WPX Energy (WPX) 10-Q 2015 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

R QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2015

OR

¨ 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 1-35322

WPX Energy, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	45-1836028
(State or Other Jurisdiction of Incorporation or Organization)	(IRS Employer Identification No.)
3500 One Williams Center, Tulsa, Oklahoma	74172-0172
(Address of Principal Executive Offices)	(Zip Code)

855-979-2012

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, $0.01 par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

 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 RNo  ¨

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 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  R    No  ¨

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

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

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

The number of shares outstanding of the registrant’s common stock at May 5, 2015 were 204,742,653.

WPX Energy, Inc.

Index

			Page
Part I.	Financial Information
	Item 1.	Financial Statements (Unaudited)
		Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014	4
		Consolidated Statements of Operations for the three months ended March 31, 2015 and 2014	5
		Consolidated Statements of Changes in Equity for the three months ended March 31, 2015	6
		Consolidated Statements of Cash Flows for the three months ended March 31, 2015 and 2014	7
		Notes to Consolidated Financial Statements	8
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
	Item 4.	Controls and Procedures	31
Part II.	Other Information
	Item 1.	Legal Proceedings	32
	Item 1A.	Risk Factors	32
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
	Item 3.	Defaults Upon Senior Securities	32
	Item 4.	Mine Safety Disclosures	32
	Item 5.	Other Information	32
	Item 6.	Exhibits	33

Certain matters contained in this report include forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

• amounts and nature of future capital expenditures;

• expansion and growth of our business and operations;

• financial condition and liquidity;

• business strategy;

• estimates of proved gas and oil reserves;

• reserve potential;

• development drilling potential;

• cash flow from operations or results of operations;

• acquisitions or divestitures;

• seasonality of our business; and

2

• natural gas, NGLs and crude oil prices and demand.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

• availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future natural gas and oil reserves), market demand, volatility of prices and the availability and cost of capital;

• inflation, interest rates, fluctuation in foreign exchange and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);

• the strength and financial resources of our competitors;

• development of alternative energy sources;

• the impact of operational and development hazards;

• costs of, changes in, or the results of laws, government regulations (including climate change regulation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation and rate proceedings;

• changes in maintenance and construction costs;

• changes in the current geopolitical situation;

• our exposure to the credit risk of our customers;

• risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;

• risks associated with future weather conditions;

• acts of terrorism;

• other factors described in "Management's Discussion and Analysis of Financial Condition and Results of Operations"; and

• additional risks described in our filings with the Securities and Exchange Commission ("SEC").

All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements set forth above. Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. Forward-looking statements speak only as of the date they are made. We disclaim any obligation to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, except to the extent required by applicable laws. If we update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2014.

3

WPX Energy, Inc.

Consolidated Balance Sheets

(Unaudited)

	March 31, 2015			December 31, 2014
	(Millions)
Assets
Current assets:
Cash and cash equivalents	$	82		$	41
Accounts receivable, net of allowance of $6 million as of March 31, 2015 and December 31, 2014	347			459
Derivative assets	431			498
Inventories	49			45
Margin deposits	18			27
Assets classified as held for sale	132			773
Other	28			26
Total current assets	1,087			1,869
Properties and equipment (successful efforts method of accounting)	12,041			11,753
Less—accumulated depreciation, depletion and amortization	(5,130		)	(4,911		)
Properties and equipment, net	6,911			6,842
Derivative assets	58			38
Other noncurrent assets	47			49
Total assets	$	8,103		$	8,798
Liabilities and Equity
Current liabilities:
Accounts payable	$	464		$	712
Accrued and other current liabilities	139			177
Liabilities associated with assets held for sale	47			132
Deferred income taxes	164			151
Derivative liabilities	22			37
Total current liabilities	836			1,209
Deferred income taxes	614			621
Long-term debt	2,000			2,280
Derivative liabilities	2			5
Asset retirement obligations	203			198
Other noncurrent liabilities	59			57
Contingent liabilities and commitments (Note 8)
Equity:
Stockholders’ equity:
Preferred stock (100 million shares authorized at $0.01 par value; no shares issued)	—			—
Common stock (2 billion shares authorized at $0.01 par value; 204.8 million shares issued at March 31, 2015 and 203.7 million shares issued at December 31, 2014)	2			2
Additional paid-in-capital	5,564			5,562
Accumulated deficit	(1,177		)	(1,244		)
Accumulated other comprehensive income (loss)	—			(1		)
Total stockholders’ equity	4,389			4,319
Noncontrolling interests in consolidated subsidiaries	—			109
Total equity	4,389			4,428
Total liabilities and equity	$	8,103		$	8,798

See accompanying notes.

4

WPX Energy, Inc.

Consolidated Statements of Operations

(Unaudited)

	Three months ended March 31,
	2015			2014
Revenues:	(Millions, except per-share amounts)
Product revenues:
Natural gas sales	$	167		$	317
Oil and condensate sales	117			149
Natural gas liquid sales	23			61
Total product revenues	307			527
Gas management	158			561
Net gain (loss) on derivatives (Note 10)	105			(195		)
Other	2			1
Total revenues	572			894
Costs and expenses:
Lease and facility operating	57			60
Gathering, processing and transportation	73			89
Taxes other than income	22			35
Gas management, including charges for unutilized pipeline capacity	109			391
Exploration (Note 4)	7			15
Depreciation, depletion and amortization	216			193
Gain on sale of assets (Note 4)	(69		)	—
General and administrative	64			67
Other—net	26			2
Total costs and expenses	505			852
Operating income (loss)	67			42
Interest expense	(33		)	(29		)
Investment income and other	1			—
Income (loss) from continuing operations before income taxes	35			13
Provision (benefit) for income taxes	13			13
Income (loss) from continuing operations	22			—
Income (loss) from discontinued operations	46			19
Net income (loss)	68			19
Less: Net income (loss) attributable to noncontrolling interests	1			1
Comprehensive income (loss) attributable to WPX Energy, Inc.	$	67		$	18
Amounts attributable to WPX Energy, Inc.:
Income (loss) from continuing operations	$	22		$	—
Income (loss) from discontinued operations	45			18
Net income (loss)	$	67		$	18
Basic earnings (loss) per common share (Note 3):
Income (loss) from continuing operations	$	0.11		$	—
Income (loss) from discontinued operations	0.22			0.09
Net income (loss)	$	0.33		$	0.09
Weighted-average shares (millions)	204.1			201.5
Diluted earnings (loss) per common share (Note 3):
Income (loss) from continuing operations	$	0.11		$	—
Income (loss) from discontinued operations	0.21			0.09
Net income (loss)	$	0.32		$	0.09
Weighted-average shares (millions)	205.9			205.2

See accompanying notes.

5

WPX Energy, Inc.

Consolidated Statements of Changes in Equity

(Unaudited)

	WPX Energy, Inc., Stockholders												Noncontrolling Interests in Consolidated Subsidiaries (a)			Total Equity
	Common Stock		Additional Paid-In- Capital		Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
	(Millions)
Balance at December 31, 2014	$	2	$	5,562	$	(1,244	)	$	(1	)	$	4,319	$	109		$	4,428
Comprehensive income (loss):
Net income (loss)	—		—		67			—			67		1			68
Other comprehensive loss	—		—		—			—			—		—			—
Comprehensive income (loss)																68
Stock based compensation	—		2		—			—			2		—			2
Impact of divestitures								1			1		(110		)	(109		)
Balance at March 31, 2015	$	2	$	5,564	$	(1,177	)	$	—		$	4,389	$	—		$	4,389

__________ 

(a) Primarily represents the 31 percent interest in Apco Oil and Gas International Inc. owned by others.

See accompanying notes.

6

WPX Energy, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

	Three months ended March 31,
	2015			2014
	(Millions)
Operating Activities
Net income (loss)	$	68		$	19
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	216			207
Deferred income tax provision (benefit)	4			21
Provision for impairment of properties and equipment (including certain exploration expenses)	15			11
Amortization of stock-based awards	9			7
(Gain) loss on sale of international interests and domestic assets	(110		)	—
Cash provided (used) by operating assets and liabilities:
Accounts receivable	110			(128		)
Inventories	(3		)	4
Margin deposits and customer margin deposits payable	8			(44		)
Other current assets	(5		)	20
Accounts payable	(90		)	104
Accrued and other current liabilities	(62		)	(51		)
Changes in current and noncurrent derivative assets and liabilities	30			27
Other, including changes in other noncurrent assets and liabilities	4			9
Net cash provided by operating activities	194			206
Investing Activities
Capital expenditures(a)	(480		)	(352		)
Proceeds from sale of international interests and domestic assets	563			—
Other	4			(2		)
Net cash provided by (used in) investing activities	87			(354		)
Financing Activities
Proceeds from common stock	2			4
Borrowings on credit facility	181			622
Payments on credit facility	(461		)	(497		)
Other	9			(17		)
Net cash provided by (used in) financing activities	(269		)	112
Net increase (decrease) in cash and cash equivalents	12			(36		)
Effect of exchange rate changes on cash and cash equivalents	—			(5		)
Cash and cash equivalents at beginning of period(b)	70			99
Cash and cash equivalents at end of period	$	82		$	58
__________
(a) Increase to properties and equipment	$	(297	)	$	(372	)
Changes in related accounts payable and accounts receivable	(183		)	20
Capital expenditures	$	(480	)	$	(352	)
(b) For periods prior to sale, amounts include cash associated with our international operations and represents the difference between amounts reported as cash on the Consolidated Balance Sheet.

See accompanying notes.

7

WPX Energy, Inc.

Notes to Consolidated Financial Statements

Note 1. Basis of Presentation and Description of Business

Description of Business

Operations of our company include natural gas, oil and NGL development, production and gas management activities primarily located in Colorado, New Mexico and North Dakota in the United States. We specialize in development and production from tight-sands and shale formations in the Piceance, Williston and San Juan Basins. We also have operations and interests in the Appalachian and Green River Basins located in Pennsylvania and Wyoming. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts, such as transportation and related derivatives, coupled with the sale of our commodity volumes.

In addition, we have operations in the Powder River Basin in Wyoming that are classified as held for sale and, until January 29, 2015, we had a 69 percent controlling interest in Apco Oil and Gas International Inc. (“Apco”), an oil and gas exploration and production company with activities in Argentina and Colombia. For all periods presented, the results of Powder River Basin and Apco are reported as discontinued operations.

The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company” is at times referred to in the first person as “we”, “us” or “our”.

Basis of Presentation

The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2014 in the Company’s Annual Report on Form 10-K. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at March 31, 2015, results of operations for the three months ended March 31, 2015 and 2014, changes in equity for the three months ended March 31, 2015 and cash flows for the three months ended March 31, 2015 and 2014.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Our continuing operations are comprised of a single business segment, which includes the development, production and gas management activities of natural gas, oil and NGLs in the United States. Prior to classifying our international operations as discontinued operations, we reported business segments for domestic and international.

Discontinued Operations

On January 29, 2015, we completed the disposition of our international interests and we received net proceeds of $291 million after expenses but before $17 million of cash on hand at Apco as of the closing date. The results of operations of our international segment have been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheet as of December 31, 2014.

The results of operations of the Powder River Basin have also been reported as discontinued operations on the Consolidated Statements of Operations and the assets and liabilities have been classified as held for sale on the Consolidated Balance Sheets.

Additionally, see Note 8 for a discussion of contingencies related to Williams’ former power business (most of which was disposed of in 2007).

See Note 2 for a further discussion of discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.

Recently Issued Accounting Standards

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The core principles of the guidance in ASU 2014-09 are that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. On April 1, 2015, the FASB voted to propose to defer the effective date of ASU 2014-09 by one year to annual reporting periods beginning after December 15, 2017. The FASB plans to expose its decision sometime during the second quarter of 2015. The Company is currently evaluating the impact, if any, of ASU 2014-09 to the Company's financial position, results of operations or cash flows.

8

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, to provide guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The Company does not expect the adoption of ASU 2014-15 to have a significant impact on its Consolidated Financial Statements or related disclosures.

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The guidance is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. The Company does not believe the adoption of this guidance will have a material impact on its financial position, results of operations or cash flows.

Note 2. Discontinued Operations

On October 3, 2014, we announced an agreement to sell our international interests for approximately $294 million subject to the successful consummation of the definitive merger agreement entered into between Pluspetrol Resources Corporation and Apco. On January 29, 2015 we completed this divestiture and received net proceeds of $291 million after expenses but before $17 million of cash on hand at Apco as of the closing date. Together, these non-operated international holdings comprised our international segment. We recorded a pretax gain of $41 million related to this transaction during first quarter 2015.

During the third quarter of 2014, our management signed an agreement to sell our remaining mature, coalbed methane holdings in the Powder River Basin for $155 million. This sales agreement did not successfully close in March 2015 and we subsequently terminated the transaction with the counterparty. However, management is still pursuing the divestiture of these holdings with interested parties. In the first quarter of 2015 we recorded a $10 million impairment of the net assets to a probability weighted-average of expected sales prices. The Powder River operations have firm gathering and treating agreements with total commitments of $119 million through 2020. These commitments have been in excess of our production throughput. We also have certain pipeline capacity obligations held by our marketing company with total commitments for 2015 and thereafter totaling $163 million. Depending on the final terms upon closing a Powder River sale, we may record a portion of these obligations if they meet the definition of exit activities in association with exiting the Powder River Basin.

Summarized Results of Discontinued Operations

	Three months ended March 31, 2015
	Domestic			International			Total
				(Millions)
Total revenues	$	25		$	15		$	40
Costs and expenses:
Lease and facility operating	$	10		$	4		$	14
Gathering, processing and transportation	14			—			14
Taxes other than income	3			3			6
Impairment of assets held for sale	10			—			10
General and administrative	1			1			2
Other—net	(1		)	—			(1		)
Total costs and expenses	37			8			45
Operating income (loss)	(12		)	7			(5		)
Investment income and other	2			1			3
Gain on sale of international assets	—			41			41
Income (loss) from discontinued operations before income taxes	(10		)	49			39
Provision (benefit) for income taxes(a)	(4		)	(3		)	(7		)
Income (loss) from discontinued operations	$	(6	)	$	52		$	46

__________

(a) International includes the reversal of certain U.S. deferred tax liabilities associated with Apco.

9

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

	Three months ended March 31, 2014
	Domestic		International		Total
			(Millions)
Total revenues	$	62	$	31	$	93
Costs and expenses:
Lease and facility operating	$	11	$	8	$	19
Gathering, processing and transportation	17		—		17
Taxes other than income	6		6		12
Depreciation, depletion and amortization	4		10		14
General and administrative	1		4		5
Other—net	—		1		1
Total costs and expenses	39		29		68
Operating income (loss)	23		2		25
Investment income and other	2		2		4
Income (loss) from discontinued operations before income taxes	25		4		29
Provision (benefit) for income taxes	8		2		10
Income (loss) from discontinued operations	$	17	$	2	$	19

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

As of March 31, 2015 the following table presents assets classified as held for sale and liabilities associated with assets held for sale related to our Powder River Basin operations.

	March 31, 2015
	Total
	(Millions)
Assets classified as held for sale
Current assets:
Inventories	$	1
Total current assets	1
Investments	19
Properties and equipment (successful efforts method of accounting)(a)	122
Less—accumulated depreciation, depletion and amortization	(10		)
Properties and equipment, net	112
Total assets classified as held for sale on the Consolidated Balance Sheets	$	132
Liabilities associated with assets held for sale
Current liabilities:
Accrued and other current liabilities	$	3
Total current liabilities	3
Asset retirement obligations	44
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets	$	47

__________

(a) Includes a cumulative total of $55 million in impairments of the net assets held for sale of the Powder River Basin.

10

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

As of December 31, 2014 the following table presents domestic assets classified as held for sale and liabilities associated with assets held for sale related to our Powder River Basin and Appalachian Basin operations, and the international assets classified as held for sale and liabilities associated with assets held for sale related to our international operations which were divested in January 2015.

	December 31, 2014
	Domestic			International			Total
				(Millions)
Assets classified as held for sale
Current assets:
Cash and cash equivalents	$	—		$	29		$	29
Accounts receivable	—			25			25
Inventories	1			7			8
Other	—			14			14
Total current assets	1			75			76
Investments	18			134			152
Properties and equipment (successful efforts method of accounting)(a)	132			445			577
Less—accumulated depreciation, depletion and amortization	(10		)	(228		)	(238		)
Properties and equipment, net	122			217			339
Other noncurrent assets	—			6			6
Total assets classified as held for sale—discontinued operations	$	141		$	432		$	573
Total assets classified as held for sale—continuing operations (Note 4)	200			—			200
Total assets classified as held for sale on the Consolidated Balance Sheets	$	341		$	432		$	773
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—		$	34		$	34
Accrued and other current liabilities	3			23			26
Total current liabilities	3			57			60
Deferred income taxes	—			13			13
Long-term debt	—			2			2
Asset retirement obligations	45			7			52
Other noncurrent liabilities	—			3			3
Total liabilities associated with assets held for sale—discontinued operations	$	48		$	82		$	130
Total liabilities associated with assets held for sale—continuing operations (Note 4)	$	2		$	—		$	2
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets	$	50		$	82		$	132

__________

(a) Domestic includes a total of $45 million in impairments of the net assets held for sale of the Powder River Basin.

Cash Flows Attributable to Discontinued Operations

Excluding income taxes and changes to working capital, total cash used by operating activities related to the Powder River Basin was $1 million for the three months ended March 31, 2015 and total cash provided by operating activities was $30 million for the three months ended March 31, 2014. Total cash used in investing activities related to Powder River Basin discontinued operations was $1 million and $2 million for the three months ended March 31, 2015 and 2014, respectively. Cash provided by operating activities related to our international operations was $3 million and $11 million for the three months ended March 31, 2015 and 2014, respectively. Total cash used in investing activities related our international operations was $15 million and $21 million for the three months ended March 31, 2015 and 2014, respectively.

11

WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Note 3. Earnings (Loss) Per Common Share from Continuing Operations

The following table summarizes the calculation of earnings per share.

	Three months ended March 31,
	2015		2014
	(Millions, except per-share amounts)
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	22	$	—
Basic weighted-average shares	204.1		201.5
Effect of dilutive securities(a):
Nonvested restricted stock units and awards	1.7		2.7
Stock options	0.1		1.0
Diluted weighted-average shares	205.9		205.2
Earnings (loss) per common share from continuing operations:
Basic	$	0.11	$	—
Diluted	$	0.11	$	—

The table below includes information related to stock options that were outstanding at March 31, 2015 and 2014 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the first quarter weighted-average market price of our common shares.

	March 31,
	2015		2014
Options excluded (millions)	2.6		0.4
Weighted-average exercise price of options excluded	$	16.16	$	20.23
Exercise price range of options excluded	$11.46 - $21.81		$19.95 - $20.97
First quarter weighted-average market price	$	11.43	$	18.44

For the three months ended March 31, 2015, approximately 1.0 million nonvested restricted stock units were antidilutive and were excluded from the computation of diluted weighted-average shares.

Note 4. Asset Sale, Other Expenses and Exploration Expenses

Asset Sale

During the first quarter of 2015, we sold a portion of our Appalachian Basin operations and released certain firm transportation capacity to Southwestern Energy Company (NYSE: SWN) for approximately $288 million, subject to post closing adjustments. Including an estimate of post closing adjustments, we have recorded a net gain of $69 million in first-quarter 2015. This transaction included physical operations covering approximately 46,700 acres, roughly 50 MMcfe per day of net natural gas production and 63 horizontal wells. The assets are primarily located in the Appalachian Basin in Susquehanna County, Pennsylvania. The transaction also included the release of firm transportation capacity that we had under contract in the northeast, primarily 260 MMcfe per day with Millennium Pipeline. Upon the transfer of the firm capacity, we will be released from approximately $24 million per year in annual demand obligations associated with the transport.

Other Expenses

During the first quarter of 2015, we executed a termination and settlement agreement to release us from a crude oil transportation and sales agreement in anticipation of entering into a different agreement with another third party with more favorable terms. As a result of this contract termination and settlement, we recorded an expense of approximately $22 million which is included in Other—net on the Consolidated Statements of Operations.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Exploration Expenses

The following table presents a summary of exploration expenses.

	Three months ended March 31,
	2015		2014
	(Millions)
Geologic and geophysical costs	$	1	$	5
Unproved leasehold property impairment, amortization and expiration	6		10
Total exploration expenses	$	7	$	15

As of March 31, 2015, our total capitalized well costs associated with our exploratory areas, including the Niobrara Shale in the Piceance Basin, totaled approximately $38 million.

Note 5. Inventories

	March 31, 2015		December 31, 2014
	(Millions)
Material, supplies and other	$	48	$	43
Crude oil production in transit	1		2
Total inventories	$	49	$	45

Note 6. Debt and Banking Arrangements

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

	March 31, 2015		December 31, 2014
	(Millions)
5.250% Senior Notes due 2017	$	400	$	400
6.000% Senior Notes due 2022	1,100		1,100
5.250% Senior Notes due 2024	500		500
Credit facility agreement	—		280
Other	1		1
Total debt	$	2,001	$	2,281
Less: Current portion of long-term debt	1		1
Total long-term debt	$	2,000	$	2,280

Credit Facility

We have a $1.5 billion five-year senior unsecured revolving credit facility agreement with Citibank, N.A., as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). Under the terms of the Credit Facility and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. The Credit Facility matures on October 28, 2019. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of March 31, 2015, we were in compliance with our financial covenants and had full access to the Credit Facility. For additional information regarding the terms of our Credit Facility, see our Annual Report on Form 10-K for the year ended December 31, 2014.

Letters of Credit

WPX has also entered into three bilateral, uncommitted letter of credit (“LC”) agreements. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility. At March 31, 2015, a total of $315 million in letters of credit have been issued.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Note 7. Provision (Benefit) for Income Taxes

The provision (benefit) for income taxes from continuing operations includes:

	Three months ended March 31,
	2015		2014
	(Millions)
Current:
Federal	$	—	$	1
State	—		—
	—		1
Deferred:
Federal	12		(1		)
State	1		13
	13		12
Total provision (benefit)	$	13	$	13

The effective tax rate for all periods presented above differs from the federal statutory rate primarily due to the effects of state income taxes. Tax reform legislation was enacted by the state of New York on March 31, 2014, and had an impact on us as a result of our marketing activities in the state. As a result, we recorded an additional $9 million of deferred tax expense in the first quarter of 2014 to accrue for the impact of this new legislation.

As of March 31, 2015, the amount of unrecognized tax benefits is not material. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of our unrecognized tax benefit.

Pursuant to our tax sharing agreement with The Williams Companies, Inc. (“Williams”), we remain responsible for the tax from audit adjustments related to our business for periods prior to the spin-off. The 2011 consolidated tax filing by Williams is currently being audited by the IRS and is the only pre spin-off period for which we continue to have exposure to audit adjustments as part of Williams. We are not aware of any significant issues related to our business for which we would owe additional tax; however, the alternative minimum tax credit deferred tax asset that was allocated to us by Williams at the time of the spin-off could change due to audit adjustments unrelated to our business.

Note 8. Contingent Liabilities

Royalty litigation

In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for proceeds received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments related to calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class for certification, resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim related to the issue of whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are entitled to deduct a proportionate share of transportation costs in calculating royalty payments. Plaintiffs had claimed damages of approximately $20 million plus interest for the period from July 2000 to July 2008. The court issued pretrial orders finding that we do bear the burden of demonstrating enhancement of the value of gas in order to deduct transportation costs and that the enhancement test must be applied on a monthly basis in order to determine the reasonableness of post-production transportation costs. Trial occurred in December 2013 on the issue of whether we have met that burden. Following that trial, the court issued its order rejecting plaintiffs’ proposed standard and accepting our position as to the methodology to use in determining the standard by which our activity should be judged. We have completed the accounting process under the standard and have obtained the court's approval. However, as we continue to believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law, we have appealed this matter to the Colorado

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Court of Appeals. Plaintiffs have now filed a second class action lawsuit in the District Court, Garfield County containing similar allegations but related to subsequent time periods. The parties have agreed to stay this new lawsuit pending resolution of the first lawsuit in the Colorado Court of Appeals.

In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint presently alleges failure to pay royalty on hydrocarbons including drip condensate, breach of the duty of good faith and fair dealing, fraudulent concealment, conversion, misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons in Colorado, violation of the New Mexico Oil and Gas Proceeds Payment Act, and bad faith breach of contract. Plaintiffs sought monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter was removed to the United States District Court for New Mexico. In March 2015, the court denied plaintiffs' motion for class certification. Plaintiffs have not timely filed an appeal of this denial but have filed a motion seeking to conduct additional discovery in order to attempt to redefine their proposed class. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico and violation of the New Mexico Oil and Gas Proceeds Payment Act, and seek declaratory judgment, accounting and injunction. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.

Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The guidelines for New Mexico properties were revised slightly in September 2013 as a result of additional work performed by the ONRR. The revisions did not change the basic function of the original guidance. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states though such guidelines are expected in the future. However, the timing of any such guidance is uncertain and, independent of the issuance of additional guidance, ONRR asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments, and the effect could be material to our results of operations. Interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and may vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. Correspondence in 2009 with the ONRR’s predecessor did not take issue with our calculation regarding the Piceance Basin assumptions, which we believe have been consistent with the requirements. From April 2008 through March 2015, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $113 million.

Environmental matters

The Environmental Protection Agency (“EPA”), other federal agencies, and various state and local regulatory agencies and jurisdictions routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, new air quality standards for ground level ozone, methane, green completions, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

Matter related to Williams’ former power business

In connection with a Separation and Distribution Agreement between WPX and Williams, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us, and we are obligated to pay Williams any net proceeds realized from, the pending litigation described below relating to the reporting of certain natural gas-related information to trade publications.

Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin and brought on behalf of direct and indirect purchasers of

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. When a final order is entered against the one remaining defendant, the Colorado plaintiffs may appeal the order.

In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed to the United States Court of Appeals for the Ninth Circuit. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit issued its opinion in the Western States Antitrust Litigation holding that the Natural Gas Act does not preempt the plaintiffs’ state antitrust claims and reversing the summary judgment previously entered in favor of the defendants. The U.S. Supreme Court granted Defendants' writ of certiorari. On April 21, 2015, the U.S. Supreme Court determined that the state antitrust claims are not preempted by the federal Natural Gas Act. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time.

Other Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.

At March 31, 2015, we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.

In connection with the separation from Williams, we agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.

Summary

As of March 31, 2015 and December 31, 2014, the Company had accrued approximately $16 million for loss contingencies associated with royalty litigation and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.

Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Note 9. Fair Value Measurements

The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash, and margin deposits and customer margin deposits payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.

	March 31, 2015								December 31, 2014
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)								(Millions)
Energy derivative assets	$	9	$	479	$	1	$	489	$	14	$	517	$	5	$	536
Energy derivative liabilities	$	16	$	7	$	1	$	24	$	32	$	10	$	—	$	42
Total debt(a)	$	—	$	1,868	$	—	$	1,868	$	—	$	2,218	$	—	$	2,218

__________

(a) The carrying value of total debt, excluding capital leases, was $2,000 million and $2,280 million as of March 31, 2015 and December 31, 2014, respectively.

Energy derivatives include commodity based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and swaptions. These are carried at fair value on the Consolidated Balance Sheets.

Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.

The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.

Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.

Forward, swap, option and swaption contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars or as swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with 100 percent of the net fair value of our derivatives portfolio expiring at the end of 2016. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes or market indications and documented on a monthly basis.

Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 were a net asset of less than $1 million at March 31, 2015, and consist primarily of natural gas index transactions that are used to manage our physical requirements.

Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers occurred during the periods ended March 31, 2015 and 2014.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

There have been no material changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.

Note 10. Derivatives and Concentration of Credit Risk

Energy Commodity Derivatives

Risk Management Activities

We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas, oil and natural gas liquids attributable to commodity price risk.

We produce, buy and sell natural gas, crude oil and natural gas liquids at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements and financial option contracts to mitigate the price risk on forecasted sales of natural gas, crude oil and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased options, a combination of options that comprise a net purchased option or a zero-cost collar or swaptions.

We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements and financial option contracts to mitigate the price risk associated with these contracts. Derivatives for transportation contracts economically hedge the expected cash flows generated by those agreements.

Derivatives related to production

The following table sets forth the derivative notional volumes that are economic hedges of production volumes, which are included in our commodity derivatives portfolio as of March 31, 2015.

Commodity	Period	Contract Type (a)	Location	Notional Volume (b)		Weighted Average Price (c)
Natural Gas
Natural Gas	Apr-Dec 2015	Fixed Price Swaps	Henry Hub	(410	)	$	4.05
Natural Gas	Apr-Dec 2015	Costless Collars	Henry Hub	(50	)	$ 4.00 - 4.50
Natural Gas	Apr-Dec 2015	Basis Swaps	NGPL	(18	)	$	(0.18	)
Natural Gas	Apr-Dec 2015	Basis Swaps	Rockies	(220	)	$	(0.16	)
Natural Gas	Apr-Dec 2015	Basis Swaps	San Juan	(100	)	$	(0.11	)
Natural Gas	Apr-Dec 2015	Basis Swaps	SoCal	(20	)	$	0.18
Natural Gas	2016	Fixed Price Swaps	Henry Hub	(280	)	$	3.81
Natural Gas	2016	Swaptions	Henry Hub	(90	)	$	4.23
Natural Gas	2017	Swaptions	Henry Hub	(65	)	$	4.19
Crude Oil
Crude Oil	Apr-Dec 2015	Fixed Price Swaps	WTI	(19,658	)	$	94.84
Crude Oil	Apr-Dec 2015	Swaptions	WTI	(1,171	)	$	97.29
Crude Oil	2016	Fixed Price Swaps	WTI	(4,500	)	$	62.04
Crude Oil	2016	Swaptions	WTI	(8,500	)	$	84.27

__________

(a) Derivatives related to crude oil production are fixed price swaps settled on the business day average and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, swaptions and costless collars. In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas and crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us.

(b) Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.

(c) The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Derivatives primarily related to transportation

The following table sets forth the derivative notional volumes of the net long (short) positions of derivatives primarily related to transportation contracts, which are included in our commodity derivatives portfolio as of March 31, 2015. The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.

Commodity	Period	Contract Type (a)	Location (b)	Notional Volume (c)
Natural Gas	Apr-Dec 2015	Basis Swaps	Multiple	(7	)
Natural Gas	Apr-Dec 2015	Index	Multiple	(108	)
Natural Gas	2016	Index	Multiple	(70	)
Natural Gas	2017	Index	Multiple	(70	)
Natural Gas	2018+	Index	Multiple	(70	)

__________

(a) We enter into exchange traded fixed price and basis swaps, over-the-counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.

(b) We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation and asset management agreements.

(c) Natural gas volumes are reported in BBtu/day.

Fair values and gains (losses)

The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Consolidated Balance Sheets as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

	March 31, 2015				December 31, 2014
	Assets		Liabilities		Assets		Liabilities
	(Millions)
Derivatives related to production	$	479	$	7	$	517	$	10
Derivatives related to physical marketing agreements	10		17		19		32
Total derivatives	$	489	$	24	$	536	$	42

We enter into commodity derivative contracts that serve as economic hedges but are not designated as cash flow hedges for accounting purposes as we do not utilize this method of accounting on derivative instruments. The following table presents the net gain (loss) related to our energy commodity derivatives.

	Three months ended March 31,
	2015			2014
	(Millions)
Gain (loss) from derivatives related to production(a)	$	122		$	(86	)
Gain (loss) from derivatives related to physical marketing agreements(b)	(17		)	(109		)
Net gain (loss) on derivatives not designated as hedges	$	105		$	(195	)

__________

(a) Includes receipts totaling $158 million and payments totaling $50 million for the three months ended March 31, 2015 and 2014, respectively.

(b) Includes payments totaling $23 million and $118 million for the three months ended March 31, 2015 and 2014, respectively.

The cash flow impact of our derivative activities is presented in the Consolidated Statements of Cash Flows as changes in current and noncurrent derivative assets and liabilities.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

Offsetting of derivative assets and liabilities

The following table presents our gross and net derivative assets and liabilities.

	Gross Amount Presented on Balance Sheet			Netting Adjustments (a)			Cash Collateral Posted (Received)		Net Amount
March 31, 2015	(Millions)
Derivative assets with right of offset or master netting agreements	$	489		$	(17	)	$	—	$	472
Derivative liabilities with right of offset or master netting agreements	$	(24	)	$	17		$	7	$	—
December 31, 2014
Derivative assets with right of offset or master netting agreements	$	536		$	(25	)	$	—	$	511
Derivative liabilities with right of offset or master netting agreements	$	(42	)	$	25		$	17	$	—

__________

(a) With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

Credit-risk-related features

Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.

As of March 31, 2015, we had collateral totaling $18 million posted to derivative counterparties, which included $11 million of initial margin to clearinghouses or exchanges to enter into positions and $7 million of maintenance margin for changes in the fair value of those positions, to support the aggregate fair value of our net $7 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was less than $1 million at March 31, 2015.

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Derivative assets and liabilities

We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations.Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties.

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WPX Energy, Inc.

Notes to Consolidated Financial Statements — (Continued)

We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2015 and 2014, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.

The gross and net credit exposure from our derivative contracts as of March 31, 2015, is summarized as follows:

Counterparty Type	Gross Total		Net Total
	(Millions)
Financial institutions (Investment Grade)(a)	$	490	$	473
	490		473
Credit reserves	1		1
Credit exposure from derivatives	$	489	$	472

__________

(a) We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum S&P’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

Our eight largest net counterparty positions represent approximately 96 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Under our marginless hedging agreements with key banks, neither party is required to provide collateral support related to hedging activities.

Other

Collateral support for our commodity agreements could include margin deposits, letters of credit and guarantees of payment by credit worthy parties.

Note 11. Subsequent Events

Subsequent to March 31, 2015, WPX signed an agreement to sell a package of marketing contracts and release certain related firm transportation capacity in the Northeast to an undisclosed buyer for an amount in excess of $200 million cash. The parties expect to close the transaction in the second quarter, subject to regulatory approval and typical closing conditions. Upon completing the transaction, WPX will be released from various long-term natural gas purchase and sales obligations and approximately $390 million in future demand payment obligations associated with the transport position.

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

General

The following discussion should be read in conjunction with the selected historical consolidated financial data and the consolidated financial statements and the related notes included in Part I, Item 1 in this Form 10-Q and our 2014 Annual Report on Form 10-K. The matters discussed below may contain forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this Form 10-Q and our Annual Report on Form 10-K.

On January 29, 2015, we completed the disposition of our international interests pursuant to the successful merger of Apco Oil and Gas International Inc. ("Apco") with a subsidiary of privately held Pluspetrol Resources Corporation. The results of Apco are reported as discontinued operations.

During the third quarter of 2014, we signed an agreement for the sale of our remaining mature, coalbed methane holdings in the Powder River Basin in Wyoming. This agreement did not successfully close in March 2015 and we subsequently terminated the transaction with the counterparty. However, management is still pursuing the divestiture of these holdings with interested parties. As a result, we have reported the results of operations and financial position of the Powder River Basin as discontinued operations.

Unless indicated otherwise, the following discussion relates to continuing operations.

Overview

The following table presents our production volumes and financial highlights for the three months ended March 31, 2015 and 2014:

	Three months ended March 31,
	2015		2014
Production Sales Data(a):
Natural gas (MMcf)	63,476		71,531
Oil (MBbls)	3,117		1,737
NGLs (MBbls)	1,518		1,587
Combined equivalent volumes (MMcfe)(b)	91,291		91,475
Per day combined equivalent volumes (MMcfe/d)	1,014		1,016
Combined equivalent volumes (MBoe)(b)	15,215		15,246
Per day combined equivalent volumes (MBoe/d)	169.1		169.4
Financial Data (millions):
Total revenues	$	572	$	894
Operating income (loss)	$	67	$	42
Cash capital expenditures(c)	$	480	$	352
Capital expenditure activity(c)	$	297	$	372

__________

(a) Excludes production from our discontinued operations.

(b) MBoe and MMcfe are converted using the ratio of one barrel of oil, condensate or NGL to six thousand cubic feet of natural gas.

(c) Includes capital expenditures related to discontinued operations of $16 million and $23 million for the three months ended March 31, 2015 and 2014, respectively.

Our first-quarter 2015 operating results were $25 million favorable compared to first-quarter 2014. The primary favorable impacts include a $300 million favorable change in net gain (loss) on derivatives and a $69 million gain on the sale of a portion of ourAppalachian Basin assets, partially offset by $220 million lower product revenues and $121 million lower net gas management margin.

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Outlook

As previously disclosed, our strategy is to simplify our geographic focus and expand returns, margins and cash flow over the next five years. Key to this strategy are the core resource plays in North Dakota, New Mexico and Colorado. In regards to simplifying our geographic focus, we made significant progress toward this goal as evidenced by the completion of the sales of our international interests and a portion of our Appalachian Basin operations. Although an agreement signed in the third quarter of 2014 for the sale of our coalbed methane assets in Wyoming has been terminated after extensions by both parties, we continue our efforts to complete a sale of these assets in the foreseeable future. Additionally, we are evaluating other transactions that would monetize certain of our assets and enable us to redeploy the sales proceeds in areas where there is an opportunity for a higher return. While market conditions are challenging for producers, opportunities may also arise that we will evaluate. Although we are simplifying our current geographic focus, there may be opportunities for acquisitions in other areas that would be a complimentary addition to our portfolio.

While the significant declines in forward commodity prices, especially oil, is challenging to the oil and gas industry as evidenced by the reduced 2015 capital plans among our peers and reductions in workforces across the industry, we are committed to our long term strategy. However, we will remain flexible to adjust to market conditions and prudent in preserving the strength of our balance sheet. For 2015, approximately three-fourths of our expected natural gas production and two-thirds of our expected oil production were hedged at prices above the current market which provides significant protection to price downturns in 2015. Our 2015 drilling activity will be greatly reduced in comparison to 2014 as we plan to primarily drill locations that preserve leases or optimize the drilling rigs already under contract in an effort to reduce the impact of rig release penalties while potentially deferring completions. Additionally, as we reduce our areas of focus, we have the opportunity to improve our cost structure and ensure that our organization is in alignment with growth objectives. We will continue to focus on lowering costs through reduced drilling times, efficient use of pad design and completion activities, and working with our vendors to lower costs on goods and services. Additionally, we continue to review our general and administrative costs and services. In March 2015, we announced that we would trim our company-wide workforce by approximately 8 percent and consolidate most of our regional office staff in Denver, Colorado, with personnel at the company's headquarters in Tulsa, Oklahoma.

Our 2015 capital program is expected to be in line with our projected cash flow. Through March 31, 2015, our 2015 capital activity totaled $297 million. Capital activity was higher early in the quarter before reduction of our rig count by 10 and temporarily suspending completions in the Piceance Basin to realign operational costs. Planned capital investments for new activity in full-year 2015 are approximately $675 million to $775 million. A slower run rate for the latter half of the year is expected to offset a stronger run rate in the first two quarters.

For the full-year 2015, we expect to spend $200 million to $225 million in the Williston Basin optimizing rigs already under contract ramping down to one rig by late spring for the balance of the year. Additionally, we are deferring completions of wells drilled. We expect to spend $295 million to $320 million in the Gallup Sandstone in 2015, primarily preserving the leases and forming units. Despite the decrease in the capital expenditures in 2015, we are targeting a 20 to 25 percent full-year growth in oil production.

We will also continue to focus our natural gas drilling effort in the Piceance Basin because of our scale and efficiency of that operation combined with significant infrastructure already in place. We expect to spend $180 million to $205 million in the Piceance Basin and plan to deploy an average of three drilling rigs in the Piceance Basin for 2015, which includes limited drilling in the Niobrara Shale but focused on driving down costs while optimizing completion techniques. Our drilling activity has primarily been focused in the Piceance Valley, however, we will start to shift more capital to opportunities in the Ryan Gulch field of the Piceance Basin where we have more than 4,000 drillable locations at 10-acre spacing.

As we execute on our long-term strategy, we continue to operate with a focus on increasing shareholder value and investing in our businesses in a way that enhances our competitive position by:

• continuing to diversify our commodity portfolio (production and reserves) through the development of our oil play positions in the Williston Basin and Gallup Sandstone in the San Juan Basin;

• continuing to pursue cost improvements and efficiency gains;

• employing new technology and operating methods;

• continuing to invest in projects to assess resources and add new development opportunities to our portfolio;

• retaining the flexibility to make adjustments to our planned levels and allocation of capital investment expenditures in response to changes in economic conditions or business opportunities; and

• continuing to maintain an active economic hedging program around our commodity price risks.

Potential risks or obstacles that could impact the execution of our plan include:

• lower than anticipated energy commodity prices;

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• higher capital costs of developing our properties;

• lower than expected levels of cash flow from operations;

• lower than expected proceeds from asset sales;

• counterparty credit and performance risk;

• general economic, financial markets or industry downturn;

• changes in the political and regulatory environments;

• increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment supplies, skilled labor or transportation;

• decreased drilling success; and

• unavailability of capital.

Changes in the forward prices will be considered as we proceed with our 2015 capital program. Additionally, if forecasted natural gas and oil prices were to decline we would need to review the producing properties net book value for possible impairment. See our discussion of impairment of long-lived assets in our critical accounting estimates discussion in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2014. With the exception of potential impairments, we continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we utilize master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements.

Commodity Price Risk Management

To manage the commodity price risk and volatility of owning producing gas and oil properties, we enter into derivative contracts for a portion of our future production. We chose not to designate our derivative contracts associated with our future production as cash flow hedges for accounting purposes. For the remainder of 2015 and 2016, we have the following contracts as of the date of this filing shown at weighted average volumes and basin-level weighted average prices:

Natural Gas	Apr - Dec 2015				2016
	Volume (BBtu/d)	Weighted Average Price ($/MMBtu)			Volume (BBtu/d)	Weighted Average Price ($/MMBtu)
Fixed-price—Henry Hub	410	$	4.05		280	$	3.81
Swaptions—Henry Hub	—	$	—		90	$	4.23
Collars—Henry Hub	50	$ 4.00 - 4.50			—	$	—
Basis swaps—NGPL	18	$	(0.18	)	—	$	—
Basis swaps—San Juan	100	$	(0.11	)	—	$	—
Basis swaps—Rockies	220	$	(0.16	)	—	$	—
Basis swaps—SoCal	20	$	0.18		—	$	—

Crude Oil	Apr - Dec 2015			2016
	Volume (Bbls/d)	Weighted Average Price ($/Bbl)		Volume (Bbls/d)	Weighted Average Price ($/Bbl)
Fixed-price—WTI	19,658	$	94.84	8,500	$	61.91
Swaptions—WTI	1,171	$	97.29	8,500	$	84.27

In conjunction with the closing of a sale of our Powder River Basin assets, we may record certain pipeline capacity obligations associated with exiting the Powder River Basin. Our total commitments related to these pipeline agreements for 2015 and thereafter total $163 million.

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Results of Operations

Operations of our company include natural gas, oil and NGL development, production and gas management activities primarily located in Colorado, New Mexico and North Dakota in the United States. Our development and production techniques specialize in production from tight-sands and shale formations primarily in the Piceance, Williston and San Juan Basins. Associated with our commodity production are sales and marketing activities, referred to as gas management activities, that include the management of various commodity contracts, such as transportation and related derivatives, coupled with the sale of our commodity volumes.

Three Month-Over-Three Month Results of Operations

Revenue Analysis

	Three months ended March 31,					Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2015		2014
	(Millions)
Revenues:
Natural gas sales	$	167	$	317		$	(150	)	(47	)%
Oil and condensate sales	117		149			(32		)	(21	)%
Natural gas liquid sales	23		61			(38		)	(62	)%
Total product revenues	307		527			(220		)	(42	)%
Gas management	158		561			(403		)	(72	)%
Net gain (loss) on derivatives	105		(195		)	300			NM
Other	2		1			1			100	%
Total revenues	$	572	$	894		$	(322	)	(36	)%

__________

NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.

Significant variances in the respective line items of revenues are comprised of the following:

• $150 million decrease in natural gas sales is primarily due to $114 million related to lower sales prices and $36 million related to lower production sales volumes. The decrease in our production sales volumes is due in part to the impact of the sales of Appalachian Basin assets in the first quarter of 2015 and a portion of our working interests in the Piceance Basin during second-quarter 2014. Natural gas production from the Piceance Basin represented approximately 75 percent of our total natural gas production. The following table reflects natural gas production prices and volumes for the three months ended March 31, 2015 and 2014:

	Three months ended March 31,
	2015		2014
Natural gas sales (per Mcf)	$	2.62	$	4.42
Impact of net cash received (paid) related to settlement of derivatives (per Mcf)(a)	1.05		(0.62		)
Natural gas net price including derivative settlements (per Mcf)	$	3.67	$	3.80
Natural gas production sales volumes (MMcf)	63,476		71,531
Per day natural gas production sales volumes (MMcf/d)	705		795

__________

(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.

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• $32 million decrease in oil and condensate sales reflects $151 million related to lower sales prices partially offset by a $119 million increase in production sales volumes for 2015 compared to 2014. The increase in production sales volumes primarily relates to continued development drilling in the Williston Basin and the Gallup Sandstone in the San Juan Basin. In the Williston and San Juan Basins, volumes were 24.9 MBbls per day and 8.1 MBbls per day, respectively, for the first three months of 2015 compared to 15.6 MBbls per day and 1.7 MBbls per day, respectively, for the same period in 2014. The following table reflects oil and condensate production prices and volumes for the three months ended March 31, 2015 and 2014:

	Three months ended March 31,
	2015		2014
Oil sales (per barrel)	$	37.64	$	86.24
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)	29.49		(2.30		)
Oil net price including derivative settlements (per barrel)	$	67.13	$	83.94
Oil and condensate production sales volumes (MBbls)	3,117		1,737
Per day oil and condensate production sales volumes (MBbls/d)	34.6		19.3

__________

(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.

• $38 million decrease in natural gas liquids sales primarily reflects lower NGL prices for 2015 compared to 2014. The following table reflects NGL production prices and volumes for the three months ended March 31, 2015 and 2014:

	Three months ended March 31,
	2015		2014
NGL sales (per barrel)	$	15.40	$	38.27
Impact of net cash received (paid) related to settlement of derivatives (per barrel)(a)	—		(0.48		)
NGL net price including derivative settlements (per barrel)	$	15.40	$	37.79
NGL production sales volumes (MBbls)	1,518		1,587
Per day NGL production sales volumes (MBbls/d)	16.9		17.6

__________

(a) Included in net gain (loss) on derivatives on the Consolidated Statements of Operations.

The following table summarizes the composition of the Piceance NGL barrel for the three months ended March 31, 2015 and 2014:

	Three months ended March 31,
	2015				2014
	% of barrel		$/gallon		% of barrel		$/gallon
Ethane	25	%	$	0.22	32	%	$	0.30
Propane	35	%	$	0.55	32	%	$	1.28
Iso-Butane	10	%	$	0.70	9	%	$	1.40
Normal Butane	9	%	$	0.70	8	%	$	1.37
Natural Gasoline	21	%	$	1.09	19	%	$	2.11

• $403 million decrease in gas management revenues is primarily due to lower average prices on physical natural gas sales as well as lower natural gas sales volumes. The decrease in the sales price was greater than the decrease in the purchase price as reflected in the $282 million decrease in related gas management costs and expenses, discussed below. Subsequent to March 31, 2015, we entered into an agreement to sell a package of marketing contracts and release firm transportation capacity (see Note 11 of Notes to Consolidated

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Financial Statements). As a result, gas management revenues and expenses in future periods will be significantly less than current levels.

• $300 million favorable change in net gain (loss) on derivatives primarily reflects a $208 million favorable change realized on derivatives for our production, primarily natural gas and crude, and a $95 million decrease in loss realized on gas management derivatives.

Cost and operating expense and operating income (loss) analysis

	Three months ended March 31,					Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2015			2014
	(Millions)
Costs and expenses:
Lease and facility operating	$	57		$	60	$	3		5	%
Gathering, processing and transportation	73			89		16			18	%
Taxes other than income	22			35		13			37	%
Gas management, including charges for unutilized pipeline capacity	109			391		282			72	%
Exploration	7			15		8			53	%
Depreciation, depletion and amortization	216			193		(23		)	(12	)%
Gain on sale of assets	(69		)	—		69			NM
General and administrative	64			67		3			4	%
Other—net	26			2		(24		)	NM
Total costs and expenses	$	505		$	852	$	347		41	%
Operating income (loss)	$	67		$	42	$	25		60	%

__________

NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.

Significant components on our domestic costs and expenses are comprised of the following:

• $3 million decrease in lease and facility operating expenses primarily relates to lower natural gas volumes due to the sales of a portion of our Appalachian Basin assets in the first quarter of 2015 and a portion of our working interests in the Piceance Basin during second-quarter 2014. This decrease is partially offset by higher oil production volumes for the three months ended March 31, 2015 compared to the same period in 2014. Lease and facility operating expense averaged $3.73 per Boe for the three months ended March 31, 2015 compared to $3.99 per Boe for the same period in 2014.

• $16 million decrease in gathering, processing and transportation expenses primarily relates to lower natural gas volumes. Gathering, processing and transportation charges averaged $4.80 per Boe for 2015 and $5.81 per Boe for 2014.

• $13 million decrease in taxes other than income primarily relates to lower commodity prices and decreased natural gas production volumes. Taxes other than income averaged $1.45 per Boe for the three months ended March 31, 2015 compared to $2.27 per Boe for the same period in 2014.

• $282 million decrease in gas management expenses is primarily due to lower average prices on physical natural gas cost of sales as well as lower gas purchase volumes. Also included in gas management expenses are $10 million and $16 million for the three months ended March 31, 2015 and 2014, respectively, for unutilized pipeline capacity. As previously noted, gas management expenses in future periods will be lower and future expenses will primarily relate to unutilized pipeline capacity.

• $8 million decrease in exploration expenses primarily relates to lower geologic and geophysical costs as well as lower unproved leasehold amortization and expiration expenses in 2015 compared to 2014 (see Note 4 of Notes to Consolidated Financial Statements).

• $23 million increase in depreciation, depletion and amortization is primarily due to higher oil production volumes. Also, during 2015, we have adjusted the proved reserves used for the calculation of depletion and amortization to reflect the impact of a decrease in the 12-month average price resulting in a $5 million addition to depreciation, depletion and amortization. During the three months ended March 31, 2015, our depreciation, depletion and amortization averaged $14.21 per Boe compared to an average $12.67 per Boe for the same period in 2014.

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• $69 million gain on sale of a portion of our Appalachian Basin assets (see Note 4 of Notes to Consolidated Financial Statements).

• $3 million decrease in general and administrative expenses is primarily due to reduced employee and related costs as a result of headcount reductions. General and administrative expenses averaged $4.21 per Boe for the three months ended March 31, 2015 compared to $4.42 per Boe for the same period in 2014. General and administrative expenses in 2015 include approximately $8 million of severance and relocation costs associated with the workforce reduction and office consolidation announced during the first quarter of 2015. Excluding these costs, general and administrative expenses would have averaged $3.68 per Boe for 2015.

• $24 million increase in other expenses primarily relates to expenses recorded in association with a contract termination (see Note 4 of Notes to Consolidated Financial Statements).

Results below operating income (loss)

	Three months ended March 31,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
	2015			2014
	(Millions)
Operating income (loss)	$	67		$	42		$	25		60	%
Interest expense	(33		)	(29		)	(4		)	(14	)%
Investment income and other	1			—			1			NM
Income (loss) from continuing operations before income taxes	35			13			22			169	%
Provision (benefit) for income taxes	13			13			—			—	%
Income (loss) from continuing operations	22			—			22			NM
Income (loss) from discontinued operations	46			19			27			142	%
Net income (loss)	68			19			49			NM
Less: Net income (loss) attributable to noncontrolling interests	1			1			—			—	%
Net income (loss) attributable to WPX Energy, Inc.	$	67		$	18		$	49		NM

__________

NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.

The increase in interest expense primarily relates to the notes issued in the third quarter of 2014.

Provision (benefit) for income taxes in 2015 were comparable to 2014. See Note 7 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods. The provision for income taxes in the first quarter of 2014 reflects an additional $9 million of deferred tax expense to accrue for the impact of new legislation enacted by the state of New York on March 31, 2014 (see Note 7 of Notes to Consolidated Financial Statements).

The change in income (loss) from discontinued operations was primarily due to the gain on the sale of Apco partially offset by a $10 million impairment in the Powder River Basin for the three months ended March 31, 2015 (see Note 2 of Notes to Consolidated Financial Statements).

Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview and Liquidity

Our main sources of liquidity are cash on hand, internally generated cash flow from operations and our bank credit facility. Additional sources of liquidity, if needed and if available, include bank financings, proceeds from the issuance of long-term debt and equity securities, and proceeds from asset sales. In consideration of our liquidity, we note the following:

• as of March 31, 2015, we maintained liquidity through cash, cash equivalents and available credit capacity under our credit facility; and

• our credit exposure to derivative counterparties is partially mitigated by master netting agreements and collateral support.

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Outlook

We expect our capital structure will provide us financial flexibility to meet our requirements for working capital, capital expenditures, and tax and debt payments while maintaining a sufficient level of liquidity. Our primary sources of liquidity in 2015 are expected cash flows from operations, proceeds from monetization of assets and, if necessary, borrowings on our $1.5 billion credit facility. We anticipate that the combination of these sources should be sufficient to allow us to pursue our business strategy and goals for 2015.

We note the following assumptions for 2015:

• our cash capital expenditures are estimated to be approximately $875 million in 2015 and exceed the previously mentioned $675 million to $775 million of capital expenditures due to costs incurred in 2014 that will be paid in 2015. The new spending is generally considered to be largely discretionary; and

• we have hedged approximately three-fourths of our anticipated 2015 natural gas production at a weighted-average price of $4.10 per MMbtu, and approximately two-thirds of anticipated 2015 oil production at a weighted-average price of $94.88 per barrel.

Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:

• lower than expected levels of cash flow from operations, primarily resulting from lower energy commodity prices;

• lower than expected proceeds from asset sales;

• higher than expected collateral obligations that may be required, including those required under new commercial agreements;

• significantly lower than expected capital expenditures could result in the loss of undeveloped leasehold; and

• reduced access to our credit facility.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses throughout 2015. Our internal and external sources of consolidated liquidity include cash generated from operations, cash and cash equivalents on hand, and our credit facility. Additional sources of liquidity, if needed and if available, include bank financings, proceeds from the issuance of long-term debt and equity securities, and proceeds from asset sales.

We have a $1.5 billion five-year senior unsecured revolving credit facility agreement with Citibank, N.A., as Administrative Agent, Lender and Swingline Lender and the other lenders party thereto (the “Credit Facility”). Under the terms of the Credit Facility and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. The Credit Facility matures on October 28, 2019. The financial covenants in the Credit Facility may limit our ability to borrow money, depending on the applicable financial metrics at any given time. As of March 31, 2015, we were in compliance with our financial covenants, had full access to the Credit Facility and did not have any outstanding borrowings. For additional information regarding the terms of our Credit Facility, see our Annual Report on Form 10-K for the year ended December 31, 2014.

Under the Credit Facility when our long-term unsecured debt rating is not BBB- or better by S&P or Baa3 or better by Moody’s and not less than BB+ by S&P or Ba1 by Moody's, we will be required to maintain a ratio of Consolidated Net Indebtedness (as defined in the Credit Facility) to Consolidated EBITDAX (as defined in the Credit Facility) of not greater than 3.75 to 1.00. Consolidated Net Indebtedness includes a reduction attributable to unrestricted cash and cash equivalents not to exceed $50 million. Consolidated EBITDAX will be calculated for the four fiscal quarters ending on the last day of any fiscal quarter for which financial statements have been or were required to be delivered. Additionally, the ratio of Consolidated Indebtedness (defined as Indebtedness of us and our consolidated subsidiaries determined on a consolidated basis) to Consolidated Total Capitalization (defined as Consolidated Indebtedness plus Consolidated Net Worth) will not be permitted to be greater than 60 percent and will be applicable for the life of the agreement.

When our long-term unsecured debt rating is BB or worse by S&P and Ba2 or worse by Moody’s or BB- or worse by S&P or Ba3 or worse by Moody’s, we will also be required to maintain a ratio of net present value of projected future cash flows from proved reserves, calculated in accordance with the terms of the Credit Facility, to Consolidated Indebtedness ratio of at least 1.25 to 1.00 for fiscal periods ending on or prior to December 31, 2015, and 1.50 to 1.00 for fiscal periods ending after December 31, 2015. Based on our current long-term unsecured debt ratings, as of the date of this filing, we are not required to comply with this covenant. In addition, this covenant will not apply at any time after the occurrence of the Investment Grade Date, which is the first date after closing on which our long-term unsecured debt is rated BBB- or better by S&P or Baa3 or

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better by Moody’s (without negative outlook or watch by either agency), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.

We have three bilateral, uncommitted letter of credit agreements which we anticipate will be renewed annually. These agreements allow us to preserve our liquidity under our Credit Facility while providing support to our ability to meet performance obligation needs for, among other items, various interstate pipeline contracts into which we have entered. These unsecured agreements incorporate similar terms as those in the Credit Facility. At March 31, 2015, a total of $315 million in letters of credit have been issued.

Sources (Uses) of Cash

	Three months ended March 31,
	2015			2014
	(Millions)
Net cash provided (used) by:
Operating activities	$	194		$	206
Investing activities	87			(354		)
Financing activities	(269		)	112
Increase (decrease) in cash and cash equivalents	$	12		$	(36	)

Operating activities

Our net cash provided by operating activities for the three months ended March 31, 2015 decreased from the same period in 2014 primarily due to a decrease in commodity prices and natural gas volumes, substantially offset by cash received on settlement of derivative contracts and higher oil volumes.

Total cash provided by operating activities related to discontinued operations was approximately $4 million and $41 million for the three months ended March 31, 2015 and 2014, respectively.

Investing activities

Cash capital expenditures for drilling and completion were $431 million and $268 million for the three months ended March 31, 2015 and 2014, respectively. Capital expenditures incurred during the three months ended March 31, 2015 and 2014 for drilling and completions were $269 million and $291 million, respectively. Domestic land activities were $8 million and $47 million during the three months ended March 31, 2015 and 2014, respectively. In addition, expenditures related to international were $15 million and $21 million for the three months ended March 31, 2015 and 2014, respectively.

In January 2015, we received proceeds of $288 million, subject to post closing adjustments, for the sale of a portion of our operations in the Appalachian Basin and release of certain firm transportation capacity to Southwestern Energy Company announced in 2014 (see Note 4 of Notes to Consolidated Financial Statements). In addition, we also received net proceeds of approximately $291 million after expenses but before $17 million of cash on hand at Apco as of the closing date, for the divestiture of our 69 percent controlling equity interest in Apco and additional Argentina-related assets to Pluspetrol (see Note 2 of Notes to Consolidated Financial Statements).

Financing activities

Net cash used by financing activities for the three months ended March 31, 2015 was primarily due to the repayment of all outstanding amounts on borrowings under the Credit Facility as previously discussed. Net cash provided by financing activities for the three months ended March 31, 2014 primarily relates to borrowings under our Credit Facility (see Note 6 of Notes to Consolidated Financial Statements) made to partially fund capital expenditures for the first quarter of 2014.

Off-Balance Sheet Financing Arrangements

We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements at March 31, 2015 or at December 31, 2014.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first three months of 2015.

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Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of natural gas, oil and natural gas liquids as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our marketing trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted and changes in interest rates. See Notes 9 and 10 of Notes to Consolidated Financial Statements.

We measure the risk in our portfolios using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolios. Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolios will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolios in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.

We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value at risk.

We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.

Trading

Our trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives was zero at March 31, 2015 and a net asset of $1 million at December 31, 2014. The value at risk for contracts held for trading purposes was zero at March 31, 2015 and less than $1 million at December 31, 2014.

Nontrading

Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from our natural gas and crude oil purchases and sales. The fair value of our derivatives not designated as hedging instruments was a net asset of $465 million and $493 million at March 31, 2015 and December 31, 2014, respectively.

The value at risk for derivative contracts held for nontrading purposes was $16 million at both March 31, 2015 and December 31, 2014. During the last 12 months, our value at risk for these contracts ranged from a high of $19 million to a low of $16 million.

Item 4. Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (“Disclosure Controls”) or our internal control over financial reporting (“Internal Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure

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Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have been no changes during the first quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

The information called for by this item is provided in Note 8 of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.

Item 1A. Risk Factors

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K, for the year ended December 31, 2014, includes certain risk factors that could materially affect our business, financial condition or future results. Those risk factors have not materially changed as of March 31, 2015.

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

Not applicable.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

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EXHIBITS

Exhibit No.	Description
2.1	Contribution Agreement, dated as of October 26, 2010, by and among Williams Production RMT Company, LLC, Williams Energy Services, LLC, Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC and Williams Field Services Group, LLC (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s registration statement on Form S-1/A (File No. 333-173808) filed with the SEC on July 19, 2011)
2.2**	Agreement and Plan of Merger, dated October 2, 2014, by and among Pluspetrol Resources Corporation, Pluspetrol Black River Corporation and Apco Oil and Gas International Inc. (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on October 7, 2014)
3.1	Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current report on Form 8-K (File No. 001-35322) filed with the SEC on January 6, 2012)
3.2	Amended and Restated Bylaws of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current report on Form 8-K (File No. 001-35322) filed with the SEC on March 21, 2014)
4.1	Indenture, dated as of November 14, 2011, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to The Williams Companies, Inc.’s Current report on Form 8-K (File No. 001-04174) filed with the SEC on November 15, 2011)
4.2	Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
4.3	First Supplemental Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
10.1	Separation and Distribution Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011)
10.2	Employee Matters Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current report on Form 8-K (File No. 001-35322) filed with the SEC on January 6, 2012)
10.3	Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current report on Form 8-K (File No. 001-35322) filed with the SEC on January 6, 2012)
10.4	Transition Services Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.4 to WPX Energy, Inc.’s Current report on Form 8-K (File No. 001-35322) filed with the SEC on January 6, 2012)
10.5	Credit Agreement, dated as of June 3, 2011, by and among WPX Energy, Inc., the lenders named therein, and Citibank, N.A., as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.3 to The Williams Companies, Inc.’s Current report on Form 8-K (File No. 001-04174) filed with the SEC on June 9, 2011)
10.6#	Amended and Restated Gas Gathering, Processing, Dehydrating and Treating Agreement by and among Williams Field Services Company, LLC, Williams Production RMT Company, LLC, Williams Production Ryan Gulch LLC and WPX Energy Marketing, LLC, effective as of August 1, 2011 (incorporated herein by reference to Exhibit 10.7 to WPX Energy, Inc.’s registration statement on Form S-1/A (File No. 333-173808) filed with the SEC on July 19, 2011)
10.7	Form of Change in Control Agreement between WPX Energy, Inc. and CEO (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current report on Form 8-K (File No. 001-35322) filed with the SEC on July 23, 2012) (1)
10.8	Form of Change in Control Agreement between WPX Energy, Inc. and Tier One Executives (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s current report on Form 8-K (File No. 001-35322) filed with the SEC on July 23, 2012) (1)

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Exhibit No.	Description
10.9	First Amendment to the Credit Agreement, dated as of November 1, 2011, by and among WPX Energy, Inc., the lenders named therein, and Citibank, N.A., as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.2 to The Williams Companies, Inc.’s Current report on Form 8-K (File No. 001-04174) filed with the SEC on November 1, 2011)
10.10	WPX Energy, Inc. 2013 Incentive Plan (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.'s Current report on Form 8-K (File No. 001-35322) filed with the SEC on May 29, 2013) (1)
10.11	WPX Energy, Inc. 2011 Employee Stock Purchase Plan (incorporated herein by reference to Exhibit 4.4 to WPX Energy, Inc.’s registration statement on Form S-8 (File No. 333-178388) filed with the SEC on December 8, 2011) (1)
10.12	Form of Restricted Stock Agreement between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011) (1)
10.13	Form of Restricted Stock Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
10.14	Form of Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
10.15*	Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (1)
10.16	Form of Stock Option Agreement between WPX Energy, Inc. and Section 16 Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014) (1)
10.17	WPX Energy Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.16 to WPX Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2012) (1)
10.18	WPX Energy Board of Directors Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.17 to WPX Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2012) (1)
10.19	Agreement, dated December 17, 2013, between WPX Energy, Inc. and Taconic Capital Advisors L.P. (incorporated herein by reference to Exhibit 99.1 to WPX Energy, Inc.'s Current report on Form 8-K filed with the SEC on December 18, 2013)
10.20	Retirement Agreement, dated December 16, 2013, between WPX Energy, Inc. and Ralph A. Hill (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.'s Current report on Form 8-K filed with the SEC on December 17, 2013)
10.21	Severance Agreement, dated February 18, 2014, between WPX Energy, Inc. and Neal A. Buck (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.'s current report on Form 8-K filed with the SEC on February 19, 2014) (1)
10.22	Employment Agreement, dated April 29, 2014, between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.23	Form of Nonqualified Stock Option Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.24	Form of 2014 Time-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.25	Form of 2014 Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.4 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)

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Exhibit No.	Description
10.26	Form of Time-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.5 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.27	Form of Performance-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.6 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
10.28	Form of Restricted Stock Unit Award between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 3, 2014) (1)
10.29	Separation and Release Agreement, dated July 28, 2014, between WPX Energy, Inc. and James J. Bender (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 3, 2014) (1)
10.30	WPX Energy Executive Severance Pay Plan (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 19, 2014) (1)
10.31	Amended and Restated Credit Agreement, dated as of October 28, 2014, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 3, 2014)
12*	Computation of Ratio of Earnings to Fixed Charges
31.1*	Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification by the Chief Executive Officer and the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Label Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase

# Certain portions have been omitted pursuant to an Order Granting Confidential Treatment issued by the SEC on December 5, 2011. Omitted information has been filed separately with the SEC.

*	Filed herewith
**	All schedules to the Merger Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the SEC upon request

(1) Management contract or compensatory plan or arrangement

35

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.

WPX Energy, Inc. (Registrant)
By:	/s/ Stephen L. Faulkner
	Stephen L. Faulkner Controller (Principal Accounting Officer)

Date: May 6, 2015

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