Edgar Filing: PIONEER NATURAL RESOURCES CO

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Smaller reporting company

PXD-2014.06.30

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-Q

______________________________



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

For the quarterly period ended June 30, 2014



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

For the transition period from ________ to ________

Commission File Number: 1-13245

______________________________

PIONEER NATURAL RESOURCES COMPANY

(Exact name of Registrant as specified in its charter)

______________________________



Delaware		75-2702753
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5205 N. O'Connor Blvd., Suite 200, Irving, Texas		75039
(Address of principal executive offices)		(Zip Code)

(972) 444-9001

(Registrant's telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

______________________________

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 ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 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 ý 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.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No ý

Number of shares of Common Stock outstanding as of August 1, 2014 143,098,392

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

TABLE OF CONTENTS



		Page
Cautionary Statement Concerning Forward-Looking Statements		3

Definitions of Certain Terms and Conventions Used Herein		4

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	5

	Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013	7

	Consolidated Statement of Equity for the six months ended June 30, 2014	8

	Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013	9

	Notes to Consolidated Financial Statements	10

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36

Item 4.	Controls and Procedures	40

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	41

Item 1A.	Risk Factors	41

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

Item 4.	Mine Safety Disclosures	41

Item 6.	Exhibits	42

Signatures		43

Exhibit Index		44

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PIONEER NATURAL RESOURCES COMPANY

Cautionary Statement Concerning Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (the "Report") contains forward-looking statements that involve risks and uncertainties. When used in this document, the words "believes," "plans," "expects," "anticipates," "forecasts," "intends," "continue," "may," "will," "could," "should," "future," "potential," "estimate" or the negative of such terms and similar expressions as they relate to Pioneer Natural Resources Company ("Pioneer" or the "Company") are intended to identify forward-looking statements. The forward-looking statements are based on the Company's current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company's control.

These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, completion of planned divestitures, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to perform the Company's drilling and operating activities, access to and availability of transportation, processing, fractionation and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer's credit facility and derivative contracts and the purchasers of Pioneer's oil, NGL and gas production, uncertainties about estimates of reserves and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impacts of climate change, the risks associated with the ownership and operation of the Company's industrial sand mining and oilfield services businesses, and acts of war or terrorism. These and other risks are described in the Company's Annual Report on Form 10-K, this and other Quarterly Reports on Form 10-Q and other filings with the United States Securities and Exchange Commission. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," "Part 1, Item 3. Quantitative and Qualitative Disclosures About Market Risk" and "Part II, Item 1A. Risk Factors" in this Report and "Part I, Item 1. Business — Competition, Markets and Regulations," "Part I, Item 1A. Risk Factors," "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in the Company's Annual Report on Form 10-K for the year ended December 31, 2013 for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.

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PIONEER NATURAL RESOURCES COMPANY

Definitions of Certain Terms and Conventions Used Herein

Within this Report, the following terms and conventions have specific meanings:


•	"BBL" means a standard barrel containing 42 United States gallons.


•	"BOE" means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of gas to one BBL of oil or natural gas liquid.


•	"BOEPD" means BOE per day.


•	"BTU" means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.


•	"Conway" means the daily average natural gas liquids components as priced in Oil Price Information Service ("OPIS") in the table "U.S. and Canada LP – Gas Weekly Averages" at Conway, Kansas.


•	"DD&A" means depletion, depreciation and amortization.


•	"GAAP" means accounting principles that are generally accepted in the United States of America.


•	"LIBOR" means London Interbank Offered Rate, which is a market rate of interest.


•	"MCF" means one thousand cubic feet and is a measure of gas volume.


•	"MMBTU" means one million BTUs.


•	"Mont Belvieu" means the daily average natural gas liquids components as priced in OPIS in the table "U.S. and Canada LP – Gas Weekly Averages" at Mont Belvieu, Texas.


•	"NGL" means natural gas liquid.


•	"NYMEX" means the New York Mercantile Exchange.


•	"Pioneer" or the "Company" means Pioneer Natural Resources Company and its subsidiaries.


•	"Pioneer Southwest" means Pioneer Southwest Energy Partners L.P. and its subsidiaries.

•

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

(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons ("LKH") as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil ("HKO") elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.


•	"U.S." means United States.

•

With respect to information on the working interest in wells, drilling locations and acreage, "net" wells, drilling locations and acres are determined by multiplying "gross" wells, drilling locations and acres by the Company's working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.


•	Unless otherwise indicated, all currency amounts are expressed in U.S. dollars.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)



	June 30, 2014			December 31, 2013
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	445		$	393
Accounts receivable:
Trade, net	457			431
Due from affiliates	8			3
Income taxes receivable	7			5
Inventories	221			220
Prepaid expenses	11			16
Assets held for sale	193			584
Other current assets:
Derivatives	1			76
Other	37			2
Total current assets	1,380			1,730
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	14,602			13,406
Unproved properties	151			123
Accumulated depletion, depreciation and amortization	(5,279		)	(4,903		)
Total property, plant and equipment	9,474			8,626
Goodwill	274			274
Other property and equipment, net	1,230			1,224
Other assets:
Investment in unconsolidated affiliate	229			225
Derivatives	10			91
Other, net	113			124
	$	12,710		$	12,294

The financial information included as of June 30, 2014 has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (continued)

(in millions)



	June 30, 2014			December 31, 2013
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,074		$	910
Due to affiliates	71			150
Interest payable	62			62
Income taxes payable	1			—
Deferred income taxes	36			19
Liabilities held for sale	45			39
Other current liabilities:
Derivatives	98			12
Other	78			58
Total current liabilities	1,465			1,250
Long-term debt	2,659			2,653
Derivatives	66			10
Deferred income taxes	1,475			1,473
Other liabilities	295			293
Equity:
Common stock, $.01 par value; 500 million shares authorized; 146 million shares issued as of June 30, 2014 and December 31, 2013, respectively	1			1
Additional paid-in capital	5,128			5,080
Treasury stock at cost: 3 million shares as of June 30, 2014 and December 31, 2013, respectively	(172		)	(144		)
Retained earnings	1,784			1,665
Total equity attributable to common stockholders	6,741			6,602
Noncontrolling interests in consolidating subsidiaries	9			13
Total equity	6,750			6,615
Commitments and contingencies
	$	12,710		$	12,294

The financial information included as of June 30, 2014 has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Revenues and other income:
Oil and gas	$	959		$	781		$	1,869		$	1,510
Sales of purchased oil and gas	205			56			353			112
Interest and other	3			(5		)	7			(5		)
Derivative gains (losses), net	(218		)	144			(322		)	102
Gain on disposition of assets, net	4			183			10			207
	953			1,159			1,917			1,926
Costs and expenses:
Oil and gas production	173			153			338			303
Production and ad valorem taxes	59			51			116			103
Depletion, depreciation and amortization	248			225			469			437
Purchased oil and gas	198			55			341			111
Exploration and abandonments	29			18			60			36
General and administrative	82			66			163			128
Accretion of discount on asset retirement obligations	3			3			6			6
Interest	47			43			92			94
Other	22			22			38			42
	861			636			1,623			1,260
Income from continuing operations before income taxes	92			523			294			666
Income tax provision	(34		)	(183		)	(87		)	(233		)
Income from continuing operations	58			340			207			433
Income (loss) from discontinued operations, net of tax	(57		)	11			(83		)	27
Net income	1			351			124			460
Net income attributable to noncontrolling interests	—			(14		)	—			(22		)
Net income attributable to common stockholders	$	1		$	337		$	124		$	438

Basic earnings per share attributable to common stockholders:
Income from continuing operations	$	0.41		$	2.37		$	1.44		$	3.03
Income (loss) from discontinued operations	(0.40		)	0.05			(0.58		)	0.21
Net income	$	0.01		$	2.42		$	0.86		$	3.24
Diluted earnings per share attributable to common stockholders:
Income from continuing operations	$	0.41		$	2.35		$	1.44		$	2.95
Income (loss) from discontinued operations	(0.40		)	0.05			(0.58		)	0.24
Net income	$	0.01		$	2.40		$	0.86		$	3.19
Weighted average shares outstanding:
Basic	143			138			143			133
Diluted	143			139			143			136
Dividends declared per share	$	—		$	—		$	0.04		$	0.04

Amounts attributable to common stockholders:
Income from continuing operations	$	58		$	326		$	207		$	411
Income (loss) from discontinued operations, net of tax	(57		)	11			(83		)	27
Net income	$	1		$	337		$	124		$	438

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENT OF EQUITY

(in millions, except dividends per share)

(Unaudited)



		Equity Attributable To Common Stockholders
	Shares Outstanding	Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Noncontrolling Interests			Total Equity
Balance as of December 31, 2013	143	$	1	$	5,080		$	(144	)	$	1,665		$	13		$	6,615
Dividends declared ($0.04 per share)	—	—		—			—			(5		)	—			(5		)
Exercise of long-term incentive plan stock options	—	—		2			5			—			—			7
Purchases of treasury stock	—	—		—			(33		)	—			—			(33		)
Sendero divestiture	—	—		—			—			—			(4		)	(4		)
Tax benefits related to stock-based compensation	—	—		4			—			—			—			4
Pioneer Southwest merger transaction costs	—	—		(1		)	—			—			—			(1		)
Compensation costs included in net income	—	—		43			—			—			—			43
Net income	—	—		—			—			124			—			124
Balance as of June 30, 2014	143	$	1	$	5,128		$	(172	)	$	1,784		$	9		$	6,750

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(Unaudited)



	Six Months Ended June 30,
	2014			2013
Cash flows from operating activities:
Net income	$	124		$	460
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	469			437
Impairment of inventory and other property and equipment	4			4
Exploration expenses, including dry holes	10			1
Deferred income taxes	69			219
Gain on disposition of assets, net	(10		)	(207		)
Accretion of discount on asset retirement obligations	6			6
Discontinued operations	166			60
Interest expense	9			9
Derivative related activity	298			(14		)
Amortization of stock-based compensation	43			34
Other	28			(8		)
Change in operating assets and liabilities:
Accounts receivable, net	(59		)	(33		)
Income taxes receivable	(2		)	7
Inventories	(8		)	(1		)
Prepaid expenses	2			(10		)
Other current assets	(4		)	3
Accounts payable	30			(9		)
Interest payable	—			(7		)
Income taxes payable	1			1
Other current liabilities	7			(15		)
Net cash provided by operating activities	1,183			937
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	369			675
Additions to oil and gas properties	(1,362		)	(1,388		)
Additions to other assets and other property and equipment, net	(110		)	(101		)
Net cash used in investing activities	(1,103		)	(814		)
Cash flows from financing activities:
Borrowings under long-term debt	325			419
Principal payments on long-term debt	(325		)	(1,323		)
Proceeds from issuance of common stock, net of issuance costs	—			1,281
Distributions to noncontrolling interests	—			(18		)
Exercise of long-term incentive plan stock options	7			4
Purchases of treasury stock	(33		)	(19		)
Excess tax benefits from share-based payment arrangements	4			6
Dividends paid	(6		)	(6		)
Net cash provided by (used in) financing activities	(28		)	344
Net increase in cash and cash equivalents	52			467
Cash and cash equivalents, beginning of period	393			229
Cash and cash equivalents, end of period	$	445		$	696

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

NOTE A. Organization and Nature of Operations

Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company operating in the United States, with continuing field operations primarily in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Raton field in southeastern Colorado, the Hugoton field in southwest Kansas and the West Panhandle field in the Texas Panhandle.

NOTE B. Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2014 and for the three and six months ended June 30, 2014 and 2013 include all adjustments and accruals, consisting only of normal, recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed in or omitted from this report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2013.

Certain reclassifications have been made to the 2013 financial statement and footnote amounts in order to conform to the 2014 presentation.

New accounting pronouncements. In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of 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 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2016 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified approach to adopt ASU 2014-09. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements or decided upon the method of adoption.

In April 2014, the FASB issued ASU 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 prospectively changes the criteria for reporting discontinued operations while enhancing disclosures around disposals of assets whether or not the disposal meets the definition of a discontinued operation. ASU 2014-08 is effective for annual and interim periods beginning after December 31, 2014 with early adoption permitted but only for disposals that have not been reported in financial statements previously issued. The adoption of this new guidance is not expected to have a material impact on the Company's consolidated financial statements.

NOTE C. Acquisitions and Divestitures

Divestitures Recorded in Continuing Operations

For the three and six months ended June 30, 2014, the Company recorded net gains on disposition of assets in continuing operations of $4 million and $10 million, respectively, as compared to $183 million and $207 million for the same respective periods in 2013. The net gains attributable to the disposition of assets were primarily comprised of the following:


•	Vertical drilling rigs. During December 2013, the Company committed to a plan to sell the Company's majority interest in Sendero Drilling Company, LLC ("Sendero") to Sendero's minority interest owner. At December 31, 2013, the assets and liabilities of Sendero were classified as held for sale at their estimated fair value. In March 2014, the Company

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

completed the sale of Sendero for cash proceeds of $31 million and recognized a gain of $1 million associated with the completion of the sale. As part of the sales agreement, the Company committed to lease from Sendero 12 vertical rigs through December 31, 2015, and eight vertical rigs in 2016.


•	Permian Basin. During February 2014, the Company completed the sale of proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for net cash proceeds of $72 million, which resulted in a gain of $2 million on the unproved property.

•

Southern Wolfcamp. In May 2013, the Company completed the sale of 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas to Sinochem Petroleum USA LLC ("Sinochem") for net cash proceeds of $624 million, which resulted in a gain of $181 million related to the unproved property interests conveyed to Sinochem. Sinochem is paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the southern portion of the horizontal Wolfcamp Shale play.


•	West Panhandle. During the first quarter of 2013, the Company completed a sale of its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for net cash proceeds of $38 million, which resulted in a gain of $22 million.

Divestitures Recorded as Discontinued Operations

Alaska. During the fourth quarter of 2013, the Company committed to a plan to sell 100 percent of the capital stock in Pioneer's Alaska subsidiary ("Pioneer Alaska"). In April 2014, the Company completed the sale of Pioneer Alaska to an unaffiliated third party pursuant to an amended purchase and sale agreement for net proceeds of $267 million, including normal closing and other adjustments.

The Company has classified Pioneer Alaska's results of operations as income (loss) from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

Barnett Shale. During the fourth quarter of 2013, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas. In August 2014, the Company signed a purchase and sale agreement with an unaffiliated third party for $155 million, before normal closing adjustments. Based on the terms of the purchase and sale agreement, the Company expects to close the sale of the Barnett Shale net assets during the third quarter of 2014. The Company has classified its (i) Barnett Shale assets and liabilities as held for sale in the accompanying consolidated balance sheets and (ii) Barnett Shale results of operations as income (loss) from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

Based upon the estimated sales price for the Barnett Shale net assets at June 30, 2014, the Company recorded an additional noncash impairment charge of $114 million in discontinued operations during the three months ended June 30, 2014 to reduce the carrying value of the Barnett Shale net assets to their estimated sales value. See Note D for additional information about the Barnett Shale impairment charge.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

The following table represents the components of the Company's discontinued operations for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)
Revenues and other income:
Oil and gas	$	40		$	64		$	107		$	123
Interest and other (a)	—			6			29			26
Gain on disposition of assets, net	5			8			5			8
	45			78			141			157
Costs and expenses:
Oil and gas production	11			26			29			46
Production and ad valorem taxes	2			3			4			6
Depletion, depreciation and amortization	—			24			—			43
Impairment of oil and gas properties	114			—			225			—
Exploration and abandonments	1			5			2			15
General and administrative	1			1			3			2
Other	4			—			7			—
	133			59			270			112
Income (loss) from discontinued operations before income taxes	(88		)	19			(129		)	45
Current tax provision	—			(2		)	(1		)	(4		)
Deferred tax (provision) benefit	31			(6		)	47			(14		)
Income (loss) from discontinued operations	$	(57	)	$	11		$	(83	)	$	27

____________________


(a)	Primarily comprised of cash received associated with Alaskan Petroleum Production Tax credits on qualifying capital expenditures.

The carrying values of the Company's ownership in the Barnett Shale field as of June 30, 2014, and the carrying values of the Company's ownership in Pioneer Alaska, the Barnett Shale field and Sendero as of December 31, 2013, were included in assets and liabilities held for sale in the accompanying consolidated balance sheet and were comprised of the following:



	June 30, 2014		December 31, 2013
	(in millions)
Composition of assets included in assets held for sale:
Current assets	$	25	$	58
Property, plant and equipment	168		526
Total assets	$	193	$	584

Composition of liabilities included in liabilities held for sale:
Current liabilities	$	41	$	29
Other liabilities	4		10
Total liabilities	$	45	$	39

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

NOTE D. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:


•	Level 1 – quoted prices for identical assets or liabilities in active markets.


•	Level 2 – quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.


•	Level 3 – unobservable inputs for the asset or liability.

Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

The following table presents the Company's assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2014 for each of the fair value hierarchy levels:



	Fair Value Measurement at the End of the Reporting Period Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Fair Value at June 30, 2014
	(in millions)
Recurring fair value measurements
Assets:
Commodity derivatives	$	—	$	11		$	—	$	11
Deferred compensation plan assets	71		—			—		71
Total assets	71		11			—		82
Liabilities:
Commodity derivatives	—		164			—		164
Total liabilities	—		164			—		164
Total recurring fair value measurements	$	71	$	(153	)	$	—	$	(82	)

Deferred compensation plan assets. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on observable prices on major exchanges. As of June 30, 2014, the significant inputs to these asset values represented Level 1 independent active exchange market price inputs.

Commodity derivatives. The Company's commodity derivatives represent oil, natural gas liquids ("NGL") and gas swap contracts, collar contracts and collar contracts with short puts. The asset and liability measurements for the Company's commodity derivative contracts represent Level 2 inputs in the hierarchy. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives.

The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs that include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and collar contracts with short puts, which is based on active and independent market-quoted volatility factors.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventory, proved and unproved oil and gas properties that are written down to fair value when they are impaired and assets and liabilities associated with other long-lived assets that have been reduced to fair value when they are impaired or held for sale.

Assets classified as held for sale. The Company records assets and liabilities associated with long-lived assets that are classified as held for sale at the lower of the asset's net carrying amount or estimated fair value less costs to sell. At June 30, 2014, the fair value of the Barnett Shale field assets was based upon its estimated sales price, including normal closing adjustments, less costs to sell. Associated therewith, the Company recognized a $114 million impairment charge during the second quarter to reduce the carrying value of the Barnett Shale field assets to their estimated sales price. See Note C for additional information regarding the Company's planned divestiture of its Barnett Shale field assets.

At March 31, 2014, the fair value of the Barnett Shale field assets was based upon a probability weighted average calculation that used management inputs including an estimated sales price and a discounted cash flow model for the proved properties using Level 3 assumptions including (i) management's longer-term commodity price outlooks ("Management's Price Outlooks") for oil and gas prices of $81.58 per barrel ("BBL") for oil and $4.64 per million British thermal units ("MMBTU") for gas, and management's outlooks for (ii) production costs, (iii) capital expenditures, (iv) production and (v) estimated proved reserves. Management's Price Outlooks represent longer-term expectations of oil and gas prices that are developed based on third-party futures price outlooks as of a measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

At March 31, 2014, the fair value of Pioneer Alaska was based upon an agreed sales price, including normal closing adjustments, less estimated costs to sell.

The following table presents each of the fair value adjustments made by the Company during 2014 related to assets that were classified as discontinued operations held for sale:



		Estimated Fair Value Less Costs to Sell		Fair Value Adjustment
		(in millions)
Barnett Shale field	June 2014	$	148	$	(114	)
Barnett Shale field	March 2014	$	208	$	(14	)
Alaska	March 2014	$	253	$	(97	)

Inventories. During the three and six months ended June 30, 2014, the Company recorded an impairment charge of $4 million to reduce the carrying value of its excess vertical well pipe inventory. The Company calculated the estimated fair value of the inventory using significant Level 2 assumptions based on third-party price quotes for the asset in an active market. The impairment charge is included in other expense on the Company's accompanying consolidated statements of operations.

Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets as of June 30, 2014 and December 31, 2013 are as follows:



	June 30, 2014				December 31, 2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in millions)
Long-term debt	$	2,659	$	3,058	$	2,653	$	3,019

Long-term debt includes the Company's credit facility and the Company's senior notes. The fair value of debt is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

Credit facility. The fair value of the Company's credit facility is calculated using a discounted cash flow model based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted United States Treasury Bill rates and (iii) the applicable credit-adjustments.

Senior notes. The Company's senior notes represent debt securities that are traded on major exchanges but are not actively traded. The fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges.

The Company has other financial instruments consisting primarily of cash equivalents, receivables, prepaid expenses, payables and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities. Non-financial assets and liabilities initially measured at fair value include certain assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations.

NOTE E. Derivative Financial Instruments

The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness.

Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices. The Company uses derivative contracts to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX prices and actual index prices at which the oil is sold.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of June 30, 2014 and the weighted average oil prices for those contracts:



	Six Months Ending December 31,		Year Ending December 31,
	2014		2015		2016
Collar contracts with short puts:
Volume (BBL) (a)(b)	69,000		95,767		54,000
Price per BBL:
Ceiling	$	114.05	$	99.36	$	98.36
Floor	$	93.70	$	87.98	$	85.83
Short put	$	77.61	$	73.54	$	74.26
Swap contracts:
Volume (BBL)	12,500		—		—
Price per BBL	$	95.33	$	—	$	—
Rollfactor swap contracts:
Volume (BBL)	10,000		5,000		—
NYMEX roll price (c)	$	1.10	$	0.60	$	—

____________________

(a)

Counterparties have the option to extend for an additional year 5,000 BBLs per day of 2015 collar contracts with short puts with a ceiling price of $100.08 per BBL, a floor price of $90.00 per BBL and a short put price of $80.00 per BBL. The option to extend is exercisable on December 31, 2015. These contracts give the counterparties the option to extend the contracts under the same terms for an additional year if the option to extend is exercised by the counterparties on December 31, 2015.


(b)	Subsequent to June 30, 2014, the Company entered into additional collar contracts with short puts for 4,000 BBL per day of the Company's 2016 production with a ceiling price of $100.73 per BBL, a floor price of $90.00 per BBL and a short put price of $80.00 per BBL.


(c)	Represents swaps that fix the difference between (i) each day's price per BBL of WTI for the first nearby month less (ii) the price per BBL of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per BBL of WTI for the first nearby month less (iv) the price per BBL of WTI for the third nearby NYMEX month, multiplied by .3333.

NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities' NGL component product prices.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of June 30, 2014 and the weighted average NGL prices for those contracts:



	Six Months Ending December 31,
	2014
Collar contracts with short puts (a):
Volume (BBL)	3,500
Price per BBL:
Ceiling	$	97.93
Floor	$	90.14
Short put	$	81.36
Collar contracts (b):
Volume (BBL)	3,000
Price per BBL:
Ceiling	$	13.72
Floor	$	10.78
Swap contracts (c):
Volume (BBL)	2,337
Average price per BBL	$	48.11

____________________


(a)	Represent collar contracts with short puts that reduce the price volatility of natural gasoline forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.


(b)	Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.


(c)	Represent swap contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.

Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to NYMEX Henry Hub ("HH") gas prices or regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and basis swap contracts to reduce basis risk between HH prices and actual index prices at which the gas is sold.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of June 30, 2014 and the weighted average gas prices for those contracts:



	Six Months Ending December 31,			Year Ending December 31,
	2014			2015			2016
Collar contracts with short puts:
Volume (MMBTU)	115,000			285,000			20,000
Price per MMBTU:
Ceiling	$	4.70		$	5.07		$	5.36
Floor	$	4.00		$	4.00		$	4.00
Short put	$	3.00		$	3.00		$	3.00
Swap contracts:
Volume (MMBTU)	195,000			20,000			—
Price per MMBTU	$	4.04		$	4.31		$	—
Basis swap contracts:
Volume (MMBTU) (a)	130,000			90,000			—
Price per MMBTU	$	(0.21	)	$	(0.22	)	$	—

____________________


(a)	Subsequent to June 30, 2014, the Company entered into additional basis swap contracts for 20,000 MMBTU per day for August 2014 and 40,000 MMBTU per day for September 2014 with respective price differentials of $0.38 per MMBTU and $0.39 per MMBTU between Permian Basin index prices and southern California index prices.

Marketing and basis transfer derivative activities. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of June 30, 2014, the Company had marketing gas index swap contracts for 40,000 MMBTU per day for the remainder of 2014 with a price differential of $0.31 per MMBTU between Permian Basin index prices and southern California index prices.

Interest rate derivative activities. During the three months ended June 30, 2014, the Company terminated its interest rate derivative contracts for cash proceeds of $14 million. Prior to termination, the Company received a fixed interest rate of 3.95 percent in exchange for paying a floating interest rate comprised of the three-month LIBOR plus an average rate of 1.11 percent on a notional amount of $400 million.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

The aggregate fair value of the Company's derivative instruments reported in the consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following:



Fair Value of Derivative Instruments as of June 30, 2014
Type	Consolidated Balance Sheet Location	Fair Value		Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
		(in millions)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	14	$	(13	)	$	1
Commodity price derivatives	Derivatives - noncurrent	$	20	$	(10	)	10
							$	11
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	111	$	(13	)	$	98
Commodity price derivatives	Derivatives - noncurrent	$	76	$	(10	)	66
							$	164



Fair Value of Derivative Instruments as of December 31, 2013
Type	Consolidated Balance Sheet Location	Fair Value		Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
		(in millions)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	73	$	(7	)	$	66
Interest rate derivatives	Derivatives - current	$	10	$	—		10
Commodity price derivatives	Derivatives - noncurrent	$	95	$	(4	)	91
Interest rate derivatives	Derivatives - noncurrent	$	15	$	(15	)	—
							$	167
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	19	$	(7	)	$	12
Commodity price derivatives	Derivatives - noncurrent	$	4	$	(4	)	—
Interest rate derivatives	Derivatives - noncurrent	$	25	$	(15	)	10
							$	22

The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company's credit risk policies and procedures.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

The following table details the location of gains and losses recognized on the Company's derivative contracts in the accompanying consolidated statements of operations:




Derivatives Not Designated as Hedging	Location of Gain / (Loss) Recognized in	Three Months Ended June 30,					Six Months Ended June 30,
Instruments	Earnings on Derivatives	2014			2013		2014			2013
		(in millions)
Commodity price derivatives	Derivative gains (losses), net	$	(226	)	$	138	$	(340	)	$	92
Interest rate derivatives	Derivative gains (losses), net	8			6		18			10
Total		$	(218	)	$	144	$	(322	)	$	102

NOTE F. Exploratory Costs

The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

The following table reflects the Company's capitalized exploratory well and project activity during the three and six months ended June 30, 2014:



	Three Months Ended June 30, 2014			Six Months Ended June 30, 2014
	(in millions)
Beginning capitalized exploratory costs	$	248		$	159
Additions to exploratory costs pending the determination of proved reserves	382			689
Reclassification due to determination of proved reserves	(265		)	(475		)
Disposition of assets	(36		)	(36		)
Impairment of properties	(4		)	(11		)
Exploratory well costs charged to exploration expense	(3		)	(4		)
Ending capitalized exploratory costs (a)	$	322		$	322

_______________


(a)	Includes $5 million of capitalized exploratory well costs classified as held for sale in the accompanying consolidated balance sheet as of June 30, 2014.

The following table provides an aging, as of June 30, 2014 and December 31, 2013, of capitalized exploratory costs and the number of projects for which exploratory costs have been capitalized for a period greater than one year based on the date drilling was completed:



	June 30, 2014		December 31, 2013
	(in millions, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	316	$	116
More than one year	6		43
	$	322	$	159

Number of projects with exploratory costs that have been suspended for a period greater than one year	2		1

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

At June 30, 2014, the $6 million of suspended well costs that have been suspended for a period greater than one year are comprised of two wells in eastern Colorado that were drilled as stratigraphic test wells. The costs are capitalized pending the results of further drilling operations in the area during the second half of 2014. The $43 million of suspended well costs suspended for a period greater than one year at December 31, 2013 related to Pioneer Alaska, which was sold in April 2014. See Note C for additional information on the sale of Pioneer Alaska.

NOTE G. Long-term Debt

The Company's long-term debt consists of senior notes and a revolving corporate credit facility (the "Credit Facility"), including the effects of net deferred fair value hedge losses and issuance discounts. The Credit Facility is maintained with a syndicate of financial institutions and has aggregate loan commitments of $1.5 billion that expire in December 2017. As of June 30, 2014, the Company had no outstanding borrowings under the Credit Facility and was in compliance with all of its debt covenants.

NOTE H. Incentive Plans

Stock-based compensation

For the three and six months ended June 30, 2014, the Company recorded $33 million and $62 million, respectively, of stock-based compensation expense for all plans, as compared to $25 million and $53 million for the same respective periods of 2013. As of June 30, 2014, there was $193 million of unrecognized compensation expense related to unvested share-based compensation plan awards, including $58 million attributable to stock-based awards that are expected to be settled on their vesting date in cash, rather than in equity shares ("Liability Awards"). The unrecognized compensation expense will be recognized over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. As of June 30, 2014 and December 31, 2013, accounts payable – due to affiliates includes $19 million and $33 million, respectively, of liabilities attributable to Liability Awards.

The following table summarizes the activity that occurred during the six months ended June 30, 2014, for each type of share-based incentive award issued by Pioneer:



	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units		Stock Options
Outstanding as of December 31, 2013	1,371,207		422,382		134,476		289,927
Awards granted	390,998		132,803		67,182		—
Awards vested	(429,365	)	(187,203	)	(898	)	—
Options exercised	—		—		—		(80,869	)
Awards forfeited	(42,854	)	(18,278	)	(1,078	)	—
Outstanding as of June 30, 2014	1,289,986		349,704		199,682		209,058

Postretirement Benefit Obligations

As of June 30, 2014 and December 31, 2013, the Company had $6 million and $8 million, respectively, of unfunded accumulated postretirement benefit obligations. These obligations are comprised of five unfunded plans, of which four relate to predecessor entities that the Company acquired in prior years. Other than the Company's retirement plan, the participants of these plans are not current employees of the Company. The plans had no assets as of June 30, 2014 or December 31, 2013.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

NOTE I. Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and facilities. The following table summarizes the Company's asset retirement obligation activity during the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)
Beginning asset retirement obligations	$	194		$	191		$	194		$	198
New wells placed on production	1			1			2			2
Changes in estimates	—			(1		)	1			(6		)
Dispositions	—			—			(1		)	(4		)
Liabilities settled	(5		)	(3		)	(9		)	(5		)
Accretion of discount	3			3			6			6
Ending asset retirement obligations	$	193		$	191		$	193		$	191

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of June 30, 2014 and December 31, 2013, the current portions of the Company's asset retirement obligations were both $19 million.

NOTE J. Commitments and Contingencies

The Company is a party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

NOTE K. Interest and Other Income

The following table provides the components of the Company's interest and other income for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)
Other income	$	5		$	2		$	6		$	4
Equity interest in income of EFS Midstream (a)	3			3			6			6
Deferred compensation plan income	—			—			2			2
Loss from vertical integration services (b)	(5		)	(10		)	(7		)	(17		)
Total interest and other income	$	3		$	(5	)	$	7		$	(5	)

____________________


(a)	The Company accounts for its investment in EFS Midstream LLC ("EFS Midstream") using the equity method. EFS Midstream is providing gathering, treating and transportation services for the Company during a 20-year contractual term.

(b)

Loss from vertical integration services primarily represents net margins that result from Company-provided fracture stimulation and related service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three and six months ended June 30, 2014, these net margins included $104 million and $196 million of gross vertical integration revenues, respectively, and $109 million and $203 million of total vertical integration costs and expenses, respectively. For the same periods in 2013, these net margins included $47 million and $103 million of gross vertical integration revenues, respectively, and $57 million and $120 million of total vertical integration costs and expenses, respectively.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

NOTE L. Other Expense

The following table provides the components of the Company's other expense for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in millions)
Transportation commitment charge (a)	$	12	$	9	$	23	$	19
Other	6		6		9		10
Impairment of inventory (b)	4		1		4		2
Contingency and environmental accrual adjustments	—		1		2		2
Above market and idle drilling and well services equipment charges (c)	—		5		—		8
Terminated drilling rig contract charges	—		—		—		1
Total other expense	$	22	$	22	$	38	$	42

____________________


(a)	Primarily represents firm transportation payments on excess pipeline capacity commitments.


(b)	Represents charges to reduce excess material and supplies inventories to their market values. See Note D for additional information on the fair value of materials and supplies inventory.


(c)	Primarily represents expenses attributable to the portion of the Company's contracted rig rates that were above market rates and idle rig fees, neither of which were chargeable to joint operations.

NOTE M. Income Taxes

The Company's income tax provisions attributable to income from continuing operations consisted of the following for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in millions)
Current	$	6	$	7	$	18	$	14
Deferred	28		176		69		219
Income tax provision	$	34	$	183	$	87	$	233

For the three and six months ended June 30, 2014, the Company's effective tax rates, excluding income attributable to the noncontrolling interest, were 37 percent and 30 percent, respectively, as compared to effective rates of 36 percent for each of the same respective periods in 2013. The Company's 2014 effective tax rates differed from the U.S. statutory rate of 35 percent primarily due to state income tax apportionments, nondeductible expenses and, for the six months ended June 30, 2014, the recognition of a $21 million tax benefit resulting from the resolution during the first quarter of 2014 of the tax uncertainty related to net operating loss carryovers and alternative minimum tax credits obtained from the 2012 acquisition of Premier Silica. There are no unrecognized tax benefits as of June 30, 2014.

The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. The Internal Revenue Service has closed examinations of the 2012 and prior tax years and, with few exceptions, the Company believes that it is no longer subject to examinations by state and foreign tax authorities for years before 2008. As of June 30, 2014, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company's liquidity, future results of operations or financial position.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014

(Unaudited)

NOTE N. Net Income Per Share

The following table reconciles the Company's net income from continuing operations attributable to common stockholders to basic and diluted net income from continuing operations attributable to common stockholders for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30,					Six Months Ended June 30,
	2014		2013			2014			2013
	(in millions)
Net income from continuing operations attributable to common stockholders	$	58	$	326		$	207		$	411
Participating basic earnings	—		(4		)	(1		)	(5		)
Basic and diluted income from continuing operations attributable to common stockholders	$	58	$	322		$	206		$	406

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30,		Six Months Ended June 30,
	2014	2013	2014	2013
	(in millions)
Weighted average common shares outstanding:
Basic	143	138	143	133
Dilution attributable to convertible senior notes	—	1	—	3
Diluted (a)	143	139	143	136

____________________


(a)	Options to purchase 5,707 and 52,263 shares of the Company's common stock were excluded from the diluted income per share calculations for the three and six months ended June 30, 2013, respectively, because they would have been anti-dilutive to the calculation.

NOTE O. Subsequent Events

Divestitures. As discussed in Note C, in August 2014 the Company signed a purchase and sale agreement with an unaffiliated third party to sell its net assets in the Barnett Shale field in North Texas for $155 million, before normal closing adjustments.

In July 2014, the Company entered into a purchase and sale agreement with an unaffiliated third party to sell its net assets in the Hugoton field in southwest Kansas for cash proceeds of $340 million, before normal closing adjustments. Closing of the transaction is expected to occur during the third quarter of 2014 and is subject to customary closing conditions. Associated with the sale of the Hugoton field, the Company expects to record a pretax noncash loss of approximately $20 million during the three months ended September 30, 2014. The financial and operating results of the Hugoton field activities for the quarter ending September 30, 2014 and all prior periods presented in future filings are expected to be reflected as discontinued operations. No impairment of the net assets of the Hugoton field was recorded as of June 30, 2014 due to (i) the probability-weighted undiscounted cash flows of the Hugoton field net assets exceeding their carrying value at June 30, 2014 and (ii) the uncertainty regarding the willingness of third parties to purchase the Hugoton field net assets on terms and at a price acceptable to the Company, which precluded held for sale criteria as of June 30, 2014.

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

Financial and Operating Performance

The Company's financial and operating performance for the second quarter of 2014 included the following highlights:

•

Net income attributable to common stockholders for the second quarter of 2014 was $1 million ($0.01 per diluted share), as compared to net income of $337 million ($2.40 per diluted share) for the second quarter of 2013. The decrease in net income attributable to common stockholders is comprised of a $268 million decrease in net income from continuing operations and a $68 million decrease in income from discontinued operations, net of tax.

The primary components of the decrease in net income from continuing operations include:


•	a $362 million increase in net derivative losses, primarily as a result of increases in forward commodity prices and changes in the Company's portfolio of derivatives;


•	a $179 million decrease in gain on disposition of assets, primarily due to the $181 million gain related to the Company's unproved property interests that were conveyed to Sinochem in the second quarter of 2013;


•	a $28 million increase in total oil and gas production costs and production and ad valorem taxes, primarily associated with a 12 percent increase in sales volumes;


•	a $23 million increase in DD&A expense, primarily attributable to a 12 percent increase in sales volumes;


•	a $16 million increase in general and administrative expense, primarily due to increased personnel, occupancy and information technology costs resulting from the growth in employee headcount in support of the Company's capital expansion initiatives; and


•	an $11 million increase in exploration and abandonment expense, primarily attributable to the acquisition costs for seismic data covering portions of the Company's Spraberry/Wolfcamp acreage position; partially offset by


•	a $178 million increase in oil and gas revenues as a result of a 12 percent increase in sales volumes and a 10 percent increase in the average commodity prices received per BOE; and


•	a $149 million decrease in the Company's income tax provision as a result of the Company's decrease in income from continuing operations before taxes.

The primary components of the decrease in income from discontinued operations, net of tax, include:


•	a $114 million impairment charge to reduce the carrying value of the Company's Barnett Shale field assets to their estimated sales value less costs to sell;


•	a $33 million decrease in revenues and other income due to the sale of Pioneer Alaska in April 2014; partially offset by


•	a $24 million decrease in depletion, depreciation and amortization due to the assets of the Barnett Shale field and Pioneer Alaska being classified as held for sale at December 31, 2013;


•	a $15 million decrease in oil and gas production costs due to the sale of Pioneer Alaska in April 2014; and


•	a $39 million change in the Company's income taxes attributable to discontinued operations as a result of the loss from discontinued operations before taxes.

•

During the second quarter of 2014, average daily sales volumes from continuing operations increased by 12 percent to 182,747 BOEPD, as compared to 163,443 BOEPD during the second quarter of 2013. The increase in second quarter 2014 average daily sales volumes, as compared to the second quarter of 2013, is primarily due to the Company's successful Spraberry/Wolfcamp and Eagle Ford Shale drilling programs.


•	Average oil, NGL and gas prices increased during the second quarter of 2014 to $95.87 per BBL, $30.65 per BBL and $4.38 per MCF, respectively, as compared to $90.35 per BBL, $28.54 per BBL and $3.76 per MCF, respectively, in the second quarter of 2013.


•	Net cash provided by operating activities increased to $718 million for the three months ended June 30, 2014, as compared to $576 million for the three months ended June 30, 2013. The $142 million increase in net cash provided by operating activities is primarily due to an increase in sales volumes and commodity prices, partially offset by a decrease in net cash flows from derivative settlements.


•	As of both June 30, 2014 and December 31, 2013, the Company's net debt to book capitalization was 25 percent.

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Recent Developments

Divestitures

During the fourth quarter of 2013, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas. In August 2014 the Company signed a purchase and sale agreement with an unaffiliated third party for $155 million, before normal closing adjustments. The Company anticipates that the divestiture will close in the third quarter of 2014 and is subject to customary closing conditions.

In July 2014, the Company entered into a purchase and sale agreement with an unaffiliated third party to sell its net assets in the Hugoton field in southwest Kansas for cash proceeds of $340 million, before normal closing adjustments. Closing of the transaction is expected to occur during the third quarter of 2014 and is subject to customary closing conditions. Associated with the sale of the Hugoton field, the Company expects to record a pretax noncash loss of approximately $20 million during the three months ended September 30, 2014. The financial and operating results of the Hugoton field activities for the quarter ending September 30, 2014 and all prior periods presented in future filings are expected to be reflected as discontinued operations. See Note O of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information about the sale of the Hugoton field.

Third Quarter 2014 Outlook

Based on current estimates, the Company expects the following operating and financial results from continuing operations for the quarter ending September 30, 2014:

Production is forecasted to average 181,000 to 186,000 BOEPD.

Production costs (including production and ad valorem taxes and transportation costs) are expected to average $13.50 to $15.50 per BOE based on current NYMEX strip commodity prices. DD&A expense is expected to average $14.00 to $16.00 per BOE.

Total exploration and abandonment expense is expected to be $25 million to $35 million. General and administrative expense is expected to be $80 million to $85 million. Interest expense is expected to be $47 million to $52 million, and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $3 million to $5 million.

The Company's effective income tax rate is expected to range from 35 percent to 40 percent assuming current capital spending plans and no significant mark-to-market changes in the Company's derivative position. Cash income taxes are expected to range from $10 million to $15 million and are primarily attributable to federal alternative minimum tax and state taxes.

Operations and Drilling Highlights

The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during the six months ended June 30, 2014:



	Oil (BBLs)	NGLs (BBLs)	Gas (MCF)	Total (BOE)
Permian Basin	58,153	18,619	78,457	89,849
South Texas - Eagle Ford Shale	17,228	12,915	86,714	44,595
Raton Basin	—	—	125,762	20,960
Mid-Continent	3,010	7,003	38,593	16,445
South Texas - Other	792	9	28,230	5,506
Other	5	2	79	20
Total continuing operations	79,188	38,548	357,835	177,375
Barnett Shale	2,138	3,639	27,097	10,293
Alaska	2,018	—	—	2,018
Total including discontinued operations	83,344	42,187	384,932	189,686

During 2014 and 2013, the Company has focused its capital budgets and expenditures on oil and liquids-rich gas drilling activities due to relatively lower gas prices. As a result of these capital activities, the Company's total liquids production from continuing operations increased to 66 percent of total production, on a BOE basis, for the six months ended June 30, 2014, as compared to 62 percent for the same period last year. The Company's liquids revenue as a percent of total commodity sales was

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84 percent for the six months ended June 30, 2014, as compared to 85 percent for the same period last year, due to a 32 percent increase in the average gas price relative to increases of six percent and eight percent in the average oil and NGL prices, respectively.

The following table summarizes by geographic area the Company's finding and development costs incurred during the six months ended June 30, 2014:



	Acquisition Costs				Exploration			Development		Asset Retirement
	Proved		Unproved		Costs			Costs		Obligations		Total
	(in millions)
Permian Basin	$	1	$	5	$	441		$	588	$	—	$	1,035
South Texas - Eagle Ford Shale	—		—		176			121		1		298
Raton Basin	—		—		2			15		—		17
Mid-Continent	—		—		2			4		—		6
South Texas - Other	—		—		15			7		—		22
Other	—		1		4			—		—		5
Total continuing operations	1		6		640			735		1		1,383
Barnett Shale	3		3		97			22		—		125
Alaska	—		—		(1		)	48		4		51
Total including discontinued operations	$	4	$	9	$	736		$	805	$	5	$	1,559

The following table summarizes the Company's development and exploration/extension drilling activities for the six months ended June 30, 2014:



	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Wells Sold	Ending Wells in Progress
Permian Basin	59	140	151	4	44
South Texas - Eagle Ford Shale	16	20	22	—	14
Total continuing operations	75	160	173	4	58
Barnett Shale	1	—	1	—	—
Alaska	4	1	—	5	—
Total including discontinued operations	80	161	174	9	58



	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Wells Sold	Ending Wells in Progress
Permian Basin	31	109	51	—	1	88
South Texas - Eagle Ford Shale	24	51	35	—	—	40
South Texas - Other	—	8	6	—	—	2
Other	3	—	—	1	—	2
Total continuing operations	58	168	92	1	1	132
Barnett Shale	17	35	36	—	—	16
Alaska	2	—	—	—	2	—
Total including discontinued operations	77	203	128	1	3	148

Permian Basin area. The Company successfully completed 202 wells in the Permian Basin area during the first six months of 2014. During 2014, the Company expects to place on production approximately 200 vertical wells and to drill approximately 255 horizontal wells, with the horizontal wells being drilled in the Spraberry/Wolfcamp Shale horizons. The Company expects to spend $2.4 billion of drilling capital in the Spraberry/Wolfcamp area during 2014.

The Company believes it has significant resource potential within its acreage based on its extensive geologic data covering the Spraberry and Wolfcamp A, B, C and D intervals and its drilling results to-date. During 2014, the Company expects to drill 130 horizontal wells in the northern portion of the play and 125 horizontal wells in the southern portion of the play, where the Company has its joint venture with Sinochem. The wells in these areas are expected to be drilled on multiple-well pads to gain

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efficiencies; therefore, the wells will not be completed until after the last well on each pad is drilled and, accordingly, production from these wells is not expected until all wells on the pad are ready to produce. With the addition of drilling rigs during the first half of 2014, combined with the effects of pad drilling, the Company continues to expect production growth to be weighted towards the second half of 2014.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval, including the Strawn and Atoka intervals. The Company is reducing its vertical drilling activity from 11 rigs to nine rigs during the second half of 2014, with further reductions expected in 2015. The Company expects to place on production approximately 200 vertical wells that are predominately targeting deeper intervals during 2014. These wells are being drilled to meet continuous drilling obligations.

The Company continues to benefit from its integrated services to control well costs and operating costs in addition to supporting the execution of its drilling and production activities in the Spraberry field. The Company is currently utilizing six Company-owned fracture stimulation fleets totaling approximately 250,000 horsepower in the Spraberry field. To support its operations, the Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, Premier Silica (the Company's wholly-owned sand mining subsidiary) is supplying brown sand for proppant, which is being used by the Company to fracture stimulate vertical and horizontal wells in the Spraberry and Wolfcamp Shale intervals.

During April 2014, the Company extended its gas processing agreement with Atlas Pipeline Partners, L.P. ("Atlas") for an additional 10 years (through 2032) to help ensure adequate gas processing capacity across the Spraberry/Wolfcamp area as the Company increases its drilling activities. Associated with the agreement, Atlas is adding 400 million cubic feet per day of new processing capacity by the second half of 2015, with half of the new capacity coming online during the fourth quarter of 2014 and the other half coming online during the second half of 2015. The Company owns a 27 percent interest in the Atlas gas processing facilities and will fund its share of capital to build these new facilities.

Eagle Ford Shale area. The Company's drilling activities in the South Texas area during 2014 continue to be primarily focused on delineation and development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2014 drilling program has been focused on liquids-rich drilling, with no wells planned to be drilled in dry gas acreage. The Company completed 57 horizontal Eagle Ford Shale wells during the first six months of 2014, all of which were successful, with average lateral lengths of approximately 5,500 feet and, on average, 19-stage fracture stimulations. Of the 57 Eagle Ford Shale wells that were placed on production during the first six months of 2014, the Company placed 17 Upper Eagle Ford interval wells on production and estimates that approximately 25 percent of the Company's acreage is prospective for this interval in the Eagle Ford Shale play. The Company plans to spend $545 million of drilling capital in 2014 to drill approximately 125 Eagle Ford Shale wells. The Company is operating two Pioneer-owned fracture stimulation fleets in the play and supplements with third-party fleets as needed.

In 2013, the Company added approximately 300 drilling locations in the liquids-rich area of the play as a result of downspacing from 1,000 feet between wells (120-acre spacing) to 500 feet (60-acre spacing) between wells. Further downspacing and staggered testing to 175 feet between wells is underway in the liquids-rich areas where the 500-foot spacing was successful. Some areas will include testing of the Lower Eagle Ford Shale only, while others will include a combination of the Lower and Upper Eagle Ford interval tests. Early results from the initial downspacing and staggered tests in the Eagle Ford Shale continue to be encouraging.

The Company's drilling operations in the Eagle Ford Shale continue to focus on improving drilling efficiencies. In 2014, most Eagle Ford Shale wells will be drilled utilizing three-well and four-well pads, which are not completed until after the last well on the pad is drilled and, accordingly, production from these wells is not expected until all wells on the pad are ready to produce. Pad drilling saves the Company a significant amount of capital costs per well, as compared to drilling single-well locations. The Company has also been using lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in all active development areas, including deeper areas of the field. Well performance continues to be similar to direct offset ceramic-stimulated wells. The Company is continuing to monitor the performance of these wells.

During the second quarter of 2014, the Company received confirmation from the U.S. Department of Commerce that condensate processed through distillation units such as those located at several of Pioneer's Eagle Ford Shale central gathering plants in South Texas is a petroleum product that may be exported without a license.

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operations from the Company's Barnett Shale field are reported as discontinued operations, net of tax, in the Company's accompanying consolidated statements of operations.

See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's divestiture of its Barnett Shale assets.

Alaska. During the fourth quarter of 2013, the Company committed to a plan to sell 100 percent of the capital stock in Pioneer Alaska. In April 2014, the Company completed the sale of Pioneer Alaska to an unaffiliated third party pursuant to an amended purchase and sale agreement. Pioneer Alaska's results of operations are reported as discontinued operations, net of tax, in the Company's accompanying consolidated statements of operations.

See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's divestiture of Pioneer Alaska.

Results of Operations from Continuing Operations

Oil and gas revenues. Oil and gas revenues totaled $959 million and $1.9 billion for the three and six months ended June 30, 2014, respectively, as compared to $781 million and $1.5 billion for the same respective periods in 2013.

The increase in oil and gas revenues during the three months ended June 30, 2014, as compared to the same period in 2013, reflected 15 percent and 32 percent increases in daily oil and NGL sales volumes, respectively, and six percent, seven percent and 16 percent increases in average oil, NGL and gas prices, respectively. Partially offsetting the effects of these increases was a two percent decline in gas sales volumes. The increase in oil and gas revenues during the six months ended June 30, 2014, as compared to the same period in 2013, reflected 15 percent and 26 percent increases in daily oil and NGL sales volumes, respectively, and six percent, eight percent and 32 percent increases in average oil, NGL and gas prices, respectively. Partially offsetting the effects of these increases was a three percent decline in gas sales volumes.

The following table provides average daily sales volumes for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30,		Six Months Ended June 30,
	2014	2013	2014	2013
Oil (BBLs)	79,780	69,501	79,188	69,145
NGLs (BBLs)	41,302	31,231	38,548	30,595
Gas (MCF)	369,987	376,267	357,835	368,018
Total (BOEs)	182,747	163,443	177,375	161,076

Average daily BOE sales volumes increased by 12 percent and 10 percent for the three and six months ended June 30, 2014, respectively, as compared to the same respective periods in 2013, principally due to the Company's successful Spraberry/Wolfcamp and Eagle Ford Shale drilling programs.

The oil, NGL and gas prices that the Company reports are based on the market prices received for each commodity. The following table provides the Company's average prices for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Oil (per BBL)	$	95.87	$	90.35	$	94.15	$	89.03
NGL (per BBL)	$	30.65	$	28.54	$	31.91	$	29.67
Gas (per MCF)	$	4.38	$	3.76	$	4.58	$	3.47
Total (per BOE)	$	57.64	$	52.52	$	58.21	$	51.78

Sales of purchased oil and gas. The Company periodically enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company’s areas of production. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to satisfy unused pipeline capacity commitments and to diversify a portion of the Company's WTI oil sales to a Gulf Coast oil price. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming responsibility to deliver the commodities sold. Deficiency payments on excess pipeline capacity commitments are included in other expense in the accompanying consolidated statements

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of operations. See Note L of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for further information on transportation commitment charges.

Interest and other income. Interest and other income for the three and six months ended June 30, 2014 was $3 million and $7 million, respectively, as compared to a loss of $5 million for each of the same respective periods in 2013. The increases in interest and other income for the three and six months ended June 30, 2014, as compared to the same respective periods in 2013, are primarily due to a decrease of $5 million and $10 million, respectively, in the net loss from vertical integration services between the periods. See Note K of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Derivative gains (losses), net. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces, sells and consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. During the three and six months ended June 30, 2014, the Company recorded $218 million and $322 million of net derivative losses on commodity price and interest rate derivatives, of which $6 million and $24 million, respectively, represented net cash payments. During the three and six months ended June 30, 2013, the Company recorded $144 million and $102 million of net derivative gains, which included $34 million and $88 million, respectively, of cash receipts. Derivative gains and losses result from changes in the fair values of the Company's derivative contracts. See Notes D and E of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding the Company's derivative activities and market risks associated with those activities.

Gain on disposition of assets, net. The Company recorded net gains on the disposition of assets of $4 million and $10 million for the three and six months ended June 30, 2014, respectively, as compared to $183 million and $207 million for the same respective periods in 2013.

The net gain for the six months ended June 30, 2014 included the Company's February 2014 sale of proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for net cash proceeds of $72 million, which resulted in a gain of $2 million on the unproved properties. The Company also recognized a $1 million gain during the first quarter of 2014 associated with the sale of Sendero.

The net gain for the three months ended June 30, 2013 is primarily associated with the sale of a 40 percent interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas for net cash proceeds of $624 million, which resulted in a gain of $181 million related to the unproved property interests conveyed to Sinochem. The net gain for the six months ended June 30, 2013 also included the sale of the Company's interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for net cash proceeds of $38 million, which resulted in a gain of $22 million. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's gains and losses on the disposition of assets.

Oil and gas production costs. The Company recorded oil and gas production costs of $173 million and $338 million during the three and six months ended June 30, 2014, respectively, as compared to $153 million and $303 million during the same respective periods in 2013. Lease operating expenses and workover costs represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant charges represent the net costs to gather and process the Company's gas, reduced by net revenues earned from the gathering and processing of third-party gas in Company-owned facilities.

Total oil and gas production costs per BOE for each of the three and six months ended June 30, 2014 increased by one percent as compared to the same respective periods in 2013. The increase in production costs per BOE during the three and six months ended June 30, 2014, as compared to the same respective periods in 2013, is primarily reflective of increases in (i) lease operating expenses and (ii) third-party transportation charges, partially offset by decreases in (i) net natural gas plant charges resulting from increased gathering and processing revenues from processing third-party gas in Company-owned facilities and (ii) workover expenses, primarily related to reduced activity levels.

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The following table provides the components of the Company's oil and gas production costs per BOE for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2013		2014			2013
Lease operating expenses	$	8.15		$	7.62	$	8.22		$	7.65
Third-party transportation charges	1.86			1.56		1.76			1.61
Net natural gas plant charges	(0.16		)	0.16		(0.10		)	0.20
Workover costs	0.57			0.99		0.65			0.93
Total production costs	$	10.42		$	10.33	$	10.53		$	10.39

Production and ad valorem taxes. The Company's production and ad valorem taxes were $59 million and $116 million during the three and six months ended June 30, 2014, respectively, as compared to $51 million and $103 million for the same respective periods in 2013. In general, production and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices.

The following table provides the Company's production and ad valorem taxes per BOE for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Production taxes	2.24		2.13		$	2.28	$	2.17
Ad valorem taxes	$	1.30	$	1.31	1.33		1.35
Total production and ad valorem taxes	$	3.54	$	3.44	$	3.61	$	3.52

Depletion, depreciation and amortization expense. The Company's DD&A expense was $248 million ($14.90 per BOE) and $469 million ($14.60 per BOE) for the three and six months ended June 30, 2014, respectively, as compared to $225 million ($15.17 per BOE) and $437 million ($15.00 per BOE) during the same respective periods in 2013. The decrease in per BOE DD&A expense during the three and six months ended June 30, 2014, as compared to the same periods in 2013, is primarily due to the change in depletion expense.

Depletion expense on oil and gas properties was $14.35 and $14.04 per BOE during the three and six months ended June 30, 2014, respectively, as compared to $14.50 and $14.33 per BOE during the same respective periods in 2013. The one percent and two percent decreases in per BOE depletion expense during the three and six months ended June 30, 2014, as compared to the same respective periods in 2013, are primarily due to the impairment of proved properties in the Raton field during the fourth quarter of 2013, which reduced the Raton field's carrying value by $1.5 billion, partially offset by negative revisions of previous estimates during the fourth quarter of 2013 to remove undeveloped vertical well locations that were no longer expected to be drilled as the Company shifted its planned capital expenditures to higher-rate-of-return horizontal drilling.

Impairment of oil and gas properties. The Company performs assessments of its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. It is reasonably possible that the estimate of undiscounted future net cash flows attributable to its properties may change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of future cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) Management's Price Outlooks and (iv) increases or decreases in production and capital costs associated with these fields.

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Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense for the three and six months ended June 30, 2014 and 2013 (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Geological and geophysical	$	26	$	17	$	50	$	35
Exploratory dry holes	3		—		4		—
Leasehold abandonments and other	—		1		6		1
	$	29	$	18	$	60	$	36

The Company's geological and geophysical costs increased by $9 million and $15 million, respectively, during the three and six months ended June 30, 2014, as compared to the same respective periods in 2013, primarily due to increased seismic and seismic interpretation expenditures supportive of drilling activities in the Spraberry field.

During the six months ended June 30, 2014, the Company drilled and evaluated 129 exploration/extension wells, 128 of which were successfully completed as discoveries. During the same period in 2013, the Company drilled and evaluated 113 exploration/extension wells, 107 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense for the three and six months ended June 30, 2014 was $82 million and $163 million, respectively, as compared to $66 million and $128 million for the same respective periods in 2013. The increases in general and administrative expense for the three and six months ended June 30, 2014, as compared to the same respective periods in 2013, are primarily due to increases in expenses related to personnel, occupancy and information technology in support of the Company's capital expansion initiatives.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $3 million and $6 million for both the three and six months ended June 30, 2014 and 2013, respectively. See Note I of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding the Company's asset retirement obligations.

Interest expense. Interest expense was $47 million and $92 million for the three and six months ended June 30, 2014, respectively, as compared to $43 million and $94 million during the same respective periods in 2013. The weighted average interest rate on the Company's indebtedness for the three and six months ended June 30, 2014, including the effects of capitalized interest, were 6.4 percent and 6.8 percent, respectively, as compared to 6.1 percent and 6.0 percent for the same respective periods in 2013. The $4 million increase in interest expense during the three months ended June 30, 2014, as compared to the three months ended June 30, 2013, is primarily due to the reduction in capitalized interest associated with the Company's Alaska development project that was sold in April 2014. The $2 million decrease in interest expense during the six months ended June 30, 2014, as compared to the six months ended June 30, 2013, is primarily due to a reduction in aggregate debt as a result of the repayment of amounts outstanding under Pioneer Southwest's credit facility in December 2013 and conversions of the Company's convertible senior notes in April 2013, partially offset by the reduction in capitalized interest expense during the second quarter of 2014 due to the sale of Pioneer Alaska in April 2014.

Other expense. Other expense was $22 million and $38 million for the three and six months ended June 30, 2014, respectively, as compared to $22 million and $42 million during the same respective periods in 2013. The decrease in other expense for the six months ended June 30, 2014, as compared to the same period in 2013, is primarily due to an $8 million decrease in above market and idle drilling and well service equipment charges, partially offset by a $4 million increase in transportation commitment charges. See Note L of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Income tax provision. The Company recorded income tax provisions from continuing operations of $34 million and $87 million for the three and six months ended June 30, 2014, respectively, as compared to $183 million and $233 million during the same respective periods in 2013. The Company's effective tax rate for the three and six months ended June 30, 2014 were 37 percent and 30 percent, respectively, as compared to 36 percent for each of the three and six months ended June 30, 2013. The difference between the effective tax rate and the U.S. statutory tax rate of 35 percent during the six months ended June 30, 2014 is primarily due to the recognition of a $21 million tax benefit related to net operating loss carryovers and alternative minimum tax credits obtained from the 2012 acquisition of Premier Silica. See Note M of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's income taxes.

Income/loss from discontinued operations, net of tax. The Company reported losses from discontinued operations, net of tax, of $57 million and $83 million for the three and six months ended June 30, 2014, respectively, as compared to income from

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discontinued operations, net of tax, of $11 million and $27 million for the same respective periods in 2013. The decreases in earnings from discontinued operations for the three and six months ended June 30, 2014, as compared to the same respective periods in 2013, are primarily due to (i) the $114 million and $225 million impairment charges for the three and six months ended June 30, 2014, respectively, to reduce the carrying values of the Company's Barnett Shale field assets and Pioneer Alaska to their estimated sales values less costs to sell. The impairment charges were partially offset by a reduction in DD&A for both the three and six months ended June 30, 2014 due to the Barnett Shale field assets and Pioneer Alaska being classified as held for sale at December 31, 2013. See Note C of the Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for specific information regarding the Company's discontinued operations.

Net income attributable to noncontrolling interest. Net income attributable to noncontrolling interests for the three and six months ended June 30, 2014 was nominal, as compared to $14 million and $22 million for the same respective periods in 2013. The decreases in income attributable to noncontrolling interests for the three and six months ended June 30, 2014, as compared to the same respective periods in 2013, are due to the Company's acquisition of all of the outstanding common units of Pioneer Southwest not owned by the Company in December 2013. The portion of income from noncontrolling interest for the three and six months ended June 30, 2013 related to Pioneer Southwest was $14 million and $22 million, respectively.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. The Company's primary needs for cash are for capital expenditures and acquisition expenditures on oil and gas properties and related vertical integration assets and facilities, payment of contractual obligations, dividends and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, cash and cash equivalents on hand, proceeds from the divestiture of assets held for sale, proceeds from the sales of other nonstrategic assets or external financing sources as discussed in "Capital resources" below.

The Company's capital budget for 2014 is focused on oil and liquids-rich gas drilling activities with total planned expenditures of $3.3 billion (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs and capital expenditures associated with Pioneer Alaska and Barnett Shale field assets prior to their sale), consisting of $3.0 billion for drilling operations, including budgeted land capital for existing assets, and $285 million for buildings, vertical integration and other plant and equipment additions. Based on results for the six months ended June 30, 2014 and Management's Price Outlook, the Company expects its cash flows from operating activities, cash and cash equivalents on hand, proceeds from the divestiture of assets held for sale, proceeds from other nonstrategic assets sales and, if necessary, availability under its Credit Facility to be sufficient to fund its planned capital expenditures and contractual obligations for the remainder of 2014.

Investing activities. Investing activities used $1.1 billion of cash during the six months ended June 30, 2014, as compared to $814 million of cash used in investing activities during the six months ended June 30, 2013. The $289 million increase in cash used in investing activities for the six months ending June 30, 2014, as compared to the six months ended June 30, 2013, is primarily due to a $306 million decrease in proceeds from the disposition of assets. During the six months ended June 30, 2014, the Company's expenditures for investing activities were primarily funded by net cash provided by operating activities and proceeds from disposition of assets.

Dividends/distributions. During February of both 2014 and 2013, the Board declared semiannual dividends of $0.04 per common share. Future dividends are at the discretion of the Board, and, if declared, the Board may change the current dividend amount based on the Company's liquidity and capital resources at the time.

During January 2013 and April 2013, the Pioneer Southwest board of directors declared a quarterly distribution of $0.52 per limited partner unit. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $18 million during the six months ended June 30, 2013.

Contractual obligations, including off-balance sheet obligations. The Company's contractual obligations include long-term debt, operating leases, drilling commitments (including commitments to pay day rates for drilling rigs), capital funding obligations, derivative obligations, firm transportation and fractionation commitments, minimum annual gathering, treating and transportation commitments and other liabilities (including postretirement benefit obligations). From time-to-time, the Company enters into arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of June 30, 2014, the material off-balance sheet arrangements and transactions that the Company has entered into include (i) operating lease agreements, (ii) drilling commitments, (iii) firm transportation and fractionation commitments, (iv) open purchase commitments and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates and gathering, treating, fractionation and transportation commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no

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transactions, arrangements or other relationships with unconsolidated entities or other parties that are reasonably likely to materially affect the Company's liquidity or availability of or requirements for capital resources. Since December 31, 2013, the primary change in the Company's contractual obligations is a $298 million decrease in the fair value of the Company's derivative contracts.

The Company's commodity and interest rate derivative contracts are periodically measured and recorded at fair value and continue to be subject to market or credit risk. As of June 30, 2014, these contracts represented net liabilities of $153 million. The ultimate liquidation value of the Company's commodity and interest rate derivatives will be dependent upon actual future commodity prices and interest rates, which may differ materially from the inputs used to determine the derivatives' fair values as of June 30, 2014. See Note E of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information about the Company's derivative instruments and market risk.

Capital resources. The Company's primary capital resources are cash and cash equivalents, net cash provided by operating activities, proceeds from the divestiture of assets held for sale, proceeds from sales of other nonstrategic assets and proceeds from financing activities (principally borrowings under the Company's Credit Facility or issuances of debt or equity securities). If internal cash flows and cash on hand do not meet the Company's expectations, the Company may reduce its level of capital expenditures, and/or fund a portion of its capital expenditures using availability under its Credit Facility, issue debt or equity securities or obtain capital from other sources, such as through the sale of nonstrategic assets.

Operating activities. Net cash provided by operating activities during the six months ended June 30, 2014 was $1.2 billion, as compared to $937 million during the same period in 2013. The increase in net cash provided by operating activities for the six months ended June 30, 2014, as compared to the six months ended June 30, 2013, is primarily due to an increase in oil, NGL and gas sales volumes as a result of the Company's successful drilling program and higher realized commodity prices, partially offset by a decrease in net cash flows from derivative settlements.

Asset divestitures. During the six months ended June 30, 2014, the Company completed the sale of (i) Pioneer Alaska for cash proceeds of $267 million, (ii) Sendero for cash proceeds of $31 million (Sendero had $14 million of cash on hand at the time of the sale) and (iii) proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for net cash proceeds of $72 million.

During the fourth quarter of 2013, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas. In August 2014, the Company signed a purchase and sale agreement with an unaffiliated third party for $155 million, before normal closing adjustments. Based on the terms of the purchase and sale agreement, the Company expects to close the sale of the Barnett Shale net assets during the third quarter of 2014. The Company has classified Barnett Shale assets and liabilities as held for sale in the accompanying consolidated balance sheet as of June 30, 2014 and December 31, 2013 and has reported Barnett Shale historical results of operations, and the related impairment loss, as discontinued operations, net of tax, in the Company's accompanying consolidated statements of operations.

In January 2013, the Company signed an agreement with Sinochem, an unaffiliated third party, to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for total consideration of $1.8 billion, including normal closing adjustments. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $624 million. Sinochem is paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the southern portion of the horizontal Wolfcamp Shale play.

Financing activities. Net cash used in financing activities during the six months ended June 30, 2014 was $28 million, as compared to net cash provided by financing activities of $344 million during the same period in 2013. The decrease in net cash provided by financing activities during the six months ended June 30, 2014, as compared to the same period of 2013, is primarily the result of a decrease of $1.3 billion of realized net proceeds from the Company's completion of an offering of its common stock in February 2013, partially offset by (i) a decrease in net principal payments on long-term debt of $904 million and (ii) a decrease of $18 million in distributions to noncontrolling interests.

As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company cannot predict the timing or ultimate outcome of any such actions as they are subject to market conditions, among other factors. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class

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preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined by the Board.

Liquidity. The Company's principal sources of short-term liquidity are cash on hand and unused borrowing capacity under its Credit Facility. As of June 30, 2014, the Company had no outstanding borrowings under its Credit Facility, leaving $1.5 billion of unused borrowing capacity. The Company was in compliance with all of its debt covenants as of June 30, 2014. The Company also had cash on hand of $445 million as of June 30, 2014. If internal cash flows and cash on hand do not meet the Company's expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its Credit Facility, issuances of debt or equity securities or other sources, such as the sale of nonstrategic assets. The Company cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that internal operating cash flows, cash on hand, proceeds from the divestiture of assets held for sale, proceeds from the sales of other nonstrategic assets and, if necessary, available capacity under the Company's Credit Facility will be adequate to fund 2014 capital expenditures, dividend payments and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet the Company's future needs.

Debt ratings. The Company is rated as investment grade by three credit rating agencies. The Company receives debt credit ratings from several of the major ratings agencies, which are subject to regular reviews. The Company believes that each of the rating agencies considers many factors in determining the Company's ratings including: production growth opportunities, liquidity, debt levels, asset composition and proved reserve mix. A reduction in the Company's debt ratings could increase the interest rates that the Company incurs on Credit Facility borrowings and could negatively impact the Company's ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.

Book capitalization and current ratio. The Company's net book capitalization at June 30, 2014 was $9.0 billion, consisting of $445 million of cash and cash equivalents, debt of $2.7 billion and equity of $6.7 billion. The Company's net debt to net book capitalization was 25 percent at both June 30, 2014 and December 31, 2013. The Company's ratio of current assets to current liabilities decreased to 0.94 to 1.00 at June 30, 2014, as compared to 1.38 to 1.00 at December 31, 2013, primarily due to a decrease in assets held for sale due to the sale of Pioneer Alaska in April 2014 and an increase in net derivative liabilities.

New accounting pronouncements. The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial Statements included in "Item1. Financial Statements".

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company's Annual Report on Form 10-K for the year ended December 31, 2013. As such, the information contained herein should be read in conjunction with the related disclosures in the Company's Annual Report on Form 10-K for the year ended December 31, 2013.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company's potential exposure to market risks. The term "market risks," insofar as it relates to currently anticipated transactions of the Company, refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators regarding how the Company views and manages ongoing market risk exposures. None of the Company's market risk sensitive instruments are entered into for speculative purposes.

The following table reconciles the changes that occurred in the fair values of the Company's open derivative contracts during the six months ending June 30, 2014:



	Derivative Contract Net Assets
	Commodities			Interest Rates			Total
	(in millions)
Fair value of contracts outstanding as of December 31, 2013	$	145		$	—		$	145
Changes in contract fair value	(340		)	18			(322		)
Contract maturity payments (receipts)	40			(4		)	36
Contract terminations payments (receipts)	2			(14		)	(12		)
Fair value of contracts outstanding as of June 30, 2014	$	(153	)	$	—		$	(153	)

Interest rate sensitivity. See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and Capital Commitments, Capital Resources and Liquidity included in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information regarding the Company's long-term debt.

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The following table provides information about financial instruments to which the Company was a party as of June 30, 2014 and that are sensitive to changes in interest rates. The table presents debt maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions and the debt's estimated fair value. For fixed rate debt, the weighted average interest rate represents the contractual fixed rates that the Company was obligated to periodically pay on the debt as of June 30, 2014. The Company had no outstanding variable rate debt as of June 30, 2014, but presents for the reader's information the average variable contractual rates for its credit facility projected forward proportionate to the forward yield curve for LIBOR on August 1, 2014.



	Six Months Ending December 31,			Year Ending December 31,																	Liability Fair Value at June 30,
	2014			2015			2016			2017			2018			Thereafter			Total		2014
	(dollars in millions)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	—		$	455		$	485		$	450		$	1,300		$	2,690	$	3,058
Weighted average fixed interest rate	6.15		%	6.15		%	6.17		%	6.11		%	5.91		%	5.81		%
Weighted average variable interest rate	1.76		%	2.19		%	3.20		%	4.09		%	—			—

____________________


(a)	Represents maturities of principal amounts excluding debt issuance discounts and net deferred fair value hedge losses.

Commodity derivative instruments and price sensitivity. The following table provides information about the Company's oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of June 30, 2014. Although mitigated by the Company's derivative activities, declines in oil, NGL and gas prices would reduce the Company's revenues.

The Company manages commodity price risk with derivative contracts, such as swap contracts, collar contracts and collar contracts with short put options. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum ("floor" or "long put") and maximum ("ceiling") prices on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other collar contracts by virtue of the short put option price, below which the Company's realized price will exceed the variable market prices by the long put-to-short put price differential.

See Note E of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for a description of the accounting procedures followed by the Company relative to its derivative financial instruments and for specific information regarding the terms of the Company's derivative financial instruments that are sensitive to changes in oil, NGL or gas prices.

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	Six Months Ending December 31,			Year Ending December 31,					Asset (Liability) Fair Value at June 30,
	2014			2015			2016		2014 (a)
									(in millions)
Oil Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts (b)(c)	69,000			95,767			54,000		$	(130	)
Weighted average ceiling price per BBL	$	114.05		$	99.36		$	98.36
Weighted average floor price per BBL	$	93.70		$	87.98		$	85.83
Weighted average short put price per BBL	$	77.61		$	73.54		$	74.26
Swap contracts	12,500			—			—		$	(17	)
Weighted average fixed price per BBL	$	95.33		$	—		$	—
Average forward NYMEX oil prices (d)	$	96.73		$	93.26		$	90.10
Rollfactor swap contracts (e)	10,000			5,000			—		$	—
Weighted average fixed price per BBL	$	1.10		$	0.60		$	—
Average forward rollfactor prices (d)	$	0.80		$	0.45		$	—
NGL Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts (f)	3,500			—			—		$	(1	)
Weighted average ceiling price per BBL	$	97.93		$	—		$	—
Weighted average floor price per BBL	$	90.14		$	—		$	—
Weighted average short put price per BBL	$	81.36		$	—		$	—
Average forward NGL prices (g)	$	87.61		$	—		$	—
Collar contracts (h)	3,000			—			—		$	—
Weighted average ceiling price per BBL	$	13.72		$	—		$	—
Weighted average floor price per BBL	$	10.78		$	—		$	—
Average forward NGL prices (g)	$	10.21		$	—		$	—
Swap contracts (i)	2,337			—			—		$	1
Weighted average fixed price per BBL	$	48.11		$	—		$	—
Average forward NGL prices (g)	$	43.38		$	—		$	—
Gas Derivatives:
Average daily notional MMBTU volumes:
Collar contracts with short puts	115,000			285,000			20,000		$	9
Weighted average ceiling price per MMBTU	$	4.70		$	5.07		$	5.36
Weighted average floor price per MMBTU	$	4.00		$	4.00		$	4.00
Weighted average short put price per MMBTU	$	3.00		$	3.00		$	3.00
Swap contracts	195,000			20,000			—		$	(14	)
Weighted average fixed price per MMBTU	$	4.04		$	4.31		$	—
Average forward NYMEX gas prices (d)	$	3.87		$	3.87		$	4.03
Basis swap contracts (j)	130,000			90,000			—		$	(1	)
Weighted average fixed price per MMBTU	$	(0.21	)	$	(0.22	)	$	—
Average forward basis differential prices (k)	$	(0.13	)	$	(0.22	)	$	—

___________________

(a)

In accordance with Financial Accounting Standards Board Accounting Standards Codification ("ASC") 210-20 and ASC 815-10, the Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, as the case may be. The net asset and liability amounts shown above have been provided on a commodity contract-type basis, which may differ from their master netting arrangements classifications.

(b)

Counterparties have the option to extend 5,000 BBLs per day of 2015 collar contracts with short puts for an additional year with a ceiling price of $100.08 per BBL, a floor price of $90.00 per BBL and a short put price of $80.00 per BBL. The option to extend is exercisable on December 31, 2015. These contracts give the counterparties the option to extend the contracts under the same terms for an additional year if the option to extend is exercised by the counterparties on December 31, 2015.

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(c)	Subsequent to June 30, 2014, the Company entered into additional collar contracts with short puts for 4,000 BBL per day of the Company's 2016 production with a ceiling price of $100.73 per BBL, a floor price of $90.00 per BBL and a short put price of $80.00 per BBL.


(d)	The average forward NYMEX oil and gas prices are based on August 1, 2014 market quotes.


(e)	Represents swaps that fix the difference between (i) each day's price per BBL of WTI for the first nearby month less (ii) the price per BBL of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per BBL of WTI for the first nearby month less (iv) the price per BBL of WTI for the third nearby NYMEX month, multiplied by .3333.


(f)	Represent collar contracts with short puts that reduce the price volatility of natural gasoline forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.


(g)	Forward component NGL prices are derived from respective active-market NGL component price quotes as of August 1, 2014.


(h)	Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.


(i)	Represent swap contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.


(j)	Subsequent to June 30, 2014, the Company entered into additional basis swap contracts for 20,000 MMBTU per day for August 2014 and 40,000 MMBTU per day for September 2014 with respective price differentials of $0.38 per MMBTU and $0.39 per MMBTU between Permian Basin index prices and southern California index prices.


(k)	The average forward basis differential prices are based on August 1, 2014 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

Marketing and basis transfer derivatives. The Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of June 30, 2014, the Company had marketing gas index swap contracts for 40,000 MMBTU per day for the remainder of 2014 with a price differential of $0.31 per MMBTU between Inside FERC-EPNG (Permian Basin) index prices and NGI-SoCal Border Monthly index prices. As of June 30, 2014, these positions had an asset fair value of $15 thousand. Based on August 1, 2014 market quotes, the respective average forward basis differential price was $0.38 per MMBTU for basis differentials between the relevant quoted forward gas index prices.

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Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the "Exchange Act"), the effectiveness of the Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that the Company's disclosure controls and procedures were effective, as of the end of the period covered by this Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, including that such information is accumulated and communicated to the Company's management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There have been no changes in the Company's internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended June 30, 2014 that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The Company is party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations.

Item 1A. Risk Factors

In addition to the information set forth in this Report, you should carefully consider the risks discussed in the Company's Annual Report on Form 10-K for the year ended December 31, 2013, under the headings "Part I, Item 1. Business – Competition, Markets and Regulations," "Part I, Item 1A. Risk Factors" and "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk," which risks could materially affect the Company's business, financial condition or future results. There has been no material change in the Company's risk factors from those described in the Annual Report on Form 10-K.

These risks are not the only risks facing the Company. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may have a material adverse effect on the Company's business, financial condition or future results.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company's purchases of treasury stock under plans or programs during the three months ended June 30, 2014:



Period	Total Number of Shares (or Units) Purchased (a)	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased As Part of Publicly Announced Plans or Programs	Approximate Dollar Amount of Shares that May Yet Be Purchased under Plans or Programs
April 2014	5,912	$	188.43	—
May 2014	2,441	$	193.27	—
June 2014	—	$	—	—
Total	8,353	$	189.84	—	$	—

____________________


(a)	Consists of shares purchased from each employee in order for the employee to satisfy tax withholding payments related to share-based awards that vested during the period.

Item 4. Mine Safety Disclosures

The Company's sand mines are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Quarterly Report filed on Form 10-Q.

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Item 6. Exhibits

Exhibits



Exhibit Number		Description

10.1	—	Indemnification Agreement, dated July 7, 2014, between the Company and Phillip A. Gobe, together with a schedule identifying other substantially identical agreement between the Company and the other non-employee director identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 10, 2014).

12.1	(a) —	Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.

31.1	(a) —	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

31.2	(a) —	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

32.1	(b) —	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

32.2	(b) —	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

95.1	(a) —	Mine Safety Disclosures.

101.INS	(a) —	XBRL Instance Document.

101.SCH	(a) —	XBRL Taxonomy Extension Schema.

101.CAL	(a) —	XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF	(a) —	XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB	(a) —	XBRL Taxonomy Extension Label Linkbase Document.

101.PRE	(a) —	XBRL Taxonomy Extension Presentation Linkbase Document.

_____________


(a)	Filed herewith.


(b)	Furnished herewith.

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

SIGNATURES

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 hereto duly authorized.



	PIONEER NATURAL RESOURCES COMPANY

Date: August 6, 2014	By:	/s/ RICHARD P. DEALY
		Richard P. Dealy,
		Executive Vice President and Chief Financial Officer

Date: August 6, 2014	By:	/s/ MARGARET M. MONTEMAYOR
		Margaret M. Montemayor,
		Vice President and Chief Accounting Officer

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

Exhibit Index



Exhibit Number		Description
10.1	—	Indemnification Agreement, dated July 7, 2014, between the Company and Phillip A. Gobe, together with a schedule identifying other substantially identical agreement between the Company and the other non-employee director identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 10, 2014).

12.1	(a) —	Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.

31.1	(a) —	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

31.2	(a) —	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

32.1	(b) —	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

32.2	(b) —	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

95.1	(a) —	Mine Safety Disclosures.

101.INS	(a) —	XBRL Instance Document.

101.SCH	(a) —	XBRL Taxonomy Extension Schema.

101.CAL	(a) —	XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF	(a) —	XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB	(a) —	XBRL Taxonomy Extension Label Linkbase Document.

101.PRE	(a) —	XBRL Taxonomy Extension Presentation Linkbase Document.

_____________


(a)	Filed herewith.


(b)	Furnished herewith.