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 2015 Q2 - 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 June 30, 2015



¨		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 July 31, 2015, there were 162,988,578 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

TABLE OF CONTENTS



		Page
PART I

Item 1.	Unaudited Financial Statements:

	Consolidated Balance Sheet as of June 30, 2015 and December 31, 2014	1

	Consolidated Statement of Operations for the three and six months ended June 30, 2015 and 2014	2

	Consolidated Statement of Comprehensive Income for the three and six months ended June 30, 2015 and 2014	3

	Consolidated Statement of Cash Flows for the six months ended June 30, 2015 and 2014	4

	Consolidated Statement of Stockholders' Equity for the six months ended June 30, 2015	5

	Notes to Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38

Item 4.	Controls and Procedures	39


PART II

Item 1.	Legal Proceedings	39

Item 1A.	Risk Factors	39

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40

Item 6.	Exhibits	41

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEET

(In millions, except share data)

(Unaudited)



	June 30, 2015			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	42		$	14
Accounts receivable, net	447			439
Inventories	25			33
Derivative assets	353			431
Other current assets	18			23
Total current assets	885			940
Oil and gas properties — full cost method ($721 and $677 were excluded from amortization at June 30, 2015 and December 31, 2014, respectively)	14,753			16,384
Less — accumulated depreciation, depletion and amortization	(8,619		)	(8,152		)
Total oil and gas properties, net	6,134			8,232
Other property and equipment, net	175			182
Derivative assets	168			190
Long-term investments	21			26
Deferred taxes	30			—
Other assets	45			28
Total assets	$	7,458		$	9,598
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	92		$	32
Accrued liabilities	588			880
Advances from joint owners	42			34
Asset retirement obligations	1			3
Derivative liabilities	5			8
Deferred taxes	117			144
Total current liabilities	845			1,101
Other liabilities	46			45
Derivative liabilities	4			—
Long-term debt	2,450			2,892
Asset retirement obligations	187			183
Deferred taxes	669			1,484
Total long-term liabilities	3,356			4,604
Commitments and contingencies (Note 13)
Stockholders' equity:
Preferred stock ($0.01 par value, 5,000,000 shares authorized; no shares issued)	—			—
Common stock ($0.01 par value, 300,000,000 and 200,000,000 shares authorized at June 30, 2015 and December 31, 2014, respectively; 163,347,409 and 137,603,643 shares issued at June 30, 2015 and December 31, 2014, respectively)	2			1
Additional paid-in capital	2,415			1,576
Treasury stock (at cost, 381,767 and 275,069 shares at June 30, 2015 and December 31, 2014, respectively)	(14		)	(10		)
Accumulated other comprehensive gain (loss)	(1		)	(1		)
Retained earnings	855			2,327
Total stockholders' equity	3,257			3,893
Total liabilities and stockholders' equity	$	7,458		$	9,598

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						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Oil, gas and NGL revenues	$	469		$	612		$	818		$	1,183

Operating expenses:
Lease operating	73			80			148			154
Transportation and processing	52			37			101			74
Production and other taxes	17			30			30			58
Depreciation, depletion and amortization	248			213			485			405
General and administrative	51			68			114			124
Ceiling test and other impairments	1,521			—			2,313			—
Other	3			3			7			5
Total operating expenses	1,965			431			3,198			820
Income (loss) from operations	(1,496		)	181			(2,380		)	363

Other income (expense):
Interest expense	(46		)	(51		)	(90		)	(102		)
Capitalized interest	8			13			15			26
Commodity derivative income (expense)	(10		)	(174		)	143			(270		)
Other, net	(22		)	1			(14		)	3
Total other income (expense)	(70		)	(211		)	54			(343		)

Income (loss) from continuing operations before income taxes	(1,566		)	(30		)	(2,326		)	20

Income tax provision (benefit):
Current	15			(1		)	18			2
Deferred	(589		)	(7		)	(872		)	13
Total income tax provision (benefit)	(574		)	(8		)	(854		)	15
Income (loss) from continuing operations	(992		)	(22		)	(1,472		)	5
Income (loss) from discontinued operations, net of tax	—			—			—			257
Net income (loss)	$	(992	)	$	(22	)	$	(1,472	)	$	262

Earnings (loss) per share:
Basic:
Income (loss) from continuing operations	$	(6.09	)	$	(0.16	)	$	(9.55	)	$	0.03
Income (loss) from discontinued operations	—			—			—			1.89
Basic earnings (loss) per share	$	(6.09	)	$	(0.16	)	$	(9.55	)	$	1.92
Diluted:
Income (loss) from continuing operations	$	(6.09	)	$	(0.16	)	$	(9.55	)	$	0.03
Income (loss) from discontinued operations	—			—			—			1.87
Diluted earnings (loss) per share	$	(6.09	)	$	(0.16	)	$	(9.55	)	$	1.90
Weighted-average number of shares outstanding for basic earnings (loss) per share	163			136			154			136
Weighted-average number of shares outstanding for diluted earnings (loss) per share	163			136			154			138

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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net income (loss)	$	(992	)	$	(22	)	$	(1,472	)	$	262
Other comprehensive income (loss):
Unrealized gain (loss) on investments, net of tax	—			—			—			—
Other comprehensive income (loss), net of tax	—			—			—			—
Comprehensive income (loss)	$	(992	)	$	(22	)	$	(1,472	)	$	262

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)

(Unaudited)



	Six Months Ended
	June 30,
	2015			2014
Cash flows from operating activities:
Net income (loss)	$	(1,472	)	$	262
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	485			437
Deferred tax provision (benefit)	(872		)	153
Stock-based compensation	25			35
Unrealized (gain) loss on derivative contracts	101			184
Ceiling test and other impairments	2,313			—
Gain on sale of Malaysia business	—			(388		)
Other, net	22			(2		)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(25		)	76
(Increase) decrease in inventories	1			(6		)
(Increase) decrease in other current assets	5			(5		)
(Increase) decrease in other assets	(3		)	1
Increase (decrease) in accounts payable and accrued liabilities	(8		)	(14		)
Increase (decrease) in advances from joint owners	9			(2		)
Increase (decrease) in other liabilities	(4		)	2
Net cash provided by (used in) operating activities	577			733
Cash flows from investing activities:
Additions to oil and gas properties	(916		)	(1,004		)
Acquisitions of oil and gas properties	(1		)	(15		)
Proceeds from sales of oil and gas properties	29			12
Proceeds received from sale of Malaysia business, net	—			809
Additions to other property and equipment	(10		)	(17		)
Redemptions of investments	—			39
Net cash provided by (used in) investing activities	(898		)	(176		)
Cash flows from financing activities:
Proceeds from borrowings under credit arrangements	916			1,134
Repayments of borrowings under credit arrangements	(1,362		)	(1,752		)
Proceeds from issuance of senior notes	691			—
Repayment of senior subordinated notes	(700		)	—
Debt issue costs	(8		)	—
Proceeds from issuances of common stock, net	817			2
Purchases of treasury stock, net	(4		)	—
Other	(1		)	—
Net cash provided by (used in) financing activities	349			(616		)
Increase (decrease) in cash and cash equivalents	28			(59		)
Cash and cash equivalents, beginning of period	14			95
Cash and cash equivalents, end of period	$	42		$	36

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, 2014	137.6	$	1	(0.3	)	$	(10	)	$	1,576	$	2,327		$	(1	)	$	3,893
Issuances of common stock	25.7	1							816								817
Stock-based compensation									23								23
Treasury stock, net				(0.1	)	(4		)	—								(4		)
Net income (loss)											(1,472		)				(1,472		)
Balance, June 30, 2015	163.3	$	2	(0.4	)	$	(14	)	$	2,415	$	855		$	(1	)	$	3,257

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). We focus on U.S. resource plays and our primary areas of operation include the Mid-Continent, the Rocky Mountains and onshore Texas. We also have offshore oil developments in China.

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, 2014.

Risks and Uncertainties

As an independent oil and natural gas producer, our revenue, profitability and future rate of growth are substantially dependent on prevailing prices for oil, natural gas and NGLs. Historically, the energy markets have been very volatile, and there can be no assurance that commodity prices will not be subject to wide fluctuations in the future. A substantial or extended decline in commodity prices could have a material adverse effect on our financial position, results of operations, cash flows, access to capital and on the quantities of oil, natural gas and NGL reserves that we can economically produce.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the 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, the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool and the fair value of both our derivative positions and our stock-based compensation liability awards.

Restructuring Costs

Restructuring costs include severance and related benefit costs, costs associated with abandoned office space, employee relocation costs and other associated costs. Employee severance and related benefit costs are recognized on a straight-line basis over the required service period, if any. Employee relocation costs are expensed as incurred. A liability for noncancellable office-lease costs associated with restructuring will be recognized and measured at fair value on our consolidated balance sheet on the date the leased property ceases to be used. Fair value estimates include assumptions regarding estimated future sub-lease payments. These estimates could materially differ from actual results and may require revision to initial estimates of the liability. See Note 15, "Restructuring Costs," for additional disclosures.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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

We have restricted cash of $7 million included in "Other assets" on our consolidated balance sheet at June 30, 2015 that represents amounts held in escrow accounts to satisfy future plug and abandonment obligations for our China operations. These amounts are restricted as to their current use and will be released as we plug and abandon wells and facilities in our China field. Consistent with our other plug and abandonment activities, changes in restricted cash is included in cash flows from operating activities in our consolidated statement of cash flows.

Discontinued Operations

The results of our Malaysia 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 17, "Discontinued Operations," for additional disclosures, as well as information regarding the sale of our Malaysia business, which closed in February 2014.

New Accounting Requirements

In April 2015, the Financial Accounting Standards Board (FASB) issued guidance regarding the presentation of debt issuance costs in the financial statements and requires that debt issuance costs be presented as a reduction of the carrying value of the financial liability and not as a separate asset. The guidance requires retrospective adjustment to the balance sheet presentation and disclosures applicable for a change in an accounting principle. The guidance is effective for interim and annual periods beginning after December 15, 2015. We expect to adopt this guidance on or before the effective date.

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. In July 2015, the FASB approved a deferral of the effective date by one year. As a result, the guidance is effective for interim and annual periods beginning on or after December 15, 2017. We are currently evaluating the impact of this guidance on our financial statements.

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:

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In millions, except per share data)
Income (numerator):
Income (loss) from continuing operations	$	(992	)	$	(22	)	$	(1,472	)	$	5
Income (loss) from discontinued operations	—			—			—			257
Net income (loss)	$	(992	)	$	(22	)	$	(1,472	)	$	262

Weighted-average shares (denominator):
Weighted-average shares — basic	163			136			154			136
Dilution effect of stock options and unvested restricted stock and restricted stock units outstanding at end of period⁽¹⁾⁽²⁾	—			—			—			2
Weighted-average shares — diluted	163			136			154			138

Earnings (loss) per share:
Basic:
Income (loss) from continuing operations	$	(6.09	)	$	(0.16	)	$	(9.55	)	$	0.03
Income (loss) from discontinued operations	—			—			—			1.89
Basic earnings (loss) per share	$	(6.09	)	$	(0.16	)	$	(9.55	)	$	1.92
Diluted:
Income (loss) from continuing operations	$	(6.09	)	$	(0.16	)	$	(9.55	)	$	0.03
Income (loss) from discontinued operations	—			—			—			1.87
Diluted earnings (loss) per share	$	(6.09	)	$	(0.16	)	$	(9.55	)	$	1.90

_______

(1)

The effect of 1.8 million and 2.1 million unvested restricted stock or restricted stock units and stock options for the three and six months ended June 30, 2015, respectively, and 2.2 million unvested restricted stock or restricted stock units and stock options for the three months ended June 30, 2014 have not been included in the calculation of shares outstanding for diluted EPS as their effect would have been anti-dilutive. Had we recognized income from continuing operations for these periods, 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 1.5 million and 1.4 million shares for the three and six months ended June 30, 2015, respectively, and 1.6 million shares for the three months ended June 30, 2014.


(2)	Excludes 0.8 million shares of unvested restricted stock or restricted stock units and stock options for the six months ended June 30, 2014, respectively, because including the effect would have been anti-dilutive.

3. Stockholders' Equity Activity

During the first quarter of 2015, we issued 25.3 million additional shares of common stock through a public equity offering. We received net proceeds of approximately $815 million, which were used primarily to repay all borrowings under our credit facility and money market lines of credit.

In May 2015, our stockholders approved an amendment to the Company's Certificate of Incorporation that increases the total authorized shares of common stock from 200 million to 300 million shares.

4. Inventories

Inventories primarily consist of tubular goods and well equipment held for use in our oil and natural gas operations and oil produced but not sold in our China operations. At June 30, 2015, the crude oil inventory from our China operations consisted of approximately 63,000 barrels of crude oil valued at cost of approximately $2 million. At December 31, 2014, the crude oil inventory from our China operations consisted of approximately 240,000 barrels of crude oil valued at cost of approximately $8

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

million and is included under the caption "Inventories" on our consolidated balance sheet. Cost for purposes of the carrying value of oil inventory is the sum of related production costs and depletion expense.

5. Oil and Gas Assets

Property and Equipment

Property and equipment consisted of the following:



	June 30, 2015			December 31, 2014
	(In millions)
Oil and gas properties:
Subject to amortization	$	14,032		$	15,707
Not subject to amortization	721			677
Gross oil and gas properties	14,753			16,384
Accumulated depreciation, depletion and amortization	(8,619		)	(8,152		)
Net oil and gas properties	$	6,134		$	8,232
Other property and equipment:
Furniture, fixtures and equipment	$	148		$	144
Gathering systems and equipment	115			114
Accumulated depreciation and amortization	(88		)	(76		)
Net other property and equipment	$	175		$	182

Oil and gas properties not subject to amortization as of June 30, 2015, consisted of the following:



	Costs Incurred In
	2015		2014		2013		2012 and Prior		Total
	(In millions)
Acquisition costs	$	102	$	178	$	158	$	70	$	508
Exploration costs	89		22		—		—		111
Fee mineral interests	—		—		1		23		24
Capitalized interest	15		52		11		—		78
Total oil and gas properties not subject to amortization	$	206	$	252	$	170	$	93	$	721

We capitalized approximately $26 million and $65 million of interest and direct internal costs during the three months ended June 30, 2015 and 2014, respectively, and $58 million and $120 million during the six months ended June 30, 2015 and 2014, respectively.

During the second quarter of 2015, we finalized a settlement agreement with our insurance carriers related to the August 2013 LF-7 topside incident in China and recorded a $57 million receivable and associated reduction to capital expenditures. In July 2015, we received these proceeds.

At June 30, 2015, the ceiling value of our reserves was calculated based upon SEC pricing of $3.39 per MMBtu for natural gas and $71.56 per barrel for oil. Using these prices, our ceiling for the U.S. did not exceed the net capitalized costs of oil and gas properties resulting in a ceiling test writedown. Our ceiling test writedown was approximately $1.5 billion ($958 million after tax) during the three months ended June 30, 2015. During the three months ended March 31, 2015, we recorded a ceiling test writedown of approximately $788 million ($496 million after tax).

The cost center ceiling with respect to the China full cost pool exceeded the net capitalized costs of oil and gas properties by approximately $160 million, net of tax, as of June 30, 2015, and as such, no ceiling test writedown was required.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

The continued decline of SEC pricing for oil and natural gas reserves since June 30, 2015 will likely result in an additional U.S. ceiling test writedown and could result in a ceiling test writedown in China in the third quarter of 2015.

Granite Wash Asset Sale

In September 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.

6. 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 may limit or partially reduce 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, 2014, we purchased call options in early 2015 that effectively lock in the maximum value for a portion of our corresponding oil swaps with short puts. We elected to defer the premiums related to these calls until contract settlement. As of June 30, 2015, the total deferred premiums were $9 million. Excluding the effect of the deferred premium, if the settlement price is above the call strike price, the counterparty is required to make a payment to us.

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 9, “Fair Value Measurements.”

At June 30, 2015, we had outstanding derivative positions as set forth in the tables below.

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NEWFIELD EXPLORATION COMPANY

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)		Purchased Calls (Weighted Average)		Sold Puts (Weighted Average)⁽¹⁾		Floors (Weighted Average)		Ceilings (Weighted Average)
												(In millions)
2015:
Fixed-price swaps	736	$	90.00	$	—	$	—	$	—	$	—	$	22
Fixed-price swaps with sold puts:	8,050
Fixed-price swaps		90.02		—		—		—		—		238
Sold puts		—		—		71.37		—		—		(97		)
Collars with sold puts:	368
Collars		—		—		—		90.00		104.00		11
Sold puts		—		—		75.00		—		—		(6		)
2016:
Fixed-price swaps with sold puts:	10,060
Fixed-price swaps		89.98		—		—		—		—		277
Sold puts		—		—		74.14		—		—		(154		)
Collars with sold puts:	6,220
Collars		—		—		—		90.00		96.15		176
Sold puts		—		—		75.00		—		—		(99		)
Purchased calls	2,562	—		69.07		—		—		—		11
2017:
Fixed-price swaps with sold puts:	4,468
Fixed-price swaps		88.37		—		—		—		—		108
Sold puts		—		—		73.28		—		—		(63		)
Collars with sold puts:	2,080
Collars		—		—		—		90.00		95.59		56
Sold puts		—		—		75.00		—		—		(32		)
Total												$	448

_________________


(1)	If the market prices remain below our sold puts at contract settlement, we will receive the market price plus the following associated with our production:


•	the difference between our floors and our sold puts for collars with sold puts; or


•	the difference between our swaps and our sold puts for fixed-price swaps with sold puts.

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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)
2015:
Fixed-price swaps	30,990	$	4.03	$	—	$	—	$	—	$	35
Swaptions⁽¹⁾	—	3.50		—		—		—		(1		)
Collars	19,320	—		—		3.93		4.74		20
2016:
Swaptions⁽¹⁾	—	3.50		—		—		—		—
Collars	10,980	—		—		4.00		4.54		10
Total										$	64

________

(1)

During the second quarter of 2015, we sold natural gas swaption contracts that, if exercised on their expiration date in the third quarter of 2015, would protect 7,600 MMMBtus of November 2015 through March 2016 production from future commodity price volatility. These contracts give the counterparties the option to enter into swap contracts with us at $3.50 per MMBtu for production in the above period.

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)
June 30, 2015
Oil positions	$	860	$	(403	)	$	294	$	163	$	(412	)	$	403	$	(5	)	$	(4	)
Natural gas positions	65		(1		)	59		5		(1		)	1		—			—
Total	$	925	$	(404	)	$	353	$	168	$	(413	)	$	404	$	(5	)	$	(4	)

December 31, 2014
Oil positions	$	1,115	$	(597	)	$	332	$	186	$	(605	)	$	597	$	(8	)	$	—
Natural gas positions	105		(2		)	99		4		(2		)	2		—			—
Total	$	1,220	$	(599	)	$	431	$	190	$	(607	)	$	599	$	(8	)	$	—

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(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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In millions)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	91		$	(35	)	$	187		$	(52	)
Realized gain (loss) on natural gas positions	32			(12		)	57			(34		)
Total realized gain (loss)	123			(47		)	244			(86		)
Unrealized gain (loss) on oil positions	(99		)	(136		)	(62		)	(176		)
Unrealized gain (loss) on natural gas positions	(34		)	9			(39		)	(8		)
Total unrealized gain (loss)	(133		)	(127		)	(101		)	(184		)
Total	$	(10	)	$	(174	)	$	143		$	(270	)

The use of derivative transactions 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, 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 June 30, 2015, ten of our 17 counterparties accounted for approximately 85% of our contracted volumes, with the largest counterparty accounting for approximately 15%.

Approximately 71% of our volumes subject to derivative instruments are with lenders under our credit facility. Our credit facility, senior 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.

7. Accounts Receivable

Accounts receivable consisted of the following:



	June 30, 2015			December 31, 2014
	(In millions)
Revenue	$	166		$	155
Joint interest	178			230
Insurance proceeds	57			—
Other	62			70
Reserve for doubtful accounts	(16		)	(16		)
Total accounts receivable, net	$	447		$	439

Reserve for doubtful accounts includes an allowance of $15 million related to discontinued operations. See Note 17, "Discontinued Operations."

8. Accrued Liabilities

Accrued liabilities consisted of the following:

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	June 30, 2015		December 31, 2014
	(In millions)
Revenue payable	$	159	$	197
Accrued capital costs	206		441
Accrued lease operating expenses	40		47
Employee incentive expense	33		62
Accrued interest on debt	59		67
Taxes payable	55		32
Other	36		34
Total accrued liabilities	$	588	$	880

9. 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) 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 12, “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.

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.

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(Unaudited)



	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, 2014:
Money market fund investments	$	1		$	—	$	—		$	1
Deferred compensation plan assets	9			—		—			9
Equity securities available-for-sale	10			—		—			10
Oil and gas derivative swap contracts	—			994		—			994
Oil and gas derivative option and swaption contracts	—			—		(381		)	(381		)
Stock-based compensation liability awards	(12		)	—		(3		)	(15		)
Total	$	8		$	994	$	(384	)	$	618

As of June 30, 2015:
Money market fund investments	$	17		$	—	$	—		$	17
Deferred compensation plan assets	5			—		—			5
Equity securities available-for-sale	9			—		—			9
Oil and gas derivative swap contracts	—			680		—			680
Oil and gas derivative option and swaption contracts	—			—		(168		)	(168		)
Stock-based compensation liability awards	(24		)	—		(3		)	(27		)
Total	$	7		$	680	$	(171	)	$	516

The determination of the fair values of our derivative contracts above incorporates various factors, which include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), 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.

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.

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(Unaudited)



	Investments			Derivatives			Stock-Based Compensation			Total
	(In millions)
Balance at January 1, 2014	$	39		$	(8	)	$	(5	)	$	26
Realized or unrealized gains (losses) included in earnings	—			(23		)	(54		)	(77		)
Purchases, issuances, sales and settlements:
Sales	(39		)	—			—			(39		)
Settlements	—			4			13			17
Transfers in to Level 3	—			—			—			—
Transfers out of Level 3	—			3			—			3
Balance at June 30, 2014	$	—		$	(24	)	$	(46	)	$	(70	)
Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at June 30, 2014	$	—		$	(17	)	$	(28	)	$	(45	)

Balance at January 1, 2015	$	—		$	(381	)	$	(3	)	$	(384	)
Realized or unrealized gains (losses) included in earnings	—			109			—			109
Purchases, issuances, sales and settlements:
Settlements	—			104			—			104
Transfers in to Level 3	—			—			—			—
Transfers out of Level 3	—			—			—			—
Balance at June 30, 2015	$	—		$	(168	)	$	(3	)	$	(171	)
Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at June 30, 2015	$	—		$	108		$	—		$	108

Qualitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

Investments. During the first quarter of 2014, all auction rate securities that we held as of January 1, 2014, were sold for $39 million.

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 volatility factors and 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. See Note 6, "Derivative Financial Instruments," for additional discussion of our derivative instruments.

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 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.

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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	$	(197	)	Black-Scholes	Oil price volatility	20.19	%	—	57.66	%
					Credit risk	0.01	%	—	3.08	%
Natural gas option and swaption contracts	$	29		Black-Scholes	Natural gas price volatility	24.25	%	—	51.83	%
					Credit risk	0.01	%	—	1.87	%
SVAP	$	(3	)	Monte Carlo	Implied volatility				36.2	%

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:



	June 30, 2015		December 31, 2014
	(In millions)
5¾% Senior Notes due 2022	$	765	$	772
5⅝% Senior Notes due 2024	1,013		989
5⅜% Senior Notes due 2026	696		—
6⅞% Senior Subordinated Notes due 2020	—		721

Any amounts outstanding under our credit arrangements as of the indicated dates are stated at cost, which approximates fair value. Please see Note 10, “Debt.”

10. Debt

Our debt consisted of the following:



	June 30, 2015		December 31, 2014
	(In millions)
Senior unsecured debt:
Revolving credit facility — LIBOR based loans	$	—	$	345
Money market lines of credit⁽¹⁾	—		101
Total credit arrangements	—		446
5¾% Senior Notes due 2022	750		750
5⅝% Senior Notes due 2024	1,000		1,000
5⅜% Senior Notes due 2026	700		—
Total senior unsecured debt	2,450		2,196
6⅞% Senior Subordinated Notes due 2020	—		700
Discount on notes	—		(4		)
Total long-term debt	$	2,450	$	2,892

________

(1) Because we have the ability and intent to use our available credit facility 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.

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Credit Arrangements

In March 2015, we entered into the fourth amendment to our Credit Agreement. This amendment extended the maturity date of the revolving credit facility from June 2018 to June 2020 and increased the borrowing capacity from $1.4 billion to $1.8 billion. We incurred $7 million of deferred financing costs related to this amendment, which will be amortized through June 2020. As of June 30, 2015, the largest individual loan commitment by any lender was 12% 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 June 30, 2015) 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 June 30, 2015).

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 June 30, 2015). We incurred aggregate commitment fees under our current credit facility of approximately $1 million and $2 million for the three and six-month periods ended June 30, 2015, respectively, which are recorded in “Interest expense” on our consolidated statement of operations. For the three and six months ended June 30, 2014, we incurred commitment fees under our credit facility of approximately $1 million and $2 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 June 30, 2015, we were in compliance with all of our debt covenants.

As of June 30, 2015, 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 June 30, 2015).

Subject to compliance with the restrictive covenants in our credit facility, at June 30, 2015, 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.

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 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 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.

Senior Notes and Senior Subordinated Notes

In March 2015, we issued $700 million of 5⅜% Senior Notes due 2026 and received net proceeds of approximately $690 million (net of offering costs of approximately $10 million). These notes were issued at par to yield 5⅜%. We used the net proceeds to redeem our $700 million aggregate principal amount of 6⅞% Senior Subordinated Notes due 2020 in April 2015. In connection with the redemption, we paid a premium of $24 million. The premium was recorded under the caption "Other income (expense) — Other, net" on our consolidated statement of income. In addition, associated unamortized offering costs and discounts of approximately $8 million were charged to interest expense during the second quarter of 2015 as a result of the redemption.

11. Income Taxes

The following table presents a reconciliation of the United States statutory income tax rate to our effective income tax rate.

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(Unaudited)



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
U.S. statutory income tax rate	35.0	%	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal effect	2.1		(6.7	)	2.1		22.1
Foreign tax on foreign earnings	(0.6	)	(0.9	)	(0.5	)	13.4
Other	0.2		(1.0	)	0.1		8.0
Effective income tax rate	36.7	%	26.4	%	36.7	%	78.5	%

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. These effective tax rate fluctuations are magnified when income before taxes approaches zero.

As of June 30, 2015, 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 2014 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

12. Stock-Based Compensation

Our stock-based compensation consisted of the following:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In millions)
Equity awards	$	12		$	11		$	22		$	22
Liability awards:
Cash-settled restricted stock units	5			10			12			16
Stockholder Value Appreciation Program	(5		)	40			—			54
Total liability awards	—			50			12			70
Total stock-based compensation	12			61			34			92
Capitalized in oil and gas properties	(2		)	(26		)	(9		)	(40		)
Net stock-based compensation expense	$	10		$	35		$	25		$	52

As of June 30, 2015, we had approximately $61 million of total unrecognized stock-based compensation expense related to unvested stock-based compensation awards that vest 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 are currently granted under the 2011 Omnibus Stock Plan, as amended (2011 Plan), to employees and non-employee directors. 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.

Shares available for grant under our 2011 Plan are reduced by 1.87 times the number of shares of restricted stock or restricted stock units awarded under the plan and are reduced by 1 times the number of shares subject to stock options awarded under the plan. In May 2015, our stockholders approved an additional 7.0 million shares available for issuance under our 2011 Plan. As a result, at June 30, 2015, we had approximately (1) 8.4 million shares available for issuance under our 2011 Plan if all future awards are stock options, or (2) 4.5 million shares available for issuance under our 2011 Plan if all future awards are

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(Unaudited)

restricted stock or restricted stock units. Thus far, all awards under our 2011 Plan have been granted as restricted stock or restricted stock unit awards.

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 January 1, 2015	1,902		945		2,847		$	30.05
Granted	271		414		685		25.87
Forfeited	(205	)	(79	)	(284	)	26.89
Vested	(194	)	(172	)	(366	)	36.64
Non-vested shares outstanding at June 30, 2015	1,774		1,108		2,882		$	27.92

On June 30, 2015, the last reported sales price of our common stock on the New York Stock Exchange was $36.12 per share.

Employee Stock Purchase Plan. During the first six months of 2015, options to purchase approximately 85,000 shares of our common stock were issued under our employee stock purchase plan (ESPP). The weighted-average fair value of each option was $7.93 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 0.12%, an expected life of six months and weighted-average volatility of 52%.

Stock Options. As of June 30, 2015, we had approximately 200,000 stock options outstanding and exercisable. No stock options have been granted since 2008, except for ESPP options as discussed above.

Liability Awards

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

Cash-Settled Restricted Stock Units. We grant cash-settled restricted stock units to employees that vest over three years. As of June 30, 2015, we accrued $24 million for future cash settlement upon vesting of awards. 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. As of June 30, 2015, we had unrecognized stock-based compensation expense related to cash-settled restricted stock units of approximately $16 million. The following table provides information about cash-settled restricted stock unit activity.



	Cash-Settled Restricted Stock Units
	(In thousands)
Non-vested units outstanding at January 1, 2015	1,216
Granted	204
Forfeited	(141	)
Vested	(6	)
Non-vested units outstanding at June 30, 2015	1,273

Stockholder Value Appreciation Program. In September 2013, the Compensation and Management Development Committee of the Board approved the 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. Each price trigger, if any, that is reached during the second half of 2015 would result in an approximately $11 million payment.

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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. Each of the first four SVAP payments was approximately $13 million.

Based on the valuation of the SVAP as of June 30, 2015, the fair value was $4 million, of which $3 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 0.13%, a plan term of six months and an average of implied and historical stock price volatility of 41%. Future changes in our stock price could cause the total cost of the program to be different than our estimates as of June 30, 2015. In the event we do not achieve the next price threshold of $47.50 before December 31, 2015, any accrued expense would be reversed.

13. Commitments and Contingencies

We have been named as a defendant in a number of lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (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.


14.	Segment Information

While we only have operations in the oil and gas exploration and production industry, we are organizationally structured along geographic operating segments. Our current operating segments are the United States and China. The accounting policies of each of our operating segments are the same as those described in Note 1, “Organization and Summary of Significant Accounting Policies,” in our Annual Report on Form 10-K for the year ended December 31, 2014.

The following tables provide the geographic operating segment information for our continuing operations for the three- and six- month periods ended June 30, 2015 and 2014. Income tax allocations have been determined based on statutory rates in the applicable geographic segment. Our earnings and profits in China are taxed at the combined statutory rates for China and the U.S. for our income tax allocation of our China operations in the following tables.

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	Domestic			China		Total
	(In millions)
Three Months Ended June 30, 2015:
Oil, gas and NGL revenues	$	370		$	99	$	469
Operating expenses:
Lease operating	56			17		73
Transportation and processing	52			—		52
Production and other taxes	17			—		17
Depreciation, depletion and amortization	207			41		248
General and administrative	49			2		51
Ceiling test and other impairments	1,521			—		1,521
Other	3			—		3
Allocated income tax (benefit)	(568		)	23
Net income (loss) from oil and gas properties	$	(967	)	$	16
Total operating expenses						1,965
Income (loss) from continuing operations						(1,496		)
Interest expense, net of interest income, capitalized interest and other						(60		)
Commodity derivative income (expense)						(10		)
Income (loss) from continuing operations before income taxes						$	(1,566	)
Total assets	$	6,799		$	659	$	7,458
Additions to long-lived assets	$	340		$	15	$	355



	Domestic		China		Total
	(In millions)
Three Months Ended June 30, 2014:
Oil, gas and NGL revenues	$	608	$	4	$	612
Operating expenses:
Lease operating	79		1		80
Transportation and processing	37		—		37
Production and other taxes	29		1		30
Depreciation, depletion and amortization	212		1		213
General and administrative	68		—		68
Other	3		—		3
Allocated income tax (benefit)	67		1
Net income (loss) from oil and gas properties	$	113	$	—
Total operating expenses					431
Income (loss) from continuing operations					181
Interest expense, net of interest income, capitalized interest and other					(37		)
Commodity derivative income (expense)					(174		)
Income (loss) from continuing operations before income taxes					$	(30	)
Total assets	$	8,321	$	635	$	8,956
Additions to long-lived assets	$	550	$	49	$	599

Table of Contents

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)



	Domestic			China		Total
	(In millions)
Six Months Ended June 30, 2015:
Oil, gas and NGL revenues	$	673		$	145	$	818
Operating expenses:
Lease operating	121			27		148
Transportation and processing	101			—		101
Production and other taxes	30			—		30
Depreciation, depletion and amortization	419			66		485
General and administrative	110			4		114
Ceiling test and other impairments	2,313			—		2,313
Other	6			1		7
Allocated income tax (benefit)	(898		)	28
Net income (loss) from oil and gas properties	$	(1,529	)	$	19
Total operating expenses						3,198
Income (loss) from continuing operations						(2,380		)
Interest expense, net of interest income, capitalized interest and other						(89		)
Commodity derivative income (expense)						143
Income (loss) from continuing operations before income taxes						$	(2,326	)
Total assets	$	6,799		$	659	$	7,458
Additions to long-lived assets	$	736		$	27	$	763



	Domestic		China		Total
	(In millions)
Six Months Ended June 30, 2014:
Oil, gas and NGL revenues	$	1,161	$	22	$	1,183
Operating expenses:
Lease operating	151		3		154
Transportation and processing	74		—		74
Production and other taxes	54		4		58
Depreciation, depletion and amortization	400		5		405
General and administrative	124		—		124
Other	5		—		5
Allocated income tax (benefit)	131		6
Net income (loss) from oil and gas properties	$	222	$	4
Total operating expenses					820
Income (loss) from continuing operations					363
Interest expense, net of interest income, capitalized interest and other					(73		)
Commodity derivative income (expense)					(270		)
Income (loss) from continuing operations before income taxes					$	20
Total assets	$	8,321	$	635	$	8,956
Additions to long-lived assets	$	988	$	66	$	1,054

Table of Contents

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

15. Restructuring Costs

In April 2015, we announced plans to combine our onshore Gulf Coast and Rocky Mountain business units into one operating region to be managed from The Woodlands, Texas. Our decision to restructure our organization, which only affects our domestic business, was in response to the current oil and gas commodity price environment. These changes are expected to result in better utilization of our resources and improve cost efficiencies in operations. We expect substantially all one-time restructuring-related costs to be incurred by December 31, 2015 and do not expect these costs to materially affect our cash flows or results of operations. We will abandon most of our Denver, Colorado office space during the third quarter of 2015 and record a liability for the remaining contracted payments net of expected sublease income. We expect the remaining space will be abandoned by December 31, 2015. We will close our North Houston (Greenspoint area) office on or before April 2016, consistent with the terms of our lease.

Restructuring costs recorded in our consolidated statement of operations are set forth below.



		Three Months Ended June 30,				Six Months Ended June 30,
		2015		2014		2015		2014
		(In millions)
Type of Restructuring Cost	Location in the Consolidated Statement of Operations
Severance and related benefit costs	Operating expenses - General and administrative	$	3	$	—	$	3	$	—
Relocation costs	Operating expenses - General and administrative	1		—		1		—
Other associated costs	Operating expenses - Depreciation, depletion and amortization	1		—		1		—
Total		$	5	$	—	$	5	$	—

The following table summarizes our restructuring costs and related accruals.



	Severance and Related Benefit Costs		Office-lease Termination Costs		Relocation Costs			Other Associated Costs			Total
	(In millions)
Restructuring liability at January 1, 2015	$	—	$	—	$	—		$	—		$	—
Additions	3		—		1			1			5
Settlements	—		—		(1		)	(1		)	(2		)
Revisions	—		—		—			—			—
Restructuring liability at June 30, 2015	$	3	$	—	$	—		$	—		$	3

Cumulative costs as of June 30, 2015	$	3	$	—	$	1		$	1		$	5
Expected total costs	$	8	$	10	$	10		$	1		$	29

16. Supplemental Cash Flow Information

The following table presents information about investing and financing activities that affect recognized assets and liabilities but do not result in cash receipts or payments for the indicated periods.



	Six Months Ended
	June 30,
	2015		2014
	(In millions)
Non-cash investing and financing activities excluded from the statement of cash flows:
(Increase) decrease in receivables for property sales	$	8	$	1
(Increase) decrease in accrued capital expenditures	169		(4		)
(Increase) decrease in accrued insurance proceeds	57		—
(Increase) decrease in asset retirement costs	1		13

Table of Contents

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

17. Discontinued Operations

In 2013, we met the criteria to classify our Malaysia business as held for sale and discontinued operations. In February 2014, we closed the sale of our Malaysia business to SapuraKencana Petroleum Berhad (SapuraKencana), a Malaysian public company, for $898 million. As a result of the sale, we recorded a gain in the first quarter of 2014 of approximately $388 million ($252 million, after tax). In the fourth quarter of 2014, we recorded an allowance against a receivable from SapuraKencana and reduced the previously recognized gain by $15 million ($10 million, after tax) due to uncertainty associated with collectability. In April 2015, we initiated a notice of dispute related to the final post-close settlement, which was countered by SapuraKencana. We believe the dispute may result in arbitration proceedings. As a result of the sale of our Malaysia business, there are no other assets and liabilities in the consolidated balance sheet attributable to discontinued operations as of June 30, 2015 or December 31, 2014.

Results of Discontinued Operations



	Six Months Ended June 30,
	2014
	(In millions)
Oil and gas revenues	$	90
Operating expenses	69
Income (loss) from discontinued operations	21
Gain on sale of Malaysia business	388
Income from discontinued operations before income taxes	409
Income tax provision (benefit):
Current	12
Deferred	140
Total income tax provision (benefit)	152
Income (loss) from discontinued operations, net of tax	$	257

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. We focus on U.S. resource plays and our primary areas of operation include the Mid-Continent, the Rocky Mountains and onshore Texas. We also have offshore oil developments in China.

Second quarter 2015 highlights include:


•	increased total domestic production 7% compared to the first quarter of 2015 to 12.2 MMBOE, excluding approximately 1.9 Bcf of natural gas produced and consumed in operations. Domestic liquids production increased 10%;


•	lowered consolidated lease operating expense per BOE by 24% compared to the same quarter in 2014 and 13% from the first quarter of 2015;


•	used proceeds from our March 2015 $700 million 5⅜% Senior Notes offering to redeem our $700 million aggregate principal of our 6⅞% Senior Subordinated Notes due 2020; and


•	reduced completed well costs in our STACK play to approximately $7.9 million gross.

Results of Continuing Operations

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

Domestic Revenues and Production. Revenues during the second quarter of 2015 were $238 million lower than the same quarter of 2014. The lower revenues were attributable to a 42% decrease in the average revenue per BOE compared to the second quarter of 2014. We increased our crude oil production for the second quarter 2015 by 22% over the same period of 2014, reducing the impact of the lower prices by $90 million. Oil production in the Anadarko Basin increased 80% and accounted for $69 million of the $90 million.

Revenues during the six months ended June 30, 2015 were $488 million lower than the same period of 2014. The lower revenues were attributable to a 46% decrease in the average revenue per BOE, period over period. We increased our crude oil production for the six months ended June 30, 2015 by 21% over the same period of 2014, reducing the impact of lower prices by $162 million. Oil production in the Anadarko Basin increased 81% and accounted for $130 million of the $162 million.

China Revenues and Production/Liftings. During the first six months of 2015, our Pearl development in China exceeded our expected volumes as we completed the last of our first six wells on time and managed maintenance-related downtime to maximize production rates. In June 2015, these wells reached peak production and we are on track to lift five million barrels of oil for 2015 from our China operations. Substantially all of our China production comes from our Pearl development. Despite the almost 50% reduction in realized crude oil prices, our revenues from China of $99 million and $145 million for the three and six months ended June 30, 2015, respectively, were significantly higher than the comparable periods of 2014 because our Pearl development commenced production during the fourth quarter of 2014. As such, we expect that 2015 revenues and expenses in China will continue to increase compared to 2014.

The following table reflects our production/liftings from continuing operations and average realized commodity prices:



	Three Months Ended June 30,				Percentage Increase (Decrease)		Six Months Ended June 30,				Percentage Increase (Decrease)
	2015		2014		Percentage Increase (Decrease)		2015		2014		Percentage Increase (Decrease)
Production/Liftings:
Domestic:⁽¹⁾
Crude oil and condensate (MBbls)	5,532		4,535		22	%	10,482		8,656		21	%
Natural gas (Bcf)	27.9		30.5		(8	)%	55.2		58.5		(6	)%
NGLs (MBbls)	1,976		2,022		(2	)%	3,825		3,703		3	%
Total (MBOE)	12,160		11,639		4	%	23,515		22,105		6	%
China:⁽²⁾
Crude oil and condensate (MBbls)	1,643		38		>100 %		2,549		201		>100 %
Total Continuing Operations:
Crude oil and condensate (MBbls)	7,175		4,573		57	%	13,031		8,857		47	%
Natural gas (Bcf)	27.9		30.5		(8	)%	55.2		58.5		(6	)%
NGLs (MBbls)	1,976		2,022		(2	)%	3,825		3,703		3	%
Total (MBOE)	13,803		11,677		18	%	26,064		22,306		17	%
Average Realized Prices:
Domestic:⁽³⁾
Crude oil and condensate (per Bbl)	$	47.59	$	90.19	(47	)%	$	43.16	$	88.41	(51	)%
Natural gas (per Mcf)	2.36		4.32		(45	)%	2.53		4.48		(44	)%
NGLs (per Bbl)	19.17		31.11		(38	)%	19.55		34.29		(43	)%
Crude oil equivalent (per BOE)	30.43		52.18		(42	)%	28.60		52.51		(46	)%
China:
Crude oil and condensate (per Bbl)	$	60.24	$	106.86	(44	)%	$	56.87	$	107.57	(47	)%
Total Continuing Operations:
Crude oil and condensate (per Bbl)	$	50.49	$	90.33	(44	)%	$	45.84	$	88.85	(48	)%
Natural gas (per Mcf)	2.36		4.32		(45	)%	2.53		4.48		(44	)%
NGLs (per Bbl)	19.17		31.11		(38	)%	19.55		34.29		(43	)%
Crude oil equivalent (per BOE)	33.98		52.36		(35	)%	31.37		53.01		(41	)%

________________


(1)	Excludes natural gas produced and consumed in operations of 1.9 Bcf and 2.6 Bcf during the three months ended June 30, 2015 and 2014, respectively, and 4.1 Bcf and 4.4 Bcf during the six months ended June 30, 2015 and 2014, respectively.


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


(3)	We had no outstanding derivative contracts related to our NGL production or our production associated with our international operations. Had we included the realized effects of derivative contracts, the domestic average realized prices would have been as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Crude oil and condensate (per Bbl)	$	64.18	$	82.46	$	61.03	$	82.37
Natural gas (per Mcf)	3.50		3.90		3.56		3.89

Operating Expenses.

Three months ended June 30, 2015 compared to June 30, 2014

The following table presents information about our operating expenses for our continuing operations:



	Unit-of-Production						Total Amount
	Three Months Ended June 30,				Percentage Increase (Decrease)		Three Months Ended June 30,				Percentage Increase (Decrease)
	2015		2014		Percentage Increase (Decrease)		2015		2014		Percentage Increase (Decrease)
	(Per BOE)						(In millions)
Domestic:
Lease operating	$	4.58	$	6.81	(33	)%	$	56	$	79	(30	)%
Transportation and processing	4.22		3.24		30	%	52		37		36	%
Production and other taxes	1.35		2.49		(46	)%	17		29		(43	)%
Depreciation, depletion and amortization	17.05		18.17		(6	)%	207		212		(2	)%
General and administrative	4.09		5.85		(30	)%	49		68		(27	)%
Ceiling test and other impairments	125.05		—		100	%	1,521		—		100	%
Other	0.24		0.21		14	%	3		3		22	%
Total operating expenses	$	156.58	$	36.77	>100 %		$	1,905	$	428	>100 %
China:
Lease operating	$	10.61	$	38.16	(72	)%	$	17	$	1	>100 %
Production and other taxes	—		31.04		(100	)%	—		1		(100	)%
Depreciation, depletion and amortization	25.16		26.04		(3	)%	41		1		>100 %
General and administrative	0.96		—		100	%	2		—		100	%
Total operating expenses	$	36.73	$	95.24	(61	)%	$	60	$	3	>100 %
Total Continuing Operations:
Lease operating	$	5.28	$	6.91	(24	)%	$	73	$	80	(10	)%
Transportation and processing	3.72		3.23		15	%	52		37		36	%
Production and other taxes	1.21		2.58		(53	)%	17		30		(44	)%
Depreciation, depletion and amortization	18.01		18.20		(1	)%	248		213		17	%
General and administrative	3.72		5.83		(36	)%	51		68		(25	)%
Ceiling test and other impairments	110.18		—		100	%	1,521		—		100	%
Other	0.21		0.21		—	%	3		3		21	%
Total operating expenses	$	142.33	$	36.96	>100 %		$	1,965	$	431	>100 %

Domestic Operations. Excluding the effect of the $1.5 billion non-cash ceiling test and other impairments, our operating expenses for domestic operations for the three months ended June 30, 2015 decreased 14% over the same period of 2014 stated on a per BOE basis. The primary components within our operating expenses are as follows:


•	Lease operating expense decreased 33% on a per BOE basis primarily due to lower service costs and higher production volumes. Service costs per BOE declined in our domestic basins period over period due to our increased focus on cost-reduction initiatives combined with downward service cost pressures in the industry due to a lower commodity price environment.


•	Transportation and processing increased 36% primarily due to the increased gas and NGL volumes in our SCOOP and STACK plays, which are subject to higher fees. Second quarter 2015 gas production from these two plays increased 25% compared to the second quarter of 2014, while NGL production increased 19%.


•	Production and other taxes decreased 46% per BOE consistent with lower total revenues. As a percent of total revenue, production and other taxes were 4.4% and 4.8% for the three months ended June 30, 2015 and 2014, respectively. The lower rate in 2015 was due to development in areas with lower production taxes.

•

General and administrative (G&A) expenses per BOE decreased 30% during the second quarter of 2015 compared to the second quarter of 2014. Employee-related expenses associated with our stock-based compensation programs decreased $22 million (net of amounts capitalized) during the second quarter of 2015 compared to the same period of 2014 primarily due to a decrease in the fair value of awards under our Stockholder Value Appreciation Program as the probability of achieving the next payout decreases as the program nears conclusion and our stock price remains below the next price threshold of $47.50 per share. This decrease was partially offset by severance and related benefit costs of $4 million

primarily associated with our domestic restructuring. For the three months ended June 30, 2015, we capitalized $17 million ($1.43 per BOE) of direct internal costs as compared to $50 million ($4.26 per BOE) during the comparable quarter of 2014. This decrease in capitalization is consistent with the decrease in costs associated with our stock-based liability award programs. Capitalization was further decreased by reduced exploration and development activities in the Uinta and Maverick basins during the second quarter of 2015.

•

During the second quarter of 2015, we recorded a non-cash ceiling test writedown of $1.5 billion due to a net decrease in the discounted value of our proved reserves. The decrease primarily resulted from a 13% decrease in crude oil SEC pricing and a 13% decrease in natural gas SEC pricing since March 31, 2015. These commodity price decreases were partially offset by the impact of current service cost reductions on our cash flow estimates.

China Operations. For the three months ended June 30, 2015, total operating expenses increased $57 million due to our Pearl development commencing production during the fourth quarter of 2014. As a result of the different cost structures of our Pearl development and our Bohai Bay field, the 2015 results are not comparable with 2014. We expect our China operating costs in 2015 to continue to be higher than 2014 with the exception of production and other taxes. A new regulation was implemented by the Chinese government in early 2015 resulting in no taxes on production with a contract price below $65 per barrel. As such, until our contract prices exceed $65 per barrel, we will continue to experience lower production and other taxes in China.

Six months ended June 30, 2015 compared to June 30, 2014

The following table presents information about our operating expenses for our continuing operations:



	Unit-of-Production						Total Amount
	Six Months Ended June 30,				Percentage Increase (Decrease)		Six Months Ended June 30,				Percentage Increase (Decrease)
	2015		2014		Percentage Increase (Decrease)		2015		2014		Percentage Increase (Decrease)
	(Per BOE)						(In millions)
Domestic:
Lease operating	$	5.15	$	6.83	(25	)%	$	121	$	151	(20	)%
Transportation and processing	4.27		3.36		27	%	101		74		35	%
Production and other taxes	1.27		2.46		(48	)%	30		54		(45	)%
Depreciation, depletion and amortization	17.81		18.08		(2	)%	419		400		5	%
General and administrative	4.68		5.60		(16	)%	110		124		(11	)%
Ceiling test and other impairments	98.36		—		100	%	2,313		—		100	%
Other	0.24		0.22		9	%	6		5		13	%
Total operating expenses	$	131.78	$	36.55	>100 %		$	3,100	$	808	>100 %
China:
Lease operating	$	10.54	$	17.21	(39	)%	$	27	$	3	>100 %
Production and other taxes	—		18.95		(100	)%	—		4		(100	)%
Depreciation, depletion and amortization	26.14		23.75		10	%	66		5		>100 %
General and administrative	1.56		—		100	%	4		—		100	%
Other	0.45		—		100	%	1		—		100	%
Total operating expenses	$	38.69	$	59.91	(35	)%	$	98	$	12	>100 %
Total Continuing Operations:
Lease operating	$	5.66	$	6.92	(18	)%	$	148	$	154	(4	)%
Transportation and processing	3.86		3.33		16	%	101		74		35	%
Production and other taxes	1.16		2.61		(56	)%	30		58		(48	)%
Depreciation, depletion and amortization	18.62		18.13		3	%	485		405		20	%
General and administrative	4.37		5.55		(21	)%	114		124		(8	)%
Ceiling test and other impairments	88.75		—		100	%	2,313		—		100	%
Other	0.26		0.22		18	%	7		5		36	%
Total operating expenses	$	122.68	$	36.76	>100 %		$	3,198	$	820	>100 %

Domestic Operations. Excluding the effect of the $2.3 billion non-cash ceiling test and other impairments, our domestic operating expenses per BOE decreased 9% for the six months ended June 30, 2015 over the same period of 2014. The primary components within our operating expenses are as follows:

•

Lease operating expense decreased 20% despite a 6% increase in total production. On a per BOE basis, lease operating expense was 25% lower primarily due to lower service costs and higher production volumes. Period over period, service costs per BOE declined in our domestic basins due to our increased focus on cost-reduction initiatives as well as the current lower commodity price environment causing downward pressure on the service industry.


•	Transportation and processing increased 35% primarily due to the increased gas and NGL volumes in our SCOOP and STACK plays, which are subject to higher fees. For the first six months of 2015, gas production from these two plays increased 46% compared to the same period of 2014, while NGL production increased 32%.


•	Production and other taxes decreased 48% per BOE consistent with lower total revenues. As a percent of total revenue, production and other taxes were 4.4% and 4.7% for the six months ended June 30, 2015 and 2014, respectively. The lower rate in 2015 was due to development in areas with lower production taxes.

•

General and administrative expenses per BOE decreased 16% during the first six months of 2015 compared to the first six months of 2014. Employee-related expenses associated with our stock-based compensation programs decreased $23 million (net of amounts capitalized) during the six months ended June 30, 2015 compared to the same period of 2014 primarily due to a decrease in the fair value of awards under our Stockholder Value Appreciation Program as the probability of achieving the next payout decreases as the program nears conclusion and our stock price remains below the next price threshold of $47.50 per share. This decrease was partially offset by severance and related benefit costs of $13 million associated with the reduction in our workforce and domestic restructuring. For the six months ended June 30, 2015, we capitalized $42 million ($1.80 per BOE) of direct internal costs as compared to $86 million ($3.88 per BOE) during the comparable period of 2014. This decrease in capitalization is consistent with the decrease in costs associated with our stock-based liability award programs. Capitalization was further decreased by reduced exploration and development activities in the Uinta and Maverick basins during the first six months of 2015.

•

During the first six months of 2015, we recorded a non-cash ceiling test writedown of $2.3 billion due to a net decrease in the discounted value of our proved reserves. The decrease primarily resulted from a 25% decrease in crude oil SEC pricing and a 22% decrease in natural gas SEC pricing since December 31, 2014. These commodity price decreases were partially offset by the impact of current service cost reductions on our cash flow estimates. Additionally, during the first quarter of 2015, we recorded a $4 million rig impairment associated with our decision to indefinitely lay down both of our company-owned drilling rigs in the Uinta Basin.

China Operations. For the six months ended June 30, 2015, total operating expenses increased $86 million due to our Pearl development commencing production during the fourth quarter of 2014. As a result of the different cost structures of our Pearl development and our Bohai Bay field, the 2015 results are not comparable with 2014. We expect our China operating costs in 2015 to continue to be higher than 2014 with the exception of production and other taxes. A new regulation was implemented by the Chinese government in early 2015 resulting in no taxes on production with a contract price below $65 per barrel. As such, until our contract prices exceed $65 per barrel, we will continue to experience lower production and other taxes in China.

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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In millions)
Gross interest expense:
Credit arrangements	$	2		$	2		$	6		$	5
Senior notes	35			25			63			50
Senior subordinated notes	9			24			21			47
Total gross interest expense	46			51			90			102
Capitalized interest	(8		)	(13		)	(15		)	(26		)
Net interest expense	$	38		$	38		$	75		$	76

Gross interest expense decreased for the three and six months ended June 30, 2015 as compared to the three and six months ended June 30, 2014, primarily due to the redemption of our 7⅛% Senior Subordinated Notes due 2018 in the fourth quarter of 2014 and the redemption of our 6⅞% Senior Subordinated Notes due 2020 in April 2015. This decrease was partially offset by the additional interest expense associated with our $700 million 5⅜% Senior Notes due 2026 issued in March of 2015 and the write off of unamortized offering costs and discounts of approximately $8 million related to the April 2015 redemption.

Interest expense associated with oil and gas properties excluded from amortization is capitalized into oil and gas properties. Capitalized interest decreased for the three and six months ended June 30, 2015, as compared to the three and six months ended June 30, 2014, due to the reduction of oil and gas properties excluded from amortization during the fourth quarter of 2014 and a reduced capitalization rate due to our reduced average borrowing rate.

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. 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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In millions)
Derivatives not designated as hedging instruments:
Total realized gain (loss)	$	123		$	(47	)	$	244		$	(86	)
Total unrealized gain (loss)	(133		)	(127		)	(101		)	(184		)
Commodity derivative income (expense)	$	(10	)	$	(174	)	$	143		$	(270	)

See Note 6, "Derivative Financial Instruments," and Note 9, "Fair Value Measurements," to our consolidated financial statements in Item 1 of this report.

Taxes. The effective tax rates for continuing operations for the three months ended June 30, 2015 and 2014 were 36.7% and 26.4%, respectively. The effective tax rates for continuing operations for the six months ended June 30, 2015 and 2014 were 36.7% and 78.5%, respectively. Our effective tax rate for both periods was different than the federal statutory rate of 35% due to non-deductible expenses, state income taxes, the differences between international and U.S. federal statutory rates, and the impact of our China earnings being taxed both in the U.S. and China. This double taxation is a byproduct of our federal net operating loss (NOL) position that limits our ability to utilize related foreign tax credits (FTC) until our remaining NOLs are utilized. As a result of our earnings being taxed in both the U.S. and China, we expect our effective tax rate for future China earnings to be approximately 60%. We expect the U.S. portion of the rate to be a 35% tax rate, all of which is expected to be deferred.

Our effective tax rate for our domestic operations generally approximates 37%. For the six months ended June 30, 2015, our effective tax rate was 36.7% for continuing operations as the majority of our consolidated net loss from continuing operations resulted from our domestic business, which was only taxable in the U.S.

Discontinued Operations

As a result of the sale of our Malaysia business in February 2014, we do not have current operations classified as discontinued operations, and the period-over-period change in discontinued operations is solely related to the sale. Historical

Malaysia results of operations are not indicative of our future trends or results; therefore, we have not provided detailed information of prior year results of discontinued operations in the results of operations discussion. See Note 1, “Organization and Summary of Significant Accounting Policies,” and Note 17, “Discontinued Operations,” to our consolidated financial statements appearing earlier in this report for additional information regarding the sale of our Malaysia business.

Liquidity and Capital Resources

During the fourth quarter of 2014 and continuing into mid-2015, crude oil prices declined significantly primarily due to global supply and demand imbalances. Though crude oil prices increased in the second quarter of 2015 over first quarter of 2015, prices remain significantly lower than a year earlier. Given the future uncertainty regarding the timing and magnitude of an eventual recovery of crude oil prices, our planned capital spending for 2015 approximates our expected cash flows to preserve long-term liquidity. During the first six months of 2015, as a part of our strategy to optimize long-term liquidity we:


•	issued 25.3 million additional shares of common stock through a public equity offering and received net proceeds of approximately $815 million in the first quarter of 2015, which were used primarily to repay all borrowings under our credit facility and money market lines of credit;


•	issued $700 million 5⅜% Senior Notes due 2026 through a public debt offering and received net proceeds of approximately $690 million in March 2015. In April 2015, we used the proceeds to redeem the $700 million aggregate principal of our 6⅞% Senior Subordinated Notes due 2020; and


•	amended our credit facility in March 2015 to increase the capacity from $1.4 billion to $1.8 billion and extended the maturity date until June 2020.

We expect our 2015 budget will be financed through our cash flows from operations (inclusive of realized derivative contract gains and losses) and borrowings under our credit facility, as needed. Approximately 87% of our expected remaining 2015 domestic oil and gas sales (excluding NGLs) supporting the current 2015 capital budget are protected against oil and gas price volatility using derivative contracts. For further discussion of our derivative activities, see Note 6, "Derivative Financial Instruments," to our consolidated financial statements appearing earlier in this report. Our 2015 capital budget, excluding estimated capitalized interest and direct internal costs of approximately $110 million, is expected to be approximately $1.4 billion, inclusive of additional lease acquisition and drilling in the Anadarko Basin.

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 are 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 or fluctuations in our cash flows.

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 alternative sources of liquidity, including accessing debt and equity capital markets in light of current and expected economic conditions. We believe that our liquidity position and ability to generate cash flows from our operations will be adequate to fund 2015 operations and to meet our other obligations.

Credit Arrangements and Other Financing Activities. In March 2015, we entered into the fourth amendment to our Credit Agreement. This amendment extended the maturity date of the revolving credit facility from June 2018 to June 2020 and increased the borrowing capacity from $1.4 billion to $1.8 billion. We incurred $7 million of deferred financing costs related to this amendment, which will be amortized through June 2020. We maintain money market lines of credit of $195 million. At June 30, 2015, we had no borrowings under our revolving credit facility or our money market lines of credit and no letters of credit outstanding under our credit facility.

As of July 31, 2015, we had no outstanding borrowings and available borrowing capacity of $1.8 billion under our revolving credit facility. As of July 31, 2015, we had $64 million outstanding under our money market lines of credit and available capacity of $131 million.

In April 2015, we completed the redemption of our $700 million aggregate principal of 6⅞% Senior Subordinated Notes due 2020. The transaction included a premium payment of approximately $24 million. We have no scheduled maturities of senior notes until 2022. For a more detailed description of the terms of our credit arrangements and senior notes, please see Note 10, “Debt,” to our consolidated financial statements appearing earlier in this report.

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 June 30, 2015, we had positive working capital of $40 million compared to negative working capital of $161 million at December 31, 2014. The changes in working capital are primarily due to the issuance of 25.3 million additional shares of common stock. 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 China 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 $577 million for the six months ended June 30, 2015, which decreased compared to net cash flows from operations of $733 million (includes $18 million of cash flows from discontinued operations) for the same period in 2014. We had no cash flows from discontinued operations for the six months ended June 30, 2015. The primary driver of lower operating cash flows was lower revenues as a result of lower commodity prices.

Cash Flows from Investing Activities. Net cash used in investing activities for the six months ended June 30, 2015 was $898 million compared to $176 million net cash used in investing activities for the same period in 2014. While capital expenditures in 2015 were approximately $88 million lower due to our planned reductions in capital spending as compared to the first six months of 2014, lower net cash used in investing activities in 2014 resulted from proceeds of $809 million received from the sale of our Malaysia business.

Cash Flows from Financing Activities. Net cash provided by financing activities for the six months ended June 30, 2015 was $349 million compared to net cash used in financing activities of $616 million for the same period in 2014. During the six months ended June 30, 2015, we:


•	issued 25.3 million additional shares of common stock through a public equity offering and received net proceeds of approximately $815 million, which were used primarily to repay all borrowings under our credit facility and money market lines of credit; and


•	issued $700 million 5⅜% Senior Notes due 2026 through a public debt offering and received net proceeds of approximately $690 million in March 2015. In April 2015, we used the proceeds to redeem our $700 million aggregate principal of our 6⅞% Senior Subordinated Notes due 2020.

Capital Expenditures. Our capital investments for continuing operations for the first six months of 2015 decreased 26% as compared to the same period of 2014. The table below summarizes our capital investments.



	Six Months Ended June 30,
	2015		2014
	(In millions)
Continuing operations:
Exploitation and development	$	493	$	716
Exploration (exclusive of exploitation and leasehold)	127		155
Acquisitions	1		15
Leasing proved and unproved property (leasehold)	77		46
Pipeline spending	2		4
Total continuing operations	700		936
Discontinued operations	—		12
Total	$	700	$	948

Restructuring

In April 2015, we announced plans to restructure our organization in response to the current commodity price environment, by combining our onshore Gulf Coast and Rocky Mountain business units into one operating region to be managed from The Woodlands, Texas. These changes are expected to result in better utilization of our resources and improve cost efficiencies in operations. We began managing the new region from our existing Texas offices in August 2015, and we expect to abandon our Denver, Colorado office by December 31, 2015 and our North Houston (Greenspoint area) office on or before April 2016.

Restructuring costs include severance and related benefit costs, costs associated with abandoned office space, employee relocation costs and other associated costs. Restructuring costs are expected to total $29 million and will be funded through our cash flows from operations. We expect substantially all one-time restructuring-related costs to be incurred by December 31, 2015 and do not expect these costs to materially affect our cash flows or results of operations. See Note 15, "Restructuring Costs," to our consolidated financial statements in Item 1 of this report for additional details regarding our restructuring activities.

Ceiling Test Writedown

At June 30, 2015, the values of our U.S. and China cost center ceilings were calculated based upon SEC pricing of $3.39 per MMBtu for natural gas and $71.56 per barrel for oil. Using these prices, our ceiling for the U.S. did not exceed the net capitalized costs of oil and gas properties resulting in a non-cash ceiling test writedown of approximately $1.5 billion ($958 million after tax). The cost center ceiling with respect to the China full cost pool exceeded the net capitalized costs of oil and gas properties by approximately $160 million, net of tax, and as such, no ceiling test writedown was required. Holding all other factors constant, it is likely that we will experience a ceiling test writedown in the U.S. in the third quarter of 2015. In addition, we could have a ceiling test writedown for our China full cost pool. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes. Subject to these numerous factors and inherent limitations, we believe that an impairment in the third quarter of 2015 could exceed $1.0 billion for our U.S. full cost pool. Once recorded, a ceiling test writedown is not reversible at a later date even if oil and gas prices increase.

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 Annual Report on Form 10-K for the year ended December 31, 2014. There have been no material changes to the disclosure since year-end 2014, except that in March 2015 we issued $700 million of 5⅜% Senior Notes due 2026 and in April 2015 we redeemed our 6⅞% Senior Subordinated Notes due 2020. The 2026 Senior Notes were issued at par to yield 5⅜%. The semi-annual interest payments of approximately $19 million associated with these notes will be made in January and July of each year.

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.

Oil and Gas Derivatives

We use derivative contracts to manage the variability in cash flows caused by commodity price fluctuations associated with our anticipated oil and gas production for the next 24 to 36 months. As of June 30, 2015, we had no outstanding derivative contracts related to our NGL production. We do not use derivative instruments for trading purposes.

For a further discussion of our derivative activities, see "Oil, Natural Gas and NGL Prices" in Item 3 of this report. See the discussion and tables in Note 6, “Derivative Financial Instruments,” and Note 9, “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 contracts and the estimated fair market value of those positions as of June 30, 2015.

Between July 1, 2015 and July 31, 2015, we did not enter into additional derivative contracts.

Accounting for Derivative Activities. As our derivative contracts are not designated for hedge accounting, they 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 June 30, 2015, we had net derivative assets of $512 million, of which 58%, 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:

•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 June 30, 2015. 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, 2014 and Note 6, “Derivative Financial Instruments,” and Note 9, “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 the expectations reflected in such forward-looking statements 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 natural gas liquids prices;


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


•	accuracy and fluctuations in our reserves estimates due to sustained low commodity prices;


•	ability to develop existing reserves or acquire new reserves;

•the timing and our success in discovering, producing and estimating reserves;

•sustained decline in commodity prices resulting in writedowns of assets;

•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, climate change and over-the-counter derivatives;


•	land, legal, regulatory, 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;

•drilling risks and results;

•the prices and availability of goods and services;

•the cost and 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;

•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 other factors affecting our business described under the caption “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” included in our 2014 Annual Report on Form 10-K.

Should one or more of the risks described above occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

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 activities. 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. Most of the exploitation wells we drill are located in the Mid-Continent or the Monument Butte field. 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.

Liquids. Crude oil and NGLs.

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.

Probable reserves. Those additional reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered. The SEC provides a complete definition of probably reserves in Rule 4-10(a)(18) of Regulation S-X.

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.

SCOOP. South-Central Oklahoma Oil Province. A field in the Anadarko Basin of Oklahoma in which we operate.

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).

STACK. Sooner Trend Anadarko Canadian Kingfisher. A play in the Anadarko Basin of Oklahoma in which we operate.

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 can limit or reduce 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 June 30, 2015, ten of our 17 counterparties accounted for approximately 85% of our contracted volumes, with the largest counterparty accounting for approximately 15%. Of our remaining expected 2015 crude oil production, 88% is protected against price volatility through the use of derivative contracts. Approximately 90% of our crude oil derivative structures include short puts. Short puts effectively limit our downward price protection below the weighted average of our short puts of $71.53 per barrel. If the market price remains below $71.53 per barrel, we receive the market price for our associated production plus the difference between our short puts and the associated floors or fixed-price swaps, which average $18.49 per barrel. We do not have any natural gas derivative contracts that include short puts. 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 6, “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, 2014.

Interest Rates

We consider our interest rate exposure to be minimal because 100% of our obligations were at fixed rates as of June 30, 2015. A 10% increase in LIBOR would not impact our interest cost on debt outstanding as of June 30, 2015, 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 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 June 30, 2015.

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 June 30, 2015.

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 second quarter of 2015 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

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 individually or in the aggregate exceed $100,000. If any fines or penalties are in fact imposed that are greater than $100,000, or we expect to be greater than $100,000, then we will disclose such fact in our subsequent filings.

Item 1A. Risk Factors

The following risk factor updates, and should be considered in addition to, the risk factors previously reported in our Annual Report on Form 10-K for the year ended December 31, 2014. Other than the risk factor discussed below, there have been no material changes with respect to the risk factors previously reported in our Annual Report on Form 10-K.

Legislation or regulatory initiatives intended to address seismic activity in Oklahoma could increase our costs of compliance or lead to operational delays, which could have a material adverse effect on our business, results of operations or financial condition. We conduct oil and natural gas exploration, development and drilling activities in Oklahoma and elsewhere. In recent years, Oklahoma has experienced a significant increase in seismic activity. This increase has led the Oklahoma Corporation Commission (OCC), and other state and federal agencies, to evaluate and monitor the correlation between seismicity and oil and natural gas exploration and production activities, with the primary concern focused on injection wells used for wastewater disposal. In September 2014, the OCC adopted amended monitoring and reporting rules for disposal wells in certain seismically-active areas. The Oklahoma Geologic Survey (“OGS”) then issued in April 2015 a document entitled “Statement of Oklahoma

Seismicity,” in which the agency states “[t]he OGS considers it very likely that the majority of recent earthquakes, particularly those in central and north-central Oklahoma, are triggered by the injection of produced water in disposal wells.” Thereafter, in July 2015, the OCC issued an additional directive regarding its regulations targeting disposal operations in specific counties in Oklahoma. These developments may result in additional levels of regulation, or increased complexity and costs with respect to existing regulations, that could lead to operational delays or increased operating and compliance costs, which could have a material adverse effect on our business, results of operations or financial condition.

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 June 30, 2015.



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
April 1 — April 30, 2015	53,964	$	37.90	—	—
May 1 — May 31, 2015	9,184	38.06		—	—
June 1 — June 30, 2015	13,675	37.22		—	—
Total	76,823	$	37.80	—	—

_______


(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		Fourth Amended and Restated Certificate of Incorporation of Newfield Exploration Company dated July 20, 2015 (incorporated by reference to Exhibit 3.1 to Newfield’s Current Report on Form 8-K filed with the SEC on July 27, 2015 (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		Newfield Exploration Company Second Amended and Restated 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8 filed with the SEC on June 3, 2015 (Registration No. 333-204694))

*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: August 5, 2015	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		Fourth Amended and Restated Certificate of Incorporation of Newfield Exploration Company dated July 20, 2015 (incorporated by reference to Exhibit 3.1 to Newfield’s Current Report on Form 8-K filed with the SEC on July 27, 2015 (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		Newfield Exploration Company Second Amended and Restated 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8 filed with the SEC on June 3, 2015 (Registration No. 333-204694))

*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

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* Filed or furnished herewith.