Edgar Filing: NEWFIELD EXPLORATION CO /DE/

e10vq

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 June 30, 2007


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 or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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 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 whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ Accelerated filer o Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o No þ

As of August 1, 2007, there were 130,463,308 shares of the Registrant’s Common Stock, par value $0.01 per share, outstanding.

TABLE OF CONTENTS


		Page
	PART I

Item 1.	Unaudited Financial Statements:

	Consolidated Balance Sheet as of June 30, 2007 and December 31, 2006		1

	Consolidated Statement of Income for the three and six months ended June 30, 2007 and 2006		2

	Consolidated Statement of Cash Flows for the six months ended June 30, 2007 and 2006		3

	Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2007		4

	Notes to Consolidated Financial Statements		5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		31

Item 4.	Controls and Procedures		32

	PART II

Item 1.	Legal Proceedings		33

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		33

Item 4.	Submission of Matters to a Vote of Security Holders		33

Item 5.02	Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers		34

Item 6.	Exhibits		35
Amendment No.2 to Newfield Employee 1993 Incentive Compensation Plan
2nd Amended and Restated Newfield Exploration Co. 2003 Incentive Compensation Plan
Newfield Exploration Co. Deferred Compensation Plan as Amended and Restated as of July 26, 2007
2nd Amended and Restated Newfield Exploration Co. Change of Control Severance Agreement
Form of 2nd Amended and Restated Change of Control Severance Agreement
Amended and Restated Change of Control Severance Agreement
2nd Amended and Restated Change of Control Severance Agreement
Form of 2nd Amended and Restated Change of Control Severance Agreement
Form of Amended and Restated Change of Control Severance Agreement
Form of Restricted Stock Agreement
Credit Agreement
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 1350
Certification of CFO Pursuant to Section 1350

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEET

(In millions, except share data)

(Unaudited)


	June 30,			December 31,
	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	37		$	80
Short-term investments		¾			10
Accounts receivable		419			378
Inventories		68			44
Derivative assets		127			280
Other current assets		90			59

Total current assets		741			851

Oil and gas properties (full cost method, of which $1,292 at June 30, 2007 and $1,002 at December 31, 2006 were excluded from amortization)		10,419			8,890
Less—accumulated depreciation, depletion and amortization		(3,607	)		(3,235	)

		6,812			5,655


Furniture, fixtures and equipment, net		34			28
Derivative assets		10			19
Other assets		24			20
Goodwill		62			62

Total assets	$	7,683		$	6,635

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	104		$	59
Current debt		124			124
Accrued liabilities		618			667
Advances from joint owners		40			90
Asset retirement obligation		35			40
Derivative liabilities		101			80
Deferred taxes		10			63

Total current liabilities		1,032			1,123

Other liabilities		31			28
Derivative liabilities		181			179
Long-term debt		1,979			1,048
Asset retirement obligation		246			232
Deferred taxes		1,060			963

Total long-term liabilities		3,497			2,450


Commitments and contingencies (Note 5)		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 June 30, 2007 and December 31, 2006; 132,264,849 and 131,063,555 shares issued and outstanding at June 30, 2007 and December 31, 2006, respectively)		1			1
Additional paid-in capital		1,231			1,198
Treasury stock (at cost; 1,887,585 and 1,879,874 shares at June 30, 2007 and December 31, 2006, respectively)		(32	)		(30	)
Accumulated other comprehensive income (loss):
Foreign currency translation adjustment		17			14
Commodity derivatives		(1	)		(5	)
Minimum pension liability		(3	)		(3	)
Retained earnings		1,941			1,887

Total stockholders’ equity		3,154			3,062

Total liabilities and stockholders’ equity	$	7,683		$	6,635

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)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Oil and gas revenues	$	528		$	390		$	968		$	821


Operating expenses:
Lease operating		96			67			208			119
Production and other taxes		20			15			38			31
Depreciation, depletion and amortization		198			144			378			275
General and administrative		33			28			72			58
Ceiling test writedown		¾			¾			47			¾
Other		¾			25			¾			(5	)

Total operating expenses		347			279			743			478


Income from operations		181			111			225			343


Other income (expense):
Interest expense		(28	)		(24	)		(51	)		(42	)
Capitalized interest		11			10			22			22
Commodity derivative income (expense)		77			46			(81	)		52
Other		1			4			2			5

		61			36			(108	)		37


Income before income taxes		242			147			117			380


Income tax provision:
Current		11			1			20			12
Deferred		81			52			43			125

		92			53			63			137


Net income	$	150		$	94		$	54		$	243


Earnings per share:
Basic	$	1.17		$	0.74		$	0.42		$	1.92

Diluted	$	1.15		$	0.73		$	0.41		$	1.89


Weighted average number of shares outstanding for basic earnings per share		127			127			127			126


Weighted average number of shares outstanding for diluted earnings per share		130			129			130			129

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)


	Six Months Ended
	June 30,
	2007			2006
Cash flows from operating activities:
Net income	$	54		$	243

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		378			275
Deferred taxes		43			125
Stock-based compensation		10			16
Early redemption premium		¾			8
Commodity derivative (income) expense
Total (gains) losses		81			(52	)
Realized gains		113			35
Ceiling test writedown		47			¾

Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(30	)		104
Increase in inventories		(23	)		(7	)
Increase in other current assets		(31	)		(46	)
Increase in other assets		(5	)		(4	)
Increase (decrease) in accounts payable and accrued liabilities		48			(6	)
Decrease in commodity derivative liabilities		(2	)		(15	)
Increase (decrease) in advances from joint owners		(50	)		13
Increase in other liabilities		2			3

Net cash provided by operating activities		635			692


Cash flows from investing activities:
Acquisition of oil and gas properties		(578	)		—
Additions to oil and gas properties		(1,088	)		(836	)
Proceeds from sale of oil and gas properties		23			—
Additions to furniture, fixtures and equipment		(8	)		(2	)
Purchases of short-term investments		¾			(484	)
Redemption of short-term investments		24			352

Net cash used in investing activities		(1,627	)		(970	)


Cash flows from financing activities:
Proceeds from borrowings under credit arrangements		2,219			342
Repayments of borrowings under credit arrangements		(1,287	)		(342	)
Proceeds from issuance of senior subordinated notes		¾			550
Repayment of senior subordinated notes		¾			(250	)
Proceeds from issuances of common stock		13			8
Stock-based compensation excess tax benefit		4			3
Purchases of treasury stock		¾			(4	)

Net cash provided by financing activities		949			307


Effect of exchange rate changes on cash and cash equivalents		¾			5


Increase (decrease) in cash and cash equivalents		(43	)		34
Cash and cash equivalents, beginning of period		80			39

Cash and cash equivalents, end of period	$	37		$	73

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		Retained		Comprehensive			Stockholders’
	Shares		Amount		Shares			Amount			Capital		Earnings		Income (Loss)			Equity
Balance, December 31, 2006		131.1	$	1		(1.9	)	$	(30	)	$	1,198	$	1,887	$	6		$	3,062
Issuance of common and restricted stock		1.2										13							13
Stock-based compensation												16							16
Treasury stock, at cost									(2	)									(2	)
Stock-based compensation excess tax benefit												4							4
Comprehensive income:
Net income														54					54
Foreign currency translation adjustment, net of tax of ($2)																3			3
Reclassification adjustments for settled hedging positions, net of tax of $2																(3	)		(3	)
Changes in fair value of outstanding hedging positions, net of tax of ($4)																7			7

Total comprehensive income																			61

Balance, June 30, 2007		132.3	$	1		(1.9	)	$	(32	)	$	1,231	$	1,941	$	13		$	3,154

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

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 state 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 on Form 10-K for the year ended December 31, 2006.

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. Historically, the energy markets have 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 can 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 associated with our proved oil and gas reserves.

Investments

Investments consist of highly liquid investment grade commercial paper and municipal and corporate bonds with a maturity of less than one year. These investments are classified as “available-for-sale.” Accordingly, unrealized gains and losses and the related deferred income tax effects are excluded from earnings and reported as a separate component of stockholders’ equity. Realized gains or losses are computed based on specific identification of the securities sold.

Inventories

Inventories consist primarily of tubular goods and well equipment held for use in our oil and gas operations and oil produced in our operations offshore Malaysia and China but not yet sold. Inventories are carried at the lower of cost or market. Crude oil from our operations offshore Malaysia and China is produced into floating production, storage and off-loading vessels and sold periodically as barge quantities are accumulated. The product inventory at June 30, 2007 consisted of approximately 191,000 barrels of crude oil valued at cost of $7 million. Cost for purposes of the carrying value of oil inventory is the sum of production costs and depreciation, depletion and amortization expense.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Foreign Currency

The British pound is the functional currency for our operations in the United Kingdom. Translation adjustments resulting from translating our United Kingdom subsidiaries’ British pound financial statements into U.S. dollars are included as accumulated other comprehensive income on our consolidated balance sheet and statement of stockholders’ equity. The functional currency for all other foreign operations is the U.S. dollar. Gains and losses incurred on currency transactions in other than a country’s functional currency are recorded under the caption “Other income (expense) — Other” on our consolidated statement of income.

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 assuming the normal operation of the asset, 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 within the related full cost pool. Both the accretion and the depreciation are included in depreciation, depletion and amortization on our consolidated statement of income.

The changes to our ARO for the six months ended June 30, 2007 are set forth below (in millions):


Balance as of January 1, 2007	$	272
Accretion expense		7
Additions		4
Revisions		14
Settlements		(16	)

Balance of ARO as of June 30, 2007	$	281

Stock-Based Compensation

On January 1, 2006, we adopted SFAS No. 123 (revised 2004) (SFAS No. 123 (R)), “Share-Based Payment,” to account for stock-based compensation. Among other items, SFAS No. 123(R) eliminated the use of APB 25 and the intrinsic value method of accounting and requires companies to recognize in their financial statements the cost of services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options and other equity-based compensation beginning in the first quarter of adoption. For all unvested options outstanding as of January 1, 2006, the previously measured but unrecognized compensation expense, based on the fair value at the original grant date, has been or will be recognized in our financial statements over the remaining vesting period. For equity-based compensation awards granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant or modification, has been or will be recognized in our financial statements over the vesting period. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and a lattice-based model for our performance and market-based restricted shares. Prior to the adoption of SFAS No. 123(R), we followed the intrinsic value method in accordance with APB 25 to account for stock-based compensation. See Note 11, “Stock-Based Compensation,” for a full discussion of our stock-based compensation.

Income Taxes

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” FIN 48 prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on a tax return. Under FIN 48, tax positions are recognized in our consolidated financial statements as the largest amount of tax benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with tax authorities assuming full knowledge of the position and all relevant facts. These amounts are subsequently reevaluated and changes are recognized as adjustments to current period tax expense. FIN 48 also revised disclosure requirements to include an annual tabular rollforward of unrecognized tax benefits.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We adopted the provisions of FIN 48 on January 1, 2007. The adoption did not result in a material adjustment to our tax liability for unrecognized income tax benefits. At the adoption date of January 1, 2007, we had approximately $0.4 million of unrecognized tax benefits, all of which would affect our effective tax rate if recognized. At June 30, 2007, the unrecognized tax benefit amount was unchanged from adoption.

If applicable, we would recognize interest and penalties related to uncertain tax positions in interest expense. As of June 30, 2007, we had not accrued interest related to uncertain tax positions because we have overpaid our tax liability.

The tax years 2003-2006 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

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 and unvested restricted stock and restricted stock units (using the treasury stock method).

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
	(In millions, except per share data)
Income (numerator):
Net income — basic	$	150	$	94	$	54	$	243

Net income — diluted	$	150	$	94	$	54	$	243


Weighted average shares (denominator):
Weighted average shares — basic		127		127		127		126
Dilution effect of stock options and unvested restricted stock and restricted stock units outstanding at end of period		3		2		3		3

Weighted average shares — diluted		130		129		130		129


Earnings per share:
Basic	$	1.17	$	0.74	$	0.42	$	1.92

Diluted	$	1.15	$	0.73	$	0.41	$	1.89

There were no antidilutive shares for the three and six months ended June 30, 2007 and 2006.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

3. Oil and Gas Assets:

Oil and Gas Properties

Oil and gas properties consisted of the following at:


	June 30,			December 31,
	2007			2006
	(In millions)
Subject to amortization	$	9,127		$	7,888
Not subject to amortization:
Exploration wells in progress		337			182
Development wells in progress		28			49
Capitalized interest		102			94
Fee mineral interests		23			23
Other capital costs:
Incurred in 2007		219			—
Incurred in 2006		108			118
Incurred in 2005		70			82
Incurred in 2004 and prior		405			454

Total not subject to amortization		1,292			1,002

Gross oil and gas properties		10,419			8,890
Accumulated depreciation, depletion and amortization		(3,607	)		(3,235	)

Net oil and gas properties	$	6,812		$	5,655

Oil and gas properties not subject to amortization represent investments in unproved properties and major development projects in which we own an interest. These unproved property costs include unevaluated leasehold acreage, geological and geophysical data costs associated with leasehold or drilling interests, costs associated with wells currently drilling and capitalized interest. We exclude these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. Unproved property costs are grouped by major prospect area where individual property costs are not significant and are assessed individually when individual costs are significant. Costs associated with exploration and development wells in progress are transferred to the amortization base upon the determination of whether proved reserves can be assigned to the properties, which is generally based on drilling results. All other costs excluded from the amortization base are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the amortization base or a charge is made against earnings for those international operations where a reserve base has not yet been established. We believe that our evaluation activities related to substantially all of the properties associated with costs not currently subject to amortization will be completed within four to ten years.

We use the full cost method of accounting for our oil and gas producing activities. 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.

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 using end of period oil and gas prices applicable to our reserves (including the effects of hedging contracts that are designated for hedge accounting); plus

	•		the lower of cost or estimated fair value of properties not 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.

If net capitalized costs of 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, a ceiling test writedown would reduce earnings and stockholders’ equity in the period of occurrence and result in lower depreciation, depletion and amortization expense in future periods.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The risk that we will be required to writedown the carrying value of our oil and gas properties increases when oil and gas prices decrease significantly or if we have substantial downward revisions in our estimated proved reserves. At March 31, 2007, the cost center ceiling for our U.K. oil and gas properties was calculated based upon quoted market prices of $3.74 per Mcf for gas and $55.38 per Bbl for oil, adjusted for market differentials. Using these prices, the unamortized net capitalized costs of our U.K. cost pool exceeded the full cost ceiling, resulting in a ceiling test writedown of $47 million in the first quarter of 2007.

Gulf of Mexico Asset Sale

On June 20, 2007, we entered into a purchase and sale agreement with McMoRan Oil & Gas LLC to sell substantially all of our properties in the Gulf of Mexico for $1.1 billion in cash and the assumption of liabilities associated with the abandonment of wells and platforms. We will retain most of our deepwater properties and interests in some potential exploration opportunities on the shelf. We anticipate closing the transaction in early August 2007, subject to customary closing conditions.

Acquisition of Rocky Mountain Assets

In June 2007, we completed the $578 million acquisition of Stone Energy Corporation’s Rocky Mountain assets. These assets increase our existing presence and provide an entry into large developments in many of the Rocky Mountains’ most attractive areas. We financed the acquisition with borrowings under our revolving credit agreement but it will ultimately be financed by proceeds from the sale of our Gulf of Mexico properties described above.

Pro Forma Results

The unaudited pro forma results presented below for the three and six months ended June 30, 2007 and 2006 have been prepared to give effect to the Rocky Mountain asset acquisition described above on our results of operations as if it had been consummated on January 1, 2006. The unaudited pro forma results do not purport to represent what our results of operations actually would have been if this acquisition had been completed on such date or to project our results of operations for any future date or period.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
	(Unaudited)
	(In millions, except per share)
Pro forma:
Revenue	$	552	$	414	$	1,017	$	869
Income from operations		188		119		286		360
Net income		157		102		115		259
Basic earnings per share	$	1.23	$	0.80	$	0.90	$	2.05
Diluted earnings per share	$	1.20	$	0.79	$	0.88	$	2.02

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

4. Debt:

As of the indicated dates, our debt consisted of the following:


	June 30,			December 31,
	2007			2006
	(In millions)
Senior unsecured debt:
Bank revolving credit facility:
Prime rate based loans	$	145		$	¾
LIBOR based loans		775			¾

Total bank revolving credit facility		920			¾
Money market lines of credit ⁽¹⁾		12			¾

Total credit arrangements		932			¾

$125 million 7.45% Senior Notes due 2007 ⁽²⁾		125			125
Fair value of interest rate swaps ^{(2) (3)}		(1	)		(1	)
$175 million 7 5/8% Senior Notes due 2011		175			175
Fair value of interest rate swaps ⁽³⁾		(3	)		(2	)

Total senior unsecured notes		296			297


Total senior unsecured debt		1,228			297


$325 million 6 5/8% Senior Subordinated Notes due 2014		325			325
$550 million 6 5/8% Senior Subordinated Notes due 2016		550			550

Total debt		2,103			1,172
Less: Current portion of debt ⁽²⁾		124			124

Total long-term debt	$	1,979		$	1,048


(1)		Because capacity under our credit facility was available to repay borrowings under our money market lines of credit as of the indicated dates, these obligations were classified as long-term.

(2)		Due October 2007.

(3)		We have hedged $50 million principal amount of our $125 million 7.45% Senior Notes due 2007 and $50 million principal amount of our $175 million 7 5/8% Senior Notes due 2011. The hedges provide for us to pay variable and receive fixed interest payments.

Credit Arrangements

In June 2007, we entered into a new revolving credit facility that matures in June 2012. This facility replaces our previous facility. The terms of the credit facility provide for initial loan commitments of $1.25 billion from a syndicate of banks, led by JPMorgan Chase as the agent bank. The loan commitments under the credit facility may be increased to a maximum aggregate amount of $1.65 billion if the lenders increase their loan commitments or new financial institutions are added to the credit facility. Loans under the credit facility bear interest, at our option, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by JPMorgan Chase Bank or the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 50 basis points or (b) a base Eurodollar rate substantially equal to the London Interbank Offered Rate, plus a margin that is based on a grid of our debt rating (87.5 basis points per annum at June 30, 2007). At June 30, 2007, we had $920 million outstanding under the credit facility.

Under our new credit facility and our previous credit facility, we pay commitment fees on the undrawn amounts based on a grid of our debt rating (0.175% per annum at June 30, 2007). We incurred fees under these arrangements of approximately $0.8 million and $1.5 million for the three and six months ended June 30, 2007, respectively.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The new credit facility has restrictive covenants that include the maintenance of a ratio of total debt to book capitalization not to exceed 0.6 to 1.0; maintenance of a ratio of total debt to earnings before gain or loss on the disposition of assets, interest expense, income taxes and non-cash items (such as depreciation, depletion and amortization expense and unrealized gains and losses on commodity derivatives) of at least 3.5 to 1.0; and, so long as our debt rating is below investment grade, the maintenance of a ratio of the calculated net present value of our oil and gas properties to total debt of at least 1.75 to 1.00. At June 30, 2007, we were in compliance with all of our debt covenants.

As of June 30, 2007, we had $47 million of undrawn letters of credit outstanding under our credit facility. Letters of credit issued under our credit facility are subject to an issuance fee of 12.5 basis points and annual fees based on a grid of our debt rating (87.5 basis points at June 30, 2007).

Subject to compliance with the restrictive covenants in our credit facility, we also have a total of $135 million of borrowing capacity under money market lines of credit with various banks. At June 30, 2007, we had $12 million outstanding under our money market lines.

5. Commitments and Contingencies:

In December 2002, a lawsuit against our Mid-Continent subsidiary was filed in Beaver County, Oklahoma and was later certified as a class action royalty owner lawsuit. The complaint alleges that we improperly reduced royalty payments for certain expenses and charges, and also claims breach of contract and breach of fiduciary duties, among other claims. In April 2007, we entered into a settlement agreement that has received preliminary court approval, subject to a fairness hearing. In the first quarter of 2007, we increased our litigation settlement reserve for the lawsuit, which resulted in a charge to earnings that was recorded under the caption “General and administrative” on our consolidated income statement.

We also have been named as a defendant in a number of other 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.

6. Segment Information:

While we only have operations in the oil and gas exploration and production industry, we are organizationally structured along geographic operating segments. Our operating segments are the United States, the United Kingdom, Malaysia, China and Other International. The accounting policies of each of our operating segments 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 three and six months ended June 30, 2007 and 2006. Income tax allocations have been determined based on statutory rates in the applicable geographic segment.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	United		United							Other
	States		Kingdom			Malaysia		China		International		Total
	(In millions)
Three Months Ended June 30, 2007:

Oil and gas revenues	$	493	$	3		$	17	$	15	$	¾	$	528

Operating expenses:
Lease operating		85		3			8		¾		¾		96
Production and other taxes		17		¾			2		1		¾		20
Depreciation, depletion and amortization		189		1			4		4		¾		198
General and administrative		32		1			¾		¾		¾		33
Allocated income taxes		61		¾			1		3		¾

Net income (loss) from oil and gas properties	$	109	$	(2	)	$	2	$	7	$	¾



Total operating expenses													347

Income from operations													181
Interest expense, net of interest income, capitalized interest and other													(16	)
Commodity derivative income													77

Income before income taxes												$	242


Total long-lived assets	$	6,312	$	180		$	250	$	70	$	¾	$	6,812


Additions to long-lived assets	$	1,044	$	(3	)	$	50	$	8	$	¾	$	1,099


	United		United							Other
	States		Kingdom			Malaysia		China		International		Total
	(In millions)
Three Months Ended June 30, 2006:

Oil and gas revenues	$	375	$	¾		$	15	$	¾	$	¾	$	390

Operating expenses:
Lease operating		62		¾			5		¾		¾		67
Production and other taxes		10		¾			5		¾		¾		15
Depreciation, depletion and amortization		141		¾			3		¾		¾		144
General and administrative		27		1			¾		¾		¾		28
Other		25		¾			¾		¾		¾		25
Allocated income taxes		40		¾			2		¾		¾

Net income (loss) from oil and gas properties	$	70	$	(1	)	$	¾	$	¾	$	¾



Total operating expenses													279

Income from operations													111
Interest expense, net of interest income, capitalized interest and other													(10	)
Commodity derivative income													46

Income before income taxes												$	147


Total long-lived assets	$	4,688	$	132		$	118	$	57	$	7	$	5,002


Additions to long-lived assets	$	401	$	36		$	20	$	8	$	1	$	466

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	United		United							Other
	States		Kingdom			Malaysia		China		International		Total
	(In millions)
Six Months Ended June 30, 2007:

Oil and gas revenues	$	912	$	3		$	29	$	24	$	¾	$	968

Operating expenses:
Lease operating		191		4			12		1		¾		208
Production and other taxes		32		¾			5		1		¾		38
Depreciation, depletion and amortization		363		1			7		7		¾		378
General and administrative		70		1			¾		1		¾		72
Ceiling test writedown		¾		47			¾		¾		¾		47
Allocated income taxes		92		¾			2		5		¾

Net income (loss) from oil and gas properties	$	164	$	(50	)	$	3	$	9	$	¾



Total operating expenses													743

Income from operations													225
Interest expense, net of interest income, capitalized interest and other													(27	)
Commodity derivative expense													(81	)

Income before income taxes												$	117


Total long-lived assets	$	6,312	$	180		$	250	$	70	$	¾	$	6,812


Additions to long-lived assets	$	1,506	$	27		$	76	$	11	$	¾	$	1,620


	United			United								Other
	States			Kingdom			Malaysia		China			International		Total
	(In millions)
Six Months Ended June 30, 2006:

Oil and gas revenues	$	798		$	¾		$	23	$	¾		$	¾	$	821

Operating expenses:
Lease operating		112			¾			7		¾			¾		119
Production and other taxes		26			¾			5		¾			¾		31
Depreciation, depletion and amortization		271			¾			4		¾			¾		275
General and administrative		55			2			¾		1			¾		58
Other		(5	)		¾			¾		¾			¾		(5	)
Allocated income taxes		121			(1	)		3		¾			¾

Net income (loss) from oil and gas properties	$	218		$	(1	)	$	4	$	(1	)	$	¾



Total operating expenses															478

Income from operations															343
Interest expense, net of interest income, capitalized interest and other															(15	)
Commodity derivative income															52

Income before income taxes														$	380


Total long-lived assets	$	4,688		$	132		$	118	$	57		$	7	$	5,002


Additions to long-lived assets	$	726		$	78		$	35	$	13		$	1	$	853

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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.

Cash Flow Hedges

Prior to the fourth quarter of 2005, all derivatives that qualified for hedge accounting were designated on the date we entered into the contract 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 June 30, 2007, we had a net $1 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 the entire net loss to be sold within the next 12 months. The actual gain or loss on these commodity derivatives could vary significantly as a result of changes in market conditions and other factors.

For those contracts designated as a cash flow hedge, we formally document all relationships between the derivative instruments and the hedged production, as well as our risk management objective and strategy for the 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.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At June 30, 2007, we had outstanding contracts that qualified and were designated as cash flow hedges with respect to our future oil production as set forth in the table below. At that date, we had no such contracts outstanding with respect to our future natural gas production.

NYMEX Contract Price per Bbl

Estimated

Collars

Fair Value

Swaps

Floors

Ceilings

Asset

Volume in

(Weighted

Weighted

(Liability)

Period and Type of Contract

MBbls

Average)

Range

Average

Range

Average

(In millions)

July 2007 – September 2007

Price swap contracts

61.25

)

Collar contracts

$50.00 – $55.00

52.50

$77.10 – $83.25

80.18

—

October 2007 – December 2007

Price swap contracts

61.25

)

Collar contracts

50.00 – 55.00

52.50

77.10 – 83.25

80.18

—

)

Other Derivative Contracts

In the fourth quarter of 2005, we elected not to designate any additional swap, collar and floor contracts that were entered into subsequent to September 30, 2005 as accounting hedges under SFAS No. 133. These contracts, as well as our three-way contracts that do not qualify as cash flow hedges, are carried at their fair value on our consolidated balance sheet under the captions “Derivative assets” and “Derivative liabilities.” We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statement of income under the caption “Commodity derivative income (expense).” Settlements of such derivative contracts are included in operating cash flows on our consolidated statement of cash flows.

At June 30, 2007, we had outstanding contracts with respect to our future production that were not accounted for as hedges as set forth in the tables below.

Natural Gas


			NYMEX Contract Price per MMBtu										Estimated
					Collars								Fair Value
			Swaps		Floors				Ceilings				Asset
	Volume in		(Weighted				Weighted				Weighted		(Liability)
Period and Type of Contract	MMMBtus		Average)		Range		Average		Range		Average		(In millions)
July 2007 – September 2007
Price swap contracts		25,500	$	8.87		—		—		—		—	$	51
Collar contracts		15,350		—	$	6.50 – $8.00	$	6.86	$	8.23 – $10.15	$	8.80		5
October 2007 – December 2007
Price swap contracts		12,972		8.99		—		—		—		—		20
Collar contracts		20,166		—		6.50 – 8.00		7.71		8.23 – 12.40		10.51		9
January 2008 – March 2008
Price swap contracts		6,391		9.20		—		—		—		—		2
Collar contracts		23,061		—		6.98 – 8.00		7.98		10.00 – 12.40		11.02		—
April 2008 – June 2008
Price swap contracts		7,756		7.86		—		—		—		—		1
Collar contracts		5,715		—		7.00 – 8.00		7.64		9.00 – 9.70		9.34		2
July 2008 – September 2008
Price swap contracts		7,842		7.86		—		—		—		—		—
Collar contracts		5,760		—		7.00 – 8.00		7.64		9.00 – 9.70		9.34		—
October 2008
Price swap contracts		2,325		8.06		—		—		—		—		—
Collar contracts		1,935		—		7.00 – 8.00		7.64		9.00 – 9.70		9.34		—

													$	90

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Oil


			NYMEX Contract Price per Bbl														Estimated
									Collars								Fair Value
			Swaps		Additional Put				Floors				Ceilings				Asset
	Volume in		(Weighted				Weighted				Weighted				Weighted		(Liability)
Period and Type of Contract	MBbls		Average)		Range		Average		Range		Average		Range		Average		(In millions)
July 2007 – September 2007
Price swap contracts		30	$	70.00		¾		¾		¾		¾		¾		¾	$	¾
Collar contracts		60		—		¾		¾	$	60.00	$	60.00	$	80.50 – $81.00	$	80.75		(1	)
3-Way collar contracts		888		—	$	25.00 – $50.00	$	30.00		32.00 – 60.00		37.10		44.70 – 82.00		55.31		(14	)
October 2007 – December 2007
Price swap contracts		30		70.00		¾		¾		¾		¾		¾		¾		¾
Collar contracts		60		—		¾		¾		60.00		60.00		80.50 – 81.00		80.75		(1	)
3-Way collar contracts		888		—		25.00 – 50.00		30.00		32.00 – 60.00		37.10		44.70 – 82.00		55.31		(15	)
January 2008 – March 2008
3-Way collar contracts		819		—		25.00 – 29.00		26.56		32.00 – 35.00		33.00		49.50 – 52.90		50.29		(17	)
April 2008 – June 2008
3-Way collar contracts		819		—		25.00 – 29.00		26.56		32.00 – 35.00		33.00		49.50 – 52.90		50.29		(18	)
July 2008 – September 2008
3-Way collar contracts		828		—		25.00 – 29.00		26.56		32.00 – 35.00		33.00		49.50 – 52.90		50.29		(18	)
October 2008 – December 2008
3-Way collar contracts		828		—		25.00 – 29.00		26.56		32.00 – 35.00		33.00		49.50 – 52.90		50.29		(18	)
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		(67	)
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		(66	)

																	$	(235	)

Basis Contracts

During the second quarter 2007, we added several natural gas basis hedges to lock in the differential between the NYMEX Henry Hub posted prices and those of our physical pricing points, as set forth in the table below.


											Estimated
	Onshore Gulf Coast					Rocky Mountains					Fair Value
			Weighted					Weighted			Asset
	Volume in		Average			Volume in		Average			(Liability)
	MMMBtus		Differential			MMMBtus		Differential			(In millions)
August 2007 – December 2007		17,595		($0.34	)		—		—		$	5

January 2008 – December 2008		—		—			4,800		($1.62	)		—

January 2009 – December 2009		—		—			5,520		($1.05	)		—

January 2010 – December 2010		—		—			5,520		($0.99	)		—

January 2011 – December 2011		—		—			5,280		($0.95	)		—

January 2012 – December 2012		—		—			4,920		($0.91	)		—

											$	5

Commodity Derivative Income (Expense)

The following table presents information about the components of commodity derivative income (expense) for the indicated periods.


	Three Month Period Ended				Six Month Period Ended
	June 30,				June 30,
	2007		2006		2007			2006
	(In millions)
Cash flow hedges:
Hedge ineffectiveness	$	—	$	1	$	—		$	6

Other derivative contracts:
Unrealized gain (loss) due to change in fair market value		55		9		(191	)		11
Realized gain on settlement		22		36		110			35

Total commodity derivative income (expense)	$	77	$	46	$	(81	)	$	52

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8. Accounts Receivable:

As of the indicated dates, our accounts receivable consisted of the following:


	June 30,		December 31,
	2007		2006
	(In millions)
Revenue	$	216	$	201
Joint interest		164		148
Sale of gathering and related facilities		24		¾
Receivable from broker		¾		14
MMS deposits		10		8
Texas severance tax		5		6
Other		¾		1

Total accounts receivable	$	419	$	378

9. Accrued Liabilities:

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


	June 30,		December 31,
	2007		2006
	(In millions)
Revenue payable	$	124	$	95
Accrued capital costs		284		349
Accrued lease operating expenses		51		58
Employee incentive expense		44		63
Accrued interest on notes		21		21
Taxes payable		23		21
Deferred acquisition payments		9		9
Insurance premium payable		33		16
Other		29		35

Total accrued liabilities	$	618	$	667

10. Comprehensive Income:

For the periods indicated, our comprehensive income consisted of the following:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(In millions)
Net income	$	150		$	94		$	54		$	243
Foreign currency translation adjustment, net of tax of ($1) and ($4) for the second quarter of 2007 and 2006, respectively, and ($2) and ($4) for the six months ended June 30, 2007 and 2006, respectively		2			7			3			7
Reclassification adjustments for settled hedging positions, net of tax of $1 and $3 for the second quarter of 2007 and 2006, respectively, and $2 and $12 for the six months ended June 30, 2007 and 2006, respectively		(2	)		(6	)		(3	)		(22	)
Changes in fair value of outstanding hedging positions, net of tax of ($2) and ($5) for the second quarter of 2007 and 2006, respectively, and ($4) and ($13) for the six months ended June 30, 2007 and 2006, respectively		5			9			7			24

Total comprehensive income	$	155		$	104		$	61		$	252

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

11. Stock-Based Compensation:

On January 1, 2006, we adopted SFAS No. 123(R) to account for stock-based compensation. Among other items, SFAS No. 123(R) eliminated the use of APB 25 and the intrinsic value method of accounting and requires companies to recognize in their financial statements the cost of services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options and other equity-based compensation beginning in the first quarter of adoption. For all unvested options outstanding as of January 1, 2006, the previously measured but unrecognized compensation expense, based on the fair value at the original grant date, has been or will be recognized in our financial statements over the remaining vesting period. For equity-based compensation awards granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant or modification, has been or will be recognized in our financial statements over the vesting period. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and a lattice-based model for our performance and market-based restricted shares. Prior to the adoption of SFAS No. 123(R), we followed the intrinsic value method in accordance with APB 25 to account for stock-based compensation.

Historically, we have used and we anticipate continuing to use unissued shares of stock when stock options are exercised. At June 30, 2007, we had approximately 2.6 million additional shares available for issuance pursuant to our existing employee and director plans. Of these shares, only 1.6 million could be granted as restricted shares. Grants of restricted shares under our 2004 Omnibus Stock Plan reduce the total number of shares available under that plan by two times the number of restricted shares issued.

We recorded stock-based compensation expense of $13 million and $16 million (pre-tax) for all plans for the six months ended June 30, 2007 and 2006, respectively. Of this amount, $3 million and $7 million was capitalized in oil and gas properties for the six months ended June 30, 2007 and 2006, respectively. For the six months ended June 30, 2007, we reported $4 million of excess tax benefits from stock-based compensation as cash provided by financing activities on our statement of cash flows.

As of June 30, 2007, we had approximately $70 million of total unrecognized compensation expense related to unvested stock-based compensation plans. This compensation expense is expected to be recognized on a straight-line basis over the remaining vesting period of approximately 5 years.

Stock Options. We have granted stock options under several plans. Options generally expire ten years from the date of grant and become exercisable at the rate of 20% per year. The exercise price of options cannot be less than the fair market value per share of our common stock on the date of grant.

The fair value of the stock options granted prior to and remaining outstanding at January 1, 2006 was determined using the Black-Scholes option valuation method assuming no dividends, a weighted average risk-free interest rate of 4.09%, an expected life of 6.5 years and a weighted average volatility of 37.52%.

The following table provides information related to stock option activity for the six months ended June 30, 2007:


								Weighted
	Number of					Weighted		Average
	Shares			Weighted		Average		Remaining		Aggregate
	Underlying			Average		Grant Date		Contractual		Intrinsic
	Options			Exercise Price		Fair Value		Life		Value
	(In millions)			per Share		per Share		(In years)		(In millions) ⁽¹⁾
Outstanding at December 31, 2006		5.6		$	23.68	$	10.71		6.3	$	124

Granted		¾			¾		¾		¾		¾
Exercised		(0.5	)		22.26		9.96		¾		13
Forfeited		(0.2	)		29.70		13.63		¾		2

Outstanding at June 30, 2007		4.9			23.67		10.70		5.9		107


Exercisable at June 30, 2007		2.9		$	20.67	$	9.30		5.1	$	73


(1)		The intrinsic value of a stock option is the amount by which the current market value of our common stock at the indicated date, or at the time of grant, exercise or forfeiture, as applicable, exceeds the exercise price of the option.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes information about stock options outstanding and exercisable at June 30, 2007:


Options Outstanding							Options Exercisable
	Number of		Weighted				Number of
	Shares		Average		Weighted		Shares		Weighted
	Underlying		Remaining		Average		Underlying		Average
Range of	Options		Contractual Life		Exercise Price		Options		Exercise Price
Exercise Prices	(In thousands)		(In years)		per Share		(In thousands)		per Share
$ 7.97 to $ 10.00		40		1.2	$	7.97		40	$	7.97
10.01 to 12.50		57		0.8		11.70		57		11.70
12.51 to 15.00		432		2.6		14.72		426		14.72
15.01 to 17.50		1,023		5.1		16.62		828		16.66
17.51 to 22.50		780		4.8		18.98		605		18.96
22.51 to 27.50		810		6.6		24.75		423		24.69
27.51 to 35.00		1,453		7.5		31.14		459		31.27
35.01 to 41.72		301		7.9		38.02		77		37.97

		4,896		5.9	$	23.67		2,915	$	20.67

On June 30, 2007, the last reported sales price of our common stock on the New York Stock Exchange was $45.55 per share.

Restricted Shares. At June 30, 2007, our employees held 1.1 million restricted shares or restricted share units that primarily vest over the service period of four to five years. The vesting of these shares and units is dependant upon the employees continued service with our company.

In addition, at June 30, 2007, our employees held 1.8 million restricted shares subject to performance based vesting criteria (substantially all of which are considered market based restricted shares under SFAS No. 123(R)). In February 2007, 293,338 of these restricted performance-based shares were granted. The number of these shares that vest is based upon established performance targets that will be assessed on March 1, 2010. The grant date fair value of these shares was $24.04 per share for a total value of $7 million. The expense is being recognized ratably over the service period from February 2007 to March 2010. The grants to our executive officers contain a retirement provision that permits them to retire on or after March 1, 2008, if certain other conditions are met, without forfeiting the shares granted. To the extent that our executive officers qualify under this provision, the expense will be recognized ratably over the service period from February 2007 to the applicable retirement eligibility date. Substantially all of the remaining performance based shares may vest in whole or in part in 2008, 2009 or 2010. The percentage of shares vesting, if any, in a year is subject to the achievement of the targets identified in the respective restricted share agreements.

Under our non-employee director restricted stock plan as in effect on June 30, 2007, immediately after each annual meeting of our stockholders, each of our non-employee directors then in office receive a number of restricted shares determined by dividing $100,000 by the fair market value of one share of our common stock on the date of the annual meeting. In addition, new non-employee directors elected after an annual meeting receive a number of restricted shares determined by dividing $100,000 by the fair market value of one share of our common stock on the date of their election. 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 June 30, 2007, 85,592 shares remained available for grants under this plan.

The following table provides information related to restricted share activity for the six months ended June 30, 2007:


				Performance/
	Service-Based			Market-Based			Total
	(In thousands, except per share data)
Non-vested shares outstanding at December 31, 2006		667			1,516			2,183
Granted		506			293			799
Forfeited		(43	)		(22	)		(65	)
Vested		(47	)		—			(47	)

Non-vested shares outstanding at June 30, 2007		1,083			1,787			2,870

Weighted average grant date fair value per share of shares granted during the period	$	41.77		$	24.04		$	35.11

Total fair value of shares vested during the period	$	1,368		$	—		$	1,368

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 in the plan.

During the second quarter of 2007, options to purchase 29,357 shares of our common stock at a weighted average fair value of $11.90 per share were issued under the plan. The fair value of the options granted was determined using the Black-Scholes option valuation method assuming no dividends, a risk-free weighted-average interest rate of 5.09%, an expected life of 6 months and weighted-average volatility of 35.88%. At June 30, 2007, 629,257 shares of our common stock remained available for issuance under this plan.

U.K. Bonus Plans. We have cash bonus plans for employees of our U.K. North Sea operations. The amount of bonuses is determined based on the value of the shares of our U.K. subsidiary as determined by our Board of Directors. These plans are accounted for as liability plans under SFAS No. 123(R) and are not material to our financial statements.

12. Income Taxes:

The provision for income taxes for the indicated periods was different than the amount computed using the federal statutory rate (35%) for the following reasons:


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2007			2006		2007			2006
				(In millions)
Amount computed using the statutory rate	$	84		$	51	$	40		$	133
Increase (decrease) in taxes resulting from:
State and local income taxes, net of federal effect		3			2		4			4
Net effect of different tax rates in non-U.S. jurisdictions		(3	)		—		(10	)		—
Tax credits and other		1			—		(2	)		—
Valuation allowance		7			—		31			—

Total provision for income taxes	$	92		$	53	$	63		$	137

As of June 30, 2007, we had NOL carryforwards for international income tax purposes of approximately $112 million that may be used in future years to offset taxable income. We currently estimate that we will not be able to utilize these international NOLs, therefore a valuation allowance was established for them. Utilization of NOL carryforwards is dependent upon generating sufficient taxable income in the appropriate jurisdictions 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.

The rollforward of our deferred tax asset valuation allowance is as follows:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
				(In millions)
Balance at beginning of the period	$	(45	)	$	(3	)	$	(21	)	$	(3	)
Charged to provision for income taxes:
United Kingdom NOL carryforwards		(7	)		—			(31	)		—

Balance at end of the period	$	(52	)	$	(3	)	$	(52	)	$	(3	)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas 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.

As part of our risk management program, we generally hedge a substantial, but varying, portion of our anticipated future oil and gas production. We use hedging to reduce our exposure to fluctuations in natural gas and oil prices. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and helps us manage returns on some of our acquisitions and more price sensitive drilling programs.

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;

	•		the value of our derivative positions; and

	•		the fair value of stock-based compensation.

Accounting for Hedging Activities. Beginning October 1, 2005, we elected not to designate any future price risk management activities as accounting hedges. Because hedges not designated for hedge accounting are accounted for on a mark-to-market basis, we are likely to experience significant non-cash volatility in our reported earnings during periods of commodity price volatility. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Commodity Derivative Activities” in Item 7 of our annual report on Form 10-K for the year ended December 31, 2006 and Note 7, “Commodity Derivative Instruments and Hedging Activities,” to our consolidated financial statements appearing earlier in this report for a discussion of the accounting applicable to our oil and gas derivative contracts.

Other factors. Please see “Risk Factors” in Item 1A of our annual report on Form 10-K for the year ended December 31, 2006 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

Revenues. All of our revenues are derived from the sale of our oil and gas production, which includes the effects of the settlement of derivative contracts associated with our production that are accounted for as hedges. Settlement of derivative contracts that are not accounted for as hedges 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 volumes of production sold. Revenues for the second quarter of 2007 were 35% higher than the comparable period of 2006 due to higher oil and gas production and higher oil and gas prices. Revenues for the first six months of 2007 were 18% higher than the same period of the prior year due to higher oil and gas production partially offset by slightly lower gas prices.


	Three Months Ended				Percentage			Six Months Ended				Percentage
	June 30,				Increase			June 30,				Increase
	2007		2006		(Decrease)			2007		2006		(Decrease)
Production ⁽¹⁾:
United States:
Natural gas (Bcf)		56.2		48.0		17	%		108.0		92.4		17	%
Oil and condensate (MBbls)		1,876		1,462		28	%		3,616		2,935		23	%
Total (Bcfe)		67.4		56.8		19	%		129.7		110.0		18	%
International:
Natural gas (Bcf)		0.3		—		100	%		0.4		—		100	%
Oil and condensate (MBbls)		515		253		104	%		919		368		150	%
Total (Bcfe)		3.5		1.5		127	%		5.9		2.2		166	%
Total:
Natural gas (Bcf)		56.5		48.0		18	%		108.4		92.4		17	%
Oil and condensate (MBbls)		2,391		1,715		39	%		4,535		3,303		37	%
Total (Bcfe)		70.9		58.3		22	%		135.6		112.2		21	%

Average Realized Prices ⁽²⁾:
United States:
Natural gas (per Mcf)	$	6.87	$	6.14		12	%	$	6.63	$	6.93		(4	%)
Oil and condensate (per Bbl)		56.17		54.15		4	%		53.02		52.66		1	%
Natural gas equivalent (per Mcfe)		7.28		6.58		11	%		7.00		7.23		(3	%)
International:
Natural gas (per Mcf)	$	6.91	$	—		100	%	$	6.91	$	—		100	%
Oil and condensate (per Bbl)		63.06		62.50		1	%		58.14		63.53		(8	%)
Natural gas equivalent (per Mcfe)		10.14		10.42		(3	%)		9.52		10.59		(10	%)
Total:
Natural gas (per Mcf)	$	6.87	$	6.14		12	%	$	6.63	$	6.93		(4	%)
Oil and condensate (per Bbl)		57.66		55.38		4	%		54.06		53.87		—
Natural gas equivalent (per Mcfe)		7.42		6.68		11	%		7.11		7.30		(3	%)


(1)		Represent volumes sold regardless of when produced.

(2)		Average realized prices only includes the effects of hedging contracts that are designated for hedge accounting. Had we included the effect of contracts not so designated, our average realized price for total gas would have been $7.46 and $6.97 per Mcf for the second quarter of 2007 and 2006, respectively, and $7.80 and $7.38 per Mcf for the six months ended June 30, 2007 and 2006, respectively. Our total oil and condensate average realized price would have been $53.08 and $52.88 per Bbl for the second quarter of 2007 and 2006, respectively, and $50.44 and $51.76 per Bbl for the six months ended June 30, 2007 and 2006, respectively. Without the effects of any hedging contracts, our average realized prices for the second quarter of 2007 and 2006 would have been $6.87 and $6.15 per Mcf, respectively, for gas and $59.29 and $64.67 per Bbl, respectively, for oil. Our average realized prices, without the effects of hedging, for the six months ended June 30, 2007 and 2006, would have been $6.63 and $6.87 per Mcf, respectively, for gas and $55.45 and $61.83 per Bbl, respectively, for oil.

Production. Our total oil and gas production (stated on a natural gas equivalent basis) for the second quarter of 2007 and for the six months ended June 30, 2007 increased 22% and 21%, respectively, over the comparable periods of 2006. The increases were primarily due to successful drilling efforts in the Mid-Continent, the timing of liftings of production in China and the negative impact the Gulf of Mexico production deferrals related to the 2005 storms had in the second quarter of 2006 (2 Bcfe) and the first six months of 2006 (10 Bcfe).

Natural Gas. Our second quarter of 2007 and six months ended June 30, 2007 natural gas production increased 18% and 17%, respectively, compared to the same periods of 2006. The increases were primarily the result of successful drilling efforts in the Mid-Continent and the 2006 Gulf of Mexico production deferrals mentioned above.

Crude Oil and Condensate. Our second quarter of 2007 and six months ended June 30, 2007 oil and condensate production increased 39% and 37%, respectively, compared to the same periods of 2006. The increases were the result of the timing of liftings of production in China (first lifting was in August 2006), increased sales from our Monument Butte field and the 2006 Gulf of Mexico production deferrals mentioned above.

Operating Expenses. Generally, our proved reserves and production have grown steadily since our founding. As a result, our operating expenses also have increased. We believe the most informative way to analyze changes in our operating expenses from period to period is on a unit-of-production, or per Mcfe, basis.

The following table presents information about our operating expenses for the second quarter of 2007 and 2006.


	Unit-of-Production							Amount
	(Per Mcfe)							(In millions)
	Three Months Ended				Percentage			Three Months Ended				Percentage
	June 30,				Increase			June 30,				Increase
	2007		2006		(Decrease)			2007		2006		(Decrease)
United States:
Lease operating	$	1.26	$	1.09		16	%	$	85	$	62		37	%
Production and other taxes		0.25		0.20		25	%		17		10		54	%
Depreciation, depletion and amortization		2.81		2.48		13	%		189		141		34	%
General and administrative		0.47		0.48		(2	%)		32		27		17	%
Other		—		0.44		(100	%)		—		25		(100	%)

Total operating expenses	$	4.79	$	4.69		2	%	$	323	$	265		21	%
International:
Lease operating	$	3.14	$	3.09		2	%	$	11	$	5		131	%
Production and other taxes		1.05		3.11		(66	%)		3		5		(23	%)
Depreciation, depletion and amortization		2.58		1.71		51	%		9		3		243	%
General and administrative		0.31		0.67		(54	%)		1		1		5	%

Total operating expenses	$	7.08	$	8.58		(17	%)	$	24	$	14		88	%
Total:
Lease operating	$	1.35	$	1.14		18	%	$	96	$	67		44	%
Production and other taxes		0.29		0.27		7	%		20		15		31	%
Depreciation, depletion and amortization		2.80		2.46		14	%		198		144		38	%
General and administrative		0.47		0.48		(2	%)		33		28		17	%
Other		—		0.43		(100	%)		—		25		(100	%)

Total operating expenses	$	4.91	$	4.78		3	%	$	347	$	279		24	%

Domestic Operations. Our domestic operating expenses for the second quarter of 2007, stated on an Mcfe basis, increased 2% over the same period of 2006. The period to period change was primarily related to the following items:

	•		Lease operating expense (LOE) increased due to higher operating costs for all of our operations. In addition, our LOE was adversely impacted in the second quarter of 2007 by repair expenditures of $16 million ($0.23 per Mcfe) related to 2005 hurricanes Katrina and Rita.

	•		Production and other taxes increased due to an increase in the proportion of our production volumes subject to production taxes as a result of increased production from our Mid-Continent and Rocky Mountain operations and higher commodity prices.

	•		The increase in our depreciation, depletion and amortization (DD&A) rate resulted from higher cost reserve additions. The cost of reserve additions was adversely impacted by escalating costs for drilling goods and services during 2006 and 2007. The component of DD&A associated with accretion expense related to our asset retirement obligation was $0.04 per Mcfe for the second quarter of 2007 and $0.06 per Mcfe for the second quarter of 2006.

	•		General and administrative (G&A) expense remained relatively flat on an Mcfe basis. The increase in actual G&A costs was primarily due to continued growth in our workforce. Our incentive compensation expense also increased as a result of higher adjusted net income (as defined in our incentive compensation plan) for the second quarter of 2007 as compared to the same period of the prior year. Adjusted net income for purposes of our incentive compensation plan excludes unrealized gains and losses on commodity derivatives. During the second quarter of 2007, we capitalized $11 million of direct internal costs as compared to $10 million in 2006.

	•		In the second quarter of 2006, we recorded under the caption “Operating expenses — Other” a $19 million redemption premium and an $8 million charge related to the unamortized original issue costs of our $250 million 8 3/8% senior subordinated notes that we redeemed in May 2006 and a $2 million benefit related to our business interruption insurance coverage as a result of the operations disruptions from the 2005 storms.

International Operations. Our international operating expenses for the second quarter of 2007, stated on an Mcfe basis, decreased 17% over the same period of 2006 even though our total operating expenses increased 88%. The period to period change was primarily related to the following items:

	•		LOE, on an Mcfe basis, increased due to higher operating costs for our Malaysian operations. Total LOE also increased due to initial production in the U.K. in the second quarter of 2007 and initial production in China in the third quarter of 2006.

	•		Production and other taxes and G&A expense decreased, on an Mcfe basis, due to initial liftings of production in China. In addition, production and other taxes in China are lower on a unit of production basis than our other international operations.

	•		DD&A, on an Mcfe basis, increased as a result of unsuccessful drilling operations in Malaysia during the second quarter of 2007.

The following table presents information about our operating expenses for the first six months of 2007 and 2006.


	Unit-of-Production								Amount
	(Per Mcfe)								(In millions)
	Six Months Ended					Percentage			Six Months Ended					Percentage
	June 30,					Increase			June 30,					Increase
	2007		2006			(Decrease)			2007		2006			(Decrease)
United States:
Lease operating	$	1.47	$	1.02			44	%	$	191	$	112			70	%
Production and other taxes		0.24		0.24			—			32		26			21	%
Depreciation, depletion and amortization		2.80		2.46			14	%		363		271			34	%
General and administrative		0.54		0.50			8	%		70		55			29	%
Other		—		(0.04	)		(100	%)		—		(5	)		(100	%)

Total operating expenses	$	5.05	$	4.18			21	%	$	656	$	460			43	%
International:
Lease operating	$	2.91	$	2.96			(2	%)	$	17	$	7			162	%
Production and other taxes		1.13		2.51			(55	%)		6		5			20	%
Depreciation, depletion and amortization		2.56		1.71			50	%		15		4			297	%
Ceiling test writedown		7.97		—			100	%		47		—			100	%
General and administrative		0.34		1.46			(77	%)		2		3			(39	%)

Total operating expenses	$	14.91	$	8.64			73	%	$	87	$	18			359	%
Total:
Lease operating	$	1.53	$	1.06			44	%	$	208	$	119			75	%
Production and other taxes		0.28		0.28			—			38		31			21	%
Depreciation, depletion and amortization		2.79		2.45			14	%		378		275			38	%
General and administrative		0.53		0.51			4	%		72		58			25	%
Ceiling test writedown		0.35		—			100	%		47		—			100	%
Other		—		(0.04	)		(100	%)		—		(5	)		(100	%)

Total operating expenses	$	5.48	$	4.26			29	%	$	743	$	478			55	%

Domestic Operations. Our domestic operating expenses for the first six months of 2007, stated on an Mcfe basis, increased 21% over the same period of 2006. The period to period change was primarily related to the following items:

	•		LOE increased due to higher operating costs for all of our operations and a 123% increase in insurance costs for our Gulf of Mexico operations. In addition, our 2007 LOE was adversely impacted by repair expenditures of $52 million ($0.40 per Mcfe) related to 2005 hurricanes Katrina and Rita.

	•		Our production tax expense increased 21%, as a result of increased production from our Mid-Continent and Rocky Mountain operations, which is subject to production taxes. Production and other taxes, on an Mcfe basis, remained unchanged due to a 16% increase in our production volumes that are not subject to production taxes.

	•		The increase in our DD&A rate resulted from higher cost reserve additions. The cost of reserve additions was adversely impacted by escalating costs for drilling goods and services during 2006 and 2007. The component of DD&A associated with accretion expense related to our asset retirement obligation was $0.05 per Mcfe for the first six months of 2007 and $0.07 per Mcfe for the first six months of 2006.

	•		G&A expense increased approximately $0.04 per Mcfe primarily due to an increase in a litigation settlement reserve associated with a statewide royalty owner class action lawsuit in Oklahoma. During the first six months of 2007, we capitalized $20 million of direct internal costs as compared to $19 million in 2006.

	•		For the first six months of 2006, we recorded under the caption “Operating expenses — Other” a $19 million redemption premium and an $8 million charge related to the unamortized original issue costs of our $250 million 8 3/8% senior subordinated notes that we redeemed in May 2006 and a $32 million benefit related to our business interruption insurance coverage as a result of the operations disruptions from the 2005 storms.

International Operations. Our international operating expenses for the first six months of 2007, stated on an Mcfe basis, increased 73% over the same period of 2006. The increase was primarily related to the ceiling test writedown of $47 million associated with our U.K. full cost pool in the first quarter of 2007. Without the effect of the writedown, operating expenses for the first six months of 2007, stated on an Mcfe basis, decreased by 20%. The period to period change was primarily related to the following items:

	•		LOE, production and other taxes and G&A expense decreased, on an Mcfe basis, due to initial liftings of production in China. Our initial liftings in China began in the third quarter of 2006.

	•		G&A expense also decreased due to a reduction in our accrual under our U.K. bonus plans. During the first six months of 2007, the determined value of the shares of our U.K. subsidiary decreased due to the disappointing results of the #7 development well in our Grove Field. Please see Note 11, “Stock-Based Compensation—U.K. Bonus Plans,” to our consolidated financial statements appearing earlier in this report for a description of these plans.

	•		DD&A, on an Mcfe basis, increased as a result of unsuccessful drilling operations in Malaysia during the second quarter of 2007.

Interest Expense. The increase in interest expense for the second quarter and first six months of 2007 resulted primarily from higher average debt levels outstanding under our credit arrangements as compared to the comparable periods of 2006.

Commodity Derivative Income (Expense). The following table presents information about the components of commodity derivative income (expense) for the indicated period.


	Three Month Period Ended				Six Month Period Ended
	June 30,				June 30,
	2007		2006		2007			2006
			(In millions)
Cash flow hedges:
Hedge ineffectiveness	$	—	$	1	$	—		$	6

Other derivative contracts:
Unrealized gain (loss) due to change in fair market value		55		9		(191	)		11
Realized gain on settlement		22		36		110			35

Total commodity derivative income (expense)	$	77	$	46	$	(81	)	$	52

Hedge ineffectiveness is associated with our hedging contracts that qualify for hedge accounting under SFAS No. 133. The unrealized gain (loss) due to changes in fair market value is associated with our derivative contracts that are not designated for hedge accounting and represents changes in the fair value of these open contracts during the period.

Taxes. The effective tax rates for the second quarter of 2007 and 2006 were 38.1% and 36.1%, respectively. The effective tax rates for the six months ended June 30, 2007 and 2006 were 54.1% and 36.1%, respectively. The effective tax rate for the first six months of 2007 was greater than the federal statutory rate primarily due to a $31 million valuation allowance associated with 2007 U.K. net operating loss carryforwards of $61 million that are not currently expected to be realized. For a detailed reconciliation of our provision for income taxes to the federal statutory rate, see Note 12, “Income Taxes,” to our consolidated financial statements appearing earlier in this report.

Liquidity and Capital Resources

We must find new and develop existing reserves to maintain and grow production and cash flow. We accomplish this through successful drilling programs and the acquisition of properties. These activities require substantial capital expenditures. We establish a capital budget at the beginning of each calendar year. In the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. Because of the nature of the properties we own, contractual capital commitments beyond 2007 are not significant.

We currently expect that our 2007 capital program (as adjusted for the purchase of the Rocky Mountain assets and the sale of the Gulf of Mexico properties described below), together with the repayment of $125 million of our senior notes in October 2007, will exceed estimated cash flow from operations by approximately $1.4 billion. Through June 30, 2007, the shortfall of approximately $992 million was made up with cash on hand and borrowings under our credit arrangements. For the remainder of the year, we anticipate the shortfall to be made up with the proceeds from the sale of our Gulf of Mexico properties and the other planned dispositions described below.

Acquisition and Divestiture Activity. On June 29, 2007, we completed the $578 million acquisition of Stone Energy’s Rocky Mountain assets. This acquisition was initially financed through borrowings under our revolving credit agreement but it will ultimately be financed by proceeds from the sale of our Gulf of Mexico properties described below.

We have structured the sale of our Gulf of Mexico properties and the acquisition of the Rocky Mountain assets as a like-kind exchange under Section 1031 of the Internal Revenue Code. Additional future acquisitions also may be included in the like-kind exchange structure if they are consummated within the time period required under Section 1031. At our election, we may retain all or a portion of the proceeds from the sale of our Gulf of Mexico properties, after reduction for the purchase price of the Rocky Mountain assets, in the like-kind exchange structure for application to the purchase price of any such future acquisitions. Any proceeds retained in the structure will not be available to repay outstanding borrowings under our credit arrangements.

We also have planned divestitures currently underway for two producing fields in Bohai Bay, China, all of our assets in the U.K. North Sea and smaller property packages onshore Texas and Oklahoma.

Credit Arrangements. In June 2007, we entered into a new revolving credit facility that matures in June 2012. The facility provides for initial loan commitments of $1.25 billion from a syndicate of participating banks, led by JPMorgan Chase as the agent bank. The loan commitments may be increased to a maximum aggregate amount of $1.65 billion if the current lenders increase their loan commitments or new financial institutions are added to the facility. Subject to compliance with covenants in our credit facility that restrict our ability to incur additional debt, we also have a total of $135 million of borrowing capacity under money market lines of credit with various banks. For a more detailed description of the terms of our credit arrangements, please see Note 4, “Debt,” to our consolidated financial statements appearing earlier in this report.

At July 30, 2007, we had outstanding borrowings of $940 million and undrawn letters of credit of $47 million under our credit facility, outstanding borrowings of $39 million under our money market lines and approximately $359 million of available borrowing 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 and changes in the fair value of our outstanding commodity derivative instruments. Without the effects of commodity derivative instruments, we typically have a working capital deficit or a relatively small amount of positive working capital because our capital spending generally has exceeded our cash flows from operations and we generally use excess cash to pay down borrowings under our credit arrangements. We had a working capital deficit of $291 million as of June 30, 2007. This compares to a working capital deficit of $272 million as of December 31, 2006. The increase in our working capital deficit at June 30, 2007 is due to the use of cash and short term investments to fund a portion of our capital program and the change in the fair value of our commodity derivative instruments. At June 30, 2007, the fair value of our short-term derivatives was a net asset of $26 million compared to a net asset of $200 million at December 31, 2006.

Cash Flows from Operations. Cash flows from operations primarily are affected by production and commodity prices, net of the effects of settlements of our derivative contracts. Our cash flows from operations also are impacted by changes in working capital. We also have experienced recent fluctuations as a result of higher operating costs for all of our operations and the 2005 hurricanes.

In August 2006, we reached an agreement with our insurance underwriters to settle all claims related to Hurricanes Katrina and Rita (business interruption, property damage and control of well/operator’s extra expense) for $235 million. During the first six months of 2007, we incurred $52 million of repair expenditures in excess of the insurance benefits received. This amount is reflected as a use of operating cash flows for the six months ended June 30, 2007.

We sell substantially all of our natural gas and oil production under floating market contracts. However, we generally hedge a substantial, but varying, portion of our anticipated future oil and natural gas production for the next 12-24 months. 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 is impacted by changes in working capital and is not affected by DD&A, writedowns or other non-cash charges or credits.

Our net cash flow from operations was $635 million for the six months ended June 30, 2007, compared to $692 million for the same period in 2006. Even though our revenues plus realized gains on the settlement of our derivative contracts less our operating costs and interest expense increased 17%, our net cash flow from operations decreased 8% due to increased working capital requirements during the six months ended June 30, 2007 compared to the same period of 2006. Our working capital requirements increased during the first six months of 2007 due to increased drilling activities, the timing of payments made by us to vendors and other operators and the timing and amount of advances received from our joint owners.

Capital Expenditures. Our capital spending for the first six months of 2007 was $1,601 million, an 88% increase from our $850 million in capital spending during the same period of 2006. The 2007 amount excludes asset retirement costs of $19 million. Of the $1,601 million, we invested $750 million in domestic exploitation and development, $112 million in domestic exploration (exclusive of exploitation and leasehold activity), $629 million in domestic leasehold activity (including $578 million for the Rocky Mountain assets acquired from Stone Energy) and $110 million internationally.

Our revised capital program for 2007 is $1.85 billion, excluding acquisitions. This total includes $50 million for continuing hurricane repairs in the Gulf of Mexico and excludes $130 million for capitalized interest and direct internal costs. Approximately 19% of the $1.85 billion is allocated to the Gulf of Mexico (including the shelf, the deep and ultra-deep shelf and deepwater), 21% to the onshore Gulf Coast, 37% to the Mid-Continent, 10% to the Rocky Mountains and 13% to international projects. We continue to pursue additional attractive acquisition opportunities; however, the timing and size of acquisitions are unpredictable. 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 provided by financing activities for the six months ended June 30, 2007 was $949 million. During the first six month of 2007, we borrowed a net $932 million under our credit arrangements ($578 million for the Stone Energy asset acquisition on June 29, 2007) and received proceeds of $13 million from the issuance of shares of our common stock upon the exercise of stock options.

In October 2007, our $125 million principal amount of 7.45% Senior Notes will become due. We currently plan to fund the repayment with borrowings under our credit arrangements.

Net cash flow provided by financing activities for the six months ended June 30, 2006 was $307 million. In April 2006, we issued $550 million aggregate principal amount of our 6⁵/₈% Senior Subordinated Notes due 2016. In May 2006, we used the proceeds from the offering to redeem $250 million principal amount of our 8³/₈% Senior Subordinated Notes due 2012. In addition, during the first half of 2006, we borrowed and repaid $342 million under our credit arrangements and received proceeds of $8 million from the issuance of shares of our common stock upon the exercise of stock options.

Contractual Obligations

The table below summarizes our significant contractual obligations by maturity as of June 30, 2007.


			Less than							More than
	Total		1 Year			2-3 Years		4-5 Years		5 years
Debt :
Bank revolving credit facility	$	920	$	—		$	—	$	920	$	—
Money market lines of credit		12		—			—		12		—
7.45% Senior Notes due 2007		125		125			—		—		—
7 5/8% Senior Notes due 2011		175		—			—		175		—
6 5/8% Senior Subordinated Notes due 2014		325		—			—		—		325
6 5/8% Senior Subordinated Notes due 2016		550		—			—		—		550

Total debt		2,107		125			—		1,107		875


Other obligations:
Interest payments ⁽¹⁾		856		138			267		252		199
Net derivative liabilities		142		(27	)		136		33		—
Asset retirement obligations		281		35			84		37		125
Operating leases		283		129			132		9		13
Deferred acquisition payments		9		3			4		2		—
Oil and gas activities ⁽²⁾		76

Total other obligations		1 ,647		278			623		333		337

Total contractual obligations	$	3,754	$	403		$	623	$	1 ,440	$	1,212


(1)		Interest associated with the bank revolving credit facility and money market lines of credit was calculated using the interest rate for LIBOR based loans of 6.375%, prime rate based loans of 8.25% and money market loans of 6.356% at June 30, 2007 and is included through the maturity of the credit facility.

(2)		As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. We have work related commitments for, among other things, drilling wells, obtaining and processing seismic data and fulfilling other cash commitments. At June 30, 2007, these work related commitments totaled $76 million and were comprised of $18 million in the United States and $58 million internationally. These amounts are not included by maturity because their timing cannot be accurately predicted.

Oil and Gas Hedging

As part of our risk management program, we generally hedge a substantial, but varying, portion of our anticipated future oil and natural gas production for the next 12-24 months to reduce our exposure to fluctuations in natural gas and oil prices. In the case of acquisitions, we may hedge acquired production for a longer period. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and helps us manage returns on some of our acquisitions and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our future 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, their use 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. Historically, all of our hedged natural gas and crude oil production has been sold at market prices that have had a high positive correlation to the settlement price for such hedges. Therefore, we believe that our hedged production was not subject to material basis risk. With the planned sale of the Gulf of Mexico shelf production and the corresponding shift in the geographic distribution of our natural gas production, we have begun to utilize basis hedges to a greater degree. The price that we receive for natural gas production from the Gulf of Mexico and onshore Gulf Coast, after basis differentials, transportation and handling charges, typically averages $0.40-$0.60 less per MMBtu than the Henry Hub Index. Realized gas prices for our Mid-Continent properties, after basis differentials, transportation and handling charges, typically average 75-85% of the Henry Hub Index. The price that we receive for natural gas production in the Rocky Mountains, after basis differentials, transportation, and handling charges, has recently been as much as $4.50 per MMBtu less than the Henry Hub Index. In light of this potential risk to our newly acquired Rocky Mountain assets, we have hedged the basis differential for a portion of our estimated production from proved reserves through 2012 at a weighted average of $1.18 less per MMBtu than the Henry Hub Index. The price we receive for our Gulf Coast oil production typically averages about $2 per barrel below the NYMEX West Texas Intermediate (WTI) price. The price we receive for our oil production in the Rocky Mountains is currently averaging about $12-$14 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 sales from our operations in Malaysia typically sells at Tapis, which generally is consistent with WTI. Oil sales from our operations in China typically sells at $7-$9 per barrel less than 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 June 30, 2007, J Aron & Company, Bank of Montreal, JPMorgan Chase, Citibank, N.A. and Barclays Bank PLC were the counterparties with respect to 78% of our future hedged production.

Between June 30, 2007 and July 30, 2007, we entered into additional natural gas price derivative contracts set forth in the table below. None of the contracts below have been designated for hedge accounting.


	NYMEX Contract Price per MMBtu
					Collars
			Swaps		Floors				Ceilings
	Volume in		(Weighted				Weighted				Weighted
Period and Type of Contract	MMMBtus		Average)		Range		Average		Range		Average
April 2008 – June 2008
Price swap contracts		4,550		8.18		—		—		—		—
July 2008 – September 2008
Price swap contracts		4,600		8.25		—		—		—		—
October 2008 – December 2008
Price swap contracts		1,550		8.28		—		—		—		—

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 June 30, 2007 and the fair value of those contracts as of that date.

General Information

General information about us can be found at www.newfield.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@newfield.com or visit our web page and sign up. Unless specifically incorporated, the information about us at www.newfield.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 availability of capital resources to fund capital expenditures, our financing plans, the anticipated closing date of the sale of our Gulf of Mexico properties and our divestiture plans. Although we believe that these expectations 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;

	•		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;

	•		the availability of refining capacity for the crude oil we produce from our Monument Butte Field;

	•		labor conditions; and

	•		the other factors affecting our business described under the caption “Risk Factors” in Item 1A of our annual report on Form 10-K for the year ended December 31, 2006.

In addition, the drilling of oil and gas wells and the production of hydrocarbons are subject to governmental regulations and operating risks. Completion of our proposed divestitures is subject to receiving offers that we consider acceptable for the properties.

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.

Barrel or Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

Bcf. Billion cubic feet.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel 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.

Deep shelf. We consider the deep shelf to be structures located on the shelf at depths generally greater than 14,000 feet in over pressured horizons 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.

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.

Exploitation well. An exploration well drilled to find and produce probable reserves. Most of the exploitation wells we drill are located in the Mid-Continent or the Monument Butte Field. Exploitation wells in those areas have less risk and less reserve potential and typically may be drilled at a lower cost than other exploration wells. For internal reporting and budgeting purposes, we combine exploitation and development activities.

Exploration well. A well drilled to find and produce oil or natural gas reserves that is not a development well. For internal reporting and budgeting purposes, we exclude exploitation activities from exploration activities.

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.

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 barrel of crude oil or condensate.

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 barrel of crude oil or condensate.

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

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.

Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The SEC provides a complete definition of proved reserves in Rule 4-10(a)(2) of Regulation S-X.

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

Ultra-deep shelf. We consider the ultra-deep shelf to be structures located on the shelf at depths of 20,000 feet and greater.

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 our exposure to fluctuations in natural gas and oil prices. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and helps us manage returns on some of our acquisitions and more price sensitive 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. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. For a more detailed discussion of our hedging activities, see the information under the caption “Oil and Gas Hedging’’ in Item 2 of this report and the discussion and tables in Note 7, “Commodity Derivative Instruments and Hedging Activities,” to our consolidated financial statements appearing earlier in this report.

Interest Rates

At June 30, 2007, our debt was comprised of:


	Fixed		Variable
	Rate Debt		Rate Debt
	(In millions)
Bank revolving credit facility	$	—	$	920
Money market line of credit		—		12
7.45% Senior Notes due 2007^{(1) (2)}		75		50
7 5/8% Senior Notes due 2011⁽¹⁾		125		50
6 5/8% Senior Subordinated Notes due 2014		325		—
6 5/8% Senior Subordinated Notes due 2016		550		—

Total long-term debt	$	1,075	$	1,032


(1)		$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 are 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.

(2)		Classified as current debt on our consolidated balance sheet at June 30, 2007.

At June 30, 2007, 51% of our debt obligations were at fixed rates and 49% were at variable rates, after taking into account our interest rate swap agreements. The impact on our annual cash flow of a 10% change in the floating rate applicable to our variable rate debt would be approximately $7 million.

Foreign Currency Exchange Rates

The British pound is the functional currency for our operations in the United Kingdom. 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 June 30, 2007.

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 June 30, 2007 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.

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, to determine whether any changes occurred during the second quarter of 2007 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 II

Item 1. Legal Proceedings

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

The following table sets forth certain information with respect to repurchases of our common stock during the six months ended June 30, 2007:

Maximum Number

(or Approximate

Total Number

Dollar Value) of

of Shares Purchased

Shares that May Yet

Total Number

as Part of Publicly

Be Purchased Under

of Shares

Average Price

Announced Plans

The Plans or

Period

Purchased⁽¹⁾

Paid per Share

or Programs

Programs

April 1 – April 30, 2007

178

44.16

—

May 1 – May 31, 2007

—

June 1 – June 30, 2007

265

50.40

—


(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 repurchase shares of our common stock.

Item 4. Submission of Matters to a Vote of Security Holders

At our May 3, 2007 annual meeting of stockholders, our stockholders voted on four matters. As of the March 5, 2007 record date, 129,734,947 shares of common stock were outstanding and entitled to vote at the meeting.

	(1)		Election of Thirteen Directors:

			Our stockholders elected the thirteen nominees for director by the following vote:


Nominee Elected	For		Withheld
David A. Trice		110,294,704		12,186,281
David F. Schaible		116,767,121		5,713,864
Howard H. Newman		116,518,487		5,962,498
Thomas G. Ricks		116,777,093		5,703,892
C. E. (Chuck) Shultz		116,380,022		6,100,963
Dennis R. Hendrix		119,937,980		2,543,005
Philip J. Burguieres		119,776,761		2,704,224
John Randolph Kemp III		119,946,634		2,534,351
J. Michael Lacey		119,940,163		2,540,822
Joseph H. Netherland		119,378,989		3,101,996
J. Terry Strange		113,530,880		8,950,105
Pamela J. Gardner		120,034,808		2,446,177
Juanita F. Romans		57,981,748		64,499,237

	(2)		Approval of Newfield Exploration Company 2007 Omnibus Stock Plan:

			Our stockholders approved the Newfield Exploration Company 2007 Omnibus Stock Plan by the following vote:


			Abstentions and
For	Against		Broker Non-Votes
105,182,070		5,318,573		1,949,677

	(3)		Approval of Second Amendment to Newfield Exploration Company 2000 Non-Employee Director Restricted Stock Plan:

			Our stockholders approved the Second Amendment to Newfield Exploration Company 2000 Non-Employee Director Restricted Stock Plan by the following vote:


			Abstentions and
For	Against		Broker Non-Votes
99,260,164		11,273,350		1,916,806

	(4)		Ratification of Appointment of Independent Accountants:

			Our stockholders ratified the appointment of PricewaterhouseCoopers LLP as our independent accountants for the year ending December 31, 2007 by the following vote:


			Abstentions and
For	Against		Broker Non-Votes
120,369,073		223,501		1,888,411

Item 5.02

Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers

On July 26, 2007, our Board of Directors took the following actions:

	•		elected David F. Schaible as President & Chief Operating Officer effective as of August 1, 2007;

	•		in connection with his promotion, granted Mr. Schaible 15,000 shares of restricted stock effective as of that same date;

	•		elected Lee K. Boothby as Senior Vice President — Acquisitions & Business Development effective as of October 1, 2007;

	•		subject to Mr. Boothy’s relocation to Houston, Texas and the assumption of his new duties as Senior Vice President — Acquisitions & Business Development:

	•		granted Mr. Boothy 12,000 shares of restricted stock effective as of October 1, 2007; and ;

	•		authorized and directed our company to enter into an amended and restated Change of Control Severance Agreement with Mr. Boothy effective as of July 26, 2007 that conforms the terms of his agreement to those of our other senior vice presidents;

	•		elected John Marziotti as General Counsel effective as of August 1, 2007;

	•		in connection with his promotion, granted Mr. Marziotti 4,000 shares of restricted stock as of that same date;

	•		amended and restated our 2003 Inventive Compensation Plan to clarify the terms under which retirement qualifies a participant for vesting of deferred awards and to comply with the requirements of Section 409A of the Internal Revenue Code;

	•		amended or amended and restated the following plans primarily to comply with the requirements of Section 409A:

	•		Newfield Employee 1993 Incentive Compensation Plan;

	•		Change of Control Severance Plan; and

	•		Deferred Compensation Plan; and

•

authorized and directed our company to enter into amended and restated Change of Control Severance Agreements with our senior executive officers primarily to comply with the requirements of Section 409A.

The amendments to and amended and restated plans and the form of the restricted stock agreement for the new grants and the amended and restated Change of Control Severance Agreements referred to above have been filed as exhibits to this report and are incorporated herein by reference. Subject to continued employment with our company, the new restricted stock grants to Messrs. Schaible, Boothby and Marziotti were granted under our amended and restated 2004 omnibus stock plan and will vest on the third anniversary of the effective date of the grant.

David A. Trice with continue to serve as our Chief Executive Officer and Chairman of the Board.

Item 6. Exhibits

(a) Exhibits:


Exhibit Number		Description
*† 10.1		Amendment No. 2 to Newfield Employee 1993 Incentive Compensation Plan

*† 10.2		Second Amended and Restated Newfield Exploration Company 2003 Incentive Compensation Plan

*† 10.3		Newfield Exploration Company Deferred Compensation Plan as Amended and Restated as of July 26, 2007

*† 10.4		Second Amended and Restated Newfield Exploration Company Change of Control Severance Plan

*† 10.5		Form of Second Amended and Restated Change of Control Severance Agreement between Newfield and each of David A. Trice, David F. Schaible and Terry W. Rathert dated effective as of July 26, 2007

*† 10.6		Amended and Restated Change of Control Severance Agreement between Newfield and Michael Van Horn dated effective as of July 26, 2007

*† 10.7		Second Amended and Restated Change of Control Severance Agreement between Newfield and Lee K. Boothby dated effective as of July 26, 2007

*† 10.8		Form of Second Amended and Restated Change of Control Severance Agreement between Newfield and each of George T. Dunn, Gary D. Packer and William D. Schneider dated effective as of July 26, 2007

*† 10.9		Form of Amended and Restated Change of Control Severance Agreement between Newfield and each of John H. Jasek and James T. Zernell dated effective as of July 26, 2007

*† 10.10		Form of Restricted Stock Agreement between Newfield and (a) each of David F. Schaible and John Marziotti dated as of August 1, 2007 and (b) Lee K. Boothby dated as of October 1, 2007

*10.11		Credit Agreement, dated as of June 22, 2007, among Newfield Exploration Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and as Issuing Bank (excludes signature pages and schedules and includes only select exhibits)

*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


*		Filed or furnished herewith.

†		Identifies management contracts and compensatory plans or arrangements.

SIGNATURE

Pursuant to the requirements 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.


	NEWFIELD EXPLORATION COMPANY
Date: August 1, 2007	By:	/s/ TERRY W. RATHERT
		Terry W. Rathert
		Senior Vice President and Chief Financial Officer

EXHIBIT INDEX


Exhibit Number		Description
*† 10.1		Amendment No. 2 to Newfield Employee 1993 Incentive Compensation Plan

*† 10.2		Second Amended and Restated Newfield Exploration Company 2003 Incentive Compensation Plan

*† 10.3		Newfield Exploration Company Deferred Compensation Plan as Amended and Restated as of July 26, 2007

*† 10.4		Second Amended and Restated Newfield Exploration Company Change of Control Severance Plan

*† 10.5		Form of Second Amended and Restated Change of Control Severance Agreement between Newfield and each of David A. Trice, David F. Schaible and Terry W. Rathert dated effective as of July 26, 2007

*† 10.6		Amended and Restated Change of Control Severance Agreement between Newfield and Michael Van Horn dated effective as of July 26, 2007

*† 10.7		Second Amended and Restated Change of Control Severance Agreement between Newfield and Lee K. Boothby dated effective as of July 26, 2007

*† 10.8		Form of Second Amended and Restated Change of Control Severance Agreement between Newfield and each of George T. Dunn, Gary D. Packer and William D. Schneider dated effective as of July 26, 2007

*† 10.9		Form of Amended and Restated Change of Control Severance Agreement between Newfield and each of John H. Jasek and James T. Zernell dated effective as of July 26, 2007

*† 10.10		Form of Restricted Stock Agreement between Newfield and (a) each of David F. Schaible and John Marziotti dated as of August 1, 2007 and (b) Lee K. Boothby dated as of October 1, 2007

*10.11		Credit Agreement, dated as of June 22, 2007, among Newfield Exploration Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent and as Issuing Bank (excludes signature pages and schedules and includes only select exhibits)

*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


*		Filed or furnished herewith.

†		Identifies management contracts and compensatory plans or arrangements.

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