Edgar Filing: NEWFIELD EXPLORATION CO /DE/

Large accelerated filer þ

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

NFX 2014 Q3 - 10Q

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, 2014



¨		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)

4 Waterway Square Place

Suite 100

The Woodlands, Texas 77380

(Address and Zip Code of principal executive offices)

(281) 210-5100

(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 ¨

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 ¨

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):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ

As of October 28, 2014, there were 137,229,465 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, 2014 and December 31, 2013	1

	Consolidated Statement of Operations for the three and nine months ended September 30, 2014 and 2013	2

	Consolidated Statement of Comprehensive Income for the three and nine months ended September 30, 2014 and 2013	3

	Consolidated Statement of Cash Flows for the nine months ended September 30, 2014 and 2013	4

	Consolidated Statement of Stockholders' Equity for the nine months ended September 30, 2014	5

	Notes to Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36

Item 4.	Controls and Procedures	36


PART II

Item 1.	Legal Proceedings	37

Item 1A.	Risk Factors	37

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38

Item 6.	Exhibits	39

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEET

(In millions, except share data)

(Unaudited)



	September 30, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	396		$	95
Restricted cash	—			90
Accounts receivable	395			474
Inventories	38			163
Derivative assets	48			—
Deferred taxes	—			22
Other current assets	29			57
Total current assets	906			901
Oil and gas properties — full cost method ($1,438 and $1,300 were excluded from amortization at September 30, 2014 and December 31, 2013, respectively)	15,786			16,407
Less — accumulated depreciation, depletion and amortization	(7,915		)	(8,306		)
Total oil and gas properties, net	7,871			8,101
Other property and equipment, net	180			174
Derivative assets	56			26
Long-term investments	26			63
Deferred taxes	—			19
Other assets	29			37
Total assets	$	9,068		$	9,321

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	65		$	76
Accrued liabilities	827			978
Deferred liabilities	—			90
Advances from joint owners	27			30
Asset retirement obligations	5			54
Derivative liabilities	1			62
Total current liabilities	925			1,290
Other liabilities	40			38
Long-term debt	3,046			3,694
Asset retirement obligations	105			201
Deferred taxes	1,427			1,142
Total long-term liabilities	4,618			5,075

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, 2014 and December 31, 2013; 137,469,404 and 136,682,631 shares issued at September 30, 2014 and December 31, 2013, respectively)	1			1
Additional paid-in capital	1,564			1,539
Treasury stock (at cost, 256,984 and 460,914 shares at September 30, 2014 and December 31, 2013, respectively)	(9		)	(13		)
Accumulated other comprehensive gain (loss)	2			2
Retained earnings	1,967			1,427
Total stockholders' equity	3,525			2,956
Total liabilities and stockholders' equity	$	9,068		$	9,321

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF OPERATIONS

(In millions, except per share data)

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Oil, gas and NGL revenues	$	610		$	486		$	1,771		$	1,291

Operating expenses:
Lease operating	126			104			356			299
Production and other taxes	31			19			85			52
Depreciation, depletion and amortization	228			171			628			482
General and administrative	48			61			172			160
Other	8			—			8			—
Total operating expenses	441			355			1,249			993
Income (loss) from operations	169			131			522			298

Other income (expense):
Interest expense	(51		)	(52		)	(153		)	(153		)
Capitalized interest	13			13			39			40
Commodity derivative income (expense)	303			(99		)	33			(66		)
Other, net	1			1			4			5
Total other income (expense)	266			(137		)	(77		)	(174		)

Income (loss) from continuing operations before income taxes	435			(6		)	445			124

Income tax provision (benefit):
Current	1			(4		)	1			(4		)
Deferred	155			2			164			51
Total income tax provision (benefit)	156			(2		)	165			47
Income (loss) from continuing operations	279			(4		)	280			77
Income (loss) from discontinued operations, net of tax	(1		)	31			260			53
Net income (loss)	$	278		$	27		$	540		$	130

Earnings (loss) per share:
Basic:
Income (loss) from continuing operations	$	2.04		$	(0.03	)	$	2.06		$	0.57
Income (loss) from discontinued operations	—			0.08			1.90			0.24
Basic earnings (loss) per share	$	2.04		$	0.05		$	3.96		$	0.81
Diluted:
Income (loss) from continuing operations	$	2.02		$	(0.03	)	$	2.04		$	0.57
Income (loss) from discontinued operations	—			0.08			1.88			0.24
Diluted earnings (loss) per share	$	2.02		$	0.05		$	3.92		$	0.81

Weighted-average number of shares outstanding for basic earnings (loss) per share	137			136			137			135

Weighted-average number of shares outstanding for diluted earnings (loss) per share	138			136			138			136

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(In millions)

(Unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Net income (loss)	$	278	$	27	$	540	$	130
Other comprehensive income (loss):
Unrealized gain (loss) on investments, net of tax	—		—		—		3
Other comprehensive income (loss), net of tax	—		—		—		3
Comprehensive income (loss)	$	278	$	27	$	540	$	133

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)

(Unaudited)



	Nine Months Ended
	September 30,
	2014			2013
Cash flows from operating activities:
Net income (loss)	$	540		$	130
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	665			664
Deferred tax provision (benefit)	308			89
Stock-based compensation	15			35
Commodity derivative (income) expense	(33		)	66
Cash receipts (payments) related to derivative contracts, net	(106		)	45
Gain on sale of Malaysia business	(388		)	—
Other, net	1			7
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	89			16
(Increase) decrease in inventories	(1		)	(4		)
(Increase) decrease in other current assets	(2		)	8
(Increase) decrease in other assets	1			4
Increase (decrease) in accounts payable and accrued liabilities	(20		)	30
Increase (decrease) in advances from joint owners	(1		)	10
Increase (decrease) in other liabilities	2			(5		)
Net cash provided by (used in) operating activities	1,070			1,095

Cash flows from investing activities:
Additions to oil and gas properties	(1,535		)	(1,441		)
Acquisitions of oil and gas properties	(21		)	(64		)
Proceeds from sales of oil and gas properties	616			25
Proceeds received from sale of Malaysia business, net	809			—
Additions to other property and equipment	(22		)	(25		)
Redemptions of investments	39			1
Net cash provided by (used in) investing activities	(114		)	(1,504		)

Cash flows from financing activities:
Proceeds from borrowings under credit arrangements	2,076			2,409
Repayments of borrowings under credit arrangements	(2,725		)	(1,969		)
Debt issue costs	—			(4		)
Proceeds from issuances of common stock	4			1
Repurchase of preferred shares of subsidiary	—			(20		)
Purchases of treasury stock, net	(10		)	(7		)
Net cash provided by (used in) financing activities	(655		)	410

Increase (decrease) in cash and cash equivalents	301			1
Cash and cash equivalents, beginning of period	95			88
Cash and cash equivalents, end of period	$	396		$	89

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(In millions)

(Unaudited)



									Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Gain (Loss)		Total Stockholders' Equity
	Common Stock			Treasury Stock
	Shares	Amount		Shares		Amount
Balance, December 31, 2013	136.7	$	1	(0.5	)	$	(13	)	$	1,539		$	1,427	$	2	$	2,956
Issuances of common stock	0.8	—							4							4
Stock-based compensation									35							35
Treasury stock, net				0.2		4			(14		)					(10		)
Net income												540				540
Balance, September 30, 2014	137.5	$	1	(0.3	)	$	(9	)	$	1,564		$	1,967	$	2	$	3,525

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

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and Summary of Significant Accounting Policies:

Organization and Principles of Consolidation

We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids (NGLs). Our principal areas of operation include the Mid-Continent, the Rocky Mountains and the onshore Gulf Coast regions of North America.

Our consolidated financial statements include the accounts of Newfield Exploration Company, a Delaware corporation, and its subsidiaries. We proportionately consolidate our interests in oil and natural 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,” “our” or the “Company” 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 fairly state 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 consolidated 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, 2013.

Discontinued Operations

Our businesses in Malaysia and China were classified as held for sale in the second quarter of 2013. Accordingly, the results of our international operations are reflected separately as discontinued operations in the consolidated statement of operations on a line immediately after “Income (loss) from continuing operations.” See Note 3, “Discontinued Operations,” for additional disclosures, as well as information regarding the sale of our Malaysia business, which closed in February 2014. These financial statements and notes are inclusive of our international operations unless otherwise noted.

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 quantities and values of proved oil, natural gas and NGL reserves used in calculating depletion and assessing impairment of our oil and gas properties. Actual results could differ significantly from these estimates. Our most significant estimates are associated with the quantities of proved oil, natural gas and NGL reserves and the fair value of both our derivative positions and our stock-based compensation liability awards.

Reclassifications

Certain reclassifications have been made to prior years' reported amounts in order to conform to the current year presentation. These reclassifications did not impact our net income (loss), stockholders' equity or cash flows.

Restricted Cash and Deferred Liabilities

Restricted cash and the associated deferred liability on our consolidated balance sheet at December 31, 2013, represent a deposit received in the fourth quarter of 2013 related to the sale of our Malaysia business. Amounts were contractually restricted until the transaction closed in February 2014. See Note 3, “Discontinued Operations,” for further discussion about the close of the sale of our Malaysia business.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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, interest and other internal costs directly attributable to these activities, are capitalized into cost centers that are established on a country-by-country basis. We capitalized approximately $38 million and $47 million of interest and direct internal costs during the three-month periods ended September 30, 2014 and 2013, respectively, and $158 million and $147 million during the nine-month periods ended September 30, 2014 and 2013, respectively.

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. During the first quarter of 2014, we recognized a gain of approximately $388 million ($249 million, after tax) on the sale of our Malaysia business, which constituted the entire full cost pool for Malaysia. See Note 3, “Discontinued Operations,” for further discussion.

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. We did not have a ceiling test writedown in any periods presented.

New Accounting Requirements

In August 2014, the FASB issued guidance regarding disclosures of uncertainties about an entity's ability to continue as a going concern. The guidance applies prospectively to all entities, requiring management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern and disclose certain information when substantial doubt is raised. The guidance is effective for interim and annual periods beginning on or after December 15, 2016. We do not expect adoption of this guidance to have a material impact on our financial position or results of operations.

In June 2014, the FASB issued guidance regarding stock-based compensation awards with targets that affect vesting and that could be achieved after the requisite service period. The guidance applies on a prospective basis to awards that are granted or modified on or after the effective date. The guidance is effective for annual periods beginning after December 15, 2015, and interim periods within those annual periods. We do not expect adoption of this guidance to have a material impact on our financial position or results of operations.

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings. The guidance is effective for interim and annual periods beginning on or after December 15, 2016. We are currently evaluating the impact of this guidance on our financial statements.

In April 2014, the FASB issued guidance regarding the reporting of discontinued operations. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. The guidance is effective for interim and annual periods beginning on or after December 15, 2014. We do not expect adoption of this guidance to have a material impact on our financial position or results of operations.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

2. Earnings Per Share:

The following is the calculation of basic and diluted weighted-average shares outstanding and earnings per share (EPS) for the indicated periods:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014		2013
	(In millions, except per share data)
Income (numerator):
Income (loss) from continuing operations	$	279		$	(4	)	$	280	$	77
Income (loss) from discontinued operations, net of tax	(1		)	31			260		53
Net income (loss)	278			27			540		130
Repurchase of preferred shares of subsidiary⁽³⁾	—			(20		)	—		(20		)
Net income (loss) attributable to common shareholders	$	278		$	7		$	540	$	110

Weighted-average shares (denominator):
Weighted-average shares — basic	137			136			137		135
Dilution effect of stock options and unvested restricted stock and restricted stock units outstanding at end of period^{(1) (2)}	1			—			1		1
Weighted-average shares — diluted	138			136			138		136

Earnings (loss) per share:
Basic:
Income (loss) from continuing operations	$	2.04		$	(0.03	)	$	2.06	$	0.57
Income (loss) from discontinued operations before preferred share repurchase	—			0.23			1.90		0.39
Repurchase of preferred shares of subsidiary⁽³⁾	—			(0.15		)	—		(0.15		)
Income (loss) from discontinued operations	—			0.08			1.90		0.24
Basic earnings (loss) per share	$	2.04		$	0.05		$	3.96	$	0.81
Diluted:
Income (loss) from continuing operations	$	2.02		$	(0.03	)	$	2.04	$	0.57
Income (loss) from discontinued operations before preferred share repurchase	—			0.23			1.88		0.39
Repurchase of preferred shares of subsidiary⁽³⁾	—			(0.15		)	—		(0.15		)
Income (loss) from discontinued operations	—			0.08			1.88		0.24
Diluted earnings (loss) per share	$	2.02		$	0.05		$	3.92	$	0.81

_______


(1)	Excludes 0.3 million and 1.1 million shares of unvested restricted stock or restricted stock units and stock options for the three and nine months ended September 30, 2014 and 4.1 million shares for the nine months ended September 30, 2013 because including the effect would have been anti-dilutive.

(2)

The effect of unvested restricted stock or restricted stock units and stock options has not been included in the calculation of the shares outstanding for diluted EPS for the three months ended September 30, 2013, as their effect would have been anti-dilutive. Had we recognized income from continuing operations for this period, incremental shares attributable to the assumed vesting of unvested restricted stock and restricted stock units and the assumed exercise of outstanding stock options would have increased diluted weighted-average shares outstanding by 0.7 million shares for the three months ended September 30, 2013.


(3)	The numerator includes an adjustment of $20 million related to the repurchase of preferred shares of a now wholly-owned subsidiary, which reduces net income (loss) for purposes of earnings per share for the three and nine months ended September 30, 2013. The subsidiary is part of our discontinued operations. See Note 14, “Related-Party Transactions,” for additional information.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

3. Discontinued Operations:

Malaysia Update

In February 2014, Newfield International Holdings, Inc., a wholly-owned subsidiary of the Company, closed the stock purchase agreement to sell its Malaysia business to SapuraKencana Petroleum Berhad, a Malaysian public company, for approximately $898 million (subject to purchase price adjustments). As a result of the sale, we recorded a gain in the first quarter of 2014 of approximately $388 million ($249 million, after tax). As of the date of this report, the final post-close settlement is pending due to a dispute with the purchaser regarding certain post-closing adjustments. We have not recorded any adjustments to the sales price or the gain recognized as we believe the Company would prevail in the event of arbitration on this matter.

China Update

In August 2013, during the installation of the LF-7 topside facilities by a third-party contractor, a hydraulic jacking system malfunctioned, and the installation was suspended. In August 2014, the LF-7 topside facilities were installed, and we began drilling our first well. We expect to achieve first oil production in the fourth quarter of 2014 and continue to work with potential purchasers of our China business.

Loss from discontinued operations from our China business was $2 million ($1 million, net of tax) for the three months ended September 30, 2014, and income was $8 million ($2 million, net of tax) for the nine months ended September 30, 2014. Income from discontinued operations from our China business was $9 million ($8 million, net of tax) for the three months ended September 30, 2013 and $26 million ($13 million, net of tax) for the nine months ended September 30, 2013.

Results of Discontinued Operations



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014		2013
	(In millions)
Oil and gas revenues⁽¹⁾	$	—		$	189		$	112	$	659
Operating expenses	2			128			83		501
Income (loss) from discontinued operations	(2		)	61			29		158
Other income (expense)	—			(1		)	—		(2		)
Gain on sale of Malaysia business	—			—			388		—
Income (loss) from discontinued operations before income taxes	(2		)	60			417		156
Income tax provision (benefit):
Current	(1		)	10			13		65
Deferred	—			19			144		38
Total income tax provision (benefit)	(1		)	29			157		103
Income (loss) from discontinued operations, net of tax	$	(1	)	$	31		$	260	$	53

________________


(1)	Certain payments to foreign governments made on our behalf that are part of the revenue process are recorded as a reduction of the related oil and gas revenues.

Income Taxes

Historically, our international effective tax rate has been approximately 37%. As a result of our December 2012 decision to repatriate earnings from our international operations, we have experienced higher international effective tax rates due to these earnings being taxed both in the U.S. and the local countries. We expect this to continue until we fully divest our international businesses. The effective tax rate for our discontinued operations for the three months ended September 30, 2014 was 63.1% and for the nine months ended September 30, 2014 was 37.8% as the majority of our income (loss) from discontinued operations resulted from the gain on the sale of our Malaysia business, which was only taxable in the U.S. The effective tax rate

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

for our discontinued operations for the three months ended September 30, 2013 was 48.2% and for the nine months ended September 30, 2013 was 65.7%.

Assets and Liabilities in the Consolidated Balance Sheet Attributable to Discontinued Operations



	September 30,		December 31,
	2014		2013
	(In millions)
Current assets:
Cash and cash equivalents	$	27	$	84
Accounts receivable	89		200
Inventories	14		130
Other current assets	5		33
Total current assets	135		447
Noncurrent assets:
Oil and gas properties, net of accumulated depreciation, depletion and amortization of $118 and $1,121 as of September 30, 2014 and December 31, 2013, respectively	540		989
Deferred taxes	—		19
Other assets	1		4
Total noncurrent assets	541		1,012
Total assets	$	676	$	1,459

Current liabilities:
Accounts payable	$	3	$	38
Accrued liabilities	202		324
Asset retirement obligations	—		49
Other current liabilities	—		18
Total current liabilities	205		429
Noncurrent liabilities:
Asset retirement obligations	2		86
Deferred taxes	104		129
Other liabilities	—		11
Total noncurrent liabilities	106		226
Total liabilities	$	311	$	655

Inventories

Substantially all of the crude oil from our international offshore operations is produced into floating production, storage and off-loading vessels (FPSOs) and “lifted” and sold periodically as barge quantities are accumulated. At December 31, 2013, the crude oil inventory from our Malaysia and China operations consisted of approximately 1.1 million barrels of crude oil valued at cost of $90 million and is included in the “Inventories” line item in the preceding table and in our consolidated balance sheet. Cost for purposes of the carrying value of oil inventory is the sum of related production costs and depletion expense. As of September 30, 2014, we had crude oil inventory of approximately 75,000 barrels valued at cost of $3 million related to our China operations. The remaining inventory is materials and supplies for use in our oil and gas operations.

Oil and Gas Properties

As of September 30, 2014, all of our oil and gas properties in our discontinued operations were subject to amortization. As of December 31, 2013, approximately $115 million of our Malaysia oil and gas properties in our discontinued operations were not subject to amortization.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Asset Retirement Obligations

During the nine months ended September 30, 2014, asset retirement obligations were reduced by $133 million as a result of the sale of our Malaysia business in February 2014.

4. Oil and Gas Assets:

Property and Equipment

Property and equipment consisted of the following:



	September 30, 2014			December 31, 2013
	(In millions)
Oil and gas properties:
Subject to amortization	$	14,348		$	15,107
Not subject to amortization	1,438			1,300
Gross oil and gas properties	15,786			16,407
Accumulated depreciation, depletion and amortization	(7,915		)	(8,306		)
Net oil and gas properties	$	7,871		$	8,101
Other property and equipment:
Furniture, fixtures and equipment	$	150		$	139
Gathering systems and equipment	111			104
Accumulated depreciation and amortization	(81		)	(69		)
Net other property and equipment	$	180		$	174

Oil and gas properties not subject to amortization as of September 30, 2014, consisted of the following:



	Costs Incurred In
	2014		2013		2012		2011 and Prior		Total
	(In millions)
Acquisition costs	$	129	$	199	$	86	$	410	$	824
Exploration costs	345		1		1		7		354
Development costs	14		8		31		11		64
Fee mineral interests	—		1		—		23		24
Capitalized interest	39		53		67		13		172
Total oil and gas properties not subject to amortization	$	527	$	262	$	185	$	464	$	1,438

Granite Wash Asset Sale

On September 19, 2014, we closed on the sale of our Granite Wash assets, located primarily in Texas, for approximately $588 million, subject to customary post-closing purchase price adjustments. The sale of our Granite Wash assets did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our domestic full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Granite Wash operations through the date of sale.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

5. Derivative Financial Instruments:

Commodity Derivative Instruments

We utilize derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of our future domestic oil and natural gas production. While the use of derivative instruments limits the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements.

In addition to the derivative strategies outlined in our annual Report on Form 10-K for the year ended December 31, 2013, we also utilize swaptions from time to time. A swaption is an option to exercise a swap where the buyer (counterparty) of the swaption purchases the right from the seller (Newfield), but not the obligation, to enter into a fixed-price swap with the seller on a predetermined date (expiration date). The swap price is a fixed price determined at the time of the swaption contract. If the swaption is exercised, the contract will become a swap treated consistent with our other fixed-price swaps.

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, estimated volatility, non-performance risk adjustments using credit default swaps and time to maturity. The calculation of the fair value of options requires the use of an option-pricing model. See Note 8, “Fair Value Measurements.”

At September 30, 2014, we had outstanding derivative positions as set forth in the tables below.

Natural Gas



		NYMEX Contract Price Per MMBtu
						Collars				Estimated Fair Value Asset (Liability)
Period and Type of Instrument	Volume in MMMBtus	Swaps (Weighted Average)		Sold Puts (Weighted Average)		Floors (Weighted Average)		Ceilings (Weighted Average)		Estimated Fair Value Asset (Liability)
										(In millions)
2014:
Fixed-price swaps	20,400	$	3.97	$	—	$	—	$	—	$	(2	)
Collars	5,980	—		—		3.75		4.62		—
2015:
Fixed-price swaps	49,275	4.28		—		—		—		14
Collars	38,325	—		—		3.93		4.74		7
Total										$	19

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Crude Oil



		NYMEX Contract Price Per Bbl
						Collars				Estimated Fair Value Asset (Liability)
Period and Type of Instrument	Volume in MBbls	Swaps (Weighted Average)		Sold Puts (Weighted Average)		Floors (Weighted Average)		Ceilings (Weighted Average)		Estimated Fair Value Asset (Liability)
										(In millions)
2014:
Fixed-price swaps	2,116	$	89.94	$	—	$	—	$	—	$	(1	)
Fixed-price swaps with sold puts	1,472	95.16		75.00		—		—		7
Collars with sold puts	552	—		75.83		90.83		102.93		1
2015:
Fixed-price swaps	8,845	90.42		—		—		—		23
Fixed-price swaps with sold puts	7,354	90.22		69.75		—		—		11
Collars with sold puts	730	—		75.00		90.00		104.00		3
2016:
Fixed-price swaps with sold puts	7,864	90.89		74.59		—		—		14
Collars with sold puts	6,220	—		75.00		90.00		96.15		19
Swaptions ⁽¹⁾	—	91.00		—		—		—		(1		)
2017:
Fixed-price swaps with sold puts	1,180	90.63		75.00		—		—		2
Collars with sold puts	2,080	—		75.00		90.00		95.59		6
Total										$	84

________


(1)	During the third quarter of 2014, we sold crude oil swaption contracts that, if exercised on their expiration date in the first quarter of 2015, would hedge 732 MBbls of calendar-year 2016 production. These contracts give the counterparties the option to enter into swap contracts with us at $91.00/Bbl for calendar-year 2016.

Additional Disclosures about Derivative Financial Instruments

We had derivative financial instruments recorded in our consolidated balance sheet as assets (liabilities) at their respective estimated fair value, as set forth below.



	Derivative Assets									Derivative Liabilities
	Gross Fair Value		Offset in Balance Sheet			Balance Sheet Location				Gross Fair Value			Offset in Balance Sheet		Balance Sheet Location
	Gross Fair Value		Offset in Balance Sheet			Current		Noncurrent		Gross Fair Value			Offset in Balance Sheet		Current			Noncurrent
	(In millions)									(In millions)
September 30, 2014
Natural gas positions	$	23	$	(3	)	$	15	$	5	$	(4	)	$	3	$	(1	)	$	—
Oil positions	141		(57		)	33		51		(57		)	57		—			—
Total	$	164	$	(60	)	$	48	$	56	$	(61	)	$	60	$	(1	)	$	—

December 31, 2013
Natural gas positions	$	11	$	(2	)	$	—	$	9	$	(22	)	$	2	$	(20	)	$	—
Oil positions	26		(9		)	—		17		(51		)	9		(42		)	—
Total	$	37	$	(11	)	$	—	$	26	$	(73	)	$	11	$	(62	)	$	—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

The amount of gain (loss) recognized in “Commodity derivative income (expense)” in our consolidated statement of operations related to our derivative financial instruments follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In millions)
Derivatives not designated as hedging instruments:
Realized gain (loss) on natural gas positions	$	(2	)	$	19		$	(36	)	$	51
Realized gain (loss) on oil positions	(18		)	(12		)	(70		)	(9		)
Total realized gain (loss)	(20		)	7			(106		)	42
Unrealized gain (loss) on natural gas positions	38			(6		)	30			(24		)
Unrealized gain (loss) on oil positions	285			(100		)	109			(84		)
Total unrealized gain (loss)	323			(106		)	139			(108		)
Total	$	303		$	(99	)	$	33		$	(66	)

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, 2014, 10 of our 16 counterparties accounted for approximately 85% of our contracted volumes, with no single counterparty accounting for more than 15%.

A portion of our derivative instruments are with lenders under our credit facility. Our credit facility, senior notes, 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:

Accounts receivable consisted of the following:



	September 30, 2014			December 31, 2013
	(In millions)
Revenue	$	176		$	294
Joint interest	183			156
Other	37			25
Reserve for doubtful accounts	(1		)	(1		)
Total accounts receivable	$	395		$	474

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

7. Accrued Liabilities:

Accrued liabilities consisted of the following:



	September 30, 2014		December 31, 2013
	(In millions)
Revenue payable	$	179	$	175
Accrued capital costs	449		458
Accrued lease operating expenses	27		71
Employee incentive expense	49		64
Accrued interest on debt	48		72
Taxes payable	28		93
Other	47		45
Total accrued liabilities	$	827	$	978

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 are 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 fixed-price swaps and certain investments.


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). Level 3 instruments primarily include derivative instruments, such as commodity options (i.e., price collars, sold puts or swaptions) and other financial investments.


•	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.


•	Our valuation model for the Stockholder Value Appreciation Program (SVAP) is a Monte Carlo simulation that is based on a probability model and considers various inputs including: (a) the measurement date stock price, (b) time value and (c) historical and implied volatility. See Note 11, “Stock-Based Compensation,” for a description of the SVAP.

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.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Recurring Fair Value Measurements

The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis.



	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, 2013:
Money market fund investments	$	2		$	—		$	—		$	2
Deferred compensation plan assets	8			—			—			8
Investments available-for-sale:
Equity securities	8			—			—			8
Auction rate securities	—			—			39			39
Oil and gas derivative swap contracts	—			(28		)	—			(28		)
Oil and gas derivative option contracts	—			—			(8		)	(8		)
Stock-based compensation liability awards	(11		)	—			(5		)	(16		)
Total	$	7		$	(28	)	$	26		$	5

As of September 30, 2014:
Money market fund investments	$	365		$	—		$	—		$	365
Deferred compensation plan assets	9			—			—			9
Equity securities available-for-sale	9			—			—			9
Oil and gas derivative swap contracts	—			104			—			104
Oil and gas derivative option contracts	—			—			(1		)	(1		)
Stock-based compensation liability awards	(13		)	—			(7		)	(20		)
Total	$	370		$	104		$	(8	)	$	466

The determination of the fair values above incorporates various factors, which include not only the impact of our non-performance risk on our derivative 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), if any. 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 December 31, 2013, we held $39 million of auction rate securities, which were classified as a Level 3 fair value measurement. During the first quarter of 2014, all auction rate securities were sold for $39 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Level 3 Fair Value Measurements

The following table sets 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			Stock-Based Compensation			Total
	(In millions)
Balance at January 1, 2013	$	36		$	115		$	—		$	151
Realized or unrealized gains (losses):
Included in earnings	—			(59		)	(8		)	(67		)
Included in other comprehensive income (loss)	4			—			—			4
Purchases, issuances, sales and settlements:
Settlements	(1		)	(46		)	—			(47		)
Transfers in to Level 3	—			—			—			—
Transfers out of Level 3	—			—			—			—
Balance at September 30, 2013	$	39		$	10		$	(8	)	$	41

Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at September 30, 2013	$	—		$	(8	)	$	(8	)	$	(16	)

Balance at January 1, 2014	$	39		$	(8	)	$	(5	)	$	26
Realized or unrealized gains (losses) included in earnings	—			—			(42		)	(42		)
Purchases, issuances, sales and settlements:
Sales	(39		)	—			—			(39		)
Settlements	—			4			40			44
Transfers in to Level 3	—			—			—			—
Transfers out of Level 3⁽¹⁾	—			3			—			3
Balance at September 30, 2014	$	—		$	(1	)	$	(7	)	$	(8	)

Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at September 30, 2014	$	—		$	20		$	(3	)	$	17

________


(1)	During the second quarter of 2014, we transferred $3 million of derivative option contracts out of the Level 3 hierarchy. The transfer was a result of our Level 3 swaptions being exercised by the counterparties as swaps on May 30, 2014.

Qualitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

Derivatives. Our valuation models for Level 3 derivative contracts are primarily industry-standard models that consider various factors, including certain significant unobservable inputs such as (a) quoted forward prices for commodities, (b) volatility factors and (c) counterparty credit risk. The calculation of the fair value of our option contracts requires the use of an option-pricing model. The estimated future prices are compared to the strike prices fixed by our derivative contracts, and the resulting estimated future cash inflows or outflows over the contractual life are discounted to calculate the fair value. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differences and interest rates. Significant increases (decreases) in the quoted forward prices for commodities generally lead to corresponding decreases (increases) in the fair value measurement of our oil and gas derivative contracts. Significant changes in the volatility factors utilized in our option-pricing model can cause significant changes in the fair value measurement of our oil and gas derivative contracts.

The determination of the fair values of derivative instruments incorporates various factors that 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). Historically, we have not experienced significant

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

changes in the fair value of our derivative contracts resulting from changes in counterparty credit risk as the counterparties for all of our derivative transactions have an “investment grade” credit rating.

Stock-Based Compensation. The calculation of the fair value of the SVAP liability requires the use of a probability-based Monte Carlo simulation, which includes unobservable inputs. The simulation predicts multiple scenarios of future stock returns over the performance period, which are discounted to calculate the fair value. The fair value is recognized over a service period derived from the simulation. Future stock returns and discounting variables are sensitive to market volatility. Significant increases (decreases) in the volatility factors utilized in our option-pricing model can cause significant increases (decreases) in the fair value measurement of the SVAP liability.

Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements



	Estimated Fair Value Asset (Liability)			Quantitative Information about Level 3 Fair Value Measurements
Instrument Type	Estimated Fair Value Asset (Liability)			Valuation Technique	Unobservable Input	Range
	(In millions)
Oil option contracts	$	(8	)	Black-Scholes	Oil price volatility	14.54	%	—	52.12	%
					Credit risk	0.01	%	—	3.95	%
Natural gas option contracts	$	7		Black-Scholes	Natural gas price volatility	24.78	%	—	50.03	%
					Credit risk	0.01	%	—	0.64	%
SVAP	$	(7	)	Monte Carlo	Implied volatility				37.0	%

Fair Value of Debt

The estimated fair value of our notes, based on quoted prices in active markets (Level 1) as of the indicated dates, was as follows:



	September 30, 2014		December 31, 2013
	(In millions)
5¾% Senior Notes due 2022	$	836	$	767
5⅝% Senior Notes due 2024	1,072		1,025
7⅛% Senior Subordinated Notes due 2018	615		624
6⅞% Senior Subordinated Notes due 2020	730		755

Any amounts outstanding under our credit arrangements as of the indicated dates are stated at cost, which approximates fair value. Please see Note 9, “Debt.”

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

9. Debt:

Our debt consisted of the following:



	September 30, 2014			December 31, 2013
	(In millions)
Senior unsecured debt:
Revolving credit facility - LIBOR based loans	$	—		$	585
Money market lines of credit⁽¹⁾	—			64
Total credit arrangements	—			649
5¾% Senior Notes due 2022	750			750
5⅝% Senior Notes due 2024	1,000			1,000
Total senior unsecured debt	1,750			2,399
7⅛% Senior Subordinated Notes due 2018⁽²⁾	600			600
6⅞% Senior Subordinated Notes due 2020	700			700
Discount on notes	(4		)	(5		)
Total long-term debt	$	3,046		$	3,694

________

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

(2) In September 2014, we called for the redemption of these Notes. See Note 15, “Subsequent Events.”

Credit Arrangements

We have a revolving credit facility that matures in June 2018 and provides borrowing capacity of $1.4 billion. As of September 30, 2014, the largest individual loan commitment by any lender was 14% 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, N.A. 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, plus a margin that is based on a grid of our debt rating (75 basis points per annum at September 30, 2014) or (b) the London Interbank Offered Rate, plus a margin that is based on a grid of our debt rating (175 basis points per annum at September 30, 2014).

Under our credit facility, we pay commitment fees on available but undrawn amounts based on a grid of our debt rating (30 basis points per annum at September 30, 2014). We incurred aggregate commitment fees under our current credit facility of approximately $1 million and $3 million for the three and nine months ended September 30, 2014, respectively, which are recorded in “Interest expense” on our consolidated statement of operations. For the three and nine months ended September 30, 2013, we incurred commitment fees under our current credit facility of approximately $1 million and $3 million, respectively.

Our credit facility has restrictive financial covenants that include the maintenance of a ratio of total debt to book capitalization not to exceed 0.6 to 1.0 and maintenance of a ratio of 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) to interest expense of at least 3.0 to 1.0. At September 30, 2014, we were in compliance with all of our debt covenants.

As of September 30, 2014, we had no letters of credit outstanding under our credit facility. Letters of credit are subject to a fronting fee of 20 basis points and annual fees based on a grid of our debt rating (175 basis points at September 30, 2014).

Subject to compliance with the restrictive covenants in our credit facility, at September 30, 2014, we also had a total of $195 million of available borrowing capacity under our money market lines of credit with various financial institutions, the availability of which is at the discretion of the financial institutions.

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(Unaudited)

The credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; inaccuracy of representations and warranties in any material respect; a change of control; or certain other material adverse changes in our business. Our senior notes and senior subordinated notes also contain standard events of default. If any of the foregoing defaults were to occur, our lenders under the credit facility could terminate future lending commitments, and our lenders under both the credit facility and our notes could declare the outstanding borrowings due and payable. In addition, our credit facility, senior notes, senior subordinated notes and substantially all of our derivative arrangements contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.

10. Income Taxes:

The provision (benefit) for income taxes for continuing operations 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,
	2014		2013			2014		2013
	(In millions)
Amount computed using the statutory rate	$	152	$	(3	)	$	156	$	43
Increase (decrease) in taxes resulting from:
State and local income taxes, net of federal effect	4		1			9		4
Total provision (benefit) for income taxes	$	156	$	(2	)	$	165	$	47

The effective tax rates for continuing operations for the three months ended September 30, 2014 and 2013 were 35.8% and 32.9%, respectively. The effective tax rates for continuing operations for the nine months ended September 30, 2014 and 2013 were 37.0% and 38.2%, respectively. Unrealized derivative gains and losses are treated differently for income tax purposes in the various state taxing jurisdictions to which we are subject. As a result, our effective tax rate fluctuates in periods with significant commodity price volatility.

As of September 30, 2014, we did not have a liability for uncertain tax positions, and as such, we had not accrued related interest or penalties. The tax years 2011 through 2013 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

11. Stock-Based Compensation:

Our stock-based compensation consisted of the following:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In millions)
Equity awards	$	15		$	12		$	37		$	35
Liability awards:
Stockholder Value Appreciation Program	(12		)	8			42			8
Cash-settled restricted stock units	5			5			21			6
Total liability awards	(7		)	13			63			14
Total stock-based compensation	8			25			100			49
Capitalized in oil and gas properties	2			(7		)	(38		)	(14		)
Net stock-based compensation expense	$	10		$	18		$	62		$	35

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(Unaudited)

As of September 30, 2014, we had approximately $96 million of total unrecognized stock-based compensation expense related to unvested stock-based compensation awards. The full amount is expected to be recognized within four years.

Equity Awards

Equity awards consist of service-based and performance- or market-based restricted stock units, stock options and stock purchase options under the Employee Stock Purchase Plan.

Stock-based compensation classified as equity awards to employees and non-employee directors are currently granted under the 2011 Omnibus Stock Plan (2011 Plan). The fair value of grants is determined utilizing the Black-Scholes option-pricing model for stock options and a Monte Carlo lattice-based model for our performance- and market-based restricted stock and restricted stock units. Compensation expense for equity awards is expected to be recognized on a straight-line basis over the applicable remaining vesting periods.

Restricted Stock. The following table provides information about restricted stock and restricted stock unit activity.



	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, 2013	2,999		706		3,705		$	33.31
Granted	382		339		721		25.24
Forfeited	(353	)	(46	)	(399	)	26.00
Vested	(1,088	)	(30	)	(1,118	)	36.61
Non-vested shares outstanding at September 30, 2014	1,940		969		2,909		$	30.19

Stock Options. The following table provides information about stock option activity.



	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 thousands)						(In years)	(In millions)
Outstanding at December 31, 2013	687		$	39.68			1.9	$	—
Granted	—		—		$	—
Exercised	(134	)	29.32					1
Forfeited	(236	)	40.22
Outstanding at September 30, 2014	317		$	43.64			2.3	$	—

Exercisable at September 30, 2014	317		$	43.64			2.3	$	—

________


(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, 2014, the last reported sales price of our common stock on the New York Stock Exchange was $37.07 per share.

Employee Stock Purchase Plan. During the first six months of 2014, options to purchase approximately 92,000 shares of our common stock, which were issued under our employee stock purchase plan, were exercised. The weighted-average fair value of each option was $5.96 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 0.09%, an expected life of six months and weighted-average volatility of 34%.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

On July 1, 2014, options to purchase approximately 59,000 shares of our common stock were issued under our employee stock purchase plan. The weighted-average fair value of each option was $10.28 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 0.06%, an expected life of six months and weighted-average volatility of 30%.

Liability Awards

Liability awards consist of performance awards that are settled in cash instead of shares as discussed below.

Stockholder Value Appreciation Program. In September 2013, the Compensation and Management Development Committee of the Board approved the Stockholder Value Appreciation Program (SVAP) to be administered under the 2011 Plan. The SVAP pays substantially all full-time domestic, nonexecutive employees a cash payment based on a percentage of salary upon each incremental $5 increase in our 30-calendar day average share price. Each price threshold can be reached only once during the term of the program. The SVAP's performance period lasts through December 31, 2015.

The first price threshold that triggered a payment under the SVAP was $27.50 during the fourth quarter of 2013. The second and third price thresholds for the SVAP were $32.50 and $37.50, respectively, which were reached during the second quarter of 2014. The fourth price threshold for the SVAP of $42.50 was reached in July 2014.

Based on the valuation of the SVAP as of September 30, 2014, the fair value of the awards was $12 million, of which $7 million has been accrued. The total expected cost was determined using a Monte Carlo simulation assuming no dividends, a risk-free weighted-average interest rate of 0.28%, a plan term of 1.25 years and an average of implied and historical stock price volatility of 34%. An additional $5 million is expected to be recognized over the remaining service period of the plan. Future changes in our stock price could cause the total cost of the plan to be significantly different than our estimates as of September 30, 2014.

Cash-Settled Restricted Stock Units. We also have granted cash-settled restricted stock units to employees that vest over three years. The value of the awards, and the associated stock-based compensation expense, is based on the Company’s stock price at the end of each period. During the nine months ended September 30, 2014, approximately 585,000 cash-settled restricted stock units vested and settled for approximately $19 million. During the nine months ended September 30, 2013, approximately 83,000 cash-settled restricted stock units vested and settled for approximately $2 million, all of which occurred during the first quarter of 2013. During the quarter ended September 30, 2014, we granted approximately 600,000 cash-settled restricted stock units to employees. As of September 30, 2014, we had approximately 1.2 million cash-settled restricted stock units outstanding and related unrecognized stock-based compensation expense of approximately $31 million.

12. Commitments and Contingencies:

We have been named as a defendant in a number of other lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (a) claims from royalty owners for disputed royalty payments, (b) commercial disputes, (c) personal injury claims and (d) 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.

Table of Contents

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

13. Supplemental Cash Flow Information:



	Nine Months Ended
	September 30,
	2014			2013
	(In millions)
Non-cash items excluded from the statement of cash flows:
(Increase) decrease in receivables for property sales	$	(17	)	$	(4	)
(Increase) decrease in receivables from sale of Malaysia business	(15		)	—
(Increase) decrease in accrued capital expenditures	2			(55		)
(Increase) decrease in asset retirement costs	18			(8		)
Increase (decrease) in deferred liabilities	(90		)	—

14. Related-Party Transactions:

Kevin M. Robinson, our former Vice President — Asia through February 10, 2014, and Susan G. Riggs, our current Treasurer, were minority owners of Huffco International L.L.C. (Huffco). In May 1997, before Mr. Robinson and Ms. Riggs joined the Company, we acquired from Huffco an entity now known as Newfield China, LDC, the owner of a 12% interest in a three-field unit located in Bohai Bay, offshore China. Huffco retained preferred shares of Newfield China that provided for dividend payments. During the third quarter of 2013, we purchased the outstanding preferred shares of Newfield China from Huffco for approximately $20 million, which was recorded as a charge against retained earnings.

15. Subsequent Events:

In October 2014, we completed the redemption of our $600 million aggregate principal of 7⅛% Senior Subordinated Notes due 2018. The transaction included a premium payment of approximately $14 million.

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

Overview

We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. Our principal areas of operation include the Mid-Continent, the Rocky Mountains and the onshore Gulf Coast regions of North America.

To maintain and grow our production and cash flows, we must continue to develop existing proved reserves and locate or acquire new oil and natural gas reserves to replace those reserves being produced. Our revenues, profitability and future growth depend substantially on prevailing prices for oil, natural gas and NGLs and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. Prices for oil, natural gas and NGLs fluctuate widely and affect:


•	the amount of cash flows available for capital expenditures;


•	our ability to borrow and raise additional capital; and


•	the quantity of oil, natural gas and NGLs that we can economically produce.

Discontinued Operations

During the second quarter of 2013, our international businesses met the criteria to be classified as held for sale and reported as discontinued operations. As such, the results of operations for our international businesses are reflected as discontinued operations and discussed further in Note 3, “Discontinued Operations,” to our consolidated financial statements appearing earlier in this report.

Malaysia. In February 2014, Newfield International Holdings Inc., a wholly-owned subsidiary of the Company, closed the sale of its Malaysia business to SapuraKencana Petroleum Berhad, a Malaysian public company, for approximately $898 million (subject to customary purchase price adjustments). See Note 3, “Discontinued Operations,” to our consolidated financial statements appearing earlier in this report for additional information regarding the sale of our Malaysia business.

China. In August 2013, during the installation of the LF-7 topside facilities by a third-party contractor, a hydraulic jacking system malfunctioned, and the installation was suspended. In August 2014, the LF-7 topside facilities were installed, and we began drilling our first well. We expect to achieve first oil production in the fourth quarter of 2014 and continue to work with potential purchasers of our China business.

Results of Continuing Operations

Our continuing operations consist of exploration, development and production activities in the United States.

Revenues. Our revenues are primarily from the sale of oil, natural gas and NGLs and may vary significantly from period to period as a result of changes in commodity prices or volume of production sold.

Revenues from continuing operations of $610 million for the third quarter of 2014 were 26% higher than the comparable period of 2013. Oil revenue generated 52% of the favorable revenue variance, primarily due to increased production, partially offset by lower prices. Oil production increased in our Mid-Continent, onshore Gulf Coast and Rocky Mountains regions by 50%, 35% and 23%, respectively. Approximately 21% of the revenue increase was attributable to increases in NGL production in our onshore Gulf Coast, Mid-Continent and Rocky Mountains regions of 66%, 63% and 47%, respectively. The combination of a 6% increase in natural gas production and a 19% increase in realized natural gas prices during the period generated 21% of the total favorable revenue variance.

Revenues of $1.8 billion for the first nine months of 2014 were 37% higher than the comparable period of 2013. Approximately 62% of the increase was attributable to increases in oil production in our onshore Gulf Coast, Mid-Continent and Rocky Mountains regions of 50%, 39% and 29%, respectively. Increased NGL production in the onshore Gulf Coast, Mid-Continent and Rocky Mountains regions of 66%, 65% and 40%, respectively, during the nine months ended September 30, 2014 generated approximately 14% of the total revenue variance. The combination of a 3% increase in natural gas production and a 26% increase in realized natural gas prices during the period generated 18% of the total favorable revenue variance. The following table reflects our production from continuing operations and average realized commodity prices.



	Three Months Ended September 30,				Percentage Increase (Decrease)		Nine Months Ended September 30,				Percentage Increase (Decrease)
	2014		2013		Percentage Increase (Decrease)		2014		2013		Percentage Increase (Decrease)
Production:⁽¹⁾
Crude oil and condensate (MBbls)	4,797		3,698		30	%	13,453		10,062		34	%
Natural gas (Bcf)	31.7		29.8		6	%	90.2		87.9		3	%
NGLs (MBbls)	2,242		1,390		61	%	5,945		3,675		62	%
Total (MBOE)	12,325		10,053		23	%	34,430		28,382		21	%
Average Realized Prices:⁽²⁾
Crude oil and condensate (per Bbl)	$	85.07	$	93.02	(9	)%	$	87.22	$	87.17	—	%
Natural gas (per Mcf)	3.85		3.23		19	%	4.26		3.37		26	%
NGLs (per Bbl)	34.16		30.90		11	%	34.24		29.64		16	%
Crude oil equivalent (per BOE)	49.49		48.05		3	%	51.43		45.18		14	%

________________


(1)	Excludes natural gas produced and consumed in operations of 2.0 Bcf and 1.9 Bcf during the three months ended September 30, 2014 and 2013, respectively, and 6.4 Bcf and 6.6 Bcf during the nine months ended September 30, 2014 and 2013, respectively.


(2)	Had we included the realized effects of derivative contracts, the average realized prices would have been as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Crude oil and condensate (per Bbl)	$	81.41	$	89.72	$	82.03	$	86.28
Natural gas (per Mcf)	3.79		3.88		3.86		3.96

Production. Our third quarter 2014 total production from continuing operations increased 2,272 MBOE, or 23%, compared to third quarter of 2013 primarily due to increased liquids production from the success of our liquids-focused drilling programs in all three of our operating regions. Natural gas production increased 6% due to associated gas production generated by our liquids-focused drilling programs.

For the nine months ended September 30, 2014, total production from continuing operations increased 21% compared to the same period of 2013, driven by a combined 41% increase in liquids production in all three of our operating regions.

Operating Expenses. The following tables present information about our operating expenses for our continuing operations.

Three months ended September 30, 2014 and 2013



	Unit-of-Production						Total Amount
	Three Months Ended September 30,				Percentage Increase (Decrease)		Three Months Ended September 30,				Percentage Increase (Decrease)
	2014		2013		Percentage Increase (Decrease)		2014		2013		Percentage Increase (Decrease)
	(Per BOE)						(In millions)
Lease operating	$	10.21	$	10.27	(1	)%	$	126	$	104	22	%
Production and other taxes	2.47		1.82		36	%	31		19		67	%
Depreciation, depletion and amortization	18.50		17.10		8	%	228		171		33	%
General and administrative	3.97		6.08		(35	)%	48		61		(20	)%
Other	0.62		—		100	%	8		—		100	%
Total operating expenses	$	35.77	$	35.27	1	%	$	441	$	355	24	%

Our operating expenses for continuing operations for the three months ended September 30, 2014 were relatively flat over the same period of 2013 stated on a per BOE basis. The primary offsetting components within our operating expenses are as follows:


•	Production and other taxes increased $12 million or 67% in comparison to the third quarter of 2013. Higher product revenues resulted in an increase of approximately $8 million. Additionally, production tax credits of approximately $4 million were received during the third quarter of 2013, primarily in our Mid-Continent region.


•	Total depreciation, depletion and amortization (DD&A) increased 33% primarily due to a 23% increase in production during the third quarter of 2014 compared to the third quarter of 2013, combined with an 8% increase in the cost per unit-of-production.

•

General and administrative (G&A) expenses per BOE decreased 35% during the third quarter of 2014 compared to the third quarter of 2013. Approximately one half of this per BOE decrease relates to increased production volumes. The remaining decrease is primarily related to higher third quarter 2013 employee-related expenses associated with our stock-based liability award programs. Our stock-based employee-related expenses decreased $17 million period over period but were partially offset by amounts capitalized or recorded as lease operating expense (LOE). For the three months ended September 30, 2014, we capitalized $23 million ($1.89 per BOE) of direct internal costs as compared to $27 million ($2.68 per BOE) during the comparable quarter of 2013. This decrease in capitalization is primarily related to reduced costs associated with the stock-based liability awards and increased production.


•	Other operating expense increased $8 million due to other costs related to our operations, such as legal settlements and losses on materials and supplies inventory during the period.

Nine months ended September 30, 2014 and 2013



	Unit-of-Production						Total Amount
	Nine Months Ended September 30,				Percentage Increase (Decrease)		Nine Months Ended September 30,				Percentage Increase (Decrease)
	2014		2013		Percentage Increase (Decrease)		2014		2013		Percentage Increase (Decrease)
	(Per BOE)						(In millions)
Lease operating	$	10.34	$	10.56	(2	)%	$	356	$	299	19	%
Production and other taxes	2.47		1.82		36	%	85		52		65	%
Depreciation, depletion and amortization	18.23		17.00		7	%	628		482		30	%
General and administrative	5.01		5.63		(11	)%	172		160		8	%
Other	0.22		—		100	%	8		—		100	%
Total operating expenses	$	36.27	$	35.01	4	%	$	1,249	$	993	26	%

Our total operating expenses for continuing operations for the nine months ended September 30, 2014 increased 4% as compared to the same period of 2013 stated on a per BOE basis. The primary reasons for the increase follow:

•

As a percent of revenue, production and other taxes was 4.8% and 4.0% for the nine-month periods ended September 30, 2014 and 2013, respectively. The increase is primarily due to non-recurring production tax credits in our Rocky Mountains and Mid-Continent regions recorded during the first nine months of 2013. On a per BOE basis, the increase of 36% was driven by an increase in liquids production as a percent of total production and the associated increase in average revenue per BOE produced from $45.18 for the nine months ended September 30, 2013, to $51.43 for the same period in 2014.


•	Total depreciation, depletion and amortization increased 30% primarily due to a 21% increase in production during the first nine months of 2014 compared to the comparable period of 2013, combined with a 7% increase in the cost per unit-of-production.

•

General and administrative expense per BOE decreased 11% during the first nine months of 2014 compared to the comparable period in 2013, primarily due to increased production. G&A expenses increased $12 million primarily due to increased employee-related expenses associated with our stock-based liability award programs as a result of the 51% increase in our stock price during the first nine months of 2014. Our stock-based expenses increased $51 million period over period but were partially offset by amounts capitalized or recorded as LOE. Also offsetting the increased stock-based awards is a decrease of approximately $9 million in labor costs relating primarily to the centralization of certain functions during 2013. For the nine months ended September 30, 2014, we capitalized $109 million ($3.17 per BOE) of direct internal costs as compared to $80 million ($2.83 per BOE) during the comparable period of 2013. This increase is primarily related to capitalization of a portion of the costs associated with the stock-based liability awards.


•	Other operating expense increased $8 million due to other costs related to our operations, such as legal settlements and losses on materials and supplies inventory during the period.

Interest Expense. The following table presents information about interest expense. Interest expense associated with unproved oil and gas properties is capitalized into oil and gas properties.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In millions)
Gross interest expense:
Credit arrangements	$	2		$	3		$	7		$	7
Senior notes	26			26			76			76
Senior subordinated notes	23			23			70			70
Total gross interest expense	51			52			153			153
Capitalized interest	(13		)	(13		)	(39		)	(40		)
Net interest expense	$	38		$	39		$	114		$	113

Commodity Derivative Income (Expense). The fluctuations in commodity derivative income (expense) from period to period are due to the volatility of oil and natural gas prices and changes in our outstanding derivative instruments during these periods.

Taxes. The effective tax rates for the three months ended September 30, 2014 and 2013 were 35.8% and 32.9%, respectively. The effective tax rates for the nine months ended September 30, 2014 and 2013 were 37.0% and 38.2%, respectively. Unrealized derivative gains and losses are treated differently in the various state taxing jurisdictions to which we are subject. As a result, our effective tax rate fluctuates in periods with significant commodity price volatility.

Results of Discontinued Operations - Malaysia and China

Revenues and Liftings. Our international revenues are primarily from the sale of crude oil. Substantially all of the crude oil from our offshore operations 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 FPSOs or onshore storage terminals. As a result, the timing of liftings may impact period-to-period results. In February 2014, we closed the sale of our Malaysia business. See Note 3, “Discontinued Operations,” to our consolidated financial statements appearing earlier in this report for additional information regarding the sale.

Revenues during the third quarter and nine-month period ended September 30, 2014 were significantly lower due to the sale of our Malaysia business in February 2014. Additionally, China production declined in the third quarter of 2014 compared to the same period of 2013 due to the temporary shut-in of production in Bohai Bay by the operator during the third quarter for scheduled repairs and maintenance activities. Production resumed during the third quarter of 2014; however, sufficient volumes had not accumulated for a lifting as of September 30, 2014. We expect that liftings from Bohai Bay will resume in the fourth quarter of 2014. The following table reflects our production from discontinued operations and average realized commodity prices.



	Three Months Ended September 30,				Percentage Increase (Decrease)		Nine Months Ended September 30,				Percentage Increase (Decrease)
	2014		2013		Percentage Increase (Decrease)		2014		2013		Percentage Increase (Decrease)
Production/Liftings:⁽¹⁾
Crude oil and condensate (MBbls)	—		1,655		(100	)%	1,024		6,009		(83	)%
Natural gas (Bcf)	—		0.1		(100	)%	—		0.3		(100	)%
Total (MBOE)	—		1,669		(100	)%	1,024		6,062		(83	)%

Average Realized Prices:
Crude oil and condensate (per Bbl)	$	—	$	114.12	(100	)%	$	109.36	$	109.41	—	%
Natural gas (per Mcf)	—		3.58		(100	)%	—		3.71		(100	)%
Crude oil equivalent (per BOE)	—		113.30		(100	)%	109.36		108.64		1	%

________________

(1) Represents our net share of volumes sold regardless of when produced.

Operating Expenses. The following tables present information about our operating expenses for our discontinued operations.

Three months ended September 30, 2014 and 2013



	Unit-of-Production						Total Amount
	Three Months Ended September 30,				Percentage Increase (Decrease)		Three Months Ended September 30,				Percentage Increase (Decrease)
	2014		2013		Percentage Increase (Decrease)		2014		2013		Percentage Increase (Decrease)
	(Per BOE)						(In millions)
Lease operating	$	—	$	15.27	(100	)%	$	1	$	26	(96	)%
Production and other taxes	—		27.60		(100	)%	1		46		(98	)%
Depreciation, depletion and amortization	—		31.38		(100	)%	—		52		(100	)%
General and administrative	—		2.49		(100	)%	—		4		(100	)%
Total operating expenses	$	—	$	76.74	(100	)%	$	2	$	128	(98	)%

Nine months ended September 30, 2014 and 2013



	Unit-of-Production						Total Amount
	Nine Months Ended September 30,				Percentage Increase (Decrease)		Nine Months Ended September 30,				Percentage Increase (Decrease)
	2014		2013		Percentage Increase (Decrease)		2014		2013		Percentage Increase (Decrease)
	(Per BOE)						(In millions)
Lease operating	$	15.75	$	15.63	1	%	$	16	$	95	(83	)%
Production and other taxes	29.46		35.31		(17	)%	30		214		(86	)%
Depreciation, depletion and amortization	36.27		30.02		21	%	37		182		(80	)%
General and administrative	—		1.66		(100	)%	—		10		(100	)%
Total operating expenses	$	81.48	$	82.62	(1	)%	$	83	$	501	(83	)%

Our total operating expenses for discontinued operations for the three and nine months ended September 30, 2014 decreased $126 million and $418 million, respectively, compared to the same periods of 2013. These expenses declined primarily as a result of the sale of our Malaysia business in February 2014, combined with the temporary shut-in of Bohai Bay production in China for scheduled repairs and maintenance activities during the third quarter of 2014 by the operator.

Liquidity and Capital Resources

The following discussion is inclusive of both our continuing and discontinued operations, unless otherwise noted.

We must find new and develop existing reserves to maintain and grow our production and cash flows. We accomplish this through drilling programs and property acquisitions, which require substantial capital expenditures. Lower prices for oil, natural gas and NGLs 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 and review it during the course of the year. Our capital budgets (excluding acquisitions) are created based upon our estimate of internally generated sources of cash, as well as the available borrowing capacity of our revolving credit facility. Our 2014 budget is being financed through our cash flows from operations, proceeds from our first quarter 2014 Malaysia sale and the use of our credit facility. A significant portion of our remaining expected 2014 domestic oil and gas production (excluding NGLs) is protected from price volatility through the use of derivative contracts. Our 2014 capital budget for our continuing operations, excluding estimated capitalized interest and overhead of approximately $211 million, is expected to be approximately $1.75 billion and focuses on liquids-rich projects with higher returns. During 2014, we intend to invest approximately $149 million in China, a portion of which we expect to recover through insurance related to the August 2013 LF-7 topside installation incident. We anticipate that our 2014 capital investment levels will exceed our estimate of cash flows from operations. As a result, we used proceeds from our recent Malaysia sale to fund our capital expenditures during the first half of the year and our credit arrangements to fund the expected remaining shortfall.

Actual capital expenditure levels may vary significantly due to many factors, including drilling results; oil, natural gas and NGL prices; industry conditions; the prices and availability of goods and services; and the extent to which properties are acquired or non-strategic assets sold. We continue to screen for attractive acquisition opportunities; however, the timing and size of acquisitions are unpredictable. We believe we have the operational flexibility to react quickly with our capital expenditures to changes in circumstances and our cash flows from operations.

We continuously monitor our liquidity needs, coordinate our capital expenditure program with our expected cash flows and projected debt-repayment schedule, and evaluate our available funding alternatives in light of current and expected economic conditions. We believe that our liquidity position and ability to generate cash flows from our asset portfolio will be adequate to fund 2014 operations and continue to meet our other obligations.

On September 19, 2014, we closed on the sale of our Granite Wash assets for approximately $588 million, subject to customary purchase price adjustments. See Note 4, “Oil and Gas Assets,” to our consolidated financial statements appearing earlier in this report for additional information regarding the sale.

Credit Arrangements and Other Financing Activities. We maintain a revolving credit facility of $1.4 billion that matures in June 2018, as well as money market lines of credit of $195 million. In September 2014, we called for the redemption of our $600 million aggregate principal of 7⅛% Senior Subordinated Notes due 2018. In October 2014, we completed the redemption of these Notes. The transaction included a premium payment of approximately $14 million. We have no scheduled maturities of senior notes or senior subordinated notes until 2020. For a more detailed description of the terms of our credit arrangements and senior and senior subordinated notes, please see Note 9, “Debt,” to our consolidated financial statements appearing earlier in this report.

As of October 28, 2014, we had outstanding borrowings of $295 million and available borrowing capacity of approximately $1.1 billion under our revolving credit facility. We did not have any outstanding borrowings under our money market lines of credit.

Working Capital. Our working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under our credit arrangements, changes in the fair value of our outstanding commodity derivative instruments as well as the timing of receiving reimbursement of amounts paid by us for the benefit of joint venture partners. Without the effects of commodity derivative instruments, we typically have a working capital deficit or a relatively small amount of positive working capital.

At September 30, 2014, we had negative working capital of $19 million compared to negative working capital of $389 million at December 31, 2013. The changes in our working capital are primarily a result of proceeds received from the Granite Wash asset sale in September 2014 and the sale of our Malaysia business in February 2014. The remaining change is due to the timing of the collection of receivables; changes in the fair value of our derivative positions; the timing of crude oil liftings in our discontinued operations; 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. Our primary source of capital and liquidity is cash flows from operations, which are primarily affected by the sale of our oil, natural gas and NGLs, as well as commodity prices, net of the effects of derivative contract settlements and changes in working capital.

Our net cash flows from operations were $1.1 billion (includes $55 million of cash flows from discontinued operations) for the nine months ended September 30, 2014, which is consistent with net cash flows from operations of $1.1 billion (includes $331 million of cash flows from discontinued operations) for the same period in 2013.

Cash Flows from Investing Activities. Net cash used in investing activities for the nine months ended September 30, 2014 was $114 million compared to $1.5 billion for the same period in 2013. The decrease in 2014 is due to proceeds received from the sale of our Malaysia business and Granite Wash assets, and redemption of investments, partially offset by increased capital expenditures in 2014 compared to 2013.

Cash Flows from Financing Activities. Net cash used in financing activities for the nine months ended September 30, 2014 was $655 million compared to net cash provided by financing activities of $410 million for the same period in 2013. During the nine months ended September 30, 2014, we reduced our outstanding borrowings under our revolving credit facility by $649 million using the proceeds received from the sale of our Malaysia business and Granite Wash assets.

Capital Expenditures. Our capital investments for continuing operations for the first nine months of 2014 increased 12% as compared to the same period of 2013, whereas capital investments for discontinued operations decreased 58% for the comparable

periods, primarily due to the sale of our Malaysia business in February 2014. These amounts exclude non-cash asset retirement obligations and capitalized interest and direct internal costs.



	Nine Months Ended September 30,
	2014		2013
	(In millions)
Continuing operations:
Exploitation and development	$	991	$	940
Exploration (exclusive of exploitation and leasehold)	236		141
Acquisitions	21		64
Leasing proved and unproved property (leasehold)	75		25
Pipeline spending	7		15
Plug and abandonment settlements	5		8
Total continuing operations	1,335		1,193
Discontinued operations	109		260
Total	$	1,444	$	1,453

Commitments under Joint Operating Agreements. Most of our properties are operated through joint ventures under joint operating or similar agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator if a non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses.

Contractual Obligations

We have various contractual obligations in the normal course of our operations. For further information, please see “Management's Discussion and Analysis of Financial Condition and Results of Operations - Contractual Obligations” in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014. There have been no material changes to these disclosures during the second or third quarters of 2014.

Oil and Gas Derivatives

We use derivative contracts to manage the variability in cash flows caused by commodity price fluctuations associated with our anticipated future oil and gas production for the next 24 to 36 months. As of September 30, 2014, we had no outstanding derivative contracts related to our NGL production or production associated with our discontinued operations. In addition, we may use basis contracts to manage volatilities in the differential between the NYMEX Henry Hub posted prices and those of our physical pricing points. We do not use derivative instruments for trading purposes.

See the discussion and tables in Note 5, “Derivative Financial Instruments,” and Note 8, “Fair Value Measurements,” to our consolidated financial statements appearing earlier in this report for additional information regarding the accounting applicable to our oil and gas derivative contracts, a listing of open positions and the estimated fair market value of those positions as of September 30, 2014.

Between October 1, 2014 and October 28, 2014, we entered into additional crude oil derivative contracts. A listing of all of our crude oil derivative contracts as of October 28, 2014 are as follows:

Crude Oil



		NYMEX Contract Price Per Bbl
						Collars
Period and Type of Instrument ⁽¹⁾	Volume in MBbls	Swaps (Weighted Average)		Sold Puts (Weighted Average)		Floors (Weighted Average)		Ceilings (Weighted Average)
2014:
Fixed-price swaps	2,116	$	89.94	$	—	$	—	$	—
Fixed-price swaps with sold puts:	1,472
Fixed-price swaps		95.16		—		—		—
Sold puts		—		75.00		—		—
Collars with sold puts:	552
Collars		—		—		90.83		102.93
Sold puts		—		75.83		—		—
2015:
Fixed-price swaps	2,275	90.20
Fixed-price swaps with sold puts:	15,019
Fixed-price swaps		90.02		—		—		—
Sold puts		—		71.67		—		—
Collars with sold puts:	730
Collars		—		—		90.00		104.00
Sold puts		—		75.00		—		—
2016:
Fixed-price swaps with sold puts:	10,060
Fixed-price swaps		89.98		—		—		—
Sold puts		—		74.14		—		—
Collars with sold puts:	6,220
Collars		—		—		90.00		96.15
Sold puts		—		75.00		—		—
Swaptions ⁽²⁾	—	91.00		—		—		—
2017:
Fixed-price swaps with sold puts:	4,468
Fixed-price swaps		88.37		—		—		—
Sold puts		—		73.28		—		—
Collars with sold puts:	2,080
Collars		—		—		90.00		95.59
Sold puts		—		75.00		—		—

________

(1)

Periodically, we sell put options against previously entered into fixed-price swaps or collars in order to enhance the price of new positions. As such, put option contracts may be entered into at different times and with different counterparties as compared to our open fixed-price swap or collar contracts. However, we do not sell put options for volumes in excess of our open fixed-price swap or collar contracts.


(2)	During the third quarter of 2014, we sold crude oil swaption contracts, that if exercised on their expiration date in the first quarter of 2015, would hedge 732 MBbls of calendar-year 2016 production. These contracts give the counterparties the option to enter into swap contracts with us at $91.00/Bbl for calendar-year 2016.

Accounting for Derivative Activities. We do not designate future price-risk management activities as accounting hedges. Because derivative contracts 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 non-cash volatility in our reported earnings during periods of commodity price volatility. As of September 30, 2014, we had net derivative assets of $103 million, of which 61%, based on total contracted volumes, was measured based upon our valuation model (i.e. Black-Scholes) and, as such, were classified as a Level 3 fair value measurement. We value these contracts using a model that considers various inputs including the following:

•quoted forward prices for commodities;

•time value;

•volatility factors;

•counterparty credit risk; and

•current market and contractual prices for the underlying instruments.

As a result, the value of these contracts at their respective settlement dates could be significantly different than their fair value as of September 30, 2014. We use credit default swap values to assess the impact of non-performance risk when evaluating both our liabilities to and receivables from counterparties. See “— Critical Accounting Policies and Estimates — Commodity Derivative Activities” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2013 and Note 5, “Derivative Financial Instruments,” and Note 8, “Fair Value Measurements,” to our consolidated financial statements appearing earlier in this report for additional discussion of the accounting applicable to our oil and gas derivative contracts.

New Accounting Requirements

Forward-Looking Information

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). All statements, other than statements of historical facts included in this report, are forward-looking, including information relating 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. Forward-looking statements are typically identified by use of terms such as “may,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” “project,” “target,” “goal,” “plan,” “should,” “will,” “predict,” “potential” and similar expressions that convey the uncertainty of future events or outcomes. 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, natural gas and NGL prices;


•	operating hazards inherent in the exploration for and production of oil and natural gas;


•	general economic, financial, industry or business trends or conditions;


•	the impact of, and changes in, legislation, law and governmental regulations, including those related to hydraulic fracturing and climate change;


•	land, legal and ownership complexities inherent in the U.S. oil and gas industry;


•	the impact of regulatory approvals;


•	the availability and volatility 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, derivative 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 prices and quantities of commodities reflected in our commodity derivative arrangements as compared to the actual prices or quantities of commodities we produce or use;


•	the volatility and liquidity in the commodity futures and commodity and financial derivatives markets;


•	the availability of storage, transportation and refining capacity for the crude oil we produce in the Uinta Basin;


•	drilling risks and results;


•	the prices of goods and services;


•	the availability of drilling rigs and other support services;


•	global events that may impact our domestic and international operating contracts, markets and prices;


•	labor conditions;


•	weather conditions;


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


•	competitive conditions;


•	terrorism or civil or political unrest in a region or country;


•	our ability to monetize non-strategic assets, pay debt and the impact of changes in our investment ratings;


•	electronic, cyber or physical security breaches;


•	changes in tax rates;


•	inflation rates;


•	financial counterparty risk;


•	uncertainties and changes in estimates of reserves;


•	the effect of worldwide energy conservation measures;


•	the price and availability of, and demand for, competing energy sources;


•	the availability (or lack thereof) of acquisition, disposition or combination opportunities; and


•	the additional factors discussed elsewhere in our public filings and press releases, including the factors discussed in “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” included in our 2013 Annual Report on Form 10-K.

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. 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 and in this report.

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

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 derivative transaction.

Bcf. Billion cubic feet.

BOE. One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate or 42 gallons for NGLs.

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.

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. Exploitation wells typically 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 new 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.

Liquids. Crude oil and NGLs.

Liquids-rich. Formations that contain crude oil or NGLs instead of, or as well as, natural gas.

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

MBOE. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet of natural gas.

MMBtu. One million Btus.

MMMBtu. One billion Btus.

NGL. Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasolines.

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. Those quantities of oil and natural 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.

SEC pricing. The unweighted average first-day-of-the-month commodity price for crude oil (WTI) or natural gas (NYMEX) for the prior 12 months, adjusted for market differentials. The SEC provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule).

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 and requires the owner to pay a share of the costs of drilling and production operations.

WTI. West Texas Intermediate, a grade of crude oil.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from changes in oil, natural gas and NGL prices, interest rates and foreign currency exchange rates as discussed below.

Oil, Natural Gas and NGL Prices

Our decision on the quantity and price at which we choose to enter into derivative contracts is based in part on our view of current and future market conditions. While the use of derivative contracts limits the downside risk of adverse price movements, their use also may limit future benefits from favorable price movements. In addition, the use of derivative contracts may involve basis risk. All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative contracts 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. At September 30, 2014, 10 of our 16 counterparties accounted for approximately 85% of our contracted volumes with no single counterparty accounting for more than 15%. For a further discussion of our derivative activities, see the information under the caption “Oil and Gas Derivatives” in Item 2 appearing earlier in this report and the discussion and tables in Note 5, “Derivative Financial Instruments,” to our consolidated financial statements appearing earlier in this report. For further discussion of the types of derivative positions, refer to Note 5, “Derivative Financial Instruments” within Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2013.

Interest Rates

We consider our interest rate exposure to be minimal because 100% of our obligations were at fixed rates as of September 30, 2014. A 10% increase in LIBOR would not impact our interest cost on debt outstanding as of September 30, 2014, but would affect the fair value of our outstanding debt, as well as interest costs associated with future debt issuances or borrowings under our revolving credit facility.

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 flows, to be immaterial. We did not have any open derivative contracts related to foreign currencies at September 30, 2014.

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 our 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 our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2014.

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 our Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the third quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based upon 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

Between February and December 2013, we voluntarily self-disclosed to the U.S. Environmental Protection Agency (EPA) certain potential federal air quality violations at our facilities located on state lands and on the Uintah & Ouray Indian Reservation in the Uinta Basin of northeast Utah. The self-disclosures were made after a voluntary internal environmental audit under the EPA's Self-Disclosure and Audit Policy. The potential violations related primarily to certain stationary internal combustion engines that are subject to certain air quality performance standards under 40 C.F.R. Part 60, Subpart JJJJ. The engines were installed as a result of our efforts to replace older, higher-emitting engines with new, lower-emitting engines. Subpart JJJJ requires us to conduct certain emission performance tests within a defined time period. We did not conduct all of the requisite tests on the new engines in a timely fashion and have now negotiated a settlement and resolution with the EPA by entering in to a Combined Complaint and Consent Agreement and Compliance Order on Consent. Those settlement documents require us to pay a monetary penalty of $246,000 and conduct testing for numerous engines. We anticipate the settlement documentation being finalized and the penalty being paid within the next 60 days. We also expect that we will be required to conduct the requisite performance testing over approximately the next 12 months. The violations did not contain any allegations of environmental spills, releases or pollution above permitted levels. We do not expect this resolution to have a material adverse effect on our financial position, cash flows or results of operations.

In early 2012, through a voluntary environmental audit, we discovered potential violations of section 404 of the Clean Water Act relating to possible unpermitted discharges of fill materials into certain wetlands and drainages in the Uinta Basin. The potential violations were discovered on certain Newfield locations and several locations acquired in 2011. In June 2012, we self-disclosed these potential violations to the U.S. Army Corps of Engineers (Corps), in accordance with the EPA’s Audit Policy and an interagency memorandum of understanding with the Corps. The Corps initially indicated to us that it would not pursue penalty charges, but instead would work with us to restore the unpermitted discharges and acquire the appropriate after-the-fact permits. The EPA later inquired with the Corps, and was informed about the potential violations. Thereafter, the EPA initiated an administrative enforcement action against Newfield. The EPA has evaluated the discharges and our proposed restoration and mitigation, and a negotiated settlement has been reached in principle. Newfield anticipates entering into a final administrative settlement in the near future involving restoration of much of the unpermitted discharges, off-site mitigation and the payment of a civil administrative penalty expected to be $175,000. We do not expect this administrative settlement to have a material adverse effect on our financial position, cash flows or results of operations.

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 (a) claims from royalty owners for disputed royalty payments, (b) commercial disputes, (c) personal injury claims and (d) 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. In addition, from time to time we receive notices of violation from governmental and regulatory authorities in areas in which we operate related to alleged violations of environmental statutes or rules and regulations promulgated thereunder. We cannot predict with certainty whether these notices of violation will result in fines or penalties, or if such fines or penalties are imposed, that they would exceed individually or in the aggregate $100,000. If any fines or penalties are in fact imposed that are greater than $100,000, then we will disclose such fact in our subsequent filings.

Item 1A. Risk Factors

There have been no material changes with respect to the risk factors previously reported in our Annual Report on Form 10-K for the year ended December 31, 2013 and updated in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014.

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, 2014.



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, 2014	9,621	$	36.32	—	—
August 1 — August 31, 2014	24,852	39.45		—	—
September 1 — September 30, 2014	212,598	41.00		—	—
Total	247,071	$	40.66	—	—

_______


(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.

Item 6. Exhibits



Exhibit Number		Description
3.1		Third Restated Certificate of Incorporation of Newfield Exploration Company dated December 14, 2011 (incorporated by reference to Exhibit 3.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2011 (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 July 25, 2013 (File No. 1-12534))

10.1		Retirement Agreement of Terry W. Rathert (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on August 29, 2014 (File No. 1-12534))

*31.1		Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*31.2		Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*32.1		Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*32.2		Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.LAB		XBRL Label Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

*101.DEF		XBRL Definition Linkbase Document

_______

* Filed or furnished herewith.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	NEWFIELD EXPLORATION COMPANY

Date: October 29, 2014	By:	/s/ LAWRENCE S. MASSARO
		Lawrence S. Massaro
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Exhibit Index



Exhibit Number		Description
3.1		Third Restated Certificate of Incorporation of Newfield Exploration Company dated December 14, 2011 (incorporated by reference to Exhibit 3.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2011 (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 July 25, 2013 (File No. 1-12534))

10.1		Retirement Agreement of Terry W. Rathert (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on August 29, 2014 (File No. 1-12534))

*31.1		Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*31.2		Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*32.1		Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*32.2		Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.LAB		XBRL Label Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

*101.DEF		XBRL Definition Linkbase Document

_______

* Filed or furnished herewith.