Edgar Filing: NEWFIELD EXPLORATION CO /DE/

Document

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, 2017



¨		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, smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):



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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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, 2017, there were 199,319,211 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, 2017 and December 31, 2016	1

	Consolidated Statement of Operations and Comprehensive Income for the three and six months ended June 30, 2017 and 2016	2

	Consolidated Statement of Cash Flows for the six months ended June 30, 2017 and 2016	3

	Consolidated Statement of Stockholders' Equity for the six months ended June 30, 2017	4

	Notes to Consolidated Financial Statements	5

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33

Item 4.	Controls and Procedures	34


PART II

Item 1.	Legal Proceedings	34

Item 1A.	Risk Factors	35

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35

Item 6.	Exhibits	36

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEET

(In millions, except share data)

(Unaudited)



	June 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	522		$	555
Short-term investments	25			25
Accounts receivable, net	224			232
Inventories	19			16
Derivative assets	33			75
Other current assets	60			46
Total current assets	883			949
Oil and gas properties, net — full cost method ($1,246 and $1,238 were excluded from amortization at June 30, 2017 and December 31, 2016, respectively)	3,479			3,140
Other property and equipment, net	166			167
Derivative assets	1			—
Long-term investments	23			19
Restricted cash	32			25
Other assets	11			12
Total assets	$	4,595		$	4,312
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	44		$	33
Accrued liabilities	546			498
Advances from joint owners	73			54
Asset retirement obligations	2			2
Derivative liabilities	13			97
Total current liabilities	678			684
Other liabilities	67			63
Derivative liabilities	—			3
Long-term debt	2,432			2,431
Asset retirement obligations	156			154
Deferred taxes	55			39
Total long-term liabilities	2,710			2,690
Commitments and contingencies (Note 11)
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 shares authorized at June 30, 2017 and December 31, 2016; 200,728,889 and 200,150,392 shares issued at June 30, 2017 and December 31, 2016, respectively)	2			2
Additional paid-in capital	3,278			3,247
Treasury stock (at cost, 1,397,293 and 1,195,809 shares at June 30, 2017 and December 31, 2016, respectively)	(52		)	(44		)
Accumulated other comprehensive income (loss)	(1		)	(2		)
Retained earnings (deficit)	(2,020		)	(2,265		)
Total stockholders' equity	1,207			938
Total liabilities and stockholders' equity	$	4,595		$	4,312

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

(In millions, except per share data)

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Oil, gas and NGL revenues	$	402		$	381		$	819		$	665

Operating expenses:
Lease operating	58			62			114			123
Transportation and processing	71			66			143			129
Production and other taxes	13			11			27			21
Depreciation, depletion and amortization	110			160			216			337
General and administrative	51			58			98			102
Ceiling test and other impairments	—			522			—			1,028
Other	—			—			1			1
Total operating expenses	303			879			599			1,741
Income (loss) from operations	99			(498		)	220			(1,076		)

Other income (expense):
Interest expense	(37		)	(38		)	(75		)	(79		)
Capitalized interest	15			11			31			20
Commodity derivative income (expense)	28			(133		)	81			(150		)
Other, net	2			—			4			1
Total other income (expense)	8			(160		)	41			(208		)

Income (loss) before income taxes	107			(658		)	261			(1,284		)

Income tax provision (benefit):
Current	2			6			—			4
Deferred	7			3			16			3
Total income tax provision (benefit)	9			9			16			7
Net income (loss)	$	98		$	(667	)	$	245		$	(1,291	)

Earnings (loss) per share:
Basic	$	0.49		$	(3.36	)	$	1.23		$	(6.87	)
Diluted	$	0.49		$	(3.36	)	$	1.22		$	(6.87	)
Weighted-average number of shares outstanding for basic earnings (loss) per share	199			198			199			188
Weighted-average number of shares outstanding for diluted earnings (loss) per share	200			198			200			188

Comprehensive income (loss):
Net income (loss)	$	98		$	(667	)	$	245		$	(1,291	)
Other comprehensive income (loss), net of tax	1			—			1			—
Comprehensive income (loss)	$	99		$	(667	)	$	246		$	(1,291	)

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,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	245		$	(1,291	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	216			337
Deferred tax provision (benefit)	16			3
Stock-based compensation	20			19
Unrealized (gain) loss on derivative contracts	(46		)	296
Ceiling test and other impairments	—			1,028
Other, net	7			6
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	8			(1		)
Increase (decrease) in accounts payable and accrued liabilities	5			(41		)
Other items, net	(4		)	22
Net cash provided by (used in) operating activities	467			378
Cash flows from investing activities:
Additions to oil and gas properties	(507		)	(471		)
Acquisitions of oil and gas properties	(6		)	(495		)
Proceeds from sales of oil and gas properties	28			29
Additions to other property and equipment	(8		)	(8		)
Redemptions of investments	25			—
Purchases of investments	(25		)	—
Net cash provided by (used in) investing activities	(493		)	(945		)
Cash flows from financing activities:
Proceeds from borrowings under credit arrangements	—			536
Repayments of borrowings under credit arrangements	—			(575		)
Proceeds from issuances of common stock, net	2			777
Purchases of treasury stock, net	(8		)	(11		)
Other	(1		)	—
Net cash provided by (used in) financing activities	(7		)	727
Increase (decrease) in cash and cash equivalents	(33		)	160
Cash and cash equivalents, beginning of period	555			5
Cash and cash equivalents, end of period	$	522		$	165

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 (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholders' Equity
	Common Stock			Treasury Stock
	Shares	Amount		Shares		Amount
Balance, December 31, 2016	200.2	$	2	(1.2	)	$	(44	)	$	3,247	$	(2,265	)	$	(2	)	$	938
Issuances of common stock	0.5	—							2								2
Stock-based compensation									29								29
Treasury stock, net				(0.2	)	(8		)	—								(8		)
Net income (loss)											245						245
Other comprehensive income (loss), net of tax														1			1
Balance, June 30, 2017	200.7	$	2	(1.4	)	$	(52	)	$	3,278	$	(2,020	)	$	(1	)	$	1,207

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

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and Summary of Significant Accounting Policies

Organization and Principles of Consolidation

We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids (NGLs). Our U.S. operations are onshore and focus primarily on large scale, liquids-rich resource plays. Our principal areas of operation are the Anadarko and Arkoma basins of Oklahoma, the Williston Basin of North Dakota and the Uinta Basin of Utah. In addition, we have oil producing assets offshore 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 (U.S. GAAP). 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, 2016.

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. Other risks and uncertainties that could affect us in a volatile commodity price environment include, but are not limited to, counterparty credit risk for our receivables, responsibility for decommissioning liabilities for offshore interests we no longer own, inability to access credit markets, regulatory risks and our ability to meet financial ratios and covenants in our financing agreements.

Use of Estimates

The preparation of financial statements in accordance with U.S. GAAP 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, the recoverability of our deferred tax assets and the fair value of our derivative contracts.

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.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

New Accounting Requirements

In November 2016, the Financial Accounting Standards Board (FASB) issued guidance regarding the classification and presentation of changes in restricted cash on the statement of cash flows. The guidance requires that a statement of cash flows explains the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents using a retrospective approach. The guidance is effective for interim and annual periods beginning after December 15, 2017. We do not expect this guidance to have a material impact on our financial statements.

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The guidance is effective for interim and annual periods beginning after December 15, 2017 and may be applied retrospectively or using a modified retrospective approach to adjust retained earnings (deficit). We expect to apply the guidance in the first quarter of 2018 using the modified retrospective approach to adjust retained earnings (deficit). We are in the process of comparing our current revenue recognition policies to the new requirements for each of our revenue categories. While we have not identified any material differences in the amount and timing of revenue recognition for the categories we have reviewed to date, our evaluation is not complete, and we have not concluded on the overall impacts of adopting the new requirements.

In January 2016, the FASB issued guidance regarding several broad topics related to the recognition and measurement of financial assets and liabilities. The guidance is effective for interim and annual periods beginning after December 15, 2017. We do not expect this guidance to have a material impact on our financial statements.

In February 2016, the FASB issued guidance regarding the accounting for leases. The guidance requires recognition of most leases on the balance sheet. The guidance requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The guidance is effective for interim and annual periods beginning after December 15, 2018. We are currently evaluating the impact of this guidance on our financial statements.

2. Accounts Receivable

Accounts receivable consisted of the following:



	June 30, 2017			December 31, 2016
	(In millions)
Revenue	$	144		$	163
Joint interest	65			53
Other	31			32
Reserve for doubtful accounts	(16		)	(16		)
Total accounts receivable, net	$	224		$	232

3. 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. Inventories are carried at the lower of cost or net realizable value. At June 30, 2017 and December 31, 2016, the crude oil inventory from our China operations consisted of approximately 105,400 and 11,500 barrels of crude oil, respectively.

4. 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. Our derivative strategies are outlined in our Annual Report on Form 10-K for the year ended December 31, 2016.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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 counterparty rates of default and time to maturity. The calculation of the fair value of options requires the use of an option-pricing model. See Note 5, "Fair Value Measurements."

At June 30, 2017, we had outstanding derivative positions as set forth in the tables below.

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)⁽²⁾		Sold Puts (Weighted Average)⁽¹⁾		Floors (Weighted Average)		Ceilings (Weighted Average)		Estimated Fair Value Asset (Liability)
												(In millions)
2017:
Fixed-price swaps	3,128	$	45.43	$	—	$	—	$	—	$	—	$	(4	)
Fixed-price swaps with sold puts:	2,208
Fixed-price swaps		87.95		—		—		—		—		91
Sold puts		—		—		73.08		—		—		(61		)
Purchased calls	2,208	—		73.08		—		—		—		—
Total												$	26

_________________


(1)	For the fixed-price swaps with sold puts, if the market price remains below our sold puts at contract settlement, we will receive the market price plus the difference between our swaps and our sold puts.


(2)	As a result of our purchased calls, we have effectively locked in the spread between our fixed-price swaps and sold puts (less the deferred call premium).

We deferred the premiums related to the purchased calls until contract settlement. At June 30, 2017, the deferred premiums totaled $5 million.

Natural Gas



		NYMEX Contract Price Per MMBtu
				Collars				Estimated Fair Value Asset (Liability)
Period and Type of Instrument	Volume in MMMBtus	Swaps (Weighted Average)		Floors (Weighted Average)		Ceilings (Weighted Average)		Estimated Fair Value Asset (Liability)
								(In millions)
2017:
Fixed-price swaps	13,800	$	2.73	$	—	$	—	$	(4	)
Collars	28,520	—		2.84		3.25		(2		)
2018:
Fixed-price swaps	10,950	3.01		—		—		—
Collars	18,150	—		3.00		3.55		1
Total								$	(5	)

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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, 2017
Oil positions	$	95	$	(62	)	$	33	$	—	$	(69	)	$	62	$	(7	)	$	—
Natural gas positions	9		(8		)	—		1		(14		)	8		(6		)	—
Total	$	104	$	(70	)	$	33	$	1	$	(83	)	$	70	$	(13	)	$	—

December 31, 2016
Oil positions	$	226	$	(151	)	$	75	$	—	$	(197	)	$	151	$	(46	)	$	—
Natural gas positions	10		(10		)	—		—		(64		)	10		(51		)	(3		)
Total	$	236	$	(161	)	$	75	$	—	$	(261	)	$	161	$	(97	)	$	(3	)

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In millions)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	19		$	58		$	45		$	129
Realized gain (loss) on natural gas positions	(4		)	6			(10		)	17
Total realized gain (loss)	15			64			35			146
Unrealized gain (loss) on oil positions	(4		)	(149		)	(3		)	(232		)
Unrealized gain (loss) on natural gas positions	17			(48		)	49			(64		)
Total unrealized gain (loss)	13			(197		)	46			(296		)
Total	$	28		$	(133	)	$	81		$	(150	)

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 the separate derivative instruments with that counterparty. At June 30, 2017, 10 of our 15 counterparties accounted for approximately 84% of our contracted volumes, with the largest counterparty accounting for approximately 13%.

At June 30, 2017, approximately 83% 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.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

5. 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.


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, purchased calls or swaptions).

We use a modified Black-Scholes option pricing valuation model for option and swaption derivative contracts that considers 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.

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.

The determination of the fair values of our derivative contracts 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. We utilize counterparty rate of default values to assess the impact of non-performance risk when evaluating both our liabilities to, and receivables from, counterparties.

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Recurring Fair Value Measurements

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



	Fair Value Measurement Classification
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Total
	(In millions)
As of December 31, 2016:
Money market fund investments	$	320		$	—	$	—		$	320
Deferred compensation plan assets	6			—		—			6
Equity securities available-for-sale	9			—		—			9
Oil and gas derivative swap contracts	—			50		—			50
Oil and gas derivative option contracts	—			—		(75		)	(75		)
Stock-based compensation liability awards	(11		)	—		—			(11		)
Total	$	324		$	50	$	(75	)	$	299

As of June 30, 2017:
Money market fund investments	$	289		$	—	$	—		$	289
Deferred compensation plan assets	7			—		—			7
Equity securities available-for-sale	11			—		—			11
Oil and gas derivative swap contracts	—			83		—			83
Oil and gas derivative option contracts	—			—		(62		)	(62		)
Stock-based compensation liability awards	(12		)	—		—			(12		)
Total	$	295		$	83	$	(62	)	$	316

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NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Level 3 Fair Value Measurements

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the indicated periods.



	Derivatives
	(In millions)
Balance at January 1, 2016	$	(308	)
Unrealized gains (losses) included in earnings	(4		)
Purchases, issuances, sales and settlements:
Settlements	131
Transfers into Level 3	—
Transfers out of Level 3⁽¹⁾	46
Balance at June 30, 2016	$	(135	)
Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at June 30, 2016	$	43

Balance at January 1, 2017	$	(75	)
Unrealized gains (losses) included in earnings	(17		)
Purchases, issuances, sales and settlements:
Settlements	30
Transfers into Level 3	—
Transfers out of Level 3	—
Balance at June 30, 2017	$	(62	)
Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at June 30, 2017	$	(10	)

_________________


(1)	During the second quarter of 2016, we transferred $46 million of derivative option contracts out of the Level 3 hierarchy. The transfer was the result of our Level 3 swaptions being exercised by the counterparties as swaps in June 2016.

Qualitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

Derivatives. 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 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. 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. See Note 4, "Derivative Financial Instruments."

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(Unaudited)

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	$	(61	)	Modified Black-Scholes	Oil price volatility	24.27	%	—	99.30%
					Credit risk	0.01	%	—	1.39%
Natural gas option contracts	$	(1	)	Modified Black-Scholes	Natural gas price volatility	24.42	%	—	46.56%
					Credit risk	0.01	%	—	1.39%

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, 2017		December 31, 2016
	(In millions)
5¾% Senior Notes due 2022	$	793	$	789
5⅝% Senior Notes due 2024	1,041		1,044
5⅜% Senior Notes due 2026	726		714

Any amounts outstanding under our revolving credit facility and money market lines of credit as of the indicated dates are stated at cost, which approximates fair value. See Note 10, "Debt."

6. Oil and Gas Properties

Oil and gas properties consisted of the following:



	June 30, 2017			December 31, 2016
	(In millions)
Proved	$	22,536		$	21,998
Unproved	1,246			1,238
Gross oil and gas properties	23,782			23,236
Accumulated depreciation, depletion and amortization	(9,794		)	(9,587		)
Accumulated impairment	(10,509		)	(10,509		)
Net oil and gas properties	$	3,479		$	3,140

Costs withheld from amortization as of June 30, 2017 consisted of the following:



	Costs Incurred In
	2017		2016		2015		2014 & Prior		Total
	(In millions)
Acquisition costs	$	77	$	532	$	339	$	156	$	1,104
Exploration costs	—		—		—		—		—
Capitalized interest	31		51		33		27		142
Total costs withheld from amortization	$	108	$	583	$	372	$	183	$	1,246

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We capitalized approximately $31 million and $30 million of interest and direct internal costs during the three months ended June 30, 2017 and 2016, respectively, and $64 million and $56 million during the six months ended June 30, 2017 and 2016, respectively.

At June 30, 2017, the ceiling value of our reserves was calculated based upon SEC pricing of $48.95 per barrel for oil and $3.01 per MMBtu for natural gas. Using these prices, our ceiling for the U.S. exceeded the net capitalized costs of oil and gas properties and no ceiling test impairment was required at June 30, 2017. Using SEC pricing, our ceiling for China exceeded the net capitalized costs of oil and gas properties and no ceiling test impairment was required at June 30, 2017.

Future declines in SEC pricing or downward revisions to our estimated proved reserves could result in additional ceiling test impairments of our oil and gas properties in subsequent periods.

Bohai Bay (China) Sales Agreement

On May 22, 2017, we closed our previously disclosed sale transaction with certain of our joint venture partners to divest our non-operated interest in the Bohai Bay field in China for approximately $32 million, including customary post-close adjustments. Upon completion of our assessment, the sale of our Bohai Bay assets did not significantly alter the relationship between capitalized costs and proved reserves for our China full cost pool and, as such, all proceeds were recorded as adjustments to our China full cost pool with no gain or loss recognized.

7. Other Property and Equipment

Other property and equipment consisted of the following:



	June 30, 2017			December 31, 2016
	(In millions)
Furniture, fixtures and equipment	$	157		$	150
Gathering systems and equipment	116			115
Accumulated depreciation and amortization	(107		)	(98		)
Net other property and equipment	$	166		$	167

8. Income Taxes

The effective tax rates for the three months ended June 30, 2017 and 2016 were 8.8% and (1.4)%, respectively. The effective tax rates for the six months ended June 30, 2017 and 2016 were 6.3% and (0.6)%, respectively.

Due to the ceiling test impairments of our oil and gas properties in 2015, we moved from a deferred tax liability position to a deferred tax asset position in most taxing jurisdictions. We consider it more likely than not that the related tax benefits will not be realized and therefore, we recorded a full valuation allowance on our domestic and China deferred tax assets.

As of June 30, 2017, we did not have a liability for uncertain tax positions, and as such, we did not accrue related interest or penalties. The tax years 2011 and 2013 through 2016 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

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9. Accrued Liabilities

Accrued liabilities consisted of the following:



	June 30, 2017		December 31, 2016
	(In millions)
Revenue payable	$	220	$	196
Accrued capital costs	149		92
Accrued lease operating expenses	31		37
Employee incentive expense	24		48
Accrued interest on debt	67		67
Taxes payable	15		15
Other	40		43
Total accrued liabilities	$	546	$	498

10. Debt

Our debt consisted of the following:



	June 30, 2017			December 31, 2016
	(In millions)
Senior unsecured debt:
5¾% Senior Notes due 2022	$	750		$	750
5⅝% Senior Notes due 2024	1,000			1,000
5⅜% Senior Notes due 2026	700			700
Total senior unsecured debt	2,450			2,450
Debt issuance costs	(18		)	(19		)
Total long-term debt	$	2,432		$	2,431

Credit Arrangements

We have a revolving credit facility that matures in June 2020 and provides borrowing capacity of $1.8 billion. As of June 30, 2017, the largest individual loan commitment by any lender was 12% of total commitments.

Subject to compliance with restrictive covenants in our credit facility, our available borrowing capacity (before any amounts drawn) under our money market lines of credit with various institutions, the availability of which is at the discretion of those financial institutions, was $125 million at June 30, 2017.

Loans under the credit facility bear interest, at our option, equal to (a) the Alternate Base Rate (as defined in the Credit Agreement), plus a margin that is based on a grid of our debt rating (100 basis points per annum at June 30, 2017) or (b) the Adjusted Eurodollar Rate (as defined in the Credit Agreement), plus a margin that is based on a grid of our debt rating (200 basis points per annum at June 30, 2017).

Under our credit facility, we pay commitment fees on available but undrawn amounts based on a grid of our debt rating (37.5 basis points per annum at June 30, 2017). We incurred aggregate commitment fees under our credit facility of approximately $1 million and $3 million for the three and six months ended June 30, 2017, respectively, which were recorded in “Interest expense” on our consolidated statement of operations and comprehensive income. For the three and six months ended June 30, 2016, we incurred commitment fees under our credit facility of approximately $2 million and $4 million, respectively. We incurred approximately $3 million of financing costs related to amending our revolving credit facility in March 2016, which were also included in "Interest expense" on our consolidated statement of operations and comprehensive income.

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(Unaudited)

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 the maintenance of a ratio of net income 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 and ceiling test impairments) to interest expense of at least 2.5 to 1.0. At June 30, 2017, we were in compliance with all of our debt covenants.

As of June 30, 2017, 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 (200 basis points at June 30, 2017).

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 when made; 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.

11. Commitments and Contingencies

We have various commitments for firm transportation, operating lease agreements for office space and other agreements. For further information, see Note 12, "Commitments and Contingencies," in our Annual Report on Form 10-K for the year ended December 31, 2016. There have been no material changes to the commitments disclosed at year-end 2016, other than noted below.

In March 2017, we signed an agreement for firm natural gas transportation capacity for production from the Anadarko Basin. The table below summarizes the value of the obligation by year as of June 30, 2017.



	Total		2017		2018		2019		2020		2021		Thereafter
	(In millions)
Firm transportation	$	186	$	—	$	9	$	18	$	18	$	18	$	123

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.

12. Stockholders' Equity Activity

During the first quarter of 2016, we issued 34.5 million additional shares of common stock through a public equity offering for net proceeds of approximately $776 million. A portion of the proceeds was used to acquire additional properties in the Anadarko Basin STACK play and to repay borrowings under our credit facility and money market lines of credit. The remainder was available for general corporate purposes.

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(Unaudited)

13. Earnings Per Share

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017		2016
	(In millions, except per share data)
Net income (loss)	$	98	$	(667	)	$	245	$	(1,291	)

Weighted-average shares (denominator):
Weighted-average shares — basic	199		198			199		188
Dilution effect of stock options and unvested restricted stock awards and restricted stock units outstanding at end of period	1		—			1		—
Weighted-average shares — diluted	200		198			200		188
Excluded due to anti-dilutive effect	1		2			1		2

Earnings (loss) per share:
Basic	$	0.49	$	(3.36	)	$	1.23	$	(6.87	)
Diluted	$	0.49	$	(3.36	)	$	1.22	$	(6.87	)

14. Stock-Based Compensation

Our stock-based compensation expense consisted of the following:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In millions)
Equity awards	$	13		$	9		$	29		$	18
Liability awards — cash-settled restricted stock units	—			7			2			10
Total stock-based compensation	13			16			31			28
Capitalized in oil and gas properties	(5		)	(5		)	(10		)	(9		)
Net stock-based compensation expense	$	8		$	11		$	21		$	19

As of June 30, 2017, we had approximately $59 million of total unrecognized stock-based compensation expense related to unvested stock-based compensation awards that vest within four years. On June 30, 2017, the last reported sales price of our common stock on the New York Stock Exchange was $28.46 per share.

During the first quarter of 2017, we changed our qualified retirement requirements for existing market-based restricted stock units and all subsequently issued equity and liability awards. An employee becomes eligible for qualified retirement based on a combination of years of service and age. Under the revised requirements, qualified retirement allows an employee to continue vesting between 50% and 100% of awards with no additional service requirement beyond a six-month notification period. This change resulted in the accelerated recognition of stock-based compensation expense for unvested market-based restricted stock units previously issued to eligible employees and all new equity and liability awards issued to eligible employees.

Equity Awards

Equity awards consist of service-based and market-based restricted stock awards and restricted stock units, stock options and stock purchase options under the Employee Stock Purchase Plan (ESPP). In May 2017, Newfield adopted the 2017 Omnibus Incentive Plan, as amended (2017 Plan), which replaced the 2011 Omnibus Stock Plan as the vehicle for granting

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(Unaudited)

equity-based compensation awards. At June 30, 2017, we had approximately (1) 10.4 million shares available for issuance under our 2017 Plan if all future awards are stock options, or (2) 6.2 million shares available for issuance under our 2017 Plan if all future awards are restricted stock awards or restricted stock units.

Restricted Stock and Restricted Stock Units. The following table provides information about restricted stock awards and restricted stock unit activity (excluding cash-settled restricted stock units, which are discussed below).



	Service-Based Shares		Weighted- Average Grant Date Fair Value per Share		Market-Based Shares				Weighted- Average Grant Date Fair Value per Share		Total Shares
	(In thousands, except per share data)
Non-vested shares outstanding at January 1, 2017	1,574		$	35.56	859				$	26.28	2,433
Granted	341		38.40		323		⁽¹	⁾	50.22		664
Forfeited	(40	)	22.79		(48	)			30.27		(88	)
Vested	(128	)	34.19		(386	)			22.85		(514	)
Non-vested shares outstanding at June 30, 2017	1,747		$	36.28	748				$	38.13	2,495

________


(1)	In February 2017, we granted approximately 323,000 restricted stock units, which based on achievement of certain criteria, could vest within a range of 0% to 200% of shares granted upon completion of the period ending December 31, 2019.

Employee Stock Purchase Plan. During the first six months of 2017, options to purchase approximately 61,000 shares of our common stock were issued under our ESPP. The fair value of each option was $10.73 per share. The fair value of the options granted was determined using the Black-Scholes option valuation method assuming no dividends, a risk-free interest rate of 0.61%, an expected life of six months and weighted-average volatility of 40.2%.

Stock Options. As of June 30, 2017, we had approximately 160,000 stock options outstanding and exercisable. These outstanding stock options expire in January 2018. No stock options have been granted since 2008, except for ESPP options as discussed above.

Liability Awards

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

Cash-Settled Restricted Stock Units. The value of the cash-settled restricted stock units, 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, 2017, we had a liability of $12 million related to these awards. 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, 2017	460
Granted	241
Forfeited	(22	)
Vested	(31	)
Non-vested units outstanding at June 30, 2017	648

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(Unaudited)


15.	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 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, 2016.

The following tables provide the geographic operating segment information for the three and six-month periods ended June 30, 2017 and 2016. Income tax allocations have been determined based on statutory rates in the applicable geographic segment. Our income tax allocation for our China operations is based on the combined statutory rates for China and the United States.



	Domestic		China		Total
	(In millions)
Three Months Ended June 30, 2017:
Oil, gas and NGL revenues	$	361	$	41	$	402
Operating expenses:
Lease operating	45		13		58
Transportation and processing	71		—		71
Production and other taxes	13		—		13
Depreciation, depletion and amortization	100		10		110
General and administrative	49		2		51
Allocated income tax (benefit)	30		10
Net income (loss) from oil and gas properties	$	53	$	6
Total operating expenses					303
Income (loss) from operations					99
Interest expense, net of interest income, capitalized interest and other					(20		)
Commodity derivative income (expense)					28
Income (loss) from operations before income taxes					$	107
Total assets	$	4,504	$	91	$	4,595
Additions to long-lived assets	$	334	$	1	$	335

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(Unaudited)



	Domestic			China			Total
	(In millions)
Three Months Ended June 30, 2016:
Oil, gas and NGL revenues	$	309		$	72		$	381
Operating expenses:
Lease operating	46			16			62
Transportation and processing	66			—			66
Production and other taxes	11			—			11
Depreciation, depletion and amortization	126			34			160
General and administrative	56			2			58
Ceiling test and other impairments	501			21			522
Allocated income tax (benefit)	(183		)	(1		)
Net income (loss) from oil and gas properties	$	(314	)	$	—
Total operating expenses							879
Income (loss) from operations							(498		)
Interest expense, net of interest income, capitalized interest and other							(27		)
Commodity derivative income (expense)							(133		)
Income (loss) from operations before income taxes							$	(658	)
Total assets	$	4,095		$	190		$	4,285
Additions to long-lived assets	$	699		$	—		$	699



	Domestic		China		Total
	(In millions)
Six Months Ended June 30, 2017:
Oil, gas and NGL revenues	$	744	$	75	$	819
Operating expenses:
Lease operating	93		21		114
Transportation and processing	143		—		143
Production and other taxes	27		—		27
Depreciation, depletion and amortization	196		20		216
General and administrative	95		3		98
Other	1		—		1
Allocated income tax (benefit)	69		19
Net income (loss) from oil and gas properties	$	120	$	12
Total operating expenses					599
Income (loss) from operations					220
Interest expense, net of interest income, capitalized interest and other					(40		)
Commodity derivative income (expense)					81
Income (loss) from operations before income taxes					$	261
Total assets	$	4,504	$	91	$	4,595
Additions to long-lived assets	$	591	$	1	$	592

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(Unaudited)



	Domestic			China			Total
	(In millions)
Six Months Ended June 30, 2016:
Oil, gas and NGL revenues	$	544		$	121		$	665
Operating expenses:
Lease operating	93			30			123
Transportation and processing	129			—			129
Production and other taxes	21			—			21
Depreciation, depletion and amortization	259			78			337
General and administrative	99			3			102
Ceiling test and other impairments	962			66			1,028
Other	1			—			1
Allocated income tax (benefit)	(377		)	(34		)
Net income (loss) from oil and gas properties	$	(643	)	$	(22	)
Total operating expenses							1,741
Income (loss) from operations							(1,076		)
Interest expense, net of interest income, capitalized interest and other							(58		)
Commodity derivative income (expense)							(150		)
Income (loss) from operations before income taxes							$	(1,284	)
Total assets	$	4,095		$	190		$	4,285
Additions to long-lived assets	$	960		$	—		$	960

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,
	2017			2016
	(In millions)
Non-cash investing and financing activities excluded from the statement of cash flows:
(Increase) decrease in receivables for property sales	$	—		$	6
(Increase) decrease in accrued capital expenditures	(57		)	33
(Increase) decrease in asset retirement costs	2			(8		)

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

Overview

We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. Our U.S. operations are onshore and focus primarily on large scale, liquids-rich resource plays. Our principal areas of operation are the Anadarko and Arkoma basins of Oklahoma, the Williston Basin of North Dakota and the Uinta Basin of Utah. In addition, we have oil producing assets offshore China.

Significant second quarter 2017 highlights include:


•	Anadarko Basin production was 8.0 MMBOE in the second quarter of 2017, up 6% over the same period of 2016, and 2% over the first quarter of 2017. Anadarko Basin crude oil production increased 4% over the second quarter of 2016.


•	We divested our non-operated interest in the Bohai Bay field in China for approximately $32 million.

Results of Operations

Domestic Revenues and Production. Revenues during the second quarter of 2017 were $52 million higher than the same period of 2016, primarily attributable to increases in average realized crude oil, natural gas and NGL prices of 11%, 63% and 28%, respectively. Our domestic production for the second quarter of 2017 declined 6% as compared to the same quarter of 2016 primarily due to the sale of the Texas assets in the third quarter of 2016 and natural declines resulting from reduced investment in areas outside of the Anadarko Basin. Production from the Anadarko Basin increased 6% as compared to the second quarter of 2016.

Revenues during the six months ended June 30, 2017 were $200 million higher than the same period of 2016. The higher revenues were attributable to increases in average realized crude oil, natural gas and NGL prices of 39%, 61% and 51%, respectively, compared to the six months ended June 30, 2016. Our domestic production decreased 7% compared to the six months ended June 30, 2016 primarily due to the sale of the Texas assets in the third quarter of 2016 and natural declines resulting from reduced investment in areas outside of the Anadarko Basin.

China Revenues and Production/Liftings. Revenues during the second quarter of 2017 were $31 million lower than the same quarter of 2016, primarily due to a 49% decrease in lifting volumes, partially offset by a 12% increase in average crude oil prices. The lower lifting volumes resulted from natural production declines in the Pearl field, combined with a decrease in the net entitlement percentage in accordance with the terms in the production sharing contract.

Revenues during the six months ended June 30, 2017 were $46 million lower than the same period of 2016, primarily due to a 55% decrease in lifting volumes partially offset by a 38% increase in average crude oil prices. China liftings for the first six months of 2017 were 1,799 MBbls lower than the comparable period of 2016 primarily due to natural production declines in the Pearl field, combined with a decrease in the net entitlement percentage in accordance with the terms in the production sharing contract.

The divestiture of our Bohai Bay interest did not materially impact our results of operations for the three or six-month periods ended June 30, 2017 as compared to the same periods of 2016.

The following table reflects our production/liftings and average realized commodity prices.



	Three Months Ended June 30,				Percentage Increase (Decrease)		Six Months Ended June 30,				Percentage Increase (Decrease)
	2017		2016		Percentage Increase (Decrease)		2017		2016		Percentage Increase (Decrease)
Production/Liftings:
Domestic:⁽¹⁾
Crude oil and condensate (MBbls)	5,132		5,250		(2	)%	10,120		10,585		(4	)%
Natural gas (Bcf)	30.0		32.4		(8	)%	59.4		65.3		(9	)%
NGLs (MBbls)	2,491		2,792		(11	)%	4,945		5,268		(6	)%
Total (MBOE)	12,622		13,454		(6	)%	24,960		26,742		(7	)%
China:⁽²⁾
Crude oil and condensate (MBbls)	830		1,629		(49	)%	1,473		3,272		(55	)%
Total:
Crude oil and condensate (MBbls)	5,962		6,879		(13	)%	11,593		13,857		(16	)%
Natural gas (Bcf)	30.0		32.4		(8	)%	59.4		65.3		(9	)%
NGLs (MBbls)	2,491		2,792		(11	)%	4,945		5,268		(6	)%
Total (MBOE)	13,452		15,083		(11	)%	26,433		30,014		(12	)%
Average Realized Prices:
Domestic:
Crude oil and condensate (per Bbl)	$	42.52	$	38.17	11	%	$	44.22	$	31.89	39	%
Natural gas (per Mcf)	2.75		1.69		63	%	2.84		1.76		61	%
NGLs (per Bbl)	24.54		19.23		28	%	25.77		17.12		51	%
Crude oil equivalent (per BOE)	28.69		22.96		25	%	29.83		20.35		47	%
China:
Crude oil and condensate (per Bbl)	$	49.01	$	43.95	12	%	$	50.84	$	36.89	38	%
Total:
Crude oil and condensate (per Bbl)	$	43.42	$	39.54	10	%	$	45.06	$	33.07	36	%
Natural gas (per Mcf)	2.75		1.69		63	%	2.84		1.76		61	%
NGLs (per Bbl)	24.54		19.23		28	%	25.77		17.12		51	%
Crude oil equivalent (per BOE)	29.95		25.23		19	%	31.00		22.15		40	%

________________


(1)	Excludes natural gas produced and consumed in operations of 1.2 Bcf and 1.3 Bcf during the three months ended June 30, 2017 and 2016, respectively, and 2.1 Bcf and 2.8 Bcf during the six months ended June 30, 2017 and 2016, respectively.


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

Operating Expenses.

Three months ended June 30, 2017 compared to June 30, 2016

The following table presents information about our operating expenses.



	Unit-of-Production						Total Amount
	Three Months Ended June 30,				Percentage Increase (Decrease)		Three Months Ended June 30,				Percentage Increase (Decrease)
	2017		2016		Percentage Increase (Decrease)		2017		2016		Percentage Increase (Decrease)
	(Per BOE)						(In millions)
Domestic:
Lease operating	$	3.55	$	3.42	4	%	$	45	$	46	(4	)%
Transportation and processing	5.67		4.86		17	%	71		66		9	%
Production and other taxes	1.03		0.82		26	%	13		11		17	%
Depreciation, depletion and amortization	7.92		9.35		(15	)%	100		126		(21	)%
General and administrative	3.90		4.21		(7	)%	49		56		(13	)%
Ceiling test and other impairments	—		37.28		(100	)%	—		501		(100	)%
Total operating expenses	22.07		59.94		(63	)%	278		806		(65	)%
China:
Lease operating	$	15.31	$	9.57	60	%	$	13	$	16	(18	)%
Depreciation, depletion and amortization	13.06		20.56		(36	)%	10		34		(68	)%
General and administrative	2.13		0.97		>100%		2		2		12	%
Ceiling test impairment	—		12.79		(100	)%	—		21		(100	)%
Total operating expenses	30.50		43.89		(31	)%	25		73		(65	)%
Total:
Lease operating	$	4.27	$	4.08	5	%	$	58	$	62	(7	)%
Transportation and processing	5.32		4.34		23	%	71		66		9	%
Production and other taxes	0.97		0.74		31	%	13		11		16	%
Depreciation, depletion and amortization	8.24		10.56		(22	)%	110		160		(30	)%
General and administrative	3.79		3.86		(2	)%	51		58		(12	)%
Ceiling test and other impairments	—		34.63		(100	)%	—		522		(100	)%
Total operating expenses	22.59		58.21		(61	)%	303		879		(65	)%

Domestic Operations. The primary components within our operating expenses are as follows:


•	Lease operating expense per BOE increased 4% primarily due to higher nonrecurring well servicing costs in the Williston Basin. Total lease operating expense decreased due to the sale of our Texas assets in the third quarter of 2016.


•	Transportation and processing expense per BOE increased 17% primarily due to increased oil deficiency fees of $4 million in the Uinta Basin, coupled with lower production volumes.


•	Production and other taxes per BOE increased 26% primarily due to higher commodity prices in the second quarter of 2017, as compared to the same period in 2016.


•	Depreciation, depletion and amortization (DD&A) per BOE decreased 15% primarily due to the impact of ceiling test impairments during 2015 and the first half of 2016.


•	General and administrative expenses decreased 13% during the second quarter of 2017 compared to the second quarter of 2016. Restructuring related costs were $12 million during the three months ended June 30, 2016, as compared to no restructuring related costs during the same period of 2017. This decrease was partially offset by accelerated

recognition of stock-based compensation expense and increased post-retirement expense resulting from a change in our qualified retirement plan.


•	No ceiling test impairment was required during the second quarter of 2017. During the second quarter of 2016, we recorded a ceiling test impairment of $501 million due to a net decrease in the discounted value of our proved reserves. The decrease primarily resulted from a 7% decrease in both crude oil and natural gas SEC pricing during the second quarter of 2016.

China Operations. The primary components within our operating expenses are as follows:


•	Lease operating expense per BOE increased 60% primarily due to lower lifting volumes and higher production handling fees per BOE, which increase as oil prices increase. Total lease operating expense decreased $3 million due to lower lifting volumes.


•	DD&A expense per BOE decreased 36% primarily due to a reduction of our DD&A rate as a result of the ceiling test impairments during 2015 and the first half of 2016.


•	No ceiling test impairment was required during the second quarter of 2017. During the second quarter of 2016, we recorded a ceiling test impairment of $21 million due to a net decrease in the discounted value of our proved reserves. The decrease primarily resulted from a 7% decrease in crude oil SEC pricing during the second quarter of 2016.

Six months ended June 30, 2017 compared to June 30, 2016

The following table presents information about our operating expenses.



	Unit-of-Production						Total Amount
	Six Months Ended June 30,				Percentage Increase (Decrease)		Six Months Ended June 30,				Percentage Increase (Decrease)
	2017		2016		Percentage Increase (Decrease)		2017		2016		Percentage Increase (Decrease)
	(Per BOE)						(In millions)
Domestic:
Lease operating	$	3.73	$	3.47	7	%	$	93	$	93	—	%
Transportation and processing	5.74		4.82		19	%	143		129		11	%
Production and other taxes	1.06		0.77		38	%	27		21		30	%
Depreciation, depletion and amortization	7.84		9.70		(19	)%	196		259		(25	)%
General and administrative	3.80		3.71		2	%	95		99		(4	)%
Ceiling test and other impairments	—		35.98		(100	)%	—		962		(100	)%
Other	0.06		0.02		>100%		1		1		>100%
Total operating expenses	22.23		58.47		(62	)%	555		1,564		(65	)%
China:
Lease operating	$	14.17	$	9.24	53	%	$	21	$	30	(31	)%
Depreciation, depletion and amortization	13.84		23.67		(42	)%	20		78		(74	)%
General and administrative	2.10		0.91		>100%		3		3		4	%
Ceiling test impairment	—		20.19		(100	)%	—		66		(100	)%
Total operating expenses	30.11		54.01		(44	)%	44		177		(75	)%
Total:
Lease operating	$	4.29	$	4.08	5	%	$	114	$	123	(7	)%
Transportation and processing	5.42		4.29		26	%	143		129		11	%
Production and other taxes	1.02		0.70		46	%	27		21		29	%
Depreciation, depletion and amortization	8.18		11.22		(27	)%	216		337		(36	)%
General and administrative	3.71		3.40		9	%	98		102		(4	)%
Ceiling test and other impairments	—		34.26		(100	)%	—		1,028		(100	)%
Other	0.05		0.03		67	%	1		1		81	%
Total operating expenses	22.67		57.98		(61	)%	599		1,741		(66	)%

Domestic Operations. The primary components within our operating expenses are as follows:

•

Lease operating expense per BOE increased 7% primarily due to higher nonrecurring well servicing costs in the Uinta and Williston basins during the first six months of 2017, as well as higher costs associated with winter weather in the Williston Basin. Additionally, we incurred costs to protect our wells against offset hydraulic fracturing operations by other operators in the Williston Basin. Total lease operating expense was flat period over period due to the higher costs, as discussed above, offset by the reduction of costs associated with the sale of our Texas assets in the third quarter of 2016.


•	Transportation and processing expense per BOE increased 19% due to increased oil deficiency fees of $13 million in the Uinta Basin and higher utilization of oil pipelines in the STACK play, which allows us to transport oil to more favorable markets and thus receive a higher sales price.


•	Production and other taxes per BOE increased 38% primarily due to higher commodity prices in the first six months of 2017, as compared to the same period in 2016.


•	DD&A per BOE decreased 19% primarily due to the impact of ceiling test impairments during 2015 and the first half of 2016.

•

General and administrative expenses decreased 4% during the first six months of 2017 compared to the first six months of 2016. Restructuring related costs were $12 million during the six months ended June 30, 2016, as compared to $1 million during the same period of 2017. This decrease was partially offset by accelerated recognition of stock-based compensation expense and increased post-retirement expense resulting from a change in our qualified retirement plan.


•	No ceiling test impairment was required during the first six months of 2017. During the first six months of 2016, we recorded ceiling test impairments of $962 million due to a net decrease in the discounted value of our proved reserves. The decrease primarily resulted from a 14% decrease in both crude oil and natural gas SEC pricing during the first six months of 2016.

China Operations. The primary components within our operating expenses are as follows:


•	Lease operating expense per BOE increased 53% primarily due to lower lifting volumes and higher production handling fees per BOE, which increase as oil prices increase. Total lease operating expense decreased $9 million due to lower lifting volumes.


•	DD&A expense per BOE decreased 42% primarily due to a reduction of our DD&A rate as a result of the ceiling test impairments during 2015 and the first half of 2016.


•	No ceiling test impairment was required during the first six months of 2017. During the first six months of 2016, we recorded ceiling test impairments of $66 million due to a net decrease in the discounted value of our proved reserves. The decrease primarily resulted from a 14% decrease in crude oil SEC pricing during the first six months of 2016.

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,
	2017			2016			2017			2016
	(In millions)
Gross interest expense:
Credit arrangements	$	2		$	3		$	5		$	9
Senior notes	35			35			70			70
Total gross interest expense	37			38			75			79
Capitalized interest	(15		)	(11		)	(31		)	(20		)
Net interest expense	$	22		$	27		$	44		$	59

Gross interest expense decreased for the six months ended June 30, 2017, as compared to the six months ended June 30, 2016, due to $3 million of financing costs related to amending our revolving credit facility in March 2016.

Capitalized interest increased for the three and six months ended June 30, 2017, as compared to the three and six months ended June 30, 2016, due to an increase in the average amount of unproved oil and gas properties resulting from the acquisition of unproved properties on June 30, 2016.

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 contracts during these periods. The amount of unrealized gain (loss) on derivatives is the result of the change in the total fair value of our derivative positions from the prior period.

Three months ended June 30, 2017

The $28 million gain recognized in “Commodity derivative income (expense)” in our consolidated statement of operations and comprehensive income is comprised of a $15 million realized gain and a $13 million unrealized gain. The gains are primarily attributable to the decrease in commodity prices between periods. Forward curve prices decreased 10% for oil and 3% for natural gas for the three months ended June 30, 2017. The oil average forward curve price at March 31, 2017 was $51.91 compared to $46.53 at June 30, 2017. The natural gas average forward curve price at March 31, 2017 was $3.13 compared to $3.02 at June 30, 2017. The components of the change in the fair value of our net derivative asset (liability) follow:



	Positions Settled in the Three Months Ended June 30, 2017			Positions Settling After June 30, 2017			Total
	(In millions)
Net derivative asset (liability) at March 31, 2017	$	13		$	(5	)	$	8
Change in fair value of settled positions	2			—			2
Realized settlements	(15		)	—			(15		)
Change in fair value of outstanding positions	—			26			26
Total unrealized gain (loss)	(13		)	26			13
Net derivative asset (liability) at June 30, 2017	$	—		$	21		$	21

Six months ended June 30, 2017

The $81 million gain recognized in “Commodity derivative income (expense)” in our consolidated statement of operations and comprehensive income is comprised of a $35 million realized gain and a $46 million unrealized gain. The gains are primarily attributable to the decrease in commodity prices between periods. Forward curve prices decreased 18% for oil and 8% for natural gas for the six months ended June 30, 2017. The oil average forward curve price at December 31, 2016 was $57.01 compared to $46.53 at June 30, 2017. The natural gas average forward curve price at December 31, 2016 was $3.28 compared to $3.02 at June 30, 2017. The components of the change in the fair value of our net derivative asset (liability) follow:



	Positions Settled in the Six Months Ended June 30, 2017			Positions Settling After June 30, 2017			Total
	(In millions)
Net derivative asset (liability) at December 31, 2016	$	8		$	(33	)	$	(25	)
Change in fair value of settled positions	27			—			27
Realized settlements	(35		)	—			(35		)
Change in fair value of outstanding positions	—			54			54
Total unrealized gain (loss)	(8		)	54			46
Net derivative asset (liability) at June 30, 2017	$	—		$	21		$	21

Three months ended June 30, 2016

The $133 million loss recognized in “Commodity derivative income (expense)” in our consolidated statement of operations and comprehensive income related to our derivative financial instruments is comprised of a $64 million realized gain and a $197 million unrealized loss. The unrealized loss is primarily attributable to an increase in commodity prices between periods. Forward curve prices increased 14% for oil and 19% for natural gas for the three months ended June 30, 2016. The oil average forward curve price at March 31, 2016 was $44.98 compared to $51.25 at June 30, 2016. The natural gas average forward curve price at March 31, 2016 was $2.63 compared to $3.12 at June 30, 2016. The components of the change in the fair value of our net derivative asset (liability) follow:



	Positions Settled in the Three Months Ended June 30, 2016			Positions Settling After June 30, 2016			Total
	(In millions)
Net derivative asset (liability) at March 31, 2016	$	70		$	198		$	268
Change in fair value of settled positions	(6		)	—			(6		)
Realized settlements	(64		)	—			(64		)
Change in fair value of outstanding positions	—			(127		)	(127		)
Total unrealized gain (loss)	(70		)	(127		)	(197		)
Net derivative asset (liability) at June 30, 2016	$	—		$	71		$	71

Six months ended June 30, 2016

The $150 million loss recognized in “Commodity derivative income (expense)” in our consolidated statement of operations and comprehensive income related to our derivative financial instruments is comprised of a $146 million realized gain and a $296 million unrealized loss. The unrealized loss is primarily attributable to the increase in commodity prices between periods. Forward curve prices increased 14% for oil and 16% for natural gas for the six months ended June 30, 2016. The oil average forward curve price at December 31, 2015 was $44.91 compared to $51.25 at June 30, 2016. The natural gas average forward curve price at December 31, 2015 was $2.58 compared to $2.99 at June 30, 2016. The components of the change in the fair value of our net derivative asset (liability) follow:



	Positions Settled in the Six Months Ended June 30, 2016			Positions Settling After June 30, 2016			Total
	(In millions)
Net derivative asset (liability) at December 31, 2015	$	150		$	217		$	367
Change in fair value of settled positions	(4		)	—			(4		)
Realized settlements	(146		)	—			(146		)
Change in fair value of outstanding positions	—			(146		)	(146		)
Total unrealized gain (loss)	(150		)	(146		)	(296		)
Net derivative asset (liability) at June 30, 2016	$	—		$	71		$	71

Taxes. Our effective tax rate differs from the federal statutory rate of 35% due to the change in valuation allowances, non-deductible expenses, state income taxes, the differences between international and U.S. federal statutory rates and the impact of taxation of our China earnings in both the U.S. and China. Our future effective tax rates may also be impacted by additional ceiling test impairments or other items which generate deferred tax assets, deferred tax asset valuation allowances, and/or reversal of such valuation allowances. Due to the ceiling test impairments of our oil and gas properties in 2015, we moved from a deferred tax liability position to a deferred tax asset position in most taxing jurisdictions. We have recorded a full valuation allowance against these deferred tax assets.

The effective tax rates for the three months ended June 30, 2017 and 2016 were 8.8% and (1.4)%, respectively. The effective tax rate in the second quarter of 2017 was driven by Oklahoma state taxes of $7 million, all of which were deferred, and China in country cash taxes of $6 million, partially offset by the monetization of U.S. federal alternative minimum tax (AMT) credits.

The effective tax rates for the six months ended June 30, 2017 and 2016 were 6.3% and (0.6)%, respectively. The effective tax rate for the first six months of 2017 was driven by Oklahoma state taxes of $16 million, all of which were deferred, and China in country cash taxes of $8 million, partially offset by the monetization of U.S. federal AMT credits.

See Note 8, "Income Taxes," to our consolidated financial statements earlier in this report for additional disclosures.

Liquidity and Capital Resources

We establish a capital budget at the beginning of each calendar year and review it during the course of the year. Our capital budgets (excluding acquisitions) are based upon our estimate of internally generated sources of cash, as well as cash on hand and the available borrowing capacity of our revolving credit facility and money market lines of credit.

We expect our 2017 capital budget will be financed through our cash flows from operations and cash on hand. However, given the volatility and uncertainty of commodity prices, we may borrow under our credit facility, sell non-strategic assets or access the public debt and equity markets. Our 2017 capital budget, excluding estimated capitalized interest and direct internal costs of approximately $125 million, is expected to be approximately $1.1 billion.

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 is 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 2017 operations and continue to meet our other obligations. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Credit Arrangements and Other Financing Activities. We have a revolving credit facility that matures in June 2020 and provides borrowing capacity of $1.8 billion. Subject to compliance with restrictive covenants in our credit facility, our available borrowing capacity under our money market lines of credit was $125 million at June 30, 2017.

At June 30, 2017, we had no borrowings under our money market lines of credit or revolving credit facility and had no letters of credit outstanding. 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, see Note 10, "Debt," to our consolidated financial statements appearing earlier in this report.

As of July 31, 2017, we had no borrowings under our money market lines of credit or revolving credit facility and had no letters of credit outstanding.

Working Capital. Our working capital balance fluctuates primarily 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. At June 30, 2017, we had positive working capital of $205 million compared to positive working capital of $265 million at December 31, 2016.

Cash Flows from Operations. Our primary source of capital and liquidity is cash flows provided by operations, which are primarily affected by the sale of oil, natural gas and NGLs, as well as commodity prices.

Our net cash flows from operations were $467 million for the six months ended June 30, 2017, which increased from $378 million for the same period in 2016. The primary drivers of higher operating cash flows were higher revenues as a result of higher commodity prices, partially offset by lower production volumes and lower realized derivative gains.

Cash Flows from Investing Activities. Net cash used in investing activities for the six months ended June 30, 2017 was $493 million compared to $945 million for the same period in 2016.

During the first six months of 2017, we:


•	spent $507 million for capital additions to oil and gas properties, an increase of $36 million compared to the same period of 2016 due to the timing of capital project activities; and


•	divested our non-operated interest in the Bohai Bay field in China for approximately $32 million, including customary post-close adjustments.

Cash Flows from Financing Activities. Net cash used in financing activities for the six months ended June 30, 2017 was $7 million compared to net cash provided by financing activities of $727 million for the same period in 2016. During the six months ended June 30, 2016, we issued 34.5 million additional shares of common stock through a public equity offering for net proceeds of approximately $776 million. No equity issuances occurred during the six months ended June 30, 2017.

Contractual Obligations

We have various contractual obligations in the normal course of our operations. For further information, 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, 2016. There have been no material changes to the disclosure since year-end 2016, other than noted below.

In March 2017, we signed an agreement for firm natural gas transportation capacity for production from the Anadarko Basin. See Note 11, "Commitments and Contingencies," to our consolidated financial statements appearing earlier in this report.

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 natural gas production. As of June 30, 2017, 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 4, "Derivative Financial Instruments," and Note 5, "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 contracts as of June 30, 2017.

Between July 1, 2017 and July 31, 2017, we entered into additional crude oil derivative contracts. A listing of all our crude oil derivative contracts as of July 31, 2017 follows:



		NYMEX Contract Price Per Bbl
								Collars
Period and Type of Instrument	Volume in MBbls	Swaps (Weighted Average)		Purchased Calls (Weighted Average)		Sold Puts (Weighted Average)		Floors (Weighted Average)		Ceilings (Weighted Average)

2017:
Fixed-price swaps	4,352	$	46.68	$	—	$	—	$	—	$	—
Fixed-price swaps with sold puts:	2,208
Fixed-price swaps		87.95		—		—		—		—
Sold puts		—		—		73.08		—		—
Purchased calls	2,208	—		73.08		—		—		—
2018:
Collars with sold puts:	4,380
Collars		—		—		—		46.00		56.00
Sold puts		—		—		38.00		—		—

Accounting for Derivative Activities. As our derivative contracts are not designated as hedges, 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, 2017, we had net derivative assets of $21 million, of which 56%, based on total contracted volumes, was measured based upon a modified Black-Scholes valuation model and, as such, were classified as a Level 3 fair value measurement. The model 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, 2017. We use counterparty rate of default 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, 2016 and Note 4, "Derivative Financial Instruments," and Note 5, "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

See Note 1, "Organization and Summary of Significant Accounting Policies," to our consolidated financial statements in Item 1 of this report for a discussion of 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, estimates of reserves, projected production, estimates of operating costs, acquisitions and divestitures, planned

exploratory or developed drilling, projected cash flows and liquidity, business strategy 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," "guidance," "potential," "forecast," "outlook," "could," "budget," "objectives," "strategy" 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 but not limited to, the following:


•	oil, natural gas and natural gas liquids prices;


•	actions of the Organization of the Petroleum Exporting Countries, its members and other state-controlled oil companies relating to oil price and production controls;


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


•	legislation or regulatory initiatives intended to address seismic activity;


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


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


•	ability to develop existing reserves or acquire new reserves;


•	the availability and volatility of the securities, capital or credit markets and the cost of capital;


•	maintaining sufficient liquidity to fund our operations and business strategies;


•	the accuracy of and fluctuations in our reserves estimates due to sustained low commodity prices, incorrect assumptions and other causes;


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


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


•	the impact of regulatory approvals;


•	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, including the creditworthiness of such counterparties;


•	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, instrument terms 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 oilfield services;


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


•	our ability to monetize non-strategic assets, repay or refinance our existing indebtedness and the impact of changes in our investment ratings;


•	labor conditions;


•	weather conditions;


•	competitive conditions;


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


•	electronic, cyber or physical security breaches;


•	changes in tax rates;


•	inflation rates;


•	the effect of worldwide energy conservation measures;


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


•	our ability to successfully execute our business and financial plans and strategies;


•	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 2016 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.

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 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, 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, 2017, 10 of our 15 counterparties accounted for approximately 84% of our contracted volumes with the largest counterparty accounting for approximately 13%.

As of June 30, 2017, 5,336 MBbls of our expected 2017 crude oil production were protected against price volatility using fixed-price swaps, over 41% of which have associated sold puts. The sold puts limit our downward price protection below the weighted average of our sold puts of $73.08 per barrel. If the market price remains below $73.08 per barrel, we receive the market price for our associated production plus the difference between our sold puts and the associated floors or fixed-price

swaps, which averages $14.86 per barrel. For 2,208 MBbls of our 2017 volumes, we have locked in an average minimum premium of $12.83 over the market price using purchased calls. The weighted average strike price of the purchased calls approximates the weighted average strike price of the sold puts, thereby effectively locking in the spread.

For further discussion of our derivative activities, see the discussion and tables in Note 4, "Derivative Financial Instruments," and Note 5, "Fair Value Measurements," to our consolidated financial statements appearing earlier in this report. For further discussion of the types of derivative positions, refer to Note 4, "Derivative Financial Instruments," within Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2016.

Interest Rates

We consider our interest rate exposure to be minimal as 100% of our debt obligations were at fixed rates at June 30, 2017. A 10% increase in LIBOR would not impact our interest costs on debt outstanding at June 30, 2017, but would decrease the fair value of our outstanding debt, as well as increase interest costs associated with future debt issuances or borrowings under our revolving credit facility and money market lines of credit.

Foreign Currency Exchange Rates

The functional currency for our China operations is the U.S. dollar. To the extent that business transactions in a foreign country are not denominated in the U.S. dollar, 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, 2017.

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). Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2017.

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 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 1. Legal Proceedings

In August 2016, the North Dakota Department of Health (NDDH) announced its intent to resolve alleged systemic violations of the North Dakota air pollution control laws, N.D.C.C. ch. 23-25, N.D. Admin. Code art. 33-15, the North Dakota State Implementation Plan, and those provisions of the federal Clean Air Act and its body of implementing regulations for which the NDDH has been delegated authority by the U.S. Environmental Protection Agency, at certain facilities in North Dakota, including facilities owned and operated by the Company, through a voluntary Consent Decree process. The Company entered into a Consent Decree in February 2017 that includes a payment of civil penalties, imposes additional facility design review and, potentially, air permitting obligations, as well as enhanced maintenance and inspection program obligations, but that does not contain any admission of liability. The Consent Decree was approved by the North Dakota District Court in Burleigh County on March 14, 2017. The Consent Decree is subject to termination upon consent from the NDDH that all obligations of the Consent Decree have been completed or after two years, the company may petition the court for termination. We do not anticipate that these penalties will exceed $1 million.

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 federal government fines or penalties are in fact imposed that are greater than $100,000, then we will disclose such fact in our subsequent filings. For a further discussion of our legal proceedings, see Note 11, "Commitments and Contingencies," to our consolidated financial statements appearing earlier in this report.

Item 1A. Risk Factors

There have been no material changes with respect to the risk factors previously reported in our Annual Report on Form 10-K for the year ended December 31, 2016.

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, 2017.



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, 2017	163,838	$	35.94	—	—
May 1 — May 31, 2017	10,496	34.93		—	—
June 1 — June 30, 2017	2,353	32.63		—	—
Total	176,687	$	35.84	—	—

_______


(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 22, 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 Annual Report on Form 10-K for the year ended December 31, 2016 (File No. 1-12534))

†10.1		Newfield Exploration Company 2017 Omnibus Incentive Plan (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8, filed with the SEC on May 16, 2017 (File No. 333-218027))

†10.2		Newfield Exploration Company Amended and Restated 2010 Employee Stock Purchase Plan (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8, filed with the SEC on May 16, 2017 (File No. 333-218026))

†*10.3		Form of Restricted Stock Agreement for Non-Employee Directors under 2017 Omnibus Incentive Plan

†*10.4		Form of Restricted Stock Unit Award Agreement for Non-Employee Directors under 2017 Omnibus Incentive Plan and Non-Employee Director Deferred Compensation Plan

†*10.5		Form of Notice of Restricted Stock Unit Award and Attached Terms and Conditions (New Hire and Promotions) under 2017 Omnibus Incentive Plan

*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.
†	Identifies management contracts and compensatory plans or arrangements.

SIGNATURE

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



	NEWFIELD EXPLORATION COMPANY

Date: August 1, 2017	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 22, 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 Annual Report on Form 10-K for the year ended December 31, 2016 (File No. 1-12534))

†10.1		Newfield Exploration Company 2017 Omnibus Incentive Plan (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8, filed with the SEC on May 16, 2017 (File No. 333-218027))

†10.2		Newfield Exploration Company Amended and Restated 2010 Employee Stock Purchase Plan (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8, filed with the SEC on May 16, 2017 (File No. 333-218026))

†*10.3		Form of Restricted Stock Agreement for Non-Employee Directors under 2017 Omnibus Incentive Plan

†*10.4		Form of Restricted Stock Unit Award Agreement for Non-Employee Directors under 2017 Omnibus Incentive Plan and Non-Employee Director Deferred Compensation Plan

†*10.5		Form of Notice of Restricted Stock Unit Award and Attached Terms and Conditions (New Hire and Promotions) under 2017 Omnibus Incentive Plan

*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.
†	Identifies management contracts and compensatory plans or arrangements.