10-Q

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 March 31, 2013

or

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

For the transition period from  ________ to ________                     

Commission File Number: 1-13245

______________________________ 

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.

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

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

Yes   ¨    No  ý

Number of shares of Common Stock outstanding as of May 2, 2013                                 136,578,089

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 March 31, 2013 and December 31, 2012	5
	Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012	7
	Consolidated Statements of Comprehensive Income for the three months ended March 31, 2013 and 2012	8
	Consolidated Statement of Equity for the three months ended March 31, 2013	9
	Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012	10
	Notes to Consolidated Financial Statements	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	43
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 4.	Mine Safety Disclosures	44
Item 6.	Exhibits	45
Signatures		46
Exhibit Index		47

2

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, the receipt of approvals required to consummate the Company's Southern Wolfcamp joint interest transaction, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to complete the Company's 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 an industrial sand mining business and acts of war or terrorism. These and other risks are described in the Company's Annual Report on Form 10-K, this Report and other filings with the United States Securities and Exchange Commission (the "SEC"). 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, 2012 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.

3

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.

• "MMBTUPD" means MMBTU per day.

• "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.

4

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands)

	March 31, 2013			December 31, 2012
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	430,298		$	229,396
Accounts receivable:
Trade, net	355,093			316,854
Due from affiliates	4,124			3,299
Income taxes receivable	1,394			7,447
Inventories	233,402			197,056
Prepaid expenses	13,337			13,438
Other current assets:
Derivatives	151,431			279,119
Other	7,335			3,746
Total current assets	1,196,414			1,050,355
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	15,007,980			14,259,708
Unproved properties	218,404			231,555
Accumulated depletion, depreciation and amortization	(4,633,359		)	(4,412,913		)
Total property, plant and equipment	10,593,025			10,078,350
Goodwill	298,142			298,142
Other property and equipment, net	1,228,108			1,217,694
Other assets:
Investment in unconsolidated affiliate	216,369			204,129
Derivatives	95,121			55,257
Other, net	134,118			165,103
	$	13,761,297		$	13,069,030

The financial information included as of March 31, 2013 has been prepared by management

without audit by independent registered public accountants.

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

5

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (continued)

(in thousands, except share data)

	March 31, 2013			December 31, 2012
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	780,395		$	729,942
Due to affiliates	39,968			96,935
Interest payable	37,494			68,083
Income taxes payable	292			208
Deferred income taxes	51,783			86,481
Other current liabilities:
Derivatives	20,413			13,416
Other	41,521			39,725
Total current liabilities	971,866			1,034,790
Long-term debt	3,017,280			3,721,193
Derivatives	13,372			12,307
Deferred income taxes	2,202,637			2,140,416
Other liabilities	290,071			293,016
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 145,799,929 and 134,966,740 shares issued at March 31, 2013 and December 31, 2012, respectively	1,458			1,350
Additional paid-in capital	4,898,318			3,683,934
Treasury stock at cost: 9,337,865 and 11,611,093 at March 31, 2013 and December 31, 2012, respectively	(420,947		)	(510,570		)
Retained earnings	2,609,801			2,514,640
Total equity attributable to common stockholders	7,088,630			5,689,354
Noncontrolling interests in consolidating subsidiaries	177,441			177,954
Total equity	7,266,071			5,867,308
Commitments and contingencies
	$	13,761,297		$	13,069,030

The financial information included as of March 31, 2013 has been prepared by management

without audit by independent registered public accountants.

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

6

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

	Three Months Ended March 31,
	2013			2012
Revenues and other income:
Oil and gas	$	787,855		$	718,956
Interest and other	19,315			21,908
Gain on disposition of assets, net	24,417			43,596
	831,587			784,460
Costs and expenses:
Oil and gas production	169,140			131,781
Production and ad valorem taxes	54,297			45,796
Depletion, depreciation and amortization	230,763			181,418
Exploration and abandonments	27,627			53,287
General and administrative	63,751			63,067
Accretion of discount on asset retirement obligations	3,153			2,430
Interest	50,735			46,858
Derivative (gains) losses, net	42,243			(91,750		)
Other	21,349			23,607
	663,058			456,494
Income from continuing operations before income taxes	168,529			327,966
Income tax provision	(59,329		)	(117,703		)
Income from continuing operations	109,200			210,263
Income (loss) from discontinued operations, net of tax	(465		)	10,695
Net income	108,735			220,958
Net income attributable to noncontrolling interests	(8,072		)	(6,339		)
Net income attributable to common stockholders	$	100,663		$	214,619
Basic earnings per share:
Income from continuing operations attributable to common stockholders	$	0.77		$	1.65
Income (loss) from discontinued operations attributable to common stockholders	—			0.08
Net income attributable to common stockholders	$	0.77		$	1.73
Diluted earnings per share:
Income from continuing operations attributable to common stockholders	$	0.75		$	1.60
Income (loss) from discontinued operations attributable to common stockholders	—			0.08
Net income attributable to common stockholders	$	0.75		$	1.68
Weighted average shares outstanding:
Basic	128,940			122,480
Diluted	132,751			126,247
Dividends declared per share	$	0.04		$	0.04
Amounts attributable to common stockholders:
Income from continuing operations	$	101,128		$	203,924
Income (loss) from discontinued operations, net of tax	(465		)	10,695
Net income	$	100,663		$	214,619

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.

7

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

(Unaudited)

	Three Months Ended March 31,
	2013			2012
Net income	$	108,735		$	220,958
Other comprehensive activity:
Net hedge losses included in continuing operations	—			2,508
Income tax benefit	—			(928		)
Other comprehensive activity	—			1,580
Comprehensive income	108,735			222,538
Comprehensive income attributable to the noncontrolling interests	(8,072		)	(6,339		)
Comprehensive income attributable to common stockholders	$	100,663		$	216,199

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.

8

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENT OF EQUITY

(in thousands, 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, 2012	123,356	$	1,350	$	3,683,934		$	(510,570	)	$	2,514,640		$	177,954		$	5,867,308
Issuance of common stock	10,350	103		1,280,813			—			—			—			1,280,916
Dividends declared ($0.04 per share)	—	—		—			—			(5,502		)	—			(5,502		)
Exercise of long-term incentive plan stock options	41	—		(791		)	1,838			—			—			1,047
Treasury stock purchases	2,232	—		—			(19,202		)	—			—			(19,202		)
Conversion of 2.875% senior convertible notes	—	—		(106,989		)	106,987			—			—			(2		)
Tax benefit related to conversion of 2.875% senior convertible notes	—	—		22,524			—			—			—			22,524
Tax benefit related to stock-based compensation	—	—		1,688			—			—			—			1,688
Compensation costs:
Vested compensation awards, net	484	5		(5		)	—			—			—			—
Compensation costs included in net income	—	—		17,144			—			—			300			17,444
Cash distributions to noncontrolling interests	—	—		—			—			—			(8,885		)	(8,885		)
Net income	—	—		—			—			100,663			8,072			108,735
Balance as of March 31, 2013	136,463	$	1,458	$	4,898,318		$	(420,947	)	$	2,609,801		$	177,441		$	7,266,071

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.

9

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Three Months Ended March 31,
	2013			2012
Cash flows from operating activities:
Net income	$	108,735		$	220,958
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	230,763			181,418
Exploration expenses, including dry holes	7,954			27,163
Deferred income taxes	51,894			105,871
Gain on disposition of assets, net	(24,417		)	(43,596		)
Accretion of discount on asset retirement obligations	3,153			2,430
Discontinued operations	(158		)	1,577
Interest expense	4,844			9,870
Derivative related activity	95,884			(27,243		)
Amortization of stock-based compensation	17,395			15,086
Amortization of deferred revenue	—			(10,459		)
Other noncash items	(2,922		)	(9,516		)
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	(41,803		)	(20,663		)
Income taxes receivable	6,053			1,407
Inventories	825			(31,027		)
Prepaid expenses	101			1,413
Other current assets	(636		)	2,488
Accounts payable	(57,572		)	19,326
Interest payable	(30,589		)	(21,917		)
Income taxes payable	84			16,941
Other current liabilities	(9,514		)	(15,441		)
Net cash provided by operating activities	360,074			426,086
Cash flows from investing activities:
Proceeds from disposition of assets	46,184			58,514
Additions to oil and gas properties	(697,191		)	(678,339		)
Additions to other assets and other property and equipment, net	(56,169		)	(59,841		)
Net cash used in investing activities	(707,176		)	(679,666		)
Cash flows from financing activities:
Borrowings under long-term debt	304,922			134,000
Principal payments on long-term debt	(1,012,253		)	(49,000		)
Proceeds from issuance of common stock, net of issuance costs	1,280,916			—
Distributions to noncontrolling interests	(8,885		)	(8,957		)
Borrowings (payments) of other liabilities	(210		)	458
Exercise of long-term incentive plan stock options	1,047			1,008
Purchases of treasury stock	(19,202		)	(56,129		)
Excess tax benefits from share-based payment arrangements	1,688			12,938
Payments of convertible senior note conversions and financing fees	(2		)	(1,261		)
Dividends paid	(17		)	(43		)
Net cash provided by financing activities	548,004			33,014
Net increase (decrease) in cash and cash equivalents	200,902			(220,566		)
Cash and cash equivalents, beginning of period	229,396			537,484
Cash and cash equivalents, end of period	$	430,298		$	316,918

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.

10

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(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 field operations in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Barnett Shale Combo play in North Texas, the Raton field in southeastern Colorado, the Hugoton field in southwest Kansas, the West Panhandle field in the Texas Panhandle and Alaska.

NOTE B. Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of March 31, 2013 and for the three months ended March 31, 2013 and 2012 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, 2012.

Certain reclassifications have been made to the 2012 financial statement and footnote amounts in order to conform to the 2013 presentation.

Issuance of common stock. In February 2013, the Company issued 10.35 million shares of its common stock and realized $1.3 billion of proceeds, net of associated underwriting and offering expenses.

Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest"). The Company owns and controls Pioneer Natural Resources GP LLC (the "General Partner"), which manages Pioneer Southwest. Pioneer Southwest owns interests in certain oil and gas properties in the Spraberry field in the Permian Basin of West Texas. The financial position, results of operations and cash flows of Pioneer Southwest are consolidated with those of the Company. Noncontrolling interests in consolidated subsidiaries includes $163.9 million attributable to outstanding Pioneer Southwest common units held by unitholders other than Pioneer or its subsidiaries as of March 31, 2013.

NOTE C. Acquisitions and Divestitures

Premier Silica Business Combination

On April 2, 2012, a wholly-owned subsidiary of the Company acquired an industrial sand mining business that is now called Premier Silica LLC ("Premier Silica"). Premier Silica's primary mine operations are in Brady, Texas. The Brady mine facilities primarily produce, process and provide sand to the Company for use as proppant in its fracture stimulation of oil and gas wells in Texas. Excess sand and sand not useable for fracture stimulation is sold to third parties for use as proppant or other industrial and recreational purposes. The aggregate purchase price of Premier Silica was $297.1 million, including closing adjustments.

Divestitures Recorded in Continuing Operations

Sales of unproved oil and gas properties. For the three months ended March 31, 2013, the Company's pretax gain on disposition of assets from continuing operations of $24.4 million was primarily associated with the sale of its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations to an unaffiliated third party for cash proceeds of $37.4 million, which resulted in a pretax gain of $21.7 million. For the three months ended March 31, 2012, the Company's pretax gain on disposition of assets of $43.6 million was primarily associated with the sale of a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale field to unaffiliated third parties for cash proceeds of $54.7 million, which resulted in a pretax gain of $42.6 million.

11

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

Divestitures Recorded as Discontinued Operations

South Africa. During the first quarter of 2012, the Company agreed to sell its net assets in South Africa ("Pioneer South Africa") to an unaffiliated third party, effective January 1, 2012, for $60.0 million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities of the Company's South Africa subsidiaries. In August 2012, the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale, resulting in a third quarter 2012 pretax gain of $28.6 million. The Company classified Pioneer South Africa's results of operations as income from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

For the three months ended March 31, 2012, the Company recognized revenues and other income and pretax earnings of $19.6 million and $17.4 million, respectively, associated with discontinued operations, principally related to the results of operations of Pioneer South Africa prior to its divestiture in August 2012.

Pending Divestitures

Southern Wolfcamp. In January 2013, the Company signed an agreement with Sinochem Petroleum USA LLC ("Sinochem"), a U.S. subsidiary of the Sinochem Group, 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 in West Texas for total consideration of $1.7 billion. Sinochem will pay $522.0 million in cash to Pioneer at closing, before normal closing adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of Pioneer's portion of future drilling and facilities costs attributable to the horizontal Wolfcamp Shale play. This transaction is expected to close during the second quarter of 2013, subject to governmental approvals.

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.

12

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

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 as of March 31, 2013:

	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 March 31, 2013
	(in thousands)
Recurring fair value measurements
Assets:
Trading securities	$	158	$	142	$	—	$	300
Commodity derivatives	—		246,552		—		246,552
Deferred compensation plan assets	53,768		—		—		53,768
Total assets	53,926		246,694		—		300,620
Liabilities:
Commodity derivatives	—		28,001		—		28,001
Interest rate derivatives	—		5,784		—		5,784
Total liabilities	—		33,785		—		33,785
Total recurring fair value measurements	$	53,926	$	212,909	$	—	$	266,835

Trading securities and deferred compensation plan assets. The Company's trading securities are comprised of securities that are both actively traded and not actively traded on major exchanges. 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 March 31, 2013, substantially all of the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Inputs for certain trading securities that are not actively traded on major exchanges were classified as Level 2 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 oil, NGL and gas swap, collar and collar contracts with short puts 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.

Interest rate derivatives. The Company's interest rate derivative liabilities as of March 31, 2013 represent interest rate swap contracts. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of March 31, 2013 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate ("LIBOR") yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative liability measurements represent Level 2 inputs in the hierarchy.

13

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

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 sheet as of March 31, 2013 and December 31, 2012 are as follows:

	March 31, 2013				December 31, 2012
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	3,017,280	$	3,768,884	$	3,721,193	$	4,555,770

Long-term debt includes the Company's credit facility, the Pioneer Southwest 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.

Credit facilities. The fair values of the Company's and Pioneer Southwest's credit facilities are 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 rate (in the case of the Company's credit facility) or LIBOR (in the case of the Pioneer Southwest credit facility) yield curves and (iii) the applicable credit-adjustments.

Senior notes. The Company's senior notes represent debt securities that are not actively traded on major exchanges. 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 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.

14

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

The following table sets forth the volumes per day in barrels ("BBLs") associated with the Company's outstanding oil derivative contracts as of March 31, 2013 and the weighted average oil prices per BBL for those contracts:

	Nine Months Ending December 31,			Year Ending December 31,
	2013			2014		2015
Collar contracts with short puts:
Volume (BBL)	72,430			69,000		26,000
Average price per BBL:
Ceiling	$	119.89		$	114.05	$	104.45
Floor	$	92.26		$	93.70	$	95.00
Short put	$	74.36		$	77.61	$	80.00
Swap contracts:
Volume (BBL)	3,000			—		—
Average price per BBL	$	81.02		$	—	$	—
Rollfactor swap contracts:
Volume (BBL)	6,000			15,000		—
NYMEX roll price (a)	$	0.43		$	0.38	$	—
Basis swap contracts:
Midland-Cushing index swap volume (BBL)	1,655			—		—
Average price per BBL (b)	$	(5.75	)	$	—	$	—
Cushing-LLS index swap volume (BBL)	669			—		—
Average price per BBL (c)	$	(9.30	)	$	—	$	—

 ____________________

(a) 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.

(b) Basis differential price between Midland WTI and Cushing WTI.

(c) Basis differential price between Cushing WTI and Louisiana Light Sweet crude "LLS".

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 product component prices.

The following table sets forth the volumes per day in BBLs associated with the Company's outstanding NGL derivative contracts as of March 31, 2013 and the weighted average NGL prices per BBL for those contracts:

	Nine Months Ending December 31,		Year Ending December 31,
	2013		2014
Collar contracts with short puts:
Volume (BBL)	1,064		1,000
Average price per BBL:
Ceiling	$	105.28	$	109.50
Floor	$	89.30	$	95.00
Short put	$	75.20	$	80.00

15

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

Subsequent to March 31, 2013, the Company entered into additional NGL collar contracts for (i) 2,000 BBLs per day of the Company's May through December 2013 ethane production with a ceiling price of $12.60 per BBL and a floor price of $10.50 per BBL, (ii) 500 BBLs per day of the Company's July through December 2013 ethane production with a ceiling price of $13.02 per BBL and a floor price of $10.50 per BBL and (iii) 3,000 BBLs per day of the Company's 2014 ethane production with a ceiling price of $13.72 per BBL and a floor price of $10.78 per BBL.

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 reduce basis risk between HH prices and actual index prices at which the gas is sold.

The following table sets forth the volumes per day in millions of British thermal units ("MMBTU") associated with the Company's outstanding gas derivative contracts as of March 31, 2013 and the weighted average gas prices per MMBTU for those contracts:

	Nine Months Ending December 31,			Year Ending December 31,
	2013			2014			2015		2016
Collar contracts with short puts:
Volume (MMBTU) (a)	—			65,000			235,000		20,000
Price per MMBTU:
Ceiling	$	—		$	4.70		$	5.09	$	5.36
Floor	$	—		$	4.00		$	4.00	$	4.00
Short put	$	—		$	3.00		$	3.00	$	3.00
Collar contracts:
Volume (MMBTU) (a)	150,000			—			—		—
Price per MMBTU:
Ceiling	$	6.25		$	—		$	—	$	—
Floor	$	5.00		$	—		$	—	$	—
Swap contracts:
Volume (MMBTU)	170,282			175,000			20,000		—
Price per MMBTU	$	5.07		$	4.02		$	4.31	$	—
Basis swap contracts:
Volume (MMBTU) (a)	162,500			10,000			—		—
Price per MMBTU	$	(0.22	)	$	(0.19	)	$	—	$	—

____________________

(a) Subsequent to March 31, 2013, the Company entered into additional (i) collar contracts for 2,500 MMBTUs per day of the Company's June through December 2013 production with a ceiling price of $4.50 per MMBTU and a floor price of $4.00 per MMBTU, (ii) collar contracts with short puts for 50,000 MMBTUs per day of the Company's 2014 production with a ceiling price of $4.70 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU, (iii) collar contracts with short puts for 50,000 MMBTUs per day of the Company's 2015 production with a ceiling price of $5.03 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU, (iv) basis swap contracts for 22,500 MMBTU per day of the Company's 2014 production with a negative price differential of $0.18 per MMBTU between the relevant index price and the NYMEX price and (v) basis swap contracts for 7,500 MMBTU per day of the Company's 2015 production with a negative price differential of $0.13 per MMBTU between the relevant index price and the NYMEX price.

Marketing and basis transfer derivative activities. Periodically, the Company enters into buy and sell marketing arrangements to utilize unused firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate the related price risk.

16

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

The following table sets forth the contract volumes associated with the Company's outstanding marketing derivative contracts as of March 31, 2013 and the weighted average prices for those contracts:

	Nine Months Ending December 31,
	2013
Average Daily Gas Production Associated with Marketing Derivatives:
Basis swap contracts:
Index swap volume (MMBTU)	4,364
Price differential ($/MMBTU)	$	0.34

Interest rates. As of March 31, 2013, the Company was a party to interest rate derivative contracts that lock in a fixed forward annual interest rate of 3.21 percent, for a 10-year period ending in December 2025, on a notional amount of $250 million. These derivative contracts mature and settle by their terms in December 2015.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of March 31, 2013 and December 31, 2012 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 executed under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty, as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty.

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

Fair Value of Derivative Instruments as of March 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 thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	160,149	$	(8,718	)	$	151,431
Commodity price derivatives	Derivatives - noncurrent	$	100,090	$	(4,969	)	95,121
							$	246,552
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	29,131	$	(8,718	)	$	20,413
Commodity price derivatives	Derivatives - noncurrent	$	12,557	$	(4,969	)	7,588
Interest rate derivatives	Derivatives - noncurrent	$	5,784	$	—		5,784
							$	33,785

17

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

Fair Value of Derivative Instruments as of December 31, 2012
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 thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	286,805	$	(7,686	)	$	279,119
Commodity price derivatives	Derivatives - noncurrent	$	61,618	$	(6,361	)	55,257
							$	334,376
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	21,102	$	(7,686	)	$	13,416
Commodity price derivatives	Derivatives - noncurrent	$	8,944	$	(6,361	)	2,583
Interest rate derivatives	Derivatives - noncurrent	$	9,724	$	—		9,724
							$	25,723

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.

Derivatives in Cash Flow Hedging	Location of (Gain)/Loss Reclassified from
		Three Months Ended March 31,
Relationships	AOCI into Earnings	2013		2012
		(a)
Commodity price derivatives	Oil and gas revenue	$	—	$	809
Interest rate derivatives	Interest expense	—		1,699
Total		$	—	$	2,508

____________________

(a) During 2012, all remaining Accumulated Other Comprehensive Income ("AOCI") related to hedging was transferred to earnings.

Derivatives Not Designated as Hedging	Location of (Gain) Loss Recognized in	Three Months Ended March 31,
Instruments	Earnings on Derivatives	2013			2012
Commodity price derivatives	Derivative (gains) losses, net	$	46,183		$	(88,130	)
Interest rate derivatives	Derivative (gains) losses, net	(3,940		)	(3,620		)
Total		$	42,243		$	(91,750	)

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. After an exploratory well has been completed and found oil and gas reserves, a determination may be pending as to whether the oil and gas reserves can be classified as proved. In those circumstances, the Company continues to capitalize the well or project costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. 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.

18

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

The following table reflects the Company's capitalized exploratory well and project activity during the three months ended March 31, 2013:

	Three Months Ended March 31, 2013
	(in thousands)
Beginning capitalized exploratory costs	$	212,670
Additions to exploratory costs pending the determination of proved reserves	351,575
Reclassification due to determination of proved reserves	(262,754		)
Exploratory well costs charged to exploration expense	(7,734		)
Ending capitalized exploratory costs	$	293,757

The following table provides an aging, as of March 31, 2013 and December 31, 2012, 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:

	March 31, 2013		December 31, 2012
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	174,841	$	190,678
More than one year	118,916		21,992
	$	293,757	$	212,670
Number of projects with exploratory costs that have been suspended for a period greater than one year	2		1

Alaska - Oooguruk.As of each of March 31, 2013 and December 31, 2012, the Company had $22.0 million of suspended well costs recorded for the K-13 well in the Alaska Oooguruk field. Drilling on the K-13 well was completed during September 2011. During well completion operations, subsurface damages were sustained. The Company plans to recomplete the well during 2013. The well may require additional stimulation work that, if required, will be done during the first quarter of 2014 to initiate production.

Alaska - Nuna. The Company's Nuna project, which has $96.9 million of suspended project costs as of March 31, 2013, includes the Nuna-1 exploration well that was drilled during 2012 to test the Torok formation and a second appraisal well that was drilled and logged during the first quarter of 2013. The Company flow-tested the Nuna-1 well during the second quarter of 2012 and again in the first quarter of 2013. The second appraisal well encountered a mechanical problem and could not be flow-tested before the end of the winter drilling season. The results of the flow-tests on the Nuna-1 well and the log data from the second Nuna well are both very encouraging. The Company is currently conducting a front-end engineering design ("FEED") study to evaluate the potential for onshore production facilities to support the project.

NOTE G. Long-term Debt

The Company's long-term debt consists of senior notes and revolving credit facilities, including the effects of net deferred fair value hedge losses and issuance discounts. As of March 31, 2013, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

Credit facility. The Company maintains a Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that has aggregate loan commitments of $1.5 billion that expires in December 2017. As of March 31, 2013, the Company had no outstanding borrowings under the Credit Facility.

Pioneer Southwest credit facility. Pioneer Southwest maintains a Credit Agreement (the "Pioneer Southwest Credit Facility") with a syndicate of financial institutions that has aggregate loan commitments of $300 million that expires in March 2017. As of

19

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

March 31, 2013, Pioneer Southwest had outstanding borrowings of $154.0 million under the Credit Facility, leaving $146.0 million of unused borrowing capacity.

Convertible senior notes. As of March 31, 2013 and December 31, 2012, the Company had $218.6 million and $479.9 million of 2.875% Convertible Senior Notes due 2038 ("Convertible Senior Notes") outstanding. The Convertible Senior Notes are convertible at the option of the holders under certain circumstances, using a net share settlement process, into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the Convertible Senior Notes were issued and, as of January 15, 2013, are redeemable by the Company at any time for cash at a price equal to the full principal amount plus accrued and unpaid interest.

During December 2012, the Company's stock price met the price threshold that causes the Convertible Senior Notes to be convertible at the option of the holders for the three months ended March 31, 2013. Associated therewith, during the three months ended March 31, 2013, holders of $274.1 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock and the Company paid the tendering holders $261.3 million of cash and issued to the tendering holders 2.4 million shares of the Company's common stock during the three months ended March 31, 2013, in accordance with the terms of the Convertible Senior Notes indenture agreement. The remaining $12.8 million principal amount was settled in cash and the issuance of 115 thousand shares of the Company's common stock in April 2013.

The Company's stock prices during March 2013 and 2012 also met the price threshold that causes the Convertible Senior Notes to be convertible at the option of the holders for the following three month period. In addition, on April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that have not been converted by the holders before May 16, 2013.

If all of the remaining Convertible Senior Notes had been converted on March 31, 2013, the note holders would have received $218.6 million of additional cash and approximately 2.1 million shares of the Company's common stock, which were valued at $259.7 million on March 31, 2013. Holders of the Convertible Senior Notes who present their notes for conversion prior to May 16, 2013 will be subject to a 20 consecutive day cash settlement averaging period that will encompass the trading days from April 16, 2013 through May 13, 2013. The Company has the intent and ability to fund cash payments that will be required upon the conversion or redemption of the Convertible Senior Notes with borrowing capacity under the Credit Facility. Accordingly, the Convertible Senior Notes are classified as long-term debt in the accompanying balance sheets.

Interest on the principal amount of the Convertible Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The trading price of the Convertible Senior Notes for the five consecutive trading days preceding January 15, 2013 exceeded 120 percent of the principal amount of the note and, in accordance with the indenture supplement, the interest rate in effect during the January 15, 2013 to July 14, 2013 period was reduced to 2.375 percent.

NOTE H. Incentive Plans

Stock-based compensation

For the three months ended March 31, 2013, the Company recorded $27.6 million of stock-based compensation expense for all plans, as compared to $21.3 million for the same period of 2012. As of March 31, 2013, there was $198.5 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $47.5 million attributable to stock-based awards that are expected to be settled in cash on their vesting date, rather than in equity shares ("Liability Awards"). This compensation 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 March 31, 2013 and December 31, 2012, accounts payable – due to affiliates includes $5.8 million and $18.8 million, respectively, of liabilities attributable to Liability Awards.

20

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

The following table summarizes the activity that occurred during the three months ended March 31, 2013, for each type of share-based incentive award issued by Pioneer:

	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units	Stock Options		Pioneer Southwest LTIP Restricted Units	Pioneer Southwest LTIP Phantom Units
Outstanding at December 31, 2012	1,512,762		405,916		91,370	467,486		7,496	102,644
Awards granted	397,439		238,269		94,917	—		—	32,242
Awards vested	(476,717	)	(178,143	)	—	—		—	(35,118	)
Options exercised	—		—		—	(12,818	)	—	—
Awards forfeited	(3,834	)	(5,015	)	—	—		—	—
Outstanding as of March 31, 2013	1,429,650		461,027		186,287	454,668		7,496	99,768

Postretirement Benefit Obligations

As of March 31, 2013 and December 31, 2012, the Company had $9.1 million and $9.7 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. These obligations are comprised of five unfunded plans, of which four relate to predecessor entities that the Company acquired in prior years, and one funded plan that the Company assumed sponsorship for in conjunction with the acquisition of Premier Silica.

The unfunded plans had no assets as of March 31, 2013 or December 31, 2012. The Company's funding policy for the Premier Silica plan is to contribute amounts sufficient to meet legal funding requirements, plus any additional amounts that the Company may determine to be appropriate considering the funded status of the plan, tax deductibility, the cash flow generated by the Company, and other factors. The Company continually reassesses the amount and timing of any discretionary contributions and may elect to make such contributions in future periods.

21

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(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 months ended March 31, 2013 and 2012:

		Three Months Ended March 31,
		2013			2012
	(in thousands)
Beginning asset retirement obligations		$	197,754		$	136,742
New wells placed on production		2,468			830
Changes in estimates (a)		(5,597		)	—
Dispositions		(4,079		)	—
Liabilities settled		(2,849		)	(5,688		)
Accretion of discount		3,153			2,430
Accretion of discount from integrated services (b)		11			—
Ending asset retirement obligations		$	190,861		$	134,314

_____________________

(a) The change in estimate during the three months ended March 31, 2013 is attributable to lengthening the economic life of certain wells, which reduced the present value of the associated asset retirement obligation.

(b) Accretion of discount from integrated services includes Premier Silica accretion expense, which is recorded as a reduction in third-party income from vertical integration services in interest and other income in the Company's accompanying consolidated statements of operations. See Note K for more information about interest and other income.

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 March 31, 2013 and December 31, 2012, the current portions of the Company's asset retirement obligations were $12.8 million and $13.3 million, respectively.

NOTE J. Commitments and Contingencies

The Company is a 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. 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.

22

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

NOTE K. Interest and Other Income

The following table provides the components of the Company's interest and other income for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013			2012
	(in thousands)
Alaskan Petroleum Production Tax credits and refunds (a)	$	19,408		$	11,846
Equity interest in income of unconsolidated affiliate	3,536			441
Other income	1,876			1,641
Deferred compensation plan income	1,627			1,374
Interest income	93			57
Income (loss) from vertical integration services (b)	(7,225		)	6,549
Total interest and other income	$	19,315		$	21,908

 ____________________

(a) The Company earns Alaskan Petroleum Production Tax ("PPT") credits on qualifying capital expenditures. The Company recognizes income from PPT credits when they are realized through cash refunds or as reductions in production and ad valorem taxes if realizable as offsets to PPT expense.

(b) Income (loss) from vertical integration services represent net margins that result from Company-provided fracture stimulation, drilling 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 months ended March 31, 2013 and 2012, these net margins include $56.1 million and $75.4 million of gross vertical integration revenues, respectively, and $63.3 million and $68.9 million of total vertical integration costs and expenses, respectively.

NOTE L. Other Expense

The following table provides the components of the Company's other expense for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013		2012
	(in thousands)
Transportation commitment charge (a)	$	9,377	$	8,453
Other	4,565		2,911
Above market and idle drilling and well services equipment rates (b)	3,507		4,986
Inventory impairment (c)	1,587		6,041
Contingency and environmental accrual adjustments	1,294		1,216
Terminated drilling rig contract charges (d)	1,019		—
Total other expense	$	21,349	$	23,607

 ____________________

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

(b) Primarily represents expenses attributable to the portion of Pioneer's contracted drilling rig rates that are above current market rates and idle drilling rig fees, neither of which are charged to joint operations.

(c) Represents valuation charges on excess materials and supplies inventories.

(d) Primarily represents charges to terminate a drilling rig contract that is not required to meet planned activities.

23

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

NOTE M. Income Taxes

The Company's income tax provisions attributable to income from continuing operations consisted of the following for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013			2012
	(in thousands)
Current	$	(7,435	)	$	(11,832	)
Deferred	(51,894		)	(105,871		)
Income tax provision	$	(59,329	)	$	(117,703	)

For each of the three months ended March 31, 2013 and 2012, the Company's effective tax rate, excluding income attributable to the noncontrolling interest, was 37 percent. The Company's effective tax rate differed from the U.S. statutory rate of 35 percent due to state income taxes and nondeductible expenses.

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 2011 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 March 31, 2013, 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.

NOTE N. Net Income Per Share

The Company uses the two-class method of calculating net income per share because certain of the Company's and its consolidated subsidiaries' unvested share-based awards qualify as participating securities. Participating securities participate in the Company's dividend or partnership distributions and are assumed to participate in the Company's undistributed income proportionate to their share of the weighted average outstanding common shares, but are not assumed to participate in the Company's net losses because they are not contractually obligated to do so. Accordingly, allocations of earnings to participating securities are included in the Company's calculations of basic and diluted earnings per share from continuing operations, discontinued operations and net income attributable to common stockholders.

During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share from continuing operations; therefore, conversion into common stock is assumed not to occur.

24

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

The following tables reconcile the Company's net income (loss) attributable to common stockholders to basic net income attributable to common stockholders and diluted net income (loss) attributable to common stockholders for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31, 2013
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	101,128		$	(465	)	$	100,663
Participating basic earnings	(1,270		)	—			(1,270		)
Basic net income (loss) attributable to common stockholders	99,858			(465		)	99,393
Reallocation of participating earnings	35			—			35
Diluted income (loss) attributable to common stockholders	$	99,893		$	(465	)	$	99,428

	Three Months Ended March 31, 2012
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	203,924		$	10,695		$	214,619
Participating basic earnings	(2,326		)	(122		)	(2,448		)
Basic income attributable to common stockholders	201,598			10,573			212,171
Reallocation of participating earnings	68			3			71
Diluted income attributable to common stockholders	$	201,666		$	10,576		$	212,242

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013	2012
	(in thousands)
Weighted average common shares outstanding:
Basic	128,940	122,480
Dilutive common stock options (a)	157	150
Convertible Senior Notes dilution	3,534	3,460
Contingently issuable performance unit shares	120	157
Diluted	132,751	126,247

 ____________________

(a) Options to purchase 98,819 shares of the Company's common stock were excluded from the diluted income per share calculations for the three months ended March 31, 2013 because they would have been anti-dilutive to the calculation.

NOTE O. Subsequent Event

In April 2013, Pioneer Southwest declared a cash distribution of $0.52 per common unit for the period from January 1 to March 31, 2013. The distribution is payable on May 10, 2013 to unitholders of record at the close of business on May 3, 2013. Associated therewith, Pioneer Southwest expects to pay $18.6 million of aggregate distributions.

On April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that have not been converted by the holders before May 16, 2013 for cash at a price equal to the full principal amount plus accrued and unpaid interest, in accordance with the indenture agreement. The Convertible Senior Notes are convertible at the option of

25

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

the holders prior to May 16, 2013, using a net share settlement process, into a combination of cash and shares of the Company's common stock based on a formula set forth in the indenture supplement. See Note G for additional information about the Convertible Senior Notes.

On May 7, 2013, the Company delivered a proposal to the chairman of the Conflicts Committee (the "Conflicts Committee") of the General Partner to acquire all of the outstanding common units of Pioneer Southwest that are held by unitholders other than Pioneer or its subsidiaries for consideration of .2234 of a share of common stock of Pioneer for each outstanding common unit of Pioneer Southwest held by such unitholders in a transaction to be structured as a merger of Pioneer Southwest with a wholly-owned subsidiary of Pioneer.  In proposing the .2234 exchange ratio, the Company stated that it has assumed that a regular quarterly common unit distribution of $0.52 per common unit will be declared by Pioneer Southwest in July 2013 and that, thereafter, common unit distributions will be suspended while the transaction is pending.  The consummation of the transactions contemplated by the Company's proposal is subject to approval of the Company's board of directors, approval of the Conflicts Committee and the negotiation of a definitive agreement.  There can be no assurance that a definitive agreement will be executed or that any transaction will be approved or consummated.

26

PIONEER NATURAL RESOURCES COMPANY

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 first quarter of 2013 included the following highlights:

• Net income attributable to common stockholders for the first quarter of 2013 was $100.7 million ($0.75 per diluted share), as compared to $214.6 million ($1.68 per diluted share) for the first quarter of 2012. The decrease in net income attributable to common stockholders is primarily comprised of a $101.1 million decrease in net income from continuing operations and an $11.2 million decline in income from discontinued operations, net of tax, as a result of completing the sale of Pioneer South Africa during the third quarter of 2012 and no longer recognizing the results of operations for Pioneer South Africa as discontinued operations. The primary components of the decrease in net income from continuing operations include:

▪ a $134.0 million change in net derivative activity, principally comprised of increases in gas derivative losses, partially offset by increases in oil derivative gains, as a result of cash settlements and changes in forward commodity prices and the Company's portfolio of derivatives;

▪ a $49.3 million increase in DD&A expense, primarily due to increased sales volumes and an increase in the carrying value of proved oil and gas properties; and

▪ a $37.4 million increase in oil and gas production costs, primarily due to increases in variable lease operating expenses and third-party transportation fees due to higher sales volumes; partially offset by

▪ a $68.9 million increase in oil and gas revenues as a result of an increase in sales volumes and average gas prices, partially offset by lower average oil and NGL prices; and

▪ a $58.4 million decrease in the Company's income tax provision.

• During the first quarter of 2013, average daily sales volumes from continuing operations increased by 16 percent to 170,900 BOEPD, as compared to 146,727 BOEPD during the first quarter of 2012. The increase in first quarter 2013 average daily sales volumes, as compared to the first quarter of 2012, was primarily due to the Company's successful drilling program during the last nine months of 2012 and the first three months of 2013.

• Average reported oil and NGL prices decreased during the first quarter of 2013 to $88.57 per BBL and $30.36 per BBL, respectively, as compared to $100.99 per BBL and $41.81 per BBL, respectively, in the first quarter of 2012. Average reported gas prices increased during the first quarter of 2013 to $3.14 per MCF, as compared to $2.51 per MCF in the first quarter of 2012.

• Average oil and gas production costs per BOE increased to $10.99 for the first quarter of 2013, as compared to $9.87 for the first quarter of 2012, primarily due to increases in lease operating expenses and third-party transportation charges. The increase in lease operating expenses is primarily due to inflation of field services costs and the increase in third-party transportation fees is primarily due to gathering, treating and transportation costs associated with increasing sales volumes in the Permian Basin and South Texas asset areas.

• Net cash provided by operating activities decreased to $360.1 million for the three months ended March 31, 2013, as compared to $426.1 million for the three months ended March 31, 2012. The $66.0 million decrease in net cash provided by operating activities is primarily due to working capital changes.

• 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 $1.7 billion. Sinochem will pay $522.0 million in cash to Pioneer at closing, before normal closing adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of Pioneer's portion of future drilling and facilities costs attributable to the horizontal Wolfcamp Shale play. This transaction is expected to close during the second quarter of 2013, subject to governmental approvals.

• During February 2013, the Company completed an offering of 10.35 million shares of its common stock at a per-share price, after underwriting and offering expenses, of $123.76 and realized $1.3 billion of associated net proceeds. The Company used the net proceeds from the offering to reduce outstanding debt under the Credit Facility and to increase cash and cash equivalents. The Company intends to use the increase in cash and cash equivalents for general corporate purposes, including funding the acceleration of horizontal appraisal drilling in the northern portion of the Company's highly prospective Wolfcamp/Spraberry acreage position in West Texas.

• During the first three months of 2013, certain holders of the Company's Convertible Senior Notes exercised their right to convert their Convertible Senior Notes. Associated therewith, the Company paid $261.3 million of cash and issued 2.4 million shares of the Company's common stock during the first quarter of 2013. In April 2013, the Company announced

27

PIONEER NATURAL RESOURCES COMPANY

that it would exercise its option to redeem all Convertible Senior Notes that have not been converted by the holders before May 16, 2013 for cash at a price equal to the full principal amount plus accrued and unpaid interest, in accordance with the indenture agreement. The Convertible Senior Notes are convertible at the option of the holders prior to May 16, 2013, using a net share settlement process, into a combination of cash and shares of the Company's common stock for the Convertible Senior Note's conversion value in excess of the principal amount. See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Convertible Senior Notes.

• As of March 31, 2013, the Company's net debt to book capitalization was 26 percent, as compared to 37 percent as of December 31, 2012. The Company was upgraded to investment grade by one of its debt rating agencies during the first quarter of 2013. Three of the major debt rating agencies have now upgraded the Company to investment grade.

Recent Developments

On May 7, 2013, the Company delivered a proposal to the chairman of the Conflicts Committee of the General Partner to acquire all of the outstanding common units of Pioneer Southwest that are held by unitholders other than Pioneer or its subsidiaries for consideration of .2234 of a share of common stock of Pioneer for each outstanding common unit of Pioneer Southwest held by such unitholders in a transaction to be structured as a merger of Pioneer Southwest with a wholly-owned subsidiary of Pioneer.  In proposing the .2234 exchange ratio, the Company stated that it has assumed that a regular quarterly common unit distribution of $0.52 per common unit will be declared by Pioneer Southwest in July 2013 and that, thereafter, common unit distributions will be suspended while the transaction is pending.  The consummation of the transactions contemplated by the Company's proposal is subject to approval of the Company's board of directors (the "Board"), approval of the Conflicts Committee and the negotiation of a definitive agreement.  There can be no assurance that a definitive agreement will be executed or that any transaction will be approved or consummated.

The consolidation of the properties of Pioneer and Pioneer Southwest in the Midland Basin in West Texas through this proposed transaction would facilitate the Company's plans to fully and optimally develop the area and would provide organizational, operational and administrative efficiencies. Pioneer owns 100 percent of the General Partner and owns approximately 52.4 percent of the 35,713,700 outstanding common units of Pioneer Southwest. See Notes B and O of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information about Pioneer Southwest.

Second Quarter 2013 Outlook

Based on current estimates, the Company expects the following operations and financial results from continuing operations for the quarter ending June 30, 2013:

Production is forecasted to average 174,000 to 179,000 BOEPD.

Production costs (including production and ad valorem taxes and transportation costs) are expected to average $14.00 to $16.00 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 $62 million to $67 million. Interest expense is expected to be $50 million to $55 million, and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries' net income, excluding noncash mark-to-market adjustments, is expected to be $8 million to $11 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company's effective income tax rate, excluding the effect of net income attributable to noncontrolling interest, 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 $5 million to $10 million, attributable to federal alternative minimum tax and state taxes.

28

PIONEER NATURAL RESOURCES COMPANY

Operations and Drilling Highlights

The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during the three months ended March 31, 2013:

	Oil (BBLs)	NGLs (BBLs)	Gas (MCF)	Total (BOE)
Permian Basin	52,763	13,303	62,116	76,418
South Texas - Eagle Ford Shale	12,741	10,133	86,305	37,257
Raton Basin	—	—	138,358	23,060
Mid-Continent	3,202	6,511	41,250	16,588
South Texas - Edwards and Austin Chalk	79	2	31,609	5,349
Barnett Shale	1,445	3,038	24,159	8,510
Alaska	3,707	—	—	3,707
Other	2	2	39	11
	73,939	32,989	383,836	170,900

During 2013 and 2012, the Company has focused its capital budgets and expenditures on oil and liquids-rich-gas drilling activities due to low gas prices. As a result of these capital activities, the Company's total liquids production from continuing operations increased to 63 percent of total production, on a BOE basis, for the three months ended March 31, 2013, as compared to 58 percent for the same period last year. Despite the increase in liquids production, the Company's liquids revenue, as a percent of total commodity sales, decreased to 86 percent for the three months ended March 31, 2013, as compared to 88 percent for the same period last year, due to a 25 percent increase in the average reported gas price and declines of 12 percent and 27 percent in reported oil and NGL prices, respectively, as compared to the first quarter of 2012.

The following table summarizes by geographic area the Company's finding and development costs incurred during the three months ended March 31, 2013:

	Acquisition Costs				Exploration		Development			Asset Retirement
	Proved		Unproved		Costs		Costs			Obligations			Total
	(in thousands)
Permian Basin	$	266	$	3,531	$	170,876	$	313,455		$	1,339		$	489,467
South Texas - Eagle Ford Shale	—		763		121,520		39,910			776			162,969
Raton Basin	—		—		1,728		1,009			—			2,737
Mid-Continent	—		59		712		861			—			1,632
South Texas - Edwards and Austin Chalk	—		—		292		72			—			364
Barnett Shale	1,071		1,452		22,612		(1,413		)	168			23,890
Alaska	—		—		41,326		52,827			(5,434		)	88,719
Other	4		360		9,176		—			22			9,562
	$	1,341	$	6,165	$	368,242	$	406,721		$	(3,129	)	$	779,340

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PIONEER NATURAL RESOURCES COMPANY

The following table summarizes the Company's development and exploration/extension drilling activities for the three months ended March 31, 2013:

	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	136	72	143	—	65
South Texas - Eagle Ford Shale	11	7	11	—	7
Alaska	4	1	1	—	4
	151	80	155	—	76

	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	17	23	14	—	26
South Texas - Eagle Ford Shale	21	30	26	—	25
Barnett Shale	9	8	7	2	8
Alaska	2	1	—	—	3
Other	—	3	—	—	3
	49	65	47	2	65

Permian Basin area. The Company completed 157 wells in the Permian Basin area during the first three months of 2013, all of which were successful.

The Company currently has 24 rigs operating in the Spraberry field, of which 15 are drilling vertical wells and nine are drilling horizontal Wolfcamp Shale wells. During 2013, the Company expects to drill approximately 290 vertical wells and 120 horizontal wells, with the horizontal wells being principally in the Wolfcamp Shale horizon. Excluding the southern Wolfcamp joint interest area, the Company expects to incur $1.2 billion of drilling capital in the Spraberry field during 2013.

In the horizontal Wolfcamp Shale play, the Company believes it has significant resource potential within its acreage based on its extensive geologic data covering the Wolfcamp A, B, C and D intervals and its drilling results to-date. The Company's horizontal drilling activity for 2013 will be focused on both the northern and southern portions of the play. During 2013, the Company expects to drill 30 to 40 horizontal wells in the northern portion of the play and 86 horizontal wells in the southern portion of the play.

During the fourth quarter of 2012, the Company initiated horizontal Wolfcamp Shale drilling activities to delineate the northern portion of its Spraberry acreage position by drilling in Midland County. During 2013, the Company plans to also test the Wolfcamp Shale potential in Martin County, Glasscock County and possibly Gaines County. Wells drilled in these areas are expected to benefit from greater original oil in place and higher reservoir pressures associated with deeper drilling depths. In addition, during 2013, the Company plans to drill several Spraberry Shale and Jo Mill horizontal wells. The Company expects to utilize five horizontal rigs in its northern acreage during 2013 to delineate the area's resource potential.

Specifically, during the second quarter of 2013, the Company's five-rig northern Spraberry drilling program will be focused in Midland and Martin counties and will consist of two horizontal rigs drilling Wolfcamp Shale appraisal wells, two horizontal rigs drilling Jo Mill and Spraberry Shale appraisal wells and one rig drilling Wolfcamp wells on the DL Hutt lease. Current plans are for all wells to be drilled on two-well pads to gain efficiencies; therefore, the wells will not be completed until after the second well on each pad is drilled.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval. This deeper drilling includes the Strawn, Atoka and Mississippian intervals. Production from these deeper intervals contributed to the Company's production growth during 2012. The 2013 drilling program reflects 90 percent of the wells being deepened below the Wolfcamp interval. Based on results to-date, the Company estimates that 85 percent of its Spraberry acreage position is prospective for the Strawn interval, that 40 percent to 50 percent of its acreage position is prospective for the Atoka interval and that the Mississippian interval is prospective in 20 percent of the Company's Spraberry acreage.

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 consideration of $1.7 billion. Sinochem will pay $522.0 million in cash to Pioneer at closing, before normal closing adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of Pioneer's portion of future drilling and facilities

30

PIONEER NATURAL RESOURCES COMPANY

costs attributable to the horizontal Wolfcamp Shale play. This transaction is expected to close during the second quarter of 2013, subject to governmental approvals.

The Company and Sinochem have agreed to a plan to drill 86 horizontal Wolfcamp Shale wells during 2013, 120 wells in 2014 and 165 wells in 2015. Associated therewith, the Company expects to incur $425.0 million of drilling and facilities capital during 2013. To the extent the joint interest partner elects to participate in any vertical wells that are drilled in the joint interest area after the December 1, 2012 effective date, the joint interest partner will receive its share of production and costs from the Wolfcamp and deeper horizons based on the anticipated reserve contribution from the Wolfcamp and deeper intervals relative to anticipated reserves from all completed intervals. Pioneer's and the joint interest owner's participation in vertical wells will be based on each party's interest without any drilling carry being applied. Pioneer will retain 100 percent of its vertical production in the joint interest area for wells drilled before the December 1, 2012 effective date. Pioneer will also retain its current working interests in all horizons shallower than the Wolfcamp horizon and will continue as operator of the properties in the joint interest area.

The southern joint interest area includes defined portions of Upton, Reagan, Irion, Crockett and Tom Green counties in Texas. The thickness of the Wolfcamp B interval in the southern joint interest area provides opportunities for completions in laterally stacked Upper B and Lower B intervals. The Company is also assessing opportunities to optimize completion techniques in the joint interest area, including the testing of slickwater fracture stimulation techniques. The Company performed five Wolfcamp B slickwater fracture stimulations during the first four months of 2013 in the southern Wolfcamp joint interest area with encouraging results. Slickwater fracture stimulations are expected to result in significant cost savings, as compared to the hybrid fracture stimulations that the Company has been utilizing in the area. The Company operated seven rigs in the southern joint interest area during the first quarter of 2013 and plans to continue at this level of utilization throughout 2013.

The Company continues to expand its integrated services to control drilling and operating costs and support the execution of its drilling and production activities in the Spraberry field. The Company owns 15 vertical drilling rigs and is presently utilizing three Company-owned vertical fracture stimulation fleets totaling approximately 60,000 horsepower and three Company-owned horizontal fracture stimulation fleets totaling approximately 105,000 horsepower in the Spraberry field. To support its growing 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 the majority of the Company's brown sand requirements for proppant that is being used to fracture stimulate vertical and horizontal wells in the Spraberry and Wolfcamp Shale intervals.

Eagle Ford Shale area. The Company's drilling activities in the South Texas area during 2013 continue to be primarily focused on delineation and development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2013 drilling program has been focused on liquids-rich drilling, with only 10 percent of the wells designated to hold strategic dry gas acreage.

The Company completed 37 horizontal Eagle Ford Shale wells during the first three months of 2013, all of which were successful, with average lateral lengths of approximately 5,100 feet and, on average, 13-stage fracture stimulations. The Company plans to incur $575 million of drilling capital and utilize 10 drilling rigs in 2013 to drill approximately 130 Eagle Ford Shale wells. The Company plans to primarily use two Pioneer-owned fracture stimulation fleets during 2013 in the Eagle Ford Shale area.

The Company's drilling operations in the Eagle Ford Shale continue to have a focus on efficiencies. The number of wells drilled from pads, as opposed to single-well locations, is expected to increase from about 45 percent of the Eagle Ford Shale wells during 2012 to about 80 percent in 2013, reflecting that most of the Company's acreage is now held by production. Pad drilling saves the Company a significant amount of capital costs per well, as compared to single-well location drilling.

The Company has been using lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. The Company is expanding the use of white sand proppant to deeper areas of the field to further define its performance limits. Early well performance has been similar to direct offset ceramic-stimulated wells. The Company fracture stimulated 22 wells with white sand proppant in the first quarter of 2013, with significant capital savings per well. The Company is continuing to monitor the performance of these wells and expects that greater than 70 percent of its 2013 drilling program will use lower-cost white sand proppant.

The unconsolidated affiliate formed by the Company to operate gathering facilities in the Eagle Ford Shale area, EFS Midstream LLC ("EFS Midstream"), is obligated to construct midstream assets in the Eagle Ford Shale area. Eleven of the 13 planned central gathering plants ("CGPs") had been completed as of March 31, 2013. EFS Midstream is providing gathering, treating and transportation services for the Company during a 20-year contractual term.

Barnett Shale. The Company completed nine Barnett Shale Combo wells during the first three months of 2013, of which seven were successful. During 2013, the Company increased from one drilling rig to two drilling rigs late in the first quarter. The Company expects to drill 55 wells in 2013 and incur capital expenditures of $185.0 million.

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PIONEER NATURAL RESOURCES COMPANY

Alaska. The Company owns a 70 percent working interest in, and is the operator of, the Oooguruk development project. Since inception, the Company has drilled 19 production wells and ten injection wells to develop this project. During the first quarter of 2012, the Company drilled the Nuna-1 exploration well from an onshore location to evaluate the productivity of the Torok formation and the feasibility of future development expansion.  The Company flow-tested the well during April 2012 until production could no longer be transported along the ice road being utilized. During the first quarter of 2013, the Company re-entered and performed a second flow-test of the well at a facility-limited average rate of approximately 2,800 BOEPD. In addition, the Company drilled and logged a second appraisal well in the Torok formation to further evaluate its resource potential. The second appraisal well encountered a mechanical problem and could not be flow-tested before the end of the winter drilling season. The results of the flow-tests on the Nuna-1 well and the log data from the second Nuna well are both encouraging. The Company is currently evaluating the results of the first two Torok wells and the potential for permanent onshore production facilities, for which a FEED study has been initiated.

The Company completed one Oooguruk development well during the three months ended March 31, 2013, which was successful. The Company also successfully completed mechanically-diverted fracture stimulations of four wells from the Oooguruk island facilities during the first quarter of 2013. Three of these wells were in the Nuiqsut interval and one was in the Torok interval. All of the wells are scheduled to be placed on production during the second quarter of 2013. The Company plans to incur $190 million of capital expenditures in Alaska during 2013.

Results of Operations from Continuing Operations

Oil and gas revenues. Oil and gas revenues totaled $787.9 million for the three months ended March 31, 2013, as compared to $719.0 million for the same period in 2012.

The increase in oil and gas revenues during the three months ended March 31, 2013, as compared to the same period in 2012, is reflective of 28 percent, 20 percent and four percent increases in daily oil, NGL and gas sales volumes, respectively, and a 25 percent increase in reported gas prices. Partially offsetting the effects of these increases were declines of 12 percent and 27 percent in reported oil and NGL prices, respectively.

The following table provides average daily sales volumes for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013	2012
Oil (BBLs)	73,939	57,671
NGLs (BBLs)	32,989	27,485
Gas (MCF)	383,836	369,422
Total (BOE)	170,900	146,727

Average daily BOE sales volumes increased by 16 percent for the three months ended March 31, 2013, as compared to the same period in 2012, principally due to the Company's successful drilling programs.

Production growth for the three months ended March 31, 2013, as compared to the first quarter of 2012, was negatively impacted by gas processing capacity limitations in the Spraberry field as a result of wet gas production for the Company and other industry participants growing faster than anticipated. The gas processing capacity limitations resulted in reduced recoveries of ethane, negatively impacting sales volumes for the first quarter of 2013 by approximately 2,700 BOEPD. New Spraberry field gas processing facilities were recently completed and began processing gas in mid-April 2013, which is expected to alleviate the Spraberry gas processing capacity limitations.

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PIONEER NATURAL RESOURCES COMPANY

The oil, NGL and gas prices that the Company reports are based on the market prices received for the commodities. The following table provides the Company's average prices for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013		2012
Oil (per BBL)	$	88.57	$	100.99
NGL (per BBL)	$	30.36	$	41.81
Gas (per MCF)	$	3.14	$	2.51
Total (per BOE)	$	51.22	$	53.85

 ____________________

(a) For the three months ended March 31, 2012, the Company's average realized oil price per BBL and total price per BOE were $99.15 and $53.12, respectively. The average realized prices do not include the impact of transfers of the Company's deferred hedge losses, net from Accumulated Other Comprehensive Income from hedging activities ("AOCI-Hedging") and the amortization of deferred volumetric production payment ("VPP") revenue. During the three months ended March 31, 2012, the Company transferred $809 thousand of deferred oil hedge gains from AOCI-Hedging to oil revenue. During 2012, all remaining AOCI-Hedging was transferred to earnings. Amortization of deferred VPP revenue increased oil revenues by $10.5 million during the three months ended March 31, 2012. As of December 31, 2012, all VPP production volumes had been delivered and there were no further obligations under VPP contracts or deferred revenue.

Interest and other income. Interest and other income for the three months ended March 31, 2013 was $19.3 million, as compared to $21.9 million for the same period in 2012. The $2.6 million decrease in interest and other income during the three months ended March 31, 2013, as compared to the same period in 2012, was primarily due to a $13.8 million decrease in earnings from third-party vertical integration services, primarily due to under-utilized services capacity, partially offset by a $7.6 million increase in Alaskan PPT credit recoveries and a $3.1 million increase in equity in earnings of EFS Midstream. See Note K of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding interest and other income.

Gain on disposition of assets, net. The Company recorded net gains on the disposition of assets of $24.4 million during the three months ended March 31, 2013, as compared to net gains on the disposition of assets of $43.6 million for the same period of 2012. The net gains for the three months ended March 31, 2013 are primarily associated with the sale of the Company's interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations to an unaffiliated third party for cash proceeds of $37.4 million, which resulted in a pretax gain of $21.7 million. The net gain for the three months ended March 31, 2012 includes the first quarter sale of a portion of the Company's interest in an unproved oil and gas property in the Eagle Ford Shale field to unaffiliated third parties for cash proceeds of $54.7 million, which resulted in a pretax gain of $42.6 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 $169.1 million during the three months ended March 31, 2013 as compared to $131.8 million during the same period in 2012. In general, 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/gathering 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 the three months ended March 31, 2013 increased by 11 percent, as compared to the same period in 2012. The increase in production costs per BOE during the three months ended March 31, 2013, as compared to the first quarter of 2012, is primarily reflective of increases in lease operating expenses and third-party transportation charges. The increase in per BOE lease operating costs during the three months ended March 31, 2013 was primarily due to inflation of field services costs, increases in salt-water disposal costs and sales volumes lost due to the aforementioned gas processing capacity constraints in the Spraberry field. The increase in third-party transportation charges during the three months ended March 31, 2013 is primarily due to gathering, treating and transportation costs associated with increasing sales volumes from the Company's successful drilling program in the Permian Basin and South Texas asset areas.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides the components of the Company's oil and gas production costs per BOE for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013		2012
Lease operating expenses	$	8.34	$	7.69
Third-party transportation charges	1.67		1.25
Net natural gas plant charges	0.17		0.24
Workover costs	0.81		0.69
Total production costs	$	10.99	$	9.87

Production and ad valorem taxes. The Company's production and ad valorem taxes were $54.3 million during the three months ended March 31, 2013 as compared to $45.8 million for the same period in 2012. 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 months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013		2012
Production taxes	$	2.11	$	2.32
Ad valorem taxes	1.42		1.11
Total production and ad valorem taxes	$	3.53	$	3.43

Depletion, depreciation and amortization expense. The Company's DD&A expense was $230.8 million ($15.00 per BOE) for the three months ended March 31, 2013 as compared to $181.4 million ($13.59 per BOE) during the same period in 2012. The increase in per BOE depletion expense during the three months ended March 31, 2013, as compared to the same periods of 2012, is primarily due to increases in depletion expense per BOE on oil and gas properties.

Depletion expense on oil and gas properties was $14.34 per BOE during the three months ended March 31, 2013 as compared to $12.99 per BOE during the same period in 2012. The 10 percent increase in per BOE depletion expense during the three months ended March 31, 2013, as compared to the same period in 2012, is primarily due to capital expenditures to develop proved undeveloped locations, primarily in the Spraberry field, partially offset by the impairment effects of reducing the carrying value of proved properties for the Barnett Shale field during 2012.

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 these or other 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 commodity price outlooks and (iv) increases or decreases in production and capital costs associated with these fields.

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 months ended March 31, 2013 and 2012 (in thousands):

	Three Months Ended March 31,
	2013		2012
Geological and geophysical	$	19,623	$	26,035
Exploratory dry holes	7,745		26,879
Leasehold abandonments and other	259		373
	$	27,627	$	53,287

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PIONEER NATURAL RESOURCES COMPANY

The Company's geological and geophysical costs decreased by $6.4 million during the three months ended March 31, 2013, as compared to the same period in 2012, primarily as a result of decreased seismic and seismic interpretation expenditures supportive of drilling activities in the Spraberry field. The Company's exploratory dry holes decreased by $19.1 million during the three months ended March 31, 2013, as compared to the same period in 2012, primarily due to dry hole provisions of $19.1 million related to an unsuccessful exploration well in Alaska that was drilled during the first quarter of 2012 and first quarter 2012 dry hole provisions associated with exploration wells completed in the South Texas Austin Chalk field and the Mid-Continent area, which were partially offset by first quarter 2013 dry hole provisions associated with exploration wells drilled in the Barnett Shale field.

During the three months ended March 31, 2013, the Company drilled and evaluated 49 exploration/extension wells, 47 of which were successfully completed as discoveries. During the same period in 2012, the Company drilled and evaluated 54 exploration/extension wells, 48 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense for the three months ended March 31, 2013 was $63.8 million, as compared to $63.1 million for the same period in 2012.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $3.2 million for the three months ended March 31, 2013, as compared to $2.4 million during the same period in 2012. 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 $50.7 million for the three months ended March 31, 2013, as compared to $46.9 million during the same period in 2012. The weighted average interest rate on the Company's indebtedness for the three months ended March 31, 2013, including the effects of capitalized interest, was 5.9 percent, as compared to 7.7 percent for the same period in 2012. Interest expense increased by $3.8 million during the three months ended March 31, 2013, as compared to the same period in 2012, primarily due to an increase of $6.9 million in interest on credit facility and senior note borrowings due to higher average borrowings during January and early-February 2013, and a decrease of $2.2 million in capitalized interest, partially offset by a decrease of $5.0 million in noncash amortization of debt issuance discounts and deferred hedge losses.

Derivative (gains) losses, net. The primary purposes for which the Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts are 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 months ended March 31, 2013, the Company recorded $42.2 million of net derivative losses on commodity price and interest rate derivatives, of which $95.9 million represented unrealized net losses and $53.7 million represented realized net gains. During the three months ended March 31, 2012, the Company recorded $91.8 million of net derivative gains, of which $28.1 million represented unrealized net gains and $63.7 million represented realized net gains. 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.

Other expense. Other expense for the three months ended March 31, 2013 was $21.3 million, as compared to $23.6 million for the same period in 2012. The decrease in other expense for the three months ended March 31, 2013, as compared to the same period in 2012, is primarily attributable to a $4.5 million decrease in inventory valuation charges, partially offset by $1.0 million and $924 thousand increases in rig contract termination fees and transportation commitment charges on excess pipeline capacity commitments, respectively. See Note L of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Income tax provision. The Company recorded an income tax provision from continuing operations of $59.3 million for the three months ended March 31, 2013, as compared to an income tax provision of $117.7 million for the same period in 2012. The Company's effective tax rates, excluding net income attributable to noncontrolling interests, for the each of the three months ended March 31, 2013 and 2012 were 37 percent, as compared to the Company's combined United States federal and state statutory rate of 37 percent. 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 a loss from discontinued operations, net of tax, of $465 thousand for the three months ended March 31, 2013, as compared to income from discontinued operations, net of tax, of $10.7 million for the three months ended March 31, 2012. The decrease in earnings from discontinued operations is primarily the result of completing the sale of Pioneer South Africa during the third quarter of 2012 and no longer recognizing the results of operations for Pioneer South Africa as discontinued operations.

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PIONEER NATURAL RESOURCES COMPANY

In August 2012, the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, including normal post-closing adjustments. The sale resulted in a pretax gain of $28.6 million. 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 the noncontrolling interests for the three months ended March 31, 2013 was $8.1 million, as compared to $6.3 million for the same period of 2012. The $1.8 million increase in income attributable to noncontrolling interests for the three months ended March 31, 2013, as compared to the same period in 2012, is primarily due to decreases in Pioneer Southwest's mark-to-market derivative losses, offset by reduced revenues, higher production costs and higher depletion expense.

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/distributions 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 sale of joint interests and nonstrategic assets or external financing sources as discussed in "Capital resources" below.

The Company's capital budget for 2013 is focused on oil and liquids-rich-gas drilling activities with total expenditures of $3.0 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs), consisting of $2.75 billion for drilling operations, including budgeted land capital for existing assets, and $240 million for buildings, expansion of the Company's principal sand mine in Brady, Texas and vertical integration additions. Based on results for the three months ended March 31, 2013 and management's commodity price outlooks, the Company expects its cash flows from operating activities, cash and cash equivalents on hand, proceeds from asset sales and/or joint ventures and availability under its Credit Facility to be sufficient to fund its planned capital expenditures and contractual obligations for the remainder of 2013.

Investing activities. Investing activities used $707.2 million of cash during the three months ended March 31, 2013, as compared to $679.7 million of cash used in investing activities during the three months ended March 31, 2012. The $27.5 million increase in cash used in investing activities for the three months ending March 31, 2013, as compared to the three months ended March 31, 2012, is primarily due to (i) an $18.9 million increase in additions to oil and gas properties and (ii) a $12.3 million decrease in proceeds from the disposition of assets, partially offset by (iii) a $3.7 million decrease in additions to other assets and other property and equipment. During the three months ended March 31, 2013, the Company's investing activities were funded by net cash provided by operating activities and a portion of the proceeds from the February issuance of 10.35 million shares of the Company's common stock.

Dividends/distributions. During February of both 2013 and 2012, 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, the Pioneer Southwest board of directors (the "Pioneer Southwest Board") declared a quarterly distribution of $0.52 per limited partner unit, compared to the quarterly distribution of $0.51 per limited partner unit declared in January 2012. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $8.8 million and $8.7 million during the three months ended March 31, 2013 and 2012, respectively. During April 2013, the Pioneer Southwest Board declared a quarterly distribution of $0.52 per limited partner unit for unitholders of record on May 3, 2013, payable May 10, 2013. Future distributions by Pioneer Southwest are at the discretion of the Pioneer Southwest Board, and, if declared, the Pioneer Southwest Board may change the distribution amount based on Pioneer Southwest's liquidity and capital resources at the time.

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 March 31, 2013, 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

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PIONEER NATURAL RESOURCES COMPANY

transportation commitments on uncertain volumes of future throughput. Other than the off-balance sheet arrangements described above, the Company has no 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, 2012, the material changes in the Company's contractual obligations include a $707.3 million decrease in the principal balances of outstanding long-term debt and a $95.9 milliondecrease in the Company's derivative net assets.

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 March 31, 2013, these contracts represented net assets of $212.8 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 March 31, 2013. 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 sales of joint interests and 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 joint interests or nonstrategic assets.

Operating activities. Net cash provided by operating activities during the three months ended March 31, 2013 was $360.1 million, as compared to $426.1 million during the same period of 2012. The decrease in net cash provided by operating activities for the three months ended March 31, 2013, as compared to the three months ended March 31, 2012, is primarily due to working capital changes.

Asset divestitures. 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 $1.7 billion. Sinochem will pay $522.0 million in cash to Pioneer at closing, before normal closing adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of Pioneer's portion of future drilling and facilities costs attributable to the horizontal Wolfcamp Shale play. This transaction is expected to close during the second quarter of 2013, subject to governmental approvals.

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 $37.4 million of cash proceeds, which resulted in a pretax gain of $21.7 million.

Financing activities. Net cash provided by financing activities during the three months ended March 31, 2013 was $548.0 million, as compared to net cash provided by financing activities of $33.0 million during the three months ended 2012. The increase in net cash provided from financing activities during the first quarter of 2013 was primarily the result of the Company completing an offering of 10.35 million shares of its common stock in February 2013 at a per-share price, after underwriting and offering expenses, of $123.76 for a total of $1.3 billion of realized net proceeds. The increase was offset by net principal payments on long-term debt of $707.3 million.

The Convertible Senior Notes are convertible at the option of the holders under certain circumstances, using a net share settlement process, into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the Convertible Senior Notes were issued. In the three months ended December 31, 2012, the Company's stock price met the price threshold that causes the Convertible Senior Notes to be convertible at the option of the holders for the three months ended March 31, 2013. Associated therewith, during the three months ended March 31, 2013, holders of $274.1 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock and the Company paid the tendering holders $261.3 million of cash and issued to the tendering holders 2.4 million shares of the Company's common stock during the three months ended March 31, 2013, in accordance with the terms of the Convertible Senior Notes indenture agreement. The remaining $12.8 million principal amount was settled in cash and 115 thousand shares of the Company's common stock in April 2013. The Company's stock prices during March 2013 and 2012 also met the price threshold that causes the Convertible Senior Notes to be convertible at the option of the holders for the following three month period.

On January 15, 2013, the Convertible Senior Notes became redeemable by the Company at any time for cash at a price equal to the full principal amount plus accrued and unpaid interest. On April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that have not been converted by the holders before May 16, 2013. As a result of the Company's notice of intent to redeem, all of the remaining Convertible Senior Notes are convertible by the holders

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PIONEER NATURAL RESOURCES COMPANY

if a notice of intent to convert is provided by the holder prior to May 16, 2013. The Company expects that the holders will exercise their right to convert the Convertible Senior Notes rather than allow their securities to be redeemed by the Company. The Company has the intent and ability to fund cash payments that may be required upon the conversion or redemption of the Convertible Senior Notes with borrowing capacity under the Credit Facility. Accordingly, the Convertible Senior Notes are classified as long-term debt in the accompanying balance sheets.

If all of the remaining Convertible Senior Notes had been converted on March 31, 2013, the note holders would have received $218.6 million of cash and approximately 2.1 million shares of the Company's common stock, which were valued at $259.7 million on March 31, 2013. Holders of the Convertible Senior Notes who present their notes for conversion prior to May 16, 2013, will be subject to a 20 consecutive day cash settlement averaging period that will encompass the trading days from April 16, 2013 through May 13, 2013.

Interest on the principal amount of the Convertible Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The trading price of the Convertible Senior Notes for the five consecutive trading days preceding January 15, 2013 exceeded 120 percent of the principal amount of the note and, in accordance with the indenture supplement, the interest rate in effect during the January 15, 2013 to July 14, 2013 period was reduced to 2.375 percent.

As the Company pursues its strategy, it may utilize various financing sources, including, to the extent available, fixed and floating rate debt, convertible securities, preferred stock or common stock. 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 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 March 31, 2013, the Company had no outstanding borrowings under its Credit Facility and was in compliance with all of its debt covenants. The Company had $1.5 billion of unused borrowing capacity as of March 31, 2013. 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 joint interests or 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 sales of joint interests or nonstrategic assets and available capacity under the Company's Credit Facility will be adequate to fund 2013 capital expenditures and dividend/distribution 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 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. The Company is rated as investment grade by three credit rating agencies, including one credit rating agency that upgraded the Company's credit rating during March 2013.

Book capitalization and current ratio. The Company's net book capitalization at March 31, 2013 was $9.9 billion, consisting of $430.3 million of cash and cash equivalents, debt of $3.0 billion and equity of $7.3 billion. The Company's net debt to net book capitalization was 26 percent and 37 percent at March 31, 2013 and December 31, 2012, respectively. The Company's ratio of current assets to current liabilities was 1.23 to 1.00 at March 31, 2013, as compared to 1.02 to 1.00 at December 31, 2012.

New accounting pronouncements. There are no new accounting pronouncements that are likely of having a material effect on the Company's consolidated financial statements.

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PIONEER NATURAL RESOURCES COMPANY

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, 2012. 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, 2012.

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 of 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 three months ending March 31, 2013:

	Derivative Contract Net Assets
	Commodities			Interest Rates			Total
	(in thousands)
Fair value of contracts outstanding as of December 31, 2012	$	318,377		$	(9,724	)	$	308,653
Changes in contract fair value	(46,183		)	3,940			(42,243		)
Contract maturities	(53,643		)	—			(53,643		)
Fair value of contracts outstanding as of March 31, 2013	$	218,551		$	(5,784	)	$	212,767

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 debt transactions.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides information about financial instruments to which the Company was a party as of March 31, 2013 and that are sensitive to changes in interest rates. For debt obligations, the table presents 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 March 31, 2013. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on May 2, 2013.

	Nine Months Ending December 31,			Year Ending December 31,																	Liability Fair Value at March 31,
	2013			2014			2015			2016			2017			Thereafter			Total		2013
	(dollars in thousands)
Total Debt:
Fixed rate principal maturities (a)	$	218,576		$	—		$	—		$	455,385		$	485,100		$	1,749,500		$	2,908,561	$	(3,618,532	)
Weighted average interest rate	6.20		%	6.15		%	6.15		%	6.17		%	6.11		%	6.28		%
Variable rate principal maturities:
Pioneer Southwest credit facility	$	—		$	—		$	—		$	—		$	154,000		$	—		$	154,000	$	(150,352	)
Weighted average interest rate	1.91		%	1.99		%	2.21		%	2.56		%	2.64		%
Interest Rate Swaps:
Notional debt amount	$	—		$	—		$	250,000		$	—		$	—		$	—		$	250,000	$	(5,784	)
Fixed rate payable (%)	—		%	—		%	3.21		%	—		%	—		%	—		%
Variable rate receivable (%)	—		%	—		%	2.66		%	—		%	—		%	—		%

 ____________________

(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 March 31, 2013. 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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PIONEER NATURAL RESOURCES COMPANY

	Nine Months Ending December 31,			Year Ending December 31,							Asset (Liability) Fair Value at March 31,
	2013			2014			2015		2016		2013 (a)
											(in thousands)
Oil Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts	72,430			69,000			26,000		—		$	166,459
Weighted average ceiling price per BBL	$	119.89		$	114.05		$	104.45	$	—
Weighted average floor price per BBL	$	92.26		$	93.70		$	95.00	$	—
Weighted average short put price per BBL	$	74.36		$	77.61		$	80.00	$	—
Swap contracts	3,000			—			—		—		$	(12,900	)
Weighted average fixed price per BBL	$	81.02		$	—		$	—	$	—
Average forward NYMEX oil prices (b)	$	93.63		$	90.26		$	87.19	$	—
Rollfactor swap contracts	6,000			15,000			—		—		$	(156	)
Weighted average fixed price per BBL (c)	$	0.43		$	0.38		$	—	$	—
Average forward rollfactor prices (b)	$	0.38		$	0.41		$	—	$	—
Midland-Cushing index swap contracts	1,655			—			—		—		$	(2,510	)
Weighted average fixed price per BBL	$	(5.75	)	$	—		$	—	$	—
Average forward basis differential prices (d)	$	(0.11	)	$	—		$	—	$	—
Cushing-LLS index swap contracts	669			—			—		—		$	55
Weighted average fixed price per BBL	$	(9.30	)	$	—		$	—	$	—
Average forward basis differential prices (e)	$	(6.40	)	$	—		$	—	$	—
NGL Derivatives (f):
Average daily notional BBL volumes:
Collar contracts with short puts	1,064			1,000			—		—		$	2,766
Weighted average ceiling price per BBL	$	105.28		$	109.50		$	—	$	—
Weighted average floor price per BBL	$	89.30		$	95.00		$	—	$	—
Weighted average short put price per BBL	$	75.20		$	80.00		$	—	$	—
Average forward NGL prices (g)	$	84.29		$	79.25		$	—	$	—
Gas Derivatives:
Average daily notional MMBTU volumes:
Collar contracts with short puts (h)	—			65,000			235,000		20,000		$	543
Weighted average ceiling price per MMBTU	$	—		$	4.70		$	5.09	$	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
Collar contracts (h)	150,000			—			—		—		$	38,110
Weighted average ceiling price per MMBTU	$	6.25		$	—		$	—	$	—
Weighted average floor price per MMBTU	$	5.00		$	—		$	—	$	—
Swap contracts	170,282			175,000			20,000		—		$	30,629
Weighted average fixed price per MMBTU	$	5.07		$	4.02		$	4.31	$	—
Average forward NYMEX gas prices (b)	$	4.14		$	4.24		$	4.26	$	4.30
Basis swap contracts (h)	162,500			10,000			—		—		$	(4,458	)
Weighted average fixed price per MMBTU	$	(0.22	)	$	(0.19	)	$	—	$	—
Average forward basis differential prices (i)	$	(0.12	)	$	(0.20	)	$	—	$	—

___________________

(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) The average forward NYMEX oil and gas prices are based on May 2, 2013 market quotes.

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PIONEER NATURAL RESOURCES COMPANY

(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.

(d) The average forward basis differential prices are based on May 2, 2013 market quotes for basis differentials between Midland WTI and Cushing WTI.

(e) The average forward basis differential prices are based on May 2, 2013 market quotes for basis differentials between Cushing WTI and Louisiana Light Sweet crude "LLS".

(f) Subsequent to March 31, 2013, the Company entered into additional NGL contracts for (i) 2,000 BBLs per day of the Company's May through December 2013 ethane production with a ceiling price of $12.60 per BBL and a floor price of $10.50 per BBL, (ii) 500 BBLs per day of the Company's July through December 2013 ethane production with a ceiling price of $13.02 per BBL and a floor price of $10.50 per BBL and (iii) 3,000 BBLs per day of the Company's 2014 ethane production with a ceiling price of $13.72 per BBL and a floor price of $10.78 per BBL.

(g) Forward component NGL prices are derived from active-market NGL component price quotes as of May 2, 2013.

(h) Subsequent to March 31, 2013, the Company entered into additional (i) collar contracts for 2,500 MMBTUs per day of the Company's June through December 2013 production with a ceiling price of $4.50 per MMBTU and a floor price of $4.00 per MMBTU, (ii) collar contracts with short puts for 50,000 MMBTUs per day of the Company's 2014 production with a ceiling price of $4.70 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU, (iii) collar contracts with short puts for 50,000 MMBTUs per day of the Company's 2015 production with a ceiling price of $5.03 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU, (iv) basis swap contracts for 22,500 MMBTU per day of the Company's 2014 production with a negative price differential of $0.18 per MMBTU between the relevant index price and the NYMEX price and (v) basis swap contracts for 7,500 MMBTU per day of the Company's 2015 production with a negative price differential of $0.13 per MMBTU between the relevant index price and the NYMEX price.

(i) The average forward basis differential prices are based on May 2, 2013 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

Marketing and basis transfer derivative instruments and price sensitivity. The Company manages commodity price risk and mitigates firm transportation commitment costs with derivative contracts. 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.

The following table provides information about the Company's marketing and basis transfer derivative financial instruments that were sensitive to changes in prices as of March 31, 2013:

	Nine Months Ending December 31,		Asset Fair Value at March 31,
	2013		2013
			(in thousands)
Average Daily Gas Production Associated with Marketing Derivatives (MMBTU):
Basis swap contracts:
Index swap volume	4,364		$	13
Price differential ($/MMBTU)	$	0.34
Average forward basis differential prices (a)	$	0.17

 ____________________

(a) The average forward basis differential prices are based on May 2, 2013 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

42

PIONEER NATURAL RESOURCES COMPANY

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 March 31, 2013 that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting.

43

PIONEER NATURAL RESOURCES COMPANY

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, 2012, 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 have been no material changes 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 March 31, 2013:

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
January 2013	—	$	—	—
February 2013	148,258	$	129.52	—
March 2013	—	$	—	—
Total	148,258	$	129.52	—	$	—

 ____________________

(a) Consists of shares purchased from employees 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.

44

PIONEER NATURAL RESOURCES COMPANY

Item 6.Exhibits

Exhibits

Exhibit Number		Description
10.1	(a) —	Change in Control Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement.
10.2	—	Indemnification Agreement, dated February 21, 2013, between the Company and  Thomas D. Arthur, together with a schedule identifying other substantially identical agreements between the Company and each of its non-employee directors 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 February 26, 2013).
10.3	—	Indemnification Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers 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 March 8, 2013).
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.

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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: May 8, 2013	By:	/s/    RICHARD P. DEALY
		Richard P. Dealy
		Executive Vice President and Chief Financial Officer
Date: May 8, 2013	By:	/s/    FRANK W. HALL
		Frank W. Hall
		Vice President and Chief Accounting Officer

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PIONEER NATURAL RESOURCES COMPANY

Exhibit Index

Exhibit Number		Description
10.1	(a) —	Change in Control Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement.
10.2	—	Indemnification Agreement, dated February 21, 2013, between the Company and  Thomas D. Arthur, together with a schedule identifying other substantially identical agreements between the Company and each of its non-employee directors 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 February 26, 2013).
10.3	—	Indemnification Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers 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 March 8, 2013).
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.

47

EX-10.1

Exhibit 10.1

PIONEER NATURAL RESOURCES COMPANY

CHANGE IN CONTROL AGREEMENT

This Change in Control Agreement (“Agreement”) is entered into, as of March 4, 2013, among Pioneer Natural Resources Company, a Delaware corporation (“Parent”), Pioneer Natural Resources USA, Inc., a Delaware corporation that is a wholly-owned subsidiary of Parent (“Employer”), and Scott D. Sheffield (“Employee”). As henceforth used in this Agreement, the term “Company” shall be deemed to include Parent and its direct or indirect majority-owned subsidiaries.

Recitals

Parent and Employer acknowledge that Employee possesses skills and knowledge instrumental to the successful conduct of the Company’s business. Parent and Employer are willing to enter into this Agreement with Employee in order to better ensure themselves of access to the continued services of Employee both before and after a Change in Control.

NOW, THEREFORE, for and in consideration of the mutual covenants and agreements set forth herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties to this Agreement hereby agree as follows:

1.     Term. The term of this Agreement shall commence on the date indicated above (the “Effective Date”) and end on September 30, 2014. Thereafter, on the date on which the term of this Agreement (as it may be extended from time to time under this paragraph 1) would otherwise expire, so long as Employee is still an employee of the Company on such date, such term will be automatically extended for 12 months, unless Parent shall have provided written notice to Employee at least 6 months before the date that the term would otherwise expire that it does not want the term to be extended. Parent may deliver a conditional notice of non-renewal that will be effective only if Employee does not agree, within the time period specified by Parent, to any amendment or modification of this Agreement that Parent shall request be executed as a condition to allowing the term hereof to be extended. Notwithstanding the foregoing, and regardless of whether Parent has theretofore delivered a notice of non-renewal and/or sought agreement from Employee to amendments to this Agreement, if a Potential Change in Control or a Change in Control occurs during the term hereof, the term of this Agreement shall be automatically extended to the second anniversary of the date on which the Change in Control occurs (the “Change in Control Date”); provided, however, that if no Change in Control has occurred prior to the first anniversary of the occurrence of a Potential Change in Control and the Board of Directors of Parent (the “Board”), acting in good faith, thereafter adopts a resolution that such Potential Change in Control will not result in the occurrence of a Change in Control, the term of this Agreement shall expire on a date specified by the Board not earlier than the first anniversary of the adoption of such resolution (unless otherwise extended pursuant to the second sentence of this paragraph 1).

2.     Operation of Agreement. Except as expressly provided below, no benefits shall be payable under this Agreement if Employee is not employed by the Company on the Change in Control Date. Notwithstanding anything else contained herein to the contrary, if Employee’s employment is terminated (a) by the Company and such termination is not a Termination for Cause and (b) after the occurrence of a Potential Change in Control but prior to a Change in Control and a Change in Control occurs within 12 months after such termination, Employee shall be deemed,

1

solely for purposes of determining Employee’s rights under this Agreement, to have remained employed until the Change in Control Date and to have been terminated by the Company without cause immediately thereafter; provided, however, that, in such case, the Separation Payment payable hereunder shall be reduced by the amount of any other cash severance benefits theretofore paid to Employee in connection with such termination. If Employee is still an employee of the Company on the Change in Control Date, or Employee is deemed, for purposes of this Agreement, to continue to be in the employ of the Company until the Change in Control Date pursuant to the immediately preceding sentence, upon the occurrence of a Change in Control this Agreement shall supercede any other individual agreement between Parent and Employer and Employee the primary purpose of which is to provide Employee the right to receive severance benefits and certain other benefits ancillary to such severance benefits in connection with the termination of Employee’s employment (the “Severance Agreement”), subject, if applicable, to the offset set forth in the immediately preceding sentence.

3.     Certain Definitions. As used in this Agreement, the following terms shall have the meanings set forth below:

“Accrued Obligations” shall mean any vested amounts or benefits owing to Employee under any of the Company’s employee benefit plans and programs in which Employee has participated, including any compensation previously deferred by Employee (together with any accrued earnings thereon) and not yet paid.

“Base Salary” shall mean Employee’s annualized base salary at the rate in effect at the relevant date or event as reflected in Employer’s regular payroll records.

“Change in Control” shall mean an event that constitutes a “change in control” as defined in Parent’s LTIP, except that, solely for purposes of determining whether Employee is eligible for benefits under this Agreement due to a termination of employment occurring after a Potential Change in Control, but prior to the occurrence of a Change in Control, an event shall only constitute a Change in Control if it both qualifies as such under Parent’s LTIP and is a change in the ownership or effective control or in the ownership of a substantial portion of the assets of the Parent for purposes of Section 409A of the Code. Any modification to the definition of “change in control” in Parent’s LTIP (including by virtue of the adoption by the Parent of a successor plan thereto setting forth a modified definition of “change in control”) adopted after the Effective Date shall apply for purposes of this Agreement, except that any modification to such definition adopted on or after, or within 180 days prior to, a Change in Control or Potential Change in Control shall not apply in determining the definition of such term under this Agreement unless such amendment is favorable to Employee; and provided further that any change to the definition of a change in control in Parent’s LTIP adopted in 2008 to comply with the requirements of Section 409A of the Code shall be deemed to be favorable to Employee.

“Code” shall mean the Internal Revenue Code of 1986, as amended, or any successor provision thereto.

“Date of Termination” shall mean

2

(1)    In the case of a termination for which a Notice of Termination is required, the date of receipt of such Notice of Termination or, if later, the date specified therein; and

(2)     In all other cases, the actual date on which Employee’s employment terminates;

provided, however, that if Employee continues to provide or, in the 12 month period following such termination of employment, Employee is expected to provide, sufficient services that, under the Parent’s written and generally applicable policies regarding what constitutes a “separation from service” for purpose of Section 409A of the Code, Employee does not incur a separation of service for purposes of such Section 409A on the date of termination, Employee’s Date of Termination for purposes of this Agreement shall be the date on which such Employee incurs a separation from service under such policies.

“Disability” shall mean Employee’s physical or mental impairment or incapacity of sufficient severity such that

(1)    In the opinion of a qualified physician selected by Parent with the consent of Employee or Employee’s legal representative (which consent shall not be unreasonably withheld), after taking into account all reasonable accommodations that the Company has made or could make, Employee is unable to continue to perform Employee’s duties and responsibilities as an employee of the Company; and

(2)    Employee’s condition entitles Employee to long-term disability benefits under any employee benefit plan maintained by the Company or any of its affiliates that are at least comparable to those made available to Employee by the Company prior to the Change in Control.

For purposes of subparagraph (1) of this definition, Employee agrees to provide such access to Employee’s medical records and to submit to such physical examinations and medical tests as, in the opinion of the physician selected by Parent, is reasonably necessary to make the determination required as to Employee’s ability to perform Employee’s duties and responsibilities.

“Earned Salary” shall mean the Base Salary earned by Employee, but unpaid, through Employee’s Date of Termination.

“Normal Retirement Date” shall mean the date on which Employee attains age 60.

“Notice of Termination” shall mean a written notice given, in the case of a Termination for Cause, within 45 days of Parent’s or Employer’s having actual knowledge of the events giving rise to such termination, and in the case of a Termination for Good Reason, within 90 days of the later to occur of (x) the Change in Control Date or (y) Employee’s having actual knowledge of the events giving rise to such termination. Any such Notice of Termination shall

3

(1)    Indicate the specific termination provision in this Agreement relied upon;

(2)     Set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Employee’s employment under the provision so indicated; and

(3)     If the Date of Termination is other than the date of receipt of such notice, specify the Date of Termination (which date shall be not more than 30 days after the giving of such notice).

The failure by Employee to set forth in the Notice of Termination any fact or circumstance which contributes to a showing of Termination for Good Reason shall not waive any right of Employee hereunder or preclude Employee from asserting such fact or circumstance in enforcing Employee’s rights hereunder.

“Parent’s LTIP” shall mean the Parent’s 2006 Long-Term Incentive Plan, as the same may be amended from time to time, or any successor plan thereto.

“Potential Change in Control” shall mean the occurrence of any of the following events:

(1)     Any person or group shall have announced publicly an intention to effect a Change in Control, or commenced any action (such as the commencement of a tender offer for Parent’s common stock or the solicitation of proxies for the election of any of Parent’s directors) that, if successful, could reasonably be expected to result in the occurrence of a Change in Control;

(2)     Parent enters into an agreement the consummation of which would constitute a Change in Control; or

(3)     Any other event occurs which the Board declares to be a Potential Change in Control.

“Separation Payment” shall mean any lump sum cash payment in excess of Earned Salary and Accrued Obligations payable to Employee under this Agreement.

“Target Bonus” shall mean the greater of

(1)    the average of the target bonuses made available to Employee under any Company annual bonus program (which, if not stated as the target for a full year of service, shall be annualized) for the year in which the Change in Control Date occurs and for each of the last 2 years ended prior to the year in which the Change in Control Date occurs (or, if less, the number of years prior to the year in which the Change in Control Date occurs during which Employee was employed by the Company); and

(2)     Employee’s highest target bonus made available to Employee under the annual bonus program in which Employee participated for services rendered or

4

to be rendered by Employee in any calendar year after the calendar year in which the Change in Control Date occurs;

in either case as reflected in Employer’s records.

“Termination for Cause” shall mean a termination of Employee’s employment by Parent and Employer due to the occurrence of any of the following

(1)    Employee’s continued failure (i) to substantially perform Employee’s duties and responsibilities (other than any such failure resulting from Employee’s physical or mental impairment or incapacity) or (ii) to comply with any material written policy of the Company generally applicable to all officers of the Company and, if applicable, the successor in interest to Parent or, if such successor is a subsidiary of any other entity, the direct or indirect ultimate parent of such successor (such successor or such ultimate parent entity, the “Parent Successor”), which specifically provides that Employee may be dismissed (or Employee’s employment terminated) as a consequence of any such failure to comply, in either case more than 10 business days after written demand for substantial performance or compliance with the policy is delivered by Parent specifically identifying the manner in which Parent believes Employee has not substantially performed Employee’s duties and responsibilities or not complied with the written policy;

(2)     Employee’s engaging in an act or acts of gross misconduct which result in, or are intended to result in, material damage to the Company’s business or reputation;

(3)     Employee’s failure, following a written request from Parent, reasonably to cooperate (including, without limitation, the refusal by Employee to be interviewed or deposed, or to give testimony) in connection with any investigation or proceeding, whether internal or external (including, without limitation, by any governmental or quasi-governmental agency), into the business practices or operations of the Company; or

(4)     Employee’s conviction of (or plea of guilty or nolo contendere to a charge of) any felony or any crime or misdemeanor, in either case, involving moral turpitude or financial misconduct which results in significant monetary damage to the Company.

For purposes of subparagraph (2)of this definition, an act, or failure to act, on Employee’s part shall only be considered “misconduct” if done, or omitted, by Employee not in good faith and without reasonable belief that such act, or failure to act, was in the best interest of the Company.

“Termination for Good Reason” shall mean a termination of Employee’s employment by Employee due to the occurrence of any of the following, without the express written consent of Employee, after the occurrence of a Potential Change in Control or a Change in Control:

5

(1)    (i) The assignment to Employee of any duties inconsistent in any material adverse respect with Employee’s position, authority or responsibilities as in effect immediately prior to a Potential Change in Control or a Change in Control, or (ii) any other material adverse change in such position, including titles, authority or responsibilities, which, in the case of any officer of Parent, shall be deemed to have occurred unless, following the Change in Control Date, Employee holds such position or positions with the Parent Successor that are substantially comparable to the position or positions held by Employee with Parent immediately prior to the Change in Control Date (or, if higher, immediately prior to the occurrence of a Potential Change in Control);

(2)     Any failure by the Company or the Parent Successor, other than an insubstantial or inadvertent failure remedied promptly after receipt of notice thereof given by Employee, to provide Employee with an annual Base Salary which is at least equal to the Base Salary payable to Employee immediately prior to the Change in Control Date (or, if higher, immediately prior to the occurrence of a Potential Change in Control) or, if more favorable to Employee, at the rate made available to Employee at any time thereafter (the “Protected Base Salary”);

(3)    Any failure by the Company or the Parent Successor, other than an insubstantial or inadvertent failure remedied promptly after receipt of notice thereof given by Employee, to provide Employee with a reasonably achievable opportunity (determined in a manner consistent with the Company’s practices prior to the Change in Control) to receive an annual bonus ranging from 100%, at targeted levels of performance, to 200%, at superior levels of performance, of Employee’s Target Bonus;

(4)    Any failure by the Company or the Parent Successor, other than an insubstantial or inadvertent failure remedied promptly after receipt of notice thereof given by Employee, to provide Employee with annual awards of long-term incentive compensation that have a value (using the same valuation methodologies used for valuing long-term incentive compensation awards of a similar type made to senior officers of Parent and, if applicable, the Parent Successor) at least equal to the average dollar value assigned thereto by the Company at the date of grant of the last three annual long-term incentive compensation awards (including, without limitation, equity and equity-based awards) granted to Employee in respect of Employee’s employment with the Company (or if Employee has received less than three such annual grants, the average of the value of the number of grants received by Employee prior to the Change in Control Date);

(5)    Any failure by the Company or the Parent Successor, other than an insubstantial or inadvertent failure remedied promptly after receipt of notice thereof given by Employee, to permit Employee (and, to the extent applicable, Employee’s dependents) to participate in or be covered under all pension, retirement, deferred compensation, savings, medical, dental, health, disability, group life, accidental death and travel accident insurance plans and programs at a level that is materially less favorable in the aggregate than the benefits provided under the plans of the Company and its affiliated companies prior to the Change in Control Date (or, if

6

more favorable to Employee, at the level made available to Employee or other similarly situated officers at any time thereafter); or

(6)    If, not later than the Change in Control Date, any Parent Successor shall have failed to agree in writing to assume and perform this Agreement as required by paragraph 7(h) hereof.

4.     Termination of Employment.

(a)    Right to Terminate. Nothing in this Agreement shall be construed in any way to limit the right of the Company to terminate Employee’s employment, with or without cause, or for Employee to terminate Employee’s employment with the Company, with or without reason; provided, however, that the Company and Employee must nonetheless comply with any duty or obligation such party has at law or under any agreement (including paragraph 6 of this Agreement) between the parties.

(b)     Termination due to Death or Disability. Employee’s employment with the Company shall be terminated upon Employee’s death. By written notice to the other party, either the Company or Employee may terminate Employee’s employment due to Disability.

5.     Amounts Payable Upon Termination of Employment. The following provisions shall apply to any termination of Employee’s employment occurring (or which, pursuant to paragraph 2, is deemed to occur) at the time of, or at any time within 2 years following, a Change in Control:

(a)    Death or Disability. In the event that Employee’s employment terminates due to Employee’s death or Disability (regardless of whether such Disability termination is initiated by Employee or the Company) , Parent or Employer shall pay Employee (or, if applicable, Employee’s beneficiaries or legal representative(s)):

(1)    The Earned Salary, as soon as practicable (but not more than 10 days) following Employee’s Date of Termination;

(2)    The Accrued Obligations, in accordance with applicable law and the provisions of any applicable plan, program, policy or practice; and

(3)    A Separation Payment in an amount equal to Employee’s Base Salary, which shall be paid 10 days following Employee’s Date of Termination, provided that, if, at the Date of Termination, Employee is a “specified employee” within the meaning of Section 409A of the Code, as determined in accordance with the procedures specified or established by the Parent in accordance with such Section 409A and the regulations thereunder (a “Specified Employee”), and the Separation Payment is payable due to Disability, the Separation Payment shall be made six months and one day after Employee’s Date of Termination. In the event that the Separation Payment is made six months and one day after the Date of Termination, it shall be paid with interest from the Date of Termination at a rate equal to Employer’s cost of borrowing under its principal credit facility as in effect at the Date of Termination, as determined by the Parent’s Chief Financial Officer.

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(b)    Cause and Voluntary Termination. If Employee’s employment is terminated by the Company in a Termination for Cause or voluntarily by Employee, Parent or Employer shall pay Employee

(1)    The Earned Salary as soon as practicable (but in no event more than 10 days), following Employee’s Date of Termination; and

(2)     The Accrued Obligations in accordance with applicable law and the provisions of any applicable plan, program, policy or practice.

(c)    Termination After Normal Retirement. If the Employee’s employment terminates after Normal Retirement Date due to the Employee’s voluntary retirement, in addition to the payments under subparagraph 5(b), Parent or Employer shall pay Employee a Separation Payment in an amount equal to Employee’s Base Salary, which shall be paid 10 days following Employee’s Date of Termination, provided that, if, at the Date of Termination, Employee is a Specified Employee, the Separation Payment shall be made six months and one day after Employee’s Date of Termination. In the event that the Separation Payment is made six months and one day after the Date of Termination, an amount equal to such Separation Payment shall be contributed by the Company or Employer within five (5) business days following the Date of Termination to a grantor trust in the United States subject to the claims of the grantor’s creditors (a “Grantor Trust”), with such amount to be invested through the trust in U.S. Treasury securities or money market investments, with the principal investment purpose being to preserve principal (“Fixed Income Securities”). When payment of any such deferred portion of the Separation Payment is made in accordance with the second preceding sentence, it shall be increased by an amount equal to the earnings on the amounts contributed to such Grantor Trust in respect of such deferred Separation Payment.

(d)    Termination for Good Reason or Without Cause. If Employee terminates Employee’s employment in a Termination for Good Reason or the Company terminates Employee’s employment for any reason other than those described in paragraphs 5(a) and (b) above, Parent or Employer shall pay or shall provide to Employee the following benefits and compensation:

(1)    The Earned Salary, as soon as practicable (but not more than 10 days) following Employee’s Date of Termination;

(2)    The Accrued Obligations, in accordance with applicable law and the provisions of any applicable plan, program, policy or practice;

(3)    Continued coverage, at the same costs that apply to similarly situated active employees, for Employee and Employee’s eligible dependents under the Employer’s group medical plans or, to the extent such continued coverage cannot be provided under such plan without adverse consequences for the Company or Employee due to non-discrimination requirements, then under an individual or group insurance policy that is substantially similar in all material respects to the coverage made available under such group health plans, for each of the following two periods (i) from the Employee’s Date of Termination until and including the 18 month anniversary of such termination; and (ii) from the day after the 18 month anniversary

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of the Employee’s Date of Termination and continuing until the earlier of (x) the lifetime of Employee (and, if she shall survive him, Employee’s Spouse) or (y) until the date Employee (and, in respect of any coverage available to Employee’s spouse, until such spouse) is eligible for full medical benefits under the provisions of Medicare; it being understood that standard coordination of benefits provisions apply so that any coverage made available to Employee hereunder shall be secondary to any such coverage made available to Employee by a subsequent employer or other entity providing such coverage in respect of Employee’s services and that Employee must accept that available coverage; and

(4)    If Employee shall have relocated Employee’s principal residence to enter into the Company’s employ, or otherwise relocated such residence at the request of the Company, within 1 year of the Change in Control Date, and if Employee elects to relocate to Employee’s original location following Employee’s Date of Termination, relocation benefits under the same relocation policy as applied to Employee’s initial relocation; provided that the benefits provided hereunder shall (i) be paid to Employee not later than the end of the calendar year following the year in which such the corresponding reimbursable relocation expenses are incurred and (ii) not be duplicative of any relocation benefits to which Employee is entitled in connection with the plan, policy, program or practice of any subsequent employer;

(5)    To the extent that any award granted to Employee under Parent’s LTIP and outstanding on the Change in Control Date shall not have previously become fully vested and, as applicable, exercisable, payable, distributable and free of any transfer restrictions, such award shall be and become fully vested and, as applicable, exercisable, payable or distributable to, and transferable by, Employee on Employee’s Date of Termination, without any further action by the Company or any other person(s); provided, however, that (i) in the case of any award that vests upon the attainment of specified performance conditions, the extent to which such award becomes vested and payable will be contingent (to the extent specified in the applicable award agreement) upon the achievement of such criteria, as measured at the time of the Change in Control and (ii) if the award is deferred compensation subject to Section 409A that does not qualify for an otherwise available exemption from such Section 409A, payment thereof shall be made to the Employee at the same time as the Separation Payment referenced in subparagraph 5(d)(6) and, if such payment is delayed for six months and one day following the Date of Termination, the Employer shall be required to contribute the amount payable in respect of such award to the grantor trust referenced in the paragraph following such subparagraph 5(d)(6) at the same time, and subject to the same conditions, as apply with respect to such Separation Payment;

(6)    A Separation Payment in an amount equal to the sum of

(i)    the sum of 1.99 times Employee’s Protected Base Salary and 2.99 times the Employee’s Target Bonus;

(ii)    Employee shall also receive the Separation Payment payable under Section 5(c), on the same basis as though Employee had attained Normal Retirement Date immediately prior to the Date of

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Termination, regardless of whether Employee shall have attained Normal Retirement Date on or prior to the Date of Termination;

(iii)    the product of (A) the amount of the Target Bonus and (B) a fraction, the numerator of which is the number of days in the then current calendar year which have elapsed as of the Date of Termination, and the denominator of which is 365;

(iv)    if Employee’s employment was terminated prior to the Change in Control Date, but Employee is deemed to have continued in the Company’s employment for purposes of this Agreement until the Change in Control Date pursuant to paragraph 2 hereof, an amount equal to the value (as determined based on the fair market value of the Parent’s common stock on the Change in Control Date, but debiting therefrom any amount Employee would be required to pay to receive the benefit of such award) of any equity awards (including, without limitation, stock options, restricted stock units and restricted stock) granted to Employee under Parent’s LTIP that were outstanding but unvested (after taking into account any accelerated vesting thereof in connection with such termination of employment) on Employee’s Date of Termination; and

(v)    if the termination of employment is by the Company and if the Date of Termination is less than thirty (30) days after the date Notice of Termination is given, an amount equal to one-twelfth (1/12) of the Protected Base Salary.

Payment of the Separation Payment shall be made within 10 business days after the Employee’s Date of Termination, provided that, if, at the Date of Termination, Employee is a Specified Employee, the portion of the Separation Payment described in subclauses (i), (ii) (iv) and (v) above shall be made six months and one day after Employee’s Date of Termination. Any such deferred portion of the Separation Payment payable to Employee shall be contributed by the Company or Employer within five (5) business days following the Date of Termination to a Grantor Trust, with such amount to be invested through the trust in Fixed Income Securities. When payment of any such deferred portion of the Separation Payment is made in accordance with the second preceding sentence, it shall be increased by an amount equal to the earnings on the amounts contributed to such Grantor Trust in respect of such deferred Separation Payment.

(e)     Benefits Payable Due to Forced Relocation. If Employee is not otherwise entitled to terminate Employee’s employment in a Termination for Good Reason and terminates employment voluntarily because Parent or Parent Successor requires (or notifies Employee in writing that it will require) Employee to be based at any office or location more than 50 miles from that location at which Employee principally performed services for the Company immediately prior to the Change in Control Date, except for travel reasonably required in the performance of Employee’s responsibilities, Parent or Employer shall pay or shall provide to Employee the following benefits and compensation:

(1)    The Earned Salary, as soon as practicable (but not more than 10 days) following Employee’s Date of Termination;

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(2)    The Accrued Obligations, in accordance with applicable law and the provisions of any applicable plan, program, policy or practice;

(3)    Continued coverage, at the same costs that apply to similarly situated active employees, for Employee and Employee’s eligible dependents under Employer’s group health plan(s) (within the meaning of the Consolidated Omnibus Budget Reconciliation Act of 1985 (“COBRA”)) in which Employee was participating prior to the Date of Termination for a period of 12 months following Employee’s Date of Termination (or, if earlier, until Employee is eligible for comparable coverage under the group health plan(s) of a subsequent employer); and

(4)    A Separation Payment in an amount equal to Employee’s Protected Base Salary, which shall be payable within 10 business days after the Employee’s Date of Termination, provided that, if, at the Date of Termination, Employee is a Specified Employee, the portion of the Separation Payment due pursuant to this subparagraph 5(e)(4) shall be made six months and one day after Employee’s Date of Termination. Any such deferred portion of the Separation Payment payable to Employee shall be contributed by the Company or Employer within five (5) business days following the Date of Termination to a Grantor Trust, with such amount to be invested through the trust in Fixed Income Securities. When payment of any such deferred portion of the Separation Payment is made in accordance with the second preceding sentence, it shall be increased by an amount equal to the earnings on the amounts contributed to such Grantor Trust in respect of such deferred Separation Payment.

(f)    Limit on Payments by Parent and Employer.

(1)    Application of this Paragraph 5(f). In the event that

(i)     Any amount or benefit paid or distributed to Employee pursuant to this Agreement, taken together with any amounts or benefits otherwise paid or distributed to Employee by the Company or any affiliated company in connection with the Change in Control that are treated as parachute payments under Section 280G of the Code and such payments (collectively, the “Covered Payments”) would be or become subject to the tax (the “Excise Tax”) imposed under Section 4999 of the Code or any similar tax that may hereafter be imposed, and

(ii)    Employee would receive a greater net-after tax benefit by limiting the Covered Payments, so that the portion thereof that are parachute payments do not exceed the maximum amount of such parachute payments that could be paid to Employee without Employee’s being subject to any Excise Tax (the “Safe Harbor Amount”),

(iii)    then the amounts payable to Employee under this paragraph 5 shall be reduced (but not below zero) so that the aggregate amount of parachute payments that Employee receives does not exceed the Safe Harbor Amount. In the event that Employee receives reduced payments and benefits hereunder, such payments and benefits shall be reduced in connection with the application of the Safe Harbor Amount in the following

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manner: first, any portion of the Employee’s Separation Payment payable other than on account of Employee’s having attained Normal Retirement Date shall be reduced, followed by, to the extent necessary and in order, any relocation reimbursement payable, the continuation of welfare benefits, any awards under the LTIP in which Employee becomes vested under this Agreement and finally, the Accrued Obligations.

(2)    Assumptions for Calculation. For purposes of determining whether any of the Covered Payments will be subject to the Excise Tax,

(i)    such Covered Payments will be treated as “parachute payments” within the meaning of Section 280G of the Code, and all “parachute payments” in excess of the “base amount” (as defined under Section 280G(b)(3) of the Code) shall be treated as subject to the Excise Tax, unless, and except to the extent that, in the good faith judgment of a public accounting firm appointed by Parent prior to the Change in Control Date or tax counsel selected by such accounting firm (the “Accountants”), the Company has a reasonable basis to conclude that such Covered Payments (in whole or in part) either do not constitute “parachute payments” or represent reasonable compensation for personal services actually rendered (within the meaning of Section 280G(b)(4)(B) of the Code) in excess of the “base amount,” or such “parachute payments” are otherwise not subject to such Excise Tax, and

(ii)    the value of any non cash benefits or any deferred payment or benefit shall be determined by the Accountants in accordance with the principles of Section 280G of the Code.

(3)    Adjustments in Respect of the Safe Harbor Amount. If Employee receives reduced payments and benefits under this subparagraph 5(f) (or this subparagraph 5(f) is determined not to be applicable to Employee because the Accountants conclude that Employee is not subject to any Excise Tax) and it is established pursuant to a final determination of a court or an Internal Revenue Service proceeding (a “Final Determination”) that, notwithstanding the good faith of Employee and the Company in applying the terms of this Agreement, the aggregate “parachute payments” within the meaning of Section 280G of the Code paid to Employee or for Employee’s benefit exceed the Safe Harbor Amount and the provisions of this subparagraph 5(f) would otherwise have applied, then the amount of such parachute payment in excess of such Safe Harbor Amount shall be deemed for all purposes to be a loan to Employee made on the date of receipt of such excess payments, which Employee shall have an obligation to repay to the Company on demand, together with interest on such amount at the applicable Federal rate (as defined in Section 1274(d) of the Code) from the date of the payment hereunder to the date of repayment by Employee.

6.     Nonpublic Information.

(a)    Acknowledgement of Access. Employee hereby acknowledges that, in connection with Employee’s employment with the Company, Employee has received, and

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will continue to receive, various information regarding the Company and its business, operations and affairs. All such information, to the extent not publicly available other than as a result of a disclosure by Employee in violation of this Agreement, is referred to herein as the “Nonpublic Information.”

(b)    Agreement to Keep Confidential. Employee hereby agrees that, from and after the Effective Date and continuing until 3 years following Employee’s Date of Termination, Employee will keep all Nonpublic Information confidential and will not, without the prior written consent of the Board, Chief Executive Officer or the President of Parent, disclose any Nonpublic Information in any manner whatsoever or use any Nonpublic Information other than in connection with the performance of Employee’s services to the Company; provided, however, that the provisions of this subparagraph shall not prevent Employee from

(1)    Disclosing any Nonpublic Information to any other employee of the Company or to any representative or agent of the Company (such as an independent accountant, engineer, attorney or financial advisor) when such disclosure is reasonably necessary or appropriate (in Employee’s judgment) in connection with the performance by Employee of Employee’s duties and responsibilities;

(2)    Disclosing any Nonpublic Information as required by applicable law, rule, regulation or legal process (but only after compliance with the provisions of subparagraph (c) of this paragraph); and

(3)    Disclosing any information about this Agreement and Employee’s other compensation arrangement to Employee’s spouse, financial advisors or attorneys, or to enforce any of Employee’s rights under this Agreement.

(c)    Commitment to Seek Protective Order. If Employee is requested pursuant to, or required by, applicable law, rule, regulation or legal process to disclose any Nonpublic Information, Employee will notify Parent promptly so that the Company may seek a protective order or other appropriate remedy or, in Parent’s sole discretion, waive compliance with the terms of this subparagraph, and Employee will fully cooperate in any attempt by the Company to obtain any such protective order or other remedy. If no such protective order or other remedy is obtained, or Parent waives compliance with the terms of this paragraph, Employee will furnish or disclose only that portion of the Nonpublic Information as is legally required and will exercise all reasonable efforts to obtain reliable assurance that confidential treatment will be accorded the Nonpublic Information that is so disclosed.

7.    Miscellaneous Provisions.

(a)    No Mitigation, No Offset. Employee shall not be required to mitigate the amount of any payment provided for in this Agreement by seeking other employment or otherwise, and the amount of any payment provided for in this Agreement shall not be reduced by any compensation earned by Employee as the result of employment by another employer after the Date of Termination. Except as provided in subparagraph 5(d)(3), Parent’s or Employer’s obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any circumstances,

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including, without limitation, any set-off, counterclaim, recoupment, defense or other right which the Company may have against Employee or others whether by reason of the subsequent employment of Employee or otherwise.

(b)    Arbitration. Except to the extent provided in paragraph 7(d), any dispute or controversy arising under or in connection with this Agreement shall be resolved by binding arbitration. The arbitration shall be held in Dallas, Texas and except to the extent inconsistent with this Agreement, shall be conducted in accordance with the Expedited Employment Arbitration Rules of the American Arbitration Association then in effect at the time of the arbitration, and otherwise in accordance with principles which would be applied by a court of law or equity. The arbitrator shall be acceptable to both Parent and Employee. If the parties cannot agree on an acceptable arbitrator, the dispute shall be heard by a panel of three arbitrators, one appointed by each of the parties and the third appointed by the other two arbitrators.

(c)    Interest. Until paid, all past due amounts required to be paid by the Company to Employee under any provision of this Agreement shall bear interest at the per annum rate equal to the higher of (1) 12% or (2) the prime rate announced from time to time by the Company’s primary bank lender, plus 3%, in either case subject to the maximum rate allowed by law.

(d)    Equitable Relief Available. Employee acknowledges that remedies at law may be inadequate to protect the Company against any actual or threatened breach of the provisions of paragraph 6 by Employee. Accordingly, without prejudice to any other rights or remedies otherwise available to the Company, Employee agrees that the Company shall have the right to equitable and injunctive relief to prevent any breach of the provisions of paragraph 6 (without the requirement to post any bond), as well as to such damages or other relief as may be available to the Company by reason of any such breach as does occur.

(e)    Not A Contract of Employment. Employee acknowledges that this Agreement is not an “employment agreement” or “employment contract” (written or otherwise), as either term is used or defined in, or contemplated by or under

(1)    Parent's LTIP;

(2)    Any other plan or agreement to which the Company is a party; or

(3)    Applicable statutory, common or case law.

(f)    Breach Not a Defense. The representations and covenants on the part of Employee contained in paragraph 6 shall be construed as ancillary to and independent of any other provision of this Agreement, and the existence of any claim or cause of action of Employee against the Company or any officer, director, stockholder or representative of the Company, whether predicated on this Agreement or otherwise, shall not constitute a defense to the enforcement by the Company of the covenants on the part of Employee contained in paragraph 6.

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(g)    Notices. Any Notice of Termination or other communication called for by the terms of this Agreement shall be in writing and either delivered personally or by registered or certified mail (postage prepaid and return receipt requested) and shall be deemed given when received at the following addresses (or at such other address for a party as shall be specified by like notice):

(1)    If to Parent, Employer or the Company, 5205 North O’Connor Boulevard, Suite 200, Irving, Texas 75039, Attention: General Counsel.

(2)    If to Employee, the address of Employee set forth below Employee’s signature on the signature page of this Agreement.

(h)    Assumption by Parent Successor. Parent shall require any Parent Successor (regardless of whether the Parent Successor is the direct or indirect successor to all or substantially all of the business or assets of Parent and regardless of whether it became the Parent Successor by purchase of securities, merger, consolidation, sale of assets or otherwise), to expressly assume and agree to perform the obligations to be performed by the Company under this Agreement in the same manner and to the same extent that the Company would be required to perform if no such succession had taken place.

(i)    Assignment. Employer may assign its duties and obligations hereunder to any other direct or indirect majority-owned subsidiary of Parent, but shall remain secondarily liable for the performance of this Agreement by Parent and/or any such assignee. Except pursuant to either the immediately preceding sentence or an assumption by a Parent Successor, the rights and obligations of Parent and Employer pursuant to this Agreement may not be assigned, in whole or in part, by Parent or Employer to any other person or entity without the express written consent of Employee. The rights and obligations of Employee pursuant to this Agreement may not be assigned, in whole or in part, by Employee to any other person or entity without the express written consent of the Board.

(j)    Successors. This Agreement shall be binding on, and shall inure to the benefit of, Parent, Employer, the Company, Employee and their respective successors, permitted assigns, personal and legal representatives, executors, administrators, heirs, distributees, devisees and legatees, as applicable.

(k)    Amendments and Waivers. No provision of this Agreement may be amended or otherwise modified, and no right of any party to this Agreement may be waived, unless such amendment, modification or waiver is agreed to in a written instrument signed by Employee, Parent and Company. No waiver by either party hereto of, or compliance with, any condition or provision of this Agreement to be performed by the other party hereto shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.

(l)    Complete Agreement. This Agreement replaces and supersedes all prior agreements, if any, among the parties with respect to the payments to be made to Employee upon termination of employment following a Change in Control, including, but not limited to, the Change in Control Agreement between Parent, Employer and Employee, as in effect immediately prior to the date hereof, and the provisions of this Agreement constitute the

15

complete understanding and agreement among the parties with respect to the subject matter hereof. Nothing in this subparagraph (l) is intended to, or shall be construed to, (1) supercede the Severance Agreement at any time prior to the time expressly provided in paragraph 2 hereof or (2) limit Employee’s rights upon the occurrence of a Change in Control under Parent’s LTIP or any other Company plan, policy, program or practice (other than any plan, policy, program or practice primarily providing severance or other termination benefits) generally applicable to similarly situated employees.

(m)    Governing Law. THIS AGREEMENT IS BEING MADE AND EXECUTED IN, AND IS INTENDED TO BE PERFORMED IN, THE STATE OF TEXAS AND SHALL BE GOVERNED, CONSTRUED, INTERPRETED AND ENFORCED IN ACCORDANCE WITH THE SUBSTANTIVE LAWS OF THE STATE OF TEXAS.

(n)    Attorney Fees. All legal fees and other costs incurred by Employee in connection with the resolution of any dispute or controversy under or in connection with this Agreement shall be reimbursed by Parent and Employer to Employee, on a quarterly basis, upon presentation of proof of such expenses, but in no event later than the end of the calendar year following the calendar year in which such legal fees and expenses are incurred; provided, however, that if Employee asserts any claim in any contest and Employee shall not prevail, in whole or in part, as to at least one material issue as to the validity, enforceability or interpretation of any provision of this Agreement, Employee shall reimburse Parent and Employer for such amounts, plus simple interest thereon at the 90-day United States Treasury Bill rate as in effect from time to time, compounded annually. The Company shall be responsible for, and shall pay, all legal fees and other costs incurred by the Company in connection with the resolution of any dispute or controversy under or in connection with this Agreement, regardless of whether such dispute or controversy is resolved in favor of the Company or Employee.

(o)    Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same agreement.

(p)    Construction. The captions of the paragraphs, subparagraphs and sections of this Agreement have been inserted as a matter of convenience of reference only and shall not affect the meaning or construction of any of the terms or provisions of this Agreement. Unless otherwise specified, references in this Agreement to a “paragraph,” “subparagraph,” “section,” “subsection,” or “schedule” shall be considered to be references to the appropriate paragraph, subparagraph, section, subsection, or schedule, respectively, of this Agreement. As used in this Agreement, the term “including” shall mean “including, but not limited to.”

(q)    Validity and Severability. If any term or provision of this Agreement is held to be illegal, invalid or unenforceable under the present or future laws effective during the term of this Agreement, (1) such term or provision shall be fully severable, (2) this Agreement shall be construed and enforced as if such term or provision had never comprised a part of this Agreement and (3) the remaining terms and provisions of this Agreement shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable term or provision or by its severance from this Agreement. Furthermore, in lieu of such illegal, invalid or unenforceable term or provision, there shall be added

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automatically as a part of this Agreement, a term or provision as similar to such illegal, invalid or unenforceable term or provision as may be possible and be legal, valid and enforceable.

(r)    Survival. Notwithstanding anything else in this Agreement to the contrary (including, without limitation, the termination of this Agreement in accordance with paragraph 1), paragraphs 6 and 7, and, to the extent that any of Parent’s and Employer’s obligations thereunder have not theretofore been satisfied, paragraph 5 of this Agreement shall survive the termination hereof.

(s)    Joint and Several Liability. Parent and Employer (or any assignee of Employer pursuant to paragraph 7(i)) shall each be jointly and severally liable to Employee hereunder with regard to any obligation imposed by the terms hereof on Parent or Employer.

(SIGNATURE PAGE ATTACHED)

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In witness whereof, the parties have executed this Agreement effective as of the date first written above.

PIONEER NATURAL RESOURCES COMPANY
By:
Name:	Mark S. Berg
Title:	Executive Vice President and General Counsel
PIONEER NATURAL RESOURCES USA, INC.
By:
Name:	Mark S. Berg
Title:	Executive Vice President and General Counsel
EMPLOYEE:
/s/ Scott D. Sheffield

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Schedule I

1. The Company entered into a Change in Control Agreement with Timothy L. Dove which is otherwise identical to the one entered into with Scott D. Sheffield.

2. The Company entered into a Change in Control Agreement with each of Mark S. Berg, Chris J. Cheatwood, Richard P. Dealy, Frank W. Hall, William F. Hannes, Danny L. Kellum and Jay P. Still, which varied from Mr. Sheffield’s agreement by modifying Section 5(d)(3) to provide, in its entirety, the following:

(3)    Continued coverage following Employee’s Date of Termination, at the same costs that apply to similarly situated active employees, for Employee and Employee’s eligible dependents under whichever of the Company’s group medical plans in which Employee was participating prior to the Date of Termination or, to the extent such continued coverage cannot be provided under such plan without adverse consequences for the Company or Employee due to non-discrimination requirements, then under an individual or group insurance policy that is substantially similar in all material respects to the coverage made available under such group health plan(s), for each of the following two periods (i) from the Employee’s Date of Termination until and including the 18 month anniversary of such termination; and (ii) from the day after the 18 month anniversary of the Employee’s Date of Termination and continuing until the day before the third anniversary of the Employee’s Date of Termination; provided, however, that such continued coverage shall cease if and when Employee becomes eligible for comparable coverage under the group health plan(s) of a subsequent employer; and

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EX-12.1

EXHIBIT 12.1

RATIOS OF EARNINGS TO FIXED CHARGES AND EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

The following table sets forth the Company's ratios of consolidated earnings to fixed charges and earnings to fixed charges and preferred stock dividends for the periods presented:

	Three Months Ended	Year ended December 31,
	March 31, 2013	2012	2011	2010	2009	2008
Ratio of earnings to fixed charges (a)	3.92	1.99	4.01	4.63	(b)	2.08
Ratio of earnings to fixed charges and preferred stock (c)	3.92	1.99	4.01	4.63	(b)	2.08

____________________

(a)	The ratio has been computed by dividing earnings by fixed charges. For purposes of computing the ratio:
	- earnings consist of income from continuing operations before income taxes, cumulative effect of change in accounting principle, adjustments for net income or loss attributable to the noncontrolling interest and the Company's share of investee's income or loss accounted for under the equity method, and adjustment for capitalized interest, plus fixed charges and the Company's share of distributed income from investees accounted for under the equity method; and
	- fixed charges consist of interest expense, capitalized interest and the portion of rental expense deemed to be representative of the interest component of rental expense.
(b)	The ratio indicates a less than one-to-one coverage because the earnings are inadequate to cover the fixed charges during the year ended December 31, 2009 by $244.7 million.
(c)	The ratio has been computed by dividing earnings by fixed charges and preferred stock dividends. For purposes of computing the ratio:
	- earnings consist of income from continuing operations before income taxes, cumulative effect of change in accounting principle, adjustments for net income or loss attributable to the noncontrolling interest and the Company's share of investee's income or loss accounted for under the equity method, and adjustment for capitalized interest, plus fixed charges, the Company's share of distributed income from investees accounted for under the equity method and preferred stock dividends, net of preferred stock dividends of a consolidated subsidiary; and
	- fixed charges and preferred stock dividends consist of interest expense, capitalized interest and the portion of rental expense deemed to be representative of the interest component of rental expense, preferred stock dividends of a consolidated subsidiary and preferred stock dividends.

EX-31.1

EXHIBIT 31.1

CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Scott D. Sheffield, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pioneer Natural Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 8, 2013

/s/ Scott D. Sheffield

Scott D. Sheffield, Chairman and

Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CHIEF FINANCIAL OFFICER CERTIFICATION

I, Richard P. Dealy, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pioneer Natural Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 8, 2013

/s/ Richard P. Dealy

Richard P. Dealy, Executive Vice President

and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF PIONEER NATURAL RESOURCES COMPANY

PURSUANT TO 18 U.S.C. § 1350

I, Scott D. Sheffield, Chairman and Chief Executive Officer of Pioneer Natural Resources Company (the “Company”), hereby certify that the accompanying Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013 and filed with the Securities and Exchange Commission pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

I further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Scott D. Sheffield
Name:	Scott D. Sheffield, Chairman and
	Chief Executive Officer
Date:	May 8, 2013

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF PIONEER NATURAL RESOURCES COMPANY

PURSUANT TO 18 U.S.C. § 1350

I, Richard P. Dealy, Executive Vice President and Chief Financial Officer of Pioneer Natural Resources Company (the “Company”), hereby certify that the accompanying Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013 and filed with the Securities and Exchange Commission pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

I further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Richard P. Dealy
Name:	Richard P. Dealy, Executive Vice
	President and Chief Financial Officer
Date:	May 8, 2013

EX-95.1

EXHIBIT 95.1

Mine Safety Disclosure

The following disclosures are provided pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act") and Item 104 of Regulation S-K, which requires certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate mines regulated under the Federal Mine Safety and Health Act of 1977 (the "Mine Act").

Whenever the Federal Mine Safety and Health Administration ("MSHA") believes a violation of the Mine Act, any health or safety standard or any regulation has occurred, it may issue a citation which describes the alleged violation and fixes a time within which the U.S. mining operator must abate the alleged violation. In some situations, such as when MSHA believes that conditions pose a hazard to miners, MSHA may issue an order removing miners from the area of the mine affected by the condition until the alleged hazards are corrected. When MSHA issues a citation or order, it generally proposes a civil penalty, or fine, as a result of the alleged violation, that the operator is ordered to pay. Citations and orders can be contested and appealed, and as part of that process, are often reduced in severity and amount, and are sometimes dismissed. The number of citations, orders and proposed assessments vary depending on the size and type (underground or surface) of the mine as well as by the MSHA inspector(s) assigned.

The table below sets forth for the three months ended March 31, 2013 for each sand mine of Pioneer Natural Resources Company or its subsidiaries (the "Company"), (i) the total number of citations for violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of mine safety or health hazard under section 104 of the Mine Act for which the operator received a citation from MSHA; (ii) the total number of orders issued under section 104(b) of the Mine Act; (iii) the total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under section 104(d) of the Mine Act; (iv) the total number of flagrant violations under section 110(b)(2) of the Mine Act; (v) the total number of imminent danger orders issued under section 107(a) of the Mine Act; (vi) the total dollar value of proposed assessments from MSHA; (vii) the total number of mining-related fatalities; (viii) whether or not the mine has received any notices from MSHA of a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under section 104(e) of the Mine Act; (ix) whether or not the mine has received any notices from MSHA regarding the potential to have a pattern of violations as referenced in (viii) above; and (x) the total number of pending legal actions before the Federal Mine Safety and Health Review Commission (the "Commission") (as of March 31, 2013) involving such mine, as well as the aggregate number of legal actions instituted and the aggregate number of legal actions resolved during the reporting period. The MSHA citations, orders and assessments are those initially issued or proposed by MSHA. They do not reflect any subsequent changes in the level of severity of a citation or order or the value of an assessment that may occur as a result of proceedings conducted in accordance with MSHA rules.

Mine/MSHA Identification Number(1)	Section  104 S&S Citations	Section 104(b) Orders	Section 104(d) Citations and  Orders	Section 110(b)(2) Violations	Section 107(a) Orders	Total Dollar Value of Proposed Assessments		Mining Related Fatalities	Received Notice of Pattern of Violations under Section 104(e) (yes/no)	Received Notice of Potential to have Pattern under Section 104(e) (yes/no)	Legal Actions Pending as of Last Day of Period	Legal Actions Initiated During Period	Legal Actions Resolved During Period
Orange County Operation / 0402801	—	—	—	—	—	$	—	—	No	No	—	—	—
Riverside Operation / 0404263	1	—	—	—	—	$	112	—	No	No	—	—	—
Colorado Springs Operation / 0503295	—	—	—	—	—	$	—	—	No	No	—	—	—
Glass Rock Operation / 3301354	5	—	—	—	—	$	—	—	No	No	—	—	—
Millwood Operation / 3301355	—	—	—	—	—	$	3,249	—	No	No	—	—	—
Voca Pit and Plant / 4101003	3	—	—	—	—	$	1,263	—	No	No	—	—	—
Brady Plant / 4101371	3	—	—	—	—	$	762	—	No	No	—	—	—
Voca West / 4103618	1	—	—	—	—	$	112	—	No	No	—	—	—

_______________

(1 ) The definition of mine under section three of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting minerals, such as land, structures, facilities, equipment, machines, tools and minerals preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. MSHA assigns an identification number to each mine and may or may not assign separate identification numbers to related facilities such as preparation facilities.

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Derivative Financial Instruments (Schedule Of Oil Derivative Contracts Volume And Weighted Average Prices) (Details)	3 Months Ended
	Mar. 31, 2013
Rollfactor Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX swap multiple, second nearby month	0.6667
NYMEX swap multiple, third nearby month	0.3333
Oil contracts [Member] | Two Thousand Thirteen Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	72,430
Oil contracts [Member] | Two Thousand Fourteen Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	69,000
Oil contracts [Member] | Two Thousand Fifteen Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	26,000
Oil contracts [Member] | Two Thousand Thirteen Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	3,000
Oil contracts [Member] | Two Thousand Fourteen Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	0
Oil contracts [Member] | 2015 Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	0
Oil contracts [Member] | 2013 Rollfactor Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	6,000
Oil contracts [Member] | Two Thousand Fourteen Rollfactor Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	15,000
Oil contracts [Member] | Two Thousand Fifteen Rollfactor Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	0
Oil contracts [Member] | 2013 Mid Cush Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	1,655
Oil contracts [Member] | 2014 Mid Cush Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	0
Oil contracts [Member] | 2015 Mid Cush Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	0
Oil contracts [Member] | 2013 Cushing LLS Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	669
Oil contracts [Member] | 2014 Cushing LLS Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	0
Oil contracts [Member] | 2015 Cushing LLS Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day	0
Oil contracts, price per bbl [Member] | Two Thousand Thirteen Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price	119.89
Derivative, Average Floor Price	92.26
Oil contracts, price per bbl [Member] | Two Thousand Thirteen Collar Contracts With Short Puts [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	74.36
Oil contracts, price per bbl [Member] | Two Thousand Fourteen Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price	114.05
Derivative, Average Floor Price	93.70
Oil contracts, price per bbl [Member] | Two Thousand Fourteen Collar Contracts With Short Puts [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	77.61
Oil contracts, price per bbl [Member] | Two Thousand Fifteen Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Average Cap Price	104.45
Derivative, Average Floor Price	95.00
Oil contracts, price per bbl [Member] | Two Thousand Fifteen Collar Contracts With Short Puts [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	80.00
Oil contracts, price per bbl [Member] | Two Thousand Thirteen Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price	81.02
Oil contracts, price per bbl [Member] | Two Thousand Fourteen Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price	0.00
Oil contracts, price per bbl [Member] | 2015 Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Swap Type, Average Fixed Price	0.00
Oil contracts, price per bbl [Member] | 2013 Rollfactor Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	0.43	[1]
Oil contracts, price per bbl [Member] | Two Thousand Fourteen Rollfactor Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	0.38	[1]
Oil contracts, price per bbl [Member] | Two Thousand Fifteen Rollfactor Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	0.00	[1]
Oil contracts, price per bbl [Member] | 2013 Mid Cush Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	(5.75)	[2]
Oil contracts, price per bbl [Member] | 2014 Mid Cush Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	0.00	[2]
Oil contracts, price per bbl [Member] | 2015 Mid Cush Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	0.00	[2]
Oil contracts, price per bbl [Member] | 2013 Cushing LLS Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	(9.30)	[3]
Oil contracts, price per bbl [Member] | 2014 Cushing LLS Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	0.00	[3]
Oil contracts, price per bbl [Member] | 2015 Cushing LLS Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	0.00	[3]

[1] 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.

[2] Basis differential price between Midland WTI and Cushing WTI.

[3] Basis differential price between Cushing WTI and Louisiana Light Sweet crude "LLS".

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Net Income (Loss) Per Share (Reconciliation Of Basic To Diluted Weighted Average Common Shares Outstanding) (Details)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Weighted Average Number of Shares Outstanding Reconciliation [Line Items]
Basic	128,940,000	122,480,000
Dilutive common stock options	157,000	150,000	[1]
Convertible senior notes dilution	3,534,000	3,460,000
Contingently issuable performance unit shares	120,000	157,000
Diluted	132,751,000	126,247,000
Stock Options [Member]
Weighted Average Number of Shares Outstanding Reconciliation [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	98,819

[1] Options to purchase 98,819 shares of the Company's common stock were excluded from the diluted income per share calculations for the three months ended March 31, 2013 because they would have been anti-dilutive to the calculation.

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Incentive Plans Incentive Plans (Stock-based compensation) (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 27.6	$ 21.3
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	198.5
Share Based Compensation Arrangement By Share Based Payment Award Liability	47.5
Postretirement benefit obligation revaluation	9.1		9.7
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Amount Of Liabilities Attributable To Liability Awards Included In Accounts Payable	$ 5.8		$ 18.8
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	1,429,650		1,512,762
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period	397,439
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(476,717)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	(3,834)
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	461,027		405,916
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period	238,269
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(178,143)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	(5,015)
Pioneer Southwest Ltip Restricted Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	7,496		7,496
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	454,668		467,486
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	(12,818)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	186,287		91,370
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period	94,917
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0
Pioneer Southwest Ltip Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	99,768		102,644
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period	32,242
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(35,118)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0

XML

Subsequent Events (Details) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended
	Jul. 31, 2013	May 08, 2013
Subsequent Events [Abstract]
Distribution Made to Member or Limited Partner, Cash Distributions Declared		$ 18.6
Share Per Unit Exchange Ratio		0.2234
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit	$ 0.52	$ 0.52

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Exploratory Costs Exploratory Costs (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	$ 118,916	$ 21,992
Oooguruk [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	21,992	21,992
Nuna [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	$ 96,900

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Net Income (Loss) Per Share (Tables)

3 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Reconciliation of earnings attributable to common stockholders, basic and diluted

The following tables reconcile the Company's net income (loss) attributable to common stockholders to basic net income attributable to common stockholders and diluted net income (loss) attributable to common stockholders for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31, 2013
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	101,128		$	(465	)	$	100,663
Participating basic earnings	(1,270		)	—			(1,270		)
Basic net income (loss) attributable to common stockholders	99,858			(465		)	99,393
Reallocation of participating earnings	35			—			35
Diluted income (loss) attributable to common stockholders	$	99,893		$	(465	)	$	99,428

	Three Months Ended March 31, 2012
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	203,924		$	10,695		$	214,619
Participating basic earnings	(2,326		)	(122		)	(2,448		)
Basic income attributable to common stockholders	201,598			10,573			212,171
Reallocation of participating earnings	68			3			71
Diluted income attributable to common stockholders	$	201,666		$	10,576		$	212,242

Reconciliation Of Basic To Diluted Weighted Average Common Shares Outstanding

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013	2012
	(in thousands)
Weighted average common shares outstanding:
Basic	128,940	122,480
Dilutive common stock options (a)	157	150
Convertible Senior Notes dilution	3,534	3,460
Contingently issuable performance unit shares	120	157
Diluted	132,751	126,247

 ____________________

(a) Options to purchase 98,819 shares of the Company's common stock were excluded from the diluted income per share calculations for the three months ended March 31, 2013 because they would have been anti-dilutive to the calculation.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

Schedule of assets and liabilities measured at fair value on a recurring basis

The following table presents the Company's assets and liabilities that are measured at fair value as of March 31, 2013:

	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 March 31, 2013
	(in thousands)
Recurring fair value measurements
Assets:
Trading securities	$	158	$	142	$	—	$	300
Commodity derivatives	—		246,552		—		246,552
Deferred compensation plan assets	53,768		—		—		53,768
Total assets	53,926		246,694		—		300,620
Liabilities:
Commodity derivatives	—		28,001		—		28,001
Interest rate derivatives	—		5,784		—		5,784
Total liabilities	—		33,785		—		33,785
Total recurring fair value measurements	$	53,926	$	212,909	$	—	$	266,835

Schedule of carrying values and 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 sheet as of March 31, 2013 and December 31, 2012 are as follows:

	March 31, 2013				December 31, 2012
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	3,017,280	$	3,768,884	$	3,721,193	$	4,555,770

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Interest And Other Income (Components Of Interest And Other Income) (Details) (USD $)	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Interest and Other Income [Abstract]
Alaskan Petroleum Production Tax credits and refunds	$ 19,408,000	[1]	$ 11,846,000	[1]
Equity interest in income of unconsolidated affiliate	3,536,000		441,000
Other income	1,876,000		1,641,000
Deferred compensation plan income	1,627,000		1,374,000
Interest income	93,000		57,000
Third-party income from vertical integration services	(7,225,000)	[2]	6,549,000	[2]
Total interest and other income	19,315,000		21,908,000
GrossRevenuesIncludedInThirdPartyIncomeFromVerticalIntegrationServices	56,100,000		75,400,000
GrossExpensesIncludedInThirdPartyIncomeFromVerticalIntegrationServices	$ 63,300,000		$ 68,900,000

[1] The Company earns Alaskan Petroleum Production Tax ("PPT") credits on qualifying capital expenditures. The Company recognizes income from PPT credits when they are realized through cash refunds or as reductions in production and ad valorem taxes if realizable as offsets to PPT expense.

[2] Income (loss) from vertical integration services represent net margins that result from Company-provided fracture stimulation, drilling 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 months ended March 31, 2013 and 2012, these net margins include $56.1 million and $75.4 million of gross vertical integration revenues, respectively, and $63.3 million and $68.9 million of total vertical integration costs and expenses, respectively.

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Derivative Financial Instruments (Schedule Of Marketing And Basis Transfer Derivative Contracts) (Details) (Two Thousand And Thirteen Index Basis Swap Contracts [Member], Basic Index Swaps [Member])	Mar. 31, 2013 MMBTU
Two Thousand And Thirteen Index Basis Swap Contracts [Member] | Basic Index Swaps [Member]
Derivative [Line Items]
Average Daily Index Swaps Volume	4,364
Price Differential	0.34

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Fair Value Measurements (Schedule Of Carrying Values And Financial Instruments Not Carried At Fair Value) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt Element	$ 3,017,280	$ 3,721,193
Carrying Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt Element	3,017,280	3,721,193
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt Element	$ 3,768,884	$ 4,555,770

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Income Taxes (Schedule Of Income Tax (Provisions) Benefits Attributable To Income From Continuing Operations) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Income Tax Disclosure [Abstract]
Current Income Tax (Expense) Benefit	$ (7,435)	$ (11,832)
Deferred income tax (provision) benefit	(51,894)	(105,871)
Income tax (provision) benefit	$ (59,329)	$ (117,703)
Effective Tax Rate	37.00%	37.00%

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Long-Term Debt (Details) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	1 Months Ended	3 Months Ended
	May 08, 2013	Mar. 31, 2013 Rate	Jan. 15, 2013	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Convertible Debt					479.9
PXD Credit Facility [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capacity		1,500
Pioneer Southwest Credit Facility [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capacity		300
Outstanding borrowing		154.0
Unused borrowing capacity		146.0
2.875% Convertible Senior Notes Due 2038 [Member]
Debt Instrument [Line Items]
Convertible Debt		218.6		479.9
Senior notes, interest rate, percentage		2.875%	2.375%		2.875%
Principal amount of notes tendered for conversion		274.1
Shares issued for conversion of debt	115	2,400
Cash Paid To Conversion Of Convertible Senior Notes	12.8	261.3
Stock price in excess of principal amount of note interest rate trigger		120.00%
If Converted [Member] | 2.875% Convertible Senior Notes Due 2038 [Member]
Debt Instrument [Line Items]
Shares issued for conversion of debt		2,100
Cash Paid To Conversion Of Convertible Senior Notes		218.6
Non-Cash [Member] | If Converted [Member] | 2.875% Convertible Senior Notes Due 2038 [Member]
Debt Instrument [Line Items]
Value of shares received for conversion of debt		$ 259.7

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Organization And Nature Of Operations

3 Months Ended

Mar. 31, 2013

Organization And Nature Of Operations [Abstract]

Organization And Nature Of Operations

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 field operations in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Barnett Shale Combo play in North Texas, the Raton field in southeastern Colorado, the Hugoton field in southwest Kansas, the West Panhandle field in the Texas Panhandle and Alaska.

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Derivative Financial Instruments (Schedule Of Derivative Instruments) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Derivative Assets, Current	$ 151,431	$ 279,119
Derivative Assets, Noncurrent	95,121	55,257
Derivative Asset, Fair Value, Net	246,552
Derivative Liabilities, Current	20,413	13,416
Derivative Liabilities, Noncurrent	13,372	12,307
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Net	246,552	334,376
Derivative Liability, Fair Value, Net	33,785	25,723
Not Designated as Hedging Instrument [Member] | Commodity Price Derivatives [Member] | Derivatives - Current [Member]
Derivative [Line Items]
Total derivatives, Asset, Gross	160,149	286,805
Total derivatives, Liability. Gross	29,131	21,102
Derivative Assets and Liabilities Offset In Balance Sheet	(8,718)	(7,686)
Derivative Assets, Current	151,431	279,119
Derivative Liabilities, Current	20,413	13,416
Not Designated as Hedging Instrument [Member] | Commodity Price Derivatives [Member] | Derivatives - Noncurrent [Member]
Derivative [Line Items]
Total derivatives, Asset, Gross	100,090	61,618
Total derivatives, Liability. Gross	12,557	8,944
Derivative Assets and Liabilities Offset In Balance Sheet	(4,969)	(6,361)
Derivative Assets, Noncurrent	95,121	55,257
Derivative Liabilities, Noncurrent	7,588	2,583
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member] | Derivatives - Noncurrent [Member]
Derivative [Line Items]
Total derivatives, Liability. Gross	5,784	9,724
Derivative Assets and Liabilities Offset In Balance Sheet	0	0
Derivative Liabilities, Noncurrent	$ 5,784	$ 9,724

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2013

Asset Retirement Obligation [Abstract]

Schedule of asset retirement obligations

The following table summarizes the Company's asset retirement obligation activity during the three months ended March 31, 2013 and 2012:

		Three Months Ended March 31,
		2013			2012
	(in thousands)
Beginning asset retirement obligations		$	197,754		$	136,742
New wells placed on production		2,468			830
Changes in estimates (a)		(5,597		)	—
Dispositions		(4,079		)	—
Liabilities settled		(2,849		)	(5,688		)
Accretion of discount		3,153			2,430
Accretion of discount from integrated services (b)		11			—
Ending asset retirement obligations		$	190,861		$	134,314

_____________________

(a) The change in estimate during the three months ended March 31, 2013 is attributable to lengthening the economic life of certain wells, which reduced the present value of the associated asset retirement obligation.

(b) Accretion of discount from integrated services includes Premier Silica accretion expense, which is recorded as a reduction in third-party income from vertical integration services in interest and other income in the Company's accompanying consolidated statements of operations. See Note K for more information about interest and other income.

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Incentive Plans (Tables)

3 Months Ended

Mar. 31, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Share Based Incentive Award Activity

The following table summarizes the activity that occurred during the three months ended March 31, 2013, for each type of share-based incentive award issued by Pioneer:

	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units	Stock Options		Pioneer Southwest LTIP Restricted Units	Pioneer Southwest LTIP Phantom Units
Outstanding at December 31, 2012	1,512,762		405,916		91,370	467,486		7,496	102,644
Awards granted	397,439		238,269		94,917	—		—	32,242
Awards vested	(476,717	)	(178,143	)	—	—		—	(35,118	)
Options exercised	—		—		—	(12,818	)	—	—
Awards forfeited	(3,834	)	(5,015	)	—	—		—	—
Outstanding as of March 31, 2013	1,429,650		461,027		186,287	454,668		7,496	99,768

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Derivative Financial Instruments (Schedule Of Derivative Obligations Under Terminated Hedge Arrangements) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	$ 0	$ 2,508
Derivative (gains) losses, net	42,243	(91,750)
Commodity Price Derivatives [Member] | Oil And Gas revenue [Member]
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	0	809
Commodity Price Derivatives [Member] | Derivative Gains, Net [Member]
Derivative [Line Items]
Derivative (gains) losses, net	46,183	(88,130)
Interest Rate Derivatives [Member] | Interest Expense [Member]
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	0	1,699
Interest Rate Derivatives [Member] | Derivative Gains, Net [Member]
Derivative [Line Items]
Derivative (gains) losses, net	$ (3,940)	$ (3,620)

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Interest And Other Income (Tables)

3 Months Ended

Mar. 31, 2013

Interest and Other Income [Abstract]

Components of interest and other income

The following table provides the components of the Company's interest and other income for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013			2012
	(in thousands)
Alaskan Petroleum Production Tax credits and refunds (a)	$	19,408		$	11,846
Equity interest in income of unconsolidated affiliate	3,536			441
Other income	1,876			1,641
Deferred compensation plan income	1,627			1,374
Interest income	93			57
Income (loss) from vertical integration services (b)	(7,225		)	6,549
Total interest and other income	$	19,315		$	21,908

 ____________________

(a) The Company earns Alaskan Petroleum Production Tax ("PPT") credits on qualifying capital expenditures. The Company recognizes income from PPT credits when they are realized through cash refunds or as reductions in production and ad valorem taxes if realizable as offsets to PPT expense.

(b) Income (loss) from vertical integration services represent net margins that result from Company-provided fracture stimulation, drilling 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 months ended March 31, 2013 and 2012, these net margins include $56.1 million and $75.4 million of gross vertical integration revenues, respectively, and $63.3 million and $68.9 million of total vertical integration costs and expenses, respectively.

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Other Expense (Tables)

3 Months Ended

Mar. 31, 2013

Other Expense [Abstract]

Schedule of components of other expense

The following table provides the components of the Company's other expense for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013		2012
	(in thousands)
Transportation commitment charge (a)	$	9,377	$	8,453
Other	4,565		2,911
Above market and idle drilling and well services equipment rates (b)	3,507		4,986
Inventory impairment (c)	1,587		6,041
Contingency and environmental accrual adjustments	1,294		1,216
Terminated drilling rig contract charges (d)	1,019		—
Total other expense	$	21,349	$	23,607

 ____________________

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

(b) Primarily represents expenses attributable to the portion of Pioneer's contracted drilling rig rates that are above current market rates and idle drilling rig fees, neither of which are charged to joint operations.

(c) Represents valuation charges on excess materials and supplies inventories.

(d) Primarily represents charges to terminate a drilling rig contract that is not required to meet planned activities.

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Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Cash flows from operating activities:
Net income	$ 108,735	$ 220,958
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	230,763	181,418
Exploration expenses, including dry holes	7,954	27,163
Deferred income taxes	51,894	105,871
Gains (Losses) on Sales of Assets	(24,417)	(43,596)
Accretion of discount on asset retirement obligations	3,153	2,430
Discontinued operations	(158)	1,577
Amortization of Financing Costs and Discounts	4,844	9,870
Derivative related activity	95,884	(27,243)
Amortization of stock-based compensation	17,395	15,086
Amortization of deferred revenue	0	(10,459)
Other noncash items	(2,922)	(9,516)
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	(41,803)	(20,663)
Income taxes receivable	6,053	1,407
Inventories	825	(31,027)
Prepaid expenses	101	1,413
Other current assets	(636)	2,488
Accounts payable	(57,572)	19,326
Interest payable	(30,589)	(21,917)
Income taxes payable	84	16,941
Other current liabilities	(9,514)	(15,441)
Net cash provided by operating activities	360,074	426,086
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	46,184	58,514
Additions to oil and gas properties	(697,191)	(678,339)
Additions to other assets and other property and equipment, net	(56,169)	(59,841)
Net cash used in investing activities	(707,176)	(679,666)
Cash flows from financing activities:
Borrowings under long-term debt	304,922	134,000
Principal payments on long-term debt	(1,012,253)	(49,000)
Proceeds from Issuance of Common Stock	1,280,916	0
Distributions to noncontrolling interests	(8,885)	(8,957)
Payments of other liabilities	(210)	458
Exercise of long-term incentive plan stock options	1,047	1,008
Purchases of treasury stock	(19,202)	(56,129)
Excess tax benefits from share-based payment arrangements	1,688	12,938
Payment of financing fees	(2)	(1,261)
Dividends paid	(17)	(43)
Net cash provided by (used in) financing activities	548,004	33,014
Net increase (decrease) in cash and cash equivalents	200,902	(220,566)
Cash and cash equivalents, beginning of period	229,396	537,484
Cash and cash equivalents, end of period	$ 430,298	$ 316,918

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2013

Income Tax Disclosure [Abstract]

Income tax (provisions) benefits attributable to income from continuing operations

The Company's income tax provisions attributable to income from continuing operations consisted of the following for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013			2012
	(in thousands)
Current	$	(7,435	)	$	(11,832	)
Deferred	(51,894		)	(105,871		)
Income tax provision	$	(59,329	)	$	(117,703	)

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Derivative Financial Instruments Derivative Financial Instruments (Schedule of NGL Derivative Contracts Volume and Weighted Average Prices) (Details)	Mar. 31, 2013
NGL contracts, price per BBL [Member] | Two Thousand Fourteen Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Derivative, Average Cap Price	109.50
Derivative, Average Floor Price	95.00
NGL contracts, price per BBL [Member] | Two Thousand Fourteen Collar Contracts With Short Puts [Member] | Short Put [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	80.00
NGL contracts, price per BBL [Member] | Two Thousand Thirteen Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Derivative, Average Cap Price	105.28
Derivative, Average Floor Price	89.30
NGL contracts, price per BBL [Member] | Two Thousand Thirteen Collar Contracts With Short Puts [Member] | Short Put [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	75.20
NGL contract, in BBLS [Member] | Two Thousand Fourteen Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Average Daily NGL Production Derivative Barrels Per Day	1,000
NGL contract, in BBLS [Member] | Two Thousand Thirteen Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Average Daily NGL Production Derivative Barrels Per Day	1,064

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Net Income (Loss) Per Share (Reconciliation Of Earnings Attributable To Common Stockholders, Basic And Diluted) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Statement Operating Activities Segment [Line Items]
Income (loss) from continuing operations attributable to parent	$ 101,128	$ 203,924
Income (loss) from discontinued operations, net of tax, attributable to parent	(465)	10,695
Income (loss) as reported	100,663	214,619
Participating basic earnings	(1,270)	(2,448)
Basic income attributable to common stockholders	99,393	212,171
Reallocation of participating earnings	35	71
Diluted income attributable to common stockholders	99,428	212,242
Continuing Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) from continuing operations attributable to parent	101,128	203,924
Participating basic earnings	(1,270)	(2,326)
Basic income attributable to common stockholders	99,858	201,598
Reallocation of participating earnings	35	68
Diluted income attributable to common stockholders	99,893	201,666
Discontinued Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) from discontinued operations, net of tax, attributable to parent	(465)	10,695
Participating basic earnings	0	(122)
Basic income attributable to common stockholders	(465)	10,573
Reallocation of participating earnings	0	3
Diluted income attributable to common stockholders	$ (465)	$ 10,576

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 430,298	$ 229,396
Accounts receivable:
Trade, net	355,093	316,854
Due from affiliates	4,124	3,299
Income taxes receivable	1,394	7,447
Inventories	233,402	197,056
Prepaid expenses	13,337	13,438
Other current assets:
Derivatives Assets, Current	151,431	279,119
Other	7,335	3,746
Total current assets	1,196,414	1,050,355
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	15,007,980	14,259,708
Unproved properties	218,404	231,555
Accumulated depletion, depreciation and amortization	(4,633,359)	(4,412,913)
Total property, plant and equipment	10,593,025	10,078,350
Goodwill	298,142	298,142
Other property and equipment, net	1,228,108	1,217,694
Other assets:
Investment in unconsolidated affiliate	216,369	204,129
Derivative Assets, Noncurrent	95,121	55,257
Other, net	134,118	165,103
Assets, Total	13,761,297	13,069,030
Accounts payable:
Trade	780,395	729,942
Due to affiliates	39,968	96,935
Interest payable	37,494	68,083
Income taxes payable	292	208
Deferred Tax Liabilities, Net, Current	51,783	86,481
Other current liabilities:
Derivative Liabilities, Current	20,413	13,416
Other	41,521	39,725
Total current liabilities	971,866	1,034,790
Long-term debt	3,017,280	3,721,193
Derivative Liabilities, Noncurrent	13,372	12,307
Deferred income taxes	2,202,637	2,140,416
Other liabilities	290,071	293,016
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 134,763,095 and 133,121,092 shares issued at June 30, 2012 and December 31, 2011, respectively	1,458	1,350
Additional paid-in capital	4,898,318	3,683,934
Treasury stock at cost: 11,727,359 and 11,264,936 at June 30, 2012 and December 31, 2011, respectively	(420,947)	(510,570)
Retained earnings	2,609,801	2,514,640
Total equity attributable to common stockholders	7,088,630	5,689,354
Noncontrolling interests in consolidating subsidiaries	177,441	177,954
Total equity	7,266,071	5,867,308
Commitments and contingencies
Liabilities and Stockholders' Equity, Total	$ 13,761,297	$ 13,069,030

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Exploratory Costs (Schedule Of Capitalized Exploratory Well And Project Activity) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Exploratory Cost Disclosure [Abstract]
Beginning capitalized exploratory costs	$ 212,670
Additions to exploratory costs pending the determination of proved reserves	351,575
Reclassification due to determination of proved reserves	(262,754)
Exploratory well costs charged to exploration expense	(7,734)
Ending capitalized exploratory costs	293,757
Capitalized exploratory costs that have been suspended, One year or less	174,841	190,678
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	$ 118,916	$ 21,992
Number of projects with exploratory costs that have been suspended for a period greater than one year	2	1

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Consolidated Statement Of Equity (USD $) In Thousands, except Share data, unless otherwise specified	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]
Balance at Dec. 31, 2012	$ 5,867,308	$ 1,350	$ 3,683,934	$ (510,570)	$ 2,514,640	$ 177,954
Balance, shares at Dec. 31, 2012		123,356,000
Stock Issued During Period, Shares, New Issues	10,350,000
Stock Issued During Period, Value, New Issues	1,280,916	103	1,280,813
Dividends declared ($0.04 per share)	(5,502)				(5,502)
Exercise of long-term incentive plan stock options	1,047		(791)	1,838	0
Exercise of long-term incentive plan stock options, shares		41,000
Treasury stock purchases	(19,202)			(19,202)		0
Treasury stock purchases, shares		2,232,000
Conversion of 2.875% senior convertible notes	(2)		(106,989)	106,987
Adjustments to Additional Paid in Capital, Income Tax Benefit from Conversion of Convertible Notes	22,524		22,524
Tax benefit related to stock-based compensation	1,688		1,688
Compensation costs:
Vested compensation awards, net	0	5	(5)
Vested compensation awards, net, shares		484,000
Compensation costs included in net income	17,444		17,144			300
Cash distributions to noncontrolling interests	8,885					(8,885)
Net income	108,735				100,663	8,072
Balance at Mar. 31, 2013	$ 7,266,071	$ 1,458	$ 4,898,318	$ (420,947)	$ 2,609,801	$ 177,441
Balance, shares at Mar. 31, 2013		136,463,000

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Acquisitions and Divestitures (Narrative) (Details) (USD $)	3 Months Ended			12 Months Ended		3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012	Dec. 31, 2012 Pioneer South Africa [Member]	Mar. 31, 2012 Pioneer South Africa [Member]	Mar. 31, 2013 Wolfcamp [Member] Rate	Mar. 31, 2013 West Panhandle [Member]	Mar. 31, 2012 Eagle Ford Shale [Member]
Acquisitions and Divestitures [Line Items]
Business acquisition, cost of acquired entity, purchase price			$ 297,100,000
Gains (Losses) on Sales of Assets	24,417,000	43,596,000					21,700,000	42,600,000
Proceeds from Sale of Productive Assets	46,184,000	58,514,000					37,400,000	54,700,000
Business Combination, Consideration Transferred					60,000,000	1,700,000,000
Proceeds from Divestiture of Interest in Consolidated Subsidiaries				15,900,000		522,000,000
Gains Losses On Sales Of Assets Discontinued Operations				28,600,000
Oil And Gas Revenue From Discontinued Operations		19,600,000
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax		17,400,000
Joint Venture Investment Ownership Percentage						40.00%
Maximum Payments From Related Party For Exploration Drilling And Completion Costs						$ 1,200,000,000
Payments From Related Party For Exploration Drilling And Completion Costs Percent						75.00%

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Net Income (Loss) Per Share

3 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Net Income (Loss) Per Share

Net Income Per Share

The Company uses the two-class method of calculating net income per share because certain of the Company's and its consolidated subsidiaries' unvested share-based awards qualify as participating securities. Participating securities participate in the Company's dividend or partnership distributions and are assumed to participate in the Company's undistributed income proportionate to their share of the weighted average outstanding common shares, but are not assumed to participate in the Company's net losses because they are not contractually obligated to do so. Accordingly, allocations of earnings to participating securities are included in the Company's calculations of basic and diluted earnings per share from continuing operations, discontinued operations and net income attributable to common stockholders.

During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share from continuing operations; therefore, conversion into common stock is assumed not to occur.

The following tables reconcile the Company's net income (loss) attributable to common stockholders to basic net income attributable to common stockholders and diluted net income (loss) attributable to common stockholders for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31, 2013
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	101,128		$	(465	)	$	100,663
Participating basic earnings	(1,270		)	—			(1,270		)
Basic net income (loss) attributable to common stockholders	99,858			(465		)	99,393
Reallocation of participating earnings	35			—			35
Diluted income (loss) attributable to common stockholders	$	99,893		$	(465	)	$	99,428

	Three Months Ended March 31, 2012
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	203,924		$	10,695		$	214,619
Participating basic earnings	(2,326		)	(122		)	(2,448		)
Basic income attributable to common stockholders	201,598			10,573			212,171
Reallocation of participating earnings	68			3			71
Diluted income attributable to common stockholders	$	201,666		$	10,576		$	212,242

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013	2012
	(in thousands)
Weighted average common shares outstanding:
Basic	128,940	122,480
Dilutive common stock options (a)	157	150
Convertible Senior Notes dilution	3,534	3,460
Contingently issuable performance unit shares	120	157
Diluted	132,751	126,247

 ____________________

(a) Options to purchase 98,819 shares of the Company's common stock were excluded from the diluted income per share calculations for the three months ended March 31, 2013 because they would have been anti-dilutive to the calculation.

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Fair Value Measurements (Schedule Of Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities, Fair Value Disclosure	$ 300
Derivative Asset, Fair Value, Net	246,552
Deferred Compensation Plan Assets	53,768
Assets, Fair Value Disclosure	300,620
Liabilities, Fair Value Disclosure	33,785
Recurring Measurements, (Fair Value, Total)	266,835
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities, Fair Value Disclosure	158
Derivative Asset, Fair Value, Net	0
Deferred Compensation Plan Assets	53,768
Assets, Fair Value Disclosure	53,926
Liabilities, Fair Value Disclosure	0
Recurring Measurements, (Fair Value, Total)	53,926
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities, Fair Value Disclosure	142
Derivative Asset, Fair Value, Net	246,552
Deferred Compensation Plan Assets	0
Assets, Fair Value Disclosure	246,694
Liabilities, Fair Value Disclosure	33,785
Recurring Measurements, (Fair Value, Total)	212,909
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities, Fair Value Disclosure	0
Derivative Asset, Fair Value, Net	0
Deferred Compensation Plan Assets	0
Assets, Fair Value Disclosure	0
Liabilities, Fair Value Disclosure	0
Recurring Measurements, (Fair Value, Total)	0
Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	5,784
Interest Rate Derivatives [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	0
Interest Rate Derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	5,784
Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	0
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	28,001
Commodity Derivatives [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	0
Commodity Derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	28,001
Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	$ 0

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Basis Of Presentation (Policies)

3 Months Ended

Mar. 31, 2013

Basis Of Presentation [Abstract]

Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of March 31, 2013 and for the three months ended March 31, 2013 and 2012 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, 2012.

Certain reclassifications have been made to the 2012 financial statement and footnote amounts in order to conform to the 2013 presentation.

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Consolidated Statement Of Equity (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Statement of Stockholders' Equity [Abstract]
Dividends declared per share	$ 0.04	$ 0.04

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Consolidated Balance Sheets (Parenthetical) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000,000	500,000,000,000
Common Stock, Shares, Issued	145,799,929	134,966,740
Treasury Stock, Shares	9,337,865	11,611,093

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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2013

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

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 months ended March 31, 2013 and 2012:

		Three Months Ended March 31,
		2013			2012
	(in thousands)
Beginning asset retirement obligations		$	197,754		$	136,742
New wells placed on production		2,468			830
Changes in estimates (a)		(5,597		)	—
Dispositions		(4,079		)	—
Liabilities settled		(2,849		)	(5,688		)
Accretion of discount		3,153			2,430
Accretion of discount from integrated services (b)		11			—
Ending asset retirement obligations		$	190,861		$	134,314

_____________________

(a) The change in estimate during the three months ended March 31, 2013 is attributable to lengthening the economic life of certain wells, which reduced the present value of the associated asset retirement obligation.

(b) Accretion of discount from integrated services includes Premier Silica accretion expense, which is recorded as a reduction in third-party income from vertical integration services in interest and other income in the Company's accompanying consolidated statements of operations. See Note K for more information about interest and other income.

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 March 31, 2013 and December 31, 2012, the current portions of the Company's asset retirement obligations were $12.8 million and $13.3 million, respectively.

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Document And Entity Information	3 Months Ended
	Mar. 31, 2013	May 02, 2013
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Trading Symbol	PXD
Entity Registrant Name	PIONEER NATURAL RESOURCES CO
Entity Central Index Key	0001038357
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		136,578,089

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Commitments And Contingencies

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

Commitments and Contingencies

The Company is a 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. 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.

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Consolidated Statements Of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Revenues and other income:
Oil and gas	$ 787,855	$ 718,956
Interest and other	19,315	21,908
Gains (Losses) on Sales of Assets	24,417	43,596
Total revenues and other income	831,587	784,460
Costs and expenses:
Oil and gas production	169,140	131,781
Production and ad valorem taxes	54,297	45,796
Depletion, depreciation and amortization	230,763	181,418
Exploration and abandonments	27,627	53,287
General and administrative	63,751	63,067
Accretion of discount on asset retirement obligations	3,153	2,430
Interest	50,735	46,858
Derivative (gains) losses, net	42,243	(91,750)
Other	21,349	23,607
Costs and expenses, Total	663,058	456,494
Income (loss) from continuing operations before income taxes	168,529	327,966
Income tax benefit (provision)	(59,329)	(117,703)
Income (loss) from continuing operations	109,200	210,263
Income (loss) from discontinued operations, net of tax	(465)	10,695
Net income (loss)	108,735	220,958
Net income attributable to noncontrolling interests	(8,072)	(6,339)
Net income (loss) attributable to common stockholders	100,663	214,619
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$ 0.77	$ 1.65
Income (loss) from discontinued operations attributable to common stockholders	$ 0.00	$ 0.08
Net income (loss) attributable to common stockholders	$ 0.77	$ 1.73
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$ 0.75	$ 1.60
Income (loss) from discontinued operations attributable to common stockholders	$ 0.00	$ 0.08
Net income (loss) attributable to common stockholders	$ 0.75	$ 1.68
Weighted average shares outstanding:
Basic	128,940	122,480
Diluted	132,751	126,247
Dividends declared per share	$ 0.04	$ 0.04
Amounts attributable to common stockholders:
Income (loss) from continuing operations	101,128	203,924
Income (loss) from discontinued operations, net of tax	(465)	10,695
Net income (loss)	$ 100,663	$ 214,619

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Fair Value Measurements

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

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 as of March 31, 2013:

	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 March 31, 2013
	(in thousands)
Recurring fair value measurements
Assets:
Trading securities	$	158	$	142	$	—	$	300
Commodity derivatives	—		246,552		—		246,552
Deferred compensation plan assets	53,768		—		—		53,768
Total assets	53,926		246,694		—		300,620
Liabilities:
Commodity derivatives	—		28,001		—		28,001
Interest rate derivatives	—		5,784		—		5,784
Total liabilities	—		33,785		—		33,785
Total recurring fair value measurements	$	53,926	$	212,909	$	—	$	266,835

Trading securities and deferred compensation plan assets. The Company's trading securities are comprised of securities that are both actively traded and not actively traded on major exchanges. 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 March 31, 2013, substantially all of the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Inputs for certain trading securities that are not actively traded on major exchanges were classified as Level 2 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 oil, NGL and gas swap, collar and collar contracts with short puts 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.

Interest rate derivatives. The Company's interest rate derivative liabilities as of March 31, 2013 represent interest rate swap contracts. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of March 31, 2013 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate ("LIBOR") yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative liability measurements represent Level 2 inputs in the hierarchy.

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 sheet as of March 31, 2013 and December 31, 2012 are as follows:

	March 31, 2013				December 31, 2012
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	3,017,280	$	3,768,884	$	3,721,193	$	4,555,770

Long-term debt includes the Company's credit facility, the Pioneer Southwest 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.

Credit facilities. The fair values of the Company's and Pioneer Southwest's credit facilities are 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 rate (in the case of the Company's credit facility) or LIBOR (in the case of the Pioneer Southwest credit facility) yield curves and (iii) the applicable credit-adjustments.

Senior notes. The Company's senior notes represent debt securities that are not actively traded on major exchanges. 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 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.

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Acquisitions and Divestitures

3 Months Ended

Mar. 31, 2013

Acquisitions and Divestitures [Abstract]

Acquisition and Divestitures

Acquisitions and Divestitures

Premier Silica Business Combination

On April 2, 2012, a wholly-owned subsidiary of the Company acquired an industrial sand mining business that is now called Premier Silica LLC ("Premier Silica"). Premier Silica's primary mine operations are in Brady, Texas. The Brady mine facilities primarily produce, process and provide sand to the Company for use as proppant in its fracture stimulation of oil and gas wells in Texas. Excess sand and sand not useable for fracture stimulation is sold to third parties for use as proppant or other industrial and recreational purposes. The aggregate purchase price of Premier Silica was $297.1 million, including closing adjustments.

Divestitures Recorded in Continuing Operations

Sales of unproved oil and gas properties. For the three months ended March 31, 2013, the Company's pretax gain on disposition of assets from continuing operations of $24.4 million was primarily associated with the sale of its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations to an unaffiliated third party for cash proceeds of $37.4 million, which resulted in a pretax gain of $21.7 million. For the three months ended March 31, 2012, the Company's pretax gain on disposition of assets of $43.6 million was primarily associated with the sale of a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale field to unaffiliated third parties for cash proceeds of $54.7 million, which resulted in a pretax gain of $42.6 million.

Divestitures Recorded as Discontinued Operations

South Africa. During the first quarter of 2012, the Company agreed to sell its net assets in South Africa ("Pioneer South Africa") to an unaffiliated third party, effective January 1, 2012, for $60.0 million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities of the Company's South Africa subsidiaries. In August 2012, the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale, resulting in a third quarter 2012 pretax gain of $28.6 million. The Company classified Pioneer South Africa's results of operations as income from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

For the three months ended March 31, 2012, the Company recognized revenues and other income and pretax earnings of $19.6 million and $17.4 million, respectively, associated with discontinued operations, principally related to the results of operations of Pioneer South Africa prior to its divestiture in August 2012.

Pending Divestitures

Southern Wolfcamp. In January 2013, the Company signed an agreement with Sinochem Petroleum USA LLC ("Sinochem"), a U.S. subsidiary of the Sinochem Group, 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 in West Texas for total consideration of $1.7 billion. Sinochem will pay $522.0 million in cash to Pioneer at closing, before normal closing adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of Pioneer's portion of future drilling and facilities costs attributable to the horizontal Wolfcamp Shale play. This transaction is expected to close during the second quarter of 2013, subject to governmental approvals.

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Subsequent Events

3 Months Ended

Mar. 31, 2013

Subsequent Events [Abstract]

Subsequent Events

Subsequent Event

In April 2013, Pioneer Southwest declared a cash distribution of $0.52 per common unit for the period from January 1 to March 31, 2013. The distribution is payable on May 10, 2013 to unitholders of record at the close of business on May 3, 2013. Associated therewith, Pioneer Southwest expects to pay $18.6 million of aggregate distributions.

On April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that have not been converted by the holders before May 16, 2013 for cash at a price equal to the full principal amount plus accrued and unpaid interest, in accordance with the indenture agreement. The Convertible Senior Notes are convertible at the option of the holders prior to May 16, 2013, using a net share settlement process, into a combination of cash and shares of the Company's common stock based on a formula set forth in the indenture supplement. See Note G for additional information about the Convertible Senior Notes.

On May 7, 2013, the Company delivered a proposal to the chairman of the Conflicts Committee (the "Conflicts Committee") of the General Partner to acquire all of the outstanding common units of Pioneer Southwest that are held by unitholders other than Pioneer or its subsidiaries for consideration of .2234 of a share of common stock of Pioneer for each outstanding common unit of Pioneer Southwest held by such unitholders in a transaction to be structured as a merger of Pioneer Southwest with a wholly-owned subsidiary of Pioneer.  In proposing the .2234 exchange ratio, the Company stated that it has assumed that a regular quarterly common unit distribution of $0.52 per common unit will be declared by Pioneer Southwest in July 2013 and that, thereafter, common unit distributions will be suspended while the transaction is pending.  The consummation of the transactions contemplated by the Company's proposal is subject to approval of the Company's board of directors, approval of the Conflicts Committee and the negotiation of a definitive agreement.  There can be no assurance that a definitive agreement will be executed or that any transaction will be approved or consummated.

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Interest And Other Income

3 Months Ended

Mar. 31, 2013

Interest and Other Income [Abstract]

Interest And Other Income

Interest and Other Income

The following table provides the components of the Company's interest and other income for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013			2012
	(in thousands)
Alaskan Petroleum Production Tax credits and refunds (a)	$	19,408		$	11,846
Equity interest in income of unconsolidated affiliate	3,536			441
Other income	1,876			1,641
Deferred compensation plan income	1,627			1,374
Interest income	93			57
Income (loss) from vertical integration services (b)	(7,225		)	6,549
Total interest and other income	$	19,315		$	21,908

 ____________________

(a) The Company earns Alaskan Petroleum Production Tax ("PPT") credits on qualifying capital expenditures. The Company recognizes income from PPT credits when they are realized through cash refunds or as reductions in production and ad valorem taxes if realizable as offsets to PPT expense.

(b) Income (loss) from vertical integration services represent net margins that result from Company-provided fracture stimulation, drilling 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 months ended March 31, 2013 and 2012, these net margins include $56.1 million and $75.4 million of gross vertical integration revenues, respectively, and $63.3 million and $68.9 million of total vertical integration costs and expenses, respectively.

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Long-Term Debt

3 Months Ended

Mar. 31, 2013

Debt Disclosure [Abstract]

Long-Term Debt

Long-term Debt

The Company's long-term debt consists of senior notes and revolving credit facilities, including the effects of net deferred fair value hedge losses and issuance discounts. As of March 31, 2013, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

Credit facility. The Company maintains a Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that has aggregate loan commitments of $1.5 billion that expires in December 2017. As of March 31, 2013, the Company had no outstanding borrowings under the Credit Facility.

Pioneer Southwest credit facility. Pioneer Southwest maintains a Credit Agreement (the "Pioneer Southwest Credit Facility") with a syndicate of financial institutions that has aggregate loan commitments of $300 million that expires in March 2017. As of March 31, 2013, Pioneer Southwest had outstanding borrowings of $154.0 million under the Credit Facility, leaving $146.0 million of unused borrowing capacity.

Convertible senior notes. As of March 31, 2013 and December 31, 2012, the Company had $218.6 million and $479.9 million of 2.875% Convertible Senior Notes due 2038 ("Convertible Senior Notes") outstanding. The Convertible Senior Notes are convertible at the option of the holders under certain circumstances, using a net share settlement process, into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the Convertible Senior Notes were issued and, as of January 15, 2013, are redeemable by the Company at any time for cash at a price equal to the full principal amount plus accrued and unpaid interest.

During December 2012, the Company's stock price met the price threshold that causes the Convertible Senior Notes to be convertible at the option of the holders for the three months ended March 31, 2013. Associated therewith, during the three months ended March 31, 2013, holders of $274.1 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock and the Company paid the tendering holders $261.3 million of cash and issued to the tendering holders 2.4 million shares of the Company's common stock during the three months ended March 31, 2013, in accordance with the terms of the Convertible Senior Notes indenture agreement. The remaining $12.8 million principal amount was settled in cash and the issuance of 115 thousand shares of the Company's common stock in April 2013.

The Company's stock prices during March 2013 and 2012 also met the price threshold that causes the Convertible Senior Notes to be convertible at the option of the holders for the following three month period. In addition, on April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that have not been converted by the holders before May 16, 2013.

If all of the remaining Convertible Senior Notes had been converted on March 31, 2013, the note holders would have received $218.6 million of additional cash and approximately 2.1 million shares of the Company's common stock, which were valued at $259.7 million on March 31, 2013. Holders of the Convertible Senior Notes who present their notes for conversion prior to May 16, 2013 will be subject to a 20 consecutive day cash settlement averaging period that will encompass the trading days from April 16, 2013 through May 13, 2013. The Company has the intent and ability to fund cash payments that will be required upon the conversion or redemption of the Convertible Senior Notes with borrowing capacity under the Credit Facility. Accordingly, the Convertible Senior Notes are classified as long-term debt in the accompanying balance sheets.

Interest on the principal amount of the Convertible Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The trading price of the Convertible Senior Notes for the five consecutive trading days preceding January 15, 2013 exceeded 120 percent of the principal amount of the note and, in accordance with the indenture supplement, the interest rate in effect during the January 15, 2013 to July 14, 2013 period was reduced to 2.375 percent.

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Derivative Financial Instruments

3 Months Ended

Mar. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

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 following table sets forth the volumes per day in barrels ("BBLs") associated with the Company's outstanding oil derivative contracts as of March 31, 2013 and the weighted average oil prices per BBL for those contracts:

	Nine Months Ending December 31,			Year Ending December 31,
	2013			2014		2015
Collar contracts with short puts:
Volume (BBL)	72,430			69,000		26,000
Average price per BBL:
Ceiling	$	119.89		$	114.05	$	104.45
Floor	$	92.26		$	93.70	$	95.00
Short put	$	74.36		$	77.61	$	80.00
Swap contracts:
Volume (BBL)	3,000			—		—
Average price per BBL	$	81.02		$	—	$	—
Rollfactor swap contracts:
Volume (BBL)	6,000			15,000		—
NYMEX roll price (a)	$	0.43		$	0.38	$	—
Basis swap contracts:
Midland-Cushing index swap volume (BBL)	1,655			—		—
Average price per BBL (b)	$	(5.75	)	$	—	$	—
Cushing-LLS index swap volume (BBL)	669			—		—
Average price per BBL (c)	$	(9.30	)	$	—	$	—

 ____________________

(a) 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.

(b) Basis differential price between Midland WTI and Cushing WTI.

(c) Basis differential price between Cushing WTI and Louisiana Light Sweet crude "LLS".

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 product component prices.

The following table sets forth the volumes per day in BBLs associated with the Company's outstanding NGL derivative contracts as of March 31, 2013 and the weighted average NGL prices per BBL for those contracts:

	Nine Months Ending December 31,		Year Ending December 31,
	2013		2014
Collar contracts with short puts:
Volume (BBL)	1,064		1,000
Average price per BBL:
Ceiling	$	105.28	$	109.50
Floor	$	89.30	$	95.00
Short put	$	75.20	$	80.00

Subsequent to March 31, 2013, the Company entered into additional NGL collar contracts for (i) 2,000 BBLs per day of the Company's May through December 2013 ethane production with a ceiling price of $12.60 per BBL and a floor price of $10.50 per BBL, (ii) 500 BBLs per day of the Company's July through December 2013 ethane production with a ceiling price of $13.02 per BBL and a floor price of $10.50 per BBL and (iii) 3,000 BBLs per day of the Company's 2014 ethane production with a ceiling price of $13.72 per BBL and a floor price of $10.78 per BBL.

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 reduce basis risk between HH prices and actual index prices at which the gas is sold.

The following table sets forth the volumes per day in millions of British thermal units ("MMBTU") associated with the Company's outstanding gas derivative contracts as of March 31, 2013 and the weighted average gas prices per MMBTU for those contracts:

	Nine Months Ending December 31,			Year Ending December 31,
	2013			2014			2015		2016
Collar contracts with short puts:
Volume (MMBTU) (a)	—			65,000			235,000		20,000
Price per MMBTU:
Ceiling	$	—		$	4.70		$	5.09	$	5.36
Floor	$	—		$	4.00		$	4.00	$	4.00
Short put	$	—		$	3.00		$	3.00	$	3.00
Collar contracts:
Volume (MMBTU) (a)	150,000			—			—		—
Price per MMBTU:
Ceiling	$	6.25		$	—		$	—	$	—
Floor	$	5.00		$	—		$	—	$	—
Swap contracts:
Volume (MMBTU)	170,282			175,000			20,000		—
Price per MMBTU	$	5.07		$	4.02		$	4.31	$	—
Basis swap contracts:
Volume (MMBTU) (a)	162,500			10,000			—		—
Price per MMBTU	$	(0.22	)	$	(0.19	)	$	—	$	—

____________________

(a) Subsequent to March 31, 2013, the Company entered into additional (i) collar contracts for 2,500 MMBTUs per day of the Company's June through December 2013 production with a ceiling price of $4.50 per MMBTU and a floor price of $4.00 per MMBTU, (ii) collar contracts with short puts for 50,000 MMBTUs per day of the Company's 2014 production with a ceiling price of $4.70 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU, (iii) collar contracts with short puts for 50,000 MMBTUs per day of the Company's 2015 production with a ceiling price of $5.03 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU, (iv) basis swap contracts for 22,500 MMBTU per day of the Company's 2014 production with a negative price differential of $0.18 per MMBTU between the relevant index price and the NYMEX price and (v) basis swap contracts for 7,500 MMBTU per day of the Company's 2015 production with a negative price differential of $0.13 per MMBTU between the relevant index price and the NYMEX price.

Marketing and basis transfer derivative activities. Periodically, the Company enters into buy and sell marketing arrangements to utilize unused firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate the related price risk.

The following table sets forth the contract volumes associated with the Company's outstanding marketing derivative contracts as of March 31, 2013 and the weighted average prices for those contracts:

	Nine Months Ending December 31,
	2013
Average Daily Gas Production Associated with Marketing Derivatives:
Basis swap contracts:
Index swap volume (MMBTU)	4,364
Price differential ($/MMBTU)	$	0.34

Interest rates. As of March 31, 2013, the Company was a party to interest rate derivative contracts that lock in a fixed forward annual interest rate of 3.21 percent, for a 10-year period ending in December 2025, on a notional amount of $250 million. These derivative contracts mature and settle by their terms in December 2015.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of March 31, 2013 and December 31, 2012 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 executed under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty, as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty.

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

Fair Value of Derivative Instruments as of March 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 thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	160,149	$	(8,718	)	$	151,431
Commodity price derivatives	Derivatives - noncurrent	$	100,090	$	(4,969	)	95,121
							$	246,552
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	29,131	$	(8,718	)	$	20,413
Commodity price derivatives	Derivatives - noncurrent	$	12,557	$	(4,969	)	7,588
Interest rate derivatives	Derivatives - noncurrent	$	5,784	$	—		5,784
							$	33,785

Fair Value of Derivative Instruments as of December 31, 2012
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 thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	286,805	$	(7,686	)	$	279,119
Commodity price derivatives	Derivatives - noncurrent	$	61,618	$	(6,361	)	55,257
							$	334,376
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	21,102	$	(7,686	)	$	13,416
Commodity price derivatives	Derivatives - noncurrent	$	8,944	$	(6,361	)	2,583
Interest rate derivatives	Derivatives - noncurrent	$	9,724	$	—		9,724
							$	25,723

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.

Derivatives in Cash Flow Hedging	Location of (Gain)/Loss Reclassified from
		Three Months Ended March 31,
Relationships	AOCI into Earnings	2013		2012
		(a)
Commodity price derivatives	Oil and gas revenue	$	—	$	809
Interest rate derivatives	Interest expense	—		1,699
Total		$	—	$	2,508

____________________

(a) During 2012, all remaining Accumulated Other Comprehensive Income ("AOCI") related to hedging was transferred to earnings.

Derivatives Not Designated as Hedging	Location of (Gain) Loss Recognized in	Three Months Ended March 31,
Instruments	Earnings on Derivatives	2013			2012
Commodity price derivatives	Derivative (gains) losses, net	$	46,183		$	(88,130	)
Interest rate derivatives	Derivative (gains) losses, net	(3,940		)	(3,620		)
Total		$	42,243		$	(91,750	)

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Exploratory Costs

3 Months Ended

Mar. 31, 2013

Exploratory Cost Disclosure [Abstract]

Exploratory Costs

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. After an exploratory well has been completed and found oil and gas reserves, a determination may be pending as to whether the oil and gas reserves can be classified as proved. In those circumstances, the Company continues to capitalize the well or project costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. 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 months ended March 31, 2013:

	Three Months Ended March 31, 2013
	(in thousands)
Beginning capitalized exploratory costs	$	212,670
Additions to exploratory costs pending the determination of proved reserves	351,575
Reclassification due to determination of proved reserves	(262,754		)
Exploratory well costs charged to exploration expense	(7,734		)
Ending capitalized exploratory costs	$	293,757

The following table provides an aging, as of March 31, 2013 and December 31, 2012, 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:

	March 31, 2013		December 31, 2012
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	174,841	$	190,678
More than one year	118,916		21,992
	$	293,757	$	212,670
Number of projects with exploratory costs that have been suspended for a period greater than one year	2		1

Alaska - Oooguruk.As of each of March 31, 2013 and December 31, 2012, the Company had $22.0 million of suspended well costs recorded for the K-13 well in the Alaska Oooguruk field. Drilling on the K-13 well was completed during September 2011. During well completion operations, subsurface damages were sustained. The Company plans to recomplete the well during 2013. The well may require additional stimulation work that, if required, will be done during the first quarter of 2014 to initiate production.

Alaska - Nuna. The Company's Nuna project, which has $96.9 million of suspended project costs as of March 31, 2013, includes the Nuna-1 exploration well that was drilled during 2012 to test the Torok formation and a second appraisal well that was drilled and logged during the first quarter of 2013. The Company flow-tested the Nuna-1 well during the second quarter of 2012 and again in the first quarter of 2013. The second appraisal well encountered a mechanical problem and could not be flow-tested before the end of the winter drilling season. The results of the flow-tests on the Nuna-1 well and the log data from the second Nuna well are both very encouraging. The Company is currently conducting a front-end engineering design ("FEED") study to evaluate the potential for onshore production facilities to support the project.

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Incentive Plans

3 Months Ended

Mar. 31, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Incentive Plans

Incentive Plans

Stock-based compensation

For the three months ended March 31, 2013, the Company recorded $27.6 million of stock-based compensation expense for all plans, as compared to $21.3 million for the same period of 2012. As of March 31, 2013, there was $198.5 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $47.5 million attributable to stock-based awards that are expected to be settled in cash on their vesting date, rather than in equity shares ("Liability Awards"). This compensation 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 March 31, 2013 and December 31, 2012, accounts payable – due to affiliates includes $5.8 million and $18.8 million, respectively, of liabilities attributable to Liability Awards.

The following table summarizes the activity that occurred during the three months ended March 31, 2013, for each type of share-based incentive award issued by Pioneer:

	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units	Stock Options		Pioneer Southwest LTIP Restricted Units	Pioneer Southwest LTIP Phantom Units
Outstanding at December 31, 2012	1,512,762		405,916		91,370	467,486		7,496	102,644
Awards granted	397,439		238,269		94,917	—		—	32,242
Awards vested	(476,717	)	(178,143	)	—	—		—	(35,118	)
Options exercised	—		—		—	(12,818	)	—	—
Awards forfeited	(3,834	)	(5,015	)	—	—		—	—
Outstanding as of March 31, 2013	1,429,650		461,027		186,287	454,668		7,496	99,768

Postretirement Benefit Obligations

As of March 31, 2013 and December 31, 2012, the Company had $9.1 million and $9.7 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. These obligations are comprised of five unfunded plans, of which four relate to predecessor entities that the Company acquired in prior years, and one funded plan that the Company assumed sponsorship for in conjunction with the acquisition of Premier Silica.

The unfunded plans had no assets as of March 31, 2013 or December 31, 2012. The Company's funding policy for the Premier Silica plan is to contribute amounts sufficient to meet legal funding requirements, plus any additional amounts that the Company may determine to be appropriate considering the funded status of the plan, tax deductibility, the cash flow generated by the Company, and other factors. The Company continually reassesses the amount and timing of any discretionary contributions and may elect to make such contributions in future periods.

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Basis Of Presentation Basis of Presentation (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Summary Of Significant Accounting Policies [Line Items]
Stock Issued During Period, Shares, New Issues	10,350
Proceeds from Issuance of Common Stock	$ 1,280,916	$ 0
Noncontrolling interests in consolidating subsidiaries	177,441		177,954
General Partner Interest [Member]
Summary Of Significant Accounting Policies [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	0.10%
Limited Partner Interest [Member]
Summary Of Significant Accounting Policies [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	52.40%
Pioneer Southwest [Member]
Summary Of Significant Accounting Policies [Line Items]
Noncontrolling interests in consolidating subsidiaries	$ 163,900

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Other Expense (Schedule Of Components Of Other Expense) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Other Expense [Abstract]
Transportation commitment charges	$ 9,377	[1]	$ 8,453	[1]
Other	4,565		2,911
Above market drilling rig rates	3,507	[2]	4,986	[2]
Inventory valuation charges	1,587	[3]	6,041	[3]
Contingency and environmental accrual adjustments	1,294		1,216
Terminated drilling rig contract charges	1,019		0
Total other expense	$ 21,349		$ 23,607

[1] Primarily represents firm transportation payments on excess pipeline capacity commitments.

[2] Primarily represents expenses attributable to the portion of Pioneer's contracted drilling rig rates that are above current market rates and idle drilling rig fees, neither of which are charged to joint operations.

[3] Represents valuation charges on excess materials and supplies inventories.

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Income Taxes

3 Months Ended

Mar. 31, 2013

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company's income tax provisions attributable to income from continuing operations consisted of the following for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013			2012
	(in thousands)
Current	$	(7,435	)	$	(11,832	)
Deferred	(51,894		)	(105,871		)
Income tax provision	$	(59,329	)	$	(117,703	)

For each of the three months ended March 31, 2013 and 2012, the Company's effective tax rate, excluding income attributable to the noncontrolling interest, was 37 percent. The Company's effective tax rate differed from the U.S. statutory rate of 35 percent due to state income taxes and nondeductible expenses.

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 2011 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 March 31, 2013, 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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Derivative Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of oil derivative contracts volume and weighted average price

The following table sets forth the volumes per day in barrels ("BBLs") associated with the Company's outstanding oil derivative contracts as of March 31, 2013 and the weighted average oil prices per BBL for those contracts:

	Nine Months Ending December 31,			Year Ending December 31,
	2013			2014		2015
Collar contracts with short puts:
Volume (BBL)	72,430			69,000		26,000
Average price per BBL:
Ceiling	$	119.89		$	114.05	$	104.45
Floor	$	92.26		$	93.70	$	95.00
Short put	$	74.36		$	77.61	$	80.00
Swap contracts:
Volume (BBL)	3,000			—		—
Average price per BBL	$	81.02		$	—	$	—
Rollfactor swap contracts:
Volume (BBL)	6,000			15,000		—
NYMEX roll price (a)	$	0.43		$	0.38	$	—
Basis swap contracts:
Midland-Cushing index swap volume (BBL)	1,655			—		—
Average price per BBL (b)	$	(5.75	)	$	—	$	—
Cushing-LLS index swap volume (BBL)	669			—		—
Average price per BBL (c)	$	(9.30	)	$	—	$	—

 ____________________

(a) 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.

(b) Basis differential price between Midland WTI and Cushing WTI.

(c) Basis differential price between Cushing WTI and Louisiana Light Sweet crude "LLS".

Schedule of NGL derivative volumes and weighted average prices

The following table sets forth the volumes per day in BBLs associated with the Company's outstanding NGL derivative contracts as of March 31, 2013 and the weighted average NGL prices per BBL for those contracts:

	Nine Months Ending December 31,		Year Ending December 31,
	2013		2014
Collar contracts with short puts:
Volume (BBL)	1,064		1,000
Average price per BBL:
Ceiling	$	105.28	$	109.50
Floor	$	89.30	$	95.00
Short put	$	75.20	$	80.00

Schedule of gas derivative volume and weighted average prices

The following table sets forth the volumes per day in millions of British thermal units ("MMBTU") associated with the Company's outstanding gas derivative contracts as of March 31, 2013 and the weighted average gas prices per MMBTU for those contracts:

	Nine Months Ending December 31,			Year Ending December 31,
	2013			2014			2015		2016
Collar contracts with short puts:
Volume (MMBTU) (a)	—			65,000			235,000		20,000
Price per MMBTU:
Ceiling	$	—		$	4.70		$	5.09	$	5.36
Floor	$	—		$	4.00		$	4.00	$	4.00
Short put	$	—		$	3.00		$	3.00	$	3.00
Collar contracts:
Volume (MMBTU) (a)	150,000			—			—		—
Price per MMBTU:
Ceiling	$	6.25		$	—		$	—	$	—
Floor	$	5.00		$	—		$	—	$	—
Swap contracts:
Volume (MMBTU)	170,282			175,000			20,000		—
Price per MMBTU	$	5.07		$	4.02		$	4.31	$	—
Basis swap contracts:
Volume (MMBTU) (a)	162,500			10,000			—		—
Price per MMBTU	$	(0.22	)	$	(0.19	)	$	—	$	—

____________________

(a) Subsequent to March 31, 2013, the Company entered into additional (i) collar contracts for 2,500 MMBTUs per day of the Company's June through December 2013 production with a ceiling price of $4.50 per MMBTU and a floor price of $4.00 per MMBTU, (ii) collar contracts with short puts for 50,000 MMBTUs per day of the Company's 2014 production with a ceiling price of $4.70 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU, (iii) collar contracts with short puts for 50,000 MMBTUs per day of the Company's 2015 production with a ceiling price of $5.03 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU, (iv) basis swap contracts for 22,500 MMBTU per day of the Company's 2014 production with a negative price differential of $0.18 per MMBTU between the relevant index price and the NYMEX price and (v) basis swap contracts for 7,500 MMBTU per day of the Company's 2015 production with a negative price differential of $0.13 per MMBTU between the relevant index price and the NYMEX price.

Schedule of marketing and basis transfer derivative contracts

The following table sets forth the contract volumes associated with the Company's outstanding marketing derivative contracts as of March 31, 2013 and the weighted average prices for those contracts:

	Nine Months Ending December 31,
	2013
Average Daily Gas Production Associated with Marketing Derivatives:
Basis swap contracts:
Index swap volume (MMBTU)	4,364
Price differential ($/MMBTU)	$	0.34

Offsetting Asset and Liability [Table Text Block]

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

Fair Value of Derivative Instruments as of March 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 thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	160,149	$	(8,718	)	$	151,431
Commodity price derivatives	Derivatives - noncurrent	$	100,090	$	(4,969	)	95,121
							$	246,552
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	29,131	$	(8,718	)	$	20,413
Commodity price derivatives	Derivatives - noncurrent	$	12,557	$	(4,969	)	7,588
Interest rate derivatives	Derivatives - noncurrent	$	5,784	$	—		5,784
							$	33,785

Fair Value of Derivative Instruments as of December 31, 2012
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 thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	286,805	$	(7,686	)	$	279,119
Commodity price derivatives	Derivatives - noncurrent	$	61,618	$	(6,361	)	55,257
							$	334,376
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	21,102	$	(7,686	)	$	13,416
Commodity price derivatives	Derivatives - noncurrent	$	8,944	$	(6,361	)	2,583
Interest rate derivatives	Derivatives - noncurrent	$	9,724	$	—		9,724
							$	25,723

Schedule of derivative obligations under terminated hedge arrangements

Derivatives in Cash Flow Hedging	Location of (Gain)/Loss Reclassified from
		Three Months Ended March 31,
Relationships	AOCI into Earnings	2013		2012
		(a)
Commodity price derivatives	Oil and gas revenue	$	—	$	809
Interest rate derivatives	Interest expense	—		1,699
Total		$	—	$	2,508

____________________

(a) During 2012, all remaining Accumulated Other Comprehensive Income ("AOCI") related to hedging was transferred to earnings.

Derivatives Not Designated as Hedging	Location of (Gain) Loss Recognized in	Three Months Ended March 31,
Instruments	Earnings on Derivatives	2013			2012
Commodity price derivatives	Derivative (gains) losses, net	$	46,183		$	(88,130	)
Interest rate derivatives	Derivative (gains) losses, net	(3,940		)	(3,620		)
Total		$	42,243		$	(91,750	)

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Asset Retirement Obligations (Details) (USD $)	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012		Dec. 31, 2012
Asset Retirement Obligation [Abstract]
Beginning asset retirement obligations	$ 197,754,000		$ 136,742,000
Asset Retirement Obligation, Liabilities Incurred	2,468,000		830,000
Changes in estimates	(5,597,000)	[1]	0	[1]
Disposition of wells	(4,079,000)		0
Liabilities settled	(2,849,000)		(5,688,000)
Accretion of discount from continuing operations	3,153,000		2,430,000
Accretion of discount from integrated services	11,000	[2]	0	[2]
Ending asset retirement obligations	190,861,000		134,314,000
Asset retirement obligations, current portions	$ 12,800,000				$ 13,300,000

[1] The change in estimate during the three months ended March 31, 2013 is attributable to lengthening the economic life of certain wells, which reduced the present value of the associated asset retirement obligation.

[2] Accretion of discount from integrated services includes Premier Silica accretion expense, which is recorded as a reduction in third-party income from vertical integration services in interest and other income in the Company's accompanying consolidated statements of operations. See Note K for more information about interest and other income.

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Derivative Financial Instruments Derivative Financial Instruments (Schedule of Gas Derivative Contracts Volume and Weighted Average Prices) (Details)	May 08, 2013 MMBTU		Mar. 31, 2013 MMBTU
Two Thousand Thirteen Collar Contracts With Short Puts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day			0
Two Thousand Thirteen Collar Contracts With Short Puts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price			0.00
Derivative, Average Floor Price			0.00
Two Thousand Thirteen Collar Contracts With Short Puts [Member] | Gas contracts, price per MMBTU [Member] | Short Put [Member]
Derivative [Line Items]
Nonmonetary Notional Amount of Price Risk Derivative Instruments Not Designated as Hedging Instruments			0.00
Two Thousand Sixteen Collar Contracts With Short Puts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day			20,000
Two Thousand Sixteen Collar Contracts With Short Puts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price			5.36
Derivative, Average Floor Price			4.00
Two Thousand Sixteen Collar Contracts With Short Puts [Member] | Gas contracts, price per MMBTU [Member] | Short Put [Member]
Derivative [Line Items]
Nonmonetary Notional Amount of Price Risk Derivative Instruments Not Designated as Hedging Instruments			3.00
Two Thousand Fifteen Collar Contracts With Short Puts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day	50,000	[1]	235,000	[1]
Two Thousand Fifteen Collar Contracts With Short Puts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price	5.03	[1]	5.09	[1]
Derivative, Average Floor Price	4.00	[1]	4.00	[1]
Two Thousand Fifteen Collar Contracts With Short Puts [Member] | Gas contracts, price per MMBTU [Member] | Short Put [Member]
Derivative [Line Items]
Nonmonetary Notional Amount of Price Risk Derivative Instruments Not Designated as Hedging Instruments	3.00	[1]	3.00	[1]
Two Thousand Fourteen Collar Contracts With Short Puts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day	50,000		65,000	[1]
Two Thousand Fourteen Collar Contracts With Short Puts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price	4.70		4.70	[1]
Derivative, Average Floor Price	4.00		4.00	[1]
Two Thousand Fourteen Collar Contracts With Short Puts [Member] | Gas contracts, price per MMBTU [Member] | Short Put [Member]
Derivative [Line Items]
Nonmonetary Notional Amount of Price Risk Derivative Instruments Not Designated as Hedging Instruments	3.00		3.00	[1]
Two Thousand Thirteen Collar Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day	2,500		150,000	[1]
Two Thousand Thirteen Collar Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price	4.50		6.25	[1]
Derivative, Average Floor Price	4.00		5.00	[1]
Two Thousand Fourteen Collar Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day			0
Two Thousand Fourteen Collar Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price			0.00
Derivative, Average Floor Price			0.00
Two Thousand Fifteen Collar Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day			0
Two Thousand Fifteen Collar Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price			0.00
Derivative, Average Floor Price			0.00
Two Thousand Sixteen Collar Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day			0
Two Thousand Sixteen Collar Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price			0.00
Derivative, Average Floor Price			0.00
Two Thousand Thirteen Swap Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day			170,282
Two Thousand Thirteen Swap Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Fixed Price			5.07
Two Thousand Fourteen Swap Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day			175,000
Two Thousand Fourteen Swap Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Fixed Price			4.02
2015 Swap Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day			20,000
2015 Swap Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Fixed Price			4.31
Two Thousand Sixteen Swap Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day			0
Two Thousand Sixteen Swap Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Fixed Price			0.00
Two Thousand And Thirteen Basis Swap Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day			162,500
Two Thousand And Thirteen Basis Swap Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Fixed Price			(0.22)
Two Thousand Fourteen Basis Swap Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day	22,500		10,000	[1]
Two Thousand Fourteen Basis Swap Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	(0.18)		(0.19)	[1]
Two Thousand Fifteen Basis Swap Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day	7,500		0
Two Thousand Fifteen Basis Swap Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	(0.13)		0.00
Two Thousand Sixteen Basis Swap Contracts [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Average Daily Gas Production Derivatives Volume per Day			0
Two Thousand Sixteen Basis Swap Contracts [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Fixed Price			0.00

[1] Subsequent to March 31, 2013, the Company entered into additional (i) collar contracts for 2,500 MMBTUs per day of the Company's June through December 2013 production with a ceiling price of $4.50 per MMBTU and a floor price of $4.00 per MMBTU, (ii) collar contracts with short puts for 50,000 MMBTUs per day of the Company's 2014 production with a ceiling price of $4.70 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU, (iii) collar contracts with short puts for 50,000 MMBTUs per day of the Company's 2015 production with a ceiling price of $5.03 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU, (iv) basis swap contracts for 22,500 MMBTU per day of the Company's 2014 production with a negative price differential of $0.18 per MMBTU between the relevant index price and the NYMEX price and (v) basis swap contracts for 7,500 MMBTU per day of the Company's 2015 production with a negative price differential of $0.13 per MMBTU between the relevant index price and the NYMEX price.

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Consolidated Statements Of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Statement of Other Comprehensive Income [Abstract]
Net income (loss)	$ 108,735	$ 220,958
Other comprehensive activity:
Net hedge (gains) losses included in continuing operations	0	2,508
Income tax (benefit) provision	0	(928)
Other comprehensive activity	0	1,580
Comprehensive income (loss)	108,735	222,538
Comprehensive (income) loss attributable to the noncontrolling interests	(8,072)	(6,339)
Comprehensive income (loss) attributable to common stockholders	$ 100,663	$ 216,199

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Basis Of Presentation

3 Months Ended

Mar. 31, 2013

Basis Of Presentation [Abstract]

Basis Of Presentation

Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of March 31, 2013 and for the three months ended March 31, 2013 and 2012 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, 2012.

Certain reclassifications have been made to the 2012 financial statement and footnote amounts in order to conform to the 2013 presentation.

Issuance of common stock. In February 2013, the Company issued 10.35 million shares of its common stock and realized $1.3 billion of proceeds, net of associated underwriting and offering expenses.

Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest"). The Company owns and controls Pioneer Natural Resources GP LLC (the "General Partner"), which manages Pioneer Southwest. Pioneer Southwest owns interests in certain oil and gas properties in the Spraberry field in the Permian Basin of West Texas. The financial position, results of operations and cash flows of Pioneer Southwest are consolidated with those of the Company. Noncontrolling interests in consolidated subsidiaries includes $163.9 million attributable to outstanding Pioneer Southwest common units held by unitholders other than Pioneer or its subsidiaries as of March 31, 2013.

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Exploratory Costs (Tables)

3 Months Ended

Mar. 31, 2013

Exploratory Cost Disclosure [Abstract]

Capitalized exploratory well and project activity

The following table reflects the Company's capitalized exploratory well and project activity during the three months ended March 31, 2013:

	Three Months Ended March 31, 2013
	(in thousands)
Beginning capitalized exploratory costs	$	212,670
Additions to exploratory costs pending the determination of proved reserves	351,575
Reclassification due to determination of proved reserves	(262,754		)
Exploratory well costs charged to exploration expense	(7,734		)
Ending capitalized exploratory costs	$	293,757

Aging of capitalized exploratory costs and the number of projects for which exploratory costs have been capitalized

The following table provides an aging, as of March 31, 2013 and December 31, 2012, 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:

	March 31, 2013		December 31, 2012
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	174,841	$	190,678
More than one year	118,916		21,992
	$	293,757	$	212,670
Number of projects with exploratory costs that have been suspended for a period greater than one year	2		1

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Derivative Financial Instruments (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	May 08, 2013 NGL contract, in BBLS [Member] May through December Two Thousand Thirteen Collar Contracts [Member] bbl	May 08, 2013 NGL contract, in BBLS [Member] July through December Two Thousand Thirteen Collar Contracts [Member] bbl	May 08, 2013 NGL contract, in BBLS [Member] Two Thousand Fourteen Collar Contracts [Member] bbl	May 08, 2013 NGL contracts, price per BBL [Member] May through December Two Thousand Thirteen Collar Contracts [Member]	May 08, 2013 NGL contracts, price per BBL [Member] July through December Two Thousand Thirteen Collar Contracts [Member]	May 08, 2013 NGL contracts, price per BBL [Member] Two Thousand Fourteen Collar Contracts [Member]
Schedule of Trading Securities and Other Trading Assets [Line Items]
Average Daily NGL Production Derivative Barrels Per Day		2,000	500	3,000
Derivative, Average Cap Price					12.60	13.02	13.72
Derivative, Average Floor Price					10.50	10.50	10.78
Derivative, Fixed Interest Rate	3.21%
Notional amount of debt	$ 250

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Other Expense

3 Months Ended

Mar. 31, 2013

Other Expense [Abstract]

Other Expense

Other Expense

The following table provides the components of the Company's other expense for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013		2012
	(in thousands)
Transportation commitment charge (a)	$	9,377	$	8,453
Other	4,565		2,911
Above market and idle drilling and well services equipment rates (b)	3,507		4,986
Inventory impairment (c)	1,587		6,041
Contingency and environmental accrual adjustments	1,294		1,216
Terminated drilling rig contract charges (d)	1,019		—
Total other expense	$	21,349	$	23,607

 ____________________

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

(b) Primarily represents expenses attributable to the portion of Pioneer's contracted drilling rig rates that are above current market rates and idle drilling rig fees, neither of which are charged to joint operations.

(c) Represents valuation charges on excess materials and supplies inventories.

(d) Primarily represents charges to terminate a drilling rig contract that is not required to meet planned activities.