NEWFIELD EXPLORATION CO /DE/ - 10-Q Quarterly Report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended March 31, 2005

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 (State or other jurisdiction of incorporation or organization)		72-1133047 (I.R.S. Employer Identification Number)

363 North Sam Houston Parkway East
Suite 2020
Houston, Texas 77060
(Address and Zip Code of principal executive offices)

(281) 847-6000
(Registrant’s telephone number, including area code)

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 twelve 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 ¨

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes þ No ¨

As of April 28, 2005, there were 63,199,417 shares of the Registrant’s Common Stock, par value $0.01 per share, outstanding.

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEET

(In millions, except share data)

(Unaudited)


	March 31,			December 31,
	2005			2004
ASSETS

Current assets:
Cash and cash equivalents	$	30.9		$	58.3
Accounts receivable		244.8			247.7
Inventories		16.3			7.8
Derivative assets		13.3			54.5
Deferred taxes		63.0			1.0
Other current assets		18.4			22.3

Total current assets		386.7			391.6

Oil and gas properties (full cost method, of which $866.8 at March 31, 2005 and $835.4 at December 31, 2004 were excluded from amortization)		6,156.8			5,907.8
Less—accumulated depreciation, depletion and amortization		(2,260.2	)		(2,132.5	)

		3,896.6			3,775.3


Furniture, fixtures and equipment, net		18.4			18.3
Derivative assets		19.6			55.6
Other assets		20.8			21.4
Deferred taxes		8.6			—
Goodwill		65.3			65.3

Total assets	$	4,416.0		$	4,327.5


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	41.6		$	32.5
Accrued liabilities		298.4			353.5
Advances from joint owners		19.1			18.0
Asset retirement obligation		22.7			22.9
Deferred taxes		¾			0.1
Derivative liabilities		156.8			47.0

Total current liabilities		538.6			474.0

Other liabilities		16.1			15.8
Derivative liabilities		144.8			83.1
Long-term debt		933.0			992.4
Asset retirement obligation		200.4			194.2
Deferred taxes		577.1			551.1

Total long-term liabilities		1,871.4			1,836.6


Commitments and contingencies		¾			¾

Stockholders’ equity:
Preferred stock ($0.01 par value; 5,000,000 shares authorized; no shares issued)		¾			¾
Common stock ($0.01 par value; 200,000,000 shares authorized at March 31, 2005 and December 31, 2004; 64,106,005 and 63,316,848 shares issued and outstanding at March 31, 2005 and December 31, 2004, respectively)		0.6			0.6
Additional paid-in capital		1,143.1			1,102.5
Treasury stock (at cost; 906,588 and 897,977 shares at March 31, 2005 and December 31, 2004, respectively)		(27.8	)		(27.3	)
Unearned compensation		(26.3	)		(9.5	)
Accumulated other comprehensive income (loss):
Foreign currency translation adjustment		2.4			2.6
Commodity derivatives		(93.9	)		0.1
Retained earnings		1,007.9			947.9

Total stockholders’ equity		2,006.0			2,016.9

Total liabilities and stockholders’ equity	$	4,416.0		$	4,327.5

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)

(Unaudited)


	Three Months Ended
	March 31,
	2005			2004
Cash flows from operating activities:
Net income	$	60.0		$	77.9

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		135.7			105.9
Deferred taxes		5.9			12.5
Stock compensation		1.7			1.0
Commodity derivative expense		106.6			10.8

Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		2.9			(34.0	)
Increase in inventories		(8.0	)		(0.2	)
Decrease in other current assets		10.9			27.7
(Increase) decrease in other assets		0.5			(1.8	)
Increase (decrease) in accounts payable and accrued liabilities		(52.0	)		8.1
Decrease in commodity derivative liabilities		(4.8	)		(0.2	)
Increase in advances from joint owners		1.1			11.0
Increase in other liabilities		0.2			¾

Net cash provided by operating activities		260.7			218.7


Cash flows from investing activities:
Additions to oil and gas properties		(244.4	)		(147.1	)
Additions to furniture, fixtures and equipment		(1.3	)		(0.7	)

Net cash used in investing activities		(245.7	)		(147.8	)


Cash flows from financing activities:
Proceeds from borrowings under credit arrangements		258.0			132.5
Repayments of borrowings under credit arrangements		(315.0	)		(202.5	)
Proceeds from issuance of common stock		15.2			3.6
Purchases of treasury stock		(0.5	)		(0.3	)
Repurchases of secured notes		—			(2.9	)

Net cash used in financing activities		(42.3	)		(69.6	)


Effect of exchange rate changes on cash and cash equivalents		(0.1	)		0.3


Increase (decrease) in cash and cash equivalents		(27.4	)		1.6
Cash and cash equivalents, beginning of period		58.3			15.3

Cash and cash equivalents, end of period	$	30.9		$	16.9

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)

(Unaudited)


																		Accumulated
											Additional							Other			Total
	Common Stock				Treasury Stock						Paid-in		Unearned			Retained		Comprehensive			Stockholders’
	Shares		Amount		Shares			Amount			Capital		Compensation			Earnings		Income (Loss)			Equity
Balance, December 31, 2004		63.3	$	0.6		(0.9	)	$	(27.3	)	$	1,102.5	$	(9.5	)	$	947.9	$	2.7		$	2,016.9
Issuance of common stock		0.5										15.2										15.2
Issuance of restricted stock, less amortization and cancellations		0.3										18.5		(17.8	)							0.7
Treasury stock, at cost									(0.5	)												(0.5	)
Amortization of stock compensation														1.0								1.0
Tax benefit from exercise of stock options												6.9										6.9
Comprehensive income:
Net income																	60.0					60.0
Foreign currency translation adjustment, net of tax of $0.1																			(0.2	)		(0.2	)
Reclassification adjustments for settled hedging positions, net of tax of ($0.4)																			0.8			0.8
Changes in fair value of outstanding hedging positions, net of tax of $51.0																			(94.8	)		(94.8	)

Total comprehensive income																						(34.2	)

Balance, March 31, 2005		64.1	$	0.6		(0.9	)	$	(27.8	)	$	1,143.1	$	(26.3	)	$	1,007.9	$	(91.5	)	$	2,006.0

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

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.

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.

These unaudited consolidated financial statements reflect, in the opinion of our management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly our financial position as of, and results of operations for, the periods presented. These financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the United States of America. Interim period results are not necessarily indicative of results of operations or cash flows for a full year.

These financial statements and notes should be read in conjunction with our audited consolidated financial statements and the notes thereto included in our annual report for the year ended December 31, 2004.

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 related to our proved oil and gas reserves.

Inventories

Inventories, consisting primarily of tubular goods and well equipment held for use in our oil and gas operations, are carried at the lower of average cost or market. Inventories also include oil produced but not sold. Crude oil from our operations 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 March 31, 2005 consisted of approximately 113,500 barrels of crude oil valued at $2.0 million and at December 31, 2004 consisted of approximately 49,000 barrels of crude oil valued at $0.8 million. The product inventory is carried at the lower of average cost (a combination of production costs and depreciation, depletion and amortization expense) 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.

Reclassifications

Certain reclassifications have been made to the prior year’s reported amounts in order to conform with the current year presentation. These reclassifications did not impact our financial condition, results of operations or cash flows.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Accounting for Asset Retirement Obligations

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record a liability (an “asset retirement obligation” or “ARO”) on our consolidated balance sheet and capitalize the asset retirement cost in oil and gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is 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.

The change in our ARO for the three months ended March 31, 2005 is set forth below (in millions):


Balance as of January 1, 2005	$	217.1
Accretion expense		3.3
Additions		4.0
Settlements		(1.3	)

Balance as of March 31, 2005	$	223.1

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 acquisition of Inland Resources in August 2004 and our acquisition of Primary Natural Resources (PNR) in September 2003. At March 31, 2005, $16.4 million relates to PNR and $48.9 million relates to Inland.

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 a 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.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 Financial Accounting Standards Board (FASB) Statement (SFAS) No. 123, “Accounting for Stock-Based Compensation,’’ had been applied using a Black-Scholes option pricing model, our net income and earnings per common share for the three months ended March 31, 2005 and 2004 would have approximated the pro forma amounts below:


	Three Months Ended
	March 31,
	2005		2004
	(In millions, except per
	share data)
Net income:
As reported ⁽¹⁾	$	60.0	$	77.9
Pro forma⁽²⁾		57.7		76.3

Basic earnings per common share —
As reported	$	0.96	$	1.39
Pro forma		0.93		1.36

Diluted earnings per common share —
As reported	$	0.95	$	1.38
Pro forma		0.91		1.35

(1)		Includes stock-based compensation costs, net of related tax effects, of $1.1 million and $0.5 million for the three months ended March 31, 2005 and 2004, 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 $3.4 million and $2.1 million for the three months ended March 31, 2005 and 2004, 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. 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 adoption 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 adoption date. 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 our 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 increase reported net financing cash flows in periods after the effective date. These future amounts cannot be reasonably estimated because they depend on, among other things, when employees exercise stock options.

We will adopt SFAS No. 123(R) effective as of January 1, 2006; however, we have not yet determined which of the aforementioned adoption methods we will use.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Recent Accounting Developments

In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107 on SFAS No. 123(R). See “—Stock-Based Compensation’’ above. SAB No. 107 reinforces the flexibility allowed by SFAS No. 123(R) to choose an option pricing model, provides guidance on when it would be appropriate to rely exclusively on either historical or implied volatility in estimating expected volatility and provided examples and simplified approaches to determining the expected term. In April 2005, the SEC extended the date by which companies of our size are required to adopt SFAS No. 123(R) from the first reporting period beginning on or after June 15, 2005 to the first reporting period of the first fiscal year beginning on or after June 15, 2005.

2. 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) and unvested restricted stock.

The following is the calculation of basic and diluted weighted average shares outstanding and EPS for the indicated periods:


	Three Months Ended
	March 31,
	2005		2004
	(In millions, except per
	share data)
Income (numerator):
Net income — basic	$	60.0	$	77.9

Net income — diluted	$	60.0	$	77.9


Weighted average shares (denominator):
Weighted average shares — basic		62.2		55.9
Dilution effect of stock options and unvested restricted stock outstanding at end of period		1.1		0.7

Weighted average shares — diluted		63.3		56.6


Earnings per share:
Basic	$	0.96	$	1.39

Diluted	$	0.95	$	1.38

The calculation of shares outstanding for diluted EPS for the three months ended March 31, 2005 and 2004, respectively, does not include the effect of outstanding stock options to purchase 0.1 and 0.4 million shares, because to do so would have been antidilutive.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

3. Oil and Gas Properties:

Oil and gas properties consisted of the following at the indicated dates:


	March 31,			December 31,
	2005			2004
	(In millions)
Subject to amortization	$	5,290.0		$	5,072.4
Not subject to amortization
Exploration wells in progress		59.7			59.9
Development wells in progress		67.9			38.2
Capitalized interest		47.6			39.3
Fee mineral interests		23.3			23.3
Other capital costs:
Incurred in 2005		15.4			¾
Incurred in 2004		465.0			478.4
Incurred in 2003		74.4			76.9
Incurred in 2002 and prior		113.5			119.4

Total not subject to amortization		866.8			835.4

Gross oil and gas properties		6,156.8			5,907.8
Accumulated depreciation, depletion and amortization		(2,260.2	)		(2,132.5	)

Net oil and gas properties	$	3,896.6		$	3,775.3

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 March 31, 2005 and December 31, 2004, 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 producing oil and gas property of Inland Resources. See Note 9, “Acquisitions—Inland Resources Inc.” Because of its size, evaluation of the Monument Butte Field in its entirety will take significantly longer than four years. At March 31, 2005 and December 31, 2004, $332 million and $341 million, respectively, of costs associated with the Monument Butte Field were not subject to amortization.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

4. Debt:

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


	March 31,			December 31,
	2005			2004
	(In millions)
Senior unsecured debt:
Bank revolving credit facility:
Prime rate based loans	$	¾		$	¾
LIBOR based loans ⁽¹⁾		63.0			120.0

Total bank revolving credit facility		63.0			120.0


7.45% Senior Notes due 2007		124.9			124.9
Fair value of interest rate swaps ⁽²⁾		(1.3	)		(0.6	)
7 5/8% Senior Notes due 2011		174.9			174.9
Fair value of interest rate swaps ⁽²⁾		(1.8	)		(0.1	)

Total senior unsecured notes		296.7			299.1


Total senior unsecured debt		359.7			419.1


8 3/8% Senior Subordinated Notes due 2012		248.3			248.3
6 5/8% Senior Subordinated Notes due 2014		325.0			325.0

Total long-term debt	$	933.0		$	992.4

(1)		At March 31, 2005 and December 31, 2004, the interest rates were 4.06% and 3.63%, respectively, for LIBOR based loans.

(2)		In September 2003, we hedged $50 million principal amount of our 7.45% Senior Notes due 2007 and $50 million principal amount of our 7 5/8% Senior Notes due 2011. The hedges provide for us to pay variable and receive fixed interest payments.

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 March 31, 2005) and 30% of the principal amount of any outstanding senior subordinated notes (a reduction of $172.5 million at March 31, 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 March 31, 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. On March 31, 2005, we had outstanding borrowings and letters of credit under our credit facility of $63 million and $25 million, respectively, and no outstanding borrowings under our money market lines. Consequently, at March 31, 2005, we had approximately $563 million of available capacity under our credit arrangements.

5. Contingencies:

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.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

6. 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 of and for the three months ended March 31, 2005 and 2004. 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)
Three Months Ended March 31, 2005:
Oil and gas revenues	$	402.6	$	0.4	$	10.1	$	¾	$	413.1

Operating expenses:
Lease operating		40.8		0.2		2.2		¾		43.2
Production and other taxes		10.5		¾		0.6		¾		11.1
Transportation		2.4		¾		¾		¾		2.4
Depreciation, depletion and amortization		133.8		0.2		1.7		¾		135.7
Allocated income taxes		75.3		¾		2.1		¾

Net income from oil and gas properties	$	139.8	$	¾	$	3.5	$	¾


General and administrative										22.8

Total operating expenses										215.2

Income from operations										197.9
Interest expense, net of interest income, capitalized interest and other										(6.6	)
Commodity derivative expense										(108.9	)

Income before income taxes									$	82.4


Total long-lived assets	$	3,744.3	$	46.1	$	56.0	$	50.2	$	3,896.6


Additions to long-lived assets	$	231.4	$	20.1	$	1.4	$	1.2	$	254.1

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	United		United				Other
	States		Kingdom		Malaysia		International		Total
	(In millions)
Three Months Ended March 31, 2004:
Oil and gas revenues	$	304.4	$	1.0	$	¾	$	¾	$	305.4

Operating expenses:
Lease operating		29.6		0.3		¾		¾		29.9
Production and other taxes		8.4		¾		¾		¾		8.4
Transportation		1.4		¾		¾		¾		1.4
Depreciation, depletion and amortization		105.5		0.4		¾		¾		105.9
Allocated income taxes		55.8		0.1		¾		¾

Net income from oil and gas properties	$	103.7	$	0.2	$	¾	$	¾


General and administrative										18.6

Total operating expenses										164.2

Income from operations										141.2
Interest expense, net of interest income, capitalized interest and other										(8.0	)
Commodity derivative expense										(12.2	)

Income before income taxes									$	121.0


Total long-lived assets	$	2,411.4	$	11.7	$	¾	$	44.6	$	2,467.7


Additions to long-lived assets	$	149.1	$	0.5	$	¾	$	2.7	$	152.3

7. 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.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 oil three-way contracts of $2.3 million and $1.5 million for the three months ended March 31, 2005 and 2004, respectively. No gas three-way contracts were settled for the three months ended March 31, 2005 and 2004.

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

On the date we enter into a derivative contract, we determine whether the derivative qualifies for hedge accounting under SFAS No. 133. 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 March 31, 2005, we had a net $93.9 million after-tax loss 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 $84.6 million to be sold within the next 12 months and hedged production associated with a remaining net loss of approximately $9.3 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.

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

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Natural Gas

As of March 31, 2005, 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														Estimated
					Collars												Fair Value
			Swaps		Floors				Ceiling				Floor Contracts				Asset
	Volume in		(Weighted				Weighted				Weighted				Weighted		(Liability)
Period and Type of Contract	MMMBtus		Average)		Range		Average		Range		Average		Range		Average		(In millions)
April 2005 – June 2005
Price swap contracts		10,660	$	6.36		¾		¾		¾		¾		¾		¾	$	(12.6	)
Collar contracts		18,495		¾	$	3.50 - $6.24	$	5.74	$	4.16 - $9.00	$	7.87		¾		¾		(5.3	)
Floor contracts		9,600		¾		¾		¾		¾		¾	$	5.50 - $6.50	$	5.75		2.2
July 2005 – September 2005
Price swap contracts		11,806		6.40		¾		¾		¾		¾		¾		¾		(17.4	)
Collar contracts		18,495		¾		3.50 - 6.24		5.74		4.16 - 9.00		7.87		¾		¾		(12.2	)
Floor contracts		10,800		¾		¾		¾		¾		¾		5.50 - 6.50		5.84		2.5
October 2005 – December 2005
Price swap contracts		7,225		6.08		¾		¾		¾		¾		¾		¾		(14.7	)
Collar contracts		7,995		¾		3.50 - 6.24		5.69		4.16 - 10.00		8.19		¾		¾		(6.9	)
Floor contracts		3,600		¾		¾		¾		¾		¾		5.50 - 6.50		5.84		1.1
January 2006 – December 2006
Collar contracts		2,400		¾		5.80		5.80		10.00		10.00		¾		¾		(2.1	)

																	$	(65.4	)

As of March 31, 2005, we also had entered into three-way collar contracts with respect to our future natural gas production as set forth in the table below. These contracts do not qualify for hedge accounting.


			NYMEX Contract Price Per MMBtu												Estimated
							Collars								Fair Value
			Additional Put				Floors				Ceilings				Asset
	Volume in				Weighted				Weighted				Weighted		(Liability)
Period and Type of Contract	MMMBtus		Range		Average		Range		Average		Range		Average		(In millions)
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	$	(2.0	)
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		(4.9	)
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		(2.5	)
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		(1.7	)

															$	(11.1	)

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Oil

As of March 31, 2005, 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										Estimated
					Collars								Fair Value
			Swaps		Floors				Ceilings				Asset
	Volume in		(Weighted				Weighted				Weighted		(Liability)
Period and Type of Contract	MBbls		Average)		Range		Average		Range		Average		(In millions)
April 2005 – June 2005
Price swap contracts		631	$	33.21		¾		¾		¾		¾	$	(14.6	)
Collar contracts		828		¾	$	27.00 - $45.00	$	37.82	$	30.65 - $64.00	$	53.23		(5.8	)
July 2005 – September 2005
Price swap contracts		635		33.25		¾		¾		¾		¾		(15.0	)
Collar contracts		681		¾		35.60 - 45.00		40.20		48.00 - 64.00		57.45		(3.2	)
October 2005 – December 2005
Price swap contracts		635		33.25		¾		¾		¾		¾		(14.5	)
Collar contracts		681		¾		35.60 - 45.00		40.20		48.00 - 64.00		57.45		(3.4	)
January 2006 – December 2006
Price swap contracts		1,534		31.64		—		—		—		—		(34.2	)
January 2007 – December 2007
Price swap contracts		240		27.00		—		—		—		—		(5.9	)

													$	(96.6	)

As of March 31, 2005, 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												Estimated
							Collars								Fair Value
			Additional Put				Floors				Ceilings				Asset
	Volume in				Weighted				Weighted				Weighted		(Liability)
Period and Type of Contract	MBbls		Range		Average		Range		Average		Range		Average		(In millions)
April 2005 – June 2005
3-Way collar contracts		302	$	30.00 - $40.00	$	33.97	$	35.00 - $46.00	$	39.62	$	49.00 - $51.25	$	50.08	$	(2.2	)
July 2005 – September 2005
3-Way collar contracts		304		30.00 - 40.00		33.95		35.00 - 46.00		39.60		49.00 - 51.25		50.08		(2.6	)
October 2005 – December 2005
3-Way collar contracts		304		30.00 - 40.00		33.95		35.00 - 46.00		39.60		49.00 - 51.25		50.08		(2.7	)
January 2006 – December 2006
3-Way collar contracts		1,006		30.00		30.00		35.00 - 36.00		35.27		50.50 - 55.00		51.74		(7.7	)
January 2007 – December 2007
3-Way collar contracts		2,920		25.00 - 29.00		26.50		32.00 - 35.00		33.00		44.70 - 52.80		50.19		(20.5	)
January 2008 – December 2008
3-Way collar contracts		3,294		25.00 - 29.00		26.56		32.00 - 35.00		33.00		49.50 - 52.90		50.29		(20.3	)
January 2009 – December 2009
3-Way collar contracts		3,285		25.00 - 30.00		27.00		32.00 - 36.00		33.33		50.00 - 54.55		50.62		(18.2	)
January 2010 – December 2010
3-Way collar contracts		3,645		25.00 - 32.00		28.60		32.00 - 38.00		34.90		50.00 - 53.50		51.52		(18.4	)

															$	(92.6	)

8. Accrued Liabilities:

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


	March 31,		December 31,
	2005		2004
	(In millions)
Revenue payable	$	75.7	$	108.7
Accrued capital costs		90.7		100.4
Accrued lease operating expense		23.2		25.9
Employee incentive expense		42.4		44.9
Accrued interest on notes		9.8		22.2
Taxes payable		21.0		14.4
Deferred acquisition payments		13.7		17.0
Other		21.9		20.0

Total accrued liabilities	$	298.4	$	353.5

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

9. Acquisitions:

Malaysia PSCs

In May 2004, we entered into production sharing contracts with Malaysia’s state-owned oil company with respect to two offshore blocks. The consideration for our interests was comprised of a one-time reimbursement of sunk costs of $38.5 million, a deferred payment of $10.5 million and exploration commitments of $30.5 million. The reimbursement of the sunk costs was financed through cash on hand and borrowings under our credit arrangements.

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 $55 million and a deferred payment of approximately $3.5 million due in 2006. These acquisitions were financed through cash on hand and borrowings under our credit arrangements.

Denbury Offshore, Inc.

In July 2004, we acquired Denbury Offshore, Inc., the subsidiary of Denbury Resources Inc. that held substantially all of its Gulf of Mexico assets, for approximately $174 million. The acquisition was financed through cash on hand and borrowings under our credit arrangements.

Inland Resources Inc.

In August 2004, we acquired Inland Resources for $575 million. Inland’s sole producing 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 6 5/8% Senior Subordinated Notes due 2014.

Pro Forma Results

The unaudited pro forma results presented below for the three months ended March 31, 2004 have been prepared to give effect to our 2004 acquisitions and the issuance of our common stock and notes on our results of operations under the purchase method of accounting as if they had been consummated on January 1, 2004. 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.


	Three Months
	Ended
	March 31, 2004
	(Unaudited)
	(In millions, except
	per share data)
Pro forma:
Revenue	$	345.4
Income from operations		154.5
Net income		89.3
Basic earnings per share	$	1.46
Diluted earnings per share	$	1.44

10. Income Taxes:

In 2004, we recorded a valuation allowance of $7.8 million for a United Kingdom deferred tax asset related to a net operating loss (NOL) carryforward. During the first quarter of 2005, as a result of a substantial increase in estimated future taxable income resulting from our Grove discovery in the U.K. North Sea, the entire valuation allowance was reversed.

11. Subsequent Event:

As a result of our acquisition of EEX Corporation in November 2002, we owned 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. At the time of acquisition, we estimated the fair value of these assets to be $35 million.

Item 2. 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 Item 7 of our annual report for the year ended December 31, 2004 for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations. This report should be read together with those discussions.

Results of Operations

In May 2004, we entered into production sharing contracts with Malaysia’s state-owned oil company with respect to two offshore blocks. Liftings of oil production began during the third quarter of 2004. Prior thereto, our producing international operations consisted of one field in the U.K. North Sea.

Revenues. 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 period to period as a result of changes in commodity prices or production volumes. Oil and gas revenues for the first quarter of 2005 were 35% higher than the comparable period of 2004 due to higher commodity prices and higher production.


	Three Months Ended				Percentage
	March 31,				Increase
	2005		2004		(Decrease)
Production ⁽¹⁾:
United States:
Natural gas (Bcf)		51.2		47.9		7	%
Oil and condensate (MBbls)		2,040		1,543		32	%
Total (Bcfe)		63.4		57.2		11	%
International:
Natural gas (Bcf)		—		0.2		N/M	⁽³⁾
Oil and condensate (MBbls)		231		4		N/M	⁽³⁾
Total (Bcfe)		1.5		0.2		N/M	⁽³⁾
Total:
Natural gas (Bcf)		51.2		48.1		6	%
Oil and condensate (MBbls)		2,271		1,547		47	%
Total (Bcfe)		64.9		57.4		13	%

Average Realized Prices ⁽²⁾:
United States:
Natural gas (per Mcf)	$	6.23	$	5.33		17	%
Oil and condensate (per Bbl)		40.90		31.98		28	%
Natural gas equivalent (per Mcfe)		6.34		5.33		19	%
International:
Natural gas (per Mcf)	$	5.01	$	4.03		24	%
Oil and condensate (per Bbl)		43.87		33.00		33	%
Natural gas equivalent (per Mcfe)		7.19		4.19		72	%
Total:
Natural gas (per Mcf)	$	6.22	$	5.32		17	%
Oil and condensate (per Bbl)		41.20		31.98		29	%
Natural gas equivalent (per Mcfe)		6.36		5.32		20	%

(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 effect of these contracts, our average realized price for total oil and condensate would have been $40.20 per Bbl and $31.03 per Bbl for the first quarter of 2005 and 2004, respectively. No three-way gas contracts settled in the first quarter of 2005 or 2004.

(3)		Not meaningful.

Production. Our total oil and gas production (stated on a natural gas equivalent basis) for the first quarter of 2005 increased 13% over the comparable period of 2004. The increase primarily was the result of our Oklahoma property and Denbury Offshore acquisitions in July 2004, the Inland Resources acquisition in August 2004, liftings in Malaysia and successful drilling efforts. These increases were partially offset by natural field declines.

Natural Gas. Our first quarter of 2005 natural gas production increased 6% when compared to the same period of 2004. The increase primarily was the result of our Oklahoma property and Denbury Offshore acquisitions and successful drilling efforts, partially offset by natural field declines.

Crude Oil and Condensate. Our first quarter of 2005 oil and condensate production increased 47% when compared to the same period of 2004 primarily due to liftings in Malaysia and the acquisition of Inland Resources in the third quarter of 2004 partially offset by natural field declines.

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


	Average				Ratio of
	Realized Prices				Hedged to
	With		Without		Non-Hedged
	Hedge⁽¹⁾		Hedge		Price⁽²⁾
Natural Gas:
Three months ended March 31, 2005	$	6.22	$	6.06		103	%
Three months ended March 31, 2004		5.32		5.45		98	%

Crude Oil and Condensate:
Three months ended March 31, 2005	$	41.20	$	47.17		87	%
Three months ended March 31, 2004		31.98		34.41		93	%

(1)		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 effect of these contracts, our average realized price for total oil and condensate would have been $40.20 per Bbl and $31.03 per Bbl for the first quarter of 2005 and 2004, respectively. No three-way gas contracts settled in the first quarter of 2005 or 2004.

(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 from period to period in our operating expenses is on a unit-of-production, or per Mcfe, basis.

The following table presents information about our operating expenses for the first quarter of 2005 and 2004.


	Unit-of-Production							Amount
	(Per Mcfe)							(In millions)
	Three Months Ended				Percentage			Three Months Ended				Percentage
	March 31,				Increase			March 31,				Increase
	2005		2004		(Decrease)			2005		2004		(Decrease)
United States:
Lease operating	$	0.64	$	0.52		23	%	$	40.8	$	29.6		38	%
Production and other taxes		0.17		0.15		13	%		10.5		8.4		25	%
Transportation		0.04		0.03		33	%		2.4		1.4		71	%
Depreciation, depletion and amortization		2.11		1.85		14	%		133.8		105.5		27	%
General and administrative		0.35		0.32		9	%		22.3		18.3		22	%

Total operating expenses	$	3.31	$	2.87		15	%	$	209.8	$	163.2		29	%
International:
Lease operating	$	1.61	$	1.16		N/M	⁽¹⁾	$	2.4	$	0.3		N/M	⁽¹⁾
Production and other taxes		0.40		—		N/M	⁽¹⁾		0.6		—		N/M	⁽¹⁾
Depreciation, depletion and amortization		1.29		1.59		N/M	⁽¹⁾		1.9		0.4		N/M	⁽¹⁾
General and administrative		0.39		1.09		N/M	⁽¹⁾		0.5		0.3		N/M	⁽¹⁾

Total operating expenses	$	3.69	$	3.84		N/M	⁽¹⁾	$	5.4	$	1.0		N/M	⁽¹⁾
Total:
Lease operating	$	0.67	$	0.52		29	%	$	43.2	$	29.9		44	%
Production and other taxes		0.17		0.15		13	%		11.1		8.4		32	%
Transportation		0.04		0.03		33	%		2.4		1.4		71	%
Depreciation, depletion and amortization		2.09		1.85		13	%		135.7		105.9		28	%
General and administrative		0.35		0.32		9	%		22.8		18.6		23	%

Total operating expenses	$	3.32	$	2.87		16	%	$	215.2	$	164.2		31	%

(1)

Not meaningful.

Domestic Operations. Our domestic operating expenses for the first quarter of 2005, stated on an Mcfe basis, increased 15% over the same period of 2004. This increase was primarily related to the following items:

•   Lease operating expense (LOE), on an Mcfe basis, in the first quarter of 2005 was more than LOE in the same period of 2004 as a result of higher operating costs, well workover activity and natural field declines in our Gulf of Mexico properties.

•   Production and other taxes, on an Mcfe basis, increased in the first quarter of 2005 as compared to the same period of 2004 due to higher commodity prices and an increase in our production volumes subject to production taxes as a result of our acquisition of Inland Resources and increased production in the Mid-Continent and onshore Gulf Coast.

•   Depreciation, depletion and amortization (DD&A) (excluding furniture, fixtures and equipment) for the first quarter of 2005 was $2.09 per Mcfe versus $1.83 per Mcfe for the comparable period of 2004. The increase resulted from higher cost reserve additions during 2004 and the first quarter of 2005. The component of DD&A associated with accretion expense related to SFAS No. 143 was $0.05 per Mcfe for the first quarter of 2005 and $0.04 per Mcfe for the first quarter of 2004.

•   General and administrative (G&A) expense, on an Mcfe basis, increased $0.03 per Mcfe, or 9%. The increase was primarily due to growth in our domestic workforce as a result of acquisitions and an increase in incentive compensation as a result of higher adjusted net income (as defined in our incentive compensation plan) in the first quarter of 2005 as compared to the prior year. Adjusted net income for purposes of our incentive compensation plan excludes unrealized gains and losses on commodity derivatives. During the first quarter of 2005, we capitalized $10.3 million of direct internal costs compared to $5.9 million in the first quarter of 2004.

International Operations. The majority of LOE, production and other taxes and DD&A for the first quarter of 2005 relates to our Malaysian operations. G&A expense is primarily associated with our U.K. North Sea operations.

Interest Expense. The following table presents information about our interest expense for the first quarter of 2005 compared to the same period of the prior year.


	Three Months Ended
	March 31,
	2005			2004
	(In millions)
Gross interest expense	$	18.0		$	12.5
Capitalized interest		(11.4	)		(3.9	)

Total interest expense	$	6.6		$	8.6

Gross Interest Expense. The components of gross interest expense for the three months ended March 31, 2005 and 2004 are as follows:


	Three Months Ended
	March 31,
	2005			2004
	(In millions)
Credit arrangements	$	1.3		$	0.9
Senior and senior subordinated notes		16.8			11.3
Interest rate swaps		(0.3	)		(0.6	)
Other		0.2			0.9

Gross interest expense	$	18.0		$	12.5

Average outstanding borrowings under our credit arrangements during the three months ended March 31, 2005 were about 11% higher than during the same period of 2004 and the weighted average interest rate was slightly higher during the first quarter of 2005 compared to the same period of 2004. During the second half of 2004, we financed the cash consideration for our Oklahoma property and Denbury Offshore acquisitions (approximately $226 million) primarily with borrowings under our credit arrangements. In addition, in August 2004, we issued $325 million principal amount of our 6 5/8% Senior Subordinated Notes due 2014 in connection with our acquisition of Inland Resources.

Capitalized Interest. We capitalize interest with respect to unproved properties. Interest capitalized in the first quarter of 2005 increased over the first quarter of 2004 primarily due to an increase in our unproved property base as a result of our acquisition of Inland Resources.

Commodity Derivative Expense. The following table presents information about the components of commodity derivative expense for the first quarter of 2005 compared to the same period of the prior year.


	Three Months Ended
	March 31,
	2005			2004
	(In millions)
Cash Flow Hedges:
Hedge ineffectiveness	$	(9.0	)	$	(0.8	)
Three-Way Collar Contracts:
Unrealized (loss) due to changes in fair market value		(97.6	)		(9.9	)
Realized (loss) on settlement		(2.3	)		(1.5	)

Total commodity derivative (expense)	$	(108.9	)	$	(12.2	)

Hedge ineffectiveness is associated with our hedging contracts that qualify for hedge accounting under SFAS No. 133. 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 first quarter of 2005 and 2004 were 27.2% and 35.6%, respectively. The effective tax rate for the first quarter of 2005 was less than the federal statutory tax rate because the valuation allowance on our U.K. net operating loss carryforwards was reduced by $7.8 million primarily because of a substantial increase in estimated future taxable income as a result of our Grove discovery in the U.K. North Sea. The effective tax rate for the first quarter of 2004 was more than the federal statutory tax rate primarily due to state income taxes. Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, the timing and amount of future production and future operating expenses and capital costs.

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 reserves 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. We have 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 April 28, 2005) and 30% of the principal amount of any outstanding senior subordinated notes (a reduction of $172.5 million at April 28, 2005). The borrowing base is redetermined at least semi-annually and, after all required adjustments, exceeded the facility amount by $175 million and therefore was limited to $600 million at April 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 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 April 28, 2005, we had outstanding borrowings and letters of credit under our credit facility of approximately $110.1 million and no borrowings under our money market lines. Consequently, at April 28, 2005, we had approximately $540 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 $151.9 million as of March 31, 2005. This compares to a working capital deficit of $82.4 million as of December 31, 2004. Our working capital is affected by fluctuations in the fair value of our commodity derivative instruments. As of March 31, 2005, we had a net short-term derivative liability of $143.5 million compared to a net short-term derivative asset of $7.5 million at December 31, 2004.

Cash Flows from 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 “Oil and Gas Hedging” below. 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 are impacted by changes in working capital and are not affected by DD&A.

Our net cash flow from operations was $260.7 million for the three months ended March 31, 2005, a 19% increase over the same period of the prior year. The increase was due to a 20% increase in our realized oil and gas prices (on a natural gas equivalent basis), a 13% increase in production volumes primarily due to our acquisitions during 2004 and the timing of payments and increased working capital requirements during the first quarter of 2005.

Capital Expenditures. Our capital spending for the first quarter of 2005 was $254 million. This includes $164 million in domestic development, $54 million in domestic exploration, $13 million in other domestic leasehold activity and $23 million internationally. Our capital spending for the first quarter of 2004 was $152 million.

Our current budget for capital spending in 2005, excluding acquisitions, is $950 million. 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 flow used in financing activities for the three months ended March 31, 2005 was $42.3 million compared to $69.6 million of net cash flow used in financing activities for the same period of 2004. During the three months ended March 31, 2005, we repaid a net $57 million under our credit arrangements and received proceeds of $15.2 million from the issuance of shares of our common stock. During the three months ended March 31, 2004, we repaid a net $70 million under our credit arrangements.

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.

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.

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 7, “Commodity Derivative Instruments and Hedging Activities,” to our consolidated financial statements appearing earlier in this report for a description of the accounting applicable to our hedging program and a listing of open contracts as of March 31, 2005 and the fair value of those contracts as of that date.

Between March 31, 2005 and April 27, 2005, we entered into additional natural gas three-way collar contracts set forth in the table below. These contracts do not qualify for hedge accounting.


			NYMEX Contract Price Per MMBtu
							Collars
			Additional Put				Floors				Ceilings
	Volume in				Weighted				Weighted				Weighted
Period and Type of Contract	MMMBtus		Range		Average		Range		Average		Range		Average
October 2005 – December 2005
3-Way collar contracts		1,700	$	6.00	$	6.00	$	7.00	$	7.00	$	13.70 - $14.50	$	14.08
January 2006 – March 2006
3-Way collar contracts		2,550		6.00		6.00		7.00		7.00		13.70 - 14.50		14.08

New Accounting Standards

In December 2004, the FASB issued SFAS No. 123 (revised 2004), "Share-Based Payment." SFAS No. 123(R) requires companies to recognize on their income statement the cost of employee services received in exchange for stock options and other equity awards based on the fair value of such awards on the date of grant. We will adopt the provisions of this pronouncement beginning with the first quarter of 2006. We have not completed our evaluation of the impact of SFAS No. 123(R) on our financial statements.

General Information

General information about us can be found at www.newfld.com. In conjunction with our web page, we also maintain an electronic publication entitled @NFX. @NFX is periodically published to provide updates on our operating activities and our latest publicly announced estimates of expected production volumes, costs and expenses for the then current quarter. Recent editions of @NFX are available on our web page. To receive @NFX directly by email, please forward your email address to info@newfld.com or visit our web page and sign up. Unless specifically incorporated, the information about us at www.newfld.com or in any edition of @NFX is not part of this report.

Our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission.

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 funding of capital expenditures and anticipated cash flows. 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; and

•   the availability of capital resources.

Commonly Used Oil and Gas Terms

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

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 of natural 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.

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 other liquid hydrocarbons.

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

MMBtu. One million Btus.

MMMBtu. One billion Btus.

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 other liquid hydrocarbons.

NYMEX. The New York Mercantile Exchange.

Item 3. 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 2 of this report.

Interest Rates

At March 31, 2005, our long-term debt was comprised of:


	Fixed		Variable
	Rate Debt		Rate Debt
	(In millions)
Bank revolving credit facility⁽¹⁾	$	—	$	63
7.45% Senior Notes due 2007⁽²⁾		75		50
7 5/8% Senior Notes due 2011⁽²⁾		125		50
8 3/8% Senior Subordinated Notes due 2012		250		—
6 5/8% Senior Subordinated Notes due 2014		325		—

Total long-term debt	$	775	$	163

(1)		At March 31, 2005, the interest rate for our LIBOR based loans under our credit facility was 4.06%.

(2)		As of March 31, 2005, $50 million principal amount of our 7.45% Senior Notes due 2007 and $50 million principal amount of our 7 5/8% Senior Notes due 2011 were subject to interest rate swaps. 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 as of March 31, 2005 to be minimal because about 83% of our long-term debt obligations, after taking into account our interest rate swap agreements, were at fixed rates.

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 March 31, 2005.

Item 4. 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 March 31, 2005 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.

PART II

Item 1. Legal Proceedings

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

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table sets forth certain information with respect to repurchases of our equity securities during the three months ended March 31, 2005.


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

January 1 – January 31, 2005		—		—		—		—
February 1 – February 28, 2005		8,611	$	65.35		—		—
March 1 – March 31, 2005		—		—		—		—

(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. Exhibits and Reports on Form 8-K

(a) Exhibits:


Exhibit Number		Description
	31.1	Certification of Chief Executive Officer of Newfield 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 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 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 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(b) Reports on Form 8-K:

On March 29, 2005, we filed a Current Report on Form 8-K to provide the information required by Regulation BTR with respect to our 401(k) plan.

On February 22, 2005, we filed a Current Report on Form 8-K to disclose that we had entered into change of control severance agreements with certain of our executive officers and adopted a change of control severance plan.

On February 11, 2005, we filed a Current Report on Form 8-K to furnish our press releases dated February 9, 2005 announcing significant exploration discoveries in the North Sea, deepwater Gulf of Mexico and onshore Gulf Coast and our fourth quarter and full-year 2004 financial and operating results. In addition, we disclosed that our executive officers had been granted restricted stock awards and that three of our directors were retiring or would not stand for reelection at our 2005 annual meeting of stockholders.


	NEWFIELD EXPLORATION COMPANY
Date: April 29, 2005	By:	/s/ TERRY W. RATHERT
		Terry W. Rathert
		Senior Vice President and Chief Financial Officer

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


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


		Page
	PART I
Item 1.	Unaudited Financial Statements:
	Consolidated Balance Sheet as of March 31, 2005 and December 31, 2004		1
	Consolidated Statement of Income for the three months ended March 31, 2005 and 2004		2
	Consolidated Statement of Cash Flows for the three months ended March 31, 2005 and 2004		3
	Consolidated Statement of Stockholders’ Equity for the three months ended March 31, 2005		4
	Notes to Consolidated Financial Statements		5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		26
Item 4.	Controls and Procedures		26
	PART II
Item 1.	Legal Proceedings		28
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		28
Item 6.	Exhibits and Reports on Form 8-K		28
Certification of CEO pursuant to Section 302
Certification of CFO pursuant to Section 302
Certification of CEO pursuant to Section 906
Certification of CFO pursuant to Section 906


	Three Months Ended
	March 31
	2005			2004
Oil and gas revenues	$	413.1		$	305.4


Operating expenses:
Lease operating		43.2			29.9
Production and other taxes		11.1			8.4
Transportation		2.4			1.4
Depreciation, depletion and amortization		135.7			105.9
General and administrative		22.8			18.6

Total operating expenses		215.2			164.2


Income from operations		197.9			141.2

Other income (expenses):
Interest expense		(18.0	)		(12.5	)
Capitalized interest		11.4			3.9
Commodity derivative expense		(108.9	)		(12.2	)
Other		—			0.6

		(115.5	)		(20.2	)


Income before income taxes		82.4			121.0

Income tax provision:
Current		16.5			30.6
Deferred		5.9			12.5

		22.4			43.1


Net income	$	60.0		$	77.9


Earnings per share:
Basic	$	0.96		$	1.39

Diluted	$	0.95		$	1.38


Weighted average number of shares outstanding for basic earnings per share		62.2			55.9


Weighted average number of shares outstanding for diluted earnings per share		63.3			56.6

	•	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.

	•	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.

	•	Lease operating expense (LOE), on an Mcfe basis, in the first quarter of 2005 was more than LOE in the same period of 2004 as a result of higher operating costs, well workover activity and natural field declines in our Gulf of Mexico properties.

	•	Production and other taxes, on an Mcfe basis, increased in the first quarter of 2005 as compared to the same period of 2004 due to higher commodity prices and an increase in our production volumes subject to production taxes as a result of our acquisition of Inland Resources and increased production in the Mid-Continent and onshore Gulf Coast.

	•	Depreciation, depletion and amortization (DD&A) (excluding furniture, fixtures and equipment) for the first quarter of 2005 was $2.09 per Mcfe versus $1.83 per Mcfe for the comparable period of 2004. The increase resulted from higher cost reserve additions during 2004 and the first quarter of 2005. The component of DD&A associated with accretion expense related to SFAS No. 143 was $0.05 per Mcfe for the first quarter of 2005 and $0.04 per Mcfe for the first quarter of 2004.

	•	General and administrative (G&A) expense, on an Mcfe basis, increased $0.03 per Mcfe, or 9%. The increase was primarily due to growth in our domestic workforce as a result of acquisitions and an increase in incentive compensation as a result of higher adjusted net income (as defined in our incentive compensation plan) in the first quarter of 2005 as compared to the prior year. Adjusted net income for purposes of our incentive compensation plan excludes unrealized gains and losses on commodity derivatives. During the first quarter of 2005, we capitalized $10.3 million of direct internal costs compared to $5.9 million in the first quarter of 2004.

	•	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; and

	•	the availability of capital resources.