0 million). The unrealized expense of $29.1 million in 2002 primarily
reflects the reversal of the time value gains that were previously recognized
during 2001. The $24.8 million of unrealized income for the year ended 2001
primarily reflects the change in the time value of our open hedging contracts.
For a further description of these items, please see Note 6, "Commodity
Derivative Instruments and Hedging Activities," to our consolidated financial
statements appearing in this Form 10-K.

TAXES. The effective tax rate for the years ended December 31, 2003, 2002
and 2001 was 36%. The effective tax rate for all three years was more than the
federal statutory tax rate primarily due to the state income taxes associated
with applicable income from various states.

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE -- ADOPTION OF SFAS NO.
143. We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," as
of January 1, 2003. This statement changes the method of accounting for expected
future costs associated with our obligation to perform site reclamation,
dismantle facilities and plug and abandon wells. Prior to January 1, 2003, we
recognized the undiscounted estimated cost to abandon our oil and gas properties
over their estimated productive lives on a unit-of-production basis as a
component of DD&A expense and no liability or capitalized costs associated with
such abandonment were recorded on our consolidated balance sheet. SFAS No. 143
requires that, if a reasonable estimate of the fair value of an abandonment
obligation can be made, a liability (an "asset retirement obligation" or "ARO")
will be recorded on our consolidated balance sheet and the asset retirement cost
will be capitalized in oil and gas properties in the period in which the
retirement obligation is incurred.

In general, the amount of an ARO and the costs capitalized will be equal to
the estimated future cost to satisfy the abandonment obligation using current
prices that are escalated by an assumed inflation factor after discounting the
future cost back to the date that the abandonment obligation was incurred using
an assumed cost of funds for our company. After recording these amounts, the ARO
will be accreted to its future estimated value using the same assumed cost of
funds and the additional capitalized costs will be depreciated on a
unit-of-production basis over the productive life of the related properties.
Both the accretion and the depreciation are included in DD&A expense on our
consolidated statement of income.
22

At adoption of SFAS No. 143, a cumulative effect of change in accounting
principle was required in order to recognize:

- an initial ARO as a liability on our consolidated balance sheet;

- an increase in oil and gas properties for the cost to abandon our oil and
gas properties;

- cumulative accretion of the ARO from the period incurred up to the
January 1, 2003 adoption date; and

- cumulative depreciation on the additional capitalized costs included in
oil and gas properties up to the January 1, 2003 adoption date.

As a result of our adoption of SFAS No. 143, we recorded a $134.8 million
increase in the net capitalized costs of our oil and gas properties and an
initial ARO of $128.5 million. Additionally, we recognized an after-tax gain of
$5.6 million (the after-tax amount by which additional capitalized costs, net of
accumulated depreciation, exceeded the initial ARO, including in each case
discontinued operations) as the cumulative effect of change in accounting
principle.

RESULTS OF DISCONTINUED OPERATIONS

On September 5, 2003, we sold our wholly owned subsidiary, Newfield
Exploration Australia Ltd., which held all of our Australian assets. As a result
of the sale, the historical financial position, results of operations and cash
flow of Newfield Exploration Australia Ltd. are reflected in our financial
statements as "discontinued operations." Please see Note 2, "Discontinued
Operations," to our consolidated financial statements.

The results of operations of Newfield Exploration Australia Ltd., which
have been reclassified as discontinued operations for the twelve months ended
December 31, 2003, 2002 and 2001 are summarized as follows:

The decrease in earnings from discontinued operations for the year ended
2003 compared to the same period in 2002 was primarily due to the loss on sale
of Newfield Exploration Australia Ltd. of $9.9 million, a ceiling test writedown
of $7.3 million ($5.1 million after-tax) recorded in the second quarter of 2003
and the timing of oil liftings from our FPSOs in 2003 as compared to 2002.

The decrease in earnings from discontinued operations for the year ended
2002 compared to the same period in 2001 was due to the timing of oil liftings
from our FPSOs in 2002 as compared to 2001 and foreign currency exchange gains
and losses. This decrease was offset by a $3.1 million tax benefit resulting
from revised tax legislation enacted in Australia in 2002.

23

LIQUIDITY AND CAPITAL RESOURCES

Our 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. Based on current commodity prices and the high percentage of our
anticipated 2004 production that has been hedged, we currently anticipate that
our cash flow will exceed our capital budget (which excludes acquisitions) by
more than $100 million in 2004. This excess should allow us to pay down debt and
other obligations during the year, unless we increase our capital budget.

Our cash flow from operations during 2003 exceeded our capital expenditures
(including the acquisition of Primary Natural Resources) during that period. We
used the excess cash flow to pay down debt (see "-- Credit Arrangements" and
"-- Cash Flows from Continuing Operations" below and Note 8, "Debt," to our
consolidated financial statements).

CREDIT ARRANGEMENTS. We maintain our reserve-based revolving credit
facility with JPMorgan 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 10, 2004) and 30% of the principal amount of any outstanding senior
subordinated notes (a reduction of $75 million at March 10, 2004). The borrowing
base is redetermined at least semi-annually and, after reduction for the
foregoing items, was $425 million at March 10, 2004. 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, 2005. We are in the process of replacing the
facility with a new four year, $600 million, senior unsecured, reserve-based
revolving credit facility. We expect that the borrowing base features of the new
facility will be substantially identical to those in the current facility.

We also have money market lines of credit with various banks. Our credit
facility limits our borrowings under these lines to $40 million. At March 10,
2004, we had outstanding borrowings under our credit facility of $50 million and
no borrowings under our money market lines. Consequently, at March 10, 2004, we
had approximately $415 million of available capacity under our credit
arrangements.

At December 31, 2003, the interest rate for our outstanding LIBOR-based
loans was 2.5% and for our outstanding money market lines of credit was 3.0%. At
December 31, 2002, the interest rate was 2.737% for LIBOR-based loans under our
credit facility and 2.615% for the loans outstanding under the money market
lines of credit.

During the third quarter of 2003, we entered into interest rate swap
agreements which provide for us to pay variable and receive fixed interest
payments and are designated as fair value hedges of a portion of our senior
notes (see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk"
and Note 8, "Debt -- Interest Rate Swaps," to our consolidated financial
statements.

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 $61.3 million as of December 31, 2003. This compares to a working
capital deficit of $57.0 million at the end of 2002 and a surplus of $65.6
million at the end of 2001. Our 2003 working capital deficit included $12.1
million in asset retirement obligations (see Note 1, "Organization and Summary
of Significant Accounting Policies -- Accounting for Asset Retirement
Obligations"). Our 2002 working capital deficit included an $11.2 million
secured note payment due January 2003 and accrued severance costs associated
with the EEX acquisition.

24

CASH FLOWS FROM CONTINUING OPERATIONS. Our net cash flows from continuing
operations were $659.2 million in 2003, $383.3 million in 2002 and $495.6
million in 2001. Our net cash flows from continuing operations in 2003 increased
72% when compared to 2002. The significant increase is due to higher oil and gas
prices and a 25% increase in production volumes primarily due to the EEX
acquisition. Net cash flows from continuing operations in 2002 declined 23% 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.

CAPITAL EXPENDITURES. Our 2003 capital spending was $647 million, a 27%
decrease from 2002 capital spending of $888 million. Capital spending in 2003
included approximately $142 million in acquisitions. In 2003, we also invested
$302 million in domestic development, $155 million in domestic exploration, $32
million in other domestic leasehold activity and $16 million internationally.
The largest component of 2002 spending was the $571 million acquisition of EEX
in late 2002. In 2002, we also invested $150 million in domestic development,
$106 million in domestic exploration, $53 million in other domestic acquisitions
and $8 million internationally. In 2001, our capital spending totaled $846
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 domestic development, $97 million in domestic
exploration and $12 million internationally.

We budgeted $600 million for capital spending in 2004, excluding
acquisitions. We expect that 50% of this budget will be invested in the Gulf of
Mexico (including deepwater), 40% in the onshore U.S. and the remainder
internationally. We anticipate that our current capital expenditure budget for
2004 will be fully 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
shortfall 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 the acquisition for drilling and development activities on
the acquired properties.

CASH FLOWS FROM FINANCING ACTIVITIES. Net cash flows used in financing
activities for the year ended December 31, 2003 were $85.4 million compared to
$137.0 million of net cash flows provided by financing activities for the same
period of 2002. During 2003, we:

- repaid or repurchased $74.3 million principal amount of secured notes;

- settled our obligation under a gas sales contract, $62.0 million of which
was accounted for as debt, in exchange for a cash payment by us;

- sold 3.5 million shares of our common stock for net proceeds of
approximately $131.2 million, or $37.49 per share; and

- redeemed all of our outstanding trust preferred securities for an
aggregate redemption price of approximately $148.4 million.

25

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, 2003. Hedging contracts are excluded because they are sensitive to
future changes in commodity prices and other factors. See "-- Oil and Gas
Hedging" below.

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

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

(2) As of December 31, 2003, all of the outstanding principal is classified
as current because the secured notes were repaid in full in January
2004.

(3) See Note 16, "Commitments 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.

26

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. Because the proceeds
were held in escrow pending the closing of the EEX acquisition, interest accrued
prior to closing of the EEX acquisition of approximately $1.6 million was
capitalized as a cost of the transaction. Interest on the notes is payable
semi-annually. 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 accrued interest at a rate of 7.54% per year and
were secured by the floating production system and pipelines described in Note
5, "Oil and Gas Assets -- Floating Production System and Pipelines," to our
consolidated financial statements. At the time we acquired EEX, $100.8 million
principal amount of secured notes were outstanding. In December 2002, we
repurchased $23.6 million principal amount of the secured notes. During 2003, we
repaid or repurchased $74.3 million of the $77.2 million outstanding principal
amount of secured notes at year-end 2002. The notes were repurchased with
borrowings under our credit arrangements. The remaining secured notes were
repaid in full in January 2004.

COMMITMENTS UNDER JOINT OPERATING AGREEMENTS. The oil and gas industry
operates in many instances through joint ventures under joint operating
agreements, and our operations are no exception. Typically, the operator under a
joint operating agreement enters into contracts, such as drilling contracts, for
the benefit of all joint venture partners. Through the joint operating
agreement, the non-operators reimburse, and in some cases advance, the funds
necessary to meet the contractual obligations entered into by the operator.
These obligations are typically shared on a "working interest" basis. The joint
operating agreement provides remedies to the operator in the event that the
non-operator does not satisfy its share of the contractual obligations.
Occasionally, the operator is permitted by the joint operating agreement to
enter into lease obligations and other contractual commitments that are then
passed on to the non-operating joint interest owners as lease operating
expenses, frequently without any identification as to the long-term nature of
any commitments underlying such expenses.

27

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. No shares were purchased under this
program.

OIL AND GAS 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
returns on some of our acquisitions and drilling programs, such as our "gas
mining" initiative. 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 75% of our 2003 production was subject to hedge
positions. In 2002, 84% of our production was subject to hedge positions,
compared to 68% in 2001.

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. In addition, the use of hedging transactions may involve basis
risk. Substantially all of our hedging transactions are settled based upon
reported settlement prices on the NYMEX. We believe there is no material basis
risk with respect to our natural gas price hedging contracts because
substantially all of our hedged natural gas production is sold at market prices
that historically have highly correlated to the settlement price. 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 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.

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, 2003, Bank of Montreal, Morgan Stanley Capital Group, Inc.,
Barclays Bank PLC and J Aron & Company were the counterparties with respect to
82% of our future hedged production. Such contracts are accounted for as
derivatives in accordance with SFAS No. 133.

In 2003, we entered into three-way collar derivative contracts. Although
our three-way collar contracts are effective as economic hedges of our commodity
price exposure, they do not qualify for hedge accounting under SFAS No. 133.

Please see the discussion and tables in Note 6, "Commodity Derivative
Instruments and Hedging Activities," to our consolidated financial statements
for a description of the accounting applicable to our hedging program and a
listing of open hedging contracts as of December 31, 2003 and the fair value of
those contracts as of that date.

28

Between December 31, 2003 and March 10, 2004, we entered into the
additional natural gas price hedging contracts set forth in the table below.

Between December 31, 2003 and March 10, 2004, we entered into the
additional oil price hedging contracts with respect to our Gulf Coast oil
production set forth in the table below.

FLOATING PRODUCTION SYSTEM AND PIPELINES

As a result of our acquisition of EEX in November 2002, we own a 60%
interest in a floating production system (FPS), some offshore pipelines and a
processing facility located at the end of the pipelines in shallow water. The
FPS is a combination deepwater drilling rig and processing facility capable of
simultaneous drilling and production operations. These infrastructure assets are
not currently in service and we do not have a specific use for them in our
offshore operations. At the time of acquisition, we estimated their fair market
value to be $35 million and classified them as "assets held for sale" under the
provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." This statement provides that an asset can only be classified
as "held for sale" for one year. Accordingly, we have now re-categorized them as
held in use assets and they will be periodically evaluated for possible
impairment.

We have engaged brokers who survey the world market for potential
application of the assets "as is" or "to-be-modified" for a particular
application. We also have direct discussions with other operators about the
potential application of the assets to their developments around the world.
Because there is no established market for these unique assets, it is difficult
to accurately estimate their fair market value. An immediate sale or a sale
under distressed circumstances might realize less than the current carrying
value of the assets. No assurance can be given that we will be successful in
selling this asset or that any sale will recover the carrying value of the
asset.

OFF-BALANCE SHEET ARRANGEMENTS

We do not currently utilize any off-balance sheet arrangements with
unconsolidated entities to enhance liquidity and capital resource positions, or
for any other purpose.

29

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The discussion and analysis of our financial condition and results of
operations are based upon the consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States. The preparation of our financial statements 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. Certain
accounting policies involve judgments and uncertainties to such an extent that
there is reasonable likelihood that materially different amounts could have been
reported under different conditions, or if different assumptions had been used.
We evaluate our estimates and assumptions on a regular basis. We base our
estimates on historical experience and various other assumptions that are
believed to be reasonable under the circumstances, the results of which form the
basis for making judgments about the carrying values of assets and liabilities
that are not readily apparent from other sources. Actual results may differ from
these estimates and assumptions used in preparation of our financial statements.
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. We discussed the
development, selection and disclosure of each of these with our audit committee.
See "Results of Operations" in this Item 7, and Note 1, "Organization and
Summary of Significant Accounting Policies," to our consolidated financial
statements for a discussion of additional accounting policies and estimates made
by management.

For discussion purposes, we have divided our significant policies into four
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 STOCK-BASED COMPENSATION may be accounted for under one of
two available methods.

- ACCOUNTING FOR COMMODITY DERIVATIVE ACTIVITIES REQUIRES ESTIMATES AND
ASSUMPTIONS regarding the valuation of derivative 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

30

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 estimated to directly relate 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 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.

All reserve information in this report is based on estimates prepared by
our petroleum engineering staff. As a requirement of our revolving credit
facility, independent reserve engineers prepare separate reserve reports with
respect to properties holding at least 80% of our proved reserves. For December
31, 2003, the independent reserve engineers' reports covered properties
representing 83% of our proved reserves and for such properties, the reserves
were within 3% of the reserves we reported for such properties.

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. The full
cost ceiling test impairment calculations also take into consideration the
effects of hedging. See "Results of Operations -- Writedown of Oil and Gas
Properties" in this Item 7.

31

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

In addition, a portion of incurred (if not previously included in the
amortization base) and future development costs associated with qualifying major
development projects may be temporarily excluded from amortization. To qualify,
a project must require significant costs to ascertain the quantities of proved
reserves attributable to the properties under development (e.g., the
installation of an offshore production platform from which development wells are
to be drilled). Incurred and future costs are allocated between completed and
future work. Any temporarily excluded costs are included in the amortization
base upon the earlier of when the associated reserves are determined to be
proved or impairment is indicated.

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, 2003, we had
approximately $331 million of costs excluded from our amortization base,
including $25.7 million associated with development costs for our deepwater Gulf
of Mexico project known as "Glider," located at Green Canyon 247/248. Because
the application of the full cost ceiling test at December 31, 2003 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 such as drilling costs and
the installation of production equipment. Future abandonment costs include costs
to dismantle and relocate or dispose of our production platforms, gathering
systems 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 extend many years into the future, estimating these future costs is
difficult and requires management to make judgments that are subject to future
revisions based upon numerous factors, including changing technology and the
political and regulatory environment. We review our assumptions and estimates of
future abandonment costs on an annual basis. The accounting for future
abandonment costs changed on January 1, 2003 with the adoption of SFAS No. 143.
This new standard requires that a liability for the discounted fair value of an
asset retirement obligation be recorded in the period in which it is incurred
and the corresponding cost capitalized by increasing the carrying amount of the
related long-lived asset. The liability is accreted to its present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. See "-- Results of
Operations -- Cumulative Effect of Change in Accounting Principle -- Adoption of
SFAS No. 143."

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 is
32

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.

Effective January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," under which goodwill is no longer subject to amortization.
Rather, goodwill of each reporting unit is tested for impairment on an annual
basis, or more frequently if an event occurs or circumstances change that would
reduce the fair value of the reporting unit below its carrying amount. In making
this assessment, we rely on a number of factors including operating results,
business plans, economic projections and anticipated cash flows. As there are
inherent uncertainties related to these factors and our judgment in applying
them to the analysis of goodwill impairment, there is risk that the carrying
value of our goodwill may be overstated or understated. We elected to make
December 31 our annual assessment date.

STOCK-BASED COMPENSATION

In accordance with current accounting standards, there are two alternative
methods that can be used to account for stock-based compensation. The first
method -- the intrinsic value method -- recognizes compensation cost as the
excess, if any, of the quoted market price of our stock at the grant date over
the amount an employee must pay to acquire the stock. Under the second
method -- the fair value method -- compensation cost is measured at the grant
date based on the value of an award and is recognized over the service period,
which is usually the vesting period. Currently, we account for our stock-based
compensation in accordance with the intrinsic value method. See Note 1,
"Organization and Summary of Significant Accounting Policies -- Stock-Based
Compensation," to our consolidated financial statements.

COMMODITY DERIVATIVE ACTIVITIES

We utilize derivative contracts to hedge against the variability in cash
flows associated with the forecasted sale of our future natural gas and oil
production. We generally hedge a substantial portion of our anticipated oil and
natural gas production for the next 18-24 months. We do not use derivative
instruments for trading purposes. Most of our derivatives qualify for hedge
accounting. Under the accounting rules, we designate these derivatives as cash
flow hedges against the price that we will receive for our future oil and
natural gas production. To the extent that changes in the fair values of these
derivatives 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. Derivatives that do not qualify for hedge
accounting (such as three-way collar contracts) are carried at their fair value
on our consolidated balance sheet. We recognize all changes in the fair value of
these contracts on our consolidated statement of income in the period in which
the change occurs.

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 an
option-pricing model. The estimated future prices are compared to the prices
fixed by the hedge agreements and the resulting estimated future cash inflows or
outflows over the lives of the hedges are discounted to calculate the fair value
of the derivative contracts. These pricing and discounting variables are
sensitive to market volatility as well as changes in future price forecasts,
regional price differences and interest rates. We periodically validate our
valuations using independent third-parties' quotations.

33

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 obligation 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. See "-- Results of Operations -- Cumulative Effect of
Change in Accounting Principle -- Adoption of SFAS No. 143."

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. See "-- Critical Accounting Policies and
Estimates -- Stock-Based Compensation" and Note 1, "Organization and Summary of
Significant Accounting Policies -- Stock-Based Compensation," to our
consolidated financial statements.

We adopted in 2002 or 2003, or will be required to adopt in 2004, several
other new accounting standards. Please see Note 1, "Organization and Summary of
Significant Accounting Policies -- Accounting Changes," to our consolidated
financial statements for a discussion of these additional new accounting
standards. Our adoption of these additional new standards has not had or is not
expected to have a material impact on our consolidated financial statements.

RECENT ACCOUNTING DEVELOPMENTS

SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other Intangible Assets," were issued by the FASB in June 2001 and became
effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141
requires that all business combinations initiated after June 30, 2001 be
accounted for using the purchase method and that certain intangible assets be
disaggregated and reported separately from goodwill. SFAS No. 142 established
new guidelines for accounting for goodwill and other intangible assets. Under
the statement, goodwill and certain other intangible assets are reviewed
annually for impairment but are not amortized. To our knowledge, substantially
all publicly traded oil and gas companies have continued to include oil and gas
rights and interests held under leases, governmental licenses or other
contractual arrangements ("leasehold interests") as part of oil and gas
properties after SFAS No. 141 and SFAS No. 142 became effective. The Emerging
Issues Task Force (EITF) has added the oil and gas industry's application of
SFAS Nos. 141 and 142 to leasehold interests to an upcoming agenda. We continue
to classify our leasehold interests as tangible oil and gas properties until
further guidance is provided. See Note 1, "Organization and Summary of
Significant Accounting Policies -- Recent Accounting Developments" to our
consolidated financial statements.

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;
34

- 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 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. There are currently no
regulations implemented by the FERC under its OCSLA authority on gatherers and
other entities outside the reach of its Natural Gas Act jurisdiction. 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

35

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.
The MMS regulations governing the calculation of royalties and the valuation of
crude oil produced from federal leases provide that the MMS will collect
royalties based upon the market value of oil produced from federal leases. On
August 20, 2003, the MMS issued a proposed rule that would change certain
components of its valuation procedures for the calculation of royalties owed for
crude oil sales. The proposed changes include changing the valuation basis for
transactions not at arm's length from spot to NYMEX prices adjusted for locality
and quality differentials, and clarifying the treatment of transactions under a
joint operating agreement. Final comments on the proposed rule were due on
November 10, 2003. We cannot predict what action the MMS will take on this
matter. We believe that the proposed rule 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 and 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"
36

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 and spill
prevention, control and countermeasure or "SPCC" plans. We have such plans in
existence and are currently upgrading or, as necessary, developing SPCC plans
that will satisfy new SPCC plan certification and implementation requirements
that become effective in August 2004 and February 2005, respectively.

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

37

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, including soil or
groundwater contamination by prior owners or operators, or to perform remedial
plugging or pit closure operations to prevent future contamination.

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;

- 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.

38

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.

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 effect 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.

39

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.

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;
40

- 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;

- 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 in 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

41

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 and Financial Results." All written
and oral forward-looking statements attributable to us or persons acting on our
behalf are expressly qualified in their entirety by such factors.

COMMONLY USED OIL AND GAS TERMS

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

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

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.

42

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.

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.
43

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.

44

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 "Oil and Gas Hedging" in Item 7 of this report.

INTEREST RATES

At December 31, 2003, we had $550 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; and

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

Our year-end 2003 variable rate debt consisted of $90 million borrowed
under our bank revolving credit facility and $5 million borrowed under our money
market lines of credit. The interest rate at December 31, 2003 for our LIBOR
based loans under our credit facility was 2.5% and the interest rate for the
money market lines was 3.0%.

During 2003, we entered into interest rate swap agreements to take
advantage of low interest rates and to obtain what we view as a more desirable
proportion of variable and fixed rate debt. These swap agreements provide for us
to pay variable and receive fixed interest payments, and are designated as fair
value hedges of a portion of our outstanding senior notes. As of December 31,
2003, $50 million principal amount of our 7.45% Senior Notes due 2007 and $50
million principal amount of our 7 5/8% Senior Notes due 2011 were subject to
interest rate swaps.

We considered our interest rate exposure at year-end 2003 to be minimal
because about 70% of our long-term debt obligations, after taking into account
our interest rate swap agreements, 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 $0.4 million.

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, 2003.

45

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

NEWFIELD EXPLORATION COMPANY
INDEX

CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA

46

MANAGEMENT RESPONSIBILITY FOR FINANCIAL STATEMENTS

Our management is responsible for the preparation, integrity and
objectivity of our consolidated financial statements and other financial
information contained in this report. Our consolidated financial statements are
prepared in accordance with accounting principles generally accepted in the
United States and, accordingly, include certain informed judgments and estimates
made by 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 properly recorded and 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 solely of
independent directors, meets regularly 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 our consolidated financial
statements and the other information appearing in this report.

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

Houston, Texas
March 10, 2004

47

REPORT OF INDEPENDENT AUDITORS

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, 2003 and 2002, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2003 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

As described in Note 1 to the consolidated financial statements, the
Company changed its method of accounting for asset retirement obligations
effective January 1, 2003. Additionally, 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.

/s/ PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 10, 2004

48

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.
49

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.
50

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.
51

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)

The accompanying notes to consolidated financial statements are an integral part
of this statement.
52

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. 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 Gulf of Mexico, the onshore U.S. Gulf Coast, the
Anadarko and Arkoma Basins, China's Bohai Bay and the North Sea.

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
subsidiaries.

On November 26, 2002, we acquired EEX Corporation. The acquisition was
accounted for using the purchase method of accounting. As a result, the assets
and liabilities of EEX and its subsidiaries were included in our December 31,
2002 balance sheet and our results of operations and cash flows for 2002
included 35 days (November 27 to December 31, 2002) of activity for EEX and its
subsidiaries. At the time of the acquisition, 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.

On September 5, 2003, we sold Newfield Exploration Australia Ltd., the
holding company for all of our Australian assets. As a result of the sale, the
historical results of operations of our Australia operations are reflected in
our financial statements as "discontinued operations." See Note 2, "Discontinued
Operations." Except where noted and for pro forma earnings per share,
discussions in these notes relate to our continuing activities only.

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 and oil, 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 accordance with accounting
principles generally accepted in the United States 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,
including those related to our discontinued operations (see Note 2,
"Discontinued Operations"), did not impact our net income or stockholders'
equity.

53

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

REVENUE RECOGNITION

We record revenue 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 consist of materials and supplies valued at the lower of
average cost or market.

FOREIGN CURRENCY

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

FINANCIAL INSTRUMENTS

We have included fair value information in these notes when the fair value
of our financial instruments is different from the book value. 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 value.

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, including salaries, benefits and other internal costs directly
attributable to these activities, are capitalized into cost centers that are
established on a country-by-country basis. We capitalized $26.7 million, $7.0
million and $5.3 million of internal costs in 2003, 2002 and 2001, respectively.
Interest expense related to unproved properties and properties under development
are also capitalized to oil and gas properties. 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 location and
quality differences and 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.

Application of full cost accounting rules did not result in a ceiling test
writedown in 2003 or 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.
The full cost ceiling test impairment calculation took into account the effects
of hedging. The writedown would have been $184 million ($118 million after-tax)
if we had not used hedge adjusted prices for the volumes that were subject to
hedges.

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.
54

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 2003 and 2002, furniture,
fixtures and equipment of $16.1 million and $22.8 million, respectively, is net
of accumulated depreciation of $10.2 million and $15.5 million, respectively.

ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS

We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," as
of January 1, 2003. This statement changes the method of accounting for expected
future costs associated with our obligation to perform site reclamation,
dismantle facilities and plug and abandon wells. Prior to January 1, 2003, we
recognized the undiscounted estimated cost to abandon our oil and gas properties
over their estimated productive lives on a unit-of-production basis as a
component of depreciation, depletion and amortization expense and no liability
or capitalized costs associated with such abandonment were recorded on our
consolidated balance sheet. If a reasonable estimate of the fair value of an
abandonment obligation can be made, SFAS No. 143 requires us to record a
liability (an "asset retirement obligation" or "ARO") on our consolidated
balance sheet and to capitalize the asset retirement cost in oil and gas
properties in the period in which the retirement obligation is incurred.

In general, the amount of an ARO and the costs capitalized will be equal to
the estimated future cost to satisfy the abandonment obligation using current
prices that are escalated by an assumed inflation factor after discounting the
future cost back to the date that the abandonment obligation was incurred using
an assumed cost of funds for our company. After recording these amounts, the ARO
will be accreted to its future estimated value using the same assumed cost of
funds and the additional capitalized costs will be depreciated on a
unit-of-production basis over the productive life of the related properties.
Both the accretion and the depreciation are included in depreciation, depletion
and amortization on our consolidated statement of income.

At adoption of SFAS No. 143, a cumulative effect of change in accounting
principle was required in order to recognize:

- an initial ARO as a liability on our consolidated balance sheet;

- an increase in oil and gas properties for the cost to abandon our oil and
gas properties;

- cumulative accretion of the ARO from the period incurred up to the
January 1, 2003 adoption date; and

- cumulative depreciation on the additional capitalized costs included in
oil and gas properties up to the January 1, 2003 adoption date.

The change in our ARO since adoption of SFAS No. 143 is set forth below (in
thousands):

Balance as of January 1, 2003............................... $128,471
Accretion expense........................................... 7,539
Additions................................................... 31,768
Settlements................................................. (4,135)
--------
Balance as of December 31, 2003............................. $163,643
========

As a result of our adoption of SFAS No. 143, we recorded a $134.8 million
increase in the net capitalized costs of our oil and gas properties.
Additionally, we recognized an after-tax gain of $5.6 million (the after-tax

55

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

amount by which additional capitalized costs, net of accumulated depreciation,
exceeded the initial ARO, including in each case discontinued operations) for
the cumulative effect of change in accounting principle. Had we adopted SFAS No.
143 on January 1, 2002, the pro forma ARO would have been $115.7 million.

Had SFAS No. 143 been applied retroactively to the years ended December 31,
2002 and 2001, our net income and earnings per share (without any cumulative
effect of change in accounting principle) would have approximated the pro forma
amounts below:

GOODWILL

We adopted SFAS No. 142, "Goodwill and Other Intangible Assets," effective
January 1, 2002. Under SFAS No. 142, which superseded Accounting Principles
Board (APB) Opinion No. 17, "Intangible Assets," goodwill is no longer subject
to amortization but it is tested for impairment. The impairment test requires
the allocation of goodwill and all other assets and liabilities to reporting
units. The fair value of each reporting unit is determined and compared to the
book value of that reporting unit. If the fair value of the reporting unit is
less than the book value (including goodwill) then goodwill is reduced to its
implied fair value and the amount of the write-down is charged to earnings.
Goodwill is tested for impairment on an annual basis, or more frequently if an
event occurs or circumstances change that have an adverse effect on the fair
value of the reporting unit such that the fair value could be less than the book
value of such unit.

As of December 31, 2003, we had recorded goodwill of $16.4 million,
representing the excess of the purchase price over the estimated fair value of
the assets acquired less the liabilities assumed in our Primary Natural
Resources acquisition (see Note 4, "Acquisitions -- Primary Natural Resources").
We allocated all of the goodwill to our Mid-Continent reporting unit. This is
the first time we have recorded goodwill in connection with an acquisition.

We perform our goodwill impairment test annually on December 31, or more
frequently if indications of potential impairment appear. The fair value of the
Mid-Continent reporting unit is based on our estimates of future net cash flows
from proved reserves and from future exploration for and development of unproved
reserves. Downward revisions of estimated reserves or production, increases in
estimated future costs or decreases in oil and gas prices could lead to an
impairment of all or a portion of this goodwill in future periods.

We determined that no goodwill impairment existed as of December 31, 2003.

56

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 APB Opinion No. 25.

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 2003, 2002 and 2001 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 an 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, 2003, Bank

57

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of Montreal, Morgan Stanley Capital Group, Inc., Barclays Bank PLC and J Aron &
Company were the counterparties with respect to 82% of our future hedged
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, 2003 to Superior
Natural Gas Corporation (29%) and ConocoPhillips Inc. (25%); for the year ended
December 31, 2002 to Superior Natural Gas Corporation (25%) and ConocoPhillips
Inc. (23%); and for the year ended December 31, 2001 to Conoco Inc. (28%) and
Superior Natural Gas Corporation (25%). 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.

DERIVATIVE FINANCIAL INSTRUMENTS

On January 1, 2001, 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." In accordance with the
transition provisions of SFAS No. 133, on January 1, 2001, we recorded a
cumulative effect adjustment loss of $114.2 million ($74.2 million net of tax)
in accumulated other comprehensive loss and a loss of $7.4 million ($4.8 million
net of tax) 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 our consolidated 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 elected to prospectively record subsequent changes
in the fair value of our collar and floor contracts (other than contracts that
are part of three-way collar 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 "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 "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.

Although three-way collar contracts are effective as economic hedges of our
commodity price exposure, they do not qualify for hedge accounting under SFAS
No. 133. These contracts are carried at their fair value on our consolidated
balance sheet under the captions "Derivative assets" and "Derivative
liabilities." We recognize all changes in the fair value of our three-way collar
contracts on our consolidated statement of income for the period in which the
change occurs under the caption "Commodity derivative income (expense)."
Realized gains and losses on our three-way collar contracts are also recognized
under the caption "Commodity derivative income (expense)."

See Note 6, "Commodity Derivative Instruments and Hedging Activities," for
a full discussion of our hedging activities.

58

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) includes net earnings (loss) as well as
unrealized gains and losses on derivative instruments, cumulative foreign
currency translation adjustments and minimum pension liability, all recorded net
of tax.

ACCOUNTING CHANGES

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 on
income statement classification 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 has 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 (EITF) 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 No. 146 on January 1, 2003 has 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 beginning with our year-end 2002
consolidated 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 prior practice of recording
a liability only when a loss was probable and reasonably estimable, as those
terms are defined in SFAS No. 5, "Accounting for Contingencies." FIN 45 had a
dual effective date. The initial recognition and measurement provisions are
applicable on a prospective basis only to guarantees issued or modified after
December 31, 2002. The disclosure requirements in the interpretation were
effective for us as of October 1, 2002. The adoption of the applicable
provisions of FIN 45 at the indicated dates has not had a material effect on our
financial statements.

59

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In January 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities, an Interpretation of ARB 51." In December 2003, the FASB
issued FIN 46R. The primary objectives of FIN 46R 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 VIEs. This new model for consolidation applies to an entity for
which either:

- the equity investors (if any) do not have a controlling financial
interest; or

- the equity investment at risk is insufficient to finance the entity's
activities without receiving additional subordinated financial support
from other parties.

In addition, FIN 46R requires that all enterprises with a significant
variable interest in a VIE make additional disclosures regarding their
relationship with the VIE. The interpretation requires public entities to apply
FIN 46R to all entities that are considered special purpose entities in practice
and under the FASB literature that was applied before the issuance of FIN 46R by
the end of the first reporting period that ends after December 15, 2003.
Application of the accounting requirement of the interpretation to all other
entities is required by the end of the first reporting period that ends after
March 15, 2004. We do not expect the adoption of FIN 46R to have any effect on
our consolidated financial statements.

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies accounting for derivative instruments, including certain derivative
instruments embedded in other contracts and hedging activities under SFAS No.
133. The amendments set forth in SFAS No. 149 require that contracts with
comparable characteristics be accounted for similarly. SFAS No. 149 is generally
effective for contracts entered into or modified after June 30, 2003 (with a few
exceptions) and for hedging relationships designated after June 30, 2003. The
guidance is to be applied prospectively only. Our adoption of SFAS No. 149 as of
July 1, 2003 has had no effect on our consolidated financial statements.

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." This
statement establishes standards for classification and measurement of certain
financial instruments with characteristics of both liabilities and equity on a
company's balance sheet. SFAS No. 150 requires that an issuer classify a
financial instrument that is within its scope as a liability (or an asset in
some circumstances) because that financial instrument embodies an obligation of
the issuer. Many of these instruments were previously classified as equity. SFAS
No. 150 is effective for financial instruments entered into after May 31, 2003.
Our adoption of SFAS No. 150 has had no effect on our consolidated financial
statements.

RECENT ACCOUNTING DEVELOPMENTS

SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other Intangible Assets," were issued by the FASB in June 2001 and became
effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141
requires that all business combinations initiated after June 30, 2001 be
accounted for using the purchase method and that certain intangible assets be
disaggregated and reported separately from goodwill. SFAS No. 142 established
new guidelines for accounting for goodwill and other intangible assets. Under
the statement, goodwill and certain other intangible assets are reviewed
annually for impairment but are not amortized. To our knowledge, substantially
all publicly traded oil and gas companies have continued to include oil and gas
rights and interests held under leases, governmental licenses or other
contractual arrangements ("leasehold interests") as part of oil and gas
properties after SFAS No. 141 and SFAS No. 142 became effective. The EITF has
added the oil and gas industry's application of SFAS Nos. 141 and 142 to
leasehold interests to an upcoming agenda.

60

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Based on our understanding of a potential interpretation, if all leasehold
interests were deemed to be intangible assets, for companies like us that use
the full cost method of accounting for oil and gas activities:

- leasehold interests with proved reserves that were acquired after June
30, 2001 and leasehold interests with no proved reserves would be
classified as intangible assets and would not be included in oil and gas
properties on our consolidated balance sheet;

- our results of operations and cash flows would not be affected because
leasehold costs would continue to be amortized in accordance with full
cost accounting rules; and

- the disclosures required by SFAS Nos. 141 and 142 relative to intangibles
would be included in the notes to our financial statements.

If SFAS Nos. 141 and 142 were applied as described above at December 31, 2003
and 2002, we had undeveloped leasehold interests of approximately $112 million
and $109 million, respectively (without reduction for depreciation, depletion
and amortization) that would be classified on our consolidated balance sheet as
"intangible undeveloped leaseholds" and we had developed leasehold interests of
approximately $635 million and $487 million, respectively (without reduction for
depreciation, depletion and amortization) that would be classified on our
consolidated balance sheet as "intangible developed leaseholds." We will
continue to classify our leasehold interests as tangible oil and gas properties
until further guidance is provided.

2. DISCONTINUED OPERATIONS:

On September 5, 2003, we sold our wholly owned subsidiary, Newfield
Exploration Australia Ltd., the holding company for all of our Australian
assets. We received $9.7 million in proceeds, which was the agreed upon sales
price plus estimated working capital at the time of closing. In addition, we
recorded a receivable for the barrels in inventory at the time of sale. As of
December 31, 2003, this inventory had been lifted and sold by the new owner and
the entire receivable of $10.1 million had been collected. We recognized a loss
of $9.9 million on the sale.

61

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The historical results of operations of our Australian operations are
reflected in our consolidated financial statements as "discontinued operations."
This reclassification affects not only the 2003 presentation of our consolidated
financial statements, but also the presentation of all prior period financial
statements. The results of operations of our Australian operations for the
twelve months ended December 31, 2003, 2002 and 2001 are summarized as follows:

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

(1) Operating expenses for the year ended December 31, 2003 include the
ceiling test writedown of $7.3 million ($5.1 million after-tax)
recorded in June 2003.

(2) Other income (expense) primarily consists of foreign currency exchange
gains and losses.

(3) In 2002, we realized a one-time tax benefit resulting from revised
Australian tax legislation.

62

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The major classes of assets and liabilities of our Australian operations
that have been reclassified as discontinued operations as of December 31, 2002
are summarized as follows:

3. EARNINGS PER SHARE:

Basic earnings per share (EPS) is calculated by dividing net income (the
numerator) by the weighted average number of shares of common stock outstanding
during the period (the denominator). Diluted earnings per share incorporates the
incremental shares issuable (if dilutive) upon the assumed exercise of stock
options (using the treasury stock method) and upon the assumed conversion of our
trust preferred securities as if exercise or conversion to common stock had
occurred at the beginning of the accounting period. Net income also has been
increased for distributions accrued during the period on our trust preferred
securities. We redeemed all of our outstanding trust preferred securities in
June 2003. See Note 10, "Redemption of Trust Preferred Securities" and Note 13,
"Stock-Based Compensation -- Stock Options."

63

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following is the calculation of basic and diluted weighted average
shares outstanding and EPS for each of the years in the three-year period ended
December 31, 2003:

The calculation of shares outstanding for diluted EPS for the years ended
December 31, 2003, 2002 and 2001 does not include the effect of outstanding
stock options to purchase 683,350, 1,087,850 and 907,300 shares, respectively,
because to do so would have been antidilutive.

64

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

4. ACQUISITIONS:

PRIMARY NATURAL RESOURCES ACQUISITION

On September 5, 2003, we acquired Primary Natural Resources, Inc. (PNR) for
approximately $91 million in cash. We acquired PNR primarily to strengthen our
position in one of our focus areas -- the Anadarko and Arkoma Basins of the
Mid-Continent.

We accounted for the acquisition as a purchase using the accounting
standards established in SFAS No. 141, "Business Combinations," and SFAS No.
142, "Goodwill and Other Intangible Assets." Our consolidated financial
statements include PNR's results of operations subsequent to September 5, 2003.
We recorded the estimated fair values of the assets acquired and the liabilities
assumed at September 5, 2003, which primarily consisted of oil and gas
properties of $94.4 million, a deferred tax liability of $19.7 million and
goodwill of $16.4 million. We recorded the deferred tax liability to recognize
the difference between the historical tax basis of PNR's assets and the
acquisition costs recorded for book purposes. The recorded book value of the
proved oil and gas properties was increased and goodwill was recorded to
recognize this tax basis differential. Goodwill represents the excess of the
purchase price over the estimated fair value of the net assets acquired in the
purchase. Goodwill is not deductible for tax purposes. See Note 1, "Organization
and Summary of Significant Accounting Policies -- Goodwill."

EEX ACQUISITION

On November 26, 2002, we acquired EEX Corporation 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.

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
Floating production system and pipelines(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 trading days on or around the date the acquisition was first
publicly announced.

65

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(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 resulted from change in control provisions in
employment contracts and employee plans.

(4) Represents $100.8 million principal amount of secured notes and $61.6
million related to a forward gas sales contract. See Note 8, "Debt."

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

(6) See Note 5, "Oil and Gas Assets -- Floating Production System and
Pipelines."

(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.

LARIAT PETROLEUM ACQUISITION

On January 23, 2001, we acquired Lariat Petroleum, Inc. for 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 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.

PRO FORMA RESULTS

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 and Lariat acquisitions on
our results of operations under the purchase method of accounting as if we had
acquired both EEX and Lariat on January 1, 2001.

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.

66

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

5. OIL AND GAS ASSETS:

OIL AND GAS PROPERTIES

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

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

A portion of incurred (if not previously included in the amortization base)
and future development costs associated with qualifying major development
projects may be temporarily excluded from amortization. To qualify, a project
must require significant costs to ascertain the quantities of proved reserves
attributable to the properties under development (e.g., the installation of an
offshore production platform from which development wells are to be drilled).
Incurred and future costs are allocated between completed and future work. Any
temporarily excluded costs are included in the amortization base upon the
earlier of when the associated reserves are determined to be proved or
impairment is indicated.

As of December 31, 2003, we excluded from the amortization base $25.7
million (which is included in costs not subject to amortization in the table
above) associated with development costs for our deepwater Gulf of Mexico
project known as "Glider," located at Green Canyon 247/248.

FLOATING PRODUCTION SYSTEM AND PIPELINES

As a result of our acquisition of EEX, we own a 60% interest in a floating
production system (FPS), some offshore pipelines and a processing facility
located at the end of the pipelines in shallow water. The FPS is a combination
deepwater drilling rig and processing facility capable of simultaneous drilling
and production operations. These infrastructure assets are not currently in
service and we do not have a specific use for them in our offshore operations.
At the time of acquisition, we estimated their fair market value to be $35
million and classified them as "assets held for sale" under the provisions of
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets."
This statement provides that an asset can only be classified as "held for sale"
for one year. As of December 31, 2003, these assets have been re-categorized as
held in use assets and will periodically be evaluated for impairment. The costs
associated with maintaining these assets
67

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

are included in operating expenses on our consolidated income statement. Such
costs were not significant in 2003 or 2002.

We have engaged brokers who survey the world market for potential
application of the assets "as is" or "to-be-modified" for a particular
application. We also have direct discussions with other operators about the
potential application of the assets to their developments around the world.
Because there is no established market for these unique assets, it is difficult
to accurately estimate their fair market value. An immediate sale or a sale
under distressed circumstances might realize less than the current carrying
value of the assets.

6. COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

We utilize swap, floor, collar and three-way collar derivative contracts to
hedge against the variability in cash flows associated with the forecasted sale
of our future oil and gas production. While the use of these derivative
instruments limits the downside risk of adverse price movements, their use also
may limit future revenues from favorable price movements.

With respect to a swap contract, 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 contract, 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 contract. For a 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 contract. We are not required to make
any payment in connection with the settlement of a floor contract. For a collar
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 contract, we
are required to make payment to the counterparty if the settlement price for any
settlement period is above the ceiling price for such contract and neither party
is required to make a payment to the other party if the settlement price for any
settlement period is equal to or greater than the floor price and equal to or
less than the ceiling price for such contract. A three-way collar contract
consists of a standard collar contract plus a put sold by us with a price below
the floor price of the collar. This additional put requires us to make a payment
to the counterparty if the settlement price for any settlement period is below
the put price. Combining the collar contract with the additional put results in
us being entitled to a net payment equal to the difference between the floor
price of the standard collar and the additional put price if the settlement
price is equal to or less than the additional put price. If the settlement price
is greater than the additional put price, the result is the same as it would
have been with a standard collar contract only. This strategy enables us to
increase the floor and the ceiling price of the collar beyond the range of a
traditional no cost collar while defraying the associated cost with the sale of
the additional put.

Substantially all of our oil and gas derivative contracts are settled based
upon reported prices on the NYMEX. The estimated fair value of these contracts
is based upon various factors, including closing exchange prices on the NYMEX,
over-the-counter quotations, volatility and, in the case of collars and floors,
the time value of options. The calculation of the fair value of collars and
floors requires the use of an option-pricing model.

On the date 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 future oil and gas production. After-tax 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 under the caption "Accumulated other comprehensive income
(loss) -- Commodity derivatives" on our consolidated balance sheet until the
sale of the hedged oil and gas production. Upon the sale of the hedged
production, the net after-tax change in the fair value of the associated
derivative recorded under the caption "Accumulated other comprehensive income
(loss) -- Commodity derivatives" is reversed and the gain or loss on the hedge,
to the extent that it is effective, is reported in "Oil and gas revenues" on our
consolidated statement of income. At December 31, 2003, we had a net $26.4
million after-tax loss recorded under the caption "Accumulated other
comprehensive income (loss) --
68

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Commodity derivatives." We expect hedged production associated with commodity
derivatives accounting for a net loss of approximately $22.7 million to be sold
within the next 12 months and hedged production associated with the remaining
net loss of approximately $3.7 million to be sold thereafter. The actual gain or
loss on these commodity derivatives could vary significantly as a result of
changes in market conditions and other factors.

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 reported currently each period under the
caption "Commodity derivative income (expense)" on our consolidated statement of
income.

Prior to January 1, 2002, the periodic changes in the time value component
of our collar and floor contracts were treated as ineffective and were reported
under the caption "Commodity derivative income (expense)" on our consolidated
statement of income for the period in which the change occurred. On January 1,
2002, we began assessing hedge effectiveness based on the total changes in cash
flows on our collar and floor contracts without adjustment for time value as
described by DIG Issue G20, "Cash Flow Hedges: Assessing and Measuring the
Effectiveness of a Purchased Option Used in a Cash Flow Hedge." Pursuant to the
guidance in DIG Issue G20, we elected to prospectively record subsequent changes
in fair value associated with time value under the caption "Accumulated other
comprehensive income (loss) -- Commodity derivatives" on our consolidated
balance sheet. As a result, amounts recorded in 2002 consist of the reversal of
the time value gains that were recognized in 2001 and a diminutive amount
representing the ineffective portion of our hedges.

We formally document all relationships between derivative instruments and
hedged production, as well as our risk management objective and strategy for
particular derivative contracts. 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
derivative's inception and on an ongoing basis) whether the derivatives being
utilized have been highly effective at offsetting changes in the cash flows of
hedged production and whether those derivatives may be expected to remain highly
effective in future periods. If it is determined that a derivative has ceased to
be highly effective as a hedge, we will discontinue hedge accounting
prospectively. If hedge accounting is discontinued and the derivative remains
outstanding, we will carry the derivative at its fair value on our consolidated
balance sheet and recognize all subsequent changes in its fair value on our
consolidated statement of income for the period in which the change occurs.
Hedge accounting was not discontinued during the periods presented for any
hedging instruments.

Although our three-way collar contracts are effective as economic hedges of
our commodity price exposure, they do not qualify for hedge accounting under
SFAS No. 133. These contracts are carried at their fair value on our
consolidated balance sheet under the captions "Derivative assets" and
"Derivative liabilities." We recognize all changes in the fair value of our
three-way collar contracts on our consolidated statement of income for the
period in which the change occurs under the caption "Commodity derivative income
(expense)." Upon realization of gains and losses on our three-way collar
contracts, previously recorded unrealized gains and losses will be reversed and
realized gains and losses will be recorded under the caption "Commodity
derivative income (expense)." We did not recognize any realized gains or losses
on our three-way collar contracts during 2003.

69

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NATURAL GAS

As of December 31, 2003, we had entered into derivative contracts that
qualify as cash flow hedges with respect to our future natural gas production as
follows:

As of December 31, 2003, we also had entered into three-way collar
contracts with respect to our future natural gas production as set forth in the
table below. These contracts do not qualify for hedge accounting.

70

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

OIL

As of December 31, 2003, we had entered into derivative contracts that
qualify as cash flow hedges with respect to our future oil production as
follows:

As of December 31, 2003, we also had entered into three-way collar
contracts with respect to our future oil production as set forth in the table
below. These contracts do not qualify for hedge accounting.

71

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

7. ACCRUED LIABILITIES:

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

72

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

8. DEBT:

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

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

(1) Because capacity under our credit facility was available to repay
borrowings under our money market lines of credit and to pay current
amounts due under the gas sales obligation as of the indicated dates,
these obligations were classified as long-term.

(2) See "--Interest Rate Swaps" below.

(3) As of December 31, 2003, the outstanding principal of $2.9 million is
classified as current on our consolidated balance sheet because the
secured notes were repaid in full in January 2004.

CREDIT ARRANGEMENTS

At December 31, 2003, we maintained our reserve-based, senior unsecured
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 any outstanding senior notes ($300 million
at December 31, 2003), 30% of the principal amount of any outstanding senior
subordinated notes (a reduction of $75 million at December 31, 2003) and the
outstanding principal amount of the secured notes ($3 million at December 31,
2003). The borrowing base is redetermined at least semi-annually and, after all
required adjustments, was $425 million at December 31, 2003 and $218 million at
December 31, 2002. No assurances can be given that the banks will not determine
in the future that the borrowing base should be reduced. 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,
2005. We are in the process of replacing the facility.

73

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

We also have money market lines of credit with various banks in an amount
limited by our credit facility to $40 million. At December 31, 2003, we had
outstanding borrowings under our credit facility of $90 million and borrowings
under our money market lines of credit of $5 million. Consequently, at December
31, 2003, we had approximately $370 million of available capacity under our
credit arrangements.

At December 31, 2003 and 2002, the interest rate was 2.500% and 2.737%,
respectively, for LIBOR based loans under our credit facility and 3.0% and
2.615%, 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 value.

Our current and previous credit facilities provide or provided for the
payment of a commitment fee and a standby fee. We paid fees under these
facilities of approximately $885,000, $447,000 and $397,000 for the years ended
December 31, 2003, 2002 and 2001, 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 (approximately $173.1
million) were used to repay outstanding indebtedness under our 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 value of our 7.45% Senior Notes due 2007 at December 31,
2003 and 2002 was $133.4 million and $130.1 million, respectively, based on
quoted market prices on those dates. The estimated fair value of our 7 5/8%
Senior Notes due 2011 at December 31, 2003 and 2002 was $186.2 million and
$183.6 million, respectively, based on quoted market prices on those dates.

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 may 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 issued $250 million aggregate principal amount of
our 8 3/8% Senior Subordinated Notes due 2012 priced (at 99.168% of par) with a
yield to maturity of 8.50%. The net proceeds from the offering (approximately
$241.8 million) were used to repay EEX debt that became due upon EEX's
acquisition and to pay transaction costs associated with the acquisition.
Because the proceeds were held in escrow pending the closing of the EEX
acquisition, interest accruing prior to the closing of approximately $1.6
million was capitalized as a cost of the transaction. The estimated fair value
of the 8 3/8% Senior Subordinated Notes due 2012 at December 31, 2003 and 2002
was $272.9 million and $245.0 million, respectively, based on quoted market
prices on those dates.

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
74

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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
under certain circumstances 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 accrued interest at a rate of 7.54% per year and were
secured by the floating production system and pipelines described in Note 5,
"Oil and Gas Assets -- Floating Production System and Pipelines." Principal was
payable in annual installments on January 2 of each year (except 2006) with the
final installment due in 2009.

In addition to the scheduled payment of $11.2 million of principal we made
during 2003, we also repurchased $63.1 million outstanding principal amount of
notes. In January 2004, we repaid the remaining secured notes in full.

INTEREST RATE SWAPS

During September 2003, we entered into interest rate swap agreements to
take advantage of low interest rates and to obtain what we view as a more
desirable proportion of variable and fixed rate debt. These swap agreements
provide for us to pay variable and receive fixed interest payments, and are
designated as fair value hedges of a portion of our outstanding senior notes. At
December 31, 2003, we had hedged $50 million principal amount of our 7.45%
Senior Notes due 2007 and $50 million principal amount of our 7 5/8% Senior
Notes due 2011.

Pursuant to SFAS No. 133, changes in the fair value of derivatives
designated as fair value hedges are recognized as offsets to the changes in fair
value of the exposure being hedged. As a result, the fair value of our interest
rate swap agreements is reflected within our derivative assets on our
consolidated balance sheet and changes in their fair value are recorded as an
adjustment to the carrying value of the associated long-term debt. Receipts and
payments related to our interest rate swaps are reflected in interest expense.

GAS SALES OBLIGATION SETTLEMENT

Pursuant to a gas forward sales contract entered into in 1999, EEX
committed to deliver approximately 50 Bcf of production to Bob West Treasure
L.L.C. (BWT) in exchange for proceeds of $105 million. As of the date of our
acquisition of EEX, we recorded a liability of approximately $62 million, which
represented the then current market value of approximately 16 Bcf of reserves
remaining subject to the gas sales contract. We accounted for this obligation as
debt on our consolidated balance sheet.

On March 31, 2003, pursuant to a settlement agreement with BWT and the
other parties to related transactions, the gas sales contract, the swaps entered
into by BWT in connection with the gas sales contract and all other agreements
related to the gas sales contract, including the guarantee and all liens and
other security interests on EEX's properties, were terminated in exchange for a
payment by us of approximately $73 million. This payment represented:

- the remaining unamortized obligation under the gas sales contract;

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

75

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- various transaction fees related to the termination; and

- an agreed upon value for BWT's membership interest in an EEX subsidiary
(see Note 9, "Minority Interest").

In connection with the settlement, we recognized a loss of $10 million under the
caption "Gas sales obligation settlement and redemption of securities" on our
consolidated statement of income.

9. MINORITY INTEREST:

In conjunction with EEX entering into the gas sales obligation, BWT
acquired a limited membership interest in an EEX subsidiary that owned a
substantial portion of EEX's consolidated reserves, a portion of which were
subject to the gas sales obligation. We reported this limited membership
interest as a "minority interest" on our consolidated balance sheet at December
31, 2002 based on our estimated price to re-acquire the interest. BWT's limited
membership interest was not allocated any earnings and was not entitled to cash
distributions. On March 31, 2003, the gas sales obligation and all related
financing structures, including the minority interest, were terminated (see Note
8, "Debt -- Gas Sales Obligation Settlement").

10. REDEMPTION OF TRUST PREFERRED SECURITIES:

We redeemed all of the outstanding 6 1/2% Cumulative Quarterly Income
Convertible Preferred Securities of Newfield Financial Trust I on June 27, 2003
for an aggregate redemption price of approximately $148.4 million or $38.31 on a
per share of underlying common stock basis (excluding in each case accrued but
unpaid distributions). The holders of only a small number of the securities
elected to convert their securities into shares of our common stock prior to the
redemption date (a total of 48,076 shares of common stock were issued). Included
in the aggregate redemption price is $6.5 million of optional redemption
premium. Upon redemption, this premium and $4.0 million of unamortized offering
costs (which were being amortized over the 30-year life of the securities) were
expensed under the caption "Gas sales obligation settlement and redemption of
securities" on our consolidated statement of income.

We financed the redemption with the net proceeds from the issuance and sale
of 3.5 million shares of our common stock on May 27, 2003 (approximately $131.2
million, or $37.49 per share) and borrowings under our revolving credit
facility.

11. INCOME TAXES:

Income from continuing operations before income taxes consists of the
following:

76

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

The provision for income taxes for each of the years in the three-year
period ended December 31, 2003 was different than the amount computed using the
federal statutory rate (35%) for the following reasons:

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

77

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2003, we had net operating loss (NOL) carryforwards for
federal income tax purposes of approximately $241.3 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
2004 through 2023 with a majority expiring in 2019 through 2022. Realization of
net operating loss carryforwards is dependent upon generating sufficient taxable
income within the carryforward period. Estimates of future taxable income can be
significantly affected by changes in natural gas and oil prices, estimates of
the timing and amount of future production and estimates of future operating and
capital costs.

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 shares were repurchased under this program. 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.

STOCK OPTIONS

We have granted stock options under several employee stock option and
omnibus stock plans. Options that have been granted and are outstanding
generally expire ten years from the date of grant and become exercisable at the
rate of 20% per year. If additional options are granted under our existing
employee plans, the exercise price will not be less than the fair market value
per share of our common stock on the date of grant.

78

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following is a summary of all stock option activity for 2001, 2002 and
2003:

The weighted average fair value of an option to purchase one share of
common stock granted during 2003, 2002 and 2001 was $14.81, $14.74 and $16.08,
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.

79

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table summarizes information about stock options outstanding
and exercisable at December 31, 2003:

Common stock issued upon 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 2003, 2002 and 2001 resulted in a tax benefit to us of
approximately $4.9 million, $2.5 million and $2.1 million, respectively.

At December 31, 2003, we had approximately 1,463,384 additional shares
available for issuance pursuant to our existing employee 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, 2003, only
98,589 could be granted as restricted shares.

RESTRICTED SHARES

At December 31, 2003, there were 384,400 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 to employees 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 of one share of our common stock 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, 2003, 24,422 shares
remain available for grants under this plan.

80

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 our
common stock on the date of grant. As the restricted shares vest, we reduce
unearned compensation and recognize compensation expense. The table below sets
forth 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, 2003.

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

(1) Eight directors received grants in each of the years 2003, 2002 and
2001.

(2) As restricted shares vest, the unearned compensation associated with
those restricted shares (based on the fair value of our common stock on
the date of grant of such restricted shares) is recorded as
compensation expense.

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 foreign subsidiaries are not eligible to participate.

At December 31, 2003, 110,824 shares of common stock were available for
issuance pursuant to our stock purchase plan. Under the plan, we sold 30,825
shares in 2003 at a weighted average price of $31.03; 29,410 shares in 2002 at a
weighted average price of $30.27; and 28,941 shares in 2001 at a weighted
average price of $27.16. In accordance with APB Opinion No. 25 and related
interpretations, we have not recognized any compensation expense with respect to
the plan.

81

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The weighted average fair value of the option to purchase stock during 2003
was $10.89, during 2002 was $9.85 and during 2001 was $9.86. 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 2003, 2002 and 2001:

14. PENSION PLAN OBLIGATION:

As part of the EEX acquisition in November 2002, we assumed responsibility
for a defined pension benefit plan for current and former employees of EEX and
its subsidiaries. This plan has been amended to cease all future retirement
benefit accruals, effective March 31, 2003. After March 31, 2003, no participant
has earned any further benefit accruals under the plan. The result of this
change is that the participant benefits will be frozen at their levels
determined as of March 31, 2003 and the benefits will not increase based upon
future service completed or compensation received after that date. Accrued
pension costs are funded based upon applicable requirements of federal law and
deductibility for federal income tax purposes. The components of the pension
plan obligation and its funded status are as follows:

82

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In developing the assumed overall expected long-term rate of return on
assets, we used a building block approach in which rates of return in excess of
inflation were considered separately for equity securities, debt securities,
real estate and all other assets. The excess returns were weighted by the
representative target allocation and added along with an approximate rate of
inflation to develop the overall expected long-term rate of return.

We have developed an investment policy to invest in a broad range of
securities. The diversified portfolio aims to maximize investment return without
exposing it to risk levels above those determined by us. The investment policy
takes into consideration the retirement plan's benefit obligations including the
expected

83

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

timing of benefit payments. The following is the allocation of the plan's assets
by category at December 31, 2003 and 2002 as well as the target allocation of
assets for 2004.

During 2004, we anticipate making contributions to the plan of $140,000.

15. EMPLOYEE BENEFIT PLANS:

POST-RETIREMENT MEDICAL PLAN

We sponsor a post-retirement medical plan that covers retired employees
until they attain the age of 65. The components of the accrued post-retirement
benefit obligation, all of which is unfunded, are as follows:

84

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

During 2004, we anticipate making contributions to the plan of $197,000 and
the participants are expected to contribute approximately $13,000.

INCENTIVE COMPENSATION PLAN

Effective January 1, 2003, our Board of Directors adopted our 2003
Incentive Compensation Plan and terminated the ability to grant any further
awards pursuant to our 1993 Incentive Compensation Plan. Our new incentive plan
provides for the creation each calendar year of an award pool that is generally
equal to 5% of our adjusted net income (as defined in the plan) plus the
revenues attributable to an overriding royalty interest bearing on the interests
of investors that participate in certain of our activities. Both of the
incentive plans are administered by the Compensation & Management Development
Committee of our Board of Directors and award amounts are (or, in the case of
the 1993 plan, were) recommended by our chief executive officer. All employees
are (or were) eligible for awards if employed on both October 1 and December 31
of the performance period. Awards under both of our incentive plans may (or
could), and generally do (or did), have both a current and a deferred component.
Deferred awards are paid in four annual installments, each

85

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

installment consisting of 25% of the deferred award, plus interest on awards
paid in cash (all deferred awards under the 2003 plan are paid in cash). Total
expense under our 2003 incentive plan for the year ended December 31, 2003 was
$20.2 million.

The 1993 plan is very similar to the new plan. Under the 1993 plan, the
incentive pool generally equaled 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 on 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. In addition,
under the 1993 plan a participant could elect for all or a portion of his or her
deferred award 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. Total expense under
the 1993 incentive plan for the years ended December 31, 2002 and 2001 was $10.1
million and $11.6 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 foreign 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 $1.7 million, $1.5 million and $1.3
million for the years ended December 31, 2003, 2002 and 2001, 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 his or her 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 $32,500, $32,000 and
$32,000 for the years ended December 31, 2003, 2002 and 2001, respectively.

16. COMMITMENTS AND CONTINGENCIES:

LEASE COMMITMENTS

Rent expense with respect to our lease commitments for the years ended
December 31, 2003, 2002 and 2001 was $4.0 million, $4.8 million and $4.1
million, respectively. We are obligated under non-cancellable operating leases
for our office space in Houston, Texas and Tulsa, Oklahoma. Future minimum
payments required under our office leases as of December 31, 2003 are as follows
(in thousands):

86

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

LITIGATION

We have been named as a defendant in a number of lawsuits arising in the
ordinary course of our 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.

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.

87

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

18. GEOGRAPHIC INFORMATION:

88

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

89

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) General and administrative expense includes stock compensation charges of
$3,059, $2,801 and $2,751 for the years ended December 31, 2003, 2002 and
2001, respectively.

(2) Includes $131.2 million (domestic) and $1.1 million (international) for
asset retirement obligations associated with our adoption of SFAS No. 143.

19. SUPPLEMENTAL CASH FLOW INFORMATION:

90

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

20. RELATED PARTY TRANSACTIONS:

Three private equity funds (the WP funds) managed by Warburg Pincus LLC (WP
LLC) held all of the outstanding preferred stock of EEX prior to our acquisition
of EEX in November 2002 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.

The sole general partner of each of the WP funds is Warburg, Pincus & Co.
(WP & Co.). 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. Mr. Newman also was a director of EEX prior to its acquisition.

Terry Huffington, a former director of our company, 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, 2003,
Newfield China had approximately $42 million in unrecovered costs, no proved
reserves and no revenue and, as a result, no dividends have been paid to date on
its preferred shares.

91

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

21. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):

The results of operations by quarter for the years ended December 31, 2003
and 2002 are as follows:

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

(1) The sum of the individual quarterly earnings (loss) per share may not agree
with year-to-date earnings (loss) per share as each quarterly computation is
based on the income or loss for that quarter and the weighted average number
of shares outstanding during that quarter.

92

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, 2003 are as follows (in thousands):

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

(1) Excludes $100.6 million of cumulative asset retirement cost recorded
upon the adoption of the provisions of SFAS No. 143 on January 1, 2003.

93

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, 2003 (in thousands):

94

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 total net proved reserves and our total
net proved developed reserves as of December 31, 2000, 2001, 2002 and 2003 and
the changes in our total net proved reserves during the three-year period ended
December 31, 2003, as estimated by our petroleum engineering staff:

95

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.
The "standardized measure of discounted future net cash flows" should not be
viewed as representative of our current value. It and the other information
contained in the following tables may be useful for certain comparative
purposes, but should not be solely relied upon in evaluating us or our
performance.

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;

- 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 do not reflect the impact of future production that is
subject to open hedge positions (see Note 6, "Commodity Derivative Instruments
and Hedging Activities").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 No. 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.

96

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:

97

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 during each of the years in the three-year period ended December
31, 2003:

98

NEWFIELD EXPLORATION COMPANY

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

99

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

On January 28, 2004, under the supervision and with the participation of
our management, including our principal executive officer and principal
financial officer, we conducted an evaluation of the effectiveness of the design
and operation of our disclosure controls and procedures (as defined in Rules
13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended),
which have been designed to permit us to effectively identify and timely
disclose important information. Based on this evaluation, our principal
executive officer and principal financial officer concluded that our disclosure
controls and procedures were effective as of the end of the period covered by
this report such that the information relating to Newfield, including our
consolidated subsidiaries, required to be disclosed in our SEC reports (i) is
recorded, processed, summarized and reported within the time periods specified
in SEC rules and forms, and (ii) is accumulated and communicated to Newfield's
management, including our principal executive officer and principal financial
officer, as appropriate to allow timely decisions regarding required disclosure.

During the three months ended December 31, 2003, we made no changes in our
internal control over financial reporting or in other factors that has
materially affected, or is reasonably likely to materially affect, our internal
control over financial reporting.

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 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 2004
Annual Meeting of Stockholders to be held on May 6, 2004 and to the information
set forth in Item 4A, "Executive Officers," in this report.

CORPORATE CODE OF BUSINESS CONDUCT AND ETHICS

We have adopted a corporate code of business conduct and ethics for
directors, officers (including our principal executive officer, principal
financial officer and controller or principal accounting officer) and employees.
Our corporate code includes a financial code of ethics applicable to our chief
executive officer, chief financial officer and controller or chief accounting
officer. Both of these codes are available on our website at
http://www.newfld.com/Corporate Governance/Overview. Stockholders may request a
free copy of these codes from:

Newfield Exploration Company
Attention: Investor Relations
363 North Sam Houston Parkway East, Suite 2020
Houston, Texas 77060
(281) 405-4284
http://www.newfld.com/Investor Relations/Information Request.

CORPORATE GOVERNANCE GUIDELINES

We have adopted corporate governance guidelines, which are available on our
website at http://www.newfld.com/Corporate Governance/Overview/Guidelines for
Corporate Governance. Stockholders may request a free copy of our corporate
governance guidelines from the address and phone number set forth above under
"-- Corporate Code of Business Conduct and Ethics."

100

COMMITTEE CHARTERS

The charters of the Audit Committee, the Compensation & Management
Development Committee and the Nominating & Corporate Governance Committee of our
Board of Directors are available on our website at
http://www.newfld.com/CorporateGovernance/Overview. Stockholders may request a
free copy of any of these charters from the address and phone number set forth
above under "-- Corporate Code of Business Conduct and Ethics."

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Information regarding Section 16(a) beneficial ownership reporting
compliance is set forth under "Common Stock Ownership of Certain Beneficial
Owners and Management -- Section 16(a) Beneficial Ownership Reporting
Compliance" in our definitive Proxy Statement, which information is incorporated
herein by reference.

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 2004
Annual Meeting of Stockholders to be held on May 6, 2004.

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 2004
Annual Meeting of Stockholders to be held on May 6, 2004.

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 2004
Annual Meeting of Stockholders to be held on May 6, 2004.

ITEM 14. PRINCIPAL AUDITOR FEES AND SERVICES

The information required by Item 14 is incorporated herein by reference to
such information as set forth in our definitive Proxy Statement for our 2004
Annual Meeting of Stockholders to be held on May 6, 2004.

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 46 of this report.

(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.

(b) Reports on Form 8-K

On October 15, 2003, we filed a Current Report on Form 8-K reporting the
issuance of our @NFX publication, which included a summary of our natural gas
and crude oil hedge positions as of October 14, 2003.

On October 30, 2003, we filed a Current Report on Form 8-K announcing the
2004 production estimate disclosed in our third quarter 2003 financial and
operating results conference call.
101

On October 30, 2003, we filed a Current Report on Form 8-K in connection
with the announcement of our third quarter and year-to-date 2003 financial
results and fourth quarter 2003 guidance regarding production and significant
operating and financial data.

On December 15, 2003, we filed a Current Report on Form 8-K announcing the
temporary suspension of trading under our 401(k) plan.

(c) Index of Exhibits

3. EXHIBITS

102

103

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

* Filed or furnished herewith.

+ Identifies management contracts and compensatory plans or arrangements.

104

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 12th day of
March, 2004.

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 12th day of March, 2004.

105

INDEX TO EXHIBITS

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

* Filed or furnished herewith.

+ Identifies management contracts and compensatory plans or arrangements.