Edgar Filing: NEWFIELD EXPLORATION CO /DE/

NEWFIELD EXPLORATION COMPANY

Date: October 22, 2010

/s/ TERRY W. RATHERT

Terry W. Rathert

Executive Vice President and Chief Financial Officer

nfx10q-09302010.htm

UNITED STATES

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 September 30, 2010


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 100

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)

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 October 20, 2010, there were 133,876,360 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 September 30, 2010 and December 31, 2009	1

	Consolidated Statement of Income for the three and nine months ended September 30, 2010 and 2009	2

	Consolidated Statement of Cash Flows for the nine months ended September 30, 2010 and 2009	3

	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2010	4

	Notes to Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39

Item 4.	Controls and Procedures	40


PART II

Item 1.	Legal Proceedings	40

Item 1A.	Risk Factors	40

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42

Item 6.	Exhibits	43

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NEWFIELD EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEET
(In millions, except share data)
(Unaudited)
	September 30, 2010				December 31, 2009
	September 30, 2010				December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents		$	128			$	78
Accounts receivable			276				339
Inventories			86				84
Derivative assets			296				269
Other current assets			74				123
Total current assets			860				893
Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($1,664 and
$1,223 were excluded from amortization at September 30, 2010 and December 31, 2009, respectively)			11,803				10,406
Less ─ accumulated depreciation, depletion and amortization			(5,619	)			(5,159	)
Total property and equipment, net			6,184				5,247

Derivative assets			73				19
Long-term investments			46				55
Deferred taxes			29				26
Other assets			34				14
Total assets		$	7,226			$	6,254

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable		$	81			$	83
Accrued liabilities			625				640
Advances from joint owners			50				51
Asset retirement obligation			14				10
Derivative liabilities			3				2
Deferred taxes			103				87
Total current liabilities			876				873

Other liabilities			96				55
Derivative liabilities			20				5
Long-term debt			2,169				2,037
Asset retirement obligation			85				82
Deferred taxes			680				434
Total long-term liabilities			3,050				2,613

Commitments and contingencies (Note 12)			—				—

Stockholders' equity:
Preferred stock ($0.01 par value, 5,000,000 shares authorized; no shares issued)			—				—
Common stock ($0.01 par value, 200,000,000 shares authorized at September 30, 2010 and December 31, 2009;
135,482,920 and 134,493,670 shares issued at September 30, 2010 and December 31, 2010, respectively)			1				1
Additional paid-in capital			1,430				1,389
Treasury stock (at cost; 1,676,719 and 1,488,968 shares at September 30, 2010 and December 31, 2009, respectively)			(41	)			(33	)
Accumulated other comprehensive income (loss):
Unrealized loss on investments			(13	)			(11	)
Retained earnings			1,923				1,422
Total stockholders' equity			3,300				2,768
Total liabilities and stockholders' equity		$	7,226			$	6,254

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

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NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF INCOME
(In millions, except per share data)
(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009

Oil and gas revenues	$	449		$	375		$	1,355		$	924

Operating expenses:
Lease operating		86			64			237			192
Production and other taxes		21			14			77			38
Depreciation, depletion and amortization		156			144			463			440
General and administrative		40			40			117			106
Ceiling test writedown		—			—			—			1,344
Other		—			1			10			8
Total operating expenses		303			263			904			2,128

Income (loss) from operations		146			112			451			(1,204	)

Other income (expenses):
Interest expense		(39	)		(31	)		(116	)		(95	)
Capitalized interest		15			13			43			39
Commodity derivative income (expense)		131			(8	)		414			189
Other		1			(1	)		2			4
Total other income (expense)		108			(27	)		343			137

Income (loss) before income taxes		254			85			794			(1,067	)

Income tax provision (benefit):
Current		7			35			34			36
Deferred		86			(28	)		259			(448	)
Total income tax provision (benefit)		93			7			293			(412	)

Net income (loss)	$	161		$	78		$	501		$	(655	)

Income (loss) per share:
Basic	$	1.22		$	0.59		$	3.80		$	(5.06	)
Diluted	$	1.20		$	0.58		$	3.75		$	(5.06	)


Weighted-average number of shares outstanding for basic income (loss) per share		132			130			132			129


Weighted-average number of shares outstanding for diluted income (loss) per share		134			132			134			129

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

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NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
(Unaudited)

	Nine Months Ended September 30,
	Nine Months Ended September 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	501		$	(655	)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		463			440
Deferred tax provision (benefit)		259			(448	)
Stock-based compensation		16			22
Ceiling test writedown		—			1,344
Commodity derivative income		(414	)		(189	)
Cash receipts on derivative settlements		345			701

Changes in operating assets and liabilities:
Decrease in accounts receivable		63			81
(Increase) decrease in inventories		3			(22	)
(Increase) decrease in other current assets		49			(18	)
Increase in other assets		(11	)		—
Increase (decrease) in accounts payable and accrued liabilities		26			(59	)
Increase (decrease) in advances from joint owners		(1	)		1
Increase in other liabilities		8			19
Net cash provided by operating activities		1,307			1,217

Cash flows from investing activities:
Additions to oil and gas properties		(1,191	)		(1,045	)
Acquisitions of oil and gas properties		(209	)		(9	)
Proceeds from sales of oil and gas properties		14			—
Additions to furniture, fixtures and equipment		(11	)		(7	)
Redemptions of investments		5			18
Net cash used in investing activities		(1,392	)		(1,043	)

Cash flows from financing activities:
Proceeds from borrowings under credit arrangements		558			813
Repayments of borrowings under credit arrangements		(942	)		(920	)
Net proceeds from issuance of senior subordinated notes		694			—
Debt issue costs		(8	)		—
Repayment of senior notes		(175	)		—
Proceeds from issuances of common stock		22			6
Purchases of treasury stock, net		(14	)		(1	)
Net cash provided by (used in) financing activities		135			(102	)

Increase in cash and cash equivalents		50			72
Cash and cash equivalents, beginning of period		78			24
Cash and cash equivalents, end of period	$	128		$	96

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

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NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(In millions)

(Unaudited)

	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity
	Shares	Amount		Shares	Amount		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity
Balance, December 31, 2009	134.5	$	1	(1.5)	$	(33)	$	1,389	$	1,422	$	(11)	$	2,768
Issuances of common and restricted stock	1.0		—					17						17
Treasury stock, at cost				(0.2)		(8)								(8)
Stock-based compensation								24						24
Comprehensive income (loss):
Net income										501				501
Unrealized loss on investments												(2)		(2)
Total comprehensive income														499
Balance, September 30, 2010	135.5	$	1	(1.7)	$	(41)	$	1,430	$	1,923	$	(13)	$	3,300

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

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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 oil and gas properties. Our domestic areas of operation include the Anadarko and Arkoma Basins of the Mid-Continent, the Rocky Mountains, onshore Texas and the Gulf of Mexico. Internationally, we are active in Malaysia and China.

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, 2009.

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 oil and gas. 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 estimated proved oil and gas reserves and the fair value of our derivative positions.

Investments

Investments consist primarily of debt and equity securities as well as auction rate securities, substantially all of which are classified as “available-for-sale” and stated at fair value. 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. We regularly assess our investments for impairment and consider any impairment to be other than temporary if we intend to sell the security, it is more likely than not that we will be required to sell the security, or we do not expect to recover our cost of the security. We realized interest income and gains on our investment securities for the three months ended September 30, 2010 and 2009 of $0.4 million and $0.5 million, respectively, and for the nine months ended September 30, 2010 and 2009 of $1 million and $2 million, respectively.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Inventories

Inventories primarily consist 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 sold. Inventories are carried at the lower of cost or market. Crude oil from our operations offshore Malaysia and China is produced into FPSO’s and sold periodically as barge quantities are accumulated. The product inventory consisted of approximately 511,000 barrels and 289,000 barrels of crude oil valued at cost of $21 million and $11 million at September 30, 2010 and December 31, 2009, respectively. Cost for purposes of the carrying value of oil inventory is the sum of production costs and depreciation, depletion and amortization expense.

Oil and Gas Properties

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 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. Beginning January 1, 2010, 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 the newly effective oil and gas reserve estimation requirements (See “New Accounting Requirements” in this Note), which require use of the unweighted-average first-day-of-the-month commodity prices for the prior twelve months, adjusted for market differentials applicable to our reserves (including the effects of hedging contracts that are designated for hedge accounting, if any); 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.

During the first, second and third quarters of 2009, the present value (10% per annum discount rate) of estimated future net revenues from proved reserves was calculated using the end of period quoted market prices for oil and gas.

Proceeds from the sale of oil and gas properties are applied to reduce the costs in the applicable cost center unless the reduction would significantly alter the relationship between capitalized costs and proved reserves, 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 reduces earnings and stockholders’ equity in the period of occurrence and, holding other factors constant, results in lower depreciation, depletion and amortization expense in future periods.

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 September 30, 2010, the ceiling value of our reserves was calculated based upon the unweighted-average first-day-of-the-month commodity prices for the prior twelve months of $4.41 per MMBtu for natural gas and $77.33 per barrel for oil, adjusted for market differentials. Using these prices, the cost center ceilings with respect to our properties in the U.S., Malaysia and China exceeded the net capitalized costs of the respective properties. As such, no ceiling test writedowns were required at September 30, 2010.

During the first quarter of 2009, natural gas prices decreased significantly as compared to prices in effect at December 31, 2008. At March 31, 2009, the ceiling value of our reserves was calculated based upon quoted period-end market prices of $3.63 per MMBtu for natural gas and $49.65 per barrel for oil, adjusted for market differentials. Using these prices, the unamortized net capitalized costs of our domestic oil and gas properties at March 31, 2009 exceeded the ceiling amount and, as a result, we recorded a charge of $1.3 billion ($854 million, after-tax) during the first quarter of 2009.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Accounting for Asset Retirement Obligations

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record a liability (an asset retirement obligation or ARO) on our consolidated balance sheet and capitalize the present value of 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 expense on our consolidated statement of income.

The change in our ARO for the nine months ended September 30, 2010 is set forth below (in millions):

Balance as of January 1, 2010		$	92
	Accretion expense		6
	Additions		6
	Settlements		(5)
Balance at September 30, 2010		$	99
Less: Current portion of ARO at September 30, 2010			(14)
Total long-term ARO at September 30, 2010		$	85

Income Taxes

We use the liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are determined by applying tax regulations existing at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in our financial statements. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

As of September 30, 2010, we did not have any liability for uncertain tax positions. The tax years 2007-2009 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject. During the fourth quarter of 2008, the Internal Revenue Service (IRS) commenced a limited scope audit of our U.S. income tax return for the 2005 tax year. In 2010, the IRS issued a “No Change” letter for the 2005 tax year and closed the audit.

Derivative Financial Instruments

We account for our derivative activities by applying authoritative accounting and reporting guidance which requires that every derivative instrument be recorded on the balance sheet as either an asset or a liability measured at its fair value and that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. All of the derivative instruments that we utilize are to manage the price risk attributable to our expected oil and gas production. We have elected not to designate price risk management activities as accounting hedges under the accounting guidance, and, accordingly, account for them using the mark-to-market accounting method. Under this method, the changes in contract values are reported currently in earnings. Previously, we also utilized derivatives to manage our exposure to variable interest rates. See Note 5, “Derivative Financial Instruments—Interest Rate Swap.”

The related cash flow impact of our derivative activities are reflected as cash flows from operating activities. See Note 5 “Derivative Financial Instruments,” for a more detailed discussion of our derivative activities.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

New Accounting Requirements

In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2010-03, Oil and Gas Reserve Estimation and Disclosures (ASU 2010-03), which aligns the FASB’s oil and gas reserve estimation and disclosure requirements with the requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements (Final Rule), which was issued on December 31, 2008 and became effective for the year ended December 31, 2009. We adopted the Final Rule and ASU 2010-03 effective December 31, 2009, as a change in accounting principle that is inseparable from a change in accounting estimate. Such a change is accounted for prospectively under the authoritative accounting guidance. Comparative disclosures applying the new rules for periods before the adoption of ASU 2010-03 and the Final Rule are not required.

In January 2010, the FASB issued additional disclosure requirements related to fair value measurements. The guidance requires disclosure of transfers of assets and liabilities between Level 1 and Level 2 in the fair value measurement hierarchy, including the reasons for the transfers and disclosure of major purchases, sales, issuances, and settlements on a gross basis in the reconciliation of the assets and liabilities measured under Level 3 of the fair value measurement hierarchy. The guidance is effective for interim and annual periods beginning after December 15, 2009, except for the Level 3 reconciliation disclosures, which are effective for interim and annual periods beginning after December 15, 2010. We adopted the provisions for the quarter ended March 31, 2010, except for the Level 3 reconciliation disclosures, which we will adopt for the quarter ending March 31, 2011. Adopting the disclosure requirements did not have a material impact on our financial position or results of operations. We do not expect adoption of the Level 3 reconciliation disclosures in 2011 to have a material impact on our financial position or results of operations.

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 and restricted stock units) 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). Under the treasury stock method, the amount the employee must pay for exercising stock options, the amount of unrecognized compensation expense related to unvested stock-based compensation grants and the amount of excess tax benefits that would be recorded when the award becomes deductible are assumed to be used to repurchase shares. Please see Note 11, “Stock-Based Compensation.”

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(In millions, except per share data)
Income (numerator):
Net income (loss) — basic and diluted	$	161	$	78	$	501	$	(655	)

Weighted-average shares (denominator):
Weighted-average shares — basic		132		130		132		129
Dilution effect of stock options and unvested restricted stock
and restricted stock units outstanding at end of period (1)		2		2		2		—
Weighted-average shares — diluted		134		132		134		129

Income (loss) per share:
Basic	$	1.22	$	0.59	$	3.80	$	(5.06	)
Diluted	$	1.20	$	0.58	$	3.75	$	(5.06	)

_______________
(1)	The effect of stock options and unvested restricted stock and restricted stock units outstanding has not been included in the calculation of shares outstanding for diluted EPS for the nine months ended September 30, 2009 as their effect would have been anti-dilutive. Had we recognized net income for this period, incremental shares attributable to the assumed exercise of outstanding options and the assumed vesting of unvested restricted stock and restricted stock units would have increased diluted weighted-average shares outstanding by 2 million shares for the nine months ended September 30, 2009.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

3. Comprehensive Income (Loss):

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	Three Months Ended September 30,							Nine Months Ended September 30,
	2010			2009				2010				2009
	(In millions)
Net income (loss)		$	161		$	78			$	501			$	(655	)
Unrealized loss on investments, net of tax of $1			—			—				(2	)			—
Realized loss on post retirement benefits, net of tax of $2			—			(3	)			—				(3	)
Total comprehensive income (loss)		$	161		$	75			$	499			$	(658	)

4. Oil and Gas Assets:

	Property and Equipment

		Property and equipment consisted of the following at:

	September 30, 2010			December 31, 2009
	(In millions)
Oil and gas properties:
Subject to amortization	$	10,035		$	9,090
Not subject to amortization		1,664			1,223
Gross oil and gas properties		11,699			10,313
Accumulated depreciation, depletion and amortization		(5,560	)		(5,108	)
Net oil and gas properties		6,139			5,205
Other property and equipment		104			93
Accumulated depreciation and amortization		(59	)		(51	)
Net other property and equipment		45			42
Total property and equipment, net	$	6,184		$	5,247

The following is a summary of our oil and gas properties not subject to amortization as of September 30, 2010. We believe that our evaluation activities related to substantially all of our properties not subject to amortization will be completed within four years except the Monument Butte field. Because of its size, evaluation of the field in its entirety will take significantly longer than four years.

	Costs Incurred In
	2010		2009		2008		2007 and prior		Total
	(In millions)
Acquisition costs	$	224	$	149	$	168	$	363	$	904
Exploration costs		281		73		58		22		434
Development costs		69		22		30		26		147
Fee mineral interests		3		—		—		23		26
Capitalized interest		43		51		59		—		153
Total oil and gas properties not subject to amortization	$	620	$	295	$	315	$	434	$	1,664

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Maverick Basin Asset Acquisition

On February 11, 2010, we acquired certain of TXCO Resources Inc.’s assets in the Maverick Basin of southwest Texas for approximately $209 million. In the acquisition, we obtained an interest in approximately 300,000 net acres, primarily in the Pearsall and Eagle Ford shale plays, as well as production of 1,500 barrels of oil equivalent per day. Our consolidated financial statements include the cash flows and results of operations for these assets subsequent to February 11, 2010.

5. Derivative Financial Instruments:

Commodity Derivative Instruments

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, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. 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. 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, we are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price 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. 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.

All of our derivative contracts are carried at their fair value on our consolidated balance sheet under the captions “Derivative assets” and “Derivative liabilities.” 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. Please see Note 8, “Fair Value Measurements.” We recognize all unrealized and realized gains and losses related to these contracts on a mark-to-market basis in our consolidated statement of income under the caption “Commodity derivative income (expense).” Settlements of derivative contracts are included in operating cash flows on our consolidated statement of cash flows.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

At September 30, 2010, we had outstanding contracts with respect to our future production that are not designated for hedge accounting as set forth in the tables below.

Natural Gas

		NYMEX Contract Price Per MMBtu
					Collars					Estimated
		Swaps	Additional Put		Floors		Ceilings			Fair Value
	Volume in	(Weighted-		Weighted-		Weighted-		Weighted-		Asset
Period and Type of Contract	MMMBtus	Average)	Range	Average	Range	Average	Range	Average		(Liability)
									(In millions)
October 2010 – December 2010
Price swap contracts	28,320	$6.49	—	—	—	—	—	—		$	72
January 2011 – December 2011
Price swap contracts	85,740	6.26	—	—	—	—	—	—			160
3-Way collar contracts	47,470	—	$4.50	$4.50	$5.50 - $6.00	$5.95	$6.60 - $8.03	$7.71			48
January 2012 – December 2012
Price swap contracts	18,300	5.42	—	—	—	—	—	—			8
3-Way collar contracts	65,270	—	4.50	4.50	5.25 - 6.00	5.63	6.20 - 7.55	6.68			27
January 2013 – October 2013
3-Way collar contracts	21,280	—	4.50	4.50	5.75 - 6.00	5.82	6.60 - 7.55	6.88			9
										$	324

Oil

		NYMEX Contract Price Per Bbl
						Collars						Estimated
		Swaps	Additional Put			Floors			Ceilings			Fair Value
	Volume in	(Weighted-		Weighted-			Weighted-			Weighted-		Asset
Period and Type of Contract	MBbls	Average)	Range	Average		Range	Average		Range	Average		(Liability)
											(In millions)
October 2010 – December 2010
Price swap contracts	550	$87.74	—	—		—	—		—	—		$	3
Collar contracts	828	—	—	—	$125.50–$130.50		$127.97		$170.00	$170.00			39
3-Way collar contracts	368	—	$50.00-$60.00	$55.00		60.00-75.00	67.50	100.00-112.10		106.28			—
January 2011 – December 2011
Price swap contracts	3,650	81.51	—	—		—	—		—	—			(12	)
3-Way collar contracts	5,659	—	60.00-65.00	61.61		75.00-85.00	77.58	102.25-121.50		107.76			12
January 2012 – December 2012
Price swap contracts	2,196	82.27	—	—		—	—		—	—			(10	)
3-Way collar contracts	5,856	—	60.00-65.00	62.19		75.00-85.00	78.13	107.75-115.00		111.18			2
												$	34

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Basis Contracts

At September 30, 2010, we had natural gas basis contracts that are not designated for hedge accounting to lock in the differential between the NYMEX Henry Hub posted prices and those of our physical pricing points in the Rocky Mountains and Mid-Continent, as set forth in the table below.

	Rocky Mountains					Mid-Continent					Estimated Fair Value Asset (Liability)
			Weighted- Average Differential					Weighted- Average Differential
	Volume in MMMBtus					Volume in MMMBtus
	Volume in MMMBtus					Volume in MMMBtus
											(In millions)

October 2010 – December 2010		1,380	$	(0.99	)		1,840	$	(0.55	)	$	(1	)
January 2011 – December 2011		5,280		(0.95	)		10,350		(0.55	)		(5	)
January 2012 – December 2012		4,920		(0.91	)		18,300		(0.55	)		(6	)
											$	(12	)

Interest Rate Swap

We previously hedged $50 million principal amount of our $175 million 7 ⅝% Senior Notes due 2011 through an interest rate swap. The swap provided for us to pay variable and receive fixed payments. During the first half of 2010, we repurchased all of the outstanding 7 ⅝% Senior Notes due 2011. Thus during the first quarter of 2010, we terminated the swap and received approximately $2 million in settlement of the swap.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Additional Disclosures about Derivative Instruments and Hedging Activities

At September 30, 2010, we had derivative financial instruments recorded in our balance sheet as set forth below.

Type of Contract	Balance Sheet Location		Estimated Fair Value
		(In millions)
Derivatives not designated as hedging instruments:
Natural gas contracts	Derivative assets – current		$	251
Oil contracts	Derivative assets – current			49
Basis contracts	Derivative assets – current			(4	)
Natural gas contracts	Derivative assets – noncurrent			73
Oil contracts	Derivative assets – noncurrent			4
Basis contracts	Derivative assets – noncurrent			(4	)
Oil contracts	Derivative liabilities – current			(3	)
Oil contracts	Derivative liabilities – noncurrent			(16	)
Basis contracts	Derivative liabilities – noncurrent			(4	)
Total derivatives not designated as hedging instruments, net			$	346

The amount of gain (loss) recognized in income related to our derivative financial instruments was as follows:

Type of Contract	Location of Gain (Loss) Recognized in Income	Three Months Ended September 30,						Nine Months Ended September 30,
Type of Contract	Location of Gain (Loss) Recognized in Income	2010			2009			2010			2009
		(In millions)
Derivatives not designated as hedging instruments:
Realized gain on natural gas contracts	Commodity derivative income (expense)	$	70		$	159		$	214		$	399
Realized gain on oil contracts	Commodity derivative income (expense)		41			76			112			281
Realized loss on basis contracts	Commodity derivative income (expense)		—			—			(3	)		—
Total realized gain			111			235			323			680
Unrealized gain (loss) on natural gas contracts	Commodity derivative income (expense)		111			(175	)		191			(121	)
Unrealized loss on oil contracts	Commodity derivative income (expense)		(90	)		(61	)		(102	)		(345	)
Unrealized gain (loss) on basis contracts	Commodity derivative income (expense)		(1	)		(7	)		2			(25	)
Total unrealized gain (loss)			20			(243	)		91			(491	)
Total gain (loss) on derivatives not designated as hedging instruments			131			(8	)		414			189

Derivative designated as a fair value hedge:
Interest rate swap	Interest expense		—			—			—			1
Total		$	131		$	(8	)	$	414		$	190

The total realized gain on commodity derivatives differs from the cash receipts on derivative settlements due to the recognition of option premiums associated with derivatives settled during the period.

The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty and we have netting arrangements with all of our counterparties that provide for offsetting payables against receivables from separate derivative instruments with that counterparty. At September 30, 2010, Barclays Capital, JPMorgan Chase Bank, N.A., Bank of Montreal, J Aron & Company and Societe Generale were the counterparties with respect to 81% of our future hedged production, the largest of which was J Aron & Company and accounted for 25% of our future hedged production.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

A significant number of the counterparties to our derivative instruments also are lenders under our credit facility. Our credit facility, senior subordinated notes and substantially all of our derivative instruments contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.

6. Accounts Receivable:

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

	September 30, 2010			December 31, 2009
	(In millions)
Revenue	$	137		$	214
Joint interest		109			114
Other		31			17
Reserve for doubtful accounts		(1	)		(6	)
Total accounts receivable	$	276		$	339

During the third quarter of 2010, an oil export pipeline from our East Belumut platform was damaged by the activities of another company’s marine vessel unrelated to our operations in Malaysia. All expenses associated with the repair and clean up operations are covered by insurance. During the third quarter of 2010, we recorded a receivable of $9 million related to our insurance coverage for these costs, which is included in Accounts Receivable―Other.

7. Accrued Liabilities:

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

	September 30, 2010		December 31, 2009
	(In millions)
Revenue payable	$	76	$	55
Accrued capital costs		273		289
Accrued lease operating expenses		52		47
Employee incentive expense		52		61
Accrued interest on debt		43		25
Taxes payable		72		101
Other		57		62
Total accrued liabilities	$	625	$	640

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

8. Fair Value Measurements:

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:

	Level 1:	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

	Level 2:	Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps, certain investments and interest rate swaps.

	Level 3:	Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Our valuation models for derivative contracts are primarily industry-standard models (i.e., Black-Scholes) that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our valuation methodology for investments is a discounted cash flow model that considers various inputs including: (a) the coupon rate specified under the debt instruments, (b) the current credit ratings of the underlying issuers, (c) collateral characteristics and (d) risk adjusted discount rates. Level 3 instruments primarily include derivative instruments, such as basis swaps, commodity price collars and floors and some financial investments. Although we utilize third party broker quotes to assess the reasonableness of our prices and valuation techniques, we do not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Fair Value of Investments and Derivative Instruments

The following tables summarize the valuation of our investments and financial instrument assets (liabilities) by pricing levels:

	Fair Value Measurement Classification
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)


								Total
	(In millions)
As of December 31, 2009:
Money market fund investments	$	15	$	—	$	—		$	15
Investments available-for-sale:
Equity securities		7		—		—			7
Auction rate securities		—		—		40			40
Oil and gas derivative swap contracts		—		119		(14	)		105
Oil and gas derivative option contracts		—		—		173			173
Interest rate swap		—		3		—			3
Total	$	22	$	122	$	199		$	343

As of September 30, 2010:
Money market fund investments	$	23	$	—	$	—		$	23
Investments available-for-sale:
Equity securities		8		—		—			8
Auction rate securities		—		—		32			32
Oil and gas derivative swap contracts		—		221		(12	)		209
Oil and gas derivative option contracts		—		—		137			137
Total	$	31	$	221	$	157		$	409

The determination of the fair values above incorporates various factors which include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests). We utilize credit default swap values to assess the impact of non-performance risk when evaluating both our liabilities to and receivables from counterparties.

As of September 30, 2010, we continued to hold $32 million of auction rate securities maturing beginning in 2033 that are classified as a Level 3 fair value measurement. This amount reflects a decrease in the fair value of these investments of $18 million ($11 million net of tax), recorded under the caption “Accumulated other comprehensive income (loss)” on our consolidated balance sheet. The debt instruments underlying these investments are mostly investment grade (rated BBB+ or better) and are guaranteed by the United States government or backed by private loan collateral. We do not believe the decrease in the fair value of these securities is permanent because we currently intend to hold these investments until the auction succeeds, the issuer calls the securities or the securities mature. Our current available borrowing capacity under our credit arrangements provides us the liquidity to continue to hold these securities.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following tables set forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the indicated periods:

	Investments			Derivatives			Total
	(In millions)
Balance at January 1, 2009	$	59		$	542		$	601
Total realized or unrealized gains (losses):
Included in earnings		—			(23	)		(23	)
Purchases, issuances and settlements		(18	)		(270	)		(288	)
Transfers in and out of Level 3		—			—			—
Balance at September 30, 2009	$	41		$	249		$	290

Change in unrealized gains (losses) relating to investments and derivatives still held at September 30, 2009	$	—		$	(70	)	$	(70	)


Balance at January 1, 2010	$	40		$	159		$	199
Total realized or unrealized gains (losses):
Included in earnings		—			74			74
Included in other comprehensive income (loss)		(3	)		—			(3	)
Purchases, issuances and settlements		(5	)		(108	)		(113	)
Transfers in and out of Level 3		—			—			—
Balance at September 30, 2010	$	32		$	125		$	157

Change in unrealized gains (losses) relating to investments and derivatives still held at September 30, 2010	$	(2	)	$	87		$	85

Fair Value of Debt

The estimated fair value of our notes, based on quoted market prices on September 30, 2010, was as follows (in millions):


6 ⅝% Senior Subordinated Notes due 2014	$	333
6 ⅝% Senior Subordinated Notes due 2016		570
7 ⅛% Senior Subordinated Notes due 2018		642
6 ⅞% Senior Subordinated Notes due 2020		746

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

9. Debt:

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


		September 30, 2010		December 31, 2009
		(In millions)
Senior unsecured debt:
	Revolving credit facility:
	LIBOR based loans	$	—	$	384


	7 ⅝% Senior Notes due 2011		—		175
	Fair value of interest rate swaps (1)		—		3
	Total senior unsecured notes		—		178
	Total senior unsecured debt		—		562

6 ⅝% Senior Subordinated Notes due 2014			325		325
6 ⅝% Senior Subordinated Notes due 2016			550		550
7 ⅛% Senior Subordinated Notes due 2018			600		600
6 ⅞% Senior Subordinated Notes due 2020			694		—
	Total long-term debt	$	2,169	$	2,037

_______________
(1)	We previously hedged $50 million principal amount of our $175 million 7 ⅝% Senior Notes due 2011 through an interest rate swap. The swap provided for us to pay variable and receive fixed payments. During the first half of 2010, we repurchased all of the outstanding 7 ⅝% Senior Notes due 2011. Thus during the first quarter of 2010, we terminated the swap and received approximately $2 million in settlement of the swap.

Credit Arrangements

We have a revolving credit facility which provides for loan commitments of $1.25 billion from a syndicate of more than 15 financial institutions, led by JPMorgan Chase Bank, as agent, and matures June 2012. However, the amount that we can borrow under the facility could be limited by changing expectations of future oil and gas prices because the maximum amount that we can borrow under the facility is determined by our lenders annually each May (and may be adjusted at the option of our lenders in the case of certain acquisitions or divestitures) using a process that takes into account the value of our estimated reserves and hedge position and the lenders’ commodity price assumptions. In the future, total loan commitments under the facility could be increased to a maximum of $1.65 billion if the existing lenders increase their individual loan commitments or new financial institutions are added to the facility. As of September 30, 2010, the largest individual loan commitment by any lender was 16% of total commitments.

Loans under the credit facility bear interest, at our option, equal to (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 September 30, 2010).

We pay commitment fees on available but undrawn amounts based on a grid of our debt rating (0.175% per annum at September 30, 2010). We incurred fees under this arrangement of approximately $0.6 million and $2 million for the three and nine months ended September 30, 2010, respectively, which are recorded in interest expense on our consolidated statement of income. For the three and nine months ended September 30, 2009, we incurred commitment fees of approximately $0.3 million and $1 million, respectively.

Our 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 noncash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives, ceiling test writedowns, and goodwill impairments) of at least 3.5 to 1.0. In addition, if our debt rating is below investment grade, we must maintain a ratio of the calculated net present value of our oil and gas reserves to total debt of at least 1.75 to 1.00. For purposes of this ratio, total debt includes only 50% of the principal amount of our senior subordinated notes. At September 30, 2010, we were in compliance with all of our debt covenants.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of September 30, 2010, we had no letters of credit outstanding under our credit facility. Letters of credit 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 September 30, 2010).

Subject to compliance with the restrictive covenants in our credit facility, we also have a total of $105 million of borrowing capacity under money market lines of credit with various financial institutions, the availability of which is at the discretion of the financial institutions.

Our credit facility and senior subordinated notes contain standard events of default and, if any such events of default were to occur, our lenders could terminate future lending commitments under the credit facility and our lenders could declare the outstanding borrowings due and payable. In addition, our credit facility, senior subordinated notes and substantially all of our hedging arrangements contain provisions that provide for cross defaults and acceleration of those debt and hedging instruments in certain situations.

Senior and Senior Subordinated Notes

On January 25, 2010, we sold $700 million of 6 ⅞% Senior Subordinated Notes due 2020 and received net proceeds of $686 million (net of discount and offering costs). These notes were issued at 99.109% of par to yield 7%. We used $294 million of the net proceeds to repay all of our then outstanding borrowings under our credit facility and $209 million to fund the acquisition of assets from TXCO Resources Inc.

On February 19, 2010, we accepted for purchase and payment approximately $143 million of our $175 million aggregate principal amount of 7 ⅝% Senior Notes due 2011, representing approximately 82% of the outstanding principal. The tender included the payment of an early redemption premium of $10 million. This premium was recorded under the caption “Operating expenses – Other” on our consolidated statement of income.

On May 24, 2010, we accepted for purchase and payment the remaining $32 million of our $175 million aggregate principal amount of 7 ⅝% Senior Notes due 2011. The tender included the payment of an early redemption premium of $2 million. This premium was recorded under the caption “Operating expenses – Other” on our consolidated statement of income.

We primarily funded the tender offer and repurchase of our $175 million aggregate principal amount of 7 ⅝% Senior Notes due 2011 with a portion of the proceeds from our January 25, 2010 Senior Subordinated Notes issuance.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

10. Income Taxes:

The provision (benefit) 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 September 30,					Nine Months Ended September 30,
	2010		2009			2010		2009
	(In millions)
Amount computed using the statutory rate	$	89	$	30		$	278	$	(374	)
Increase (decrease) in taxes resulting from:
State and local income taxes, net of federal effect		3		—			10		(17	)
Net effect of different tax rates in non-U.S. jurisdictions		1		1			4		2
Valuation allowance		—		(24	)		—		(24	)
Other		—		—			1		1
Total income tax provision (benefit)	$	93	$	7		$	293	$	(412	)

In the third quarter of 2009, we reversed the valuation allowance related to the deferred tax asset associated with our fourth quarter 2008 ceiling test writedown in Malaysia. The valuation allowance was reversed as a result of a substantial increase in our estimate of future taxable income in Malaysia due to increases in current and future anticipated crude oil prices.

As of September 30, 2010, we had net operating loss (NOL) carryforwards for international income tax purposes of approximately $17 million. We currently estimate that we will not be able to utilize our international NOLs because we do not have sufficient estimated future taxable income in the appropriate jurisdictions. Therefore, valuation allowances were established for these items in 2005 and 2006. Estimates of future taxable income can be significantly affected by changes in oil and gas prices, estimates of the timing and amount of future production and estimates of future operating and capital costs.

11. Stock-Based Compensation:

We make stock-based compensation awards to employees through the Newfield Exploration Company 2009 Omnibus Stock Plan (the 2009 Omnibus Stock Plan) and to non-employee directors through the Newfield Exploration Company 2009 Non-Employee Director Restricted Stock Plan. The fair value of grants under these plans are determined utilizing the Black-Scholes option pricing model for stock options and a lattice-based model for our performance and market-based restricted stock and restricted stock units.

As of the indicated dates, our stock-based compensation consisted of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(In millions)
Total stock-based compensation	$	6		$	11		$	24		$	34
Capitalized in oil and gas properties		(2	)		(4	)		(8	)		(12	)
Net stock-based compensation expense	$	4		$	7		$	16		$	22

As of September 30, 2010, we had approximately $59 million of total unrecognized stock-based compensation expense related to unvested stock-based compensation awards. This compensation expense is expected to be recognized on a straight-line basis over the applicable remaining vesting period. The full amount is expected to be recognized within approximately five years.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Stock Options. The following table provides information about stock option activity for the nine months ended September 30, 2010:

		Number of Shares Underlying Options		Weighted- Average Exercise Price per Share		Weighted- Average Grant Date Fair Value per Share		Weighted- Average Remaining Contractual Life			Aggregate Intrinsic Value(1)
	(In millions)							(In years)		(In millions)
Outstanding at December 31, 2009		2.9		$	29.82				4.7		$	56

Granted		—			—	$	—
Exercised		(0.9	)		23.52							29
Forfeited		—			—
Outstanding at September 30, 2010		2.0		$	32.76				4.6		$	49

Exercisable at September 30, 2010		1.7		$	30.23				4.1		$	46

_______________

(1)

The intrinsic value of a stock option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the option.

On September 30, 2010, the last reported sales price of our common stock on the New York Stock Exchange was $57.44 per share.

Restricted Stock. The following table provides information about restricted stock and restricted stock unit activity for the nine months ended September 30, 2010:

	Service-Based Shares		Performance/ Market-Based Shares			Total Shares		Weighted-Average Grant Date Fair Value per Share
	(In thousands, except per share data)
Non-vested shares outstanding at December 31, 2009	2,424			782		3,206			$	31.60
Granted	505			140		645				50.67
Forfeited	(146	)		(85	)	(231	)			31.81
Vested	(580	)		(521	)	(1,101	)			31.96
Non-vested shares outstanding at September 30, 2010	2,203			316		2,519			$	36.29

Employee Stock Purchase Plan. During the first six months of 2010, options to purchase 37,746 shares of our common stock were issued under our 2001 employee stock purchase plan. The weighted-average fair value of each option was $13.08 per share. 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 0.20%, an expected life of six months and weighted-average volatility of 43%. At June 30, 2010, this plan was terminated.

At our May 7, 2010 annual meeting, our stockholders approved the Newfield Exploration Company 2010 Employee Stock Purchase Plan (2010 Plan). The 2010 Plan was effective July 1, 2010 and has 1,000,000 shares of our common stock available for issuance. Based on the assumptions utilized during the third quarter of 2010, options to purchase 40,304 shares of our common stock were issued under the 2010 Plan. The weighted-average fair value of each option was $13.36 per share. 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 0.22%, an expected life of six months and weighted-average volatility of 46%.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

12. Commitments and Contingencies:

We have been named as a defendant in a number of lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (1) claims from royalty owners for disputed royalty payments, (2) commercial disputes, (3) personal injury claims and (4) property damage claims. Although the outcome of these lawsuits and disputes 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.

13. 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 current operating segments are the United States, 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 as of and for the three and nine months ended September 30, 2010 and 2009. Income tax allocations have been determined based on statutory rates in the applicable geographic segment.

Three Months Ended September 30, 2010:
							Other International
	Domestic		Malaysia		China		Other International		Total
	(In millions)
Oil and gas revenues	$	357	$	80	$	12	$	—	$	449

Operating expenses:
Lease operating		68		17		1		—		86
Production and other taxes		2		17		2		—		21
Depreciation, depletion and amortization		128		24		4		—		156
General and administrative		39		1		—		—		40
Allocated income taxes		44		8		2		—
Net income from oil and gas properties	$	76	$	13	$	3	$	—

Total operating expenses										303
Income from operations										146
Interest expense, net of interest income, capitalized interest and other										(23	)
Commodity derivative income										131
Income before income taxes									$	254

Total long-lived assets	$	5,567	$	398	$	174	$	—	$	6,139

Additions to long-lived assets	$	361	$	18	$	7	$	—	$	386

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Three Months Ended September 30, 2009:
							Other International
	Domestic		Malaysia		China		Other International		Total
	(In millions)
Oil and gas revenues	$	231	$	132	$	12	$	—	$	375

Operating expenses:
Lease operating		48		15		1		—		64
Production and other taxes		5		8		1		—		14
Depreciation, depletion and amortization		100		41		3		—		144
General and administrative		39		1		—		—		40
Other		1		—		—		—		1
Allocated income taxes		14		26		2		—
Net income from oil and gas properties	$	24	$	41	$	5	$	—

Total operating expenses										263
Income from operations										112
Interest expense, net of interest income, capitalized interest and other										(19	)
Commodity derivative expense										(8	)
Income before income taxes									$	85

Total long-lived assets	$	4,393	$	353	$	149	$	3	$	4,898

Additions to long-lived assets	$	245	$	16	$	24	$	—	$	285

Nine Months Ended September 30, 2010:
							Other International
	Domestic		Malaysia		China		Other International			Total
	(In millions)
Oil and gas revenues	$	1,055	$	259	$	41	$	—		$	1,355

Operating expenses:
Lease operating		195		39		3		—			237
Production and other taxes		33		38		6		—			77
Depreciation, depletion and amortization		371		78		11		3			463
General and administrative		113		3		1		—			117
Other		10		—		—		—			10
Allocated income taxes		124		39		6		(1	)
Net income (loss) from oil and gas properties	$	209	$	62	$	14	$	(2	)

Total operating expenses											904
Income from operations											451
Interest expense, net of interest income, capitalized interest and other											(71	)
Commodity derivative income											414
Income before income taxes										$	794

Total long-lived assets	$	5,567	$	398	$	174	$	—		$	6,139

Additions to long-lived assets	$	1,272	$	98	$	31	$	—		$	1,401

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Nine Months Ended September 30, 2009:
								Other International
	Domestic			Malaysia		China		Other International		Total
	(In millions)
Oil and gas revenues	$	667		$	226	$	31	$	—	$	924

Operating expenses:
Lease operating		152			36		4		—		192
Production and other taxes		23			13		2		—		38
Depreciation, depletion and amortization		344			86		10		—		440
General and administrative		103			2		1		—		106
Ceiling test writedown		1,344			—		—		—		1,344
Other		8			—		—		—		8
Allocated income taxes		(471	)		34		3		—
Net income (loss) from oil and gas properties	$	(836	)	$	55	$	11	$	—

Total operating expenses											2,128
Loss from operations											(1,204	)
Interest expense, net of interest income, capitalized interest and other											(52	)
Commodity derivative income											189
Loss before income taxes										$	(1,067	)

Total long-lived assets	$	4,393		$	353	$	149	$	3	$	4,898

Additions to long-lived assets	$	860		$	44	$	50	$	—	$	954

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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 including among other items, the determination of ceiling test writedowns.

Any extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital. Please see the discussion under “Lower oil and gas prices and other factors have resulted in ceiling test writedowns in the past and may in the future result in additional ceiling test writedowns or other impairments” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009 and “— Liquidity and Capital Resources” below.

As part of our risk management program, we generally hedge a substantial, but varying, portion of our anticipated future oil and gas production. 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. To maintain and grow our production and cash flow, we must continue to develop existing reserves and locate or acquire new oil and gas reserves to replace those reserves being produced. 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 fair value of our financial instruments including derivative positions; and

•	the fair value of stock-based compensation.

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Accounting for Hedging Activities. We do not designate price risk management activities as accounting hedges. Because hedges not designated for hedge accounting are accounted for on a mark-to-market basis, we have in the past experienced, and are likely in the future to experience, significant non-cash volatility in our reported earnings during periods of commodity price volatility. As of September 30, 2010, we had net derivative assets of $346 million, of which 36% was measured based upon our valuation model (i.e. Black-Scholes) and, as such, is classified as a Level 3 fair value measurement. We value these contracts using a model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying instruments. We utilize credit default swap values to assess the impact of non-performance risk when evaluating both our liabilities to and receivables from counterparties. Please see Note 5, “Derivative Financial Instruments,” and Note 8, “Fair Value Measurements,” 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, 2009 and in Item 1A of this report for a 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 and do not include the effects of the settlements of our hedges. Please see Note 5, “Derivative Financial Instruments,” to our consolidated financial statements appearing earlier in this report for a discussion of the accounting applicable to our oil and gas derivative contracts.

Our revenues may vary significantly from period-to-period as a result of changes in commodity prices or volumes of production sold. In addition, crude oil from our operations offshore Malaysia and China is produced into FPSOs and “lifted” and sold periodically as barge quantities are accumulated. Revenues are recorded when oil is lifted and sold, not when it is produced into the FPSO. As a result, the timing of liftings may impact period-to-period results.

During the third quarter of 2010, an oil export pipeline from our East Belumut platform was damaged by the activities of another company’s marine vessel unrelated to our operations in Malaysia. Production during the third quarter of 2010 from the field was shut in for one month resulting in approximately 0.3 million barrels of deferred production. All expenses associated with the repair and clean up operations are covered by insurance. During the third quarter of 2010, we recorded a receivable related to our insurance coverage for these costs.

Revenues of $449 million for the third quarter of 2010 were 20% higher than the comparable period of 2009. Revenues of $1.4 billion for the first nine months of 2010 were 47% higher than the comparable period of 2009. The revenue increase for both periods is due to higher average realized oil and gas prices, combined with higher oil and gas production.

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The following table summarizes production and average realized prices by product and by geographic area for the three and nine months ended September 30, 2010 and 2009.

	Three Months Ended September 30,				Percentage Increase (Decrease)		Nine Months Ended September 30,				Percentage Increase (Decrease)
	2010		2009		Percentage Increase (Decrease)		2010		2009		Percentage Increase (Decrease)
Production: (1)
Domestic:
Natural gas (Bcf)		49.2		42.5	16	%		146.3		132.6	10	%
Oil and condensate (MBbls)		2,217		1,675	32	%		6,090		5,312	15	%
Total (Bcfe)		62.5		52.6	19	%		182.8		164.4	11	%
International:
Natural gas (Bcf)		—		—	—			—		—	—
Oil and condensate (MBbls)		1,279		2,151	(41	)%		4,172		4,717	(12	)%
Total (Bcfe)		7.7		12.9	(41	)%		25.0		28.3	(12	)%
Total:
Natural gas (Bcf)		49.2		42.5	16	%		146.3		132.6	10	%
Oil and condensate (MBbls)		3,496		3,826	(9	)%		10,262		10,029	2	%
Total (Bcfe)		70.2		65.5	7	%		207.8		192.7	8	%

Average Realized Prices: (2)
Domestic:
Natural gas (per Mcf)	$	4.25	$	3.14	35	%	$	4.38	$	3.16	39	%
Oil and condensate (per Bbl)		65.92		57.54	15	%		67.43		46.21	46	%
Natural gas equivalent (per Mcfe)		5.71		4.38	30	%		5.77		4.04	42	%
International:
Natural gas (per Mcf)	$	—	$	—	—		$	—	$	—	—
Oil and condensate (per Bbl)		72.04		66.76	8	%		71.83		54.45	32	%
Natural gas equivalent (per Mcfe)		12.01		11.13	8	%		11.97		9.08	32	%
Total:
Natural gas (per Mcf)	$	4.25	$	3.14	35	%	$	4.38	$	3.16	39	%
Oil and condensate (per Bbl)		68.16		62.72	9	%		69.22		50.08	38	%
Natural gas equivalent (per Mcfe)		6.40		5.71	12	%		6.52		4.78	36	%

_______________
(1)		Represents volumes lifted and sold regardless of when produced.

(2)		Had we included the effects of hedging contracts not designated for hedge accounting, our average realized price for total natural gas would have been $5.66 and $6.88 per Mcf for the three months ended September 30, 2010 and 2009, respectively, and $5.82 and $6.18 per Mcf for the nine months ended September 30, 2010 and 2009, respectively. Our total oil and condensate average realized price would have been $80.02 and $82.61 per Bbl for the three months ended September 30, 2010 and 2009, respectively, and $80.13 and $78.07 per Bbl for the nine months ended September 30, 2010 and 2009, respectively.

Domestic Production. Our three and nine months ended September 30, 2010 domestic oil and gas production, stated on a natural gas equivalent basis, increased over the comparable periods of 2009 primarily due to increased production in our Mid-Continent division as a result of continued successful development drilling efforts, combined with increased production from continued development of our Gulf of Mexico deepwater discoveries, partially offset by a decline in our onshore Gulf Coast production.

International Production. Our three and nine months ended September 30, 2010 international oil production, stated on a natural gas equivalent basis, decreased over the comparable periods of 2009 primarily due to the timing of liftings in Malaysia and China. Production during the three months ended September 30, 2010 from our operations in Malaysia was impacted by approximately 334 MBbls of deferred production related to a damaged export pipeline.

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Operating Expenses. 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 three months ended September 30, 2010 and 2009.

	Unit-of-Production						Total Amount
	Three Months Ended				Percentage		Three Months Ended				Percentage
	September 30,				Increase		September 30,				Increase
	2010		2009		(Decrease)		2010		2009		(Decrease)
Domestic:	(Per Mcfe)						(In millions)
Lease operating	$	1.09	$	0.92	18	%	$	68	$	48	42	%
Production and other taxes		0.03		0.09	(66	)%		2		5	(52	)%
Depreciation, depletion and amortization		2.06		1.91	8	%		128		100	28	%
General and administrative		0.62		0.73	(15	)%		39		39	—
Other		—		0.02	(100	)%		—		1	(100	)%
Total operating expenses		3.80		3.67	4	%		237		193	23	%
International:
Lease operating	$	2.28	$	1.23	85	%	$	18	$	16	10	%
Production and other taxes		2.48		0.72	244	%		19		9	105	%
Depreciation, depletion and amortization		3.64		3.37	8	%		28		44	(36	)%
General and administrative		0.13		0.11	18	%		1		1	(27	)%
Total operating expenses		8.53		5.43	57	%		66		70	(7	)%
Total:
Lease operating	$	1.22	$	0.98	24	%	$	86	$	64	34	%
Production and other taxes		0.30		0.21	43	%		21		14	52	%
Depreciation, depletion and amortization		2.23		2.20	1	%		156		144	9	%
General and administrative		0.56		0.61	(8	)%		40		40	—
Other		—		0.02	(100	)%		—		1	(100	)%
Total operating expenses		4.31		4.02	7	%		303		263	15	%

Domestic Operations. Our domestic operating expenses for the three months ended September 30, 2010, stated on a Mcfe basis, increased 4% over the same period of 2009. The components of the significant period-to-period change are as follows:

•	Lease operating expense (LOE) per Mcfe increased 18% primarily due to increased transportation costs resulting from the commencement of firm transportation contracts during late 2009 and early 2010 in our Mid-Continent division and increased workover activity in all divisions.

•	Production and other taxes per Mcfe decreased 66% primarily due to refunds of $15 million ($0.24 per Mcfe) recorded during the third quarter of 2010 related to production tax exemptions on some of our onshore wells, whereas we recorded similar refunds of $7 million ($0.13 per Mcfe) during the same period of 2009.

•	Our depreciation, depletion and amortization (DD&A) rate per Mcfe increased 8% primarily due to higher cost reserve additions subsequent to the second quarter of 2009. The 28% increase in total DD&A expense is primarily a result of the 19% increase in our production volumes during the third quarter of 2010 compared to the same period of 2009.

•	General and administrative (G&A) expense per Mcfe decreased 15% while total G&A costs remained flat. The decrease in G&A per Mcfe is primarily due to the 19% increase in production volumes during the third quarter of 2010 compared to the same period of 2009. During the third quarter of 2010, we capitalized $13 million of direct internal costs as compared to $16 million in the third quarter of 2009.

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International Operations. Our international operating expenses for the three months ended September 30, 2010, stated on a Mcfe basis, increased 57% over the same period of 2009. The components of the significant period-to-period change are as follows:

•	LOE per Mcfe increased 85% primarily due to fixed production and operating costs associated with certain of our production sharing contracts (PSCs) in Malaysia, a change in the mix of produced, lifted and sold production from the various PSCs during the third quarter of 2010 compared to the same period of 2009 and increased workover activity.

•	Production and other taxes per Mcfe increased significantly due to an increase in the tax rate per barrel of oil lifted and sold in Malaysia as a result of higher realized oil prices during 2010.

•	Our total DD&A expense decreased 36% primarily due to the 41% decrease in production volumes and the timing of liftings of these volumes.

The following table presents information about our operating expenses for the nine months ended September 30, 2010 and 2009.

	Unit-of-Production						Total Amount
	Nine Months Ended				Percentage		Nine Months Ended				Percentage
	September 30,				Increase		September 30,				Increase
	2010		2009		(Decrease)		2010		2009		(Decrease)
	(Per Mcfe)						(In millions)
Domestic:
Lease operating	$	1.07	$	0.92	16	%	$	195	$	152	29	%
Production and other taxes		0.18		0.14	29	%		33		23	41	%
Depreciation, depletion and amortization		2.03		2.09	(3	)%		371		344	8	%
General and administrative		0.62		0.62	—			113		103	10	%
Ceiling test writedown		—		8.18	(100	)%		—		1,344	(100	)%
Other		0.05		0.05	—			10		8	23	%
Total operating expenses		3.95		12.00	(67	)%		722		1,974	(63	)%
International:
Lease operating	$	1.66	$	1.42	17	%	$	42	$	40	4	%
Production and other taxes		1.77		0.51	247	%		44		15	207	%
Depreciation, depletion and amortization		3.69		3.38	9	%		92		96	(4	)%
General and administrative		0.18		0.12	50	%		4		3	27	%
Total operating expenses		7.30		5.43	34	%		182		154	19	%
Total:
Lease operating	$	1.14	$	1.00	14	%	$	237	$	192	24	%
Production and other taxes		0.37		0.20	85	%		77		38	105	%
Depreciation, depletion and amortization		2.23		2.28	(2	)%		463		440	5	%
General and administrative		0.56		0.55	2	%		117		106	10	%
Ceiling test writedown		—		6.98	(100	)%		—		1,344	(100	)%
Other		0.05		0.04	25	%		10		8	23	%
Total operating expenses		4.35		11.05	(61	)%		904		2,128	(58	)%

Domestic Operations. Our domestic operating expenses for the nine months ended September 30, 2010, stated on a Mcfe basis, decreased 67% over the same period of 2009 primarily due to the full cost ceiling test writedown recorded at March 31, 2009. The components of the significant period-to-period change are as follows:

•	LOE per Mcfe increased 16% primarily due to increased transportation costs resulting from the commencement of firm transportation contracts during late 2009 and early 2010 in our Mid-Continent division and increased workover activity in all divisions.

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•	Production and other taxes per Mcfe increased 29% due to significantly higher realized commodity prices during 2010, partially offset by refunds for production tax exemptions. We recorded refunds of $22 million ($0.12 per Mcfe) during the first nine months of 2010 related to production tax exemptions on some of our onshore wells, whereas we recorded similar refunds of $16 million ($0.09 per Mcfe) during the same period of 2009.

•	At March 31, 2009, we recorded a ceiling test writedown and reduced the capitalized costs of our oil and gas properties which resulted in a lower DD&A rate beginning in the second quarter of 2009. As a result, our DD&A rate for the first nine months of 2009 is the average of the first, second and third quarter rates of $2.42 per Mcfe, $1.94 per Mcfe and $1.91 per Mcfe, respectively. Since the second quarter of 2009, our DD&A rate per Mcfe increased primarily due to higher cost reserve additions. Total DD&A expense for the nine months ended September 30, 2010, increased 8% from the same period of 2009 as a result of the 11% increase in our production volumes during 2010.

•	Total G&A expense increased 10% primarily due to increased employee-related expenses associated with our growing domestic workforce. During the first nine months of 2010, we capitalized $40 million of direct internal costs as compared to $44 million in the same period of 2009.

•	During the first quarter of 2009, we recorded a ceiling test writedown of $1.3 billion ($8.18 per Mcfe) due to significantly lower natural gas prices at March 31, 2009.

•	Other expenses for the nine months ended September 30, 2010, includes the early redemption premium of $12 million associated with the tender offer and repurchase of our $175 million aggregate principal amount of 7 ⅝% Senior Notes due 2011, partially offset by the $2 million cash received resulting from the termination of the associated interest rate swap. Other expenses for the nine months ended September 30, 2009, includes long-term rig contract termination fees.

International Operations. Our international operating expenses for the nine months ended September 30, 2010, stated on a Mcfe basis, increased 34% over the same period of 2009. The components of the significant period-to-period change are as follows:

•	LOE per Mcfe increased 17% primarily due to fixed production and operating costs associated with certain of our PSCs in Malaysia, a change in the mix of produced, lifted and sold production from the various PSCs during the first nine months of 2010 compared to the same period of 2009 and increased workover activity.

•	Production and other taxes per Mcfe increased significantly due to an increase in the tax rate per barrel of oil lifted and sold in Malaysia as a result of higher realized oil prices during 2010.

•	Our total DD&A expense decreased 4% primarily due to the 12% decrease in production volumes and the timing of liftings of these volumes.

Commodity Derivative Income (Expense). The significant fluctuation in commodity derivative income (expense) from period-to-period is due to the extreme volatility of oil and gas prices and changes in our outstanding hedging contracts during these periods.

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Interest Expense. The following table presents information about interest expense for the indicated periods:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2010				2009				2010				2009
	(In millions)
Gross interest expense:
Credit arrangements		$	—			$	2			$	1			$	7
Senior notes			—				3				2				9
Senior subordinated notes			38				26				111				77
Other			1				—				2				2
Total gross interest expense			39				31				116				95
Capitalized interest			(15	)			(13	)			(43	)			(39	)
Net interest expense		$	24			$	18			$	73			$	56

The 24% and 22% increase in gross interest expense for the three and nine months ended September 30, 2010, respectively, as compared to the same periods of 2009 primarily resulted from the issuance of $700 million aggregate principal amount of 6 ⅞% Senior Subordinated Notes due 2020 in January 2010, partially offset by the tender offer and repurchase of our $175 million aggregate principal amount of 7 ⅝% Senior Notes during the first six months of 2010 and lower outstanding borrowings under our credit arrangements during 2010. See Note 9, “Debt,” to our consolidated financial statements appearing earlier in this report.

Taxes. The effective tax rates for the third quarter of 2010 and 2009 were 36.8% and 8.6%, respectively. The effective tax rates for the first nine months of 2010 and 2009 were 36.9% and 38.6%, respectively. Our effective tax rate for all periods was different than the federal statutory tax rate due to deductions that do not generate tax benefits, state income taxes and the differences between international and U.S. federal statutory rates. The decrease in our effective tax rate for the third quarter of 2009 was due to the reversal of the valuation allowance related to the deferred tax asset associated with our fourth quarter 2008 ceiling test writedown in Malaysia. The valuation allowance was reversed as a result of a substantial increase in our estimate of future taxable income in Malaysia due to increases in current and future anticipated crude oil prices. Estimates of future taxable income can be significantly affected by changes in oil and gas prices, the timing, amount, and location of future production and future operating expenses and capital costs.

Liquidity and Capital Resources

We must find new and develop existing reserves to maintain and grow our production and cash flow. We accomplish this through successful drilling programs and the acquisition of properties. These activities require substantial capital expenditures. Lower prices for oil and gas may reduce the amount of oil and gas that we can economically produce, and can also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital, as further described below.

We establish a capital budget at the beginning of each calendar year. Our 2010 capital budget is $1.6 billion and focuses on projects we believe will generate and lay the foundation for production growth. Our 2010 capital budget (excluding acquisitions) is guided by our anticipated 2010 cash flows.

Actual levels of capital expenditures may vary significantly due to many factors, including drilling results, oil and gas prices, industry conditions, the prices and availability of goods and services and the extent to which properties are acquired. In addition, in the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. We continue to screen for attractive acquisition opportunities; however, the timing and size of acquisitions are unpredictable. We have the operational flexibility to react quickly with our capital expenditures to changes in circumstances and our cash flows from operations.

During the first six months of 2010, we accepted for purchase and payment our $175 million aggregate principal amount of 7 ⅝% Senior Notes due 2011. The tender offer and repurchase included the payment of an early redemption premium of $12 million. We primarily funded the tender offer with a portion of the proceeds from our January 25, 2010 Senior Subordinated Notes issuance.

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We continue to hold auction rate securities with a fair value of $32 million. We attempt to sell these securities every 7-28 days until the auctions succeed, the issuer calls the securities or the securities mature. We currently do not believe that the decrease in the fair value of these investments is permanent or that the failure of the auction mechanism will have a material impact on our liquidity given the amount of our available borrowing capacity under our credit arrangements. See Note 8, “Fair Value Measurements,” for more information regarding the auction rate securities.

Credit Arrangements. We have a revolving credit facility that matures in June 2012 and provides for loan commitments of $1.25 billion from a syndicate of more than 15 financial institutions, led by JPMorgan Chase Bank, as agent. As of September 30, 2010, the largest individual commitment was 16% of total commitments. However, the amount that we can borrow under the facility could be limited by changing expectations of future oil and gas prices because the maximum amount that we may borrow under the facility is determined by our lenders annually each May (and may be adjusted at the option of our lenders in the case of certain acquisitions or divestitures) using a process that takes into account the value of our estimated reserves and hedge position and the lenders’ commodity price assumptions.

In the future, total commitments under the facility could be increased to a maximum of $1.65 billion if the existing lenders increase their individual loan commitments or new financial institutions are added to the facility. In addition, subject to compliance with covenants in our credit facility that restrict our ability to incur additional debt, we also have a total of $105 million of borrowing capacity under money market lines of credit with various financial institutions, the availability of which is at the discretion of the financial institution. For a more detailed description of the terms of our credit arrangements, please see Note 9, “Debt,” to our consolidated financial statements appearing earlier in this report.

At October 20, 2010, we had no letters of credit outstanding under our credit facility. We had outstanding borrowings of $13 million under our money market lines of credit and approximately $1.34 billion 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. Although we anticipate that our 2010 capital spending (excluding acquisitions) will correspond with our anticipated 2010 cash flows, we may borrow and repay funds under our credit arrangements throughout the year since the timing of expenditures and the receipt of cash flows from operations do not necessarily match.

At September 30, 2010, we had negative working capital of $16 million compared to positive working capital of $20 million at December 31, 2009. The decrease in our working capital as compared to December 31, 2009 is primarily a result of the timing of the collection of receivables, drilling activities, payments made by us to vendors and other operators and the timing and amount of advances received from our joint operations.

Cash Flows from Operations. Cash flows from operations are primarily affected by production and commodity prices, net of the effects of settlements of our derivative contracts and changes in working capital. We sell substantially all of our oil and gas production under floating price market sensitive contracts. We generally hedge a substantial, but varying, portion of our anticipated future oil and gas production for the next 12-24 months. See “—Oil and Gas Hedging” below.

We typically receive the cash associated with oil and gas sales within 45-60 days of production. As a result, cash flows from operations and income from operations generally correlate, but cash flows from operations are impacted by changes in working capital and are not affected by DD&A, ceiling test writedowns, other impairments, or other non-cash charges or credits.

Our net cash flows from operations were $1.3 billion for the nine months ended September 30, 2010, an increase of 7% compared to net cash flows from operations of $1.2 billion for the same period in 2009. The increase results from changes in our working capital requirements as a result of the timing of drilling activities, receivable collections from purchasers and joint interest partners, payments made by us to vendors and other operators and the timing and amount of advances received from our joint operations.

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Cash Flows from Investing Activities. Net cash used in investing activities for the nine months ended September 30, 2010 was $1.4 billion compared to $1.0 billion for the same period in 2009.

During the nine months ended September 30, 2010, we:

•	spent $1.4 billion primarily for additions to oil and gas properties (including $209 million for acquisitions of oil and gas properties);

•	received proceeds of $14 million from sales of oil and gas properties; and

•	redeemed investments of $5 million.

During the nine months ended September 30, 2009, we:

•	spent $1.1 billion primarily for additions to oil and gas properties; and

•	redeemed investments of $18 million.

Capital Expenditures. Our capital spending of $1.4 billion for the first nine months of 2010 increased 47% from our capital spending of $946 million during the same period of 2009. These amounts exclude recorded asset retirement obligations of $8 million in the 2010 and 2009 periods. Of the $1.4 billion spent during the first nine months of 2010, we invested $846 million in domestic exploitation and development, $157 million in domestic exploration (exclusive of exploitation and leasehold activity), $262 million in acquisitions of proved and unproved property (leasehold) and domestic leasing activity and $128 million outside the United States. Of the $946 million spent during the first nine months of 2009, we invested $685 million in domestic exploitation and development, $133 million in domestic exploration (exclusive of exploitation and leasehold activity), $34 million in domestic leasehold activity and $94 million outside the United States.

We have budgeted $1.6 billion for capital spending in 2010 (excluding acquisitions), including $124 million of estimated capitalized interest and overhead. As a result of the continued spread between oil and gas prices, we have re-allocated approximately $200 million of our budget from natural gas projects to oil projects in our portfolio. We currently expect to invest approximately $700 million in oil projects in 2010, or nearly 45% of our total budget. The 2010 capital budget is based on our expectation that we will live within anticipated cash flow from operations (excluding acquisitions). Actual levels of capital expenditures may vary significantly due to many factors, including drilling results, oil and gas prices, industry conditions, the prices and availability of goods and services and the extent to which properties are acquired. In addition, in the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. We continue to screen for attractive acquisition opportunities; however, the timing and size of acquisitions are unpredictable.

Cash Flows from Financing Activities. Net cash flows provided by financing activities for the nine months ended September 30, 2010 were $135 million compared to net cash flows used in financing activities of $102 million for the same period in 2009.

During the nine months ended September 30, 2010, we:

•	borrowed $558 million and repaid $942 million under our credit arrangements;

•	issued $700 million aggregate principal amount of our 6 ⅞% Senior Subordinated Notes due 2020 at 99.109% of par;

•	paid $8 million in debt issue costs;

•	repaid our $175 million aggregate principal amount of 7 ⅝% Senior Notes due 2011;

•	received proceeds of $22 million from the issuance of shares of our common stock upon the exercise of stock options; and

•	repurchased $14 million of our common stock surrendered by employees to pay tax withholding upon the vesting of restricted stock and restricted stock unit awards.

During the nine months ended September 30, 2009, we:

•	borrowed $813 million and repaid $920 million under our credit arrangements; and

•	received proceeds of $6 million from the issuance of shares of our common stock upon the exercise of stock options.

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Contractual Obligations

The table below summarizes our significant contractual obligations by maturity as of September 30, 2010.

		Total			Less than 1 Year			2-3 Years			4-5 Years			More than 5 Years
		(In millions)
Debt:
	Revolving credit facility	$	—		$	—		$	—		$	—		$	—
	6 ⅝% Senior Subordinated Notes due 2014		325			—			—			325			—
	6 ⅝% Senior Subordinated Notes due 2016		550			—			—			—			550
	7 ⅛% Senior Subordinated Notes due 2018		600			—			—			—			600
	6 ⅞% Senior Subordinated Notes due 2020		700			—			—			—			700
	Total debt		2,175			—			—			325			1,850

Other obligations:
	Interest payments		1,098			149			298			274			377
	Net derivative (assets) liabilities		(346	)		(293	)		(52	)		(1	)		—
	Asset retirement obligations		99			14			9			12			64
	Operating leases		133			54			25			24			30
	Deferred acquisition payments		2			2			—			—			—
	Firm transportation		578			50			138			138			252
	Oil and gas activities (1)		89			—			—			—			—
	Total other (assets) obligations		1,653			(24	)		418			447			723
	Total contractual (assets) obligations	$	3,828		$	(24	)	$	418		$	772		$	2,573

_______________

(1)

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, natural gas transportation, and fulfilling other cash commitments. At September 30, 2010, these work-related commitments totaled $89 million, all of which were attributable to our international business.

As of September 30, 2010, we have delivery commitments through 2011 to deliver to third party purchasers approximately 100,000 MMBtu of our daily production, principally from our Mid-Continent division. These commitments continue through 2012 at approximately 60,000 MMBtu of our daily production. Given the size of our proved natural gas reserves and production capacity in our Mid-Continent division, we currently believe that we have sufficient reserves and production to fulfill these delivery commitments.

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 gas production for the next 12-24 months to reduce our exposure to fluctuations in oil and gas prices. In the case of significant acquisitions, we may hedge acquired production for a longer period. In addition, we may utilize basis contracts to hedge the differential between the NYMEX Henry Hub posted prices and those of our physical pricing points. 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 also may limit future revenues from favorable price movements. In addition, the use of hedging transactions may involve basis risk. All of our hedging transactions have been carried out in the over-the-counter market. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty and we have netting arrangements with all of our counterparties that provide for offsetting payables against receivables from separate hedging arrangements with that counterparty. At September 30, 2010, Barclays Capital, JPMorgan Chase Bank, Bank of Montreal, J Aron & Company and Societe Generale were the counterparties with respect to 81% of our future hedged production, the largest of which was J Aron & Company and accounted for 25% of our future hedged production.

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A significant number of the counterparties to our hedging arrangements also are lenders under our credit facility. Our credit facility, senior subordinated notes and substantially all of our hedging arrangements contain provisions that provide for cross defaults and acceleration of those debt and hedging instruments in certain situations.

Substantially all of our hedging transactions are settled based upon reported settlement prices on the NYMEX. Historically, a majority of our hedged oil and gas production has been sold at market prices that have had a high positive correlation to the settlement price for such hedges.

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 $0.25-$0.50 per MMBtu less than the Henry Hub Index. Realized natural gas prices for our Mid-Continent properties, after basis differentials, transportation and handling charges, typically average 85-90% of the Henry Hub Index. In the Rocky Mountains, we hedged basis associated with approximately 11 Bcf of our natural gas production from October 2010 through December 2012 to lock in the differential at a weighted-average of $0.94 per MMBtu less than the Henry Hub Index. In total, this hedge and the 8,000 MMBtus per day we have sold on a fixed physical basis for the same period results in an average basis hedge of $0.92 per MMBtu less than the Henry Hub Index. In the Mid-Continent, we hedged basis associated with approximately 6 Bcf of our anticipated Stiles/Britt Ranch natural gas production from October 2010 through August 2011. In total, this hedge and the 30,000 MMBtus per day we have sold on a fixed physical basis for the same period results in an average basis hedge of $0.52 per MMBtu less than the Henry Hub Index. We have also hedged basis associated with approximately 23 Bcf of our natural gas production from this area for the period September 2011 through December 2012 at an average of $0.55 per MMBtu less than the Henry Hub Index.

The price we receive for our Gulf Coast oil production typically averages about 90-95% of 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 our Mid-Continent properties typically averages 88-92% of the WTI price. Oil sales from our operations in Malaysia typically sell at a slight discount to Tapis, or about 90-95% of WTI. Oil sales from our operations in China typically sell at $4-$6 per barrel less than the WTI price.

New Accounting Requirements

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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 and sources of capital resources to fund capital expenditures and other plans and objectives for future operations. Although we believe that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Actual results may vary significantly from those anticipated due to many factors, including:

•	oil and gas prices;

•	general economic, financial, industry or business conditions;

•	the impact of legislation and governmental regulations;

•	the impact of regulatory approvals;

•	the availability of the securities, capital or credit markets and the cost of capital to fund our operations and business strategies;

•	the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us;

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

•	drilling results;

•	the prices of goods and services;

•	the availability of drilling rigs and other support services;

•	labor conditions;

•	weather conditions, and changes in weather patterns, including adverse conditions and changes in patterns due to climate change;

•	environmental liabilities that are not covered by an effective indemnity or insurance;

•	changes in tax rates;

•	changes in estimates of reserves;

•	the effect of worldwide energy conservation measures;

•	the price and availability of, and demand for, competing energy sources; 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, 2009 and under Item 1A of this report.

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All forward-looking statements in this report, as well as all other written and oral forward-looking statements attributable to us or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements contained in this section and elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2009. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information about factors that may affect our businesses and operating results. These factors are not necessarily all of the important factors that could affect us. Use caution and common sense when considering these forward-looking statements. Unless securities laws require us to do so, we do not undertake any obligation to publicly correct or update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.

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.

Completion. The installation of permanent equipment for the production of oil or natural gas.

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 gas reservoir 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. An exploration well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test 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.

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

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

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Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

MMBtu. One million Btus.

MMMBtu. One billion Btus.

NYMEX. The New York Mercantile Exchange.

NYMEX Henry Hub. Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub Index.

Proved reserves. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

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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 significant acquisitions, we may hedge acquired production for a longer period. In addition, we may utilize basis contracts to hedge the differential between NYMEX Henry Hub posted prices and those of our physical pricing points. We use hedging to reduce our exposure to fluctuations in oil and gas 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 also may limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. For a further 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 5, “Derivative Financial Instruments,” to our consolidated financial statements appearing earlier in this report.

Interest Rates

At September 30, 2010, our debt was comprised of:

	Fixed Rate Debt			Variable Rate Debt
	(In millions)
6 ⅝% Senior Subordinated Notes due 2014		$	325	$	—
6 ⅝% Senior Subordinated Notes due 2016			550		—
7 ⅛% Senior Subordinated Notes due 2018			600		—
6 ⅞% Senior Subordinated Notes due 2020			694		—
Total debt		$	2,169	$	—

Because 100% of our debt obligations were at fixed rates, we currently do not have exposure to interest rate changes.

Foreign Currency Exchange Rates

The functional currency for all of our 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 flow, to be immaterial. We did not have any open derivative contracts relating to foreign currencies at September 30, 2010.

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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 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 September 30, 2010.

Changes in Internal Control over Financial Reporting

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the third quarter of 2010 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 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 1. Legal Proceedings

There have been no material changes with respect to Newfield’s legal proceedings previously reported in Newfield’s Annual Report on Form 10-K for the year ended December 31, 2009.

Item 1A. Risk Factors

The following risk factors update and should be considered in addition to the risk factors previously disclosed in Newfield’s Annual Report on Form 10-K for the year ended December 31, 2009.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business. In addition, potential regulatory actions could increase our costs and reduce our liquidity, delay our operations or otherwise alter the way we conduct our business. Exploration and development and the production and sale of oil and gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

•	the amounts and types of substances and materials that may be released into the environment;

•	response to unexpected releases to the environment;

•	reports and permits concerning exploration, drilling, production and other operations;

•	the spacing of wells;

•	unitization and pooling of properties;

•	calculating royalties on oil and gas produced under federal and state leases; and

•

taxation.

Under these laws, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, natural resource damages and other environmental damages. We also could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action orders. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition, results of operations or cash flows.

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In addition, changes to existing regulations or the adoption of new regulations may unfavorably impact us, our suppliers or our customers. For example, governments around the world have become increasingly focused on climate change matters. In the United States, legislation that directly impacts our industry has been proposed covering areas such as emission reporting and reductions, hydraulic fracturing, the repeal of certain oil and gas tax incentives and tax deductions, and the regulation of over-the-counter commodity hedging activities. These and other potential regulations could increase our costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business, negatively impacting our financial condition, results of operations and cash flows.

Congress has been actively considering legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs. In June of 2009, the U.S. House of Representatives passed a cap and trade bill known as the American Clean Energy and Security Act of 2009, which is now being considered by the U.S. Senate. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases. Further, on April 2, 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act. On April 24, 2009, EPA responded to the Massachusetts, et al. v. EPA decision with a proposed finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change. EPA published the final version of this finding on December 15, 2009, which allowed EPA to proceed with the rulemaking process to regulate greenhouse gases under the Clean Air Act. In anticipation of the finalization of EPA’s finding that greenhouse gases threaten public health and welfare, and that greenhouse gases from new motor vehicles contribute to climate change, EPA proposed a rule in September of 2009 that would require a reduction in emissions of greenhouse gases from motor vehicles and would trigger applicability of Clean Air Act permitting requirements for certain stationary sources of greenhouse gas emissions. In response to this issue, EPA also proposed a tailoring rule that would, in general, only impose greenhouse gas permitting requirements on facilities that emit more than 25,000 tons per year of greenhouse gases. Moreover, on September 22, 2009, EPA finalized a rule requiring nation-wide reporting of greenhouse gas emissions in 2011 for emissions occurring in 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year, and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines.

In response to the recent oil spill in the Gulf of Mexico, the United States Congress is considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore that could result in significant additional laws or regulations governing our operations in the United States. These proposals include a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990, the Consolidated Land, Energy, and Aquatic Resources Act (CLEAR), the Clean Energy Jobs and Oil Company Accountability Act, the Blowout Prevention Act, and public land leasing reforms.

Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Additional costs or operating restrictions associated with legislation or regulations could have a material adverse effect on our operating results and cash flows, in addition to the demand for the natural gas and other hydrocarbon products that we produce.

Federal legislation regarding derivatives could have an adverse effect on our ability and cost of entering into derivative transactions. On July 21, 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Reform Act), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation requires the Commodities Futures Trading Commission (the CFTC) and the Securities and Exchange Commission to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. On October 1, 2010, the CFTC introduced its first series of proposed rules coming out of the Dodd-Frank Reform Act. The effect of the proposed rules and any additional regulations on our business is currently uncertain. Of particular concern, the Dodd-Frank Reform Act does not explicitly exempt end users (such as us) from the requirements to post margin in connection with hedging activities. While several senators have indicated that it was not the intent of the Act to require margin from end users, the exemption is not in the act. The new requirements to be enacted, to the extent applicable to us or our derivatives counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments we use to hedge and otherwise manage our financial and commercial risks related to fluctuations in oil and gas commodity prices. Any of the foregoing consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

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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 three months ended September 30, 2010.

Period	Total Number of Shares Purchased(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet be Purchased Under the Plans or Programs
July 1 - July 31, 2010	2,014	$	48.90	—	—
August 1 - August 31, 2010	5,477		53.04	—	—
September 1 - September 30, 2010	4,440		49.27	—	—
Total	11,931	$	50.93	—	—

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

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Item 6. Exhibits

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

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

3.1.2		Certificate of Amendment to Second Restated Certificate of Incorporation of Newfield dated May 12, 2004 (incorporated by reference to Exhibit 4.2.3 to Newfield’s Registration Statement on Form S-8 (Registration No. 333-116191))

3.1.3		Certificate of Designation of Series A Junior Participating Preferred Stock, par value $0.01 per share, setting forth the terms of the Series A Junior Participating Preferred Stock, par value $0.01 per share (incorporated by reference to Exhibit 3.5 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 1-12534))

3.2		Amended and Restated Bylaws of Newfield (incorporated by reference to Exhibit 3.2 to Newfield’s Current Report on Form 8-K filed with the SEC on February 6, 2009 (File No. 1-12534))

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.

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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.

Table of Contents

Exhibit Index

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

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

3.1.2		Certificate of Amendment to Second Restated Certificate of Incorporation of Newfield dated May 12, 2004 (incorporated by reference to Exhibit 4.2.3 to Newfield’s Registration Statement on Form S-8 (Registration No. 333-116191))

3.1.3		Certificate of Designation of Series A Junior Participating Preferred Stock, par value $0.01 per share, setting forth the terms of the Series A Junior Participating Preferred Stock, par value $0.01 per share (incorporated by reference to Exhibit 3.5 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 1-12534))

3.2		Amended and Restated Bylaws of Newfield (incorporated by reference to Exhibit 3.2 to Newfield’s Current Report on Form 8-K filed with the SEC on February 6, 2009 (File No. 1-12534))

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.