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

Exhibit

Number

Second Restated Certificate of Incorporation of Newfield (incorporated by reference to Exhibit 3.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 1-12534))

Certificate of Amendment to Second Restated Certificate of Incorporation of Newfield dated May 15, 1997 (incorporated by reference to Exhibit 3.1.1 to Newfield’s Registration Statement on Form S-3 (Registration No. 333-32582))

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the fiscal year ended December 31, 2004

or

o		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:


Title of Each Class		Name of Each Exchange on Which Registered

Common Stock, par value $0.01 per share Rights to Purchase Series A Junior Participating Preferred Stock, par value $0.01 per share		New York Stock Exchange New York Stock Exchange

Securities registered Pursuant to Section 12(g) of the Act:

None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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. o

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $3,058,380,000 as of June 30, 2004 (based on the last sale price of such stock as quoted on the New York Stock Exchange).

As of March 7, 2005, there were 63,103,234 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 5, 2005, which is incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS


		Page

PART I
Item 1.	Business		1
	Strategy		1
	Focus Areas		2
	Plans for 2005		3
	Marketing		4
	Competition		4
	Employees		4
	Regulation and Other Factors Affecting Our Business and Financial Results		4
Item 2.	Properties		5
	Concentration		5
	Gulf of Mexico		5
	Onshore Gulf Coast		5
	Mid-Continent		5
	Rocky Mountains		5
	International		5
	Proved Reserves and Future Net Cash Flows		6
	Drilling Activity		6
	Productive Wells		7
	Acreage Data		8
	Title to Properties		9
Item 3.	Legal Proceedings		10
Item 4.	Submission of Matters to a Vote of Security Holders		10
Item 4A.	Executive Officers of the Registrant		10
PART II

Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters		11

Item 6.	Selected Financial Data		12

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
	Overview		14
	Results of Operations		14
	Results of Discontinued Operations		22
	Liquidity and Capital Resources		22
	Contractual Cash Obligations		25
	Oil and Gas Hedging		27
	Off-Balance Sheet Arrangements		29
	Critical Accounting Policies and Estimates		29
	New Accounting Standards		34
	Regulation		34
	Other Factors Affecting Our Business and Financial Results		38
	Forward-Looking Information		42
	Commonly Used Oil and Gas Terms		43
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		45
	Oil and Gas Prices		45
	Interest Rates		45
	Foreign Currency Exchange Rates		45


		Page

Item 8.	Financial Statements and Supplementary Data		46
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		99
Item 9A.	Controls and Procedures		99
PART III

Item 10.	Directors and Executive Officers of the Registrant		99
Item 11.	Executive Compensation		100
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		100
Item 13.	Certain Relationships and Related Transactions		100
Item 14.	Principal Auditor Fees and Services		100
PART IV

Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K		101
Form of TSR 2003 Restricted Stock Agreement
Amended 2003 Incentive Compensation Plan
Change of Control Severance Plan
Form of Change of Control Severance Agreement
Form of Change of Control Severance Agreement
List of Significant Subsidiaries
Consent of PricewaterhouseCoopers LLP
Certification of CEO Pursuant Section 302
Certification of CFO Pursuant Section 302
Certification of CEO Pursuant Section 906
Certification of CFO Pursuant Section 906

If you are not familiar with any of the oil and gas terms used in this report, we have provided explanations of many of them under the caption “Commonly Used Oil and Gas Terms” at the end of Item 7 of this report. 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.

PART I


Item 1.	*Business*

We are an independent oil and gas company engaged in the exploration, development and acquisition of crude oil and natural gas properties. Our company was founded in 1989 and focused initially on the shallow waters of the Gulf of Mexico. Today, we have a diversified asset base. Our domestic areas of operation include the Gulf of Mexico, the onshore Gulf Coast, the Anadarko and Arkoma Basins of the Mid-Continent and the Uinta Basin of the Rocky Mountains. Internationally, we are active offshore Malaysia, in the North Sea, offshore Brazil and in China’s Bohai Bay.

General information about us can be found at www.newfld.com. Our annual reports 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.

At year-end 2004, we had proved reserves of 1.8 Tcfe. Of those reserves:


	•	70% were natural gas;

	•	75% were proved developed;

	•	70% were located onshore in the U.S.;

	•	28% were located in the Gulf of Mexico; and

	•	2% were located internationally

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 most of our existing areas of operation and other select geographic areas. The potential to add reserves through the drillbit is a critical consideration in our acquisition screening process. In recent years, about 30-40% of our initial annual capital expenditure budget has been allocated to exploration activities. We actively look for new drilling ideas on our existing property base and on properties that may be acquired. Large acquisitions over

the last few years, recent drilling successes and active leasing efforts have provided 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 reserves through the drillbit, each year we drill a greater number of lower risk, low to moderate potential wells and a lesser number of higher risk, higher potential prospects. Our traditional shelf plays and low-risk drilling opportunities in the Rocky Mountains and the Mid-Continent are complemented with higher potential plays in the Gulf of Mexico’s deep and ultra-deep shelf and deepwater and in international waters.

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 year-end 2004, we operated about 76% 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 $131 million in the acquisition of new seismic data. At February 1, 2005, we held licenses or otherwise had access to 3-D seismic surveys covering approximately 4,000 blocks (about 22 million acres) in the Gulf of Mexico’s shallow waters, 2,200 blocks in the deepwater Gulf of Mexico, 6,050 square miles onshore Texas and Louisiana, 3,600 square miles in the Anadarko and Arkoma Basins, 600 square miles in the Uinta Basin, 400 square kilometers covering the area where we are active offshore China, 53,600 square kilometers in the North Sea and 3,500 square kilometers in Malaysia.

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 performance-based compensation. A significant portion of our employees’ compensation is contingent on our profitability. As of February 28, 2005, our employees owned or had options to acquire about 6% 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 are mature, we believe that significant opportunities remain in the deep shelf and deepwater plays. As a result, we are allocating an increasing portion of our budget to these plays. We also are active in an exploration initiative 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 of less than 13,000-15,000 feet located in water depths of less than 1,000 feet. We operate about 195 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. To date, we have drilled 12 successful deep shelf wells out of 20 attempts. The risk profile of these wells is significantly different than traditional shelf wells. These deeper targets are more difficult to analyze 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 dry hole costs of about $12-15 million per well.

Treasure Project. Through our acquisition of EEX Corporation in November 2002, we gained an interest in more than 20 blocks associated with an ultra-deep drilling concept in shallow water known as “Treasure Island.” After the acquisition, we extended the geographic scope of this concept to the west with our acquisition of interests in more than 50 lease blocks in partnership with BHP Billiton. We refer to the entire concept (Treasure Island and the areas to the west) as “Treasure Project.” This high-risk, high potential concept has targeted depths of 30,000 feet or more. There is no production from these depths on the Gulf of Mexico shelf today. Because of the risks and high drilling costs ($50-$100 million), we do not currently intend to drill any Treasure Project wells without partners to carry all or a substantial portion of our drilling costs.

On February 9, 2005, we began drilling the first test of Treasure Island — the Blackbeard West #1 well. We have a 23% interest in the well and substantially all of our costs with respect to the well will be paid by our partners. During 2004, Petrobras America committed to drill one well on the lease blocks we acquired with BHP. The well could begin drilling in late 2006 or 2007.

Deepwater. We became active in deepwater in 2001 and drilled our first well 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 exploratory targets in less than 6,000 feet of water that are located in proximity to existing infrastructure. In late 2004/early 2005, we drilled three deepwater wells. We plan to develop two of the wells through subsea tiebacks using nearby facilities. The third well will be appraised through additional drilling in mid-2005. We now own an interest in about 80 deepwater lease blocks.

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 a quarter of our total proved reserves and daily production. Our operations are concentrated in South Texas, the Val Verde Basin of 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. Since that time, a combination of acquisitions and drilling in the Anadarko and Arkoma Basins has helped us to significantly grow our production. The Mid-Continent is a gas-rich province characterized by multiple productive zones and relatively low drilling costs. Our more recent efforts have focused on an initiative that we call “gas mining.” We drilled 157 wells in the Mid-Continent in 2004 and have a multi-year inventory of lower risk drilling opportunities. Our Mid-Continent division is managed by our Tulsa, Oklahoma office.

Rocky Mountains. Through an acquisition in August 2004, we entered the Uinta Basin of the Rocky Mountains. More than 20% of our total proved reserves are now located in the Monument Butte Field, which is located in northeastern Utah. The field offers a multi-year drilling inventory of lower risk wells. The Rocky Mountains have significant remaining reserves and offer us a new focus area in which to grow through drilling opportunities, acquisitions and leasing activity. Our Rocky Mountain division is managed by our Denver, Colorado office.

International. In 2004, we acquired interests offshore Malaysia that include current production, undeveloped discoveries and lower risk drilling prospects in shallow water and a vast deepwater exploration concession. Subject to satisfaction of government requirements, we anticipate commencing development of two fields in China’s Bohai Bay by late 2005. In the North Sea, we are developing a recent discovery and drilling exploratory wells. We also are evaluating our two lease blocks offshore Brazil. We have international offices in London, England and Kuala Lumpur, Malaysia. We continue to evaluate and pursue other opportunities in select international areas.

Plans for 2005

Our capital budget for 2005 is $950 million, excluding acquisitions. About $330 million has been allocated to the Gulf of Mexico (including deepwater), $310 million to the Rocky Mountains and Mid-

Continent, $210 million to the onshore Gulf Coast and $100 million to international projects. We plan to drill about 500 wells in 2005, about 75% of which are lower risk wells in the Uinta Basin or the Mid-Continent. About $280 million has been earmarked for exploration activities.

Gulf of Mexico. We expect to drill about 30 wells in 2005, including 20 in the traditional shelf, 3-5 in the deep shelf, one in the ultra-deep Treasure Project and 3-6 in deepwater.

Onshore Gulf Coast. In 2005, we will balance development drilling of lower risk opportunities with some higher risk, higher impact exploration tests. We plan to drill about 70 wells.

Mid-Continent. We expect to drill about 200 wells. The majority of the planned drilling is associated with our gas mining initiative.

Rocky Mountains. Our primary capital program in the Monument Butte Field consists of drilling shallow, lower risk wells and water injection wells, waterflood optimization activities and investment in field infrastructure. We plan to drill about 175 wells in the field during 2005. We also plan to drill 2-4 exploratory wells to test deep gas prospects.

International. In early 2005, we drilled our first discovery in the U.K. North Sea and plan to drill at least two additional wells in 2005. Offshore Malaysia, we plan to drill up to six wells in shallow water.

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 and oil production is sold to a variety of purchasers under short-term (less than 12 months) contracts at current market prices. Oil sales contracts 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 our 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.

Refining capacity for the crude oil we produce from our Monument Butte Field in the Uinta Basin could be limited. Please see the discussion under the caption “Other Factors Affecting Our Business and Financial Results — We may not achieve the production growth we anticipated from our properties in the Uinta Basin” in Item 7 of this report.

Competition

Competition in the oil and gas industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage and the hiring and retention of technical personnel. 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 February 28, 2005, we had 640 employees. All but 20 of our employees are located in the U.S. None of our employees is covered by a collective bargaining agreement. We believe that relationships with our employees are satisfactory.

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. About 28% of our year-end 2004 proved reserves were located in the Gulf of Mexico compared to 94% just five years ago. Our ten largest fields accounted for approximately 41% of our proved reserves at year-end 2004. More than half of those reserves were located in the Monument Butte Field. This field accounted for 14% of the net present value of our proved reserves.

Gulf of Mexico

Our properties are in water depths ranging from 45 feet to more than 6,000 feet. As of December 31, 2004, we owned interests in about 300 leases on the shelf and about 80 leases in deepwater (approximately 1.9 million gross acres) and about 335 gross wells. The Gulf of Mexico accounted for about 28% of our proved reserves at December 31, 2004. We operated 81% of those reserves.

Onshore Gulf Coast

We have a significant acreage position along the Gulf Coast of Texas and Louisiana. As of December 31, 2004, we owned an interest in about 277,000 gross acres and about 495 gross wells. The onshore Gulf Coast accounted for about 25% of our proved reserves at December 31, 2004. We operated 72% of those reserves.

Mid-Continent

We have a sizeable presence in the Anadarko and Arkoma Basins. As of December 31, 2004, we owned an interest in approximately 514,000 gross lease acres, 22,000 gross mineral acres and about 2,420 gross wells. The Mid-Continent accounted for about 24% of our proved reserves at December 31, 2004. We operated 83% of those reserves.

Rocky Mountains

Our only field in the Rocky Mountains — Monument Butte — is located in the Uinta Basin of north-eastern Utah. As of December 31, 2004, we owned an interest in 110,000 gross acres, 568 gross producing wells and 293 water injection wells. The field accounted for about 21% of our proved reserves at December 31, 2004. We operated 100% of those reserves.

International

Malaysia. Through two production sharing contracts, or PSCs, we own interests in two blocks off- shore Malaysia. We own a 50% non-operated interest in shallow water concession PM 318 offshore Peninsular Malaysia. The block covers approximately 413,000 gross acres and has gross production of about 10,200 BOPD from two fields utilizing an FPSO installed in early 2004. On the same acreage, we also have active field developments underway on a series of undeveloped discoveries and exploration ideas that we plan to begin testing in 2005. Offshore Sarawak, we own a 60% operated interest in deepwater Block 2C, a 1.1 million acre area. No production exists on this acreage. We are utilizing a recent 4,200 square kilometer 3-D survey to search for drilling prospects that could be tested as early as 2006.

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. We have two undeveloped discoveries on the block — the CFD 12-1 and the CFD 12-1 South. The oil-in-place study has been approved by the Chinese government and the operator intends to file a plan of development in the first half of 2005. Subject to government approval of the plan, we anticipate commencing development of the fields by late 2005. First production from the fields could be in late 2006 or early 2007. Because of the pending governmental approvals, we have not booked any proved reserves with respect to these fields. At year-end 2004, we relinquished acreage outside of our planned field developments and now own interests in 27,000 gross acres.

North Sea. We drilled our first successful well in the North Sea in early 2005. The Grove Prospect, located on license area 49/10a, tested at over 25 MMcfe/d and is now under development with first production expected in late 2006. At December 31, 2004, we owned interests in 124,000 gross acres.

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 those reserves as of December 31, 2004.


		Proved Reserves

		Developed		Undeveloped		Total

United States:
	Oil and condensate (MMBbls)		49.7		35.1		84.8
	Gas (Bcf)		1,003.9		235.7		1,239.6
	Total proved reserves (Bcfe)		1,302.2		446.0		1,748.2
	Present value of estimated future after-tax net cash flows (in millions)⁽¹⁾					$	3,556.8
International:
	Oil and condensate (MMBbls)		5.7		—		5.7
	Gas (Bcf)		1.4		—		1.4
	Total proved reserves (Bcfe)		35.7		—		35.7
	Present value of estimated future after-tax net cash flows (in millions)⁽¹⁾					$	45.2
Total:
	Oil and condensate (MMBbls)		55.4		35.1		90.5
	Gas (Bcf)		1,005.3		235.7		1,241.0
	Total proved reserves (Bcfe)		1,337.9		446.0		1,783.9
	Present value of estimated future after-tax net cash flows (in millions)⁽¹⁾					$	3,602.0

(1)

This measure was prepared using year-end oil and gas prices adjusted for the location and quality of the reserves, discounted at 10% per year. Weighted average year-end prices, as so adjusted, were $5.86 per Mcf for gas and $40.87 per Bbl for oil. This calculation does not include the effects of hedging. For a further 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 credit facility, independent reserve engineers prepare separate reserve reports with respect to properties holding at least 80% of our proved reserves. At December 31, 2004, the independent reserve engineers’ reports covered properties representing 86% of our proved reserves and for such properties the reserves were within 1% of the reserves we estimated for such properties. Actual quantities of recoverable 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” under Item 7 of this report.

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, 2004.


			2004				2003				2002

			Gross		Net		Gross		Net		Gross		Net

Exploratory wells:
	Productive — U.S.			23		14.1		27		16.1		23		14.3
	Nonproductive — U.S.			17		11.0		24		14.4		13		7.8
	Productive — China⁽¹⁾			—		—		—		—		—		—
	Nonproductive — China			—		—		1		0.4		1		0.4
	Nonproductive — United Kingdom			1		1.0		—		—		—		—

		Total		41		26.1		52		30.9		37		22.5

Development wells:
	Productive — U.S.			231		174.8		139		92.4		36		18.0
	Nonproductive — U.S.			6		3.9		6		2.8		7		4.4

		Total		237		178.7		145		95.2		43		22.4

(1)

We drilled two gross (0.70 net) wells in 2003 and one gross (0.35 net) well in 2002 in China that are not included in the table. No wells were drilled in 2004. The oil-in-place study for the two fields in which these wells are located has been approved by the Chinese government and the operator intends to file a plan of development in the first half of 2005. Upon approval of the plan, these wells will be reported as productive.

We were in the process of drilling 47 gross (24.0 net) development wells in the U.S. and one gross (1.0 net) exploratory well in the United Kingdom at December 31, 2004.

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, 2004 and the location of, and other information with respect to, those wells.


				Company				Outside				Total
				Operated Wells				Operated Wells				Productive Wells

				Gross		Net		Gross		Net		Gross		Net

United States:
	Gulf of Mexico:
		Oil			53		38.8		6		2.1		59		40.9
		Gas			191		143.1		85		23.7		276		166.8
	Louisiana:
		Oil			1		0.8		2		0.2		3		1.0
		Gas			3		1.2		9		2.6		12		3.8
	Texas:
		Oil			23		18.4		34		4.2		57		22.6
		Gas			361		326.1		219		90.1		580		416.2
	Oklahoma:
		Oil			246		184.5		577		20.4		823		204.9
		Gas			780		578.0		625		105.2		1,405		683.2
	Utah:
		Oil			566		482.1		2		0.4		568		482.5
		Gas			—		—		—		—		—		—
	Other domestic:
		Oil			2		1.0		1		0.3		3		1.3
		Gas			9		6.8		24		4.0		33		10.8

	Total domestic:
		Oil			891		725.6		622		27.6		1,513		753.2
		Gas			1,344		1,055.2		962		225.6		2,306		1,280.8

International:
	Offshore Malaysia:
		Oil			—		—		9		3.9		9		3.9
	Offshore United Kingdom:
		Gas			—		—		2		0.4		2		0.4

Total:
		Oil			891		725.6		631		31.5		1,522		757.1
		Gas			1,344		1,055.2		964		226.0		2,308		1,281.2

			Total		2,235		1,780.8		1,595		257.5		3,830		2,038.3

The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements or production sharing contracts. The operator supervises production, maintains production records, employs or contracts for field personnel and performs other functions. Generally, 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.

Acreage Data

We own interests in developed and undeveloped oil and gas acreage in the locations set forth in the table below. Domestic ownership interests generally take the form of “working interests” in oil and gas leases that have varying terms. The following table shows certain information regarding our developed and undeveloped acreage as of December 31, 2004.


				Developed Acres				Undeveloped Acres

				Gross		Net		Gross		Net

				(in thousands)
United States:
	Gulf of Mexico:
		Shelf			749.1		420.3		263.4		192.0
		Treasure Project			—		—		454.5		191.9
		Deepwater			63.4		14.0		358.6		138.6

			Total Gulf of Mexico		812.5		434.3		1,076.5		522.5

	Louisiana				13.9		8.4		6.2		4.1
	Texas				145.5		86.5		170.6		110.7
	Oklahoma				156.5		83.7		279.0		203.4
	Utah				37.5		31.3		74.3		55.7
	Other domestic				9.9		4.0		7.8		4.5

			Total onshore		363.3		213.9		537.9		378.4

			Total domestic		1,175.8		648.2		1,614.4		900.9

International:
	Offshore Brazil				—		—		206.2		206.2
	Offshore China				—		—		27.1		9.5
	Offshore Malaysia				5.5		2.7		1,505.2		864.0
	Offshore United Kingdom				6.0		1.2		118.2		109.2

			Total international		11.5		3.9		1,856.7		1,188.9

Total					1,187.3		652.1		3,471.1		2,089.8

The table below summarizes by year and geographic area our undeveloped 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 226,580 gross (98,593 net) undeveloped acres. These interests do not expire.


				Undeveloped Acres Expiring

				2005				2006				2007				2008				2009

				Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net

				(in thousands)
United States:
	Gulf of Mexico:
		Shelf			9.5		7.1		66.7		52.3		60.0		47.1		65.9		55.1		22.2		22.2
		Treasure Project⁽¹⁾			68.2		65.5		30.2		30.2		30.2		7.5		252.2		64.8		35.0		10.2
		Deepwater			93.6		31.1		69.1		31.7		51.8		20.6		11.5		3.0		—		—

			Total Gulf of Mexico		171.3		103.7		166.0		114.2		142.0		75.2		329.6		122.9		57.2		32.4

	Onshore				222.6		102.1		106.2		77.0		87.2		71.1		11.4		8.7		2.2		0.7

			Total domestic		393.9		205.8		272.2		191.2		229.2		146.3		341.0		131.6		59.4		33.1

International:
	Offshore Brazil				—		—		120.5		120.5		85.7		85.7		—		—		—		—
	Offshore China				—		—		—		—		—		—		—		—		—		—
	Offshore Malaysia				—		—		—		—		—		—		—		—		—		—
	Offshore United Kingdom				—		—		—		—		—		—		—		—		—		—

			Total international		—		—		120.5		120.5		85.7		85.7		—		—		—		—

Total					393.9		205.8		392.7		311.7		314.9		232.0		341.0		131.6		59.4		33.1


(1)	Of the 68,200 gross acres (all or part of 14 lease blocks) associated with our Treasure Project concept (all of which are in Treasure Island) that are scheduled to expire in 2005, we anticipate that about one-half will be protected by completed or planned activities under existing or proposed regulations of the MMS.

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;

	•	burdens such as net profits interests; and

	•	capital commitments under production sharing contracts or exploration licenses.

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 2004.

Item 4A. Executive Officers of the Registrant

The following table sets forth the names and ages (as of February 28, 2005) of and positions held by our executive officers. Our executive officers serve at the discretion of our Board of Directors.


				Total Years
				of Service
				with
Name	Age		Position	Newfield

David A. Trice		56	Chairman, President and Chief Executive Officer and a Director		10
David F. Schaible		44	Executive Vice President – Operations and Acquisitions and a Director		15
Elliott Pew		50	Executive Vice President – Exploration		7
Terry W. Rathert		52	Senior Vice President, Chief Financial Officer and Secretary		15
Lee K. Boothby		43	Vice President – Mid-Continent		5
George T. Dunn		47	Vice President – Gulf Coast		12
Gary D. Packer		42	Vice President – Rocky Mountains		9
William D. Schneider		53	Vice President – International		15
Brian L. Rickmers		36	Controller and Assistant Secretary		11
Susan G. Riggs		47	Treasurer		8

The executive officers have held the positions indicated above for the past five years, except as follows:

David A. Trice was appointed Chairman in September 2004.

David F. Schaible was promoted from Vice President to Executive Vice President in November 2004. He has served as a director since May 2002.

Elliott Pew was promoted from Vice President to Executive Vice President in November 2004.

Terry W. Rathert was promoted from Vice President to Senior Vice President in November 2004.

Lee K. Boothby was promoted to Vice President – Mid-Continent in November 2004. He has managed our Mid-Continent operations since February 2002. From August 1999 through January 2002, he managed our Australian operations.

George T. Dunn was promoted to Vice President – Gulf Coast in November 2004. He has managed our onshore Gulf Coast operations since 2001. Prior to that, he was the General Manager of our Western Gulf of Mexico operations.

Gary D. Packer was promoted from a Gulf of Mexico General Manager to Vice President – Rocky Mountains in November 2004.

Brian L. Rickmers has served as Controller and Assistant Secretary since May 2001. From February 2000 to May 2001, he served as Assistant Controller.

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.


		High		Low

2003
	First Quarter	$	36.90	$	31.35
	Second Quarter		39.10		32.49
	Third Quarter		40.33		33.64
	Fourth Quarter		45.51		38.20
2004
	First Quarter		50.20		44.15
	Second Quarter		56.72		46.92
	Third Quarter		62.82		52.57
	Fourth Quarter		65.83		55.75
2005
	First Quarter (Through March 7, 2005)		76.65		54.87

On March 7, 2005, the last reported sales price of our common stock on the New York Stock Exchange was $75.38 per share.

As of March 1, 2005, there were approximately 2,900 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 8³/8% Senior Subordinated Notes due 2012 and our 6⁵/8% Senior Subordinated Notes due 2014 could restrict our ability to pay cash dividends.

The following table sets forth certain information with respect to repurchases of our common stock during the three-month period ended December 31, 2004.


							Maximum Number
					Total Number of		(or Approximate)
					Shares Purchased		Dollar Value) of
					as Part of Publicly		Shares that May Yet
	Total Number of		Average Price		Announced Plans		Be Purchased Under
Period	Shares Purchased⁽¹⁾		Paid per Share		or Programs		the Plans or Programs

October 1 – October 31, 2004		—		—		—		—
November 1 – November 30, 2004		397	$	59.78		—		—
December 1 – December 31, 2004		1,696	$	59.35		—		—


(1)	All of the shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to purchase shares of our common stock.


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.


			Year Ended December 31,

			2004			2003			2002			2001			2000

			(In millions, except per share data)
Income Statement Data:
Oil and gas revenues			$	1,352.7		$	1,017.0		$	626.8		$	714.1		$	479.9

Operating expenses:
	Lease operating			145.7			119.3			90.8			85.7			51.5
	Production and other taxes			42.3			31.7			13.3			14.4			5.6
	Transportation			6.3			6.4			5.7			5.6			6.0
	Depreciation, depletion and amortization			471.4			394.7			295.1			274.9			183.7
	Ceiling test writedown			17.0			—			—			106.0			0.5
	General and administrative			84.0			61.6			54.4			42.6			31.5
	Impairment of floating production system and pipelines			35.0			—			—			—			—
	Gas sales obligation settlement and redemption of securities			—			20.5			—			—			—

		Total operating expenses		801.7			634.2			459.3			529.2			278.8

Income from operations				551.0			382.8			167.5			184.9			201.1
Other income (expense), net				(28.3	)		(45.1	)		(30.5	)		(27.6	)		(17.6	)
Commodity derivative income (expense)⁽¹⁾				(23.8	)		(6.1	)		(29.1	)		24.8			—

Income from continuing operations before income taxes				498.9			331.6			107.9			182.1			183.5
Income tax provision				186.8			120.7			39.2			64.7			64.6

Income from continuing operations				312.1			210.9			68.7			117.4			118.9
Income (loss) from discontinued operations, net of tax ⁽²⁾				—			(17.0	)		5.1			6.4			15.8

Income before cumulative effect of change in accounting principle				312.1			193.9			73.8			123.8			134.7
Cumulative effect of change in accounting principle, net of tax^(1)(3)(4)				—			5.6			—			(4.8	)		(2.4	)

	Net income		$	312.1		$	199.5		$	73.8		$	119.0		$	132.3

Earnings per share:
Basic —
	Income from continuing operations		$	5.35		$	3.88		$	1.52		$	2.65		$	2.81
	Income (loss) from discontinued operations⁽²⁾			—			(0.31	)		0.12			0.15			0.37
	Cumulative effect of change in accounting principle, net of tax^(1)(3)(4)			—			0.10			—			(0.11	)		(0.05	)

	Net income		$	5.35		$	3.67		$	1.64		$	2.69		$	3.13

Diluted —
	Income from continuing operations		$	5.26		$	3.77		$	1.51		$	2.53		$	2.65
	Income (loss) from discontinued operations⁽²⁾			—			(0.30	)		0.10			0.13			0.33
	Cumulative effect of change in accounting principle, net of tax^(1)(3)(4)			—			0.10			—			(0.10	)		(0.05	)

	Net income		$	5.26		$	3.57		$	1.61		$	2.56		$	2.93

Weighted average number of shares outstanding for basic earnings per share				58.3			54.3			45.1			44.3			42.3
Weighted average number of shares outstanding for diluted earnings per share				59.3			56.7			49.6			48.9			47.2


		Year Ended December 31,

		2004			2003			2002			2001			2000

		(In millions)
Cash Flow Data:
Net cash provided by continuing operating activities		$	997.5		$	659.2		$	383.3		$	495.6		$	289.4
Net cash used in continuing investing activities			(1,598.8	)		(614.7	)		(501.8	)		(754.5	)		(339.3	)
Net cash provided by (used in) continuing financing activities			643.8			(85.4	)		137.0			273.1			15.9
Balance Sheet Data (at end of period):
Working capital surplus (deficit)		$	(82.4	)	$	(61.3	)	$	(57.0	)	$	65.6		$	38.5
Oil and gas properties, net			3,775.3			2,418.5			1,986.9			1,395.3			822.3
Total assets			4,327.5			2,733.1			2,315.8			1,663.4			1,023.3
Long-term debt			992.4			643.5			709.6			428.6			133.7
Convertible preferred securities			—			—			143.8			143.8			143.8
Stockholders’ equity			2,016.9			1,368.6			1,009.3			710.1			519.5
Reserve Data (at end of period):
Proved reserves:
	Oil and condensate (MMBbls)		90.5			37.8			34.0			31.0			22.6
	Gas (Bcf)		1,241			1,090			977			718			520
	Total proved reserves (Bcfe)		1,784			1,317			1,181			904			655
Present value of estimated future after-tax net cash flows		$	3,602.0		$	2,935.4		$	2,247.0		$	958.9		$	2,653.4


(1)	We adopted Financial Accounting Standards Board (FASB) Statement (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 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 – see Note 6, “Commodity Derivative Instruments and Hedging Activities,” to our consolidated financial statements), including changes associated with time value, in Accumulated other comprehensive income (loss) — Commodity derivates. 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.

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

(3)	We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” on January 1, 2003. This statement changed 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.

(4)	We adopted SEC Staff Accounting Bulletin (SAB) No. 101, “Revenue Recognition in Financial Statements,” effective January 1, 2000. SAB No. 101 required 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 $2.4 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.


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 domestic areas of operation include the Gulf of Mexico, the onshore Gulf Coast, the Anadarko and Arkoma Basins of the Mid-Continent and the Uinta Basin of the Rocky Mountains. Internationally, we are active offshore Malaysia, in the North Sea, offshore Brazil and in China’s Bohai Bay.

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 our 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 quantity 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 reduce our exposure to commodity price fluctuations.

Reserve Replacement. Most of our producing properties have declining production rates. As a result, to maintain and grow our production and cash flow 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:


	•	the quantity of our proved oil and gas reserves;

	•	the timing of future drilling, development and abandonment activities;

	•	the cost of these activities in the future;

	•	the fair value of the assets and liabilities of acquired companies; and

	•	the value of our derivative positions.

Other Factors. 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

We completed several significant acquisitions during the second and third quarters of 2004. As described in more detail in the relevant discussions below, these acquisitions had a meaningful impact on our 2004 results of operations and cash flows. In May 2004, we entered into PSCs with Malaysia’s state-owned oil company in partnership with its exploration and production subsidiary. In July 2004, we acquired producing oil and gas properties in Oklahoma. Also in July 2004, we acquired all of the outstanding stock of Denbury Offshore, Inc., the subsidiary of Denbury Resources Inc. that held substantially all of its Gulf of Mexico assets. In August 2004, we acquired Inland Resources Inc. These acquisitions were financed through cash on hand, borrowings under our credit arrangements and offerings of our common stock and

our 6⁵/8% Senior Subordinated Notes due 2014. See Note 4, “Acquisitions,” Note 8, “Debt,” and Note 10, “Common Stock Activity” to our consolidated financial statements set forth in Item 8 in this report for a full discussion of these activities.

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 our Australian operations are reflected on our consolidated financial statements as “discontinued operations.” Please see Note 2, “Discontinued Operations,” to our consolidated financial statements. 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, which is net of the effects of the settlement of qualifying hedging contracts associated with our production. Settlement of our three-way collar contracts, which do not qualify for hedge accounting under SFAS No. 133, has no effect on our reported revenues. Our revenues may vary significantly from year to year as a result of changes in commodity prices or production volumes. Revenues for 2004 reached a record $1.4 billion and were 33% higher than 2003 revenues due to a substantial increase in natural gas and crude oil prices and a 10% increase in production primarily resulting from the 2004 acquisitions mentioned above and our acquisition of Primary Natural Resources (PNR) in September 2003.


		Year Ended December 31,

		2004		2003		2002

Production⁽¹⁾:
United States:
	Natural gas (Bcf)		197.6		184.2		144.7
	Oil and condensate (MBbls)		6,686		6,054		5,235
	Total (Bcfe)		237.7		220.6		176.1
International:
	Natural gas (Bcf)		0.6		—		—
	Oil and condensate (MBbls)		879		—		—
	Total (Bcfe)		5.9		—		—
Total:
	Natural gas (Bcf)		198.2		184.2		144.7
	Oil and condensate (MBbls)		7,565		6,054		5,235
	Total (Bcfe)		243.6		220.6		176.1
Average Realized Prices⁽²⁾:
United States:
	Natural gas (per Mcf)	$	5.40	$	4.60	$	3.44
	Oil and condensate (per Bbl)		36.61		27.99		24.54
	Natural gas equivalent (per Mcfe)		5.52		4.61		3.56
International:
	Natural gas (per Mcf)	$	4.38	$	—	$	—
	Oil and condensate (per Bbl)		44.26		—		—
	Natural gas equivalent (per Mcfe)		7.07		—		—
Total:
	Natural gas (per Mcf)	$	5.39	$	4.60	$	3.44
	Oil and condensate (per Bbl)		37.50		27.99		24.54
	Natural gas equivalent (per Mcfe)		5.55		4.61		3.56


(1)	Represents volumes sold regardless of when produced.

(2)	Average realized prices include the effects of hedging other than our three-way collar contracts, which do not qualify for hedge accounting under SFAS No. 133. Had we included the effects of these contracts, our average realized price for total natural gas would have been $5.36 per Mcf and our average realized price for total oil and condensate would have been $35.27 per Bbl for 2004. No three-way contracts were settled in 2003 or 2002.

Production. Our 2004 total oil and gas production (stated on a natural gas equivalent basis) increased 10% over 2003. The increase primarily was the result of our PNR acquisition in September 2003, the Oklahoma property and Denbury Offshore acquisitions in July 2004, the Inland acquisition in August 2004 and successful drilling efforts. In addition, liftings in Malaysia began during the third quarter of 2004. These increases were partially offset by shut-in production of approximately 2.5 Bcfe during the third quarter of 2004 in the Gulf of Mexico due to Hurricane Ivan and natural field declines. Our 2003 total oil and gas production increased 25% over 2002 primarily as a result of our acquisition of EEX Corporation in November 2002, other small acquisitions and successful drilling efforts. 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.

Natural Gas. Our 2004 natural gas production increased 8% when compared to 2003. The increase primarily was the result of the 2004 acquisitions mentioned above and successful drilling efforts. The increase partially offset the shut-in due to Hurricane Ivan described above and natural field declines. Our 2003 natural gas production was 27% higher when compared to 2002. The increase primarily was the result of our acquisition of EEX. 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 the voluntarily curtailment and the shut-ins described above.

Crude Oil and Condensate. Our 2004 oil and condensate production increased 25% when compared to 2003 primarily due to initial production and liftings in Malaysia and the acquisition of Inland in the third quarter of 2004. Our domestic oil production increased primarily as a result of the Inland acquisition, partially offset by natural field declines. Our 2003 oil production increased 16% when compared to 2002 primarily due to development drilling programs in the U.S. and the acquisition of EEX in November 2002, which were partially offset by natural field declines in all producing regions.

Effects of Hedging on Realized Prices. The following table presents information about the effects of our hedging program on realized prices.


		Average Realized
		Prices				Ratio of
						Hedged to
		With		Without		Non-Hedged
		Hedge⁽¹⁾		Hedge		Price⁽²⁾

Natural Gas:
	Year ended December 31, 2004	$	5.39	$	5.75		94	%
	Year ended December 31, 2003		4.60		5.15		89	%
	Year ended December 31, 2002		3.44		3.19		108	%
Crude Oil and Condensate:
	Year ended December 31, 2004	$	37.50	$	40.95		92	%
	Year ended December 31, 2003		27.99		30.10		93	%
	Year ended December 31, 2002		24.54		24.78		99	%


(1)	Average realized prices in this column do not include the effects of our three-way collar contracts, which do not qualify for hedge accounting under SFAS No. 133. Had we included the effects of these contracts, our average realized price for natural gas for 2004 would have been $5.36 per Mcf and our average realized price for oil and condensate for 2004 would have been $35.27 per Bbl. No three-way contracts were settled in 2003 or 2002.

(2)	The ratio is determined by dividing the realized price (which includes the effects of hedging other than three-way collar contracts) 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 regularly recurring operating expenses from period to period is on a unit-of-production, or per Mcfe, basis.

Year ended December 31, 2004 compared to December 31, 2003

The following table presents information about our operating expenses for each of the years in the two-year period ended December 31, 2004.


			Unit-of-Production							Amount
			(Per Mcfe)							(In millions)

			Year Ended							Year Ended
			December 31,				Percentage			December 31,				Percentage
							Increase							Increase
			2004		2003		(Decrease)			2004		2003		(Decrease)

United States:
	Lease operating		$	0.57	$	0.54		6	%	$	136.4	$	119.3		14	%
	Production and other taxes			0.17		0.14		21	%		40.0		31.7		26	%
	Transportation			0.03		0.03		—			6.3		6.4		(2	%)
	Depreciation, depletion and amortization			1.95		1.79		9	%		463.4		394.7		17	%
	General and administrative			0.34		0.28		21	%		81.8		61.6		33	%
	Impairment of floating production system and pipelines			0.15		—		N/M	⁽²⁾		35.0		—		N/M	⁽²⁾
	Gas sales obligation settlement and redemption of securities			—		0.09		N/M	⁽²⁾		—		20.5		N/M	⁽²⁾
		Total operating expenses		3.21		2.87		12	%		762.9		634.2		20	%
		Total regularly recurring operating expenses⁽¹⁾		3.06		2.78		10	%		727.9		613.7		19	%
International:
	Lease operating		$	1.59						$	9.3
	Production and other taxes			0.38							2.3
	Transportation			—							—
	Depreciation, depletion and amortization			1.37							8.0
	General and administrative			0.37							2.2
	Ceiling test writedown			2.90							17.0
		Total operating expenses		6.61							38.8
		Total regularly recurring operating expenses⁽¹⁾		3.71							21.8
Total:
	Lease operating		$	0.60	$	0.54		11	%	$	145.7	$	119.3		22	%
	Production and other taxes			0.17		0.14		21	%		42.3		31.7		33	%
	Transportation			0.03		0.03		—			6.3		6.4		(2	%)
	Depreciation, depletion and amortization			1.94		1.79		8	%		471.4		394.7		19	%
	General and administrative			0.34		0.28		21	%		84.0		61.6		36	%
	Ceiling test writedown			0.07		—		N/M	⁽²⁾		17.0		—		N/M	⁽²⁾
	Impairment of floating production system and pipelines			0.14		—		N/M	⁽²⁾		35.0		—		N/M	⁽²⁾
	Gas sales obligation settlement and redemption of securities			—		0.09		N/M	⁽²⁾		—		20.5		N/M	⁽²⁾
		Total operating expenses		3.29		2.87		15	%		801.7		634.2		26	%
		Total regularly recurring operating expenses⁽¹⁾		3.08		2.78		11	%		749.7		613.7		22	%


(1)	Excludes the impairment of the floating production system and pipelines of $35.0 million and the ceiling test writedown of $17.0 million in 2004 and excludes the expenses associated with the settlement of our gas sales obligation and redemption of our trust preferred securities of $20.5 million in 2003. We believe the most informative way to analyze changes in our operating expenses is to compare regularly recurring operating expenses only. We discuss the ceiling test writedown, the impairment, the settlement of our gas sales obligation and the redemption of our trust preferred securities separately below. See “— Ceiling Test Writedown,” “— Impairment of Floating Production System and Pipelines,” “— Gas Sales Obligation Settlement” and “— Redemption of Trust Preferred Securities.”

(2)	Not meaningful.

Our 2004 total regularly recurring operating expenses, stated on an Mcfe basis, increased 11% over 2003.

Domestic Operations. Our domestic regularly recurring operating expenses for 2004, stated on an Mcfe basis, increased 10% over the same period of 2003. This increase was primarily related to the following items:


	•	Lease operating expense (LOE), on an Mcfe basis, increased in 2004 as a result of higher operating costs and natural field declines in our Gulf of Mexico properties.

	•	Production and other taxes, on an Mcfe basis, increased in 2004 due to higher commodity prices and an increase in our production volumes subject to production taxes.


	•	Depreciation, depletion and amortization (DD&A) (excluding furniture, fixtures and equipment) for 2004 was $1.94 per Mcfe versus $1.76 per Mcfe for the comparable period of 2003. The increase resulted from higher cost reserve additions during 2004. Accretion expense related to SFAS No. 143 was $0.05 per Mcfe for 2004 and $0.03 per Mcfe for 2003.

	•	General and administrative expense (G&A) for 2004, on an Mcfe basis, increased $0.06 per Mcfe, or 21%. The increase was primarily due to our growing workforce from acquisitions and an increase in incentive compensation expense as a result of the increase in our 2004 profitability over 2003. During 2004, we capitalized $31.7 million of direct internal costs as compared to $26.7 million in 2003.

International Operations. Prior to entering into the Malaysian PSCs, our producing international operations consisted of one field in the U.K. North Sea. Liftings in Malaysia began in the third quarter of 2004. The majority of LOE, production and other taxes and DD&A for 2004 relates to our Malaysian operations. G&A expense is primarily associated with our U.K. North Sea operations and the opening of our office in Malaysia during 2004.

Year ended December 31, 2003 compared to December 31, 2002

Our Australian operations were sold in September 2003 and have been excluded from our reported operations for the years ended December 31, 2003 and 2002. Other international operations for these periods were immaterial and are not reported separately.

The following table presents information about our operating expenses for each of the years in the two-year period ended December 31, 2003.


		Unit-of-Production							Amount
		(Per Mcfe)							(In millions)

		Year Ended							Year Ended
		December 31,				Percentage			December 31,				Percentage
						Increase							Increase
		2003		2002		(Decrease)			2003		2002		(Decrease)

Lease operating		$	0.54	$	0.52		4	%	$	119.3	$	90.8		31	%
Production and other taxes			0.14		0.08		75	%		31.7		13.3		138	%
Transportation			0.03		0.03		—			6.4		5.7		12	%
Depreciation, depletion and amortization			1.79		1.68		7	%		394.7		295.1		34	%
General and administrative			0.28		0.31		(10	%)		61.6		54.4		13	%
Gas sales obligation settlement and redemption of securities			0.09		—		N/M	⁽²⁾		20.5		—		N/M	⁽²⁾
	Total operating expenses		2.87		2.62		10	%		634.2		459.3		38	%
	Total regularly recurring operating expenses⁽¹⁾		2.78		2.62		6	%		613.7		459.3		34	%


(1)	Excludes the expenses associated with the settlement of our gas sales obligation and redemption of our trust preferred securities during 2003 of $20.5 million, or $0.09 per Mcfe. We believe the most informative way to analyze changes in our operating expenses is to compare regularly recurring operating expenses only. We discuss the settlement of our gas sales obligation and the redemption of our trust preferred securities separately below. See “— Gas Sales Obligation Settlement” and “— Redemption of Trust Preferred Securities.”

(2)	Not meaningful.

Our total regularly recurring operating expenses, stated on an Mcfe basis, increased 6% over 2002. The increase was primarily related to the following items:


	•	LOE on an Mcfe basis for 2003 increased 4% in large part due to the addition of higher cost onshore properties from the EEX acquisition and a higher level of workover activity in 2003.

	•	Production taxes on an Mcfe basis increased 75% in 2003 due to higher commodity prices. Additionally, a greater percentage of our production was onshore and subject to production taxes in 2003 as compared to 2002.

	•	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, 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.

• G&A expense for 2003, on an Mcfe basis, before capitalized direct internal costs, increased $0.05 per Mcfe, or 14%. The increase was primarily due to an increase in the number of employees as a result of our growth and an increase in incentive compensation expense due to the significant increase in 2003 earnings. The 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.

Ceiling Test Writedown. In November 2004, we announced that our Cumbria Prospect in the North Sea was a dry hole. Under full cost accounting, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized in cost centers on a country-by-country basis. Because the unamortized costs exceeded the full cost ceiling, we were required to recognize a ceiling test writedown of $17.0 million in 2004.

Impairment of 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, some offshore pipelines and a processing facility located at the end of the pipelines in shallow water. The floating production system is a combination deepwater drilling rig and processing facility capable of simultaneous drilling and production operations. At the time of acquisition, we estimated the fair market value of these assets to be $35.0 million. These infrastructure assets are not currently in service and we do not have a specific use for them in our offshore operations.

Since their acquisition, we had undertaken to sell these assets. In December 2004, when what we believed was the last commercial opportunity for sale was not realized, we determined that there was no active market for these assets. As a result, in connection with the preparation of our consolidated financial statements as of and for the year ended December 31, 2004, we recorded an impairment charge of $35.0 million in the fourth quarter of 2004 under the caption “Impairment of floating production system and pipelines” on our consolidated statement of income.

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 a third party in exchange for proceeds of $105 million. When we acquired EEX, we recorded a liability of $61.6 million, which represented the then current market value of approximately 16 Bcf of remaining reserves subject to the contract. We accounted for the obligation under the gas sales contract as debt on our consolidated balance sheet. In March 2003, pursuant to a settlement agreement, the gas sales contract and all related agreements were terminated in exchange for a payment by us of approximately $73 million. We recognized a loss of $10.0 million under the caption “Gas sales obligation settlement and redemption of securities” on our consolidated statement of income as a result of the settlement.

Redemption of Trust Preferred Securities. In June 2003, we redeemed all of our outstanding convertible trust preferred securities for an aggregate redemption price of approximately $148.4 million, including $6.5 million of optional redemption premium. 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 (approximately $131.2 million) from the issuance and sale of 3.5 million shares of our common stock in May 2003 and borrowings under our credit arrangements.

Interest Expense. The following table presents information about our interest expense for each of the years in the three-year period ended December 31, 2004.


		Year Ended December 31,

		2004			2003			2002

		(In millions)
Gross interest expense		$	57.7		$	57.8		$	34.5
Capitalized interest			(25.8	)		(15.9	)		(8.8	)

Net interest expense			31.9			41.9			25.7
Distributions on preferred securities			—			4.6			9.3

	Total interest expense and distributions	$	31.9		$	46.5		$	35.0

Gross Interest Expense. The components of gross interest expense for each of the years in the three-year period ended December 31, 2004 are as follows:


		Year Ended
		December 31,

		2004			2003			2002

		(In millions)
Credit arrangements		$	5.0		$	4.0		$	2.9
Senior notes			23.2			23.2			23.2
Interest rate swaps			(2.1	)		(0.7	)		—
Senior subordinated notes			30.2			22.1			5.2
Secured notes			0.4			5.6			0.6
Gas sales obligation			—			0.8			0.3
Other			1.0			2.8			2.3

	Gross interest expense	$	57.7		$	57.8		$	34.5

Average outstanding borrowings under our credit arrangements during 2004 were about 18% higher than during 2003 because we financed the cash consideration for our Oklahoma property and Denbury Offshore acquisitions (approximately $226 million) primarily with borrowings under our credit arrangements. The weighted average interest rate also was slightly higher in 2004. Average outstanding borrowings under our credit arrangements during 2003 were about 30% more than during 2002 because of borrowings to repay or settle the EEX obligations described below and to finance our September 2003 acquisition of PNR (approximately $91 million). The weighted average interest rate was slightly lower in 2003 compared to 2002.

During 2003, we entered into interest rate swap agreements with respect to $50 million principal amount of our 7.45% Senior Notes due 2007 and $50 million principal amount of our 7⁵/8% Senior Notes due 2011. These swap agreements provide for us to pay variable and receive fixed interest payments.

In August 2002, we issued $250 million principal amount of our 8³/8% Senior Subordinated Notes due 2012 to finance the repayment of EEX obligations due at the closing and transaction costs. 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 issued $325 million principal amount of our 6⁵/8% Senior Subordinated Notes due 2014 in August 2004 in connection with our acquisition of Inland later that month.

In connection with our acquisition of EEX, we also assumed $100.8 million principal amount of secured notes (interest rate of 7.54% per annum) and $61.6 million under a gas forward sales contract (effective interest rate of 9.5% per annum). We repurchased $23.6 million principal amount of secured notes in December 2002. During 2003, we repurchased or repaid $74.3 million principal amount of secured notes. Interest expense for 2003 includes $3.9 million of premiums paid in connection with repurchases. In January 2004, we repurchased the remainder of the secured notes. We settled the gas forward 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.

Capitalized Interest. We capitalize interest with respect to unproved properties. Interest capitalized in 2004 increased over 2003 primarily due to an increase in our unproved property base as a result of the Inland acquisition. Capitalized interest increased during 2003 because of our increased unproved property base resulting from the EEX acquisition.

Distributions on Preferred Securities. We redeemed all of our outstanding trust preferred securities in June 2003 with the net proceeds from an offering of our common stock and borrowings under our credit arrangements. See “— Redemption of Trust Preferred Securities” above.

Commodity Derivative Expense. The following table presents information about the components of commodity derivative expense for each of the years in the three-year period ended December 31, 2004.


			Year Ended December 31,

			2004			2003			2002

			(In millions)
Cash Flow Hedges:
	Hedge ineffectiveness		$	3.8		$	(1.1	)	$	(0.5	)
	Unrealized loss due to changes in time value			—			—			(28.6	)
Three-Way Collar Contracts:
	Unrealized (loss) due to changes in fair market value			(3.4	)		(5.0	)		—
	Realized (loss) on settlement			(24.2	)		—			—

		Total commodity derivative income (expense)	$	(23.8	)	$	(6.1	)	$	(29.1	)

Hedge ineffectiveness is associated with our hedging contracts that qualify for hedge accounting under SFAS No. 133. The unrealized loss associated with our cash flow hedges reflects the reversal of the time value gains that were recognized in 2001. See Note 6, “Commodity Derivative Instruments and Hedging Activities,” to our consolidated financial statements set forth in Item 8 of this report. The unrealized loss associated with our three-way collar contracts represents changes in the fair market value of our open three-way collar contracts (which do not qualify for hedge accounting).

Taxes. The effective tax rates for the years ended December 31, 2004, 2003 and 2002 were 37%, 36% and 36%, respectively. The effective tax rate for all three years was more than the federal statutory tax rate primarily due to state income taxes associated with income from various states. Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, estimates of the timing and amount of future production and estimates of future operating expenses and capital costs.

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 changed 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 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 asset retirement obligation, or 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. See Note 1, “Organization and Summary of Significant Accounting Policies — Accounting for Asset Retirement Obligations,” to our consolidated financial statements set forth in Item 8 of this report.

Results of Discontinued Operations

As a result of the sale of our Australian operations in September 2003, the historical financial position, results of operations and cash flow of these operations are reflected in our consolidated financial statements as “discontinued operations.” The results of our Australian operations for each of the years in the two-year period ended December 31, 2003 are summarized in Note 2, “Discontinued Operations,” to our consolidated financial statements.

Liquidity and Capital Resources

We must find new and develop existing reserves to maintain and grow production and cash flow. We add new reserves and grow production through successful exploration and development drilling and the acquisition of properties. These activities require substantial capital expenditures. Historically, we have successfully grown our reserve base and production, resulting in net long-term growth in our cash flow from operating activities. Fluctuations in commodity prices have been the primary reason for short-term changes in our cash flow from operating activities.

We establish a capital budget at the beginning of each calendar year based on expected cash flow from operations for that year. In the past, we often have revised our capital budget upward several times during the year as a result of acquisitions or successful drilling. Because of the nature of the properties we own, a substantial majority of our capital budget is discretionary.

Credit Arrangements. On March 16, 2004, we entered into a 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 $600 million. The amount available under the facility is subject to a calculated borrowing base determined by banks holding 75% of the aggregate commitments. The calculated borrowing base is then reduced by the principal amount of any outstanding senior notes ($300 million at February 28, 2005) and 30% of the principal amount of any outstanding senior subordinated notes (a reduction of $172.5 million at February 28, 2005). The borrowing base is redetermined at least semi-annually and, after all required adjustments, exceeded the facility amount by $100 million and therefore was limited to $600 million at February 28, 2005. 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 March 14, 2008.

We also have money market lines of credit with various banks in an amount limited by our credit facility to $50 million. At February 28, 2005, we had outstanding borrowings and letters of credit under our credit facility of $83 million and $31 million, respectively, and no outstanding borrowings under our money market lines. Consequently, at February 28, 2005, we had approximately $536 million of available capacity under our credit arrangements.

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 $82.4 million as of December 31, 2004. This compares to working capital deficits of $61.3 million at the end of 2003 and $57.0 million at the end of 2002. Our 2004 working capital deficit includes $22.9 million in asset retirement obligations compared to $12.1 million in asset retirement obligations in 2003 (see Note 1, “Organization and Summary of Significant Accounting Policies — Accounting for Asset Retirement Obligations,” to our consolidated financial statements) and a higher accrued employee incentive payable than in 2003 due to an increase in our 2004 net income and several deferred acquisition payments related to our 2004 acquisitions (see Note 7, “Accrued Liabilities,” to our consolidated financial statements). Our working capital also is affected by fluctuations in the fair value of our commodity derivative instruments. Our 2002 working capital deficit included an $11.2 million secured note payment due January 2003 and accrued severance costs associated with our acquisition of EEX.

Cash Flows from Continuing Operations. Cash flows from operations is primarily affected by production and commodity prices, net of the effects of hedging. Our cash flows from operations are also impacted by changes in working capital. We sell substantially all of our natural gas and oil production under floating market contracts. However, we enter into hedging arrangements to reduce our exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” We typically receive the cash associated with accrued oil and gas sales within 45-60 days of production. As a result, cash flows from operations and income from operations generally correlate, but cash flows from operations is impacted by changes in working capital and is not affected by DD&A or writedowns.

Our net cash flows from continuing operations were $997.5 million in 2004, a 51% increase over the prior year. The increase was primarily due to a 20% increase in our realized oil and gas prices (on a natural gas equivalent basis) and a 10% increase in production volumes due to our acquisitions during 2004. See “—Results of Operations” above. Accounts payable and accrued liabilities increased $80.0 million due to the increased levels of development and exploration activities in progress at year-end 2004, our growth from acquisitions during 2004 and higher commodity prices in effect at December 31, 2004.

Our net cash flows from continuing operations were $659.2 million in 2003, a 72% increase over the prior year. The increase was primarily due to a 30% increase in oil and gas prices (on a natural gas equivalent basis) and a 25% increase in production volumes as a result of our acquisition of EEX. See “— Results of Operations” above. A substantial portion of the net increase of $38.0 million in other current assets in 2003 is related to a receivable for overpaid federal income taxes for 2003. Accounts payable and accrued liabilities and other liabilities decreased $40.0 million. Accounts payable fluctuate from period to period depending on the level of development and exploration activities in progress and the timing of payments made by us to vendors and other operators. In 2003, other liabilities decreased as a result of payments made by us in satisfaction of liabilities assumed in connection with our acquisition of EEX.

Capital Expenditures. Our 2004 capital spending was $1,796 million, nearly three times our 2003 capital spending of $647 million. This included $719 million allocated for financial accounting purposes to the oil and gas properties acquired in our $575 million purchase of Inland. This also included approximately $225 million for acquisitions in Oklahoma and the Gulf of Mexico. During 2004, we also invested $570 million in domestic development, $191 million in domestic exploration, $38 million in other domestic leasehold activity and $102 million internationally. The international capital spending included $49 million related to the acquisition of our Malaysian PSCs.

Capital spending in 2003 was $647 million, a decrease of 27% from 2002 capital spending of $888 million. In 2003, we invested $302 million in domestic development, $155 million in domestic exploration, $32 million in other domestic leasehold activity and $16 million internationally. The 2003 amount included approximately $142 million in acquisitions. 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.

We have budgeted $950 million for capital spending in 2005, excluding acquisitions. Approximately 32% of the budget is allocated to the Gulf of Mexico (including the traditional shelf, the deep shelf and deepwater), 58% to the onshore U.S. and the remainder to international projects. We anticipate that our current capital expenditure budget for 2005 will be fully funded from cash flows 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 provided by financing activities for the year ended December 31, 2004 were $643.8 million compared to $85.4 million of net cash flows used in financing activities for the same period of 2003.

During 2004, we:


	•	borrowed a net $25 million under our credit arrangements;

	•	sold 5.4 million shares of our common stock for net proceeds of approximately $277 million, or $52.85 per share; and

	•	issued $325 million of senior subordinated notes.

During 2003, we:


	•	borrowed a net $59 million under our credit arrangements;

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

	•	settled our obligation under a gas sales contract, $61.6 million of which was accounted for as debt;

	•	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 $148.5 million.

Contractual Cash Obligations

The table below summarizes our significant contractual cash obligations and commitments by maturity as of December 31, 2004.


					Less than						More than
			Total		1 Year		1-3 Years		4-5 Years		5 Years

			(In millions)
Debt:
	Bank revolving credit facility		$	120.0	$	—	$	120.0	$	—	$	—
	Money market lines of credit			—		—		—		—		—
	7.45% Senior Notes due 2007			125.0		—		125.0		—		—
	7⁵/8% Senior Notes due 2011			175.0		—		—		—		175.0
	8³/8% Senior Subordinated Notes due 2012			250.0		—		—		—		250.0
	6⁵/8% Senior Subordinated Notes due 2014			325.0		—		—		—		325.0

		Total debt		995.0		—		245.0		—		750.0

Other commitments:
	Interest payments⁽¹⁾			511.4		70.3		195.6		111.6		133.9
	Derivative liabilities, net			28.8		6.6		20.2		2.0		—
	Asset retirement obligations			217.1		22.9		52.4		41.7		100.1
	Operating leases⁽²⁾			17.3		4.9		12.3		0.1		—
	Deferred acquisition payments⁽³⁾			6.5		3.2		3.3		—		—

		Total other commitments		781.1		107.9		283.8		155.4		234.0

		Total contractual cash obligations and other commitments	$	1,776.1	$	107.9	$	528.8	$	155.4	$	984.0


(1)	Interest associated with the bank revolving credit facility was calculated using the interest rate for LIBOR based loans at December 31, 2004 of 3.63% and is included through the maturity of the credit facility.

(2)	See Note 15, “Commitments and Contingencies — Lease Commitments,” to our consolidated financial statements set forth in Item 8 in this report.

(3)	See Note 4, “Acquisitions — Oklahoma Assets,” to our consolidated financial statements.

Credit Arrangements. Please see “— Liquidity and Capital Resources — Credit Arrangements” above for a description of our bank revolving credit facility and money market lines of credit.

Senior Notes. In October 1997, we issued $125 million aggregate principal amount of our 7.45% Senior Notes due 2007. In February 2001, we issued $175 million aggregate principal amount of our 7⁵/8% Senior Notes due 2011. 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.

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.

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).

Senior Subordinated Notes. In August 2002, we issued $250 million aggregate principal amount of our 8³/8% Senior Subordinated Notes due 2012. In August 2004, we issued $325 million aggregate principal amount of our 6⁵/8% Senior Subordinated Notes due 2014. Interest on our senior subordinated 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 8³/8% notes at any time on or after August 15, 2007 and some or all of the 6⁵/8% notes at any time on or after September 1, 2009, in each case, at a redemption price stated in the applicable indenture governing the notes. We also may redeem all but not part of the 8³/8% notes prior to August 15, 2007 and all but not part of the 6⁵/8% notes prior to September 1, 2009, in each case, 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 8³/8% notes with the net cash proceeds from certain sales of our common stock at 108.375% of the principal amount plus accrued and unpaid interest to the date of redemption. Likewise, before September 1, 2009, we may redeem up to 35% of the original principal amount of the 6⁵/8% notes with similar net cash proceeds at 106.625% 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.

Commitments under Joint Operating Agreements. The oil and gas industry operates in many instances through joint ventures under joint operating or similar 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.

Malaysian PSC Commitments. Under the terms of our Malaysian PSC’s, we have committed to spend $8.4 during the next five years on shallow water block PM 318 and $22.1 million during the next seven years on deepwater Block 2C. The consideration for our interest in PM 318 also includes our agreement to pay $10.5 million in the future as reimbursement for sunk costs.

Employee Benefit Plan Obligations. In 2004, we contributed $0.2 million to our funded pension plan and $0.2 million to our unfunded post-retirement medical plan. In 2005, we anticipate making a contribution of $0.2 million to our unfunded post-retirement medical plan and a minimal contribution to our funded pension plan. Contributions to our funded plan increase the plan assets while contributions to our unfunded plan are made to fund current period benefit payments. Future contributions to our funded pension plan will be affected by actuarial assumptions, market performance and individual year funding decisions. See Note 13, “Pension Plan Obligation” and Note 14, “Employee Benefit Plans — Post-Retirement Medical Plan,” to our consolidated financial statements.

Oil and Gas Hedging

We generally hedge a substantial, but varying, portion of our anticipated future oil and natural gas production for the next 12-24 months as part of our risk management program. In the case of acquisitions, we may hedge acquired production for a longer period. 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. 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 72% of our 2004 production was subject to hedge positions (including both contracts that qualify and do not qualify for hedge accounting under SFAS No. 133). In 2003, 75% of our production was subject to hedge positions, compared to 84% in 2002.

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 had a high positive correlation to the settlement price. Because substantially all of our oil production is sold at current market prices that historically have had a high positive correlation to the NYMEX West Texas Intermediate (WTI) price, we believe that we have no material basis risk with respect to these transactions. The price we receive for our Gulf Coast production typically averages about $2 per barrel below the WTI price. The price we receive for our production in the Rocky Mountains averages about $3 per barrel below the WTI price. Oil production from the Mid-Continent typically sells at a $1.00 – $1.50 per barrel discount to WTI. Oil production from Malaysia typically sells at Tapis, or about even with WTI.

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, 2004, Bank of Montreal, JPMorgan Chase, Barclays Bank PLC and J Aron & Company were the counterparties with respect to 78% of our future hedged production. Such contracts are accounted for as derivatives in accordance with SFAS No. 133.

In 2003, we began to utilize three-way collar derivative contracts as part of our risk management program. 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 contracts as of December 31, 2004 and the fair value of those contracts as of that date.

Between January 1, 2005 and March 1, 2005, we entered into the additional natural gas price hedging contracts set forth in the table below.


				NYMEX Contract Price Per MMBtu

				Collars

				Floors				Ceilings

Period and		Volume in				Weighted				Weighted
Type of Contract		MMMBtus		Range		Average		Range		Average

April 2005 – June 2005
	Collar contracts		11,250	$	6.24	$	5.85		$7.00 - $8.90	$	7.69
July 2005 – September 2005
	Collar contracts		10,800		6.24		5.84		7.00 - 8.90		7.65
October 2005 – December 2005
	Collar contracts		5,350		6.24		5.83		7.00 - 10.00		8.33
January 2006 – December 2006
	Collar contracts		2,400		5.80		5.80		10.00		10.00

Between January 1, 2005 and March 1, 2005, we entered into the additional oil price hedging contracts with respect to our Gulf Coast oil production set forth in the table below.


				NYMEX Contract Price Per Bbl

				Collars

				Floors				Ceilings				Floor Contracts

Period and		Volume in				Weighted				Weighted				Weighted
Type of Contract		Bbls		Range		Average		Range		Average		Range		Average

January 2005 – March 2005
	Collar contracts		60,000	$	41.00	$	41.00	$	64.00	$	64.00		—		—
	Floor contracts		120,000		—		—		—		—	$	41.00	$	41.00
April 2005 – June 2005
	Collar contracts		360,000		41.00		41.00		64.00		64.00		—		—
July 2005 – September 2005
	Collar contracts		360,000		41.00		41.00		64.00		64.00		—		—
October 2005 – December 2005
	Collar contracts		360,000		41.00		41.00		64.00		64.00		—		—

Between January 1, 2005 and March 1, 2005, we also 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.


				NYMEX Contract Price Per MMBtu

								Collars

				Additional Put				Floors				Ceilings

Period and		Volume in				Weighted				Weighted				Weighted
Type of Contract		MMMBtus		Range		Average		Range		Average		Range		Average

April 2005 – June 2005
	3-Way collar contracts		6,150		$4.50 - $5.15	$	4.86		$5.50 - $6.15	$	5.86		$7.45 - $7.60	$	7.50
July 2005 – September 2005
	3-Way collar contracts		6,150		4.50 - 5.15		4.86		5.50 - 6.15		5.86		7.45 - 7.60		7.50
October 2005 – December 2005
	3-Way collar contracts		3,650		4.50 - 5.15		4.79		5.50 - 6.15		5.95		7.45 - 12.00		8.92
January 2006 – December 2006
	3-Way collar contracts		2,400		4.50 - 5.00		4.69		6.00 - 6.15		6.06		10.00 -12.00		10.75

Between January 1, 2005 and March 1, 2005, we also 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.


				NYMEX Contract Price Per Bbl

								Collars

				Additional Put				Floors				Ceilings

Period and		Volume in				Weighted				Weighted				Weighted
Type of Contract		Bbls		Range		Average		Range		Average		Range		Average

January 2005 – March 2005
	3-Way collar contracts		80,000	$	40.00	$	40.00		$45.75 - $46.00	$	45.88	$	50.00	$	50.00
April 2005 – June 2005
	3-Way collar contracts		120,000		40.00		40.00		45.75 - 46.00		45.88		50.00		50.00
July 2005 – September 2005
	3-Way collar contracts		120,000		40.00		40.00		45.75 - 46.00		45.88		50.00		50.00
October 2005 – December 2005
	3-Way collar contracts		120,000		40.00		40.00		45.75 - 46.00		45.88		50.00		50.00

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.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our 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. Some 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 we believe are 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” above 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:


	•	quantity of our 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 value of the assets and liabilities of the acquired company.


	•	*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 value of derivative positions.


	*Oil and Gas Activities*

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

Full Cost Method. We use the full cost method of accounting for our oil and gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized into cost centers (the amortization base) that are established on a country-by-country basis. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. Capitalized costs also include salaries, employee benefits, costs of consulting services and other expenses that are estimated to directly relate to our oil and gas activities. Interest costs related to unproved properties also are capitalized. Although some of these costs will ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. 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. Our financial position and results of operations would have been significantly different had we used the successful efforts method of accounting for our oil and gas activities.

Proved Oil and Gas Reserves. Our engineering estimates of proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and the full cost ceiling limitation. Proved oil and gas reserves are the estimated quantities of natural gas and crude oil reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Depreciation, Depletion and Amortization. The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward, earnings would increase due to lower depletion expense. Likewise, if reserves are revised downward, earnings would decrease due to higher depletion expense or due to a ceiling test writedown. To increase our domestic DD&A rate by $0.01 per Mcfe for the year ended December 31, 2004 would require a decrease in our estimated proved reserves at December 31, 2003 of approximately 10 Bcfe. Due to the relatively small size of our international full cost pools in the U.K. and Malaysia, any decrease in reserves associated with the respective country’s full cost pool would significantly increase the DD&A rate in that country. However, as our international operations represent less than 5% of our consolidated production for 2004, a change in our international DD&A expense would not have materially affected our consolidated results of operations.

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. However, 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 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. 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. At December 31, 2004, the ceiling with respect to our oil and gas properties in the U.S. and Malaysia exceeded the net capitalized costs of those properties by approximately $1.4 billion and $19 million, respectively. At December 31, 2004, the net capitalized costs of our properties in the U.K. were written down to the present value of the estimated future net revenues from our U.K. proved reserves plus the fair value of unevaluated properties.

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 and 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, 2004, our domestic full cost pool had approximately $745 million of costs excluded from the 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. At December 31, 2004, capital costs not subject to amortization include $341 million related to our acquisition of Inland. Due to the significant size of the Monument Butte Field, acquired in the Inland transaction, evaluation of the entire amount will require a number of years. Because the application of the full cost ceiling test at December 31, 2004 resulted in a significant excess of the cost-center ceiling over the carrying value of our domestic 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 DD&A rate would 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 their geographic location, type of production structure, water depth, reservoir depth and characteristics, market demand for equipment, currently available procedures and ongoing 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 development and 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 Principal — Adoption of SFAS No. 143” above.

Holding all other factors constant, if our estimate of future abandonment and development costs is revised upward, earnings would decrease due to higher DD&A expense. Likewise, if these estimates are revised downward, earnings would increase due to lower DD&A expense. To increase our domestic DD&A rate by $0.01 per Mcfe for the year ended December 31, 2004 would require an increase in the present value of our estimated future abandonment and development costs at December 31, 2003 of approximately $20 million.


	*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 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 are required to record the excess as an asset called goodwill. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The value allocated to the recoverable oil and gas reserves and unproved properties is subject to the cost center ceiling as described under “ — Full Cost Ceiling Limitation” above.

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. If it is overstated, such impairment would reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill. 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. However, in Note 1, “Organization and Summary of Significant Accounting Policies — Stock-Based Compensation,” to our consolidated financial statements we have provided tabular information for each of the years in the three-year period ended December 31, 2004 that compares our net income and earnings per share as reported and on a pro forma basis as if we had used the fair value method of accounting for stock-based compensation. We will be required to adopt the fair value method in 2005. 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, but varying, portion of our anticipated oil and natural gas production for the next 12-24 months. In the case of acquisitions, we may hedge acquired production for a longer period. We do not use derivative instruments for trading purposes. Except for our three-way collar contracts, 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 in which it occurs. Derivatives that do not qualify for hedge accounting (such as three-way collar contracts — see Note 6, “Commodity Derivative Instruments and Hedging Activities,” to our consolidated financial statements) 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-party quotations.

New Accounting Standards

In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (SAB 106). This pronouncement requires companies that use the full cost method of accounting for oil and gas producing activities to include an estimate of future asset retirement costs to be incurred as a result of future development activities on proved reserves in their calculation of DD&A expense. It also requires full cost companies to exclude any cash outflows associated with settling asset retirement obligations from their full cost ceiling test calculation. In addition, it requires specific disclosures regarding the impact of asset retirement obligations on oil and gas producing activities, ceiling test calculations and depreciation, depletion and amortization calculations. We will adopt the provisions of this pronouncement in the first quarter of 2005. Since our adoption of SFAS No. 143, we have included the asset retirement obligation as a reduction of our net capitalized costs in the determination of our full cost ceiling test calculation. Prospectively, we will calculate our full cost ceiling test in accordance with this pronouncement. We have calculated our DD&A expense in accordance with SAB 106 since our adoption of SFAS No. 143. Consequently, the adoption of SAB 106 will have no immediate effect on our financial statements.

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment”. SFAS No. 123(R) requires an entity to recognize the grant-date fair value of stock options and other equity-based compensation issued to employees in the income statement. We will adopt the provisions of this pronouncement in the third quarter of 2005. We have not completed our evaluation of the impact of SFAS No. 123(R) on our financial statements.

Regulation

We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration and development and the production and sale of oil and gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:


	•	discharge permits for drilling operations;

	•	drilling bonds;

	•	reports concerning operations;

	•	the spacing of wells;

	•	unitization and pooling of properties; and

	•	taxation.

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

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, some 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 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. The MMS has asked for comments on whether it should implement regulations under its OCSLA authority on gatherers and other entities to ensure open and non-discriminatory access on gathering systems and production facilities on the shelf. We have no way of knowing whether the MMS will proceed with implementing regulations of this nature; however we do not believe that any FERC or MMS action taken under OCSLA will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers with which we compete.

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

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

Federal Leases. The majority of our U.S. operations are located on federal oil and gas leases, which are administered by the MMS. These leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to OCSLA (which are subject to change by the MMS). For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the Shelf to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the

MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. To cover the various obligations of lessees on the Shelf, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that bonds or other surety can be obtained in all cases. We are currently exempt from the supplemental bonding requirements of the MMS. Under certain circumstances, the MMS may require that our operations on federal leases be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition, cash flows and results of operations. 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 May 5, 2004, the MMS issued a final rule that changed certain components of its valuation procedures for the calculation of royalties owed for crude oil sales. The 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. We believe that the 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 imposition of remedial obligations, or the issuance 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, or OPA, imposes regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from spills in U.S. waters. A “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns strict, joint and several liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation, or if the party fails to report a spill or to cooperate fully in the cleanup. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages for offshore facilities and up to $350 million for onshore facilities. Few defenses exist to the liability imposed by OPA. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party to administrative, civil or criminal enforcement actions.

OPA also requires operators in the Gulf of Mexico to demonstrate to the MMS that they possess available financial resources that are sufficient to pay for certain costs that may be incurred in responding

to an oil spill. Under OPA and implementing 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.

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. The 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 the CWA, including discharge limits on permits issued pursuant to the CWA, may also result in administrative, civil or criminal enforcement actions. The 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 amending these plans or, as necessary, developing new SPCC plans that will satisfy new SPCC plan certification and implementation requirements that become effective in February 2006 and August 2006, 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,” the U.S. Environmental Protection Agency, also known as the “EPA” and state agencies may regulate these wastes as solid wastes. 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. Such “responsible persons” may be subject to joint and several liability under the Superfund law for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own or lease onshore properties that have been used for the exploration and production of oil and gas for a number of years. Many of these onshore properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and any wastes that may have been disposed or released on them may be subject to the Superfund law, RCRA and analogous state laws, and we potentially could be required to investigate and remediate such properties, 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 and we believe that we are in substantial compliance with any such foreign requirements. 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 lower 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 also may 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 unable to find and develop or acquire additional reserves at an acceptable cost. In addition, substantial capital is required to replace and grow reserves. If lower oil and gas prices or operating difficulties result in our cash flow from operations being less than expected or limit our ability to borrow under our credit arrangements, we may be unable to expend the capital necessary to locate and develop or acquire new oil and gas reserves.

Actual quantities of recoverable oil and gas reserves and future cash flows from those reserves most likely will vary from our estimates. Estimating accumulations of oil and gas is complex. The process relies on interpretations of available geologic, geophysic, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:


	•	the quality and quantity of available data;

	•	the interpretation of that data;

	•	the accuracy of various mandated economic assumptions; and

	•	the judgment of the persons preparing the estimate.

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

Actual quantities of recoverable oil and gas reserves, future production, oil and gas prices, revenues, taxes, development expenditures and operating expenses most likely will vary from our estimates. Any significant variance could materially affect the quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development and prevailing oil and gas prices. Our reserves also may 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 base the estimated discounted future net cash flows from proved reserves on prices and costs in effect at December 31. Actual future prices and costs may be materially higher or lower than the prices and costs we used.

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 decrease or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of operating or 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 recorded, a writedown of oil and gas properties is not reversible at a later date even if oil or gas prices increase.

We may be subject to risks in connection with acquisitions. The successful acquisition of producing properties requires an assessment of several factors, including:


	•	recoverable reserves;

	•	future oil and gas prices;

	•	operating costs; and

	•	potential environmental and other liabilities.

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

We may not achieve the production growth we anticipated from our properties in the Uinta Basin. In August 2004, we acquired Inland for approximately $575 million in cash. Inland’s primary asset is the 110,000-acre Monument Butte Field located in the Uinta Basin of Northeast Utah. Waterflooding, a secondary recovery operation that involves the injection of large volumes of water into the oil-producing reservoir, is necessary to recover the oil reserves in the field. We must negotiate with third parties to obtain additional sources of water. The crude oil produced in the Uinta Basin is known as “black wax” and has a higher paraffin content than crude oil found in most other major North American basins. Currently, area refineries have limited capacity to refine this type of crude oil. Our ability to significantly

increase production from the field may be limited by the unavailability of sufficient water supplies or refining capacity or both. In addition, the performance of waterflood operations is often difficult to predict.

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 programs. 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;

	•	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 or reductions in revenue that could reduce or eliminate the funds available for our exploration and development programs and acquisitions, or result in the 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.

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


	•	the timing and amount of capital expenditures;

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

	•	the operator’s expertise and financial resources;

	•	approval of other participants in drilling wells; and

	•	selection of technology.

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 also may 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.

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, product targets, anticipated production rates, our financing plans and our 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;

	•	well and waterflood performance;

	•	severe weather conditions (such as hurricanes);

	•	the prices of goods and services;

	•	the availability of drilling rigs and other support services;

	•	the availability of capital resources; and

	•	the 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.

Carried interest. An arrangement under which an interest in oil and gas rights is assigned in consideration for the assignee advancing all or a portion of the funds to explore on, develop or operate an oil or gas property.

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

Deep shelf. We consider the deep shelf to be structures located on the shelf at depths generally greater than 15,000 feet in areas where there has been limited or no production from deeper stratigraphic zones.

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

Developed acreage. The number of acres that are allocated or assignable to producing wells or wells capable of production.

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

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

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

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

FERC. The Federal Energy Regulatory Commission.

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

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

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.

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.


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 12-24 months as part of our risk management program. In the case of acquisitions, we may hedge acquired production for a longer period. 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. 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, 2004, our long-term debt was comprised of:


	Fixed		Variable
	Rate Debt		Rate Debt

	(In millions)
Bank revolving credit facility(1)	$	—	$	120
7.45% Senior Notes due 2007(2)		75		50
7⁵/8% Senior Notes due 2011(2)		125		50
8³/8% Senior Subordinated Notes due 2012		250		—
6⁵/8% Senior Subordinated Notes due 2014		325		—

	$	775	$	220


(1)	The interest rate at December 31, 2004 for our LIBOR based loans under our credit facility was 3.63%.

(2)	As of December 31, 2004, $50 million principal amount of our 7.45% Senior Notes due 2007 and $50 million principal amount of our 7⁵/8% Senior Notes due 2011 were subject to interest rate swaps. These swaps 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.

We considered our interest rate exposure at year-end 2004 to be minimal because about 78% 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 $0.7 million.

Foreign Currency Exchange Rates

Our operations in the U.K. and Malaysia use the British pound and the Malaysian ringgit, respectively, as their functional currency. The functional currency for all other foreign operations is the U.S. dollar. To the extent that business transactions in these countries are not denominated in the respective country’s functional currency, we are exposed to foreign currency exchange risk. 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, 2004.


Item 8.	*Financial Statements and Supplementary Data*

NEWFIELD EXPLORATION COMPANY

INDEX

CONSOLIDATED FINANCIAL STATEMENTS

AND SUPPLEMENTARY DATA


	Page

Management’s Report on Internal Control over Financial Reporting		47
Report of Independent Registered Public Accounting Firm		48
Consolidated Balance Sheets as of December 31, 2004 and 2003		50
Consolidated Statements of Income for each of the three years in the period ended December 31, 2004		51
Consolidated Statements of Stockholders’ Equity for each of the three years in the period ended December 31, 2004		52
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2004		53
Notes to Consolidated Financial Statements		54
Unaudited Supplementary Oil and Gas Disclosures		92

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our company’s management, including the Chief Executive Officer and the Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Based on our evaluation under the framework in Internal Control — Integrated Framework, the management of our company concluded that our internal control over financial reporting was effective as of December 31, 2004. We excluded the Rocky Mountains Division from our assessment of internal control over financial reporting as of December 31, 2004 because the division was formed with the acquisition of Inland in a purchase business combination on August 27, 2004. The total assets and total revenues of our Rocky Mountains Division represent 18% and 3%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2004.

The assessment by the management of our company of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report that follows.


David A. Trice President and Chief Executive Officer		Terry W. Rathert Vice President and Chief Financial Officer

Houston, Texas
March 9, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have completed an integrated audit of Newfield Exploration Company’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheets 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 (the Company) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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 discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003 in conjunction with the Company’s adoption of SFAS No. 143, Accounting for Asset Retirement Obligations. 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 pursuant to Derivative Implementation Group Issue G20, Cash Flow Hedges: Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash Flow Hedge.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded the Company’s Rocky Mountains Division from its assessment of internal control over financial reporting as of December 31, 2004 because the division was formed with the acquisition of Inland Resources Inc. in a purchase business combination during 2004. The total assets and total revenues of the Rocky Mountains Division represent 18% and 3%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2004.

Houston, Texas
March 9, 2005

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEET

(In millions, except share data)


			December 31,

			2004			2003

ASSETS
Current assets:
	Cash and cash equivalents		$	58.3		$	15.3
	Accounts receivable			247.7			134.8
	Inventories			7.8			0.5
	Derivative assets			54.5			13.8
	Deferred taxes			1.0			12.9
	Other current assets			22.3			61.6

		Total current assets		391.6			238.9

Oil and gas properties (full cost method, of which $835.4 and $331.1 were excluded from amortization at December 31, 2004 and December 31, 2003, respectively)				5,907.8			4,078.1
Less – accumulated depreciation, depletion and amortization				(2,132.5	)		(1,659.6	)

				3,775.3			2,418.5

Floating production system and pipelines				—			35.0
Furniture, fixtures and equipment, net				18.3			5.9
Derivative assets				55.6			2.2
Other assets				21.4			16.2
Goodwill				65.3			16.4

		Total assets	$	4,327.5		$	2,733.1

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	32.5		$	30.6
	Accrued liabilities			353.5			204.0
	Advances from joint owners			18.0			5.9
	Secured notes payable			—			2.9
	Asset retirement obligation			22.9			12.1
	Current portion of deferred taxes			0.1			—
	Derivative liabilities			47.0			44.7

		Total current liabilities		474.0			300.2

Other liabilities				15.8			13.2
Derivative liabilities				83.1			13.2
Long-term debt				992.4			643.5
Asset retirement obligation				194.2			151.6
Deferred taxes				551.1			242.8

		Total long-term liabilities		1,836.6			1,064.3

Commitments and contingencies				—			—
Stockholders’ equity:
	Preferred stock ($0.01 par value, 5,000,000 shares authorized; no shares issued)			—			—
	Common stock ($0.01 par value, 200,000,000 and 100,000,000 shares authorized at December 31, 2004 and December 31, 2003, respectively; 63,316,848 and 57,141,807 shares issued and outstanding at December 31, 2004 and December 31, 2003, respectively)			0.6			0.5
Additional paid-in capital				1,102.5			796.2
Treasury stock (at cost, 897,977 and 886,247 shares at December 31, 2004 and December 31, 2003, respectively)				(27.3	)		(26.7	)
Unearned compensation				(9.5	)		(10.9	)
Accumulated other comprehensive income (loss):
	Foreign currency translation adjustment			2.6			0.9
	Commodity derivatives			0.1			(26.4	)
	Minimum pension liability			—			(0.8	)
Retained earnings				947.9			635.8

		Total stockholders’ equity		2,016.9			1,368.6

		Total liabilities and stockholders’ equity	$	4,327.5		$	2,733.1

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF INCOME

(In millions, except per share data)


			Year Ended December 31,

			2004			2003			2002

Oil and gas revenues			$	1,352.7		$	1,017.0		$	626.8

Operating expenses:
	Lease operating			145.7			119.3			90.8
	Production and other taxes			42.3			31.7			13.3
	Transportation			6.3			6.4			5.7
	Depreciation, depletion and amortization			471.4			394.7			295.1
	Ceiling test writedown			17.0			—			—
	General and administrative			84.0			61.6			54.4
	Impairment of floating production system and pipelines			35.0			—			—
	Gas sales obligation settlement and redemption of securities			—			20.5			—

		Total operating expenses		801.7			634.2			459.3

Income from operations				551.0			382.8			167.5
Other income (expenses):
	Interest expense			(57.7	)		(57.8	)		(34.5	)
	Capitalized interest			25.8			15.9			8.8
	Dividends on convertible preferred securities of Newfield Financial Trust I			—			(4.6	)		(9.3	)
	Commodity derivative expense			(23.8	)		(6.1	)		(29.1	)
	Other			3.6			1.4			4.5

				(52.1	)		(51.2	)		(59.6	)

Income from continuing operations before income taxes				498.9			331.6			107.9
Income tax provision:
	Current			61.1			21.6			37.5
	Deferred			125.7			99.1			1.7

				186.8			120.7			39.2

Income from continuing operations				312.1			210.9			68.7
Income (loss) from discontinued operations, net of tax				—			(17.0	)		5.1

Income before cumulative effect of change in accounting principle				312.1			193.9			73.8
Cumulative effect of change in accounting principle, net of tax:
	Adoption of SFAS No. 143			—			5.6			—

		Net income	$	312.1		$	199.5		$	73.8

Earnings per share:
Basic —
	Income from continuing operations		$	5.35		$	3.88		$	1.52
	Income (loss) from discontinued operations			—			(0.31	)		0.12
	Cumulative effect of change in accounting principle, net of tax			—			0.10			—

		Net income	$	5.35		$	3.67		$	1.64

Diluted —
	Income from continuing operations		$	5.26		$	3.77		$	1.51
	Income (loss) from discontinued operations			—			(0.30	)		0.10
	Cumulative effect of change in accounting principle, net of tax			—			0.10			—

		Net income	$	5.26		$	3.57		$	1.61

Weighted average number of shares outstanding for basic earnings per share				58.3			54.3			45.1

Weighted average number of shares outstanding for diluted earnings per share				59.3			56.7			49.6

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)


																				Accumulated
			Common Stock				Treasury Stock						Additional							Other			Total
													Paid-In		Unearned			Retained		Comprehensive			Stockholders’
			Shares		Amount		Shares			Amount			Capital		Compensation			Earnings		Income (Loss)			Equity

Balance, December 31, 2001				45.0	$	0.5		(0.9	)	$	(25.8	)	$	364.7	$	(7.8	)	$	362.5	$	16.0		$	710.1
Issuance of common stock				7.6		—								267.7										267.7
Issuance of restricted stock, less amortization and cancellations				—		—								1.4		(1.1	)							0.3
Treasury stock, at cost								—			(0.4	)												(0.4	)
Amortization of stock compensation																2.5								2.5
Tax benefit from exercise of stock options														2.5										2.5
Comprehensive income:
	Net income																		73.8					73.8
	Foreign currency translation adjustment, net of tax of ($2.7)																				5.0			5.0
	Reclassification adjustments for settled hedging positions, net of tax of $8.4																				(15.6	)		(15.6	)
	Changes in fair value of outstanding hedging positions, net of tax of $19.7																				(36.6	)		(36.6	)

		Total comprehensive income																						26.6

Balance, December 31, 2002				52.6		0.5		(0.9	)		(26.2	)		636.3		(6.4	)		436.3		(31.2	)		1,009.3
Issuance of common stock				4.3		—								147.5										147.5
Issuance of restricted stock, less amortization of $1.0 and cancellations				0.2		—								7.5		(6.5	)							1.0
Treasury stock, at cost								—			(0.5	)												(0.5	)
Amortization of stock compensation																2.0								2.0
Tax benefit from exercise of stock options														4.9										4.9
Comprehensive income:
	Net income																		199.5					199.5
	Foreign currency translation adjustment, net of tax of ($2.6)																				4.8			4.8
	Reclassification adjustments for settled hedging positions, net of tax of $25.9																				(48.1	)		(48.1	)
	Changes in fair value of outstanding hedging positions, net of tax of ($26.4)																				49.0			49.0
	Minimum pension liability, net of tax of $0.4																				(0.8	)		(0.8	)

		Total comprehensive income																						204.4

Balance, December 31, 2003				57.1		0.5		(0.9	)		(26.7	)		796.2		(10.9	)		635.8		(26.3	)		1,368.6
Issuance of common stock				6.1		0.1								297.2										297.3
Issuance of restricted stock, less amortization and cancellations				0.1		—								2.7		(2.4	)							0.3
Treasury stock, at cost								—			(0.6	)												(0.6	)
Amortization of stock compensation																3.8								3.8
Tax benefit from exercise of stock options														6.4										6.4
Comprehensive income:
	Net income																		312.1					312.1
	Foreign currency translation adjustment, net of tax of ($0.9)																				1.7			1.7
	Reclassification adjustments for settled hedging positions, net of tax of $30.6																				(56.8	)		(56.8	)
	Changes in fair value of outstanding hedging positions, net of tax of ($44.9)																				83.3			83.3
	Minimum pension liability, net of tax of ($0.4)																				0.8			0.8

		Total comprehensive income																						341.1

Balance, December 31, 2004				63.3	$	0.6		(0.9	)	$	(27.3	)	$	1,102.5	$	(9.5	)	$	947.9	$	2.7		$	2,016.9

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)


					Year Ended December 31,

					2004			2003			2002

Cash flows from operating activities:
	Net income				$	312.1		$	199.5		$	73.8
Adjustments to reconcile net income to net cash provided by continuing operating activities:
	(Income) loss from discontinued operations, net of tax					—			17.0			(5.1	)
	Depreciation, depletion and amortization					471.4			394.7			295.1
	Deferred taxes					125.7			99.1			1.8
	Stock compensation					4.1			3.0			2.8
	Commodity derivative (income) expense					(0.4	)		6.1			29.1
	Impairment of floating production system and pipelines					35.0			—			—
	Gas sales obligation settlement and redemption of securities					—			20.5			—
	Ceiling test writedown					17.0			—			—
	Cumulative effect of change in accounting principle					—			(5.6	)		—
	Changes in operating assets and liabilities:
		Increase in accounts receivable				(100.1	)		(4.4	)		(12.8	)
		(Increase) decrease in inventories				(4.7	)		0.7			0.2
		(Increase) decrease in other current assets				58.6			(34.1	)		(8.5	)
		(Increase) decrease in other assets				(3.4	)		4.3			(9.5	)
		Increase (decrease) in accounts payable and accrued liabilities				80.0			(22.8	)		13.3
		Decrease in commodity derivative liabilities				(10.5	)		(14.2	)		—
		Increase in advances from joint owners				12.1			2.3			3.6
		Increase (decrease) in other liabilities				0.6			(6.9	)		(0.5	)

			Net cash provided by continuing activities			997.5			659.2			383.3
			Net cash provided by discontinued activities			—			10.3			20.2

				Net cash provided by operating activities		997.5			669.5			403.5

Cash flows from investing activities:
	Purchase of business, net of cash acquired of $2.0, $0.8 and $17.8 for 2004, 2003 and 2002, respectively					(755.7	)		(90.2	)		(204.4	)
	Proceeds from sale of business					—			9.7			—
	Proceeds from sale of oil and gas properties					16.7			—			—
	Additions to oil and gas properties					(853.0	)		(530.9	)		(295.0	)
	Additions to furniture, fixtures and equipment					(6.8	)		(3.3	)		(2.4	)

			Net cash used in continuing activities			(1,598.8	)		(614.7	)		(501.8	)
			Net cash used in discontinued activities			—			(3.1	)		(16.3	)

				Net cash used in investing activities		(1,598.8	)		(617.8	)		(518.1	)

Cash flows from financing activities:
	Proceeds from borrowings under credit arrangements					1,254.0			1,569.0			654.7
	Repayments of borrowings under credit arrangements					(1,229.0	)		(1,510.0	)		(747.7	)
	Proceeds from issuance of common stock					297.3			149.3			7.8
	Purchases of treasury stock					(0.6	)		(0.5	)		(0.4	)
	Proceeds from issuance of senior subordinated notes					325.0			—			247.9
	Repayments of secured notes					—			(11.2	)		—
	Repurchases of secured notes					(2.9	)		(63.1	)		(23.6	)
	Gas sales obligation settlement					—			(62.0	)		—
	Deliveries under the gas sales obligation					—			(8.4	)		(1.7	)
	Redemption of trust preferred securities					—			(148.5	)		—

			Net cash provided by (used in) continuing activities			643.8			(85.4	)		137.0
			Net cash provided by (used in) discontinued activities			—			—			—

				Net cash provided by (used in) financing activities		643.8			(85.4	)		137.0

Effect of exchange rate changes on cash and cash equivalents						0.5			0.1			(0.1	)

Increase (decrease) in cash and cash equivalents						43.0			(33.6	)		22.3
Cash and cash equivalents from continuing operations, beginning of period						15.3			33.8			8.7
Cash and cash equivalents from discontinued operations, beginning of period						—			15.1			17.9

Cash and cash equivalents, end of period					$	58.3		$	15.3		$	48.9

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

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies:


	*Organization and Principles of Consolidation*

Our financial statements include the accounts of Newfield Exploration Company, a Delaware corporation, and its subsidiaries. We proportionately consolidate our interests in oil and gas exploration and production ventures and partnerships in accordance with industry practice. 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 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 our Australian operations are reflected in our consolidated 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 on prevailing prices for natural gas and oil. 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 or gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and gas reserves that we may economically produce.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America 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 our proved oil and gas reserves.

Reclassifications

Certain reclassifications have been made to prior years’ 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 financial condition, results of operations or cash flows.

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.

Allowance for Doubtful Accounts

We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. Many of our receivables are from joint interest owners on properties of which we are the operator. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, our natural gas and crude oil receivables are collected within 45-60 days of production.

We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. As of December 31, 2004 and 2003, our allowance for doubtful accounts was immaterial.

Inventories

Inventories include oil produced but not sold. Crude oil from our operations located offshore Malaysia is produced into a floating production, storage and off-loading vessel and sold periodically as a barge quantity is accumulated. The product inventory at December 31, 2004 consisted of approximately 49,000 barrels of crude oil valued at $0.8 million and is carried at the lower of average cost or market. There was no product inventory at December 31, 2003. Also included in inventories are materials and supplies, which also are stated at the lower of average cost or market.

Foreign Currency

The functional currency for the United Kingdom is the British pound and the functional currency for Malaysia is the Malaysian ringgit. The functional currency for all other foreign operations is the U.S. dollar. Translation adjustments resulting from translating our United Kingdom subsidiaries’ British pound financial statements and our Malaysian subsidiaries’ Malaysian ringgit financial statements into U.S. dollars are included as other comprehensive income on our consolidated balance sheet and 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 materially different from their book value. Cash equivalents include highly liquid investments with a maturity of three months or less when acquired. We invested cash in excess of current capital and 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 $31.7 million, $26.7 million and $7.0 million of internal costs in 2004, 2003 and 2002, respectively. Interest expense related to unproved properties also is capitalized to oil and gas properties.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Capitalized costs and estimated future development and retirement costs are amortized on a unit-of-production method based on proved reserves associated with the applicable cost center. 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. A particular cost center ceiling is equal to 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.

Proceeds from the sale of oil and gas properties are applied to reduce the costs in the applicable 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.

In November 2004, we announced that our Cumbria Prospect in the North Sea was a dry hole. Because the unamortized costs of our U.K. cost pool exceeded the full cost ceiling, we were required to recognize a ceiling test writedown of $17.0 million in 2004.

Furniture, Fixtures and Equipment

Furniture, fixtures and equipment are recorded at cost and are depreciated over their estimated useful lives, which range from three to seven years, using the straight-line method. At December 31, 2004 and 2003, furniture, fixtures and equipment of $32.8 million and $16.1 million, respectively, are net of accumulated depreciation of $14.5 million and $10.2 million, respectively.

Accounting for Asset Retirement Obligations

We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” as of January 1, 2003. This statement changed 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 liabilities 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 are equal to the estimated future cost to satisfy the abandonment obligation using current prices that have been escalated by an assumed inflation factor up to the estimated settlement date, and then discounted 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 is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are 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.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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


Balance at January 1, 2003		$	128.5
	Accretion expense		7.5
	Additions		31.8
	Settlements		(4.1	)

Balance at December 31, 2003			163.7
	Accretion expense		11.1
	Additions		48.5
	Settlements		(6.2	)

Balance of ARO at December 31, 2004		$	217.1

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


Net income:
	As reported		$	73.8
	Pro forma			72.8
Earnings per share:
	Basic —
		As reported	$	1.64
		Pro forma		1.61
	Diluted —
		As reported	$	1.61
		Pro forma		1.59

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in our Inland Resources and Primary Natural Resources acquisitions. See Note 4, “Acquisitions — Inland Resources Inc. and — Primary Natural Resources.”

We adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” effective January 1, 2002. Under SFAS No. 142, we assess the carrying amount of goodwill by testing the goodwill for impairment. The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. We have deemed each country to be the goodwill reporting unit. 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 writedown is charged to earnings. Goodwill is tested for impairment on an annual basis on December 31, 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.

The fair value of the 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 goodwill in future periods.

We determined that no goodwill impairment existed as of December 31, 2004 or 2003.

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 our financial statements.

A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

Stock-Based Compensation

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

If the fair value based method of accounting under SFAS No. 123, “Accounting for Stock-Based Compensation,” had been applied using a Black-Scholes option pricing model, our net income and

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

earnings per common share for 2004, 2003 and 2002 would have approximated the pro forma amounts below:


		Year Ended December 31,

		2004		2003		2002

		(In millions, except per share
		data)
Net income:
	As reported⁽¹⁾	$	312.1	$	199.5	$	73.8
	Pro forma⁽²⁾		304.6		193.2		68.6
Basic earnings per common share —
	As reported	$	5.35	$	3.67	$	1.64
	Pro forma		5.22		3.56		1.52
Diluted earnings per common share —
	As reported	$	5.26	$	3.57	$	1.61
	Pro forma		5.14		3.46		1.51


	(1)	Includes stock-based compensation costs, net of related tax effects, of $2.7 million, $2.0 million and $1.8 million for the years ended December 31, 2004, 2003 and 2002, respectively.

	(2)	Includes stock-based compensation costs, net of related tax effects, that would have been included in the determination of net income had the fair value based method been applied of $10.2 million, $8.3 million and $7.0 million for the years ended December 31, 2004, 2003 and 2002, respectively.

In December 2004, the FASB issued SFAS No. 123(revised 2004), “Share – Based Payment.” SFAS No. 123(R) is a revision of SFAS No. 123, “Accounting for Stock Based Compensation,” and supercedes ABP 25. Among other items, SFAS No. 123(R) eliminates the use of APB 25 and the intrinsic value method of accounting and requires companies to recognize the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards in their financial statements. The effective date of SFAS No. 123(R) is the first reporting period beginning after June 15, 2005, although early adoption is permitted. SFAS No. 123(R) permits companies to adopt its requirements using either a “modified prospective” method, a “variation of the modified prospective” method or a “modified retrospective” method. Under the “modified prospective” method, compensation cost is recognized in the financial statements beginning with the effective date, based on the requirements of SFAS No. 123(R) for all share-based payments granted after that date, and based on the requirements of SFAS No. 123 for all unvested awards granted prior to the effective date of SFAS No. 123(R). Under the “variation of the modified prospective” method, the requirements are the same as under the “modified prospective” method except that earlier interim periods in the year of adoption are restated. Under the “modified retrospective” method, the requirements are the same as under the “modified prospective” method except that financial statements of previous periods are restated based on pro forma disclosures made in accordance with SFAS No. 123.

We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted. SFAS No. 123(R) permits the continued use of this model as well as other standard option pricing models. We have not yet determined which model we will use to measure the fair value of employee stock options upon the adoption of SFAS No. 123(R).

SFAS No. 123(R) also requires that the benefits associated with tax deductions in excess of recognized compensation cost be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce reported net operating cash flows and

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

increase reported net financing cash flows in periods after the effective date. These future amounts cannot be estimated because they depend on, among other things, when employees exercise stock options.

We currently expect to adopt SFAS No. 123(R) effective as of July 1, 2005; however, we have not yet determined which of the aforementioned adoption methods we will use.

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.

The purchasers of our oil and gas production 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 or parental guarantees from selected purchasers. Historically, we have sold a substantial portion of our oil and gas production to several purchasers (see “— Major Customers” below). 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, 2004, Bank of Montreal, JPMorgan Chase Bank, Barclays Bank PLC and J Aron & Company were the counterparties with respect to 78% of our future hedged production.

Major Customers

We sold oil and gas production representing more than 10% of our consolidated revenues before the effects of hedging for the year ended December 31, 2004 to Superior Natural Gas Corporation (20%), Louis Dreyfus Energy Services (15%) and ConocoPhillips Inc. (14%); for the year ended December 31, 2003 to Superior Natural Gas Corporation (29%) and ConocoPhillips Inc. (25%); and for the year ended December 31, 2002 to Superior Natural Gas Corporation (25%) and ConocoPhillips Inc. (23%). Because alternative purchasers of oil and gas are readily available in most geographic areas, we believe that the loss of any 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.”

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, under the caption “Accumulated other comprehensive income (loss) — Commodity derivatives” on our consolidated balance sheet. Gains or losses on these collar and

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

floor contracts are reclassified out of “Accumulated other comprehensive income (loss) — Commodity derivatives” and into earnings when the forecasted sale of production occurs.

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 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 expense.”

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

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.

New Accounting Standards

In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (SAB 106). This pronouncement requires companies that use the full cost method of accounting for oil and gas producing activities to include an estimate of future asset retirement costs to be incurred as a result of future development activities on proved reserves in their calculation of depreciation, depletion and amortization. It also requires full cost companies to exclude any cash outflows associated with settling asset retirement obligations from their full cost ceiling test calculation. In addition, it requires specific disclosures regarding the impact of asset retirement obligations on oil and gas producing activities, ceiling test calculations and depreciation, depletion and amortization calculations. We will adopt the provisions of this pronouncement in the first quarter of 2005. Since our adoption of SFAS No. 143, we have included the asset retirement obligation as a reduction of our net capitalized costs in the determination of our full cost ceiling test calculation. Prospectively, we will calculate our full cost ceiling test in accordance with this pronouncement. We have calculated our depreciation, depletion and amortization expense in accordance with SAB 106 since our adoption of SFAS No. 143. Consequently, the adoption of SAB 106 will have no immediate effect on our consolidated financial statements.

In December 2004, the FASB issued SFAS No. 123(R). See “— Stock-Based Compensation” above.

In December 2004, the FASB issued FASB Staff Position FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004.” This position clarifies how to apply SFAS No. 109 to the new law’s tax deduction for income attributable to “domestic production activities.” We are currently evaluating the impact of the new law.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2. Discontinued Operations:

In September 2003, we sold our wholly owned subsidiary, Newfield Exploration Australia Ltd., the holding company for all of our Australian assets. The historical results of our Australian operations are reflected in our consolidated financial statements as “discontinued operations” and are summarized as follows:


	For the Year Ended
	December 31,

	2003			2002

	(In millions)
Revenues	$	15.5		$	34.9
Operating expenses⁽¹⁾		(21.9	)		(29.1	)

Income (loss) from operations		(6.4	)		5.8
Other expense⁽²⁾		(3.5	)		(2.9	)

Income (loss) before income taxes		(9.9	)		2.9
Income tax benefit		2.8			2.2

Income (loss) from operations		(7.1	)		5.1
Loss on sale		(9.9	)		—

Income (loss) from discontinued operations	$	(17.0	)	$	5.1


	(1)	Operating expenses for the year ended December 31, 2003 include a ceiling test writedown of $7.3 million and a production tax credit due to a change in the estimate of Australian resource rent taxes recorded in the second quarter of 2003.

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

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 (other than unvested restricted stock) outstanding during the period (the denominator). Diluted earnings per share incorporates the dilutive impact of outstanding stock options (using the treasury stock method), unvested restricted stock and 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 any accrued distributions with respect to our trust preferred securities accrued during any of the periods presented. We redeemed all of our outstanding trust preferred securities in June 2003. See Note 9, “Redemption of Trust Preferred Securities” and Note 12, “Stock-Based Compensation — Stock Options.”

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, 2004:


				2004		2003			2002

				(In millions, except per share data)
Income (numerator):
	Income from continuing operations			$	312.1	$	210.9		$	68.7
	Income (loss) from discontinued operations, net of tax				—		(17.0	)		5.1

	Income before cumulative effect of change in accounting principle				312.1		193.9			73.8
	Cumulative effect of change in accounting principle, net of tax				—		5.6			—

	Net income — basic				312.1		199.5			73.8
	After-tax dividends on convertible trust preferred securities				—		3.0			6.1

	Net income — diluted			$	312.1	$	202.5		$	79.9

Weighted average shares (denominator):
	Weighted average shares — basic				58.3		54.3			45.1
	Dilution effect of stock options and unvested restricted stock outstanding at end of period				1.0		0.5			0.6
	Dilution effect of convertible trust preferred securities				—		1.9			3.9

	Weighted average shares — diluted				59.3		56.7			49.6

Earnings per share:
	Basic:
		Income from continuing operations		$	5.35	$	3.88		$	1.52
		Income (loss) from discontinued operations			—		(0.31	)		0.12
		Cumulative effect of change in accounting principle, net of tax			—		0.10			—

			Net income	$	5.35	$	3.67		$	1.64

	Diluted:
		Income from continuing operations		$	5.26	$	3.77		$	1.51
		Income (loss) from discontinued operations			—		(0.30	)		0.10
		Cumulative effect of change in accounting principle, net of tax			—		0.10			—

			Net income	$	5.26	$	3.57		$	1.61

The calculation of shares outstanding for diluted EPS for the years ended December 31, 2004, 2003 and 2002 does not include the effect of outstanding stock options to purchase 0.4 million, 0.7 million and 1.1 million shares, respectively, because to do so would be antidilutive.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

4. Acquisitions:

Malaysian PSCs

In May 2004, we entered into production sharing contracts, or PSCs, with Malaysia’s state-owned oil company in partnership with its exploration and production subsidiary, Petronas Carigali. The PSCs relate to two blocks – PM 318 and deepwater Block 2C.

Petronas Carigali operates PM 318, which consists of approximately 413,000 acres, located offshore Peninsular Malaysia. We have a 50% interest in the block. Through our ownership interest, we are participating in production from two recently developed shallow water fields and development of three nearby oil and gas discoveries. The consideration for our interests in PM 318 was comprised of a one-time reimbursement of sunk costs of $38.5 million, a deferred payment of $10.5 million and an exploration commitment of $8.4 million. The reimbursement of the sunk costs was financed through cash on hand and borrowings under our credit arrangements.

Our deepwater concession, Block 2C, covers 1.1 million acres offshore Sarawak and is operated by us with a 60% interest. Our exploration commitment with respect to this block is $22.1 million.

Oklahoma Assets

During the second half of 2004, we acquired producing oil and gas properties in Oklahoma in two separate transactions for total cash consideration of approximately $52 million and a deferred payment of $6.5 million. These acquisitions were financed through cash on hand and borrowings under our credit arrangements.

Denbury Offshore, Inc.

On July 20, 2004, we acquired all of the outstanding stock of Denbury Offshore, Inc., the subsidiary of Denbury Resources Inc. that held substantially all of its Gulf of Mexico assets. We accounted for the acquisition as a purchase using the accounting standards established in SFAS No. 141, “Business Combinations.” Our consolidated financial statements include Denbury Offshore’s results of operations subsequent to July 20, 2004. After purchase price adjustments, total consideration was approximately $174 million, substantially all of which was allocated to oil and gas properties. The acquisition was financed through cash on hand and borrowings under our credit arrangements.

Inland Resources Inc.

On August 27, 2004, we completed the $575 million acquisition of privately held Inland. The acquisition established a new Rocky Mountain focus area for us. Inland’s sole oil and gas property was the 110,000 acre Monument Butte Field, located in the Uinta Basin of northeast Utah. The purchase price was funded through concurrent offerings of our common stock and our 6⁵/8% Senior Subordinated Notes due 2014. See Note 8, “Debt,” and Note 10, “Common Stock Activity.”

We accounted for the acquisition as a purchase using the accounting standards established in SFAS Nos. 141 and 142. Our consolidated financial statements include Inland’s results of operations subsequent to August 27, 2004. We recorded the estimated fair value of the assets acquired and the liabilities assumed at August 27, 2004, which primarily consisted of oil and gas properties of $722.6 million, a deferred tax liability of $171.1 million, derivative liabilities of $30.6 million and goodwill of $48.9 million. We recorded the deferred tax liability to recognize the difference between the historical tax basis of Inland’s assets and the acquisition costs recorded for book purposes. Inland’s historical book value of the proved and unproved oil and gas properties was increased to estimated fair value and goodwill was recorded to recognize this tax basis differential. Goodwill is not deductible for tax purposes. See Note 1, “Organization and Summary of Significant Accounting Policies — Goodwill.”

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Pro Forma Results

The unaudited pro forma results presented below for the years ended December 31, 2004 and 2003 have been prepared to give effect to our 2004 acquisitions and the issuance of our common stock and notes (See Note 8, “Debt — Senior Subordinated Notes” and Note 10, “Common Stock Activity”) on our results of operations under the purchase method of accounting as if they had been consummated on January 1, 2003. The unaudited pro forma results do not purport to represent what our results of operations actually would have been if these acquisitions had in fact occurred on such date or to project our results of operations for any future date or period.


		Year Ended December 31,

		2004		2003

		(Unaudited)
		(In millions, except per share)
Pro forma:
	Revenue	$	1,456.9	$	1,147.2
	Income from operations		589.1		408.9
	Net income		344.2		223.2
	Basic earnings per share	$	5.58	$	3.74
	Diluted earnings per share	$	5.50	$	3.74

Primary Natural Resources

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 Nos. 141 and 142. 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 is not deductible for tax purposes. See Note 1, “Organization and Summary of Significant Accounting Policies — Goodwill.”

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,			December 31,			December 31,
				2004			2003			2002

				(In millions)
Subject to amortization				$	5,072.4		$	3,747.0		$	3,037.5
Not subject to amortization
	Exploration wells in progress				59.9			8.2			8.2
	Development wells in progress				38.2			31.1			6.7
	Capitalized interest				39.3			23.1			14.0
	Fee mineral interests				23.3			23.3			23.1
	Other capital costs:
		Incurred in 2004			478.4			—			—
		Incurred in 2003			76.9			101.5			—
		Incurred in 2002			62.4			70.0			112.5
		Incurred in 2001 and prior			57.0			73.9			97.0

			Total not subject to amortization		835.4			331.1			261.5

Gross oil and gas properties					5,907.8			4,078.1			3,299.0
Accumulated depreciation, depletion and amortization					(2,132.5	)		(1,659.6	)		(1,312.1	)

Net oil and gas properties				$	3,775.3		$	2,418.5		$	1,986.9

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, 2004 and 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 historical and future development costs for our deepwater Gulf of Mexico project known as “Glider,” located at Green Canyon 247/248.

We believe that substantially all of the properties associated with costs not currently subject to amortization will be evaluated within four years except the Monument Butte Field, which was the sole oil and gas property of Inland. Because of its size, evaluation of the Monument Butte Field in its entirety will take significantly longer than four years. At December 31, 2004, $341 million of costs associated with the Monument Butte Field were not subject to amortization.


	*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, some offshore pipelines and a processing facility located at the end of the pipelines in shallow water. The floating production system is a combination deepwater drilling rig and processing facility capable of simultaneous drilling and production operations. At the time of acquisition, we estimated

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the fair market value of these assets to be $35.0 million. These infrastructure assets are not currently in service and we do not have a specific use for them in our offshore operations.

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.

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 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 expense.” We recognized realized losses on our three-way contracts of $7.3 million and $16.9 million for gas and oil, respectively, in 2004. No three-way contracts were settled in 2003 or 2002.

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

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2004, we had a net $0.1 million after-tax gain recorded under the caption “Accumulated other comprehensive income (loss) — Commodity derivatives.” We expect hedged production associated with commodity derivatives accounting for a net loss of approximately $7.2 million to be sold within the next 12 months and hedged production associated with a remaining net gain of approximately $7.3 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 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 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. 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. For the year ended December 31, 2002, we recorded $29.1 million of expense under the income statement caption “Commodity derivative 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 No. 133, our income statement caption “Commodity derivative expense” would only have reflected $0.5 million of expense in 2002 representing the ineffective portion of our hedges. As a result, net income would have increased by $18.6 million in 2002.

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

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the change occurs. Hedge accounting was not discontinued during the periods presented for any hedging instruments.


	*Natural Gas*

At December 31, 2004, we had entered into derivative contracts that qualify as cash flow hedges with respect to our future natural gas production as follows:


				NYMEX Contract Price Per MMBtu

						Collars

																		Estimated
						Floors				Ceilings				Floor Contracts				Fair Value
				Swaps														Asset
		Volume in		(Weighted				Weighted				Weighted				Weighted		(Liability)
Period and Type of Contract		MMMBtus		Average)		Range		Average		Range		Average		Range		Average		(In millions)

January 2005 - March 2005
	Price swap contracts		8,057	$	7.00		—		—		—		—		—		—	$	6.2
	Collar contracts		23,445		—	$	3.50 - $8.00	$	5.74	$	4.16 - $13.50	$	10.35		—		—		7.9
	Floor contracts		5,400		—		—		—		—		—	$	5.47 - $5.50	$	5.49		0.9
April 2005 - June 2005
	Price swap contracts		9,060		6.19		—		—		—		—		—		—		0.9
	Collar contracts		3,495		—		3.50 - 5.50		5.30		4.16 - 8.55		7.74		—		—		—
	Floor contracts		13,500		—		—		—		—		—		5.50 - 5.51		5.50		4.2
July 2005 - September 2005
	Price swap contracts		9,406		6.17		—		—		—		—		—		—		(0.2	)
	Collar contracts		3,495		—		3.50 - 5.50		5.30		4.16 - 8.55		7.74		—		—		(0.2	)
	Floor contracts		13,500		—		—		—		—		—		5.50 - 5.51		5.50		5.3
October 2005 - December 2005
	Price swap contracts		6,425		5.93		—		—		—		—		—		—		(3.4	)
	Collar contracts		1,395		—		3.50 - 5.50		5.01		4.16 - 8.55		7.15		—		—		(0.7	)
	Floor contracts		4,500		—		—		—		—		—		5.50 - 5.51		5.50		2.1

																		$	23.0


	*Oil*

At December 31, 2004, we had entered into derivative contracts that qualify as cash flow hedges with respect to our future oil production as follows:


				NYMEX Contract Price Per Bbl

						Collars

														Estimated
						Floors				Ceilings				Fair Value
				Swaps										Asset
		Volume in		(Weighted				Weighted				Weighted		(Liability)
Period and Type of Contract		Bbls		Average)		Range		Average		Range		Average		(In millions)

January 2005 - March 2005
	Price swap contracts		717,000	$	32.78		—		—		—		—	$	(7.7	)
	Collar contracts		555,000		—	$	27.00 - $45.00	$	33.99	$	30.65 - $56.80	$	42.87		(2.6	)
April 2005 - June 2005
	Price swap contracts		631,000		33.21		—		—		—		—		(6.1	)
	Collar contracts		468,000		—		27.00 - 45.00		35.37		30.65 - 56.80		44.95		(1.4	)
July 2005 - September 2005
	Price swap contracts		635,000		33.25		—		—		—		—		(5.6	)
	Collar contracts		321,000		—		35.60 - 45.00		39.31		48.00 - 55.50		50.10		0.4
October 2005 - December 2005
	Price swap contracts		635,000		33.25		—		—		—		—		(5.2	)
	Collar contracts		321,000		—		35.60 - 45.00		39.31		48.00 - 55.50		50.10		0.6
January 2006 - December 2006
	Price swap contracts		1,534,000		31.64		—		—		—		—		(12.9	)
January 2007 - December 2007
	Price swap contracts		240,000		27.00		—		—		—		—		(2.8	)

														$	(43.3	)

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2004, 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.


				NYMEX Contract Price Per Bbl

								Collars

																Estimated
				Additional Put				Floors				Ceilings				Fair Value
																Asset
		Volume in				Weighted				Weighted				Weighted		(Liability)
Period and Type of Contract		Bbls		Range		Average		Range		Average		Range		Average		(In millions)

January 2005 - March 2005
	3-Way collar contracts		270,000	$	21.00 - $30.00	$	27.00	$	25.00 - $36.00	$	32.00	$	29.70 - $51.25	$	43.32	$	(1.4	)
April 2005 - June 2005
	3-Way collar contracts		182,000		30.00		30.00		35.00 - 36.00		35.50		49.00 - 51.25		50.13		(0.2	)
July 2005 - September 2005
	3-Way collar contracts		184,000		30.00		30.00		35.00 - 36.00		35.50		49.00 - 51.25		50.13		(0.2	)
October 2005 - December 2005
	3-Way collar contracts		184,000		30.00		30.00		35.00 - 36.00		35.50		49.00 - 51.25		50.13		(0.2	)
January 2006 - December 2006
	3-Way collar contracts		1,006,000		30.00		30.00		35.00 - 36.00		35.27		50.50 - 55.00		51.74		(0.7	)
January 2007 - December 2007
	3-Way collar contracts		2,920,000		25.00 - 29.00		26.50		32.00 - 35.00		33.00		44.70 - 52.80		50.19		(2.1	)
January 2008 - December 2008
	3-Way collar contracts		3,294,000		25.00 - 29.00		26.56		32.00 - 35.00		33.00		49.50 - 52.90		50.29		(1.7	)
January 2009 - December 2009
	3-Way collar contracts		3,285,000		25.00 - 30.00		27.00		32.00 - 36.00		33.33		50.00 - 54.55		50.62		(1.4	)
January 2010 - December 2010
	3-Way collar contracts		3,645,000		25.00 - 32.00		28.60		32.00 - 38.00		34.90		50.00 - 53.50		51.52		(0.6	)

																$	(8.5	)

7. Accrued Liabilities:

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


		December 31,		December 31,
		2004		2003

		(In millions)
Revenue payable		$	108.7	$	59.7
Accrued capital costs			100.4		70.5
Accrued lease operating expenses			25.9		20.4
Employee incentive expense			44.9		26.8
Accrued interest on notes			22.2		14.3
Taxes payable			14.4		2.8
Deferred acquisition payments			17.0		—
Other			20.0		9.5

	Total accrued liabilities	$	353.5	$	204.0

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8. Debt:

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


				December 31,			December 31,
				2004			2003

				(In millions)
Senior unsecured debt:
	Bank revolving credit facility:
		Prime rate based loans		$	—		$	—
		LIBOR based loans			120.0			90.0

			Total bank revolving credit facility		120.0			90.0
	Money market lines of credit⁽¹⁾				—			5.0

			Total credit arrangements		120.0			95.0

	7.45% Senior Notes due 2007				124.9			124.8
	Fair value of interest rate swaps⁽²⁾				(0.6	)		0.2
	7⁵/8% Senior Notes due 2011				174.9			174.9
	Fair value of interest rate swaps⁽²⁾				(0.1	)		0.5

			Total senior unsecured notes		299.1			300.4

			Total senior unsecured debt		419.1			395.4
8³/8% Senior Subordinated Notes due 2012					248.3			248.1
6⁵/8% Senior Subordinated Notes due 2014					325.0			—

			Total long-term debt	$	992.4		$	643.5


(1)	Because capacity under our credit facility was available to repay borrowings under our money market lines of credit, this obligation was classified as long-term at December 31, 2003.

(2)	See “— Interest Rate Swaps” below.


	*Credit Arrangements*

On March 16, 2004, we entered into a 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 $600 million. The amount available under the facility is subject to a calculated borrowing base determined by banks holding 75% of the aggregate commitments. The calculated borrowing base is then reduced by the principal amount of any outstanding senior notes ($300 million at December 31, 2004) and 30% of the principal amount of any outstanding senior subordinated notes (a reduction of $172.5 million at December 31, 2004). The borrowing base is redetermined at least semi-annually and, after all required adjustments, exceeded the facility amount by $100 million and therefore was limited to $600 million at December 31, 2004. 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 March 14, 2008.

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 $50 million. At December 31, 2004, we had outstanding borrowings under our credit facility of $120 million, no borrowings under our money market lines and $31 million of outstanding letters of credit. Consequently, at December 31, 2004, we had approximately $499 million of available capacity under our credit arrangements.

At December 31, 2004 and 2003, the interest rates were 3.63% and 2.50%, respectively, for the LIBOR based loans under our credit facility. At December 31, 2003, the interest rate was 3.00% 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 $1.2 million, $0.9 million and $0.4 million for the years ended December 31, 2004, 2003 and 2002, respectively.


	*Senior Notes*

On February 22, 2001, we issued $175 million aggregate principal amount of our 7⁵/8% Senior Notes due 2011. Interest is payable on each March 1 and September 1, commencing September 1, 2001. The estimated fair value of these notes at December 31, 2004 and 2003 was $196.0 million and $186.2 million, respectively, based on quoted market prices on those dates.

On October 15, 1997, we issued $125 million aggregate principal amount of our 7.45% Senior Notes due 2007. Interest is payable on April 15 and October 15, commencing April 15, 1998. The estimated fair value of these notes at December 31, 2004 and 2003 was $134.7 million and $133.4 million, respectively, based on quoted market prices on those dates.


	•	incur debt secured by certain liens;

	•	enter into sale/leaseback transactions; and

	•	enter into merger or consolidation transactions.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Senior Subordinated Notes*

On August 12, 2004, we issued $325 million aggregate principal amount of our 6⁵/8% Senior Subordinated Notes due 2014. The net proceeds of $322.6 million were used together with the net proceeds of our concurrent stock offering (see Note 10, “Common Stock Activity”) to fund the acquisition of Inland (see Note 4, “Acquisitions”). The estimated fair value of these notes at December 31, 2004 was $342.5 million based on quoted market prices on that date.

On August 13, 2002, we issued $250 million aggregate principal amount of our 8³/8% Senior Subordinated Notes due 2012. The net proceeds from the offering (approximately $241.8 million) were used to repay debt of EEX Corporation that became due at the closing of our acquisition of EEX and to pay related transaction costs. Because the proceeds were held in escrow pending closing, interest accruing prior to the closing in November 2002 of approximately $1.6 million was capitalized as a cost of the transaction. The estimated fair value of these notes at December 31, 2004 and 2003 was $279.1 million and $272.9 million, respectively, based on quoted market prices on those dates.

Interest on our senior subordinated 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 8³/8% notes at any time on or after August 15, 2007 and some or all of the 6⁵/8% notes at any time on or after September 1, 2009, in each case, at a redemption price stated in the applicable supplemental indenture governing the notes. We also may redeem all but not part of the 8³/8% notes prior to August 15, 2007 and all but not part of the 6⁵/8% notes prior to September 1, 2009, in each case, 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 8³/8% notes with the net cash proceeds from certain sales of our common stock at 108.375% of the principal amount plus accrued and unpaid interest to the date of redemption. Likewise, before September 1, 2009, we may redeem up to 35% of the original principal amount of the 6⁵/8% notes with similar net cash proceeds at 106.625% 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 connection with our acquisition of EEX Corporation in November 2002, we assumed $100.8 million principal amount of secured notes. 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

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

We repurchased $23.6 million principal amount of secured notes in December 2002. 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 secured notes. In January 2004, we repurchased the remaining $2.9 million of secured notes.


	*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 viewed as a more desirable proportion of variable and fixed rate debt. We hedged $50 million principal amount of our 7.45% Senior Notes due 2007 and $50 million principal amount of our 7⁵/8% Senior Notes due 2011. 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.

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 or liabilities 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 a third party in exchange for proceeds of $105 million. When we acquired EEX in November 2002, we recorded a liability of $61.6 million, which represented the then current market value of approximately 16 Bcf of remaining reserves subject to the contract. We accounted for the obligation under the gas sales contract as debt on our consolidated balance sheet. In March 2003, pursuant to a settlement agreement the gas sales contract and all related agreements were terminated in exchange for a payment by us of approximately $73 million. We recognized a loss of $10 million under the caption “Gas sales obligation settlement and redemption of securities” on our consolidated statement of income as a result of the settlement.


9.	Redemption of Trust Preferred Securities:

In June 2003, we redeemed all of our outstanding convertible trust preferred securities for an aggregate redemption price of approximately $148.4 million, including $6.5 million of optional redemption premium. 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 (approximately $131.2 million) from the issuance and sale of 3.5 million shares of our common stock in May 2003 and borrowings under our credit arrangements.


10.	Common Stock Activity:

In May 2004, we amended our Second Restated Certificate of Incorporation to increase the authorized number of shares of our common stock that we have authority to issue from 100,000,000 to 200,000,000.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On August 12, 2004, we issued 5.4 million shares of our common stock at $52.85 per share. The net proceeds of $277 million were used in conjunction with the net proceeds of our concurrent Senior Subordinated Notes offering (see Note 8, “Debt — Senior Subordinated Notes”) to acquire Inland (see Note 4, “Acquisitions — Inland Resources Inc.”).

Also see Note 9, “Redemption of Trust Preferred Securities.”


11.	Income Taxes:

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


		For the Year Ended
		December 31,

		2004		2003			2002

		(In millions)
U.S.		$	496.0	$	333.2		$	110.0
Foreign			2.9		(1.6	)		(2.1	)

	Total	$	498.9	$	331.6		$	107.9

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


			For the Year Ended
			December 31,

			2004		2003			2002

			(In millions)
Current taxes:
	U.S. federal		$	52.2	$	21.3		$	36.8
	U.S. state			0.7		0.3			0.7
	Foreign			8.2		—			—
Deferred taxes:
	U.S. federal			118.8		95.7			1.8
	U.S. state			6.7		3.7			0.4
	Foreign			0.2		(0.3	)		(0.5	)

		Total provision for income taxes	$	186.8	$	120.7		$	39.2

The provision for income taxes for each of the years in the three-year period ended December 31, 2004 was different than the amount computed using the federal statutory rate (35%) for the following reasons:


				For the Year Ended
				December 31,

				2004			2003		2002

				(In millions)
Amount computed using the statutory rate				$	174.6		$	116.0	$	37.8
	Increase (decrease) in taxes resulting from:
		State and local income taxes, net of federal effect			4.8			2.2		1.0
		Federal statutory rate in excess of foreign rate			(0.3	)		—		(0.1	)
		Tax credits and other			—			2.5		0.5
		Valuation allowance			7.7			—		—

			Total provision for income taxes	$	186.8		$	120.7	$	39.2

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


			December 31, 2004									December 31, 2003

			U.S.			Foreign			Total			U.S.			Foreign		Total

			(In millions)
Deferred tax asset:
	Net operating loss carryforwards		$	128.1		$	10.3		$	138.4		$	82.1		$	0.8	$	82.9
	Commodity derivatives			1.0			—			1.0			16.6			—		16.6
	Other, net			24.3			—			24.3			7.9			0.1		8.0
	Valuation allowance			—			(7.7	)		(7.7	)		—			—		—

		Deferred tax asset		153.4			2.6			156.0			106.6			0.9		107.5

Deferred tax liability:
	Oil and gas properties			(706.1	)		(0.1	)		(706.2	)		(337.4	)		—		(337.4	)

Net deferred tax asset (liability)				(552.7	)		2.5			(550.2	)		(230.8	)		0.9		(229.9	)
Less net current deferred tax asset (liability)				1.0			(0.1	)		0.9			12.9			—		12.9

Noncurrent deferred tax asset (liability)			$	(553.7	)	$	2.6		$	(551.1	)	$	(243.7	)	$	0.9	$	(242.8	)

As of December 31, 2004, we had net operating loss (NOL) carryforwards for federal income tax purposes of approximately $327 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 2009 through 2024, with a majority expiring in 2019 through 2022. Realization of NOL 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.

We recorded a valuation allowance of $7.7 million for a United Kingdom deferred tax asset related to a NOL carryforward. Realization of deferred tax assets associated with net operating loss carryforwards depends upon generating sufficient taxable income in the appropriate jurisdictions prior to the expiration of the net operating loss.

U.S. deferred taxes have not been provided on foreign income of $38.6 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.	Stock-Based Compensation:

We have several stock-based compensation plans, which are described below. We apply the intrinsic value method prescribed by APB 25 and related interpretations in accounting for our stock-based compensation plans. See Note 1, “Organization and Summary of Significant Accounting Policies — Stock-Based Compensation.”

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*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.

The following is a summary of all stock option activity for 2002, 2003 and 2004:


		Number of			Weighted
		Shares			Average
		Underlying			Exercise
		Options			Price

		(In thousands)
Outstanding at December 31, 2001			3,502		$	25.52
	Granted		1,067			34.49
	Exercised		(391	)		15.22
	Forfeited		(304	)		32.57

Outstanding at December 31, 2002			3,874			28.48
	Granted		632			35.58
	Exercised		(779	)		19.28
	Forfeited		(416	)		35.39

Outstanding at December 31, 2003			3,311			31.13
	Granted		1,017			52.37
	Exercised		(689	)		27.25
	Forfeited		(137	)		41.53

Outstanding at December 31, 2004			3,502		$	37.65

Exercisable at December 31, 2002			1,570		$	21.47

Exercisable at December 31, 2003			1,414		$	26.42

Exercisable at December 31, 2004			1,280		$	29.32

The weighted average fair value of an option to purchase one share of common stock granted during 2004, 2003 and 2002 was $24.91, $14.81 and $14.74, 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.

2004

2003

2002

Dividend yield

None

Expected volatility

40.94%

40.16%

34.15%

Risk-free interest rate

3.25%

3.48%

4.21%

Expected option life

6.5 Years

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes information about stock options outstanding and exercisable at December 31, 2004:


Options Outstanding							Options Exercisable

	Number of		Weighted				Number of
	Shares		Average		Weighted		Shares		Weighted
Range of	Underlying		Remaining		Average		Underlying		Average
Exercise Prices	Options		Contractual Life		Exercise Price		Options		Exercise Price

	(In thousands)						(In thousands)
$10.94 to $14.78		16		1.1 years	$	13.94		16	$	13.94
15.04 to 20.94		145		3.6 years		16.52		145		16.52
21.06 to 25.00		248		3.1 years		23.12		248		23.12
25.01 to 29.81		415		5.1 years		29.32		311		29.24
29.82 to 35.00		902		7.4 years		33.15		255		33.07
35.01 to 45.00		820		7.1 years		38.00		301		38.05
45.01 to 63.35		956		9.3 years		52.61		4		49.91

		3,502		7.1 years	$	37.65		1,280	$	29.32

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 2004, 2003 and 2002 resulted in a tax benefit to us of approximately $6.4 million, $4.9 million and $2.5 million, respectively.

At December 31, 2004, we had approximately 3.5 million shares available for issuance pursuant to our existing employee plans. Of those shares, only approximately 1.6 million could be granted as restricted shares. Of those 1.6 million shares, 1.5 million could be granted under the 2004 Omnibus Stock Plan. Grants of restricted stock under the 2004 Omnibus Stock Plan reduce the total number of shares available under that plan by two times the number of shares issued as restricted stock.


	*Restricted Shares*

At December 31, 2004, there were 0.4 million shares of our common stock held by employees 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, 2004, 18,360 shares remained available for grants under this plan.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In accordance with APB 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, 2004.


			Year Ended December 31,

			2004			2003			2002

Restricted shares granted:
	Employee omnibus plans			51,900			265,700			61,500
	Non-employee director plan⁽¹⁾			6,062			6,664			6,296

		Total		57,962			272,364			67,796

	Weighted average fair value per restricted share granted		$	55.48		$	33.32		$	34.28
	Unearned compensation (in millions)		$	3.2		$	9.1		$	2.3
Restricted shares cancelled:
	Employee omnibus plans			(3,600	)		(49,300	)		(25,000	)
	Non-employee director plan			—			—			—

		Total		(3,600	)		(49,300	)		(25,000	)

	Weighted average fair value per restricted share cancelled		$	36.92		$	32.09		$	35.59
	Unearned compensation (in millions)		$	(0.1	)	$	(1.6	)	$	(0.9	)
Net unearned compensation (in millions)			$	3.1		$	7.5		$	1.4
Compensation expense (in millions)⁽²⁾			$	4.1		$	3.0		$	2.8


	(1)	Eleven directors received grants in 2004 and eight in each of the years 2003 and 2002.

	(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, 2004, 82,995 shares of common stock were available for issuance pursuant to our stock purchase plan. Under the plan, we sold 27,829 shares in 2004 at a weighted average price of $42.47; 30,825 shares in 2003 at a weighted average price of $31.03; and 29,410 shares in 2002 at a weighted average price of $30.27. In accordance with APB 25 and related interpretations, we have not recognized any compensation expense with respect to the plan.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The weighted average fair value of an option to purchase one share of our stock was $14.96, $10.89 and $9.85 during 2004, 2003 and 2002, respectively. 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 2004, 2003 and 2002:

2004

2003

2002

Dividend yield

None

Expected volatility

25.87%

20.83%

25.24%

Risk-free interest rate

1.32%

1.10%

1.71%

Expected option life

6 Months


13.	Pension Plan Obligation:

As a result of our acquisition of EEX in November 2002, we assumed responsibility for a defined pension benefit plan for current and former employees of EEX and its subsidiaries. The plan was amended, effective March 31, 2003, to cease all future retirement benefit accruals. After March 31, 2003, no participant has earned any further benefit accruals under the plan — participant benefits were frozen 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:


			2004			2003

			(In millions)
Change in benefit obligation:
	Benefit obligation at beginning of year		$	(28.2	)	$	(26.4	)
		Service cost		—			(0.1	)
		Interest cost		(1.7	)		(1.6	)
		Assumption loss due to discount rate change		—			(2.1	)
		Benefits paid		2.0			1.1
		Actuarial gain		0.5			0.9

	Benefit obligation at end of year		$	(27.4	)	$	(28.2	)

Change in plan assets:
	Fair value of plan assets at beginning of year		$	20.8		$	19.9
		Actual return on plan assets		3.1			1.5
		Employer contributions		0.2			0.5
		Benefits paid		(2.0	)		(1.1	)

	Fair value of plan assets at end of year		$	22.1		$	20.8

Obligation and funded status:
	Fair value of plan assets		$	22.1		$	20.8
	Benefit obligation			(27.4	)		(28.2	)

	Funded status			(5.3	)		(7.4	)
	Unrecognized net (gain) or loss			(2.2	)		1.3

	Net amount recognized		$	(7.5	)	$	(6.1	)

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		2004			2003

		(In millions)
Amounts recognized on our consolidated balance sheet consist of:
	Prepaid benefit cost	$	—		$	—
	Accrued benefit cost		(7.5	)		(7.7	)
	Intangible assets		—			0.3
	Accumulated other comprehensive loss		—			1.3

	Net amount recognized	$	(7.5	)	$	(6.1	)

Components of net periodic benefit cost:
	Service cost	$	—		$	0.1
	Interest cost		1.7			1.6
	Expected return on plan assets		(0.2	)		(1.4	)

	Net periodic benefit cost	$	1.5		$	0.3

Additional Information:
	Accumulated benefit obligation	$	(27.4	)	$	(28.2	)
	Decrease (increase) in minimum pension liability included in other comprehensive income		1.3			(1.3	)


		2004		2003

The weighted average assumptions used to determine the benefit obligation of the pension plan at December 31 were:
	Discount rate		6.00%		6.00%
	Rate of compensation increase		4.00%		4.00%
	Cost of living		3.00%		3.00%
The weighted average assumptions used to determine the net periodic pension benefit cost for the years ended December 31 were:
	Discount rate		6.00%		6.50%
	Expected long-term rate of return on plan assets		8.00%		7.00%
	Rate of compensation increase		4.00%		4.00%
	Cost of living		3.00%		3.00%

In developing the overall expected long-term rate of return on assets assumption, 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 exposure to risk levels above those determined by us. The investment policy takes into consideration the retirement plan’s benefit obligations including the

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

expected timing of benefit payments. The following is the allocation of the plan’s assets by category at December 31, 2004 and 2003 as well as the target allocation of assets for 2005.


						Percentage of Plan
						Assets at
						December 31
			Target Allocation
			2005			2004			2003

Plan Asset Categories:
	Equity securities			40-60	%		55.55	%		53.27	%
	Debt securities			40-60	%		44.04	%		46.73	%
	Other			0-10	%		0.41	%		—

		Total		100.00	%		100.00	%		100.00	%

During 2005, we anticipate making contributions to the plan of less than $0.1 million.

The expected future benefit payments for our defined pension benefit plans for the next ten years are as follows (in millions):


2005	$	0.9
2006		0.9
2007		0.9
2008		0.9
2009		1.0
2010 — 2014		7.0


14.	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:


			2004			2003

			(In millions)
Change in benefit obligation:
	Benefit obligation at beginning of year		$	(2.2	)	$	(2.2	)
		Service cost		(0.3	)		(0.3	)
		Interest cost		(0.1	)		(0.1	)
		Participant contributions		—			—
		Assumption loss due to discount rate change		—			(0.1	)
		Benefits paid		0.2			0.3
		Actuarial gain or (loss)		(0.3	)		0.2

	Benefit obligation at end of year		$	(2.7	)	$	(2.2	)

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			2004			2003

			(In millions)
Change in plan assets:
	Fair value of plan assets at beginning of year		$	—		$	—
		Employer contributions		0.2			0.2
		Participant contributions		—			—
		Benefits paid		(0.2	)		(0.2	)

	Fair value of plan assets at end of year		$	—		$	—

Obligation and funded status:
	Fair value of plan assets		$	—		$	—
	Benefit obligation			(2.7	)		(2.2	)

	Funded status			(2.7	)		(2.2	)
	Unrecognized net loss			1.3			1.1

	Net amount recognized		$	(1.4	)	$	(1.1	)

Amounts recognized on our consolidated balance sheet consist of:
	Accrued benefit cost		$	(1.4	)	$	(1.1	)

Components of net periodic benefit cost:
	Service cost		$	0.3		$	0.3
	Interest cost			0.1			0.1
	Amortization of net loss			0.1			0.1

	Net periodic benefit cost		$	0.5		$	0.5


		2004			2003

The weighted average assumptions used to determine the benefit obligations at December 31 were:
	Discount rate		6.00	%		6.00	%
	Health care cost trend rate assumed for next year		10.00	%		9.00	%
	Ultimate health care cost trend rate		5.00	%		5.00	%
	Year that the rate reaches the ultimate trend rate		2010			2008
The weighted average assumptions used to determine the net periodic benefit cost for the years ended December 31 were:
	Discount rate		6.00	%		6.50	%
	Health care cost trend rate assumed for next year		9.00	%		10.00	%
	Ultimate health care cost trend rate		5.00	%		5.00	%
	Year that the rate reaches the ultimate trend rate		2008			2008

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		2004			2003

Assumed health care cost trend rates affect the amounts reported. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in thousands):
1-Percentage Point Increase:
	Effect on total of service and interest cost	$	60		$	55
	Effect on postretirement benefit obligation	$	288		$	201
1-Percentage Point Decrease:
	Effect on total of service and interest cost	$	(52	)	$	(39	)
	Effect on postretirement benefit obligation	$	(254	)	$	(178	)

During 2005, we anticipate making contributions to the plan of $0.2 million and participants are expected to contribute less than $0.1 million.

The expected future benefit payments under our post-retirement medical plan for the next ten years are as follows (in millions):


2005	$	0.2
2006		0.2
2007		0.1
2008		0.1
2009		0.1
2010 — 2014		1.6


	*Incentive Compensation Plans*

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. The 2003 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 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 years ended December 31, 2004 and 2003 was $29.3 million and $20.2 million, respectively.

The 1993 plan is very similar to the 2003 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 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 year ended December 31, 2002 was $10.1 million.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*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 $2.0 million, $1.7 million and $1.5 million for the years ended December 31, 2004, 2003 and 2002, 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 $32,300, $32,500 and $32,000 for the years ended December 31, 2004, 2003 and 2002, respectively.


15.	Commitments and Contingencies:


	*Lease Commitments*

Rent expense with respect to our lease commitments for the years ended December 31, 2004, 2003 and 2002 was $4.1 million, $4.0 million and $4.8 million, respectively. We are obligated under non-cancellable operating leases for our office space in Houston, Texas; Tulsa, Oklahoma; Denver, Colorado and Covington, Louisiana. Future minimum payments required under our operating leases as of December 31, 2004 are as follows (in millions):


Year Ending December 31,

2005	$	4.9
2006		4.4
2007		4.4
2008		3.5
2009		0.1

Total minimum lease payments	$	17.3


	*Litigation*

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


16.	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 or parties, 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 earnings 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 rights do not in any way diminish our financial strength, affect reported earnings per share or interfere with our business plans.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


17.	Geographic Information:

While we only have operations in the oil and gas exploration and production industry, we are organizationally structured along geographic operating segments, or divisions. Our reportable operations are the United States, the United Kingdom, Malaysia and Other International (primarily China and Brazil). For segment reporting purposes, our divisions in the United States are aggregated as one reportable segment due to similarities in their operations. The accounting policies of each of our divisions are the same as those described in Note 1, “Organization and Summary of Significant Accounting Policies.”

The following tables provide the geographic operating segment information required by SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” as well as results of operations of oil and gas producing activities required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities” as of and for the years ended December 31, 2004, 2003, and 2002. Income tax allocations have been determined based on statutory rates in the various tax jurisdictions where we have oil and gas producing activities.


			United		United					Other
			States		Kingdom			Malaysia		International		Total

			(In millions)
Year Ended December 31, 2004:
Oil and gas revenues			$	1,311.2	$	2.9		$	38.6	$	—	$	1,352.7
Operating expenses:
	Lease operating			136.4		1.2			8.1		—		145.7
	Production and other taxes			40.0		—			2.3		—		42.3
	Transportation			6.3		—			—		—		6.3
	Depreciation, depletion and amortization			463.3		2.0			6.1		—		471.4
	Ceiling test writedown			—		17.0			—		—		17.0
	Allocated income taxes			232.8		—			8.4		—

		Net income (loss) from oil and gas properties	$	432.4	$	(17.3	)	$	13.7	$	—

	Impairment of floating production system and pipelines												35.0
	General and administrative												84.0

		Total operating expenses											801.7

Income from operations													551.0
	Interest expense, net of interest income, capitalized interest and other												(28.3	)
	Commodity derivative expense												(23.8	)

Income from continuing operations before income taxes												$	498.9

Total long-lived assets			$	3,643.1	$	26.5		$	56.7	$	49.0	$	3,775.3

Additions to long-lived assets			$	1,743.1	$	31.9		$	63.0	$	7.2	$	1,845.2

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			United		United					Other
			States		Kingdom			Malaysia		International		Total

			(In millions)
Year Ended December 31, 2003:
Oil and gas revenues			$	1,016.8	$	0.2		$	—	$	—	$	1,017.0
Operating expenses:
	Lease operating			119.2		0.1			—		—		119.3
	Production and other taxes			31.7		—			—		—		31.7
	Transportation			6.4		—			—		—		6.4
	Depreciation, depletion and amortization			394.4		0.3			—		—		394.7
	Allocated income taxes			162.8		(0.1	)		—		—

		Net income (loss) from oil and gas properties	$	302.3	$	(0.1	)	$	—	$	—

	Gas sales obligation settlement and redemption of securities												20.5
	General and administrative												61.6

		Total operating expenses											634.2

Income from operations													382.8
	Interest expense and dividends, net of interest income, capitalized interest and other												(45.1	)
	Commodity derivative expense												(6.1	)

Income from continuing operations before income taxes												$	331.6

Total long-lived assets			$	2,365.2	$	11.5		$	—	$	41.8	$	2,418.5

Additions to long-lived assets⁽¹⁾			$	762.0	$	10.2		$	—	$	6.9	$	779.1


(1) Includes $100.6 million (domestic) for capitalized asset retirement obligations associated with our adoption of SFAS No. 143.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			United		United				Other
			States		Kingdom		Malaysia		International		Total

			(In millions)
Year Ended December 31, 2002:
Oil and gas revenues			$	626.8	$	—	$	—	$	—	$	626.8
Operating expenses:
	Lease operating			90.8		—		—		—		90.8
	Production and other taxes			13.3		—		—		—		13.3
	Transportation			5.7		—		—		—		5.7
	Depreciation, depletion and amortization			295.1		—		—		—		295.1
	Allocated income taxes			77.7		—		—		—

		Net income from oil and gas properties	$	144.2	$	—	$	—	$	—

	General and administrative											54.4

		Total operating expenses										459.3

Income from operations												167.5
	Interest expense and dividends, net of interest income, capitalized interest and other											(30.5	)
	Commodity derivative expense											(29.1	)

Income from continuing operations before income taxes											$	107.9

Total long-lived assets			$	1,950.6	$	1.4	$	—	$	34.9	$	1,986.9

Additions to long-lived assets			$	880.3	$	1.4	$	—	$	6.8	$	888.5


18.	Supplemental Cash Flow Information:


		Year Ended December 31,

		2004			2003			2002

		(In millions)
Cash payments:
	Interest and dividend payments, net of interest capitalized of $25.8, $15.9 and $8.8 during 2004, 2003 and 2002, respectively	$	22.2		$	41.7		$	35.5
	Income tax payments		16.5			40.0			21.5
Non-cash items excluded from the statement of cash flows:
	Accrued capital expenditures	$	(33.4	)	$	(22.9	)	$	(17.1	)
	Asset retirement costs		(48.5	)		(132.3	)		—
	Stock issued for acquisitions		—			—			(258.2	)
	Other		0.1			(0.1	)		(0.1	)

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


19.	Related Party Transaction:

David A. Trice, our Chairman, President and Chief Executive Officer, is a minority owner of Huffco International L.L.C. In May 1997, prior to Mr. Trice rejoining us as an executive officer, 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 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, 2004, Newfield China had approximately $44.7 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.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


20.	Quarterly Results of Operations (Unaudited):

The results of operations by quarter for the years ended December 31, 2004 and 2003 are as follows:


	2004 Quarter Ended

	March 31		June 30		September 30		December 31

	(In millions, except per share data)
Oil and gas revenues	$	305.4	$	282.7	$	327.7	$	436.9
Income from operations⁽¹⁾		141.2		118.5		126.5		164.8
Income from continuing operations		77.9		67.5		76.5		90.2
Net income		77.9		67.5		76.5		90.2
Basic earnings per common share⁽²⁾:
Income from continuing operations	$	1.39	$	1.20	$	1.29	$	1.46
Basic earnings per common share	$	1.39	$	1.20	$	1.29	$	1.46
Diluted earnings per common share⁽²⁾:
Income from continuing operations	$	1.38	$	1.18	$	1.27	$	1.43
Diluted earnings per common share	$	1.38	$	1.18	$	1.27	$	1.43


	2003 Quarter Ended

	March 31			June 30			September 30			December 31

	(In millions, except per share data)
Oil and gas revenues	$	267.9		$	255.5		$	248.7		$	244.9
Income from operations		108.0			94.4			93.8			86.6
Income from continuing operations		59.3			53.0			58.4			40.2
Loss from discontinued operations, net of tax		(0.8	)		(7.2	)		(9.0	)		—
Cumulative effect of change in accounting principle, net of tax		5.6			—			—			—
Net income		64.1			45.8			49.4			40.2
Basic earnings per common share⁽²⁾:
Income from continuing operations	$	1.14		$	0.99		$	1.04		$	0.72
Loss from discontinued operations		(0.01	)		(0.13	)		(0.16	)		—
Cumulative effect of change in accounting principle, net of tax		0.11			—			—			—

Basic earnings per common share	$	1.24		$	0.86		$	0.88		$	0.72

Diluted earnings per common share⁽²⁾:
Income from continuing operations	$	1.08		$	0.95		$	1.04		$	0.71
Loss from discontinued operations		(0.01	)		(0.13	)		(0.16	)		—
Cumulative effect of change in accounting principle, net of tax		0.10			—			—			—

Diluted earnings per common share	$	1.17		$	0.82		$	0.88		$	0.71


(1)	Income from operations for the fourth quarter of 2004 includes a full cost ceiling test writedown of $10.3 million related to our operations in the North Sea and a charge of $35.0 million related to the impairment of the floating production system and pipelines. See Note 1, “Organization and Summary of Significant Accounting Policies — Oil and Gas Properties,” and Note 5, “Oil and Gas Assets — Floating Production System and Pipelines.”

(2)	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.

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, 2004 are as follows (in millions):


			United				United				Other
			States		China		Kingdom		Malaysia		Foreign		Total

2004:
Property acquisition:⁽¹⁾
	Unproved		$	422.5	$	0.5	$	6.8	$	6.9	$	1.5	$	438.2
	Proved			559.9		—		—		43.7		—		603.6
Exploration				135.6		1.1		25.1		8.9		4.0		174.7
Development⁽²⁾				625.1		0.1		—		3.5		—		628.7

		Total costs incurred⁽³⁾	$	1,743.1	$	1.7	$	31.9	$	63.0	$	5.5	$	1,845.2

2003:
Property acquisition:
	Unproved		$	38.5	$	0.8	$	3.9	$	—	$	1.1	$	44.3
	Proved			137.2		—		2.9		—		—		140.1
Exploration				154.9		4.2		2.3		—		0.7		162.1
Development⁽²⁾				330.8		—		1.2		—		—		332.0

		Total costs incurred	$	661.4	$	5.0	$	10.3	$	—	$	1.8	$	678.5

2002:
Property acquisition:
	Unproved		$	112.2	$	—	$	—	$	—	$	—	$	112.2
	Proved			511.4		—		—		—		—		511.4
Exploration				102.7		4.9		1.4		—		1.9		110.9
Development				154.0		—		—		—		—		154.0

		Total costs incurred	$	880.3	$	4.9	$	1.4	$	—	$	1.9	$	888.5


(1)	Includes $344 million and $375 million recorded as unproved and proved property acquisition costs, respectively, related to the August 2004 acquisition of Inland Resources. These amounts represent the recorded fair value of the oil and gas assets. The cash consideration paid in the acquisition was approximately $575 million.

(2)	Includes $48.8 million and $31.8 million for 2004 and 2003, respectively, of asset retirement costs recorded in accordance with the provisions of SFAS No. 143.

(3)	Excludes $17.0 million in property sales in the United States and $1.8 million in foreign currency translation adjustments. Additionally, the $17.0 million ceiling test writedown in the United Kingdom is not presented as a reduction of the capital expenditures for 2004.

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION

SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Capitalized costs for our oil and gas producing activities consisted of the following at the end of each of the years in the three-year period ended December 31, 2004 (in millions):


	United					United						Other
	States			China		Kingdom			Malaysia			Foreign		Total

December 31, 2004:
Proved properties	$	5,106.7		$	—	$	11.1		$	47.2		$	—	$	5,165.0
Unproved properties		660.8			36.7		17.2			15.8			12.3		742.8

		5,767.5			36.7		28.3			63.0			12.3		5,907.8
Accumulated depreciation, depletion and amortization		(2,124.4	)		—		(1.8	)		(6.3	)		—		(2,132.5	)

Net capitalized costs	$	3,643.1		$	36.7	$	26.5		$	56.7		$	12.3	$	3,775.3

December 31, 2003:
Proved properties	$	3,782.3		$	—	$	4.0		$	—		$	—	$	3,786.3
Unproved properties		242.4			35.0		7.6			—			6.8		291.8

		4,024.7			35.0		11.6			—			6.8		4,078.1
Accumulated depreciation, depletion and amortization		(1,659.5	)		—		(0.1	)		—			—		(1,659.6	)

Net capitalized costs	$	2,365.2		$	35.0	$	11.5		$	—		$	6.8	$	2,418.5

December 31, 2002:
Proved properties	$	3,052.4		$	—	$	—		$	—		$	—	$	3,052.4
Unproved properties		210.3			30.0		1.4			—			4.9		246.6

		3,262.7			30.0		1.4			—			4.9		3,299.0
Accumulated depreciation, depletion and amortization		(1,312.1	)		—		—			—			—		(1,312.1	)

Net capitalized costs	$	1,950.6		$	30.0	$	1.4		$	—		$	4.9	$	1,986.9

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 also 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. 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, 2001, 2002, 2003 and 2004 and the changes in our total net proved reserves during the three-year period ended December 31, 2004, as estimated by our petroleum engineering staff:


		Oil, Condensate and Natural Gas
		Liquids (MBbls)												Natural Gas (MMcf)											Total (MMcfe)

		U.S.			U.K.			Malaysia			Total			U.S.			U.K.			Malaysia		Total			U.S.			U.K.			Malaysia			Total

*Proved developed and undeveloped reserves as of:*
December 31, 2001			30,959			—			—			30,959			718,312			—			—		718,312			904,066			—			—			904,066
Revisions of previous estimates			1,367			—			—			1,367			528			—			—		528			8,730			—			—			8,730
Extensions, discoveries and other additions			4,218			—			—			4,218			108,201			—			—		108,201			133,509			—			—			133,509
Purchases of properties			4,191			—			—			4,191			301,614			—			—		301,614			326,760			—			—			326,760
Sales of properties			(1,463	)		—			—			(1,463	)		(6,880	)		—			—		(6,880	)		(15,658	)		—			—			(15,658	)
Production			(5,235	)		—			—			(5,235	)		(144,660	)		—			—		(144,660	)		(176,070	)		—			—			(176,070	)

December 31, 2002			34,037			—			—			34,037			977,115			—			—		977,115			1,181,337			—			—			1,181,337
Revisions of previous estimates			663			—			—			663			(4,223	)		—			—		(4,223	)		(239	)		—			—			(239	)
Extensions, discoveries and other additions			6,267			—			—			6,267			200,382			—			—		200,382			237,970			—			—			237,970
Purchases of properties			2,835			26			—			2,861			101,344			2,517			—		103,861			118,365			2,673			—			121,038
Sales of properties			—			—			—			—			(2,762	)		—			—		(2,762	)		(2,762	)		—			—			(2,762	)
Production			(6,054	)		—			—			(6,054	)		(184,188	)		(45	)		—		(184,233	)		(220,513	)		(45	)		—			(220,558	)

December 31, 2003			37,748			26			—			37,774			1,087,668			2,472			—		1,090,140			1,314,158			2,628			—			1,316,786
Revisions of previous estimates			1,216			(5	)		—			1,211			(1,882	)		(517	)		—		(2,399	)		5,411			(546	)		—			4,865
Extensions, discoveries and other additions			5,250			—			—			5,250			230,919			—			—		230,919			262,418			—			—			262,418
Purchases of properties			47,800			—			6,588			54,388			131,359			—			—		131,359			418,155			—			39,529			457,684
Sales of properties			(575	)		—			—			(575	)		(10,824	)		—			—		(10,824	)		(14,274	)		—			—			(14,274	)
Production			(6,686	)		(6	)		(873	)		(7,565	)		(197,588	)		(602	)		—		(198,190	)		(237,700	)		(641	)		(5,239	)		(243,580	)

December 31, 2004			84,753			15			5,715			90,483			1,239,652			1,353			—		1,241,005			1,748,168			1,441			34,290			1,783,899

*Proved developed reserves as of:*
	December 31, 2001		29,151			—			—			29,151			662,879			—			—		662,879			837,785			—			—			837,785
	December 31, 2002		32,425			—			—			32,425			905,062			—			—		905,062			1,099,612			—			—			1,099,612
	December 31, 2003		30,688			26			—			30,714			955,760			2,472			—		958,232			1,139,893			2,628			—			1,142,521
	December 31, 2004		49,704			15			5,715			55,434			1,003,927			1,353			—		1,005,280			1,302,149			1,441			34,290			1,337,880

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION

SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

All of our oil reserves in Malaysia are associated with a production sharing contract for Block PM 318. Malaysia reserves include oil to be received for both cost recovery and profit sharing provisions under the contract.

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 sales 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.

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:


		U.S.			U.K.			Malaysia			Total

		(In millions)
2004:
Future cash inflows		$	10,718.3		$	7.1		$	219.3		$	10,944.7
Less related future:
	Production costs		(2,067.6	)		(3.7	)		(127.2	)		(2,198.5	)
	Development and abandonment costs		(885.6	)		(1.6	)		(10.2	)		(897.4	)

Future net cash flows before income taxes			7,765.1			1.8			81.9			7,848.8
Future income tax expense			(2,149.1	)		(0.7	)		(31.3	)		(2,181.1	)

Future net cash flows before 10% discount			5,616.0			1.1			50.6			5,667.7
10% annual discount for estimating timing of cash flows			(2,059.2	)		—			(6.5	)		(2,065.7	)

Standardized measure of discounted future net cash flows		$	3,556.8		$	1.1		$	44.1		$	3,602.0

2003:
Future cash inflows		$	7,617.6		$	11.9		$	—		$	7,629.5
Less related future:
	Production costs		(1,374.3	)		(5.6	)		—			(1,379.9	)
	Development and abandonment costs		(449.6	)		(1.5	)		—			(451.1	)

Future net cash flows before income taxes			5,793.7			4.8			—			5,798.5
Future income tax expense			(1,461.0	)		(1.9	)		—			(1,462.9	)

Future net cash flows before 10% discount			4,332.7			2.9			—			4,335.6
10% annual discount for estimating timing of cash flows			(1,400.0	)		(0.2	)		—			(1,400.2	)

Standardized measure of discounted future net cash flows		$	2,932.7		$	2.7		$	—		$	2,935.4

2002:
Future cash inflows		$	5,633.5		$	—		$	—		$	5,633.5
Less related future:
	Production costs		(1,066.3	)		—			—			(1,066.3	)
	Development and abandonment costs		(299.6	)		—			—			(299.6	)

Future net cash flows before income taxes			4,267.6			—			—			4,267.6
Future income tax expense			(1,042.3	)		—			—			(1,042.3	)

Future net cash flows before 10% discount			3,225.3			—			—			3,225.3
10% annual discount for estimating timing of cash flows			(978.3	)		—			—			(978.3	)

Standardized measure of discounted future net cash flows		$	2,247.0		$	—		$	—		$	2,247.0

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, 2004:


		U.S.			U.K.			Malaysia			Total

					(In millions)
2004:
Beginning of the period		$	2,932.7		$	2.7		$	—		$	2,935.4
Revisions of previous estimates:
	Changes in prices and costs		157.1			—			—			157.1
	Changes in quantities		(3.8	)		—			—			(3.8	)
Development costs incurred during the period			135.0			—			—			135.0
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs			733.6			—			—			733.6
Purchases and sales of reserves in place, net			855.0			—			81.2			936.2
Accretion of discount			293.3			0.3			—			293.6
Sales of oil and gas, net of production costs			(1,130.4	)		(1.5	)		(10.8	)		(1,142.7	)
Net change in income taxes			(343.7	)		0.3			(26.3	)		(369.7	)
Production timing and other			(72.0	)		(0.7	)		—			(72.7	)

Net increase			624.1			(1.6	)		44.1			666.6

End of the period		$	3,556.8		$	1.1		$	44.1		$	3,602.0

2003:
Beginning of the period		$	2,247.0		$	—		$	—		$	2,247.0
Revisions of previous estimates:
	Changes in prices and costs		575.8			—			—			575.8
	Changes in quantities		(0.1	)		—			—			(0.1	)
Development costs incurred during the period			63.4			—			—			63.4
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs			710.6			—			—			710.6
Purchases and sales of reserves in place, net			295.8			3.8			—			299.6
Accretion of discount			224.7			—			—			224.7
Sales of oil and gas, net of production costs			(852.4	)		(0.1	)		—			(852.5	)
Net change in income taxes			(246.3	)		(1.0	)		—			(247.3	)
Production timing and other			(85.8	)		—			—			(85.8	)

Net increase			685.7			2.7			—			688.4

End of the period		$	2,932.7		$	2.7		$	—		$	2,935.4

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION

SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)


		U.S.			U.K.		Malaysia		Total

					(In millions)
2002:
Beginning of the period		$	958.9		$	—	$	—	$	958.9
Revisions of previous estimates:
	Changes in prices and costs		1,046.9			—		—		1,046.9
	Changes in quantities		12.4			—		—		12.4
Development costs incurred during the period			31.9			—		—		31.9
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs			420.8			—		—		420.8
Purchases and sales of reserves in place, net			663.6			—		—		663.6
Accretion of discount			95.9			—		—		95.9
Sales of oil and gas, net of production costs			(347.8	)		—		—		(347.8	)
Net change in income taxes			(769.4	)		—		—		(769.4	)
Production timing and other			133.8			—		—		133.8

Net increase			1,288.1			—		—		1,288.1

End of the period		$	2,247.0		$	—	$	—	$	2,247.0


Item 9.	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosure*

None.


Item 9A.	*Controls and Procedures*

Disclosure Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2004 in ensuring that material information was accumulated and communicated to management, and made known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to allow disclosure as required in this report.

Management’s Report on Internal Control over Financial Reporting and Report of Independent Registered Public Accounting Firm

The information required to be furnished pursuant to this item is set forth under the captions “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” in Item 8 of this report.

Changes in Internal Control over Financial Reporting

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the fourth quarter of 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting or in other factors that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART III


Item 10.	*Directors and Executive Officers of the Registrant*

The information required by Item 10 of Form 10-K is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2005 Annual Meeting of Stockholders to be held on May 5, 2005 and to the information set forth in Item 4A of 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.”

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 incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2005 Annual Meeting of Stockholders to be held on May 5, 2005.


Item 11.	*Executive Compensation*

The information required by Item 11 of Form 10-K is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2005 Annual Meeting of Stockholders to be held on May 5, 2005.


Item 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*

The information required by Item 12 of Form 10-K is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2005 Annual Meeting of Stockholders to be held on May 5, 2005.


Item 13.	*Certain Relationships and Related Transactions*

The information required by Item 13 of Form 10-K is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2005 Annual Meeting of Stockholders to be held on May 5, 2005.


Item 14.	*Principal Auditor Fees and Services*

The information required by Item 14 of Form 10-K is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2005 Annual Meeting of Stockholders to be held on May 5, 2005.

100

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 29, 2004, we filed a Current Report on Form 8-K to furnish our press release dated October 27, 2004 announcing our third quarter 2004 financial and operating results and fourth quarter 2004 earnings guidance and to furnish our @NFX publication dated October 27, 2004, which included an update on recent drilling activities, guidance for the fourth quarter of 2004 and updated tables detailing our complete hedging positions as of October 26, 2004.

On November 4, 2004, we filed a Current Report on Form 8-K to furnish our press release of that date announcing that our Cumbria Prospect in the U.K. North Sea was a dry hole.

On November 5, 2004, we filed a Current Report on Form 8-K to disclose the appointments of J. Michael Lacey, Joseph H. Netherland and J. Terry Strange to our Board of Directors effective November 4, 2004.

On November 12, 2004, we filed an amendment to our Current Report on Form 8-K filed on August 30, 2004 to provide the required historical and pro forma financial information with respect to our acquisition of Inland Resources. The following financial statements were filed with the report:


	•	Inland Resources consolidated financial statements as of December 31, 2003 and for the calendar year then ended and related notes;

	•	Inland Resources consolidated financial statements as of June 30, 2004 and 2003 and for each of the six month periods then ended and related notes; and

	•	our unaudited pro forma combined condensed financial statements as of June 30, 2004 and for the six months then ended and for the calendar year ended December 31, 2003 that give effect to our acquisition of Inland Resources and the issuance of our 6⁵/8% Senior Subordinated Notes due 2014 and 5.4 million shares of our common stock.

On December 15, 2004, we filed a Current Report on Form 8-K to provide the information required by Regulation BTR with respect to our 401(k) plan.

3. Exhibits

101


Exhibit
Number				Title

	3	.1.2	—	Certificate of Amendment to Second Restated Certificate of Incorporation of Newfield dated May 12, 2004 (incorporated by reference to Exhibit 4.2.3 to Newfield’s Registration Statement on Form S-8 (Registration No. 333-116191))
	3	.1.3	—	Certificate of Designation of Series A Junior Participating Preferred Stock, par value $0.01 per share, setting forth the terms of the Series A Junior Participating Preferred Stock, par value $0.01 per share (incorporated by reference to Exhibit 3.5 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 1-12534))
	3	.2	—	Restated Bylaws of Newfield as amended by Amendment No. 1 thereto adopted January 31, 2000 (incorporated by reference to Exhibit 3.3 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 1-12534))
	4	.1	—	Rights Agreement, dated as of February 12, 1999, between Newfield and ChaseMellon Shareholder Services L.L.C., as Rights Agent, specifying the terms of the Rights to Purchase Series A Junior Participating Preferred Stock, par value $0.01 per share, of Newfield (incorporated by reference to Exhibit 1 to Newfield’s Registration Statement on Form 8-A filed with the SEC on February 18, 1999 (File No. 1-12534))
	4	.2	—	Indenture dated as of October 15, 1997 among Newfield, as issuer, and Wachovia Bank, National Association (formerly First Union National Bank), as trustee (incorporated by reference to Exhibit 4.3 to Newfield’s Registration Statement on Form S-4 (Registration No. 333-39563))
	4	.3	—	Senior Indenture dated as of February 28, 2001 between Newfield and Wachovia Bank, National Association (formerly First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 28, 2001 (File No. 1-12534))
	4	.4	—	Subordinated Indenture dated as of December 10, 2001 between Newfield and Wachovia Bank, National Association (formerly First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.5 of Newfield’s Registration Statement on Form S-3 (Registration No. 333-71348)
	4	.4.1	—	First Supplemental Indenture, dated as of August 13, 2002, to Subordinated Indenture dated as of December 10, 2001 between Newfield and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 of Newfield’s Current Report on Form 8-K filed with the SEC on August 13, 2002 (File No. 1-12534))
	4	.4.2	—	Second Supplemental Indenture, dated as of August 18, 2004, to Subordinated Indenture dated as of December 10, 2001 between Newfield and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.6.3 to Newfield’s Registration Statement on Form S-4 (Registration No. 333-122157))
	4	.4.2.1	—	Registration Rights Agreement, dated August 18, 2004, among Newfield, Morgan Stanley & Co. Incorporated and the other initial purchasers named therein (incorporated by reference to Exhibit 4.7 to Newfield’s Registration Statement on Form S-4 (Registration No. 333-122157))
	†10	.1	—	Newfield Exploration Company 1995 Omnibus Stock Plan (incorporated by reference to Exhibit 4.1 to Newfield’s Registration Statement on Form S-8 (Registration No. 33-92182))
	†10	.1.1	—	First Amendment to Newfield Exploration Company 1995 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 (File No. 1-12534))
	†10	.2	—	Newfield Exploration Company 1998 Omnibus Stock Plan (incorporated by reference to Exhibit 4.1.1 to Newfield’s Registration Statement on Form S-8 (Registration No. 333-59383))
	†10	.2.1	—	Amendment of 1998 Omnibus Stock Plan, dated May 7, 1998 (incorporated by reference to Exhibit 4.1.2 to Newfield’s Registration Statement on Form S-8 (Registration No. 333-59383))
	†10	.2.2	—	Second Amendment to Newfield Exploration Company 1998 Omnibus Stock Plan (as amended on May 7, 1998) (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 (File No. 1-12534))
	†10	.3	—	Newfield Exploration Company 2000 Omnibus Stock Plan (as amended and restated effective February 14, 2002) (incorporated by reference to Exhibit 10.7.2 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-12534))

102


Exhibit
Number				Title

	†10	.3.1	—	First Amendment to Newfield Exploration Company 2000 Omnibus Plan (as amended and restated effective February 14, 2002) (incorporated by reference to Exhibit 10.3 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 (File No. 1-12534))
	*†10	.3.2	—	Form of TSR 2003 Restricted Stock Agreement between Newfield and each of David A. Trice, David F. Schaible, Elliott Pew, Terry W. Rathert, Lee K. Boothby, George T. Dunn, Gary D. Packer and William D. Schneider dated as of February 12, 2003
	†10	.4	—	Newfield Exploration Company 2004 Omnibus Stock Plan (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004 (File No. 1-12534))
	†10	.4.1	—	Form of TSR 2005 Restricted Stock Agreement between Newfield and each of David A. Trice, David F. Schaible, Elliott Pew, Terry W. Rathert, Lee K. Boothby, George T. Dunn, Gary D. Packer, William D. Schneider, Brian L. Rickmers and Susan G. Riggs dated as of February 8, 2005 (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 11, 2005 (File No. 1-12534))
	†10	.5	—	Newfield Exploration Company 2000 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10.18 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 1-12534))
	†10	.6	—	Newfield Employee 1993 Incentive Compensation Plan (incorporated by reference to Exhibit 10.5 to Newfield’s Registration Statement on Form S-1 (Registration No. 33-69540))
	†10	.6.1	—	Amendment to Newfield Employee 1993 Incentive Compensation Plan (effective as of February 14, 2002) (incorporated by reference to Exhibit 10.9.2 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-12534))
	*†10	.7	—	Amended and Restated Newfield Exploration Company 2003 Incentive Compensation Plan
	†10	.8	—	Newfield Exploration Company Deferred Compensation Plan (incorporated by reference to Exhibit 10.11 to Newfield’s Registration Statement on Form S-3 (Registration No. 333-32587))
	*†10	.9	—	Newfield Exploration Company Change of Control Severance Plan
	*†10	.10	—	Form of Change of Control Severance Agreement between Newfield and each of David A. Trice, David F. Schaible, Elliott Pew and Terry W. Rathert dated effective as of February 17, 2005
	*†10	.11	—	Form of Change of Control Severance Agreement between Newfield and each of Lee K. Boothby, George T. Dunn, Gary D. Packer and William D. Schneider dated effective as of February 17, 2005
	†10	.12	—	Employment Agreement between Newfield and Joe B. Foster dated January 31, 2000 (incorporated by reference to Exhibit 10 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2000 (File No. 1-12534))
	†10	.13	—	Resolution of Members Establishing the Preferences, Limitations and Relative Rights of Series “A” Preferred Shares of Huffco China, LDC dated May 14, 1997 (incorporated by reference to Exhibit 10.15 to Newfield’s Registration Statement on Form S-3 (Registration No. 333-32587))
	10	.14	—	Credit Agreement, dated as of March 16, 2004, among Newfield, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent and as Issuing Bank(incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004 (File No. 1-12534))
	*21	.1	—	List of Significant Subsidiaries
	*23	.1	—	Consent of PricewaterhouseCoopers LLP
	*31	.1	—	Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	*31	.2	—	Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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 ninth day of March, 2005.


	Newfield Exploration Company


	By:	/s/ David A. Trice



	David A. Trice
	Chairman, 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 ninth day of March, 2005.


Signature				Title


/s/ David A. Trice David A. Trice				Chairman, President and Chief Executive Officer and Director (Principal Executive Officer)

/s/ Terry W. Rathert Terry W. Rathert				Senior Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ Brian L. Rickmers Brian L. Rickmers				Controller (Principal Accounting Officer)

/s/ Joe B. Foster Joe B. Foster				Director

/s/ Philip J. Burguieres Philip J. Burguieres				Director

/s/ Charles W. Duncan, Jr. Charles W. Duncan, Jr.				Director

/s/ Claire S. Farley Claire S. Farley				Director

/s/ Dennis Hendrix Dennis Hendrix				Director

/s/ John R. Kemp III John R. Kemp III				Director

/s/ J. Michael Lacey J. Michael Lacey				Director

/s/ Joseph H. Netherland Joseph H. Netherland				Director

/s/ Howard H. Newman Howard H. Newman				Director

/s/ Thomas G. Ricks Thomas G. Ricks				Director

105


Signature				Title


/s/ David F. Schaible David F. Schaible				Director

/s/ J. Terry Strange J. Terry Strange				Director

/s/ C. E. Shultz C. E. Shultz				Director

106

INDEX TO EXHIBITS


Exhibit
Number				Title

	3	.1	—	Second Restated Certificate of Incorporation of Newfield (incorporated by reference to Exhibit 3.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 1-12534))
	3	.1.1	—	Certificate of Amendment to Second Restated Certificate of Incorporation of Newfield dated May 15, 1997 (incorporated by reference to Exhibit 3.1.1 to Newfield’s Registration Statement on Form S-3 (Registration No. 333-32582))
	3	.1.2	—	Certificate of Amendment to Second Restated Certificate of Incorporation of Newfield dated May 12, 2004 (incorporated by reference to Exhibit 4.2.3 to Newfield’s Registration Statement on Form S-8 (Registration No. 333-116191))
	3	.1.3	—	Certificate of Designation of Series A Junior Participating Preferred Stock, par value $0.01 per share, setting forth the terms of the Series A Junior Participating Preferred Stock, par value $0.01 per share (incorporated by reference to Exhibit 3.5 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 1-12534))
	3	.2	—	Restated Bylaws of Newfield as amended by Amendment No. 1 thereto adopted January 31, 2000 (incorporated by reference to Exhibit 3.3 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 1-12534))
	4	.1	—	Rights Agreement, dated as of February 12, 1999, between Newfield and ChaseMellon Shareholder Services L.L.C., as Rights Agent, specifying the terms of the Rights to Purchase Series A Junior Participating Preferred Stock, par value $0.01 per share, of Newfield (incorporated by reference to Exhibit 1 to Newfield’s Registration Statement on Form 8-A filed with the SEC on February 18, 1999 (File No. 1-12534))
	4	.2	—	Indenture dated as of October 15, 1997 among Newfield, as issuer, and Wachovia Bank, National Association (formerly First Union National Bank), as trustee (incorporated by reference to Exhibit 4.3 to Newfield’s Registration Statement on Form S-4 (Registration No. 333-39563))
	4	.3	—	Senior Indenture dated as of February 28, 2001 between Newfield and Wachovia Bank, National Association (formerly First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 28, 2001 (File No. 1-12534))
	4	.4	—	Subordinated Indenture dated as of December 10, 2001 between Newfield and Wachovia Bank, National Association (formerly First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.5 of Newfield’s Registration Statement on Form S-3 (Registration No. 333-71348)
	4	.4.1	—	First Supplemental Indenture, dated as of August 13, 2002, to Subordinated Indenture dated as of December 10, 2001 between Newfield and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 of Newfield’s Current Report on Form 8-K filed with the SEC on August 13, 2002 (File No. 1-12534))
	4	.4.2	—	Second Supplemental Indenture, dated as of August 18, 2004, to Subordinated Indenture dated as of December 10, 2001 between Newfield and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.6.3 to Newfield’s Registration Statement on Form S-4 (Registration No. 333-122157))
	4	.4.2.1	—	Registration Rights Agreement, dated August 18, 2004, among Newfield, Morgan Stanley & Co. Incorporated and the other initial purchasers named therein (incorporated by reference to Exhibit 4.7 to Newfield’s Registration Statement on Form S-4 (Registration No. 333-122157))
	†10	.1	—	Newfield Exploration Company 1995 Omnibus Stock Plan (incorporated by reference to Exhibit 4.1 to Newfield’s Registration Statement on Form S-8 (Registration No. 33-92182))
	†10	.1.1	—	First Amendment to Newfield Exploration Company 1995 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 (File No. 1-12534))
	†10	.2	—	Newfield Exploration Company 1998 Omnibus Stock Plan (incorporated by reference to Exhibit 4.1.1 to Newfield’s Registration Statement on Form S-8 (Registration No. 333-59383))
	†10	.2.1	—	Amendment of 1998 Omnibus Stock Plan, dated May 7, 1998 (incorporated by reference to Exhibit 4.1.2 to Newfield’s Registration Statement on Form S-8 (Registration No. 333-59383))
	†10	.2.2	—	Second Amendment to Newfield Exploration Company 1998 Omnibus Stock Plan (as amended on May 7, 1998) (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 (File No. 1-12534))


Exhibit
Number				Title

	†10	.3.1	—	First Amendment to Newfield Exploration Company 2000 Omnibus Plan (as amended and restated effective February 14, 2002) (incorporated by reference to Exhibit 10.3 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 (File No. 1-12534))
	*†10	.3.2	—	Form of TSR 2003 Restricted Stock Agreement between Newfield and each of David A. Trice, David F. Schaible, Elliott Pew, Terry W. Rathert, Lee K. Boothby, George T. Dunn, Gary D. Packer and William D. Schneider dated as of February 12, 2003
	†10	.4	—	Newfield Exploration Company 2004 Omnibus Stock Plan (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004 (File No. 1-12534))
	†10	.4.1	—	Form of TSR 2005 Restricted Stock Agreement between Newfield and each of David A. Trice, David F. Schaible, Elliott Pew, Terry W. Rathert, Lee K. Boothby, George T. Dunn, Gary D. Packer, William D. Schneider, Brian L. Rickmers and Susan G. Riggs dated as of February 8, 2005 (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 11, 2005 (File No. 1-12534))
	†10	.5	—	Newfield Exploration Company 2000 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10.18 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 1-12534))
	†10	.6	—	Newfield Employee 1993 Incentive Compensation Plan (incorporated by reference to Exhibit 10.5 to Newfield’s Registration Statement on Form S-1 (Registration No. 33-69540))
	†10	.6.1	—	Amendment to Newfield Employee 1993 Incentive Compensation Plan (effective as of February 14, 2002) (incorporated by reference to Exhibit 10.9.2 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-12534))
	*†10	.7	—	Amended and Restated Newfield Exploration Company 2003 Incentive Compensation Plan
	†10	.8	—	Newfield Exploration Company Deferred Compensation Plan (incorporated by reference to Exhibit 10.11 to Newfield’s Registration Statement on Form S-3 (Registration No. 333-32587))
	*†10	.9	—	Newfield Exploration Company Change of Control Severance Plan
	*†10	.10	—	Form of Change of Control Severance Agreement between Newfield and each of David A. Trice, David F. Schaible, Elliott Pew and Terry W. Rathert dated effective as of February 17, 2005
	*†10	.11	—	Form of Change of Control Severance Agreement between Newfield and each of Lee K. Boothby, George T. Dunn, Gary D. Packer and William D. Schneider dated effective as of February 17, 2005
	†10	.12	—	Employment Agreement between Newfield and Joe B. Foster dated January 31, 2000 (incorporated by reference to Exhibit 10 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2000 (File No. 1-12534))
	†10	.13	—	Resolution of Members Establishing the Preferences, Limitations and Relative Rights of Series “A” Preferred Shares of Huffco China, LDC dated May 14, 1997 (incorporated by reference to Exhibit 10.15 to Newfield’s Registration Statement on Form S-3 (Registration No. 333-32587))
	10	.14	—	Credit Agreement, dated as of March 16, 2004, among Newfield, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent and as Issuing Bank(incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004 (File No. 1-12534))
	*21	.1	—	List of Significant Subsidiaries
	*23	.1	—	Consent of PricewaterhouseCoopers LLP
	*31	.1	—	Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	*31	.2	—	Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	*32	.1	—	Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	*32	.2	—	Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


*	Filed or furnished herewith.


†	Identifies management contracts and compensatory plans or arrangements.


		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.

	•	G&A expense for 2003, on an Mcfe basis, before capitalized direct internal costs, increased $0.05 per Mcfe, or 14%. The increase was primarily due to an increase in the number of employees as a result of our growth and an increase in incentive compensation expense due to the significant increase in 2003 earnings. The 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.