10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2012

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)

Registrant's telephone number, including area code: (972) 444-9001

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

Title of each class	Name of each exchange on which registered
Common Stock, par value $.01	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ý    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  ý

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.¨

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

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter	$	10,710,105,448
Number of shares of Common Stock outstanding as of February 8, 2013	123,360,341

DOCUMENTS INCORPORATED BY REFERENCE:

(1) Portions of the Definitive Proxy Statement for the Company's 2013 Annual Meeting of Shareholders to be held during May 2013 are incorporated into Part III of this report.

TABLE OF CONTENTS

		Page
Definitions of Certain Terms and Conventions Used Herein		4
Cautionary Statement Concerning Forward-Looking Statements		5
PART I
Item 1.	Business	6
	General	6
	Available Information	6
	Mission and Strategies	6
	Business Activities	6
	Marketing of Production	9
	Competition, Markets and Regulations	9
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	30
	Reserve Estimation Procedures and Audits	30
	Proved Reserves	33
	Description of Properties	33
	Selected Oil and Gas Information	37
Item 3.	Legal Proceedings	43
Item 4.	Mine Safety Disclosures	43
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	44
	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	44
Item 6.	Selected Financial Data	45
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	47
	Financial and Operating Performance	47
	First Quarter 2013 Outlook	48
	2013 Capital Budget	48
	Acquisitions	49
	Divestitures and Discontinued Operations	49
	Results of Operations	50
	Capital Commitments, Capital Resources and Liquidity	57
	Critical Accounting Estimates	61
	New Accounting Pronouncements	63
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	64
	Quantitative Disclosures	64
	Qualitative Disclosures	68
Item 8.	Financial Statements and Supplementary Data	69
	Index to Consolidated Financial Statements	69
	Report of Independent Registered Public Accounting Firm	70
	Consolidated Financial Statements	71
	Notes to Consolidated Financial Statements	78
	Unaudited Supplementary Information	113
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	122
Item 9A.	Controls and Procedures	122
	Management's Report on Internal Control Over Financial Reporting	122
	Report of Independent Registered Public Accounting Firm	123
Item 9B.	Other Information	124

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TABLE OF CONTENTS

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	124
Item 11.	Executive Compensation	124
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	124
	Securities Authorized for Issuance Under Equity Compensation Plans	124
Item 13.	Certain Relationships and Related Transactions, and Director Independence	125
Item 14.	Principal Accounting Fees and Services	125
PART IV
Item 15.	Exhibits, Financial Statement Schedules	125
Signatures		132
Exhibit Index		133

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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.

• "BCF" means one billion cubic feet.

• "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 6.0 MCF of gas to 1.0 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.

• "CBM" means coal bed methane.

• "Conway-posted price" means the daily average natural gas liquids components as priced in Oil Price Information Services in the table "U.S. and Canada LP – Gas Weekly Averages" at Conway, Kansas.

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

• "field fuel" means gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point.

• "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.

• "MBBL" means one thousand BBLs.

• "MBOE" means one thousand BOEs.

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

• "MMBBL" means one million BBLs.

• "MMBOE" means one million BOEs.

• "MMBTU" means one million BTUs.

• "MMCF" means one million cubic feet.

• "Mont Belvieu-posted price" means the daily average natural gas liquids components as priced in Oil Price Information Service 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.

• "NYSE" means the New York Stock 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 geosciences 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 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 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,

4

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.

• "SEC" means the United States Securities and Exchange Commission.

• "Standardized Measure" means the after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs employed in the determination of proved reserves and a ten percent discount rate.

• "U.S." means United States.

• "VPP" means volumetric production payment.

• "WTI" means a light, sweet blend of oil produced from fields in western Texas.

• 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.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this "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 the Company are intended to identify forward-looking statements, which are generally not historical in nature. 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. 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 from the anticipated results described in the forward-looking statements. See "Item 1. Business — Competition, Markets and Regulations," "Item 1A. Risk Factors," "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.

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PIONEER NATURAL RESOURCES COMPANY

PART I

ITEM 1. BUSINESS

General

The Company is a large independent oil and gas exploration and production company with operations in the United States. Pioneer is a holding company whose assets consist of direct and indirect ownership interests in, and whose business is conducted substantially through, its subsidiaries. Pioneer's common stock is listed and traded on the NYSE.

The Company is a Delaware corporation formed in 1997. The Company's executive offices are located at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039. The Company's telephone number is (972) 444-9001. The Company maintains other offices in Anchorage, Alaska; Denver, Colorado and Midland, Texas. At December 31, 2012, the Company had 3,667 employees, 2,484 of whom were employed in field and plant operations.

Available Information

Pioneer files or furnishes annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934 (the "Exchange Act"). The public may read and copy any materials that Pioneer files with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including Pioneer, that file electronically with the SEC. The public can obtain any documents that Pioneer files with the SEC at http://www.sec.gov.

The Company also makes available free of charge through its internet website (www.pxd.com) its Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after it electronically files such material with, or furnishes it to, the SEC.

Mission and Strategies

The Company's mission is to enhance shareholder investment returns through strategies that maximize Pioneer's long-term profitability and net asset value. The strategies employed to achieve this mission are predicated on maintaining financial flexibility, capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions. These strategies are anchored by the Company's interests in the long-lived Spraberry oil field; the liquid-rich Eagle Ford Shale, Barnett Shale Combo, Hugoton and West Panhandle fields; and the Raton gas field; which together have an estimated remaining productive life in excess of 40 years. Underlying these fields are 94 percent of the Company's proved oil and gas reserves as of December 31, 2012.

Business Activities

The Company is an independent oil and gas exploration and production company. Pioneer's purpose is to competitively and profitably explore for, develop and produce oil and gas reserves. In so doing, the Company sells homogenous oil, NGL and gas units that, except for geographic and relatively minor quality differences, cannot be significantly differentiated from units offered for sale by the Company's competitors. Competitive advantage is gained in the oil and gas exploration and development industry by employing well-trained and experienced personnel who make prudent capital investment decisions based on management direction, embrace technological innovation and are focused on price and cost management.

Petroleum industry. While oil and NGL prices generally improved from 2009 through 2011, during 2012, oil and NGL production growth in the United States outpaced demand growth causing prices to become more volatile and decline during the year. North American gas prices have remained volatile and have generally trended lower since 2009. The decline in North American gas prices is primarily a result of growing gas supplies associated with discoveries of significant gas reserves in United States shale plays, combined with the warmer than normal recent winters, which has resulted in gas storage levels being at historically high levels, and minimal economic demand growth in the United States. Oil prices continue to be primarily driven by world supply and demand fundamentals; however, recent increases in United States oil, NGL and gas production volumes from the Permian Basin, Eagle Ford, Bakken and Marcellus areas have been met with lower demand, higher storage levels and pipeline, gas plant and NGL fractionation infrastructure capacity limitations, which has led to a reduction in United States NYMEX oil, NGL and gas prices compared to international prices for similar commodities, including Brent oil prices.

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PIONEER NATURAL RESOURCES COMPANY

During 2010, 2011 and 2012, the economies in the United States and certain other countries stabilized with resulting improvements in industrial demand and consumer confidence. However, other economies, such as those of certain European and Asian nations, continue to face economic struggles or slowing economic growth. While the outlook for a continued worldwide economic recovery remains cautiously optimistic, it is still uncertain; therefore, the sustainability of the recovery in worldwide demand for energy is difficult to predict. As a result, the Company believes it is likely that commodity prices will continue to be volatile during 2013.

Significant factors that will affect 2013 commodity prices include: the ongoing effect of economic stimulus initiatives; fiscal challenges facing the United States federal government and potential changes to the tax laws in the United States; continuing economic struggles in European and Asian nations; political and economic developments in North Africa and the Middle East; demand from Asian and European markets; the extent to which members of the Organization of Petroleum Exporting Countries ("OPEC") and other oil exporting nations are able to manage oil supply through export quotas; and overall North American NGL and gas supply and demand fundamentals.

Pioneer uses commodity derivative contracts to mitigate the effect of commodity price volatility on the Company's net cash provided by operating activities and its net asset value. Although the Company has entered into commodity derivative contracts for a large portion of its forecasted production through 2014, a sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Company could enter into derivative contracts on additional volumes in the future. As a result, the Company's internal cash flows would be reduced for affected periods. A sustained decline in commodity prices could result in a shortfall in expected cash flows, which could negatively affect the Company's liquidity, financial position and future results of operations. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's open derivative positions as of December 31, 2012.

The Company. The Company's growth plan is anchored primarily by drilling in the Spraberry oil field located in West Texas, the liquid-rich Eagle Ford Shale field located in South Texas, the liquid-rich Barnett Shale Combo field in North Texas and, to a lesser extent, Alaska. Complementing these growth areas, the Company has oil and gas production activities and development opportunities in the Raton gas field located in southern Colorado, the Hugoton gas and liquid field located in southwest Kansas, the West Panhandle gas and liquid field located in the Texas Panhandle and the Edwards gas field located in South Texas. Combined, these assets create a portfolio of resources and opportunities that are well balanced among oil, NGL and gas, and that are also well balanced among long-lived, dependable production and lower-risk exploration and development opportunities. The Company has a team of dedicated employees who represent the professional disciplines and sciences that the Company believes are necessary to allow Pioneer to maximize the long-term profitability and net asset value inherent in its physical assets.

The Company provides administrative, financial, legal and management support to subsidiaries that explore for, develop and produce proved reserves. The Company's continuing operations are located in the United States, principally in the states of Texas, Kansas, Colorado and Alaska.

Production. The Company focuses its efforts towards maximizing its average daily production of oil, NGLs and gas through development drilling, production enhancement activities and acquisitions of producing properties, while minimizing the controllable costs associated with the production activities. For the year ended December 31, 2012, the Company's production from continuing operations of 56.9 MMBOE, excluding field fuel usage, represented a 29 percent increase over production from continuing operations during 2011. Production, price and cost information with respect to the Company's properties for 2012, 2011 and 2010 is set forth in "Item 2. Properties — Selected Oil and Gas Information — Production, price and cost data."

Development activities. The Company seeks to increase its oil and gas reserves, production and cash flow through development drilling and by conducting other production enhancement activities, such as well recompletions. During the three years ended December 31, 2012, the Company drilled 1,844 gross (1,655 net) development wells, 99 percent of which were successfully completed as productive wells, at a total drilling cost (net to the Company's interest) of $4.0 billion.

The Company believes that its current property base provides a substantial inventory of prospects for future reserve, production and cash flow growth. The Company's proved reserves as of December 31, 2012 include proved undeveloped reserves and proved developed reserves that are behind pipe of 271.4 MMBBLs of oil, 103.0 MMBBLs of NGLs and 714.6 Bcf of gas. The Company believes that its current portfolio of proved reserves provides attractive development opportunities for at least the next five years. The timing of the development of these reserves will be dependent upon commodity prices, drilling and operating costs and the Company's expected operating cash flows and financial condition.

Exploratory activities. The Company has devoted significant efforts and resources to hiring and developing a highly skilled geoscience staff as well as acquiring a significant portfolio of lower-risk exploration opportunities that are expected to be evaluated and tested over the next decade and beyond. Exploratory and extension drilling involve greater risks of dry holes or failure to find

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PIONEER NATURAL RESOURCES COMPANY

commercial quantities of hydrocarbons than development drilling or enhanced recovery activities. See "Item 1A. Risk Factors — Exploration and development drilling may not result in commercially productive reserves" below.

Integrated services. The Company continues to expand its integrated services to control drilling and operating costs and support the execution of its drilling program and operating activities. The Company has 15 owned vertical drilling rigs operating in the Spraberry field, and at the end of 2012, had Company-owned fracture stimulation fleets totaling 300,000 horsepower supporting drilling operations in the Spraberry, Eagle Ford Shale and Barnett Shale Combo areas. During April 2012, the Company acquired 100 percent of the share capital of Industrial Sands Holding Company and its wholly-owned subsidiary, Oglebay Norton Industry Sands, LLC, for an aggregate purchase price of $297.1 million. The Company changed the name of the Oglebay Norton Industrial Sands LLC to Premier Silica LLC ("Premier Silica") in April 2012. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the acquisition of Premier Silica. 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.

Acquisition activities. The Company regularly seeks to acquire properties that complement its operations, provide exploration and development opportunities and potentially provide superior returns on investment. In addition, the Company pursues strategic acquisitions that will allow the Company to expand into new geographical areas that provide future exploration/exploitation opportunities. During 2012, 2011 and 2010, the Company spent $157.5 million, $131.9 million and $181.6 million, respectively, to purchase primarily undeveloped acreage for future exploitation and exploration activities.

The Company periodically evaluates and pursues acquisition opportunities (including opportunities to acquire particular oil and gas assets or entities owning oil and gas assets and opportunities to engage in mergers, consolidations or other business combinations with such entities) and at any given time may be in various stages of evaluating such opportunities. Such stages may take the form of internal financial analyses, oil and gas reserve analyses, due diligence, the submission of indications of interest, preliminary negotiations, negotiation of letters of intent or negotiation of definitive agreements. The success of any acquisition is uncertain and depends on a number of factors, some of which are outside the Company's control. See "Item 1A. Risk Factors — The Company may be unable to make attractive acquisitions and any acquisition it completes is subject to substantial risks that could adversely affect its business."

Asset divestitures and discontinued operations. The Company regularly reviews its asset base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. While the Company generally does not dispose of assets solely for the purpose of reducing debt, such dispositions can have the result of furthering the Company's objective of increasing financial flexibility through reduced debt levels.

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 for consideration of $1.7 billion. At closing, Sinochem will pay $522.0 million in cash to Pioneer, 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 and third party approvals.

During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest its net assets in South Africa ("Pioneer South Africa"). During the first quarter of 2012, the Company agreed to sell 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 pretax gain of $28.6 million. The Company classified (i) Pioneer South Africa's assets and liabilities as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2011 and (ii) Pioneer South Africa's results of operations as income from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

In February 2011, the Company sold 100 percent of the Company's share holdings in Pioneer Natural Resources Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as "Pioneer Tunisia") to an unaffiliated third party for cash proceeds of $802.5 million, excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million. Accordingly, the Company has classified the results of operations of Pioneer Tunisia, prior to its sale, as discontinued operations, net of tax, in the accompanying consolidated statements of operations.

The Company anticipates that it will continue to sell nonstrategic properties or other assets from time to time to increase capital resources available for other activities, to achieve operating and administrative efficiencies and to improve profitability.

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PIONEER NATURAL RESOURCES COMPANY

See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for specific information regarding the Company's asset divestitures and discontinued operations, including the 2011 sale of Pioneer Tunisia and 2012 sale of Pioneer South Africa.

Marketing of Production

General. Production from the Company's properties is marketed using methods that are consistent with industry practices. Sales prices for oil, NGL and gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for additional discussion of operations and price risk.

Significant purchasers. During 2012, the Company's significant purchasers of oil, NGLs and gas were Plains Marketing LP (26 percent), Enterprise Products Partners L.P. (15 percent) and Occidental Energy Marketing Inc. (14 percent). The Company believes that the loss of a significant purchaser or an inability to secure adequate pipeline, gas plant and NGL fractionation infrastructure in its key producing areas could have a material adverse effect on its ability to sell its oil, NGL and gas production. See "Item 1A. Risk Factors" and Note L of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about significant customer and infrastructure capacity risks.

Derivative risk management activities. 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 utilizes commodity swap contracts to reduce price volatility on the fuel that the Company's drilling rigs and fracture stimulation fleets consume. The Company accounts for its derivative contracts using the mark-to-market ("MTM") method of accounting. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a description of the Company's derivative risk management activities, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk," and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information about the impact of commodity derivative activities on oil, NGL and gas revenues and net derivative gains and losses during 2012, 2011 and 2010, as well as the Company's open commodity derivative positions at December 31, 2012.

Competition, Markets and Regulations

Competition. The oil and gas industry is highly competitive. A large number of companies, including major integrated and other independent companies, and individuals engage in the exploration for and development of oil and gas properties, and there is a high degree of competition for oil and gas properties suitable for development or exploration. Acquisitions of oil and gas properties have been an important element of the Company's growth. The Company intends to continue acquiring oil and gas properties that complement its operations, provide exploration and development opportunities and potentially provide superior returns on investment. The principal competitive factors in the acquisition of oil and gas properties include the staff and data necessary to identify, evaluate and acquire such properties and the financial resources necessary to acquire and develop the properties. Many of the Company's competitors are substantially larger and have financial and other resources greater than those of the Company.

Markets. The Company's ability to produce and market oil, NGLs and gas profitably depends on numerous factors beyond the Company's control. The effect of these factors cannot be accurately predicted or anticipated. Although the Company cannot predict the occurrence of events that may affect these commodity prices or the degree to which these prices will be affected, the prices for any commodity that the Company produces will generally approximate current market prices in the geographic region of the production.

Securities regulations. Enterprises that sell securities in public markets are subject to regulatory oversight by agencies such as the SEC and the NYSE. This regulatory oversight imposes on the Company the responsibility for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting, and ensuring that the financial statements and other information included in submissions to the SEC do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made in such submissions not misleading. Failure to comply with the rules and regulations of the SEC could subject the Company to litigation from public or private plaintiffs. Failure to comply with the rules of the NYSE could result in the de-listing of the Company's common stock, which would have an adverse effect on the market price and liquidity of the Company's common stock. Compliance with some of these rules and regulations is costly, and regulations are subject to change or reinterpretation.

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PIONEER NATURAL RESOURCES COMPANY

Environmental and occupational health and safety matters. The Company's operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, worker health and safety, and the discharge of materials into the environment. These laws and regulations may, among other things:

• require the acquisition of various permits before drilling or other regulated activity commences;

• enjoin some or all of the operations of facilities deemed in noncompliance with permits;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, production and transportation activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

• impose specific criteria addressing worker protection; and

• require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the U.S. Congress, state legislatures and federal and state regulatory agencies frequently revise environmental laws and regulations, and the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant effect on the Company's operating costs.

The Company believes it is in substantial compliance with all existing environmental laws and regulations applicable to the Company's current operations and that its continued compliance with existing requirements will not have a material adverse effect on the Company's financial condition and results of operations. For example, the Company did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2012. Additionally, the Company is not aware of any environmental issues or claims that will require material capital expenditures during 2013. Nevertheless, accidental spills or releases may occur in the course of the Company's operations, and the Company cannot give any assurance that it will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, the Company cannot give any assurance that the passage of more stringent laws or regulations in the future will not have a negative effect on the Company's business, financial condition and results of operations.

The following is a summary of some of the more significant laws and regulations to which the Company's business operations are or may be subject.

Waste handling. The federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (the "EPA"), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil or gas are currently regulated under RCRA's non-hazardous waste provisions. It is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in the Company's costs to manage and dispose of wastes, which could have a material adverse effect on the Company's results of operations and financial position. Also, in the course of the Company's operations, it generates some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.

Wastes containing naturally occurring radioactive materials ("NORM") may also be generated in connection with the Company's operations. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration ("OSHA"). These state and OSHA regulations impose certain requirements concerning worker protection; the treatment, storage and disposal of NORM waste; the management of waste piles, containers and tanks containing NORM; as well as restrictions on the uses of land with NORM contamination.

Comprehensive Environmental Response, Compensation, and Liability Act. The federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the Superfund law, and analogous state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

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PIONEER NATURAL RESOURCES COMPANY

The Company currently owns or leases numerous properties that have been used for oil and gas exploration and production for many years. Although the Company believes it has used operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on or under the properties owned or leased by the Company, or on or under other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of the Company's properties have been operated by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were not under the Company's control. Certain of these properties have had historical petroleum spills or releases. All of such properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination. If a surface spill or release were to occur, the Company expects that it would be controlled, contained and remediated in accordance with the applicable requirements of state oil and gas commissions and by using the Company's spill prevention, control and countermeasure ("SPCC") plans or other spill or emergency contingency plans that it maintains in accordance with EPA requirements.

Water discharges and use. The federal Clean Water Act (the "CWA") and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. SPCC planning requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The primary federal law imposing liability for oil spills is the Oil Pollution Act ("OPA"), which sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil spill cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. If an oil spill subject to the requirements of OPA were to occur at a Company property, the Company expects that it would be controlled, contained and remediated in accordance with the applicable requirements of OPA and by using the Company's OPA spill response plan together with the assistance of trained first responders and any oil spill response contractor that the Company would have been required to engage pursuant to OPA to address such oil spills.

Operations associated with the Company's properties also produce wastewaters that are disposed via injection in underground wells. These injection wells are regulated by the Safe Drinking Water Act (the "SDWA") and analogous state and local laws. The underground injection well program under the SDWA requires permits from the EPA or analogous state agency for the Company's disposal wells, establishes minimum standards for injection well operations, and restricts the types and quantities of fluids that may be injected. Currently, the Company believes that disposal well operations on the Company's properties comply with all applicable requirements under the SDWA. However, a change in the regulations or the inability to obtain permits for new injection wells in the future may affect the Company's ability to dispose of produced waters and ultimately increase the cost of the Company's operations. In addition, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. The U.S. Geological Survey is advising the EPA regarding potential seismic hazards associated with these types of underground injection wells. It is possible that federal or state agencies will seek to regulate more stringently the underground injection of oil and gas wastewaters as a result of these events. Nevertheless, the Company is not aware of any imminent actions by federal or state agencies that would affect its use or operation of underground injection wells.

The Company also routinely uses hydraulic fracturing techniques in the majority of its drilling and completion programs in Texas, Colorado and elsewhere, where development of most of the Company's properties are dependent on the Company's ability to hydraulically fracture the producing formations. The process involves the injection of water, sand and additives under pressure into targeted subsurface formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions; however, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the SDWA Underground Injection Control Program and has published draft permitting guidance in May 2012 addressing the performance of such activities. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and the agency currently projects to issue an Advance Notice of Proposed Rulemaking in May 2013 that would seek public input on the design and scope of such disclosure regulations. In August 2012, the EPA published final rules under the federal Clean Air Act ("CAA"), which became effective October 15, 2012, that, among other things, require producers to reduce volatile organic

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PIONEER NATURAL RESOURCES COMPANY

compound emissions from certain subcategories of fractured and refractured gas wells for which well completion operations are being conducted by routing flowback emissions to a gathering line or capturing and combusting flowback emissions using a combustion device, such as a flare, until January 1, 2015 or performing reduced emission completions, also known as "green completions," with or without combustion devices, on or after January 1, 2015. In addition, the U.S. Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that new federal restrictions relating to the hydraulic-fracturing process are adopted in areas where the Company currently operates or in the future plans to operate, the Company may incur additional costs to comply with such federal requirements that may be significant in nature, become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development or production activities.

Certain states in which the Company operates, including Colorado and Texas, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (the "TRRC") and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. The Company believes that it follows applicable standard industry practices and legal requirements for groundwater protection in its hydraulic fracturing activities. Nonetheless, in the event state or local restrictions are adopted in areas where the Company is currently conducting, or in the future plans to conduct operations, the Company may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development or production activities, and be limited or precluded in the drilling of wells or in the amounts that the Company is ultimately able to produce from its reserves.

Certain governmental reviews were recently conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report released by the agency on December 21, 2012 and a final report expected to be available for public comments and peer review by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These studies, or future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

The water produced by the Company's CBM operations also may be subject to the laws of various states and regulatory bodies regarding the ownership and use of water. For example, in connection with the Company's CBM operations in the Raton Basin in Colorado, water is removed from coal seams to reduce pressure and allow the methane to be recovered. Historically, these operations have been regulated by the state agency responsible for regulating oil and gas activity in the state. In a 2008 case brought by the owners of ranch land involving a CBM competitor in a different CBM basin in Colorado, the Colorado Supreme Court held that water produced in connection with the CBM operations should be subject to state water-use regulations administered by a different agency that regulates other uses of water in the state, including requirements to obtain permits for diversion and use of surface and subsurface water, an evaluation of potential competing uses of the water, and a possible requirement to provide mitigation water for other water users. The Colorado legislature and state agency adopted laws and regulations in response to this ruling, but there continue to be litigation and uncertainty regarding permitting of produced water withdrawn in connection with CBM activities. The Company's CBM or other oil and gas operations and the Company's ability to expand its operations could be adversely affected, and these changes in regulation could ultimately increase the Company's cost of doing business.

Air emissions. The CAA and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions; obtain or strictly comply with air permits containing various emissions and operational limitations; or utilize specific emission control technologies to limit emissions of certain air pollutants. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Moreover, states can impose air emissions limitations that are more stringent than the federal standards imposed by the EPA. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for noncompliance with air permits or other requirements of the CAA and associated state laws and regulations.

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require the Company to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies for gas and oil exploration and production operations. On August 16, 2012, the EPA published final rules under the CAA that subject oil and gas production, processing,

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PIONEER NATURAL RESOURCES COMPANY

transmission and storage operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all "other" fractured and refractured gas wells. All three subcategories of wells must route flowback emissions to a gathering line or capture and combust flowback emissions using a combustion device, such as a flare, after October 15, 2012. However, the "other" wells must use reduced emission completions, also known as "green completions, " with or without combustion devices, on or after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012 and from pneumatic controllers and storage vessels, effective October 15, 2013. The Company is currently reviewing this new rule and assessing its potential effects on its operations. Compliance with these requirements could increase the Company's costs of development and production, which costs could be significant.

In addition, in response to reported concerns about high concentrations of benzene in the air near certain drilling sites and gas processing facilities in the Barnett Shale area, the Texas Commission on Environmental Quality (the "TCEQ") adopted new air emissions limitations and permitting requirements for oil and gas facilities in the state, which are applicable to facilities located in the Barnett Shale area. These new requirements could increase the cost and time associated with drilling wells in the Barnett Shale. The agency's investigations could lead to additional, more stringent air permitting requirements, increased regulation, and possible enforcement actions against producers, including Pioneer, in the Barnett Shale area. Any adoption of laws, regulations, orders or other legally enforceable mandates governing gas drilling and operating activities in the Barnett Shale or other areas of Texas that result in more stringent drilling or operating conditions or limit or prohibit the drilling of new wells for any extended period of time could increase the Company's costs or reduce its production, which could have a material adverse effect on the Company's results of operations and cash flows.

Some gas and oil production facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions.

Endangered species. The federal Endangered Species Act (the "ESA") and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of the Company's operations are conducted in areas where protected species or their habitats are known to exist. In these areas, the Company may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and the Company may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when the Company's operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where the Company performs activities could result in increased costs or limitations on the Company's ability to perform operations and thus have an adverse effect on the Company's business.

As a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA and issue decisions with respect to the 250 candidate species before completion of the agency's 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where the Company operates could cause the Company to incur increased costs arising from species protection measures or could result in limitations on the Company's exploration and production activities that could have an adverse effect on the Company's ability to develop and produce its proved reserves.

Occupational health and safety. The Company's operations are subject to the requirements of OSHA and comparable state statutes. These laws and the related regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statues require that the Company organize or disclose information about hazardous materials used or produced in the Company's operations. In addition, the Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment and other matters. The Company believes that it is in substantial compliance with these applicable standards and with OSHA and comparable requirements.

Global warming and climate change. In December 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other "greenhouse gases" ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under the CAA in 2010 establishing Title V and Prevention of Significant Deterioration permitting requirements for large sources of GHGs. The Company could become subject to these permitting

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PIONEER NATURAL RESOURCES COMPANY

requirements and be required to install "best available control technology" to limit emissions of GHGs from any new or significantly modified facilities that the Company may seek to construct in the future if they would otherwise emit large volumes of GHGs. The EPA has also adopted rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the United States, including certain oil and gas production facilities, which includes certain of the Company's facilities. The Company is monitoring GHG emissions from its operations in accordance with these GHG emissions reporting rules and believes its monitoring activities are in substantial compliance with applicable reporting obligations.

While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If the U.S. Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on the Company's operations.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would affect the Company's business, any such future laws and regulations could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements including the imposition of a carbon tax. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Company's business, financial condition and results of operations.

Some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Company's financial condition and results of operations.

Other regulation of the oil and gas industry. The oil and gas industry is regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous federal and state departments and agencies are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry may increase the Company's cost of doing business by increasing the cost of production, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Development and production. Development and production operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, the posting of bonds in connection with various types of activities and filing reports concerning operations. Most states, and some counties and municipalities, in which the Company operates also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the method and ability to fracture stimulate wells;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells; and

• notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company's interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas the Company can produce from the Company's wells or limit the number of wells or the locations at which the Company can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGL and gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from the Company's wells, negatively affect the economics of production from these wells, or limit the number of locations the Company can drill.

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PIONEER NATURAL RESOURCES COMPANY

Regulation of transportation and sale of gas. The availability, terms and cost of transportation significantly affect sales of gas. Federal and state regulations govern the price and terms for access to gas pipeline transportation. Intrastate gas pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies. The interstate transportation and sale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission ("FERC"). FERC endeavors to make gas transportation more accessible to gas buyers and sellers on an open-access and non-discriminatory basis.

Pursuant to the Energy Policy Act of 2005 ("EPAct 2005") it is unlawful for "any entity," including producers such as the Company, that are otherwise not subject to FERC's jurisdiction under the Natural Gas Act (the "NGA") to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. FERC's rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives FERC authority to impose civil penalties up to $1.0 million per day per violation of the NGA and the Natural Gas Policy Act of 1978. The anti-manipulation rule applies to activities of entities not otherwise subject to FERC's jurisdiction to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order 704 (defined below).

In December 2007, FERC issued a final rule on the annual gas transaction reporting requirements, as amended by subsequent orders on rehearing ("Order 704"). Under Order 704, any market participant, including a producer such as the Company, that engages in wholesale sales or purchases of gas that equal or exceed 2.2 million MMBTUs of physical gas in the previous calendar year must annually report such sales and purchases to FERC on Form No. 552 on May 1 of each year. Form No. 552 contains aggregate volumes of gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 is intended to increase the transparency of the wholesale gas markets and to assist FERC in monitoring those markets and in detecting market manipulation.

Additional proposals and proceedings that might affect the gas industry are considered from time to time by the U.S. Congress, FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might become effective or their effect, if any, on its operations. The Company does not believe that it will be affected by any action taken in a materially different way than other gas producers, gatherers and marketers with which it competes.

Gas gathering. Section 1(b) of the NGA exempts gas gathering facilities from FERC's jurisdiction. The Company believes that its gathering facilities meet the traditional tests FERC has used to establish a pipeline system's status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so the classification and regulation of some of the Company's gathering facilities may be subject to change based on future determinations by FERC and the courts. Thus, the Company cannot guarantee that the jurisdictional status of its gas gathering facilities will remain unchanged.

While the Company owns or operates some gas gathering facilities, the Company also depends on gathering facilities owned and operated by third parties to gather production from its properties, and therefore the Company is affected by the rates charged by these third parties for gathering services. To the extent that changes in federal or state regulation affect the rates charged for gathering services, the Company also may be affected by these changes. Accordingly, the Company does not anticipate that the Company would be affected any differently than similarly situated gas producers.

Regulation of transportation and sale of oil and NGLs. The liquids industry is also extensively regulated by numerous federal, state and local authorities. In a number of instances, the ability to transport and sell such products on interstate pipelines is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act (the "ICA"). The Company does not believe these regulations affect it any differently than other producers.

The ICA requires that pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be "just and reasonable." Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.

Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-

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PIONEER NATURAL RESOURCES COMPANY

year period beginning in 2010, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 2.65 percent. This adjustment is subject to review every five years. Under FERC's regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. Increases in liquids transportation rates may result in lower revenue and cash flows for the Company.

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to the Company. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that the Company relies upon for liquids transportation could have a material adverse effect on its business, financial condition, results of operations and cash flows. However, the Company believes that access to liquids pipeline transportation services generally will be available to it to the same extent as to its similarly-situated competitors.

Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. The Company believes that the regulation of liquids pipeline transportation rates will not affect its operations in any way that is materially different from the effects on its similarly-situated competitors.

In November 2009, the Federal Trade Commission ("FTC") issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1.0 million per violation per day. In July 2010, the U.S. Congress passed the Dodd-Frank Wall Street Reform and Consumer Protection Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission ("CFTC") to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FERC and the FTC as described above. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1.0 million or triple the monetary gain to the person for each violation.

Energy commodity prices. Sales prices of gas, oil, condensate and NGLs are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, the U.S. Congress historically has been active in their regulation. The Company cannot predict whether new legislation to regulate oil and gas, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures and what effect, if any, the proposals might have on the Company's operations.

Transportation of hazardous materials. The federal Department of Transportation has adopted regulations requiring that certain entities transporting designated hazardous materials develop plans to address security risks related to the transportation of hazardous materials. The Company does not believe that these requirements will have an adverse effect on the Company or its operations. The Company cannot provide any assurance that the security plans required under these regulations would protect against all security risks and prevent an attack or other incident related to the Company's transportation of hazardous materials.

ITEM 1A. RISK FACTORS

The nature of the business activities conducted by the Company subjects it to certain hazards and risks. The following is a summary of some of the material risks relating to the Company's business activities. Other risks are described in "Item 1. Business — Competition, Markets and Regulations" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk." These risks are not the only risks facing the Company. The Company's business could also be affected by additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial. If any of these risks actually occurs, it could materially harm the Company's business, financial condition or results of operations and impair the Company's ability to implement business plans or complete development activities as scheduled. In that case, the market price of the Company's common stock could decline.

The prices of oil, NGL and gas are highly volatile. A sustained decline in these commodity prices could adversely affect the Company's financial condition and results of operations.

The Company's revenues, profitability, cash flow and future rate of growth are highly dependent on commodity prices. Commodity prices may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, NGL and gas, market uncertainty and a variety of additional factors that are beyond the Company's control, such as:

• domestic and worldwide supply of and demand for oil, NGL and gas;

• inventory levels at Cushing, Oklahoma, the benchmark for WTI oil prices;

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PIONEER NATURAL RESOURCES COMPANY

• gas inventory levels in the United States;

• weather conditions;

• overall domestic and global political and economic conditions;

• actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;

• the effect of liquefied natural gas deliveries to and exports from the United States;

• technological advances affecting energy consumption and energy supply;

• domestic and foreign governmental regulations and taxation;

• the effect of energy conservation efforts;

• the proximity, capacity, cost and availability of pipelines and other transportation facilities; and

• the price and availability of alternative fuels.

In the past, commodity prices have been extremely volatile, and the Company expects this volatility to continue. For example, during 2012, oil prices fluctuated from a high of $109.77 per BBL in February to a low of $77.69 per BBL in June, while gas prices fluctuated from a low of $1.91 per MCF in April to a high of $3.90 per MCF in November. During 2011, oil prices fluctuated from a high $113.93 per BBL in April to a low of $75.67 per BBL in October, while gas prices fluctuated from a high of $4.85 per MCF in June to a low of $2.99 per MCF in December. The Company makes price assumptions that are used for planning purposes, and a significant portion of the Company's cash outlays, including rent, salaries and noncancellable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, the Company's financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.

Significant or extended price declines could also adversely affect the amount of oil, NGL and gas that the Company can produce economically. A reduction in production could result in a shortfall in expected cash flows and require the Company to reduce capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively affect the Company's ability to replace its production and its future rate of growth.

The Company could experience periods of higher costs if commodity prices rise. These increases could reduce the Company's profitability, cash flow and ability to complete development activities as planned.

Historically, the Company's capital and operating costs have risen during periods of increasing oil, NGL and gas prices. These cost increases result from a variety of factors beyond the Company's control, such as increases in the cost of electricity, steel and other raw materials that the Company and its vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Increased levels of drilling activity in the oil and gas industry in recent periods have led to increased costs of some drilling equipment, materials and supplies. Such costs may rise faster than increases in the Company's revenue, thereby negatively impacting the Company's profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that the Company's ability to participate in the commodity price increases is limited by its derivative risk management activities.

The Company's derivative risk management activities could result in financial losses.

To achieve more predictable cash flow and to manage the Company's exposure to fluctuations in the prices of oil, NGL and gas, the Company's strategy is to enter into derivative arrangements covering a portion of its oil, NGL and gas production. These derivative arrangements are subject to MTM accounting treatment, and the changes in fair market value of the contracts are reported in the Company's statements of operations each quarter, which may result in significant unrealized net gains or losses. These derivative contracts may also expose the Company to risk of financial loss in certain circumstances, including when:

• production is less than the contracted derivative volumes;

• the counterparty to the derivative contract defaults on its contract obligations; or

• the derivative contracts limit the benefit the Company would otherwise receive from increases in commodity prices.

On the other hand, failure to protect against declines in commodity prices exposes the Company to reduced liquidity when prices decline.

The failure by counterparties to the Company's derivative risk management activities to perform their obligations could have a material adverse effect on the Company's results of operations.

The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default on its obligations under the Company's derivative

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PIONEER NATURAL RESOURCES COMPANY

arrangements, such a default could have a material adverse effect on the Company's results of operations, and could result in a larger percentage of the Company's future production being subject to commodity price changes.

Exploration and development drilling may not result in commercially productive reserves.

Drilling involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain and drilling operations may be curtailed, delayed or canceled, or become costlier, as a result of a variety of factors, including:

• unexpected drilling conditions;

• unexpected pressure or irregularities in formations;

• equipment failures or accidents;

• fracture stimulation accidents or failures;

• adverse weather conditions;

• restricted access to land for drilling or laying pipelines; and

• access to, and the cost and availability of, the equipment, services and personnel required to complete the Company's drilling, completion and operating activities.

The Company's future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse effect on the Company's future results of operations and financial condition. While all drilling, whether developmental, extension or exploratory, involves these risks, exploratory and extension drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Company expects that it will continue to experience exploration and abandonment expense in 2013.

Future price declines could result in a reduction in the carrying value of the Company's proved oil and gas properties, which could adversely affect the Company's results of operations.

Declines in commodity prices may result in the Company having to make substantial downward adjustments to its estimated proved reserves. If this occurs, or if the Company's estimates of production or economic factors change, accounting rules may require the Company to impair, as a noncash charge to earnings, the carrying value of the Company's oil and gas properties. The Company is required to perform impairment tests on proved oil and gas properties whenever events or changes in circumstances indicate that the carrying value of proved properties may not be recoverable. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of the Company's oil and gas properties, the carrying value may not be recoverable and therefore an impairment charge would be required to reduce the carrying value of the proved properties to their fair value. For example, during 2012 and 2011, the Company recognized impairment charges of $532.6 million and $354.4 million, respectively, due to the impairment of the Company's Barnett Shale field and Edwards and Austin Chalk gas fields in South Texas, primarily due to declines in gas prices and downward adjustments to the economically recoverable resource potential. The Company may incur impairment charges in the future, which could materially affect the Company's results of operations in the period incurred.

The Company periodically evaluates its unproved oil and gas properties and could be required to recognize noncash charges in the earnings of future periods.

At December 31, 2012, the Company carried unproved property costs of $231.6 million. GAAP requires periodic evaluation of these costs on a project-by-project basis. These evaluations are affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of the leases, and contracts and permits appurtenant to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize noncash charges in the earnings of future periods.

The Company periodically evaluates its goodwill for impairment and could be required to recognize noncash charges in the earnings of future periods.

At December 31, 2012, the Company carried goodwill of $298.1 million. Goodwill is tested for impairment annually during the third quarter using a July 1 assessment date, and also whenever facts or circumstances indicate that the carrying value of the Company's goodwill may be impaired, requiring an estimate of the fair values of the reporting unit's assets and liabilities. Those assessments may be affected by (a) additional reserve adjustments both positive and negative, (b) results of drilling activities, (c) management's outlook for commodity prices and costs and expenses, (d) changes in the Company's market capitalization, (e) changes in the Company's weighted average cost of capital and (f) changes in income taxes. If the fair value of the reporting unit's net assets is not sufficient to fully support the goodwill balance in the future, the Company will reduce the carrying value

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PIONEER NATURAL RESOURCES COMPANY

of goodwill for the impaired value, with a corresponding noncash charge to earnings in the period in which goodwill is determined to be impaired.

The Company may be unable to make attractive acquisitions, and any acquisition it completes is subject to substantial risks that could adversely affect its business.

Acquisitions of producing oil and gas properties have from time to time contributed to the Company's growth. The Company's growth following the full development of its existing property base could be impeded if it is unable to acquire additional oil and gas reserves on a profitable basis. Acquisition opportunities in the oil and gas industry are very competitive, which can increase the cost of, or cause the Company to refrain from, completing acquisitions. The success of any acquisition will depend on a number of factors and involves potential risks, including among other things:

• the inability to estimate accurately the costs to develop the reserves, the recoverable volumes of reserves, rates of future production and future net cash flows attainable from the reserves;

• the assumption of unknown liabilities, losses or costs for which the Company is not indemnified or for which the indemnity the Company receives is inadequate;

• the validity of assumptions about costs, including synergies;

• the effect on the Company's liquidity or financial leverage of using available cash or debt to finance acquisitions;

• the diversion of management's attention from other business concerns; and

• an inability to hire, train or retain qualified personnel to manage and operate the Company's growing business and assets.

All of these factors affect whether an acquisition will ultimately generate cash flows sufficient to provide a suitable return on investment. Even though the Company performs a review of the properties it seeks to acquire that it believes is consistent with industry practices, such reviews are often limited in scope. As a result, among other risks, the Company's initial estimates of reserves may be subject to revision following an acquisition, which may materially and adversely affect the desired benefits of the acquisition.

The Company's ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond its control, and in certain cases the Company may be required to retain liabilities for certain matters.

From time to time, the Company sells an interest in a strategic asset for the purpose of assisting or accelerating the asset's development. In addition, the Company regularly reviews its property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect the ability of the Company to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties (as is the case with respect to the Company's southern Wolfcamp joint interest transaction) and the availability of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to the Company. For example, during the fourth quarter of 2012, the Company was unable to dispose of its Barnett Shale assets under acceptable terms. Consequently, the Company no longer expects to dispose of the Barnett Shale assets during 2013 and has reclassified the Barnett Shale assets to held for use and their historical results of operations to continuing operations. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information about the Barnett Shale disposition plans.

Sellers typically retain certain liabilities or indemnify buyers for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release the Company from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, the Company may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

The Company's gas processing operations are subject to operational risks, which could result in significant damages and the loss of revenue.

As of December 31, 2012, the Company owned interests in four gas processing plants and ten treating facilities. The Company is the operator of two of the gas processing plants and all ten of the treating facilities. There are significant risks associated with the operation of gas processing plants. Gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of a gas processing plant or facility could result in an explosion or the discharge of toxic gases, which could result in significant damage claims in addition to interrupting a revenue source.

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PIONEER NATURAL RESOURCES COMPANY

The Company's operations involve many operational risks, some of which could result in unforeseen interruptions to the Company's operations and substantial losses to the Company for which the Company may not be adequately insured.

The Company's operations, including well stimulation and completion activities, such as hydraulic fracturing, are subject to all the risks normally incident to the oil and gas development and production business, including:

• blowouts, cratering, explosions and fires;

• adverse weather effects;

• environmental hazards, such as gas leaks, oil spills, pipeline and vessel ruptures, encountering NORM, and unauthorized discharges of toxic gases, brine, well stimulation and completion fluids or other pollutants into the surface and subsurface environment;

• high costs, shortages or delivery delays of equipment, labor or other services or water for hydraulic fracturing;

• facility or equipment malfunctions, failures or accidents;

• title problems;

• pipe or cement failures or casing collapses;

• compliance with environmental and other governmental requirements;

• lost or damaged oilfield workover and service tools;

• unusual or unexpected geological formations or pressure or irregularities in formations; and

• natural disasters.

The Company's overall exposure to operational risks may increase as its drilling activity expands and as it seeks to directly provide drilling, fracture stimulation and other services internally. Any of these risks could result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigations and penalties and suspension of operations.

The Company is not fully insured against certain of the risks described above, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance. Additionally, the Company relies to a large extent on facilities owned and operated by third-parties, and damage to or destruction of those third-party facilities could affect the ability of the Company to produce, transport and sell its hydrocarbons.

The Company's expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.

The Company has identified drilling locations and prospects for future drilling opportunities, including development, exploratory and infill drilling and enhanced recovery activities. These drilling locations and prospects represent a significant part of the Company's future drilling plans. For example, the Company's proved reserves as of December 31, 2012 include proved undeveloped reserves and proved developed reserves that are behind pipe of 271.4 MMBBLs of oil, 103.0 MMBBLs of NGLs and 714.6 BCF of gas. The Company's ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services and personnel and drilling results. Because of these uncertainties, the Company cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or meet the Company's expectations for success. As such, the Company's actual drilling and enhanced recovery activities may materially differ from the Company's current expectations, which could have a significant adverse effect on the Company's proved reserves, financial condition and results of operations.

The Company may not be able to obtain access to pipelines and storage facilities, gas gathering systems and other transportation, processing, fractionation and refining facilities to market its oil, NGL and gas production; the Company relies on a limited number of purchasers for a majority of its products.

The marketing of oil, NGL and gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gas gathering systems and other transportation, processing, fractionation and refining facilities, as well as the existence of adequate markets. If there were insufficient capacity available on these systems, if these systems were unavailable to the Company, or if access to these systems were to become commercially unreasonable, the price offered for the Company's production could be significantly depressed, or the Company could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while it constructs its own facility. The Company also relies (and expects to rely in the future) on facilities developed and owned by third parties in order to store, process, transport, fractionate and sell its oil, NGL and gas production. The Company's plans to develop and sell its oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient transportation, storage or

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PIONEER NATURAL RESOURCES COMPANY

processing and fractionation facilities to the Company, especially in areas of planned expansion where such facilities do not currently exist.

To the extent that the Company enters into transportation contracts with gas pipelines that are subject to FERC regulation, the Company is subject to FERC requirements related to use of such capacity. Any failure on the Company's part to comply with FERC's regulations and policies or with an interstate pipeline's tariff could result in the imposition of civil and criminal penalties.

A limited number of companies purchase a majority of the Company's oil, NGLs and gas. The loss of a significant purchaser could have a material adverse effect on the Company's ability to sell its production.

The nature of the Company's assets and production operations exposes it to significant costs and liabilities with respect to environmental and occupational safety matters.

The oil and gas business involves the production, handling, sale and disposal of environmentally sensitive materials and is subject to environmental hazards, such as oil spills, produced water spills, gas leaks, pipeline and vessel ruptures and unauthorized discharges of substances or gases, that could expose the Company to substantial liability due to pollution and other environmental damage. Pollution and similar environmental risks generally are not fully insurable either because such insurance is not available or because of the high premium costs and deductible associated with obtaining such insurance. A variety of federal, state and local laws and regulations govern the environmental aspects of the oil and gas business. Noncompliance with these laws and regulations may subject the Company to administrative, civil or criminal penalties, remedial cleanups, and natural resource damages or other liabilities, and compliance with these laws and regulations may increase the cost of the Company's operations. Such laws and regulations may also affect the costs of acquisitions. See "Item 1. Business — Competition, Markets and Regulations — Environmental and occupational health and safety matters" above for additional discussion related to environmental risks.

Environmental laws and regulations are subject to amendment or replacement by more stringent laws and regulations and no assurance can be given that continued compliance with existing or future environmental laws and regulations will not result in a curtailment of production or processing activities, result in a material increase in the costs of production, development, exploration or processing operations or adversely affect the Company's future operations and financial condition.

The Company could incur significant costs and liabilities in responding to contamination that occurs at its properties or as a result of its operations.

There is inherent risk of incurring significant environmental costs and liabilities in operations upon the Company's properties due to its handling of petroleum hydrocarbons and wastes, because of air emissions and water discharges related to its operations, and as a result of historical operations and waste disposal practices by prior owners and operators. The Company currently owns, leases or operates properties that for many years have been used for oil and gas exploration and production activities, and petroleum hydrocarbons, hazardous substances and wastes have been released on or under such properties and could be released during future operations. Joint and several strict liabilities may be incurred in connection with such releases of petroleum hydrocarbons and wastes on, under or from the Company's properties. Private parties, including lessors of properties on which the Company operates and the owners or operators of properties adjacent to the Company's operations and facilities where the Company's petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage. The Company may not be able to recover some or any of these costs from insurance or other sources of indemnity.

The Company's credit facilities and debt instruments have substantial restrictions and financial covenants that may restrict its business and financing activities.

The Company is a borrower under fixed rate senior notes, convertible senior notes and credit facilities. The terms of the Company's borrowings under the senior notes, convertible senior notes and the credit facilities specify scheduled debt repayments and require the Company to comply with certain associated covenants and restrictions. The Company's ability to comply with the debt repayment terms, associated covenants and restrictions is dependent on, among other things, factors outside the Company's direct control, such as commodity prices and interest rates. See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's outstanding debt as of December 31, 2012 and the terms associated therewith.

The Company's ability to obtain additional financing is also affected by the Company's debt credit ratings and competition for available debt financing.

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PIONEER NATURAL RESOURCES COMPANY

The Company faces significant competition, and many of its competitors have resources in excess of the Company's available resources.

The oil and gas industry is highly competitive. The Company competes with a large number of companies, producers and operators in a number of areas such as:

• seeking to acquire oil and gas properties suitable for development or exploration;

• marketing oil, NGL and gas production; and

• seeking to acquire the equipment and expertise, including trained personnel, necessary to evaluate, operate and develop properties.

Many of the Company's competitors are larger and have substantially greater financial and other resources than the Company. See "Item 1. Business — Competition, Markets and Regulations" for additional discussion regarding competition.

The Company is subject to regulations that may cause it to incur substantial costs.

The Company's business is regulated by a variety of federal, state and local laws and regulations. For instance, in connection with the Company's CBM operations in the Raton Basin in Colorado, the Colorado Supreme Court affirmed a state water court holding that water produced in connection with CBM operations should be subject to state water-use regulations, including regulations requiring permits for diversion and use of surface and subsurface water, an evaluation of potential competing permits, possible uses of the water and a possible requirement to provide augmentation water supplies for water rights owners with more senior rights. There can be no assurance that present or future regulations will not adversely affect the Company's business and operations, including that the Company may be required to suspend drilling operations or shut in production pending compliance. See "Item 1. Business — Competition, Markets and Regulations" for additional discussion regarding government regulation.

The Company's sales of oil, gas, NGLs or other energy commodities, and any derivative activities related to such energy commodities, expose the Company to potential regulatory risks.

FERC, the FTC and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to the Company's business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to the Company's physical sales of oil, gas, NGLs or other energy commodities, and any derivative activities related to these energy commodities, the Company is required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect the Company's business results of operations and financial condition.

Estimates of proved reserves and future net cash flows are not precise. The actual quantities and net cash flows of the Company's proved reserves may prove to be lower than estimated.

Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. The estimates of proved reserves and related future net cash flows set forth in this Report are based on various assumptions, which may ultimately prove to be inaccurate.

Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:

• historical production from the area compared with production from other producing areas;

• the quality and quantity of available data;

• the interpretation of that data;

• the assumed effects of regulations by governmental agencies;

• assumptions concerning future commodity prices; and

• assumptions concerning future operating costs, severance, ad valorem and excise taxes, development costs, transportation costs and workover and remedial costs.

Because all proved reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

• the quantities of oil and gas that are ultimately recovered;

• the production costs incurred to recover the reserves;

• the amount and timing of future development expenditures; and

• future commodity prices.

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PIONEER NATURAL RESOURCES COMPANY

Furthermore, different reserve engineers may make different estimates of proved reserves and cash flows based on the same available data. The Company's actual production, revenues and expenditures with respect to proved reserves will likely be different from estimates, and the differences may be material.

As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on average prices preceding the date of the estimate and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

• the amount and timing of actual production;

• levels of future capital spending;

• increases or decreases in the supply of or demand for oil, NGLs and gas; and

• changes in governmental regulations or taxation.

Standardized Measure is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. In general, it requires the use of commodity prices that are based upon a 12-month unweighted average, as well as operating and development costs being incurred at the end of the reporting period. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and gas production because of seasonal price fluctuations or other varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general. Therefore, the estimates of discounted future net cash flows or Standardized Measure in this Report should not be construed as accurate estimates of the current market value of the Company's proved reserves.

The Company's actual production could differ materially from its forecasts.

From time to time, the Company provides forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells and the outcome of future drilling activity. Should these estimates prove inaccurate, actual production could be adversely affected. In addition, the Company's forecasts assume that none of the risks associated with the Company's oil and gas operations summarized in this "Item 1A. Risk Factors" occur, such as facility or equipment malfunctions, adverse weather effects, or downturns in commodity prices or significant increases in costs, which could make certain drilling activities or production uneconomical.

A subsidiary of the Company acts as the general partner of a publicly-traded limited partnership. As such, the subsidiary's operations may involve a greater risk of liability than ordinary business operations.

A subsidiary of the Company acts as the general partner of Pioneer Southwest, a publicly-traded limited partnership formed by the Company to own, develop and acquire oil and gas assets in its area of operations. As general partner, the subsidiary may be deemed to have undertaken fiduciary obligations to Pioneer Southwest.

Activities determined to involve fiduciary obligations to others typically involve a higher standard of conduct than ordinary business operations and therefore may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Any such liability may be material.

The tax treatment of Pioneer Southwest depends on its status as a partnership for federal income tax purposes as well as its not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (the "IRS") were to treat Pioneer Southwest as a corporation for federal income tax purposes or Pioneer Southwest becomes subject to a material amount of entity-level taxation for state tax purposes, then the value of the Company's investment in Pioneer Southwest would be substantially reduced.

The Company currently owns a 52.4 percent limited partner interest and a 0.1 percent general partner interest in Pioneer Southwest. The value of the Company's investment in Pioneer Southwest depends largely on its being treated as a partnership for federal income tax purposes. A publicly traded partnership may be treated as a corporation for United States federal income tax purposes unless 90 percent or more of its gross income for every year is "qualifying income" under section 7704 of the Internal Revenue Code of 1986, as amended. Pioneer Southwest has not requested and does not plan to request a ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes.

A change in Pioneer Southwest's business could cause it to be treated as a corporation for federal income tax purposes. In addition, a change in current law may cause Pioneer Southwest to be treated as a corporation for such purposes. For example, members of U.S. Congress have from time to time considered substantive changes to the existing federal income tax laws that

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PIONEER NATURAL RESOURCES COMPANY

would affect the tax treatment of certain publicly traded partnerships. Moreover, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If Pioneer Southwest were subject to federal income tax as a corporation or any state were to impose a tax upon Pioneer Southwest, its cash available to pay distributions would be reduced. Therefore, treatment of Pioneer Southwest as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to Pioneer Southwest's unitholders, including the Company, and would likely cause a substantial reduction in the value of the Company's investment in Pioneer Southwest.

Pioneer Southwest's partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects it to taxation as a corporation or otherwise subjects it to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution and the target distribution amounts may be adjusted to reflect the effect of that law on Pioneer Southwest.

The Company's business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

As an oil and gas producer, the Company faces various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of the Company's facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected the Company's operations to increased risks that could have a material adverse effect on the Company's business. In particular, the Company's implementation of various procedures and controls to monitor and mitigate security threats and to increase security for the Company's information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to the Company's operations and could have a material adverse effect on the Company's reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage the Company's reputation and lead to financial losses from remedial actions, loss of business or potential liability.

A failure by purchasers of the Company's production to perform their obligations to the Company could require the Company to recognize a pre-tax charge in earnings and have a material adverse effect on the Company's results of operation.

While the credit and equity markets have improved during 2010, 2011 and 2012, the economic outlook for 2013 remains uncertain. The Company relies on a limited number of purchasers to purchase a majority of its products. To the extent that purchasers of the Company's production rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to the Company if such purchasers were unable to access the credit or equity markets for an extended period of time. If for any reason the Company were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of the Company's production were uncollectible, the Company would recognize a pre-tax charge in the earnings of that period for the probable loss.

Declining general economic, business or industry conditions could have a material adverse effect on the Company's results of operations.

Concerns over the worldwide economic outlook, geopolitical issues, the availability and cost of credit and the U.S. mortgage and real estate markets have contributed to increased volatility and diminished expectations for the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment resulted in a worldwide recession. While the worldwide economic outlook seems to be improving, concerns about global economic growth or government debt in Europe or the United States could have a significant adverse effect on global financial markets and commodity prices. If the economic climate in the United States or abroad were to deteriorate, demand for petroleum products could diminish, which could depress the prices at which the Company could sell its oil, NGLs and gas and ultimately decrease the Company's net revenue and profitability.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including elimination of certain key U.S. federal income tax incentives currently available to oil and gas companies. Such tax legislation changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical

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PIONEER NATURAL RESOURCES COMPANY

expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect the value of an investment in the Company's common stock and defer planned capital expenditures if such changes accelerated the payment of taxes.

The adoption of climate change legislation by the U.S. Congress or regulation by the EPA could result in increased operating costs and reduced demand for the oil, NGLs and gas the Company produces.

In December 2009, the EPA officially published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under the CAA in 2010 establishing Title V and Prevention of Significant Deterioration permitting requirements for large sources of GHGs. The Company could become subject to these permitting requirements and be required to install "best available control technology" to limit emissions of GHGs from any new or significantly modified facilities that the Company may seek to construct in the future if they would otherwise emit large volumes of GHGs. The EPA has also adopted rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the United States, including certain oil and gas production facilities, which include certain of the Company's facilities. The Company is monitoring GHG emissions from its operations in accordance with these GHG emissions reporting rules and believes that its monitoring activities are in substantial compliance with applicable reporting obligations.

While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If the U.S. Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on the Company's operations.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would affect the Company's business, any such future laws and regulations could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Company's business, financial condition and results of operations. Also, some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Company's financial condition and results of operations. See "Item 1. Business – Competition, Markets and Regulations - Environmental and occupational health and safety matters - Global warming and climate change" for additional discussion relating to global warming and climate change.

The enactment of derivatives legislation could have an adverse effect on the Company's ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act") enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Act. In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide derivative transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Colombia in September 2012, although the CFTC has stated that it will appeal the District Court's decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of "swap", "security-based swap", "swap dealer" and "major swap participant." The Act and the CFTC rules also will require the Company, in connection with certain derivative activities, to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require the Company to comply with margin requirements although these regulations are not finalized and their application to the Company is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Act and the CFTC rules on the Company and the timing of such effects. The Act also may require the counterparties to the Company's derivative instruments to spin off some of their derivatives activities to a separate entity, which

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PIONEER NATURAL RESOURCES COMPANY

may not be as creditworthy as the current counterparty. The Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect the Company's available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company's ability to monetize or restructure its existing derivative contracts, and increase the Company's exposure to less creditworthy counterparties. If the Company reduces its use of derivatives as a result of the Act and regulations implementing the Act, the Company's results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company's ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. The Company's revenues could therefore be adversely affected if a consequence of the Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Company, its financial condition and its results of operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect the Company's production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The Company routinely utilizes hydraulic fracturing techniques in the majority of its drilling and completion programs. The process involves the injection of water, sand and additives under pressure into targeted subsurface formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions; however, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the SDWA's Underground Injection Control Program and published draft permitting guidance in May 2012 addressing the performance of such activities. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and the agency currently projects to issue an Advance Notice of Proposed Rulemaking in May 2013 that would seek public input on the design and scope of such disclosure regulations. In August 2012, the EPA published final rules under the CAA, which became effective October 15, 2012, that, among other things, require producers to reduce volatile organic compound emissions from certain subcategories of fractured and refractured gas wells for which well completion operations are being conducted by routing flowback emissions to a gathering line or capturing and combusting flowback emissions using a combustion device, such as a flare, until January 1, 2015 or performing reduced emission completions, also known as "green completions," with or without combustion devices, on or after January 1, 2015. In addition, the U.S. Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that a new federal level of legal restrictions relating to the hydraulic-fracturing process is adopted in areas where the Company currently or in the future plans to operate, the Company may incur additional costs to comply with such federal requirements that may be significant in nature, become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development or production activities.

Certain states in which the Company operates, including Colorado and Texas have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, and well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the TRRC and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. The Company believes that it follows applicable standard industry practices and legal requirements for groundwater protection in its hydraulic fracturing activities. Nonetheless, in the event state or local restrictions are adopted in areas where the Company is currently conducting, or in the future plan to conduct operations, the Company may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps be limited or precluded in the drilling of wells or in the amounts that the Company is ultimately able to produce from its reserves.

Certain governmental reviews were recently conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress released by the agency on December 21, 2012 and a final report expected to be available for public comment and peer review by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These studies, or future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. See "Item 1. Business - Competition, Markets and Regulations - Environmental and occupational health and safety matters" above for additional discussion related to environmental risks associated with the Company's hydraulic fracturing activities.

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PIONEER NATURAL RESOURCES COMPANY

Provisions of the Company's charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for the Company's common stock.

Provisions in the Company's certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which the Company is not the surviving company and may otherwise prevent or slow changes in the Company's board of directors and management. In addition, because the Company is incorporated in Delaware, it is governed by the provisions of Section 203 of the Delaware General Corporation Law. These provisions could discourage an acquisition of the Company or other change in control transaction and thereby negatively affect the price that investors might be willing to pay in the future for the Company's common stock.

The Company is growing production in areas of high industry activity, which may affect its ability to obtain the personnel, equipment, services, resources and facilities access needed to complete its development activities as planned or result in increased costs.

The Company's operations and drilling activity are concentrated in areas in which industry activity has increased rapidly, particularly in the Spraberry field in West Texas and the Eagle Ford Shale play in South Texas. As a result, demand for personnel, equipment, power, services and resources, as well as access to transportation, processing and refining facilities in these areas, has increased, as have the costs for those items. In addition, hydraulic fracturing and other operations require significant quantities of water, which supply may be affected by drought conditions. Any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for the Company to complete its planned development activities, including the result of any changes in laws or regulations applicable to the Company's operations relating to water usage, could result in oil and gas production volumes being below the Company's forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on the Company's profitability.

Laws and regulations pertaining to threatened and endangered species could delay or restrict the Company's operations and cause it to incur substantial costs.

Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the ESA, the Migratory Bird Treaty Act, the CWA and CERCLA. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered or threatened under the ESA before completion of the agency's 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where the Company conducts operations could cause the Company to incur increased costs arising from species protection measures or could result in limitations on its exploration and production activities that could have an adverse effect on the Company's ability to develop and produce reserves.

The Company's sand mining operations are subject to operating risks that are often beyond the Company's control, and such risks may not be covered by insurance.

Ownership of industrial sand mining operations are subject to risks, many of which are beyond the Company's control. These risks include:

• unusual or unexpected geological formations or pressures;

• cave-ins, pit wall failures or rock falls;

• unanticipated ground, grade or water conditions;

• inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;

• environmental hazards, such as unauthorized spills, releases and discharges of wastes, vessel ruptures, and emission of unpermitted levels of pollutants;

• changes in laws and regulations;

• inability to acquire or maintain necessary permits or mining or water rights;

• restrictions on blasting operations;

• inability to obtain necessary production equipment or replacement parts;

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PIONEER NATURAL RESOURCES COMPANY

• reduction in the amount of water available for processing;

• technical difficulties or failures;

• labor disputes;

• late delivery of supplies;

• fires, explosions or other accidents; and

• facility shutdowns in response to environmental regulatory actions.

Any of these risks could result in damage to, or destruction of, the Company's mining properties or production facilities, personal injury, environmental damage, delays in mining or processing, losses or possible legal liability. Not all of these risks are insurable, and the Company's insurance coverage contains limits, deductibles, exclusions and endorsements. The Company's insurance coverage may not be sufficient to meet its needs in the event of loss and any such loss may have a material adverse effect on the Company.

The Company's estimates of sand reserves and resource deposits are imprecise and actual reserves could be less than estimated.

The Company bases its sand reserve and resource estimates on engineering, economic and geological data assembled and analyzed by engineers and geologists, which are reviewed by outside firms. However, commercial sand reserve estimates are necessarily imprecise and depend to some extent on statistical inferences drawn from available drilling data, which may prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of commercial sand reserves and costs to mine recoverable reserves, including many factors beyond the Company's control. Estimates of economically recoverable commercial sand reserves necessarily depend on a number of factors and assumptions, all of which may vary considerably from actual results, such as:

• geological and mining conditions or effects from prior mining that may not be fully identified by available data or that may differ from experience;

• assumptions concerning future prices of commercial sand products, operating costs, mining technology improvements, development costs and reclamation costs; and

• assumptions concerning future effects of regulation, including the issuance of required permits and taxes by governmental agencies.

The Company's sand mining operations are subject to extensive environmental and occupational health and safety regulations that impose significant costs and potential liabilities.

The Company's sand mining operations are subject to a variety of federal, state and local environmental requirements affecting the mining and mineral processing industry, including, among others, those relating to employee health and safety, environmental permitting and licensing, air emissions and water discharges, GHG emissions, water pollution, waste management and disposal, remediation of soil and groundwater contamination, land use restrictions, reclamation and restoration of properties, hazardous materials and natural resources. Some environmental laws impose substantial penalties for noncompliance, and others, such as the CERCLA, impose strict, retroactive and joint and several liability for the remediation of releases of hazardous substances. Failure to properly handle, transport, store or dispose of hazardous materials or otherwise conduct the Company's sand mining operations in compliance with environmental laws could expose the Company to liability for governmental penalties, cleanup costs and civil or criminal liability associated with releases of such materials into the environment, damages to property or natural resources and other damages, as well as potentially impair the Company's ability to conduct its sand mining operations. In addition, environmental laws and regulations are subject to amendment, replacement or interpretation by more stringent and comprehensive legal requirements. The Company's continued compliance with existing or future laws and regulations could restrict the Company's ability to expand its facilities or extract mineral deposits or could require the Company to acquire costly equipment or to incur other significant expenses in connection with its sand mining operations, which restrictions or costs could have a material adverse effect on the Company's sand mining operations.

Any failure by the Company to comply with applicable environmental laws and regulations in connection with its sand mining operations may cause governmental authorities to take actions that could adversely affect the Company, including:

• issuance of administrative, civil and criminal penalties;

• denial, modification or revocation of permits or other authorizations;

• imposition of injunctive obligations or other limitations on the Company's operations, including cessation of operations; and

• requirements to perform site investigatory, remedial or other corrective actions.

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PIONEER NATURAL RESOURCES COMPANY

In addition to environmental regulation, the Company's sand mining operations are subject to laws and regulations relating to worker health and safety, including such matters as human exposure to crystalline silica dust. Several federal and state regulatory authorities, including the U.S. Mining Safety and Health Administration, may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits and required controls and personal protective equipment.

The Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, which imposes stringent health and safety standards on numerous aspects of the Company's sand mining operations.

The Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment and other matters. The Company's failure to comply with such standards, or changes in such standards or the interpretation or enforcement thereof, could have a material adverse effect on the Company's sand mining operations or otherwise impose significant restrictions on the Company's ability to conduct mineral extraction and processing operations.

The Company's sand mining operations are subject to extensive other regulations that impose significant costs and liabilities.

In addition to the environmental and occupational health and safety regulation discussed above, the Company's sand mining operations are also subject to extensive governmental regulation on matters such as permitting and licensing requirements, reclamation and restoration of mining properties after mining is completed, and the effects that mining have on groundwater quality and availability. Also, the Company's sand mining operations require numerous governmental, environmental, mining and other permits, water rights and approvals authorizing operations at each sand mining facility.

In order to obtain permits and renewals of permits in the future for its sand mining operations, the Company may be required to prepare and present data to governmental authorities pertaining to the effect that any such activities may have on the environment. Obtaining or renewing required permits may be delayed or prevented due to opposition by neighboring property owners, members of the public or other third parties and other factors beyond the Company's control. A decision by a governmental agency or other third party to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on the Company's sand mining operations at the affected facility. Current or future regulations could have a material adverse effect on the Company's sand mining operations and the Company may not be able to renew or obtain permits in the future.

The Company's sand mining operations entail silica-related health issues and litigation that could have a material adverse effect on the Company.

The inhalation of respirable crystalline silica dust is associated with the lung disease silicosis. There is evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders, such as scleroderma. These health risks have been, and may continue to be, a significant issue confronting the commercial sand industry. The actual or perceived health risks of mining, processing and handling sand could materially and adversely affect the Company through the threat of product liability or employee lawsuits and increased scrutiny by federal, state and local regulatory authorities.

Premier Silica is named as a defendant, usually among many defendants, in numerous products liability lawsuits brought by or on behalf of current or former employees of Premier Silica's customers alleging damages caused by silica exposure. As of December 31, 2012, Premier Silica was the subject of approximately 2,500 silica exposure claims, the great majority of which have been inactive for many years due to the plaintiffs' failure to meet specific legal requirements to advance their claims. Almost all of the claims pending against Premier Silica arise out of the alleged use of Premier Silica's sand products in foundries or as an abrasive blast media and have been filed in the states of Texas, Louisiana, Florida and West Virginia, although some cases have been brought in many other jurisdictions over the years.

It is possible that Premier Silica will continue to have silica-related products liability claims filed against it, including claims that allege silica exposure for periods for which there is not insurance coverage. Any pending or future claims or inadequacies of insurance coverage or indemnification from the seller could have a material adverse effect on the Company's results of operations.

The Company's pending sale of 40 percent of its acreage in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field is contingent upon the satisfaction of certain conditions and may not be consummated on the terms or timeline contemplated and may not achieve the intended results.

In January 2013, the Company agreed to sell 40 percent of its interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field to Sinochem, an unaffiliated third party, for

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PIONEER NATURAL RESOURCES COMPANY

consideration of $1.7 billion. At closing, Sinochem will pay $522.0 million in cash to Pioneer, before normal closing adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of the Company's portion of future drilling and facilities costs attributable to the horizontal Wolfcamp Shale play. The Company expects this transaction to close during the second quarter of 2013. However, the parties' obligations to consummate this transaction are conditioned upon the satisfaction or waiver of certain closing conditions, including governmental and third party approvals. If these conditions are not satisfied or waived, the acquisition will not be consummated. If the closing of the transaction is substantially delayed or does not occur at all, the Company may not realize the anticipated benefits of the transaction fully or at all. Further, if the transaction is not completed, the Company would need to reevaluate its capital expenditure budget and reduce its activities or obtain funding from other sources.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Reserve Estimation Procedures and Audits

The information included in this Report about the Company's proved reserves as of December 31, 2012, 2011 and 2010 is based on evaluations prepared by the Company's engineers and (i) audited by Netherland, Sewell & Associates, Inc. ("NSAI"), with respect to the Company's major properties for all periods, and (ii) with respect to the Company's Oooguruk field properties in Alaska, audited by Ryder Scott Company, L.P. ("RSC"), as of December 31, 2012. The Company has no oil and gas reserves from non-traditional sources. Additionally, the Company does not provide optional disclosure of probable or possible reserves. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the sale of the Company's share holdings in Pioneer Tunisia during February 2011 and the Company's sale of Pioneer South Africa in August 2012.

Reserve estimation procedures. The Company has established internal controls over reserve estimation processes and procedures to support the accurate and timely preparation and disclosure of reserve estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation reporting processes by Pioneer's Worldwide Reserves Group (the "WWR"), and annual external audits of substantial portions of the Company's proved reserves by NSAI and RSC.

Individual asset teams are responsible for the day-to-day management of the oil and gas activities in each of the Company's Permian Basin, Rockies, Mid-Continent, South Texas, Barnett Shale and Alaska asset areas (the "Asset Teams"). The Company's Asset Teams are each staffed with reservoir engineers and geoscientists who prepare reserve estimates at the end of each calendar quarter for the assets that they manage, using reservoir engineering information technology. There is shared oversight of the Asset Teams' reservoir engineers by the Asset Teams' managers and the Director of the WWR, each of whom is in turn subject to direct or indirect oversight by the Company's management committee ("MC"). The Company's MC is comprised of its Chief Executive Officer, Chief Operating Officer, Chief Financial Officer and other Executive Vice Presidents. The Asset Teams' reserve estimates are reviewed by the asset team reservoir engineers before being submitted to the WWR for further review.

The reserve estimates are summarized in reserve reconciliations that quantify reserve changes since the previous year end as revisions of previous estimates, purchases of minerals-in-place, improved recovery, extensions and discoveries, production and sales of minerals-in-place. All reserve estimates, material assumptions and inputs used in reserve estimates and significant changes in reserve estimates are reviewed for engineering and financial appropriateness and compliance with SEC and GAAP standards by the WWR, in consultation with the Company's accounting and financial management personnel. Annually, the MC reviews the reserve estimates and any differences with the reserve auditors (for the portion of the reserves audited by NSAI and RSC) on a consolidated basis before these estimates are approved. The engineers and geoscientists who participate in the reserve estimation and disclosure process periodically attend training provided by external consultants and/or through internal Pioneer programs. Additionally, the WWR has prepared and maintains written policies and guidelines for the Asset Teams to reference on reserve estimation and preparation to promote objectivity in the preparation of the Company's reserve estimates and SEC and GAAP compliance in the reserve estimation and reporting process.

Proved reserves audits. The proved reserve audits performed by NSAI for 2012, 2011 and 2010, and by RSC for 2012, in the aggregate represented 95 percent, 90 percent and 90 percent of the Company's 2012, 2011 and 2010 proved reserves, respectively; and, 99 percent, 91 percent and 79 percent of the Company's 2012, 2011 and 2010 associated pre-tax present value of proved reserves discounted at ten percent, respectively.

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PIONEER NATURAL RESOURCES COMPANY

NSAI and RSC follow the general principles set forth in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information" promulgated by the Society of Petroleum Engineers (the "SPE"). A reserve audit as defined by the SPE is not the same as a financial audit. The SPE's definition of a reserve audit includes the following concepts:

• A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable and has been presented in conformity with the 2007 SPE publication entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information."

• The estimation of reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by a company in estimating its reserves so that the reserve auditors may express an opinion as to whether, in the aggregate, the reserve information furnished by a company is reasonable.

• The methods and procedures used by a company, and the reserve information furnished by a company, must be reviewed in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare its own estimates of reserve information for the audited properties.

In conjunction with the audit of the Company's proved reserves and associated pre-tax present value discounted at ten percent, Pioneer provided to NSAI and RSC its external and internal engineering and geoscience technical data and analyses. Following the reserve auditors' review of that data, they had the option of honoring Pioneer's interpretations, or making their own interpretations. No data was withheld from NSAI or RSC. The reserve auditors accepted without independent verification the accuracy and completeness of the historical information and data furnished by Pioneer with respect to ownership interest, oil and gas production, well test data, commodity prices, operating and development costs, and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their evaluations something came to their attention that brought into question the validity or sufficiency of any such information or data, the reserve auditors did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data.

In the course of their evaluations, NSAI and RSC prepared, for all of the audited properties, their own estimates of the Company's proved reserves and the pre-tax present values of such reserves discounted at ten percent. The reserve auditors reviewed their audit differences with the Company, and, in a number of cases, held meetings with the Company to review additional reserves work performed by the Company's technical teams and any updated performance data related to the proved reserve differences. Such data was incorporated, as appropriate, by both parties into the proved reserve estimates. The reserve auditors' estimates, including any adjustments resulting from additional data, of those proved reserves and the pre-tax present value of such reserves discounted at ten percent did not differ from Pioneer's estimates by more than ten percent in the aggregate. However, when compared on a lease-by-lease, field-by-field or area-by-area basis, some of the Company's estimates were greater than those of the reserve auditors and some were less than the estimates of the reserve auditors. When such differences do not exceed ten percent in the aggregate and NSAI and RSC are satisfied that the proved reserves and pre-tax present values of such reserves discounted at ten percent are reasonable and that their audit objectives have been met, NSAI and RSC will issue an unqualified audit opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analyses by the Company and the reserve auditors. At the conclusion of the audit process, it was the opinions of NSAI and RSC, as set forth in their audit letters, which are included as exhibits to this Report, that Pioneer's estimates of the Company's proved oil and gas reserves and associated pre-tax present values discounted at ten percent are, in the aggregate, reasonable and have been prepared in accordance with the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the SPE.

See "Item 1A. Risk Factors," "Critical Accounting Estimates" in "Item 7. Management's Discussion and Analysis and Results of Operations" and "Item 8. Financial Statements and Supplementary Data" for additional discussions regarding proved reserves and their related cash flows.

Qualifications of reserves preparers and auditors. The WWR is staffed by petroleum engineers with extensive industry experience and is managed by the Director of the WWR, the technical person that is primarily responsible for overseeing the Company's reserves estimates. These individuals meet the professional qualifications of reserves estimators and reserves auditors as defined by the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information," promulgated by the SPE. The WWR Director's qualifications include 35 years of experience as a petroleum engineer, with 28 years focused on reserves reporting for independent oil and gas companies, including Pioneer. His educational background includes an undergraduate degree in Chemical Engineering and a Masters of Business Administration degree in Finance. He is also a Chartered Financial Analyst Charterholder.

NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional

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PIONEER NATURAL RESOURCES COMPANY

Engineers Registration No. F-2699. The technical person primarily responsible for auditing the Company's reserves estimates has been a practicing consulting petroleum engineer at NSAI since 1983 and has over 34 years of practical experience in petroleum engineering, including over 32 years of experience in the estimation and evaluation of proved reserves. He graduated with a Bachelor of Science degree in Chemical Engineering in 1978 and meets or exceeds the education, training and experience requirements set forth in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the board of directors of the SPE.

RSC provides worldwide petroleum property analysis services for energy clients, financial organizations and government agencies. RSC was founded in 1937 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-1580. The technical person primarily responsible for auditing the Company's reserves estimates has been a practicing consulting petroleum engineer at RSC since 2000 and has over 28 years of practical experience in petroleum engineering. He graduated with a Bachelor of Science degree in Petroleum Engineering and a Master of Business Administration degree and meets or exceeds the education, training and experience requirements set forth in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the board of directors of the SPE.

Technologies used in reserves estimates. Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped proved reserves only if an ability and intent has been established to drill the reserves within five years, unless specific circumstances justify a longer time period.

In the context of reserves estimations, reasonable certainty means a high degree of confidence that the quantities will be recovered and reliable technology means a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonable certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating proved reserves, the Company uses several different traditional methods such as performance-based methods, volumetric-based methods and analogy with similar properties. In addition, the Company utilizes additional technical analysis such as seismic interpretation, wireline formation tests, geophysical logs and core data to provide incremental support for more complex reservoirs. Information from this incremental support is combined with the traditional technologies outlined above to enhance the certainty of the Company's reserve estimates.

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PIONEER NATURAL RESOURCES COMPANY

Proved Reserves

As of December 31, 2012, the Company's oil and gas proved reserves are located entirely in the United States. Less than one percent of proved reserves as of December 31, 2011 were associated with discontinued operations in South Africa and three percent of proved reserves as of December 31, 2010 were associated with discontinued operations in South Africa and Tunisia. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional details of the Company's discontinued operations. The following table provides information regarding the Company's proved reserves and Standardized Measure as of December 31, 2012, 2011 and 2010:

	Summary of Oil and Gas Reserves as of Fiscal Year-End Based on Average Fiscal-Year Prices
	Reserve Volumes
	Oil (MBBLs)	NGLs (MBBLs)	Gas (MMCF) (a)	Total (MBOE)	%		Standardized Measure
							(in thousands)
December 31, 2012:
Developed	230,700	134,637	1,605,209	632,872	58	%	$	5,010,779
Undeveloped	256,138	97,939	592,271	452,789	42	%	1,342,619
Total Proved	486,838	232,576	2,197,480	1,085,661	100	%	$	6,353,398
December 31, 2011:
Developed	190,206	120,405	1,853,363	619,506	58	%	$	5,494,007
Undeveloped	239,799	90,630	677,675	443,375	42	%	$	2,319,016
Total Proved	430,005	211,035	2,531,038	1,062,881	100	%	$	7,813,023
December 31, 2010:
Developed	172,816	108,785	1,775,611	577,537	57	%	$	4,065,879
Undeveloped	207,993	75,433	898,911	433,244	43	%	$	1,346,130
Total Proved	380,809	184,218	2,674,522	1,010,781	100	%	$	5,412,009

 ______________________

(a) The gas reserves contain 280,344 MMCF, 301,123 MMCF and 303,748 MMCF of gas that will be produced and used as field fuel (primarily for compressors) before the gas is delivered to a sales point, for December 31, 2012, 2011 and 2010, respectively.

See the "Unaudited Supplementary Information" section included in "Item 8. Financial Statements and Supplementary Data" for additional details of the estimated quantities of the Company's proved reserves.

Description of Properties

Approximately 78 percent of the Company's proved reserves at December 31, 2012 are located in the Spraberry field in the Permian Basin area, the Hugoton and West Panhandle fields in the Mid-Continent area and the Raton field in the Rocky Mountains area. These fields generate substantial operating cash flow, which provides funding for the Company's development and exploration activities in the Spraberry field, Eagle Ford Shale play, Barnett Shale Combo play and Alaska.

The following tables summarize the Company's development and exploration/extension drilling activities during 2012:

	Development Drilling
	Beginning Wells In Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells In Progress
Permian Basin	161	633	649	9	136
Raton Basin	5	—	4	1	—
Barnett Shale	—	4	4	—	—
Alaska	1	5	2	—	4
Total	167	642	659	10	140

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PIONEER NATURAL RESOURCES COMPANY

	Exploration/Extension Drilling
	Beginning Wells In Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells In Progress
Permian Basin	—	50	33	—	17
Mid-Continent	5	—	—	5	—
South Texas—Eagle Ford Shale	39	130	137	—	32
Barnett Shale	26	36	53	—	9
Alaska	1	2	—	1	2
Total	71	218	223	6	60

The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during 2012:

	Oil (BBLs)	NGLs (BBLs)	Gas (MCF) (a)	Total (BOE)
Permian Basin	44,042	12,623	61,922	66,985
Mid-Continent	3,175	7,102	46,192	17,976
Raton Basin	—	—	149,787	24,965
Barnett Shale	1,210	2,756	20,085	7,314
South Texas—Eagle Ford Shale	9,871	7,332	63,338	27,759
South Texas—Edwards and Austin Chalk	75	1	36,945	6,233
Alaska	4,269	—	—	4,269
Other	3	2	100	21
Total	62,645	29,816	378,369	155,522

 _____________________

(a) Gas production excludes gas produced and used as field fuel.

The following table summarizes the Company's costs incurred by asset area during 2012:

	Property Acquisition Costs				Exploration Costs		Development Costs			Asset Retirement Obligations
	Proved		Unproved										Total
	(in thousands)
Permian Basin	$	4,755	$	70,558	$	441,127	$	1,603,688		$	36,221		$	2,156,349
Mid-Continent	—		4,211		4,136		17,884			529			26,760
Raton Basin	—		—		8,111		7,467			16,254			31,832
South Texas—Eagle Ford Shale	—		12,194		229,364		9,476			1,461			252,495
South Texas—Edwards and Austin Chalk	—		130		4,534		5,434			1,502			11,600
Barnett Shale	12,114		12,288		200,376		60,606			(317		)	285,067
Alaska	—		106		73,475		120,246		(a)	3,241			197,068
Other	69		41,028		3,505		10			(19		)	44,593
Total	$	16,938	$	140,515	$	964,628	$	1,824,811		$	58,872		$	3,005,764

 ____________________

(a) Includes $8.5 million of capitalized interest associated with the Oooguruk development project.

Permian Basin

Spraberry field. The Spraberry field was discovered in 1949 and encompasses eight counties in West Texas. According to the Energy Information Administration, the Spraberry field is the second largest oil field in the United States. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casinghead gas with an average energy content of 1,400 BTU. The oil and gas are produced primarily from four formations, the upper and lower Spraberry, the Dean and the Wolfcamp, at depths ranging from 6,700 feet to 11,300 feet. In addition, the Company is drilling deeper to the Strawn, Atoka and Mississippian intervals with positive results.

The Company believes the Spraberry field offers excellent opportunities to grow oil and gas production because of the numerous undeveloped drilling locations, many of which are reflected in the Company's proved undeveloped reserves. The

34

PIONEER NATURAL RESOURCES COMPANY

Spraberry field has the ability to improve incremental recovery rates through infill and deeper formation drilling, waterflood projects and horizontal drilling in certain formations while containing operating expenses and drilling costs through economies of scale and vertical integration of field services.

During 2012, the Company drilled 691 wells in the Spraberry field and its total acreage position now approximates 827,000 gross acres (707,000 net acres). 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 the southern part of the play where the Company expects to drill 86 horizontal Wolfcamp Shale wells and the northern part of the play where the Company expects to drill 30 to 40 horizontal wells.

The Company believes it also has significant horizontal potential within the northern portion of its acreage in the play. During the fourth quarter of 2012, the Company initiated horizontal Wolfcamp drilling activities to delineate the northern part 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 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 four horizontal rigs in its northern acreage during 2013 to delineate the area's resource potential.

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 the Spraberry interval, during 2012, the Company drilled two successful horizontal Jo Mill wells with lateral lengths of 2,628 and 2,178 feet. The Company is continuing to analyze the results of the two wells and plans to drill additional horizontal Jo Mill wells in 2013.

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. At closing Sinochem will pay $522.0 million in cash to Pioneer, 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 and third party 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.

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 drilling rigs and has five Company-owned vertical fracture stimulation fleets totaling 100,000 horsepower and two Company-owned horizontal fracture stimulation fleets totaling 70,000 horsepower currently operating 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, in early April 2012, the Company completed the acquisition of Premier Silica, which is expected to supply the Company's growing brown sand requirements for proppant that will be used for fracture stimulating wells in the vertical Spraberry and horizontal Wolfcamp Shale plays.

35

PIONEER NATURAL RESOURCES COMPANY

Mid-Continent

Hugoton field. The Hugoton field in southwest Kansas is one of the largest producing gas fields in the continental United States. The gas is produced from the Chase and Council Grove formations at depths ranging from 2,700 feet to 3,000 feet. The Company's Hugoton properties are located on 268,000 gross acres (235,000 net acres), covering approximately 400 square miles. The Company has working interests in approximately 1,220 wells in the Hugoton field, approximately 1,000 of which it operates.

The Company operates substantially all of the gathering and processing facilities, including the Satanta plant, which processes the production from the Hugoton field. In January 2011, the Company sold a 49 percent interest in the Satanta plant to an unaffiliated third party for the third party's commitment to dedicate gas volumes to the Satanta plant. This agreement has increased the Satanta plant's processing volumes and is expected to increase its economic longevity. The Company is also exploring opportunities to process other gas production in the Hugoton area at the Satanta plant. By maintaining operatorship of the gathering and processing facilities, the Company is able to control the production, gathering, processing and sale of its Hugoton field gas and NGL production.

West Panhandle field. The West Panhandle properties are located in the panhandle region of Texas. These stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite, Granite Wash and fractured Granite formations at depths no greater than 3,500 feet. The Company's gas has an average energy content of 1,365 BTU and is produced from approximately 867 wells on more than 333,000 gross acres (312,000 net acres) covering over 375 square miles. The Company controls 100 percent of the wells, production equipment, gathering system and the Fain gas processing plant for the field. As this field is operated at or below vacuum conditions, Pioneer continually works to improve compressor and gathering system efficiency.

Raton Basin

The Raton Basin properties are located in the southeast portion of Colorado. The Company owns 212,000 gross acres (186,000 net acres) in the center of the Raton Basin and produces CBM gas from the coal seams in the Vermejo and Raton formations from approximately 2,300 wells. The Company owns the majority of the well servicing and fracture stimulation equipment that it utilizes in the Raton field, allowing it to control costs and insure availability.

South Texas Eagle Ford Shale and Edwards

The Company's drilling activities in the South Texas area during 2012 continued to be primarily focused on delineation and development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2012 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 137 horizontal Eagle Ford Shale wells during 2012, all of which were successful, with average lateral lengths of 5,700 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 134 wells. The Company plans to primarily use two Pioneer-owned fracture stimulation fleets during 2013.

The Company has also been testing the use of 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 is continuing to monitor the performance of these wells and expects that greater than 50 percent of its 2013 drilling program will use lower-cost white sand proppant.

During June 2010, the Company entered into an Eagle Ford Shale joint venture transaction. Pursuant to the transaction, the Company entered into a purchase and sale agreement to sell 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds. Under the terms of the transaction, the purchaser also paid 75 percent (representing $886.8 million) of the Company's defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the period from June 2010 through December 2012. As of December 31, 2012, the purchaser's obligation has been satisfied. The Company also sold a 49.9 percent member interest in EFS Midstream LLC ("EFS Midstream"), an entity formed by the Company to own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play, to the purchaser for $46.4 million of cash proceeds and deferred a $46.2 million associated net gain. The Company does not have voting control of EFS Midstream and does not consolidate its financial statements.

EFS Midstream is obligated to construct midstream assets in the Eagle Ford Shale area. Construction of the midstream assets is continuing, with the majority of the construction expected to be completed by the end of 2013. Eleven of the 13 planned central gathering plants were completed as of December 31, 2012. EFS Midstream is providing gathering, treating and transportation services for the Company during a 20-year contractual term. During 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility that is being used to fund infrastructure investments that exceed its operating cash flows.

36

PIONEER NATURAL RESOURCES COMPANY

Barnett Shale

The Company has accumulated 93,000 gross acres in the liquid-rich Barnett Shale Combo area in North Texas. In addition, the Company has acquired approximately 340 square miles of proprietary 3-D seismic covering its acreage, which it is using to high-grade future drilling location selections. The Company's total lease holdings in the Barnett Shale play now approximate 149,000 gross acres (114,000 net acres).

During the first half of 2012, the Company had two drilling rigs and one Pioneer-owned fracture stimulation fleet operating in the field. During August 2012, the Company reduced to one drilling rig as a result of lower NGL and gas prices. The Company drilled 57 Barnett Shale Combo wells during 2012.

During the third quarter of 2012, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas, retained a capital markets advisor and actively solicited offers from interested purchasers of the Barnett Shale field assets. Those efforts were unsuccessful in attracting binding offers under acceptable terms to the Company. Since the Company was unable to dispose of its Barnett Shale assets under acceptable terms, in December 2012, the Company decided to retain the assets; therefore, as of December 31, 2012, the Barnett Shale assets and liabilities no longer qualified as held for sale or discontinued operations.

During 2013, the Company plans to increase from one drilling rig to two drilling rigs early in the second quarter. The Company expects to drill 55 wells in 2013 and incur capital expenditures of $185.0 million.

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 18 production wells and ten injection wells to develop this project. During the first quarter of 2012, the Company drilled an exploration well which was drilled from an onshore location to further 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. The well had a gross initial production rate of approximately 2,000 barrels of oil per day. The well will be production tested again this winter pending permanent onshore production facilities, for which an onshore development front-end engineering design (FEED) study has been initiated. In September 2012, the Company entered into a contract for a drilling rig that is currently drilling a second onshore well in the Torok formation to further appraise its resource potential.

During the first quarter of 2012, the Company also completed its first successful mechanically diverted fracture stimulation of a Nuiqsut interval well from the Oooguruk development facilities. Gross initial production from the test was at a rate of 4,000 barrels of oil per day. Based on the success of this fracture stimulation, the Company plans to fracture stimulate four new wells this winter using a similar completion design.

During 2013, the Company expects to incur capital expenditures of $190.0 million in Alaska to continue development with a one rig program at Oooguruk, mechanically fracture stimulate four wells this winter on the island drill site and to complete the other appraisal well in the Torok formation from the onshore drilling location.

International

During 2012, the Company's international operations were entirely located in offshore South Africa and during 2011, the Company's international operations were located in Tunisia and offshore South Africa. During August 2012 and February 2011, the Company completed the sale of Pioneer South Africa and Pioneer Tunisia, respectively, to different unaffiliated third parties. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the sale of Pioneer South Africa and Pioneer Tunisia. As a result of these sales, the Company no longer has operations outside the United States.

Selected Oil and Gas Information

The following tables set forth selected oil and gas information for the Company as of and for each of the years ended December 31, 2012, 2011 and 2010. Because of normal production declines, increased or decreased drilling activities and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

37

PIONEER NATURAL RESOURCES COMPANY

Production, price and cost data. The price that the Company receives for the oil and gas it produces is largely a function of market supply and demand. Demand is affected by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or gas can result in substantial price volatility. Historically, commodity prices have been volatile and the Company expects that volatility to continue in the future. A substantial or extended decline in oil or gas prices or poor drilling results could have a material adverse effect on the Company's financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and the Company's ability to access capital markets.

The following tables set forth production, price and cost data with respect to the Company's properties for 2012, 2011 and 2010. These amounts represent the Company's historical results from operations without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the respective years. The production amounts will not match the reserve volume tables in the "Unaudited Supplementary Information" section included in "Item 8. Financial Statements and Supplementary Data" because field fuel volumes are included in the reserve volume tables.

38

PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA

	Year Ended December 31, 2012
	United States							South Africa		Total
	Spraberry Field			Raton Field		Total
Production information:
Annual sales volumes:
Oil (MBBLs)	16,096			—		22,928		157		23,085
NGLs (MBBLs)	4,451			—		10,913		—		10,913
Gas (MMCF)	21,345			54,822		138,483		3,784		142,267
Total (MBOE)	24,104			9,137		56,921		787		57,708
Average daily sales volumes:
Oil (BBLs)	43,978			—		62,645		428		63,073
NGLs (BBLs)	12,160			—		29,816		—		29,816
Gas (MCF)	58,319			149,787		378,369		10,340		388,709
Total (BOE)	65,858			24,965		155,522		2,151		157,673
Average prices, including hedge results and amortization of deferred VPP revenue (a):
Oil (per BBL)	$	90.57		$	—	$	90.89	$	108.62	$	91.01
NGL (per BBL)	$	32.23		$	—	$	33.75	$	—	$	33.75
Gas (per MCF)	$	2.58		$	2.41	$	2.60	$	8.50	$	2.75
Revenue (per BOE)	$	68.72		$	14.48	$	49.40	$	62.48	$	49.57
Average prices, excluding hedge results and amortization of deferred VPP revenue (a):
Oil (per BBL)	$	87.95		$	—	$	89.19	$	108.62	$	89.32
NGL (per BBL)	$	32.23		$	—	$	33.75	$	—	$	33.75
Gas (per MCF)	$	2.58		$	2.41	$	2.60	$	8.50	$	2.75
Revenue (per BOE)	$	66.97		$	14.48	$	48.71	$	62.48	$	48.90
Average costs (per BOE):
Production costs:
Lease operating	$	11.34		$	6.47	$	8.53	$	2.86	$	8.46
Third-party transportation charges	$	0.17		$	3.12	$	1.31	$	—	$	1.29
Net natural gas plant/gathering	$	(0.49	)	$	1.82	$	0.47	$	—	$	0.47
Workover	$	1.71		$	—	$	0.85	$	—	$	0.84
Total	$	12.73		$	11.41	$	11.16	$	2.86	$	11.06
Production and ad valorem taxes:
Ad valorem	$	1.78		$	0.17	$	1.26	$	—	$	1.24
Production	$	3.47		$	0.11	$	2.04	$	—	$	2.01
Total	$	5.25		$	0.28	$	3.30	$	—	$	3.25
Depletion expense	$	15.58		$	19.52	$	13.61	$	—	$	13.42

 ____________________

(a) The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its hedging activities at a field level. As of December 31, 2012, the Company has no further obligation to deliver oil under the VPP obligation.

39

PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA - (Continued)

	Year Ended December 31, 2011
	United States							South Africa		Tunisia			Total
	Spraberry Field			Raton Field		Total
Production information:
Annual sales volumes:
Oil (MBBLs)	10,011			—		14,825		193		201			15,219
NGLs (MBBLs)	3,844			—		8,208		—		—			8,208
Gas (MMCF)	15,899			58,601		125,516		7,508		181			133,205
Total (MBOE)	16,505			9,767		43,953		1,445		229			45,627
Average daily sales volumes:
Oil (BBLs)	27,428			—		40,618		530		547			41,695
NGLs (BBLs)	10,530			—		22,487		—		—			22,487
Gas (MCF)	43,559			160,550		343,879		20,570		496			364,945
Total (BOE)	45,218			26,758		120,418		3,958		630			125,006
Average prices, including hedge results and amortization of deferred VPP revenue (a):
Oil (per BBL)	$	95.93		$	—	$	96.60	$	108.14	$	99.03		$	96.78
NGL (per BBL)	$	42.38		$	—	$	46.27	$	—	$	—		$	46.27
Gas (per MCF)	$	3.44		$	3.81	$	3.84	$	7.62	$	13.04		$	4.07
Revenue (per BOE)	$	71.37		$	22.86	$	52.19	$	54.09	$	96.29		$	52.48
Average prices, excluding hedge results and amortization of deferred VPP revenue (a):
Oil (per BBL)	$	91.44		$	—	$	91.35	$	108.14	$	99.03		$	91.67
NGL (per BBL)	$	42.38		$	—	$	46.27	$	—	$	—		$	46.27
Gas (per MCF)	$	3.44		$	3.81	$	3.84	$	7.62	$	13.04		$	4.07
Revenue (per BOE)	$	68.65		$	22.86	$	50.42	$	54.09	$	96.29		$	50.77
Average costs (per BOE):
Production costs:
Lease operating	$	10.40		$	6.49	$	8.08	$	2.35	$	7.61		$	7.90
Third-party transportation charges	$	—		$	3.01	$	1.12	$	—	$	1.91		$	1.22
Net natural gas plant/gathering	$	(1.45	)	$	2.15	$	0.15	$	—	$	—		$	0.14
Workover	$	1.74		$	—	$	0.82	$	—	$	(0.27	)	$	0.78
Total	$	10.69		$	11.65	$	10.17	$	2.35	$	9.25		$	10.04
Production and ad valorem taxes:
Ad valorem	$	1.73		$	0.41	$	1.24	$	—	$	—		$	1.20
Production	$	3.87		$	0.31	$	2.11	$	—	$	—		$	2.04
Total	$	5.60		$	0.72	$	3.35	$	—	$	—		$	3.24
Depletion expense	$	11.41		$	14.46	$	12.55	$	29.00	$	—		$	13.01

 _____________________

(a) The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its hedging activities at a field level.

40

PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA - (Continued)

	Year Ended December 31, 2010
	United States							South Africa		Tunisia		Total
	Spraberry Field			Raton Field		Total
Production information:
Annual sales volumes:
Oil (MBBLs)	6,314			—		10,297		225		1,781		12,303
NGLs (MBBLs)	3,725			—		7,203		—		—		7,203
Gas (MMCF)	14,242			62,311		122,369		10,862		1,040		134,271
Total (MBOE)	12,413			10,385		37,895		2,035		1,954		41,885
Average daily sales volumes:
Oil (BBLs)	17,300			—		28,211		616		4,880		33,707
NGLs (BBLs)	10,206			—		19,736		—		—		19,736
Gas (MCF)	39,020			170,716		335,256		29,760		2,849		367,865
Total (BOE)	34,009			28,453		103,823		5,576		5,355		114,754
Average prices, including hedge results and amortization of deferred VPP revenue (a):
Oil (per BBL)	$	91.53		$	—	$	90.56	$	78.07	$	78.42	$	88.57
NGL (per BBL)	$	33.11		$	—	$	38.14	$	—	$	—	$	38.14
Gas (per MCF)	$	3.41		$	4.20	$	4.18	$	6.20	$	11.25	$	4.40
Revenue (per BOE)	$	60.40		$	25.19	$	45.34	$	41.74	$	77.46	$	46.67
Average prices, excluding hedge results and amortization of deferred VPP revenue (a):
Oil (per BBL)	$	77.24		$	—	$	74.21	$	78.07	$	78.42	$	74.89
NGL (per BBL)	$	33.11		$	—	$	37.12	$	—	$	—	$	37.12
Gas (per MCF)	$	3.41		$	4.20	$	4.15	$	6.20	$	11.25	$	4.37
Revenue (per BOE)	$	53.14		$	25.19	$	40.61	$	41.74	$	77.46	$	42.39
Average costs (per BOE):
Production costs:
Lease operating	$	11.40		$	6.11	$	7.74	$	0.68	$	4.98	$	7.28
Third-party transportation charges	$	—		$	2.35	$	0.87	$	—	$	1.50	$	0.86
Net natural gas plant/gathering	$	(1.66	)	$	1.93	$	0.08	$	—	$	—	$	0.08
Workover	$	1.88		$	0.07	$	0.92	$	—	$	0.36	$	0.85
Total	$	11.62		$	10.46	$	9.61	$	0.68	$	6.84	$	9.07
Production and ad valorem taxes:
Ad valorem	$	2.30		$	0.46	$	1.49	$	—	$	—	$	1.35
Production	$	3.53		$	0.52	$	1.47	$	—	$	—	$	1.33
Total	$	5.83		$	0.98	$	2.96	$	—	$	—	$	2.68
Depletion expense	$	9.02		$	14.39	$	12.40	$	36.50	$	12.07	$	13.56

 ____________________

(a) The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its hedging activities at a field level.

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PIONEER NATURAL RESOURCES COMPANY

Productive wells. Productive wells consist of producing wells and wells capable of production, including shut-in wells and gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. One or more completions in the same well bore are counted as one well. Any well in which one of the multiple completions is an oil completion is classified as an oil well. As of December 31, 2012, the Company owned interests in two gross wells containing multiple completions.

The following table sets forth the number of productive oil and gas wells attributable to the Company's properties as of December 31, 2012, 2011 and 2010:

PRODUCTIVE WELLS

	Gross Productive Wells			Net Productive Wells
	Oil	Gas	Total	Oil	Gas	Total
December 31, 2012	6,703	5,306	12,009	5,960	4,755	10,715
December 31, 2011	6,111	5,004	11,115	5,525	4,505	10,030
December 31, 2010	5,566	4,842	10,408	4,779	4,350	9,129

Leasehold acreage. The following table sets forth information about the Company's developed, undeveloped and royalty leasehold acreage as of December 31, 2012:

LEASEHOLD ACREAGE

	Developed Acreage		Undeveloped Acreage		Royalty Acreage
	Gross Acres	Net Acres	Gross Acres	Net Acres
Onshore	1,690,423	1,437,950	1,492,469	997,269	307,301
Offshore	—	—	—	—	5,000
	1,690,423	1,437,950	1,492,469	997,269	312,301

The following table sets forth the expiration dates of the leases on the Company's gross and net undeveloped acres as of December 31, 2012:

	Acres Expiring (a)
	Gross	Net
2013	153,898	103,907
2014	195,783	137,503
2015	181,666	129,027
2016	780,814	494,264
2017	147,048	102,838
Thereafter	33,260	29,730
Total	1,492,469	997,269

 _____________________

(a) Acres expiring are based on contractual lease maturities.

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PIONEER NATURAL RESOURCES COMPANY

Drilling and other exploratory and development activities. The following table sets forth the number of gross and net wells drilled by the Company during 2012, 2011 and 2010 that were productive or dry holes. This information should not be considered indicative of future performance, nor should it be assumed that there was any correlation between the number of productive wells drilled and the oil and gas reserves generated thereby or the costs to the Company of productive wells compared to the costs of dry holes.

DRILLING ACTIVITIES

	Gross Wells						Net Wells
	Year Ended December 31,						Year Ended December 31,
	2012		2011		2010		2012		2011		2010
Productive wells:
Development	659		725		436		595		661		380
Exploratory	223		167		39		144		115		24
Dry holes:
Development	10		11		3		6		10		3
Exploratory	6		1		3		6		1		1
Total	898		904		481		751		787		408
Success ratio (a)	98	%	99	%	99	%	98	%	99	%	99	%

 ______________________

(a) Represents the ratio of those wells that were successfully completed as producing wells or wells capable of producing to total wells drilled and evaluated.

Present activities. The following table sets forth information about the Company's wells that were in process of being drilled as of December 31, 2012:

	Gross Wells	Net Wells
Development	140	130
Exploratory	60	42
Total	200	172

ITEM 3. 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. See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding legal proceedings involving the Company.

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, as amended by the Mine Improvement and New Emergency Response Act of 2006. 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 Annual Report filed on Form 10-K.

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PIONEER NATURAL RESOURCES COMPANY

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company's common stock is listed and traded on the NYSE under the symbol "PXD." The Company's board of directors (the "Board") declared dividends to the holders of the Company's common stock of $.04 per share during each of the first and third quarters of the years ended December 31, 2012 and 2011. The Board intends to consider the payment of dividends to the holders of the Company's common stock in the future. The declaration and payment of future dividends, however, will be at the discretion of the Board and will depend on, among other things, the Company's earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the Board deems relevant.

The following table sets forth quarterly high and low prices of the Company's common stock and dividends declared per share for the years ended December 31, 2012 and 2011:

	High		Low		Dividends Declared Per Share
Year ended December 31, 2012
Fourth quarter	$	110.67	$	99.75	$	—
Third quarter	$	115.69	$	82.18	$	0.04
Second quarter	$	117.05	$	77.41	$	—
First quarter	$	119.19	$	90.26	$	0.04
Year ended December 31, 2011
Fourth quarter	$	97.10	$	58.63	$	—
Third quarter	$	99.64	$	65.73	$	0.04
Second quarter	$	106.07	$	82.41	$	—
First quarter	$	104.29	$	85.90	$	0.04

On February 8, 2013, the last reported sales price of the Company's common stock, as reported in the NYSE composite transactions, was $128.97 per share.

As of February 8, 2013, the Company's common stock was held by 14,429 holders of record.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company's purchases of its common stock during the three months ended December 31, 2012:

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
October 2012	532	$	104.40	—
November 2012	—	$	—	—
December 2012	64,373	$	102.41	—
Total	64,905	$	102.43	—	$	—

 ______________________

(a) Consists of shares withheld to satisfy tax withholding on employees' share-based awards.

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PIONEER NATURAL RESOURCES COMPANY

ITEM 6. SELECTED FINANCIAL DATA

The following selected consolidated financial data of the Company as of and for each of the five years ended December 31, 2012 should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 8. Financial Statements and Supplementary Data."

	Year Ended December 31,
	2012		2011		2010		2009			2008
	(in millions, except per share data)
Statements of Operations Data:
Oil and gas revenues (a)	$	2,811.7	$	2,294.1	$	1,718.3	$	1,402.4		$	1,893.4
Total revenues (b)	$	3,228.3	$	2,751.5	$	2,381.7	$	1,290.4		$	1,920.1
Total costs and expenses (c)	$	2,948.3	$	2,095.1	$	1,600.1	$	1,515.6		$	1,675.3
Income (loss) from continuing operations	$	187.7	$	458.8	$	511.9	$	(142.0	)	$	144.8
Income from discontinued operations, net of tax (d)	$	55.1	$	423.2	$	134.1	$	99.7		$	86.8
Net income (loss) attributable to common stockholders	$	192.3	$	834.5	$	605.2	$	(52.1	)	$	210.0
Income (loss) from continuing operations attributable to common stockholders per share:
Basic	$	1.10	$	3.45	$	4.00	$	(1.33	)	$	1.02
Diluted	$	1.07	$	3.39	$	3.96	$	(1.33	)	$	1.02
Net income (loss) attributable to common stockholders per share:
Basic	$	1.54	$	7.01	$	5.14	$	(0.46	)	$	1.76
Diluted	$	1.50	$	6.88	$	5.08	$	(0.46	)	$	1.76
Dividends declared per share	$	0.08	$	0.08	$	0.08	$	0.08		$	0.30
Balance Sheet Data (as of December 31):
Total assets	$	13,069.0	$	11,447.2	$	9,679.1	$	8,867.3		$	9,161.8
Long-term obligations	$	6,166.9	$	4,726.5	$	4,683.9	$	4,653.0		$	4,787.2
Total stockholders' equity	$	5,867.3	$	5,651.1	$	4,226.0	$	3,643.0		$	3,679.6

 ______________________

(a) The Company's oil and gas revenues for 2012, as compared to those of 2011, increased by $517.6 million (or 23 percent) due to increases in oil, NGL, and gas sales volumes. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for discussions about oil and gas revenues and factors impacting the comparability of such revenues.

(b) The Company recognized $330.3 million of net derivative gains in its total revenues for 2012, including $65.4 million of noncash MTM losses, as compared to $392.8 million of net derivative gains during 2011, including $225.5 million of noncash MTM gains. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Notes B and E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information about the Company's derivative contracts and associated accounting methods. The Company also recognized $138.9 million of net hurricane activity gains during 2010, primarily associated with East Cameron 322 insurance recoveries, and $17.3 million of net hurricane activity charges during 2009. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the East Cameron 322 reclamation and abandonment project.

(c) During 2012, the Company recorded $604.4 million of pretax noncash impairment and abandonment charges to reduce the carrying value of its Barnett Shale field assets. During 2011, the Company recorded an impairment charge of $354.4 million related to its Edwards and Austin Chalk net assets in South Texas. See Note D of Notes to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data." During 2009 and 2008, the Company recorded impairment charges of $21.1 million and $89.8 million, respectively, to reduce its Uinta/Piceance field's carrying value.

(d) During December 2011, the Company committed to a plan to divest Pioneer South Africa and in August 2012, the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, resulting in a pretax gain of $28.6 million. During December 2010, the Company committed to a plan to sell Pioneer Tunisia and in February 2011 completed the sale of the Company's share holdings in Pioneer Tunisia to an unaffiliated party for net cash proceeds of $802.5 million, excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million. During 2010, the Company received $35.3

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PIONEER NATURAL RESOURCES COMPANY

million of interest on excess royalties paid during the period from January 1, 2003 through December 31, 2005 on oil and gas production from its deepwater Gulf of Mexico properties, which were sold in 2006. During 2009, the Company recorded $119.3 million of pretax income for the recovery of the excess royalties previously mentioned and a $17.5 million pretax gain, primarily from the sale of substantially all of its Gulf of Mexico shelf properties. The results of operations of these properties, and certain other properties sold during the periods presented are classified as discontinued operations in accordance with GAAP. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's discontinued operations.

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PIONEER NATURAL RESOURCES COMPANY

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financial and Operating Performance

Pioneer's financial and operating performance for 2012 included the following highlights:

• Earnings attributable to common stockholders was $192.3 million ($1.50 per diluted share) for the year ended December 31, 2012, as compared to $834.5 million ($6.88 per diluted share) in 2011. The decrease in earnings attributable to common stockholders is primarily due to:

• a $368.0 million decrease in income from discontinued operations, net of associated income taxes, primarily attributable to a $645.2 million pretax gain on the sale of Pioneer Tunisia during February 2011;

• a $231.9 million increase in DD&A, primarily due to a 29 percent increase in sales volumes;

• a $188.5 million increase in oil and gas production costs, primarily due to increases in lease operating expenses as a result of higher sales volumes and inflation of oilfield service costs;

• a $178.2 million increase in impairment provisions related to a $532.6 million impairment in the Barnett Shale field associated with reductions in management's commodity price outlook (see Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and "Results of Operations" below) compared to a $354.4 million impairment related to Edwards and Austin Chalk net assets in South Texas in 2011;

• an $85.0 million increase in exploration and abandonments expense, primarily due to impairment of unproved gas prospects in the Barnett Shale field;

• a $62.5 million decrease in net derivative gains, primarily due to reduced interest rate derivative gains during 2012; and

• a $55.1 million increase in general and administrative expenses due to increases in compensation expense related to a 16 percent increase in office employees supporting the Company's capital expansion initiatives, partially offset by

• a $517.6 million increase in oil and gas revenues as a result of increased sales volumes, partially offset by lower average sales prices; and

• a $105.3 million decrease in income tax provision.

• Daily sales volumes from continuing operations increased on a BOE basis by 29 percent to 155,522 BOEPD during 2012, as compared to 120,418 BOEPD during 2011, primarily due to the success of the Company's drilling programs;

• Average reported oil, NGL and gas prices from continuing operations decreased during 2012 to $90.89 per BBL, $33.75 per BBL and $2.60 per MCF, respectively, as compared to respective average reported prices of $96.60 per BBL, $46.27 per BBL and $3.84 per MCF during 2011;

• Average oil and gas production costs per BOE from continuing operations increased during 2012 to $11.16 as compared to per BOE costs of $10.17 during 2011, primarily due to increases in lease operating expenses, third party transportation charges and net natural gas plant charges. The increase in lease operating expenses is primarily due to an increase in salt water disposal costs (principally comprised of water hauling fees) during 2012. The increase in third-party transportation costs is primarily due to gathering, treating and transportation costs associated with increasing sales volumes in the Eagle Ford Shale field. Net natural gas plant charges increased primarily as a result of lower gas and NGL prices being realized on third-party volumes that are retained as processing fees in Company-owned facilities. See "Results of Operations" below for more information about changes in production costs;

• Net cash provided by operating activities increased by $307.9 million, or 20 percent, to $1.8 billion for 2012, as compared to $1.5 billion during 2011, primarily due to the increases in oil and gas sales volumes and realized derivative gains;

• During April 2012, the Company acquired 100 percent of the share capital of Industrial Sands Holding Company and its wholly-owned subsidiary, Premier Silica. Premier Silica's core business is the operation of mines and processing facilities that produce, process and sell sand, primarily to upstream oil and gas companies for proppant used in the fracture stimulation of oil and gas wells in the United States. The aggregate purchase price of Premier Silica was $297.1 million and was funded from available cash and borrowings under the Company's credit facility;

• During May 2012, the Company was rated investment grade by a second credit rating agency after having been similarly rated investment grade by another credit rating agency during 2011;

• During the December 2012, the Company entered into the First Amendment to Second Amended and Restated 5-Year Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that increased the Company's borrowing capacity under the Credit Facility to $1.5 billion and extended its maturity to December 2017;

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PIONEER NATURAL RESOURCES COMPANY

• Long-term debt increased by $1.2 billion and the Company's cash and cash equivalents decreased by $308.1 million during 2012; and

• As of December 31, 2012, the Company's net debt to book capitalization was 37 percent, as compared to 26 percent as of December 31, 2011.

During the first quarter of 2013, the following significant events occurred:

• 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. At closing, Sinochem will pay $522.0 million in cash to Pioneer, 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 and third party approvals.

• In January and February 2013, holders of $240.6 million principal amount of the Company's 2.875% Convertible Senior Notes due 2038 (the "Convertible Senior Notes") exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock. In general, upon conversion of a Convertible Senior Note, the holder will receive cash equal to the principal amount of the Convertible Senior Note 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 8. Financial Statements and Supplementary Data" for additional information about the Convertible Senior Notes.

First Quarter 2013 Outlook

Based on current estimates, the Company expects that first quarter 2013 production will average 165,000 to 170,000 BOEPD.

First quarter 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 prices for oil and gas. DD&A expense is expected to average $13.50 to $15.50 per BOE.

Total exploration and abandonment expense for the quarter is expected to be $25 million to $35 million. General and administrative expense is expected to be $60 million to $65 million. Interest expense is expected to be $53 million to $58 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 derivative MTM adjustments, is expected to be $8 million to $11 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company's first quarter effective income tax rate is expected to range from 35 percent to 40 percent, assuming current capital spending plans and no significant derivative MTM changes in the Company's derivative position. Cash income taxes are expected to be $2 million to $7 million and are primarily attributable to state taxes.

2013 Capital Budget

Pioneer's capital program for 2013 totals $3.0 billion, consisting of $2.75 billion for drilling operations, including budgeted land capital for existing assets, and $240 million for other property, plant and equipment. The 2013 budget excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical general and administrative expense and assumes the aforementioned sale of a 40 percent interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field will close on or about June 1, 2013.

The 2013 drilling capital of $2.75 billion continues to be focused on oil- and liquids-rich drilling, with 81 percent of the capital allocated to the Spraberry field, including the horizontal Wolfcamp Shale play, and the Eagle Ford Shale play. Following is a breakdown of the forecasted spending by asset area:

• Spraberry field - $1.65 billion, including (i) $425 million for drilling and facilities capital in the southern Wolfcamp joint interest area, (ii) $400 million of horizontal appraisal drilling capital associated with the Company's planned two-year $1 billion appraisal program for its northern Wolfcamp/Spraberry acreage, (iii) $625 million for vertical drilling and (iv) $200 million of infrastructure additions and automation projects;

• Eagle Ford Shale – $575 million;

• Barnett Shale Combo play – $185 million;

• Alaska – $190 million; and

48

PIONEER NATURAL RESOURCES COMPANY

• Other spending – $150 million, including land capital for existing assets.

Pioneer's budgeted expenditures for other property, plant and equipment in 2013 include:

• Buildings and other facilities – $145 million;

• Brady sand mine expansion – $70 million; and

• Vertical integration capital – $25 million.

The 2013 capital budget is expected to be funded from a combination of cash and cash equivalents, operating cash flow, borrowings under the Credit Facility, proceeds from the sale of joint interests or nonstrategic assets, and issuances of debt or equity securities.

Acquisitions

During 2012, 2011 and 2010, the Company spent $157.5 million, $131.9 million and $181.6 million, respectively, to acquire primarily undeveloped acreage for future exploitation and exploration activities. The 2012 acquisitions primarily increased the Company's acreage positions in the West Texas Spraberry field. The 2011 and 2010 acquisitions primarily increased the Company's acreage positions in the South Texas Eagle Ford Shale play, Barnett Shale play and West Texas Spraberry field. Additionally, in 2012 the Company acquired Premier Silica for $297.1 million. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's acquisitions.

Divestitures and Discontinued Operations

Barnett Shale. During the third quarter of 2012, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas. In connection therewith, the Company classified its (i) Barnett Shale assets and liabilities as discontinued operations held for sale in the Company's consolidated balance sheet as of September 30, 2012, and (ii) Barnett Shale results of operations as income or loss from discontinued operations, net of tax, in the consolidated statements of operations for the three and nine months ended September 30, 2012 and 2011.

The Company retained a capital markets advisor during the third quarter of 2012 and actively solicited offers from interested purchasers of the Barnett Shale field assets. Those efforts were unsuccessful in attracting binding offers under acceptable terms to the Company. Since the Company was unable to dispose of its Barnett Shale field assets under acceptable terms, in December 2012, the Company decided to retain the assets; therefore, the Barnett Shale assets and liabilities no longer qualified as held for sale or discontinued operations. Accordingly, all amounts related to the Barnett Shale that were previously reported as (i) discontinued operations held for sale were reclassified to continuing operations at December 31, 2012, (ii) results from the Barnett Shale operations were recorded to continuing operations for the quarter ended December 31, 2012 and results included in discontinued operations were reclassified to income from continuing operations for the nine months ended September 30, 2012, and (iii) amounts in periods prior to 2012 that were reflected in discontinued operations were reclassified to continuing operations. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's discontinued operations.

Pioneer South Africa. During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest Pioneer South Africa. The assets and liabilities of Pioneer South Africa are classified as discontinued operations held for sale in the Company's accompanying consolidated balance sheet as of December 31, 2011. During the first quarter of 2012, the Company agreed to sell 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 pretax gain of $28.6 million. Pioneer South Africa's historical results of operations, and the related gain recorded on the disposition of Pioneer South Africa, are reported as discontinued operations, net of tax in the Company's accompanying consolidated statements of operations.

Pioneer Tunisia. During December 2010, the Company committed to a plan to sell Pioneer Tunisia. In February 2011 the Company sold its share holdings in Pioneer Tunisia for cash proceeds of $802.5 million, excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million. Pioneer Tunisia's historical results of operations, and the related gain recorded on the disposition of Pioneer Tunisia, are reported as discontinued operations, net of tax in the Company's accompanying consolidated statements of operations.

Eagle Ford Shale. In June 2010, the Company entered into an Eagle Ford Shale joint venture. Associated therewith, the Company sold 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds. Under the terms of the transaction, the purchaser also paid 75 percent (representing $886.8

49

PIONEER NATURAL RESOURCES COMPANY

million) of the Company's defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the period from June 2010 through December 2012.

Uinta/Piceance. During the first half of 2010, the Company sold certain proved and unproved oil and gas properties in the Uinta/Piceance area for net proceeds of $11.8 million and the assumption by the purchaser of certain asset retirement obligations, resulting in a pretax gain of $17.3 million.

Results of Operations

Oil and gas revenues. Oil and gas revenues from continuing operations totaled $2.8 billion, $2.3 billion and $1.7 billion during 2012, 2011 and 2010, respectively.

The increase in 2012 oil and gas revenues relative to 2011 is reflective of 54 percent, 33 percent and 10 percent increases in oil, NGL and gas sales volumes, respectively. Partially offsetting the effects of these production increases were declines of six percent, 27 percent and 32 percent in average reported oil, NGL and gas prices, respectively.

The increase in 2011 oil and gas revenues relative to 2010 is reflective of seven percent and 21 percent increases in average reported oil and NGL prices, respectively and 44 percent, 14 percent and three percent increases in oil, NGL, and gas sales volumes, respectively. These increases were partially offset by an eight percent decrease in average reported gas prices.

The following table provides average daily sales volumes from continuing operations for 2012, 2011 and 2010:

	Year Ended December 31,
	2012	2011	2010
Oil (BBLs)	62,645	40,618	28,211
NGLs (BBLs)	29,816	22,487	19,736
Gas (MCF)	378,369	343,879	335,256
Total (BOE)	155,522	120,418	103,823

Average daily BOE sales volumes in 2012 and 2011 increased by 29 percent and 16 percent, respectively, as compared to the daily sales volumes in the respective prior years, principally due to the Company's successful drilling programs and declines in scheduled VPP deliveries. Oil volumes delivered under the Company's VPPs decreased by six percent and 45 percent, respectively, during 2012 and 2011. All VPP production volumes have been delivered as of December 31, 2012 and there are no further obligations under the VPP contracts.

Production growth for 2012, as compared to 2011, 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 average 2012 sales volumes by approximately 1,450 BOEPD. New Spraberry field gas processing facilities are being built and are expected to be on production in April of 2013.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides average daily sales volumes from discontinued operations by geographic area and in total during 2012, 2011 and 2010:

	Year Ended December 31,
	2012	2011	2010
Oil (BBLs):
South Africa	428	530	616
Tunisia	—	547	4,880
Worldwide	428	1,077	5,496
Gas (MCF):
South Africa	10,340	20,570	29,760
Tunisia	—	496	2,849
Worldwide	10,340	21,066	32,609
Total (BOE):
South Africa	2,151	3,958	5,576
Tunisia	—	630	5,355
Worldwide	2,151	4,588	10,931

In South Africa, sales volumes in 2012 declined by 46 percent from 2011 primarily due to the sale of Pioneer South Africa during August 2012 compared to a full year of production in 2011.

The oil, NGL and gas prices that the Company reports are based on the market prices received for the commodities adjusted for transfers of the Company's deferred hedge gains and losses from the effective portions of the discontinued deferred hedges included in accumulated other comprehensive income (loss) – net deferred hedge gains (losses), net of tax ("AOCI – Hedging") and the amortization of deferred VPP revenue. See "Derivative activities" and "Deferred revenue" discussion below for additional information regarding the Company's cash flow hedging activities and the amortization of deferred VPP revenue.

The following table provides average reported prices from continuing operations (including deferred hedge gains and losses and the amortization of deferred VPP revenue) and average realized prices from continuing operations (excluding deferred hedge gains and losses and the amortization of deferred VPP revenue) for 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
Average reported prices:
Oil (per BBL)	$	90.89	$	96.60	$	90.56
NGL (per BBL)	$	33.75	$	46.27	$	38.14
Gas (per MCF)	$	2.60	$	3.84	$	4.18
Total (per BOE)	$	49.40	$	52.19	$	45.34
Average realized prices:
Oil (per BBL)	$	89.19	$	91.35	$	74.21
NGL (per BBL)	$	33.75	$	46.27	$	37.12
Gas (per MCF)	$	2.60	$	3.84	$	4.15
Total (per BOE)	$	48.71	$	50.42	$	40.61

Derivative activities.The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts in order to (i) reduce the effect of price volatility on the commodities the Company produces, 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. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing derivative contracts. Changes in the fair value of effective cash flow hedges prior to the Company's discontinuance of hedge accounting were recorded as a component of AOCI – Hedging in the equity section of the Company's consolidated balance sheets, and were transferred to earnings during the same periods in which the hedged transactions were recognized in the Company's earnings. Since February 1, 2009, the Company has recognized all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.

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PIONEER NATURAL RESOURCES COMPANY

The following table summarizes the transfers of deferred hedge gains and losses associated with oil, NGL and gas cash flow hedges from AOCI – Hedging to oil, NGL and gas revenues for the years ending December 31, 2012, 2011 and 2010 (in thousands):

	Year Ended December 31,
	2012			2011		2010
Increase (decrease) to oil revenue from AOCI - Hedging transfers	$	(3,156	)	$	32,918	$	78,052
Increase to NGL revenue from AOCI - Hedging transfers	—			—		7,297
Increase to gas revenue from AOCI - Hedging transfers	—			—		3,691
Total	$	(3,156	)	$	32,918	$	89,040

Deferred revenue.During 2012, 2011 and 2010, the Company's amortization of deferred VPP revenue increased annual oil revenues by $42.1 million, $45.0 million and $90.2 million, respectively. All VPP production volumes have been delivered and there are no further obligations under VPP contracts or deferred revenue as of December 31, 2012. See the revenue recognition section of Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for specific information regarding the Company's deferred revenue.

Interest and other income. The Company's interest and other income from continuing operations totaled $28.3 million, $66.9 million and $57.0 million during 2012, 2011 and 2010, respectively. The $38.6 million decrease during 2012, as compared to 2011, is primarily attributable to a $27.9 million decrease in third-party income from vertical integration services, primarily due to increases in costs of services and idle equipment during the fourth quarter of 2012 and a $9.6 million decrease in Alaskan Petroleum Production Tax ("PPT") credit recoveries. The $9.9 million increase during 2011, as compared to 2010, is primarily attributable to a $15.8 million increase in third-party income associated with vertical integration services and a $2.7 million increase in equity earnings from EFS Midstream, partially offset by an $8.7 million decrease in PPT credit recoveries.

Derivative gains (losses), net. The following table summarizes the Company's net derivative gains or losses for the years ending December 31, 2012, 2011 and 2010 (in thousands):

	Year Ended December 31,
	2012			2011			2010
Unrealized changes in fair value:
Oil derivative gains	$	217,765		$	68,376		$	41,094
NGL derivative gains	1,209			10,243			10,690
Gas derivative gains (losses)	(290,058		)	179,787			277,585
Diesel derivative gains (losses)	(270		)	270			—
Marketing derivative losses	(22		)	—			—
Interest rate derivative gains (losses)	5,930			(33,206		)	35,040
Total unrealized derivative gains (losses), net (a)	(65,446		)	225,470			364,409
Cash settled changes in fair value:
Oil derivative gains (losses)	4,139			(36,664		)	(27,305		)
NGL derivative gains (losses)	13,403			(15,418		)	(7,180		)
Gas derivative gains	402,981			183,010			119,417
Diesel derivative gains	3,497			67			—
Marketing derivative gains (losses)	36			(17		)	—
Interest rate derivative gains (losses)	(28,359		)	36,304			(907		)
Total cash derivative gains, net	395,697			167,282			84,025
Total derivative gains, net	$	330,251		$	392,752		$	448,434

 __________________

(a) Unrealized changes in fair value are subject to continuing market risk.

Gain (loss) on disposition of assets. The Company recorded net gains of $58.1 million and $19.1 million during 2012 and 2010, respectively, and a net loss on the disposition of assets of $3.6 million during 2011.

During 2012, the Company recorded a $12.6 million pretax gain on the sale of its interest in the Cosmopolitan Unit in the Cook Inlet of Alaska and a $42.6 million pretax gain on the sale of a portion of its interest in an unproved oil and gas property in

52

PIONEER NATURAL RESOURCES COMPANY

the Eagle Ford Shale field. During 2011, the net loss was primarily associated with losses on the sales of excess materials and supplies inventory, partially offset by gains on the sale of certain unproved properties. During 2010, the Company recorded a $17.3 million net gain associated with the sale of proved and unproved oil and gas properties in the Uinta/Piceance area and a $6.0 million net gain associated with the Eagle Ford Shale joint venture transaction, partially offset by net losses primarily associated with the sale of excess lease and well equipment inventory.

Hurricane activity, net. The Company recorded net hurricane activity gains of $1.5 million and $138.9 million during 2011 and 2010. The Company did not record any hurricane activity in 2012. As a result of Hurricane Rita in September 2005, the Company's East Cameron 322 facility, located on the Gulf of Mexico shelf, was completely destroyed. Operations to reclaim and abandon the East Cameron 322 facility began in 2006 and were completed during 2011. In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues for the cost of reclamation and abandonment of the East Cameron 322 facility. During the fourth quarter of 2010, the Company and the insurance carriers agreed to settle an insurance policy dispute, resulting in an additional payment to the Company of $140.1 million during November 2010. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's East Cameron platform facilities reclamation and abandonment activities.

Oil and gas production costs. The Company's oil and gas production costs from continuing operations totaled $635.6 million, $447.1 million and $364.8 million during 2012, 2011 and 2010, respectively. In general, lease operating expenses and workover expenses 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 gathering and processing of third party gas in Company-owned facilities.

Total oil and gas production costs per BOE for the year ended December 31, 2012 increased by 10 percent as compared to 2011. The increase in production costs per BOE during 2012 is primarily reflective of increases in lease operating expenses, third-party transportation charges and net natural gas plant/gathering charges. Lease operating costs increased during 2012 primarily due to a $0.51 per BOE increase in salt water disposal costs (principally comprised of water hauling fees). The $0.19 per BOE increase in third-party transportation charges during 2012 is primarily due to gathering, treating and transportation costs associated with increasing sales volumes from the Company's successful drilling program in the Eagle Ford Shale field. Net natural gas plant charges increased by $0.32 per BOE during 2012, primarily due to a reduction in third-party revenues from processing third-party gas volumes in Company-owned facilities as a result of lower gas and NGL prices being realized on the volumes retained as a processing fee.

During 2011, total production costs per BOE increased by six percent as compared to 2010. The increase in production costs per BOE is primarily due to (i) increased third-party transportation and processing charges associated with increasing Eagle Ford Shale production, (ii) repairs associated with severe winter weather disruptions encountered during the first quarter of 2011 and (iii) inflation in well servicing costs, partially offset by reductions in VPP delivery commitments and decreased workover costs.

The following table provides the components of the Company's total production costs per BOE for 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
Lease operating expenses	$	8.53	$	8.08	$	7.74
Third-party transportation charges	1.31		1.12		0.87
Net natural gas plant/gathering charges	0.47		0.15		0.08
Workover costs	0.85		0.82		0.92
Total production costs	$	11.16	$	10.17	$	9.61

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $187.8 million during 2012, as compared to $147.7 million and $112.1 million for 2011 and 2010, respectively. In general, production taxes 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. During 2012, the Company's production taxes per BOE decreased by three percent as compared to 2011, primarily reflecting the impact of lower oil and NGL prices on production taxes. On a per BOE basis, ad valorem taxes increased two percent as compared to 2011. During 2011, the Company's production taxes per BOE increased 44 percent over 2010, primarily reflecting the impact of higher oil and NGL prices on production taxes, while ad valorem taxes decreased by 17 percent, which is primarily a result of an increase in sales volumes from new wells first brought on production during 2011.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides the Company's production and ad valorem taxes per BOE from continuing operations and total production and ad valorem taxes per BOE from continuing operations for 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
Production taxes	$	2.04	$	2.11	$	1.47
Ad valorem taxes	1.26		1.24		1.49
Total ad valorem and production taxes	$	3.30	$	3.35	$	2.96

Depletion, depreciation and amortization expense. The Company's total DD&A expense from continuing operations was $810.2 million ($14.23 per BOE), $578.3 million ($13.16 per BOE), and $499.9 million ($13.19 per BOE) for 2012, 2011 and 2010, respectively. Depletion expense on oil and gas properties, the largest component of DD&A expense, was $13.61, $12.55 and $12.40 per BOE during 2012, 2011 and 2010, respectively.

During 2012, the eight percent increase in per BOE depletion expense was primarily due to (i) increased drilling expenditures on proved undeveloped locations, primarily in the Spraberry field and (ii) declines in proved gas reserves due to lower first-day-of-the-month gas prices during the 12-month period ending on December 31, 2012, partially offset by (iii) the impairment effects of reducing carrying values of the Barnett Shale field and the South Texas Edwards Trend/Austin Chalk fields during 2012 and 2011, respectively (see the discussion below for more information on the Company's impairment charges).

During 2011, the one percent increase in per BOE depletion expense was primarily due to modest inflation in drilling costs in the Spraberry field in West Texas and the Barnett Shale field, partially offset by the cost containment associated with employed integrated services and increasing production in the Eagle Ford Shale play where portions of the Company's drilling costs were carried by a third party.

Impairment of oil and gas properties and other long-lived assets. 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.

Management's commodity price outlooks represent longer-term outlooks that are developed based on observable third-party futures price outlooks as of a measurement date ("Management's Price Outlooks"). During 2012 and 2011, declines in Management's Price Outlooks provided indications of possible impairment of the Company's predominantly dry gas properties in the Edwards Trend and Austin Chalk fields in South Texas, the Barnett Shale field in North Texas and the Raton field in southeastern Colorado. As a result of management's assessments, during 2012 and 2011, the Company recognized pretax noncash impairment charges of $532.6 million and $354.4 million to reduce the carrying values of the Barnett Shale field and the South Texas Edwards Trend/Austin Chalk fields, respectively, to their estimated fair values.

The Company's estimates of undiscounted future net cash flows attributable to the Raton field's oil and gas properties indicated on December 31, 2012 that its carrying amounts are expected to be recovered, but continues to be at risk for impairment if estimates of future cash flows decline. For example, the Company estimates that the carrying value of the Raton field may become partially impaired if the average gas price in Management's Price Outlooks, of $4.92 per MCF as of December 31, 2012, were to decline by approximately $0.60 to $0.80 per MCF. The Company's Raton field is a relatively long-lived asset that had a carrying value of $2.2 billion as of December 31, 2012. If the Raton field were to become impaired in a future period, the Company would recognize noncash, pretax impairment charges in that period that could range from $1.3 billion to $1.7 billion.

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 Price Outlooks and (iv) increases or decreases in production and capital costs associated with these fields.

See Notes B and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's impairment assessments.

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PIONEER NATURAL RESOURCES COMPANY

Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs, exploratory dry holes expense and leasehold abandonments and other exploration expense from continuing operations for 2012, 2011 and 2010 (in thousands):

	Year Ended December 31,
	2012		2011		2010
Geological and geophysical	$	80,456	$	73,552	$	58,016
Exploratory dry holes	30,637		3,112		91,922
Leasehold abandonments and other	95,198		44,656		39,659
	$	206,291	$	121,320	$	189,597

During 2012, the Company's exploration and abandonment expense was primarily attributable to $80.5 million of geological and geophysical costs, of which $52.4 million was geological and geophysical administrative costs; $30.6 million were dry hole provisions, $21.6 million was associated with the Company's unsuccessful Sikumi #1 well that was drilled to test the Ivishak zone on the west side of the Company's Oooguruk unit in Alaska; and $94.7 million was leasehold abandonment expense, which included $72.5 million associated with the Company's unproved properties in the Barnett Shale and other unproved property abandonments. The other significant components of the Company's 2012 leasehold abandonment expense included $9.5 million in the Eagle Ford Shale area, $4.8 million in the Rockies area and $4.7 million in the Permian Basin. During 2012, the Company completed and evaluated 229 exploration/extension wells, 223 of which were successfully completed as discoveries.

During 2011, the Company's exploration and abandonment expense was primarily attributable to $73.6 million of geological and geophysical costs, of which amount $42.5 million was geological and geophysical administrative costs, and $44.2 million of leasehold abandonment expense. The significant components of the Company's 2011 leasehold abandonment expense included dry gas unproved acreage abandonments of $14.5 million in the Barnett Shale area, $9.3 million in the South Texas area and $9.1 million in the Rockies area. During 2011, the Company completed and evaluated 168 exploration/extension wells, 167 of which were successfully completed as discoveries.

During 2010, the Company's exploration and abandonment expense was primarily attributable to $58.0 million of geological and geophysical costs, of which amount $39.9 million was geological and geophysical administrative costs, $96.7 million of dry hole and leasehold abandonment expense resulting from the Company's decision not to pursue development of the Cosmopolitan Unit in the Cook Inlet of Alaska and other dry hole provisions and unproved property abandonments. Other significant components of the Company's 2010 unproved abandonments included $6.3 million in the Raton Basin area, $6.0 million in the Permian Basin area and $4.9 million in the Barnett Shale area. During 2010, the Company completed and evaluated 37 exploration/extension wells, 34 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense from continuing operations totaled $248.3 million, $193.2 million and $164.3 million during 2012, 2011 and 2010, respectively. The increase in 2012, as compared to 2011, is primarily due to increases of $46.6 million and $4.7 million in compensation and occupancy expenses, respectively, related to staffing increases in support of the Company's capital expansion and integrated services initiatives.

The increase in general and administrative expense during 2011, as compared to 2010, was primarily due to increases of $31.9 million and $5.7 million in compensation and occupancy expenses, respectively, related to staffing increases in support of the Company's capital expansion and integrated services initiatives, partially offset by an increase in producing, drilling and other overhead recoveries.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations from continuing operations was $9.9 million, $8.3 million and $7.9 million during 2012, 2011 and 2010, respectively. The 19 percent and five percent increases in accretion of discount on asset retirement obligations during 2012 and 2011, respectively, are primarily due to additional well completions resulting from the Company's drilling activities. See Note I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's asset retirement obligations.

Interest expense. Interest expense was $204.2 million, $181.7 million and $183.1 million during 2012, 2011 and 2010, respectively. The weighted average interest rate on the Company's indebtedness for the year ended December 31, 2012 was 6.0 percent, as compared to 7.2 percent and 7.1 percent for the years ended December 31, 2011 and 2010, respectively.

The $22.5 million increase in interest expense during 2012, as compared to 2011, is primarily due to an $868.9 million increase in the Company's average outstanding indebtedness, partially offset the 1.2 percent decline in weighted average interest on indebtedness.

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PIONEER NATURAL RESOURCES COMPANY

See Notes G and Q of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's long-term debt and interest expense.

Other expenses. Other expenses from continuing operations were $113.4 million during 2012, as compared to $63.2 million during 2011 and $78.4 million during 2010. The $50.2 million increase in other expense during 2012, as compared to 2011, is primarily due to $15.8 million of contract rig termination fees incurred during 2012, a $13.9 million increase in unused gas transportation commitment charges and a $13.1 million increase in the time that drilling rigs and fracture stimulation equipment were not being utilized.

The $15.2 million decrease in other expense during 2011, as compared to 2010, is primarily due to a $30.4 million decrease in charges recorded associated with contracted rig rates that exceeded market rig rates that were able to be charged to joint operations and idle drilling rig and fracture stimulation equipment charges and a $7.6 million decrease in inventory impairments; partially offset by a $21.7 million increase in charges associated with excess gas transportation capacity.

See Note N of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's other expenses.

Income tax provision. The Company recognized income tax provisions attributable to earnings from continuing operations of $92.4 million, $197.6 million and $269.6 million during 2012, 2011 and 2010, respectively. The Company's effective tax rates on earnings from continuing operations, excluding income from noncontrolling interest, for 2012, 2011 and 2010 were 40 percent, 32 percent and 36 percent, respectively, as compared to the combined United States federal and state statutory rates of approximately 37 percent. The increase in the Company's 2012 effective tax rate is primarily due to changes in permanent tax differences and state apportionment factors.

See "Critical Accounting Estimates" below and Note O of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's income tax rates and attributes.

Income (loss) from discontinued operations, net of tax. During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest Pioneer South Africa. The assets and liabilities of Pioneer South Africa are classified as discontinued operations held for sale in the Company's accompanying consolidated balance sheet as of December 31, 2011. During the first quarter of 2012, the Company agreed to sell its net assets in 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 pretax gain of $28.6 million. Pioneer South Africa's historical results of operations, and the related gain recorded on the disposition of Pioneer South Africa, are reported as discontinued operations, net of tax in the Company's accompanying consolidated statements of operations.

During December 2010, the Company committed to a plan to sell Pioneer Tunisia and in February 2011 sold 100 percent of the Company's share holdings in Pioneer Tunisia for cash proceeds of $802.5 million, excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million. Accordingly, the Company classified the results of operations of Pioneer Tunisia as income from discontinued operations, net of tax in the accompanying consolidated statements of operations for the years ended December 31, 2011 and 2010.

The Company recognized income from discontinued operations, net of tax of $55.1 million for 2012 as compared to income of $423.2 million for 2011 and $134.1 million for 2010. The $368.0 million decrease in income from discontinued operations during 2012, as compared to 2011 is primarily attributable to the after tax gain on the sale of Pioneer Tunisia recorded in 2011, partially offset by the after tax gain on the sale of Pioneer South Africa during 2012.

The $289.1 million increase in income from discontinued operations during 2011, as compared to 2010 is primarily attributable to the after tax gain on the sale of Pioneer Tunisia during 2011, partially offset by Pioneer South Africa and Pioneer Tunisia operating income classified as discontinued operations during 2010. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's discontinued operations.

Net income attributable to noncontrolling interest. Net income attributable to noncontrolling interests was $50.5 million, $47.4 million and $40.8 million for the years ended December 31, 2012, 2011 and 2010, respectively. The Company's net income attributable to noncontrolling interest is primarily associated with the net income of Pioneer Southwest that is allocated to limited partners. The $3.1 million increase in net income attributable to noncontrolling interest in 2012, as compared to 2011, is primarily due to a 10 percent increase in noncontrolling interest in Pioneer Southwest during November 2011 as a result of an offering by

56

PIONEER NATURAL RESOURCES COMPANY

Pioneer Southwest of 4.4 million common units, representing limited partnership units, of which 1.8 million common units were sold by the Company. Partially offsetting the increase in noncontrolling interest in Pioneer Southwest was a $15.3 million decline in Pioneer Southwest's net income during 2012, as compared to 2011.

The $6.6 million increase in net income attributable to noncontrolling interest in 2011, as compared to 2010, is primarily due to an increase in Pioneer Southwest's sales volumes and realized oil prices. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding Pioneer Southwest and the Company's noncontrolling interest in consolidated subsidiaries' net income.

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, payments 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. During 2013, the Company expects that it will be able to fund its needs for cash (excluding acquisitions) with a combination of internally generated cash flows, cash and cash equivalents on hand, proceeds from the sale of joint interests, availability under its credit facility and issuances of debt or equity securities. Although the Company expects that these sources of funding will be adequate to fund 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.

During 2013, the Company plans to continue to focus its capital spending primarily on liquids-rich drilling activities. The Company's 2013 capital budget totals $3.0 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream capital contributions), consisting of $2.75 billion for drilling operations and $240 million for buildings, expansion of the Company's principal sand mine in Brady, Texas and vertical integration additions. Based on the Company's current Management Price Outlooks, Pioneer expects its net cash flows from operating activities, cash and cash equivalents on hand, proceeds from assets sales and/or joint ventures, availability under the Credit Facility and issuances of debt or equity securities to be sufficient to fund its planned capital expenditures and contractual obligations.

Investing activities. Net cash used in investing activities during 2012 was $3.3 billion, as compared to net cash used in investing activities of $1.6 billion and $954.9 million during 2011 and 2010, respectively. The increase in net cash flow used in investing activities during 2012, as compared to 2011, is primarily due to (i) an $831.1 million increase in additions to oil and gas properties associated with the Company's capital programs, (ii) a $723.5 million decrease in proceeds from disposition of assets (primarily attributable to the 2011 sale of Pioneer Tunisia, partially offset by proceeds from the sales of Pioneer South Africa and a partial interest in certain Eagle Ford Shale unproved leaseholds during 2012) and (iii) the $297.1 million acquisition of Premier Silica, partially offset by (iv) an $89.6 million decrease in investments in EFS Midstream and (v) a $66.4 million decrease in additions to other assets and other property and equipment. During the year ended December 31, 2012, the Company's investing activities were funded by net cash provided by operating activities, cash on hand and borrowings under long-term debt.

The increase in net cash flow used in investing activities during 2011, as compared to 2010, was comprised of a $915.5 million increase in additions to oil and gas properties, an increase of $178.9 million in additions to other assets and other property and equipment and a $16.8 million increase in investments in unconsolidated subsidiaries, partially offset by an increase of $505.3 million in proceeds from disposition of assets (primarily related to the sale of Pioneer Tunisia during February 2011). See "Results of Operations" above and Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding asset divestitures.

Dividends/distributions. During each of the years ended December 31, 2012, 2011 and 2010, the Board declared semiannual dividends of $0.04 per common share. Associated therewith, the Company paid $10.0 million, $9.6 million and $9.5 million, respectively, of aggregate dividends. Future dividends are at the discretion of the Board, and, if declared, the Board may change the dividend amount based on the Company's liquidity and capital resources at the time.

During January, April, July and October of 2012, 2011 and 2010, the board of directors of the general partner of Pioneer Southwest (the "Pioneer Southwest Board") declared quarterly distributions aggregating annually to $2.07, $2.03 and $2.00 per limited partner unit, respectively. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $35.2 million, $25.6 million and $25.2 million during the years ended December 31, 2012, 2011 and 2010, respectively. Future distributions of 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.

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PIONEER NATURAL RESOURCES COMPANY

Off-balance sheet arrangements. From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of December 31, 2012, the material off-balance sheet arrangements and transactions that the Company has entered into include (i) undrawn letters of credit, (ii) operating lease agreements, (iii) drilling and firm transportation commitments, (iv) open purchase commitments and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates and gathering, treating, fractionation and transportation commitments on uncertain volumes of future throughput. Other than the off-balance sheet arrangements described above and subsequent events that are described in "Financial and Operating Performance," above and in Note Q of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data," the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company's liquidity or availability of or requirements for capital resources. See "Contractual obligations" below for more information regarding the Company's off-balance sheet arrangements.

Contractual 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, other liabilities (including postretirement benefit obligations), firm transportation and fractionation commitments and minimum annual gathering, treating and transportation commitments. Other joint owners in the properties operated by the Company will incur portions of the costs represented by these commitments.

The following table summarizes by period the payments due by the Company for contractual obligations estimated as of December 31, 2012:

	Payments Due by Year
	2013		2014 and 2015		2016 and 2017		Thereafter
	(in thousands)
Long-term debt (a)	$	479,907	$	—	$	1,540,485	$	1,749,500
Operating leases (b)	24,096		32,934		28,455		36,967
Drilling commitments (c)	174,169		131,641		585		—
Derivative obligations (d)	13,416		12,307		—		—
Open purchase commitments (e)	131,727		—		—		—
Other liabilities (f)	31,056		31,580		30,265		189,024
Firm gathering, processing and transportation commitments (g)	264,213		760,341		725,378		1,255,520
	$	1,118,584	$	968,803	$	2,325,168	$	3,231,011

 _____________________

(a) Long-term debt includes $479.9 million principal amount of the Convertible Senior Notes. The Company currently anticipates that it will redeem all Convertible Senior Notes that remain outstanding during 2013. See Notes G and Q of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for further information on the conversion of these Convertible Senior Notes. Also, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for information regarding estimated future interest payment obligations under long-term debt obligations. The amounts included in the table above represent principal maturities only.

(b) See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's operating leases.

(c) Drilling commitments represent future minimum expenditure commitments for drilling rig services and well commitments under contracts to which the Company was a party on December 31, 2012.

(d) Derivative obligations represent net liabilities determined in accordance with master netting arrangements for commodity and interest rate derivatives that were valued as of December 31, 2012. The ultimate settlement amounts of the Company's derivative obligations are unknown because they are subject to continuing market risk. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's derivative obligations.

(e) Open purchase commitments primarily represent expenditure commitments for inventory, materials and other property, plant and equipment ordered, but not received, as of December 31, 2012.

(f) The Company's other liabilities represent current and noncurrent other liabilities that are comprised of postretirement benefit obligations, litigation and environmental contingencies, asset retirement obligations and other obligations for which neither the ultimate settlement amounts nor their timings can be precisely determined in advance. See Notes H, I and J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional

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PIONEER NATURAL RESOURCES COMPANY

information regarding the Company's postretirement benefit obligations, asset retirement obligations and litigation and environmental contingencies, respectively.

(g) Gathering, processing and transportation commitments represent estimated fees on production throughput commitments. See "Item 2. Properties" and Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's gathering, processing and transportation commitments.

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 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 the Credit Facility, issue debt or equity securities or obtain capital from other sources, such as through sales of joint interests or nonstrategic assets.

Operating activities. Net cash provided by operating activities for the years ended December 31, 2012, 2011 and 2010 was $1.8 billion, $1.5 billion and $1.3 billion, respectively. The increases in net cash flow provided by operating activities in both 2012 and 2011 were primarily due to increases in oil and gas sales and realized derivative gains in each year.

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 consideration of $1.7 billion. At closing, Sinochem will pay $522.0 million in cash to Pioneer, 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 and third party approvals.

During the first quarter of 2012, the Company agreed to sell Pioneer South Africa to an unaffiliated third party 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 pretax gain of $28.6 million. During 2011, the Company completed the sale of Pioneer Tunisia to an unaffiliated party for cash proceeds of $802.5 million, excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million.

In June 2010, the Company entered into an Eagle Ford Shale joint venture. Associated therewith, the Company sold 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds. Under the terms of the transaction, the purchaser also paid 75 percent (representing $886.8 million) of the Company's defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the period from June 2010 through December 2012.

During the first half of 2010, the Company sold certain proved and unproved oil and gas properties in the Uinta/Piceance area for net proceeds of $11.8 million and the assumption by the purchaser of certain asset retirement obligations, resulting in a pretax gain of $17.3 million.

See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information regarding the Company's divestitures.

Financing activities. Net cash provided by financing activities during 2012 was $1.1 billion, as compared to net cash provided by financing activities during 2011 of $457.4 million and net cash used in 2010 of $246.4 million. During 2012, the significant components of financing activities included $1.2 billion of net borrowings on long-term debt and $45.9 million of payments associated with dividends and distributions to noncontrolling interests. During 2011, significant components of financing activities included $484.2 million of net proceeds received from the offering of 5.5 million shares of the Company's common stock, $123.0 million of net proceeds received from the sale of 4.4 million common units representing limited partner interests in Pioneer Southwest, partially offset by $98.3 million of net principal payments on long-term debt and $36.3 million of payments associated with dividends and distributions to noncontrolling interests. During 2010, significant components of financing activities included $182.9 million of net principal payments on long-term debt and $36.3 million of payments associated with dividends and distributions to noncontrolling interests.

The following provides a description of the Company's significant financing activities during 2012, 2011 and 2010:

• During December 2012, the Company amended its Credit Facility with a syndicate of financial institutions to increase the aggregate loan commitments to $1.5 billion from $1.25 billion and extend its maturity to December 2017;

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PIONEER NATURAL RESOURCES COMPANY

• During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of $8.5 million of offering discounts and costs, of $591.5 million;

• During December 2011, Pioneer Southwest completed the public offering of 4.4 million common units of Pioneer Southwest, representing limited partnership interests, at a per-unit price of $29.20, before offering costs. Of the 4.4 million common units, Pioneer sold 1.8 million of its Pioneer Southwest common unit holdings for net proceeds of $50.5 million and Pioneer Southwest issued 2.6 million new common units for net proceeds of $72.5 million, including offering costs. Pioneer Southwest used its net proceeds to reduce its credit facility borrowings; and

• During November 2011, the Company completed the sale of 5.5 million shares of its common stock for $484.2 million of net proceeds.

During December 2012, the Company's stock price performance met the average price threshold that causes the Convertible Senior Notes to become convertible at the option of the holders for the three months ending March 31, 2013. Associated therewith, in January and February 2013, holders of $240.6 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of common stock. In general, upon conversion of a Convertible Senior Note, the holder will receive cash equal to the principal amount of the Convertible Senior Note and common stock for the Convertible Senior Note's conversion value in excess of the principal amount. The Company anticipates redeeming all Notes that remain outstanding during 2013; however, the decision to exercise the redemption option will depend on market and other conditions, and the Company may choose not to redeem the Notes during 2013 or at all. If the Company exercises its redemption option, the Convertible Senior Notes will automatically become convertible during the period between when the Company gives notice of its intent to redeem the Convertible Senior Notes and the date on which the Convertible Senior Notes are actually redeemed. If the Company exercises its redemption option and the Company's stock price averages above $72.60 per share during the conversion period, the Company expects that the note holders will exercise their right to convert the Convertible Senior Notes, receiving cash and shares of common stock, rather than allow their securities to be redeemed by the Company for cash. If all the outstanding Convertible Senior Notes had been converted on December 31, 2012, the holders would have received $479.9 million of cash and approximately 3.4 million shares of the Company's common stock, which were valued at $358.8 million based on the closing price of the common stock on December 31, 2012.

Interest on the principal amount of the Convertible Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. Beginning on January 15, 2013, during any six-month period thereafter from January 15 to July 14 and from July 15 to January 14, if the average trading price (as defined in the Convertible Senior Notes indenture supplement) of a Convertible Senior Note for the five consecutive trading days immediately preceding the first day of the applicable six-month interest period equals or exceeds 120 percent of the principal amount of the note, interest on the principal amount of the Convertible Senior Notes will be 2.375 percent solely for the relevant interest period. 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, accordingly, the interest rate in effect during the January 15, 2013 to July 15, 2013 period has been reduced to 2.375 percent.

See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the significant financing activities.

As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company cannot predict the timing or ultimate outcome of any such actions as they are subject to market conditions, among other factors. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class 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 and cash equivalents and unused borrowing capacity under the Credit Facility. As of December 31, 2012, the Company had outstanding borrowings of $474.0 million under the Credit Facility, leaving $1.0 billion of unused borrowing capacity. The Company was in compliance with all of its debt covenants. The Credit Facility contains certain financial covenants, which include the maintenance of a ratio of total debt to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset impairments not to exceed .60 to 1.0, which is above the Company's December 31, 2012 ratio of .39 to 1.0. 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 the Credit Facility, issuances of debt or equity securities or other sources, such as sales 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 the combination of internal operating cash flows, cash and cash equivalents on hand, proceeds from the sales of joint interests or nonstrategic assets, available capacity under the Credit Facility and issuance of debt or equity securities 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.

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PIONEER NATURAL RESOURCES COMPANY

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 and asset composition and proved reserve mix. A reduction in the Company's debt ratings could negatively affect the Company's ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. In 2011, the Company achieved an investment grade rating with one of the credit rating agencies and, in 2012, the Company achieved an investment grade rating with a second credit rating agency.

Book capitalization and current ratio. The Company's net book capitalization at December 31, 2012 was $9.4 billion, consisting of $229.4 million of cash and cash equivalents, debt of $3.7 billion and stockholders' equity of $5.9 billion. The Company's debt to book capitalization increased to 37 percent at December 31, 2012 from 26 percent at December 31, 2011, primarily due to an increase in indebtedness during 2012. The Company's ratio of current assets to current liabilities was 1.02 to 1.00 at December 31, 2012, as compared to 1.31 to 1.00 at December 31, 2011.

Critical Accounting Estimates

The Company prepares its consolidated financial statements for inclusion in this Report in accordance with GAAP. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a comprehensive discussion of the Company's significant accounting policies. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of the Company's most critical accounting estimates, judgments and uncertainties that are inherent in the Company's application of GAAP.

Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and to restore the land at the end of oil and gas production operations. The Company's removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is generally made to the oil and gas property balance. See Notes B and I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's asset retirement obligations.

Successful efforts method of accounting. The Company utilizes the successful efforts method of accounting for oil and gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that net assets and net income are more conservatively measured under the successful efforts method of accounting for oil and gas producing activities than under the full cost method, particularly during periods of active exploration. The critical difference between the successful efforts method of accounting and the full cost method is as follows: under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of depletion expense. During 2012, 2011 and 2010, the Company recognized exploration, abandonment, geological and geophysical expense from continuing operations of $206.3 million, $121.3 million and $189.6 million, respectively. During 2012, 2011 and 2010, the Company recognized exploration, abandonment, geological and geophysical expense from discontinued operations of $70 thousand, $4.3 million and $15.9 million, respectively, under the successful efforts method.

Proved reserve estimates. Estimates of the Company's proved reserves included in this Report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

The Company's proved reserve information included in this Report as of December 31, 2012, 2011 and 2010 was prepared by the Company's engineers and audited by independent petroleum engineers with respect to the Company's major properties. Estimates prepared by third parties may be higher or lower than those included herein.

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PIONEER NATURAL RESOURCES COMPANY

Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.

It should not be assumed that the Standardized Measure included in this Report as of December 31, 2012 is the current market value of the Company's estimated proved reserves. In accordance with SEC requirements, the Company based the 2012 Standardized Measure on a 12-month average of commodity prices on the first day of the month and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See "Item 1A. Risk Factors" and "Item 2. Properties" for additional information regarding estimates of proved reserves.

The Company's estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which the Company records depletion expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of the Company's assessment of its proved properties and goodwill for impairment.

Impairment of proved oil and gas properties. The Company reviews its proved properties to be held and used whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon estimated future recoverable proved and risk-adjusted probable and possible reserves, Management's Price Outlooks, production and capital costs expected to be incurred to recover the reserves; discount rates commensurate with the nature of the properties and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated. See Notes B and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's impairment assessments.

Impairment of unproved oil and gas properties. At December 31, 2012, the Company carried unproved property costs of $231.6 million. Management assesses unproved oil and gas properties for impairment on a project-by-project basis. Management's impairment assessments include evaluating the results of exploration activities, Management's Price Outlooks and planned future sales or expiration of all or a portion of such projects.

Suspended wells. The Company suspends the costs of exploratory wells that discover hydrocarbons pending a final determination of the commercial potential of the discovery. The ultimate disposition of these well costs is dependent on the results of future drilling activity and development decisions. If the Company decides not to pursue additional appraisal activities or development of these fields, the costs of these wells will be charged to exploration and abandonment expense.

The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:

(i) The well has found a sufficient quantity of reserves to justify its completion as a producing well.

(ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves to sanction the project or is noncommercial and is impaired. See Note F of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's suspended exploratory well costs.

Deferred tax asset valuation allowances. The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that its deferred tax assets, if any, will be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and reassesses the likelihood that the Company's net operating loss carryforwards and other deferred tax attributes in each jurisdiction will be utilized prior to their expiration. There can be no assurance that facts and circumstances will not materially change and require the Company to establish deferred tax asset valuation allowances in certain jurisdictions in a future period.

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PIONEER NATURAL RESOURCES COMPANY

Goodwill impairment. The Company reviews its goodwill for impairment at least annually. During the third quarter of 2012, the Company performed a qualitative assessment of goodwill in accordance with Financial Accounting Standards Board Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350) which permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Company determined that it was not likely that the Company's goodwill was impaired.

For assessments prior to 2012, the Company was required to estimate the fair value of the assets and liabilities of the reporting units that have goodwill. There is considerable judgment involved in estimating fair values, particularly in determining the valuation methodologies to utilize, the estimation of proved reserves as described above and the weighting of different valuation methodologies applied. The carrying value of the Company's goodwill was assessed and found not to be impaired during the years ended December 31, 2011 and 2010. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding goodwill and assessments of goodwill for impairment.

Litigation and environmental contingencies. The Company makes judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. Under GAAP, a liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimable. See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's commitments and contingencies.

Valuation of stock-based compensation. In accordance with GAAP, the Company calculates the fair value of stock-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. The Company utilizes (a) the Black-Scholes option pricing model to measure the fair value of stock options, (b) the closing stock price on the day prior to the date of grant for the fair value of restricted stock awards, (c) the closing stock price at the balance sheet date for restricted stock awards that are expected to be settled wholly or partially in cash on their vesting date, (d) the Monte Carlo simulation method for the fair value of performance unit awards, and (e) a probability forecasted fair value method for Series B unit awards issued by Sendero Drilling Company, LLC. See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's stock-based compensation.

Valuation of other assets and liabilities at fair value. In accordance with GAAP, the Company periodically measures and records certain assets and liabilities at fair value. The assets and liabilities that the Company periodically measures and records at fair value include trading securities, commodity derivative contracts and interest rate contracts. The Company also measures and discloses certain financial assets and liabilities at fair value, such as long-term debt. The valuation methods used by the Company to measure the fair values of these assets and liabilities require considerable management judgment and estimates to derive the inputs necessary to determine fair value estimates, such as future prices, credit-adjusted risk-free rates and current volatility factors. See Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the methods used by management to estimate the fair values of these assets and liabilities.

New Accounting Pronouncements

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

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PIONEER NATURAL RESOURCES COMPANY

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following quantitative and qualitative information is provided about financial instruments to which the Company was a party as of December 31, 2012, and from which the Company may incur future gains or losses from changes in commodity prices or interest rates.

The fair values of the Company's derivative contracts are determined based on the Company's valuation models and applications. As of December 31, 2012, the Company was a party to commodity swap contracts, interest rate swap contracts, commodity collar contracts and commodity collar contracts with short put options. See Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's derivative contracts. The following table reconciles the changes that occurred in the fair values of the Company's open derivative contracts during 2012:

	Derivative Contract Net Assets (Liabilities)
	Commodities			Interest Rate			Total
	(in thousands)
Fair value of contracts outstanding as of December 31, 2011	$	389,753		$	(15,654	)	$	374,099
Changes in contract fair values (a)	352,679			(22,428		)	330,251
Contract maturities	(277,462		)	—			(277,462		)
Contract terminations	(146,593		)	28,358			(118,235		)
Fair value of contracts outstanding as of December 31, 2012	$	318,377		$	(9,724	)	$	308,653

 _____________________

(a) At inception, new derivative contracts entered into by the Company generally have no intrinsic value.

Quantitative Disclosures

Interest rate sensitivity. See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and Capital Commitments, Capital Resources and Liquidity included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information regarding debt transactions.

The following tables provide information about financial instruments to which the Company was a party as of December 31, 2012 that were sensitive to changes in interest rates. For debt obligations, the tables present 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 rates represent the contractual fixed rates that the Company was obligated to periodically pay on the debt as of December 31, 2012. 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 February 8, 2013.

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PIONEER NATURAL RESOURCES COMPANY

INTEREST RATE SENSITIVITY

DEBT OBLIGATIONS AND DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2012

	Year Ending December 31,																				Liability Fair Value at December 31,
	2013			2014			2015			2016			2017			Thereafter			Total		2012
Total Debt:	(in thousands, except percentages)
Fixed rate principal maturities (a)	$	479,907		$	—		$	—		$	455,385		$	485,100		$	1,749,500		$	3,169,892	$	(3,939,650	)
Weighted average interest rate	6.12		%	6.15		%	6.15		%	6.17		%	6.11		%	6.28		%
Variable rate principal maturities:
Pioneer Natural Resources credit facility	$	—		$	—		$	—		$	—		$	474,000		$	—		$	474,000	$	(492,485	)
Weighted average interest rate	1.83		%	2.01		%	2.35		%	2.70		%	2.95		%	—		%
Pioneer Southwest credit facility	$	—		$	—		$	—		$	—		$	126,000		$	—		$	126,000	$	(123,635	)
Weighted average interest rate	1.96		%	2.13		%	2.48		%	2.83		%	3.07		%	—		%
Interest Rate Swaps:
Notional debt amount	$	—		$	—		$	—		$	250,000		$	—		$	—		$	250,000	$	(9,724	)
Fixed rate payable (%)	—		%	—		%	—		%	3.21		%	—		%	—		%
Variable rate receivable (%)	—		%	—		%	—		%	3.01		%	—		%	—		%

 _______________________

(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 tables provide information about the Company's oil, NGL, diesel and gas derivative financial instruments that were sensitive to changes in commodity prices as of December 31, 2012. Declines in commodity prices would reduce the Company's revenues, although the liquidity effects of such fluctuations would be mitigated by the Company's derivative activities.

The Company manages commodity price risk with derivative 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 floor-to-short put price differential.

See Notes B, D and E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" 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

OIL PRICE SENSITIVITY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2012

	Year Ending December 31,							Asset (Liability) Fair Value at December 31,
	2013			2014		2015		2012
								(in thousands)
Oil Derivatives:
Average daily notional BBL volumes:
Swap contracts	3,000			—		—		$	(13,225	)
Weighted average fixed price per BBL	$	81.02		$	—	$	—
Collar contracts with short puts (a)	71,029			60,000		26,000		$	160,817
Weighted average ceiling price per BBL	$	119.76		$	117.06	$	104.45
Weighted average floor price per BBL	$	92.27		$	92.67	$	95.00
Weighted average short put price per BBL	$	74.28		$	76.58	$	80.00
Average forward NYMEX oil prices (b)	$	97.24		$	95.03	$	91.18
Rollfactor swap contracts (a)	6,000			—		—		$	1,375
Weighted average fixed price per BBL (c)	$	0.43		$	—	$	—
Average forward NYMEX rollfactor prices (b)	$	(0.14	)	$	—	$	—
Basis swap contracts (d)	2,055			—		—		$	301
Weighted average fixed price per BBL	$	(5.75	)	$	—	$	—
Average forward basis differential prices (e)	$	(1.25	)	$	—	$	—

 _____________________

(a) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional 2014 (i) collar contracts with short puts for 9,000 BBLs per day with a ceiling price of $104.13 per BBL, a floor price of $95.00 per BBL and a short put price of $80.00 per BBL and (ii) rollfactor swap contracts for 15,000 BBLs per day priced at $0.38 per BBL; and (iii) replaced 5,000 BBLs per day of 2014 collar contracts with short puts with a ceiling price of $124.00 per BBL, a floor price of $90.00 per BBL and short put price of $72.00 per BBL with 5,000 BBLs per day of 2014 collar contracts with short puts with a ceiling price of $105.74 per BBL, a floor price of $100.00 per BBL and short put price of $80.00 per BBL.

(b) The average forward NYMEX oil prices are based on February 8, 2013 market quotes.

(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) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional basis swap contracts for 1,000 BBLs per day of October through December 2013 production with a price differential between Cushing WTI and Louisiana Light Sweet crude of $7.60 per BBL.

(e) The average forward basis differential prices are based on February 8, 2013 market quotes for basis differentials between Midland WTI and Cushing WTI.

66

PIONEER NATURAL RESOURCES COMPANY

NGL PRICE SENSITIVITY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2012

	Year Ending December 31,				Asset  Fair Value at December 31,
	2013		2014		2012
					(in thousands)
NGL Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts	1,064		1,000		$	1,799
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 (a)	$	91.88	$	84.91

_______________________ 

(a) Forward component NGL prices are derived from active-market NGL component price quotes as of February 8, 2013.

GAS PRICE SENSITIVITY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2012

	Year Ending December 31,								Asset (Liability) Fair Value at December 31,
	2013			2014			2015		2012
									(in thousands)
Gas Derivatives:
Average daily notional MMBTU volumes:
Swap contracts	162,500			105,000			—		$	93,581
Weighted average fixed price per MMBTU	$	5.13		$	4.03		$	—
Collar contracts	150,000			—			—		$	81,332
Weighted average ceiling price per MMBTU	$	6.25		$	—		$	—
Weighted average floor price per MMBTU	$	5.00		$	—		$	—
Collar contracts with short puts	—			25,000			225,000		$	(1,954	)
Weighted average ceiling price per MMBTU	$	—		$	4.70		$	5.09
Weighted average floor price per MMBTU	$	—		$	4.00		$	4.00
Weighted average short put price per MMBTU	$	—		$	3.00		$	3.00
Average forward NYMEX gas prices (a)	$	3.58		$	4.04		$	4.25
Basis swap contracts	162,500			10,000			—		$	(5,627	)
Weighted average fixed price per MMBTU	$	(0.22	)	$	(0.19	)	$	—
Average forward basis differential prices (b)	$	(0.11	)	$	(0.20	)	$	—

 _____________________

(a) The average forward NYMEX gas prices are based on February 8, 2013 market quotes.

(b) The average forward basis differential prices are based on February 8, 2013 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

Marketing 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 gas buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into gas index swaps to mitigate price risk.

67

PIONEER NATURAL RESOURCES COMPANY

MARKETING GAS PRICE SENSITIVITY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2012

	Quarter Ending March 31,		Liability Fair Value at December 31,
	2013		2012
			(in thousands)
Average Daily Gas Production Associated with Marketing Derivatives (MMBTU):
Basis swap contracts:
Index swap volume (a)	40,000		$	(22	)
Price differential ($/MMBTU)	$	0.25
Average forward basis differential prices (b)	$	0.26

 ____________________

(a) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional marketing derivative gas index swap contracts for 25,000 MMBTU per day for April 2013 volumes with a price differential of $0.35 per MMBTU.

(b) The average forward basis differential prices are based on February 8, 2013 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

Qualitative Disclosures

The Company's primary market risk exposures are to changes in commodity prices and interest rates. These risks did not change materially from December 31, 2011 to December 31, 2012.

Non-derivative financial instruments. The Company is a borrower under fixed rate and variable rate debt instruments that give rise to interest rate risk. The Company's objective in borrowing under fixed or variable rate debt is to satisfy capital requirements while minimizing the Company's costs of capital. See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a discussion of the Company's debt instruments.

Derivative financial instruments. The Company, from time to time, utilizes commodity price and interest rate derivative contracts to mitigate commodity price and interest rate risks in accordance with policies and guidelines approved by the Board. In accordance with those policies and guidelines, the Company's executive management determines the appropriate timing and extent of derivative transactions.

68

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

	Page
Consolidated Financial Statements of Pioneer Natural Resources Company:
Report of Independent Registered Public Accounting Firm	70
Consolidated Balance Sheets as of December 31, 2012 and 2011	71
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010	73
Consolidated Statements of Comprehensive Income for the Years Ended December  31, 2012, 2011 and 2010	74
Consolidated Statements of Equity for the Years Ended December  31, 2012, 2011 and 2010	75
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010	77
Notes to Consolidated Financial Statements	78
Unaudited Supplementary Information	113

69

REPORT OF INDEPENDENT REGISTERED PUBLIC

ACCOUNTING FIRM

The Board of Directors and Stockholders of

Pioneer Natural Resources Company

We have audited the accompanying consolidated balance sheets of Pioneer Natural Resources Company (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Pioneer Natural Resources Company at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pioneer Natural Resources Company's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 13, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas

February 13, 2013

70

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	229,396		$	537,484
Accounts receivable:
Trade, net of allowance for doubtful accounts of $848 and $806 as of December 31, 2012 and December 31, 2011, respectively	316,854			275,991
Due from affiliates	3,299			7,822
Income taxes receivable	7,447			3
Inventories	197,056			241,609
Prepaid expenses	13,438			14,263
Discontinued operations held for sale	—			73,349
Other current assets:
Derivatives	279,119			238,835
Other	3,746			12,936
Total current assets	1,050,355			1,402,292
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	14,259,708			12,013,805
Unproved properties	231,555			235,527
Accumulated depletion, depreciation and amortization	(4,412,913		)	(3,648,465		)
Total property, plant and equipment	10,078,350			8,600,867
Goodwill	298,142			298,142
Other property and equipment, net	1,217,694			573,075
Other assets:
Investment in unconsolidated affiliate	204,129			169,532
Derivatives	55,257			243,240
Other, net of allowance for doubtful accounts of $629 and $340 as of December 31, 2012 and December 31, 2011, respectively	165,103			160,008
	$	13,069,030		$	11,447,156

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

71

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (Continued)

(in thousands, except share data)

	December 31,
	2012			2011
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	729,942		$	647,455
Due to affiliates	96,935			68,756
Interest payable	68,083			57,240
Income taxes payable	208			9,788
Deferred income taxes	86,481			57,713
Discontinued operations held for sale	—			75,901
Other current liabilities:
Derivatives	13,416			74,415
Deferred revenue	—			42,069
Other	39,725			36,174
Total current liabilities	1,034,790			1,069,511
Long-term debt	3,721,193			2,528,905
Derivatives	12,307			33,561
Deferred income taxes	2,140,416			1,942,446
Other liabilities	293,016			221,595
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 134,966,740 and 133,121,092 shares issued at December 31, 2012 and 2011, respectively	1,350			1,331
Additional paid-in capital	3,683,934			3,613,808
Treasury stock, at cost: 11,611,093 and 11,264,936 shares at December 31, 2012 and 2011, respectively	(510,570		)	(458,281		)
Retained earnings	2,514,640			2,335,066
Accumulated other comprehensive loss—net deferred hedge losses, net of tax	—			(3,130		)
Total equity attributable to common stockholders	5,689,354			5,488,794
Noncontrolling interest in consolidating subsidiaries	177,954			162,344
Total equity	5,867,308			5,651,138
Commitments and contingencies
	$	13,069,030		$	11,447,156

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

72

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year Ended December 31,
	2012			2011			2010
Revenues and other income:
Oil and gas	$	2,811,660		$	2,294,063		$	1,718,297
Interest and other	28,310			66,880			56,972
Derivative gains, net	330,251			392,752			448,434
Gain (loss) on disposition of assets, net	58,087			(3,644		)	19,074
Hurricane activity, net	—			1,454			138,918
	3,228,308			2,751,505			2,381,695
Costs and expenses:
Oil and gas production	635,644			447,142			364,764
Production and ad valorem taxes	187,757			147,664			112,141
Depletion, depreciation and amortization	810,191			578,268			499,856
Impairment of oil and gas properties	532,589			354,408			—
Exploration and abandonments	206,291			121,320			189,597
General and administrative	248,282			193,215			164,332
Accretion of discount on asset retirement obligations	9,887			8,256			7,945
Interest	204,222			181,660			183,084
Other	113,388			63,166			78,404
	2,948,251			2,095,099			1,600,123
Income from continuing operations before income taxes	280,057			656,406			781,572
Income tax provision	(92,384		)	(197,644		)	(269,627		)
Income from continuing operations	187,673			458,762			511,945
Income from discontinued operations, net of tax	55,149			423,152			134,050
Net income	242,822			881,914			645,995
Net income attributable to noncontrolling interests	(50,537		)	(47,425		)	(40,787		)
Net income attributable to common stockholders	$	192,285		$	834,489		$	605,208
Basic earnings per share:
Income from continuing operations attributable to common stockholders	$	1.10		$	3.45		$	4.00
Income from discontinued operations attributable to common stockholders	0.44			3.56			1.14
Net income attributable to common stockholders	$	1.54		$	7.01		$	5.14
Diluted earnings per share:
Income from continuing operations attributable to common stockholders	$	1.07		$	3.39		$	3.96
Income from discontinued operations attributable to common stockholders	0.43			3.49			1.12
Net income attributable to common stockholders	$	1.50		$	6.88		$	5.08
Weighted average shares outstanding:
Basic	122,966			116,904			115,062
Diluted	126,320			119,215			116,330
Amounts attributable to common stockholders:
Income from continuing operations	$	137,136		$	411,337		$	471,158
Income from discontinued operations, net of tax	55,149			423,152			134,050
Net income	$	192,285		$	834,489		$	605,208

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

73

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Year Ended December 31,
	2012			2011			2010
Net income	$	242,822		$	881,914		$	645,995
Other comprehensive activity:
Net hedge (gains) losses included in continuing operations	4,855			(32,636		)	(84,877		)
Income tax (benefit) provision	(1,725		)	8,407			23,648
Other comprehensive activity	3,130			(24,229		)	(61,229		)
Comprehensive income	245,952			857,685			584,766
Comprehensive income attributable to the noncontrolling interests	(50,537		)	(33,687		)	(23,206		)
Comprehensive income attributable to common stockholders	$	195,415		$	823,998		$	561,560

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

74

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF EQUITY

(in thousands, except dividends per share)

			Equity Attributable to Common Stockholders
	Shares Outstanding		Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total Equity
Balance as of December 31, 2009	114,375		$	1,252	$	2,981,450		$	(415,211	)	$	917,688		$	51,009		$	106,843		$	3,643,031
Dividends declared ($0.08 per share)	—		—		—			—			(9,455		)	—			—			(9,455		)
Exercise of long-term incentive plan stock options and employee stock purchases	266		1		2,577			7,811			(3,014		)	—			—			7,375
Purchase of treasury stock	(278	)	—		—			(13,835		)	—			—			(204		)	(14,039		)
Tax related to stock-based compensation	—		—		(153		)	—			—			—			—			(153		)
Compensation costs:
Vested compensation awards, net	946		9		(8		)	—			—			—			—			1
Compensation costs included in net income	—		—		38,902			—			—			—			1,283			40,185
Cash contributions from noncontrolling interests	—		—		—			—			—			—			1,151			1,151
Cash distributions to noncontrolling interests	—		—		—			—			—			—			(26,837		)	(26,837		)
Net income	—		—		—			—			605,208			—			40,787			645,995
Other comprehensive loss:
Deferred hedging activity, net of tax:
Net hedge gains included in continuing operations	—		—		—			—			—			(43,648		)	(17,581		)	(61,229		)
Balance as of December 31, 2010	115,309		$	1,262	$	3,022,768		$	(421,235	)	$	1,510,427		$	7,361		$	105,442		$	4,226,025
Issuance of common stock	5,500		55		484,105			—			—			—			—			484,160
Sale of Pioneer Southwest common units, net of tax	—		—		26,915			—			—			—			8,176			35,091
Issuance of Pioneer Southwest common units, net of tax	—		—		8,104			—			—			—			40,688			48,792
Dividends declared ($0.08 per share)	—		—		—			—			(9,498		)	—			—			(9,498		)
Exercise of long-term incentive plan stock options and employee stock purchases	76		—		951			3,097			(352		)	—			—			3,696
Purchase of treasury stock	(439	)	—		—			(40,157		)	—			—			(198		)	(40,355		)
Conversion of 2.875% convertible senior notes	—		—		(20		)	14			—			—			—			(6		)
Tax benefits related to stock-based compensation	—		—		31,087			—			—			—			—			31,087
Disposition of subsidiary	—		—		(510		)	—			—			—			—			(510		)
Compensation costs:
Vested compensation awards, net	1,410		14		(14		)	—			—			—			—			—
Compensation costs included in net income	—		—		40,422			—			—			—			1,251			41,673
Cash distributions to noncontrolling interests	—		—		—			—			—			—			(26,702		)	(26,702		)
Net income	—		—		—			—			834,489			—			47,425			881,914
Other comprehensive loss:
Deferred hedging activity, net of tax:
Net hedge gains included in continuing operations	—		—		—			—			—			(10,491		)	(13,738		)	(24,229		)
Balance as of December 31, 2011	121,856		$	1,331	$	3,613,808		$	(458,281	)	$	2,335,066		$	(3,130	)	$	162,344		$	5,651,138

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

75

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF EQUITY (continued)

(in thousands, except dividends per share)

			Equity Attributable to Common Stockholders
	Shares Outstanding		Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Equity
Balance as of December 31, 2011	121,856		$	1,331	$	3,613,808		$	(458,281	)	$	2,335,066		$	(3,130	)	$	162,344		$	5,651,138
Dividends declared ($0.08 per share)	—		—		—			—			(9,989		)	—			—			(9,989		)
Exercise of long-term incentive plan stock options and employee stock purchases	195		—		(849		)	10,842			(2,722		)	—			—			7,271
Purchase of treasury stock	(542	)	—		—			(63,136		)	—			—			(189		)	(63,325		)
Conversion of 2.875% convertible senior notes	—		—		(5		)	5			—			—			—			—
Tax benefits related to stock-based compensation	—		—		58,486			—			—			—			—			58,486
Deferred tax provision attributable to 2008 Pioneer Southwest initial public offering	—		—		(49,072		)	—			—			—			—			(49,072		)
Compensation costs:
Vested compensation awards, net	1,847		19		(19		)	—			—			—			—			—
Compensation costs included in net income	—		—		61,585			—			—			—			1,165			62,750
Cash distributions to noncontrolling interests	—		—		—			—			—			—			(35,903		)	(35,903		)
Net income	—		—		—			—			192,285			—			50,537			242,822
Other comprehensive income:
Deferred hedging activity, net of tax:
Net hedge losses included in continuing operations	—		—		—			—			—			3,130			—			3,130
Balance as of December 31, 2012	123,356		$	1,350	$	3,683,934		$	(510,570	)	$	2,514,640		$	—		$	177,954		$	5,867,308

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

76

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2012			2011			2010
Cash flows from operating activities:
Net income	$	242,822		$	881,914		$	645,995
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	810,191			578,268			499,856
Impairment of oil and gas properties	532,589			354,408			—
Exploration expenses, including dry holes	125,376			47,231			132,772
Hurricane activity, net	—			—			4,508
Deferred income taxes	85,459			188,579			259,763
(Gain) loss on disposition of assets, net	(58,087		)	3,644			(19,074		)
Accretion of discount on asset retirement obligations	9,887			8,256			7,945
Discontinued operations	(19,344		)	(376,717		)	77,158
Interest expense	35,563			31,483			30,472
Derivative related activity	68,604			(221,899		)	(419,809		)
Amortization of stock-based compensation	62,567			41,442			39,854
Amortization of deferred revenue	(42,069		)	(44,951		)	(90,216		)
Other noncash items	(39,599		)	6,725			25,102
Change in operating assets and liabilities
Accounts receivable, net	(28,206		)	(47,331		)	36,653
Income taxes receivable	(5,953		)	29,406			(5,878		)
Inventories	33,059			(137,401		)	(26,281		)
Prepaid expenses	1,447			(3,415		)	(3,874		)
Other current assets	14,291			1,957			(14,270		)
Accounts payable	46,038			136,296			128,927
Interest payable	10,842			(1,768		)	11,999
Income taxes payable	(9,580		)	(7,623		)	4,007
Other current liabilities	(38,320		)	61,210			(40,586		)
Net cash provided by operating activities	1,837,577			1,529,714			1,285,023
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	95,564			819,044			313,780
Payments for acquisition, net of cash acquired	(297,092		)	—			—
Investment in unconsolidated subsidiary	—			(89,620		)	(72,864		)
Additions to oil and gas properties	(2,758,073		)	(1,926,965		)	(1,011,442		)
Additions to other assets and other property and equipment, net	(296,809		)	(363,246		)	(184,330		)
Net cash used in investing activities	(3,256,410		)	(1,560,787		)	(954,856		)
Cash flows from financing activities:
Borrowings under long-term debt	1,776,618			196,616			292,342
Principal payments on long-term debt	(612,001		)	(294,883		)	(475,252		)
Proceeds from issuance of common stock, net of issuance costs	—			484,160			—
Proceeds from issuance of partnership common units, net of issuance costs	—			122,976			—
Contributions from noncontrolling interests	—			—			1,151
Distributions to noncontrolling interests	(35,903		)	(26,702		)	(26,837		)
Payments of other liabilities	(1,153		)	(901		)	(21,329		)
Exercise of long-term incentive plan stock options and employee stock purchases	7,271			3,696			7,375
Purchase of treasury stock	(63,325		)	(40,355		)	(14,039		)
Excess tax benefit (provision) from share-based payment arrangements	58,486			31,087			(153		)
Payment of financing fees	(9,227		)	(8,741		)	(145		)
Dividends paid	(10,021		)	(9,556		)	(9,488		)
Net cash provided by (used in) financing activities	1,110,745			457,397			(246,375		)
Net increase (decrease) in cash and cash equivalents	(308,088		)	426,324			83,792
Cash and cash equivalents, beginning of period	537,484			111,160			27,368
Cash and cash equivalents, end of period	$	229,396		$	537,484		$	111,160

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

77

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011 and 2010

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 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. The Company's objective is to maximize shareholder investment returns by maintaining financial flexibility, capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions.

NOTE B.    Summary of Significant Accounting Policies

Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. In accordance with generally accepted accounting principles in the United States ("GAAP"), the Company proportionately consolidates certain affiliate partnerships that are less than wholly-owned and are involved in oil and gas producing activities. All material intercompany balances and transactions have been eliminated.

Certain reclassifications have been made to the 2011 and 2010 financial statement and footnote amounts in order to conform them to the 2012 presentations.

On May 6, 2008, the Company recognized a noncash gain on the sale of common units of Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest," a majority-owned and consolidated subsidiary) as a component of additional paid-in capital in stockholders' equity. In accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification Topic 740 Income Taxes, deferred income taxes of $49.1 million should be recognized for the future tax effects arising from the noncash gain on the sale of the Pioneer Southwest common units, with a corresponding decrease to additional paid-in capital. The Company recorded the deferred income taxes associated with this transaction in 2012. The effect of this adjustment is immaterial to the accompanying financial statements.

The accompanying consolidated balance sheet as of December 31, 2011 has been revised for a change in the classification of deferred income taxes associated with the Company's unrealized current derivative net gains as of December 31, 2011. The noncash revisions resulted in a $77.0 million decrease in current deferred tax assets, a $57.7 million increase in current deferred tax liabilities and a $134.7 million decrease in noncurrent deferred tax liabilities from the amounts previously reported at December 31, 2011. These revisions were made to appropriately reflect the impact on deferred income taxes based on the expected settlement periods related to derivatives, which remained subject to market risk as of December 31, 2011.

Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized.

Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less.

Accounts receivable. As of December 31, 2012 and 2011, the Company had accounts receivable – trade, net of allowances for bad debts, of $316.9 million and $276.0 million, respectively. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivable, joint interest receivables and other receivables for which the Company does not require collateral security.

As of December 31, 2012 and 2011, the Company's allowances for doubtful accounts totaled $1.5 million and $1.1 million, respectively. The Company establishes allowances for bad debts equal to the estimable portions of accounts and notes receivables for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions

78

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable.

Inventories. The Company's inventories consist of materials and supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. "Market," in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. Valuation reserve allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supply inventories in the Company's consolidated balance sheets and as other expense in the accompanying consolidated statements of operations.

Commodities inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company's commodities inventories consist of oil held in storage and natural gas liquids ("NGLs") and gas pipeline fill volumes. Any valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations.

The following table presents the Company's materials and supplies and commodities inventories as of December 31, 2012 and 2011:

	Year Ended December 31,
	2012			2011
	(in thousands)
Materials and supplies (a)	$	258,962		$	297,910
Commodities	5,446			4,453
Less: Noncurrent materials and supplies (b)	(67,352		)	(60,754		)
	$	197,056		$	241,609

____________________

(a) As of December 31, 2012 and 2011, the Company's materials and supplies inventories were net of valuation reserve allowances of $4.6 million and $0.9 million, respectively.

(b) Included in other noncurrent assets in the Company's accompanying consolidated balance sheet.

Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. For large development projects requiring significant upfront development costs to support the drilling and production of a planned group of wells, the Company continues to capitalize interest on the portion of the development costs attributable to the planned wells yet to be drilled.

The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:

(i) The well has found a sufficient quantity of reserves to justify its completion as a producing well.

(ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly.

79

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note F for additional information regarding the Company's suspended exploratory well costs.

The Company owns interests in four gas processing plants and ten treating facilities. The Company is the operator of two of the gas processing plants and all ten of the treating facilities. The Company's ownership interests in the gas processing plants and treating facilities is primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third party revenues generated from the processing plants and treating facilities for the three years ended December 31, 2012, 2011 and 2010 were $39.4 million, $46.0 million and $34.0 million, respectively. Third party expenses attributable to the processing plants and treating facilities for the same respective periods were $27.1 million, $22.7 million and $14.3 million. The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service.

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base.

The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note D for additional information regarding the Company's proved property impairment provisions.

Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time. See Note D for additional information regarding impairment of Barnett Shale unproved properties.

Goodwill. During 2004, the Company recorded goodwill associated with a business combination, which represents the cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2012, the Company performed a qualitative assessment of goodwill. Financial Accounting Standards Board ("FASB") Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350) permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. Based upon the results of the assessment, the Company determined that it was not likely that the Company's goodwill was impaired.

80

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2012 and 2011, respectively, the net carrying value of other property and equipment consisted of the following:

	Year Ended December 31,
	2012 (a)		2011 (a)
	(in thousands)
Proved and unproved sand properties	$	457,033	$	—
Equipment and rigs (b)	385,887		329,157
Land and buildings	259,629		160,795
Transportation equipment	44,928		28,108
Furniture and fixtures	43,614		34,567
Leasehold improvements	26,603		20,448
	$	1,217,694	$	573,075

____________________

(a) At December 31, 2012 and 2011, other property and equipment was net of accumulated depreciation of $395.9 million and $297.6 million, respectively.

(b) Includes drilling rigs, well servicing rigs and equipment and fracture stimulation equipment.

The Company's proved and unproved sand properties include sand mines, sales facilities and unproved leaseholds that primarily provide the Company and other unrelated customers with proppant used in the fracture stimulation of oil and gas wells. See Note C for additional information about the Company's sand mine operations. The Company's equipment and rigs include assets owned by subsidiaries that provide drilling, pumping and well services on Company-operated properties. The primary purposes of the Company's sand mines and drilling, pumping and well services operations are to accommodate the Company's drilling and producing operations by increasing the availability of supplies, equipment and services, rather than being dependent on third-party availability, and to contain associated costs. As of December 31, 2012, the Company owned 15 drilling rigs, ten fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. All intercompany gains or losses of the Company's sand mines and drilling, pumping and well services operations are eliminated. Earnings from sales of proppant and from providing drilling, pumping and well services to third-party customers and working interest owners in Company-operated properties are included in interest and other income in the accompanying consolidated statements of operations.

The capitalized costs of proved sand properties are depleted using the unit-of-production method based on proved sand reserves. Equipment items are generally depreciated by individual component on a straight line basis over their economic useful lives, which are generally from two to 12 years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases.

The Company evaluates other property and equipment for potential impairment whenever indicators of impairment are present. Circumstances that could indicate potential impairment include: significant adverse changes in industry trends and the economic outlook; legal actions; regulatory changes; and significant declines in utilization rates or oil and gas prices. If it is determined that other property and equipment is potentially impaired, the Company performs an impairment evaluation by estimating the future undiscounted net cash flow from the use and eventual disposition of other property and equipment grouped at the lowest level that cash flows can be identified. If the sum of the future undiscounted net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the assets' net book value over its estimated fair value.

Investment in unconsolidated affiliate. During 2010, the Company formed EFS Midstream LLC ("EFS Midstream") to own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play in South Texas. During June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an unaffiliated third party for $46.4 million of cash proceeds. Associated therewith, the Company recorded a $46.2 million deferred gain that is being amortized as a reduction in production costs over a 20 year period, representing the term of a continuing commitment of Pioneer to deliver production volumes through EFS Midstream handling and gathering facilities. The deferred gain is included in other current and noncurrent liabilities in the Company's accompanying consolidated balance sheet.

81

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

The Company does not have voting control of EFS Midstream. Consequently, the Company accounts for this investment under the equity method of accounting for investments in unconsolidated affiliates. Under the equity method, the Company's investment in unconsolidated affiliates is increased for investments made and the investor's share of the investee's net income, and decreased for distributions received, the carrying value of member interests sold and the investor's share of the investee's net losses.

The Company's equity interest in the net income or loss of EFS Midstream is recorded in interest and other income, net of eliminations of the profit associated with gathering, treating and transportation fees charged to the Company by EFS Midstream, in the accompanying consolidated statements of operations. See Note M for the Company's equity interest in the net income or loss of EFS Midstream for the years ended December 31, 2012, 2011 and 2010.

Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated.

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 and expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note I for additional information about the Company's asset retirement obligations.

Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.

Noncontrolling interest in consolidated subsidiaries. At December 31, 2012, the Company owned a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest. Pioneer Southwest owns interests in proved and unproved 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. On December 12, 2011, Pioneer Southwest completed the public offering of 4.4 million common units of Pioneer Southwest, representing limited partnership interests, at a per-unit offering price to the public of $29.20. Of the 4.4 million common units, Pioneer sold 1.8 million of its Pioneer Southwest common unit holdings and Pioneer Southwest issued 2.6 million of new common units. The common unit sale resulted in the Company's limited partnership interest in Pioneer Southwest decreasing from 61.9 percent to 52.4 percent.

In accordance with GAAP, the Company records transfers of any gains or losses, net of taxes, from noncontrolling interests in consolidated subsidiaries to additional paid in capital proportionate to the ownership after giving effect to the sale of common units. The following table presents the Company's net income or loss attributable to common stockholders adjusted for transfers from noncontrolling interest in consolidated subsidiaries to additional paid in capital attributable to Pioneer Southwest's common unit offerings:

	Year Ended December 31,
	2012			2011		2010
	(in thousands)
Net income attributable to common stockholders	$	192,285		$	834,489	$	605,208
Transfers from the noncontrolling interest in consolidated subsidiaries:
Increase in additional paid in capital from the sale of 1.8 million Pioneer Southwest common units during 2011, net of tax of $15.4 million	—			26,915		—
Increase in additional paid in capital from Pioneer Southwest's offering of 2.6 million common units during 2011, net of tax of $23.7 million	—			8,104		—
Decrease in additional paid in capital for deferred taxes recognized attributable to Pioneer Southwest's 2008 initial public offering of 9.5 million common units	(49,072		)	—		—
Net transfers from noncontrolling interest	(49,072		)	35,019		—
Net income attributable to common stockholders and transfers from noncontrolling interest	$	143,213		$	869,508	$	605,208

During January 2010, Pioneer Natural Resources USA, Inc. ("Pioneer USA," a wholly-owned subsidiary of the Company) formed Sendero Drilling Company, LLC ("Sendero"). Sendero was formed to own and operate land-based drilling rigs in the

82

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

United States. As of December 31, 2012, Sendero owned 15 drilling rigs operating under contract to Pioneer USA in the Spraberry field. Pioneer USA is the majority owner of Sendero.

The Company also owns the majority interests in certain other subsidiaries with operations in the United States. Noncontrolling interests in the net assets of consolidated subsidiaries totaled $178.0 million and $162.3 million as of December 31, 2012 and 2011, respectively. The Company recorded net income attributable to the noncontrolling interests of $50.5 million, $47.4 million and $40.8 million for the years ended December 31, 2012, 2011 and 2010 (principally related to Pioneer Southwest), respectively.

Revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets.

The Company had no material oil or NGL entitlement assets or liabilities as of December 31, 2012 or 2011. The following table presents the Company's gas entitlement assets and liabilities with their associated volumes as of December 31, 2012 and 2011. Gas volumes are presented in millions of cubic feet ("MMCF").

	December 31,
	2012			2011
	Amount		Volume	Amount		Volume
	(dollars in millions)
Gas entitlement assets	$	6.8	2,870	$	7.6	3,024
Gas entitlement liabilities	$	1.9	582	$	2.6	650

The Company recognized revenue of $42.1 million, $45.0 million and $90.2 million during 2012, 2011 and 2010, respectively from volumetric production payment ("VPP") agreements which represented limited-term overriding royalty interests in oil reserves that: (i) entitled the purchaser to receive production volumes over a period of time from specific lease interests, (ii) were free and clear of all associated future production costs and capital expenditures associated with the reserves, (iii) were nonrecourse to the Company (i.e., the purchaser's only recourse was to the reserves acquired), (iv) transferred title of the reserves to the purchaser and (v) allowed the Company to retain the remaining reserves after the VPPs volumetric quantities had been delivered. All VPP production volumes have been delivered and thus there are no further obligations under VPP contracts or deferred revenue as of December 31, 2012.

Derivatives. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts. The effective portions of the discontinued deferred hedges as of February 1, 2009 were included in accumulated other comprehensive income (loss) – net deferred hedge gains (losses), net of tax ("AOCI - Hedging") and were transferred to earnings during the same periods in which the forecasted hedged transactions were recognized in the Company's earnings. During 2012, the remaining AOCI - Hedging was transferred to earnings. Since discontinuing hedge accounting, the Company has recognized all changes in the fair values of its derivative contracts 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 as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's and Pioneer Southwest's credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. Pioneer Southwest's credit-adjusted risk-free rate curve is based on independent market-quoted forward London Interbank Offered Rate ("LIBOR") curves plus 162.5 basis points, representing Pioneer Southwest's estimated borrowing rate. See Note E for additional information about the Company's derivative instruments.

83

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

Hurricane activity, net. As a result of Hurricane Rita in September 2005, the Company's East Cameron 322 facility, located on the Gulf of Mexico shelf, was completely destroyed. Operations to reclaim and abandon the East Cameron 322 facility began in 2006 and were completed during 2011.

In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues for the cost of reclamation and abandonment of the East Cameron 322 facility. During 2010, the Company and the insurance carriers agreed to settle the insurance policy dispute, resulting in an additional payment to the Company of $140.1 million during November 2010. Hurricane activity reclamation and abandonment charges were recorded when changes occurred in management's estimates of total reclamation and abandonment costs. Associated insurance recoveries were credited to net hurricane activity in the accompanying consolidated statement of operations in the periods in which claims recoveries were received.

Environmental. The Company's environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs.

Stock-based compensation. For stock-based compensation awards granted or modified, stock-based compensation expense is being recognized in the Company's financial statements on a straight line basis over the awards' vesting periods based on their fair values on the dates of grant. The stock-based compensation awards generally vest over a period not exceeding three years. The amount of stock-based compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant for the fair value of restricted stock, restricted stock units, partnership unit awards or phantom unit awards that are expected to be settled in the Company's common stock or Pioneer Southwest common units ("Equity Awards"), (iii) the Monte Carlo simulation method for the fair value of performance unit awards and (iv) a probabilistic forecasted fair value method for Series B unit awards issued by Sendero.

Stock-based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity shares or units ("Liability Awards"). Stock-based Liability Awards are recorded as accounts payable—affiliates based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to stock-based compensation expense.

Segments. Operating segments are defined as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

Based upon how the Company is organized and managed, the Company has only one reportable operating segment, which is oil and gas exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.

Assets held for sale and discontinued operations. On the date at which the Company meets all the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the assets or asset group to be sold and reclassifies the assets and related liabilities to be sold as held for sale on the accompanying consolidated balance sheets. The assets and liabilities are measured at the lower of their carrying amount or estimated fair value less cost to sell.

In addition, after determining that held for sale criteria has been met, the Company considers whether the held for sale assets meet the criteria to be considered discontinued operations. If the assets held for sale are considered discontinued operations, the Company classifies the results of operations from the assets held for sale as income or loss from discontinued operations, net of tax, in the accompanying consolidated statements of operations for the current period and all prior periods. See Note C for additional information about the Company's divestitures.

84

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

NOTE C. Acquisitions and Divestitures

Premier Silica Business Combination

During April 2012, a wholly-owned subsidiary of Pioneer acquired 100 percent of the share capital of Industrial Sands Holding Company and its wholly-owned subsidiary, Oglebay Norton Industrial Sands, LLC (the "Sand Acquisition"). Subsequent to the acquisition, the Company changed the name of Oglebay Norton Industrial Sands, LLC to Premier Silica LLC ("Premier Silica"). Premier Silica's core business is the operation of mines and processing facilities that produce, process and sell sand, primarily to upstream oil and gas companies for proppant used in the fracture stimulation of oil and gas wells in the United States. Premier Silica's business is supportive to the Company's vertical integration strategy of controlling major cost components of the Company's drilling and production activities in the areas where the Company has a significant inventory of drilling locations. The aggregate purchase price of Premier Silica was $297.1 million, including normal closing adjustments, and was funded from available cash and borrowings under the Company's credit facility.

The Sand Acquisition was accounted for as a business combination which, among other things, requires that assets acquired and liabilities assumed be measured at their acquisition date fair values. The fair value of the assets acquired totaled $474.9 million and were primarily comprised of proved sand reserves, probable sand reserves and mine processing facilities and equipment of $460.3 million. The fair value of liabilities assumed totaled $177.8 million and were primarily comprised of deferred income taxes of $151.0 million.

The Company recognized $2.3 million of acquisition-related costs associated with the Sand Acquisition that were expensed during the year ended December 31, 2012. These costs are included in other expense in the accompanying consolidated statements of operations for the year ended December 31, 2012, as presented in Note N.

Discontinued Operations

Barnett Shale. During the third quarter of 2012, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas. The Company classified its (i) Barnett Shale assets and liabilities as discontinued operations held for sale in the consolidated balance sheet as of September 30, 2012, and (ii) Barnett Shale results of operations as income or loss from discontinued operations, net of tax, in the consolidated statements of operations for the three and nine months ended September 30, 2012 and 2011 (representing a recasting of the Barnett Shale results of operations for the three and nine months ended September 30, 2011, which were originally classified as continuing operations).

The Company retained a capital markets advisor during the third quarter of 2012 and actively solicited offers from interested purchasers of the Barnett Shale field assets. Those efforts were unsuccessful in attracting binding offers under acceptable terms to the Company. Since the Company was unable to dispose of its Barnett Shale field assets under acceptable terms, in December 2012, the Company decided to retain the assets; therefore, the Barnett Shale assets and liabilities no longer qualified as held for sale or discontinued operations. Accordingly, all amounts related to the Barnett Shale that were previously reported as (i) discontinued operations held for sale were reclassified to continuing operations at December 31, 2012, (ii) results from the Barnett Shale operations was recorded to continuing operations for the quarter ended December 31, 2012 and results included in discontinued operations were reclassified to income from continuing operations for the nine months ended September 30, 2012, and (iii) amounts in periods prior to 2012 that were reflected in discontinued operations were reclassified to continuing operations.

Assets classified as held for sale must be assessed for impairment at the point in time when they no longer qualify as held for sale and their carrying values (adjusted for any depreciation, depletion or amortization that would have been recognized had the asset been continuously classified as held and used) cannot exceed the lower of fair value or carrying value. Accordingly, the Company assessed its Barnett Shale field proved and unproved oil and gas properties for impairment during the fourth quarter of 2012. As a result of those assessments, the Company reduced the carrying value of its Barnett Shale field proved properties by $87.7 million and its Barnett Shale field unproved properties by $71.8 million. The reductions in the carrying values of the proved and unproved properties are included in impairment of oil and gas properties and exploration abandonments, respectively, in the Company's accompanying consolidated statements of operations for the year ended December 31, 2012. See Note D for further information about the fair values used to calculate the Barnett Shale impairment.

South Africa. During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest its net assets in South Africa ("Pioneer South Africa"). During the first quarter of 2012, the Company agreed to sell its net assets in 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.

85

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

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 pretax gain of $28.6 million. The Company classified (i) Pioneer South Africa's assets and liabilities as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2011 and (ii) Pioneer South Africa's results of operations prior to the completion of the sale as income from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

Tunisia. In February 2011, the Company sold 100 percent of the Company's share holdings in Pioneer Natural Resources Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as "Pioneer Tunisia") to an unaffiliated third party for cash proceeds of $802.5 million, including normal closing adjustments and excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million. Accordingly, the Company has classified the results of operations of Pioneer Tunisia, prior to its sale, as discontinued operations, net of tax, in the accompanying consolidated statements of operations.

The following table represents the components of the Company's discontinued operations for the years ended December 31, 2012, 2011 and 2010 (principally related to the divestitures of the Company's net assets in Pioneer South Africa and Pioneer Tunisia):

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Revenues and other income:
Oil and gas	$	49,192		$	100,275		$	236,343
Interest and other (a)	95			6,193			49,076
Gain on disposition of assets, net (b)	28,546			645,241			36
	77,833			751,709			285,455
Costs and expenses:
Oil and gas production	2,254			5,519			14,754
Depletion, depreciation and amortization (b)	—			41,916			98,495
Exploration and abandonments	70			4,268			15,908
General and administrative	1,975			10,286			5,697
Accretion of discount on asset retirement obligations (b)	1,521			2,686			2,923
Interest	—			773			—
Other	1,196			5,159			13,898
	7,016			70,607			151,675
Income from discontinued operations before income taxes	70,817			681,102			133,780
Current tax provision	(7,720		)	(43,897		)	(25,486		)
Deferred tax (provision) benefit (b)	(7,948		)	(214,053		)	25,756
Income from discontinued operations	$	55,149		$	423,152		$	134,050

 ____________________

(a) Primarily comprised of (i) $35.3 million of interest on excess royalty payments received from Bureau of Ocean Energy Management, Regulation, and Enforcement during the second quarter of 2010, (ii) $2.0 million of additional interest received during the first quarter of 2011 associated with the 2010 recovery of the aforementioned excess royalties and (iii) $2.8 million of interest income associated with Pioneer Tunisia operations during the first quarter of 2011.

(b) Represents significant noncash components of discontinued operations.

86

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

As of December 31, 2011, the carrying values of Pioneer South Africa assets and liabilities, respectively, were included in discontinued operations held for sale in the accompanying consolidated balance sheet and were comprised of the following:

	December 31, 2011
	(in thousands)
Composition of assets included in discontinued operations held for sale:
Current assets (excluding cash and cash equivalents)	$	10,465
Property, plant and equipment	53,025
Deferred tax assets	9,816
Other assets, net	43
Total assets	$	73,349
Composition of liabilities included in discontinued operations held for sale:
Current liabilities	$	11,689
Deferred revenue	34,320
Other liabilities	29,892
Total liabilities	$	75,901

As of December 31, 2012, there are no assets and liabilities held for sale.

Divestitures Recorded in Continuing Operations

The Company recorded net gains on disposition of assets in continuing operations of $58.1 million and $19.1 million during the years ended December 31, 2012 and 2010, respectively, and a net loss on disposition of assets in continuing operations of $3.6 million during the year ended December 31, 2011. The following describes the significant divestitures of continuing operations:

• Alaska. In August 2012, the Company completed the sale of its interest in the Cosmopolitan Unit in the Cook Inlet of Alaska to unaffiliated third parties for cash proceeds of $10.1 million, which, together with certain Company obligations assumed by the purchasers, resulted in a pretax gain of $12.6 million.

• Eagle Ford Shale. In January 2012, the Company sold a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale play to unaffiliated third parties for cash proceeds of $54.7 million, which resulted in a pretax gain of $42.6 million.

In June 2010, the Company entered into an Eagle Ford Shale joint venture and associated therewith the Company sold 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds, resulting in a pretax gain of $6.0 million in 2010.

• Uinta/Piceance. During 2010, the Company sold certain proved and unproved oil and gas properties in the Uinta/Piceance area for net proceeds of $11.8 million and the assumption by the purchaser of certain asset retirement obligations, resulting in a pretax gain of $17.3 million.

• Other Assets. During 2012, 2011 and 2010, the Company sold unproved leaseholds, inventory and other property and equipment and recorded a pretax net loss of $1.1 million, $5.1 million and $4.2 million, respectively.

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.

87

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

• 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 tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2012 and 2011 for each of the fair value hierarchy levels:

	Fair Value Measurements 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 December 31, 2012
	(in thousands)
Assets:
Trading securities	$	124	$	154	$	—	$	278
Commodity derivatives	—		334,376		—		334,376
Deferred compensation plan assets	49,685		—		—		49,685
Total assets	49,809		334,530		—		384,339
Liabilities:
Commodity derivatives	—		15,999		—		15,999
Interest rate derivatives	—		9,724		—		9,724
Total liabilities	—		25,723		—		25,723
Total recurring fair value measurements	$	49,809	$	308,807	$	—	$	358,616
	Fair Value Measurements 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 December 31, 2011
	(in thousands)
Assets:
Trading securities	$	257	$	168	$	—	$	425
Commodity derivatives	—		482,075		—		482,075
Deferred compensation plan assets	39,904		—		—		39,904
Total assets	40,161		482,243		—		522,404
Liabilities:
Commodity derivatives	—		92,322		—		92,322
Interest rate derivatives	—		15,654		—		15,654
Total liabilities	—		107,976		—		107,976
Total recurring fair value measurements	$	40,161	$	374,267	$	—	$	414,428

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 December 31, 2012 and 2011, 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.

88

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

Commodity derivatives.The Company's commodity derivatives represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts. The Company's oil, NGL and gas swap, collar and collar contracts with short puts asset and liability measurements represent Level 2 inputs in the hierarchy priority. 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 which 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 December 31, 2012 and 2011 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 December 31, 2012 and 2011 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted 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 priority.

Assets and liabilities measured at fair value on a nonrecurring basis. During 2012 and 2011, reductions in management's longer-term commodity price outlooks ("Management's Price Outlooks") provided indications of possible impairment of the Company's predominately dry gas properties in the Edwards Trend and Austin Chalk fields in South Texas, the Barnett Shale field in North Texas and the Raton field in southeastern Colorado. As a result of management's assessments, during June 2012 and December 2011, the Company recognized impairment charges to reduce the carrying values of the Barnett Shale field and the Edwards Trend/Austin Chalk fields, respectively, to their fair values.

As discussed in Note C, during December 2012, the Barnett Shale field assets were reclassified from held for sale to held and used. This reclassification triggered an additional assessment to determine whether an impairment charge was necessary to adjust the carrying value of Barnett Shale field proved and unproved properties to the lower of their fair value or carrying value. Based upon this assessment, the Company recognized impairment charges to reduce the carrying value of the Barnett Shale field proved and unproved properties to their fair values during December 2012.

The Company calculated the fair values of the Barnett Shale field and the Edwards Trend/Austin Chalk fields proved properties using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included Management's Price Outlooks and management's outlooks for (i) production costs, (ii) capital expenditures, (iii) production and (iv) estimated proved reserves and risk-adjusted probable reserves. Management's Price Outlooks are developed based on third-party commodity futures price outlooks as of a measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value. The following table presents the fair value and impairment (in millions) for each of the Company's 2012 and 2011 proved property impairments, as well as the oil price per barrel ("BBL") and gas price per British thermal unit ("MMBTU") utilized in respective Management's Price Outlooks:

		Fair				Management's Price Outlooks
		Value		Impairment		Oil		Gas
Edwards Trend/Austin Chalk	December 2011	$	189.9	$	354.4	$	92.69	$	5.14
Barnett Shale	June 2012	$	128.7	$	444.9	$	87.09	$	4.64
Barnett Shale	December 2012	$	184.8	$	87.7	$	87.10	$	4.92

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 Price Outlooks and (iv) increases or decreases in production and capital costs associated with these fields.

During December 2012, the Company recorded an impairment charge to reduce the carrying value of unproved properties in the Barnett Shale field of $71.8 million. The Company calculated the estimated fair value of the Barnett Shale unproved properties using significant Level 3 assumptions based on average lease bonuses per acre for its Barnett liquid-rich acreage, allocating no value to dry gas acreage as the Company does not intend to develop that acreage.

89

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

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 December 31, 2012 and 2011 are as follows:

	December 31, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	3,721,193	$	4,555,770	$	2,528,905	$	3,105,585

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 Pioneer Southwest's 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, short-term receivables, prepaids, 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.

Concentrations of credit risk. As of December 31, 2012, the Company's primary concentration of credit risks are the risks of collecting accounts receivable – trade and the risk of counterparties' failure to perform under derivative obligations. See Note L for information regarding the Company's major customers.

The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note E for additional information regarding the Company's derivative activities and information regarding derivative net assets and liabilities by counterparty.

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.

90

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

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 BBLs that were outstanding as of December 31, 2012 under the Company's oil derivative contracts and the weighted average oil prices per BBL for those contracts:

	2013			2014		2015
Swap contracts:
Volume (BBL)	3,000			—		—
Average price per BBL	$	81.02		$	—	$	—
Collar contracts with short puts:
Volume (BBL) (a)	71,029			60,000		26,000
Average price per BBL:
Ceiling	$	119.76		$	117.06	$	104.45
Floor	$	92.27		$	92.67	$	95.00
Short put	$	74.28		$	76.58	$	80.00
Rollfactor adjustment swap contracts:
Volume (BBL) (a)	6,000			—		—
NYMEX roll price (b)	$	0.43		$	—	$	—
Basis swap contracts:
Index swap volume (BBL) (c)	2,055			—		—
Average price per BBL (d)	$	(5.75	)	$	—	$	—

 ____________________

(a) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional 2014 (i) collar contracts with short puts for 9,000 BBLs per day with a ceiling price of $104.13 per BBL, a floor price of $95.00 per BBL and a short put price of $80.00 per BBL and (ii) rollfactor swap contracts for 15,000 BBLs per day priced at $0.38 per BBL; and (iii) replaced 5,000 BBLs per day of 2014 collar contracts with short puts with a ceiling price of $124.00 per BBL, a floor price of $90.00 per BBL and short put price of $72.00 per BBL with 5,000 BBLs per day of 2014 collar contracts with short puts with a ceiling price of $105.74 per BBL, a floor price of $100.00 per BBL and short put price of $80.00 per BBL.

(b) 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.

(c) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional basis swap contracts for 1,000 BBLs per day of October through December 2013 production with a price differential between Cushing WTI and Louisiana Light Sweet crude of $7.60 per BBL.

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

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 posted prices.

As of December 31, 2012, the Company had NGL collar contracts with short put derivatives for 1,064 BBLs per day of 2013 production with a ceiling price of $105.28 per BBL, a floor price of $89.30 per BBL and short put price of $75.20 per BBL and 1,000 BBLs per day of 2014 production with a ceiling price of $109.50 per BBL, a floor price of $95.00 per BBL and short put price of $80.00 per BBL.

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

91

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

The following table sets forth the volumes per day in MMBTUs that were outstanding as of December 31, 2012 under the Company's gas derivative contracts and the weighted average gas prices per MMBTU for those contracts:

	2013			2014			2015
Swap contracts:
Volume (MMBTU)	162,500			105,000			—
Price per MMBTU	$	5.13		$	4.03		$	—
Collar contracts:
Volume (MMBTU)	150,000			—			—
Price per MMBTU:
Ceiling	$	6.25		$	—		$	—
Floor	$	5.00		$	—		$	—
Collar contracts with short puts:
Volume (MMBTU)	—			25,000			225,000
Price per MMBTU:
Ceiling	$	—		$	4.70		$	5.09
Floor	$	—		$	4.00		$	4.00
Short put	$	—		$	3.00		$	3.00
Basis swap contracts:
Volume (MMBTU)	162,500			10,000			—
Price per MMBTU	$	(0.22	)	$	(0.19	)	$	—

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

As of December 31, 2012 the Company had marketing derivative gas index swap contracts outstanding for 40,000 MMBTU of January through March 2013 volumes with a price differential of $0.25 per MMBTU. During the period from January 1, 2013 to February 8, 2013, the Company entered into additional marketing derivative gas index swap contracts for 25,000 MMBTU per day of April 2013 volumes with a price differential of $0.35 per MMBTU.

Interest rates. As of December 31, 2012, 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 during December 2015.

Tabular disclosure of derivative fair value. Since February 2009, all of the Company's derivatives have been accounted for as non-hedge derivatives. The following tables provide disclosure of the Company's derivative instruments for the years ended December 31, 2012 and 2011:

Fair Value of Derivative Instruments as of December 31, 2012
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	286,805	Derivatives - current	$	21,102
Commodity price derivatives	Derivatives - noncurrent	61,618		Derivatives - noncurrent	8,944
Interest rate derivatives	Derivatives - noncurrent	—		Derivatives - noncurrent	9,724
		$	348,423		$	39,770

92

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

Fair Value of Derivative Instruments as of December 31, 2011
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	248,809	Derivatives - current	$	68,735
Commodity price derivatives	Derivatives - noncurrent	257,368		Derivatives - noncurrent	47,689
Interest rate derivatives	Derivatives - current	—		Derivatives - current	15,654
		$	506,177		$	132,078

 _____________________

(a) Derivative assets and liabilities shown in the tables above are presented as gross assets and liabilities, without regard to master netting arrangements which are considered in the presentations of derivative assets and liabilities in the accompanying consolidated balance sheets.

Derivatives in Cash Flow Hedging Relationships	Location of Gain/(Loss) Reclassified from AOCI into Earnings	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
		Year Ended December 31,
		2012			2011			2010
		(in thousands)
Interest rate derivatives	Interest expense	$	(1,699	)	$	(282	)	$	(1,698	)
Interest rate derivatives	Derivative gains, net	—			—			(2,465		)
Commodity price derivatives	Oil and gas revenue	(3,156		)	32,918			89,040
Total		$	(4,855	)	$	32,636		$	84,877

Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Earnings on Derivatives	Amount of Gain (Loss) Recognized in Earnings on Derivatives
		Year Ended December 31,
		2012			2011		2010
		(in thousands)
Interest rate derivatives	Derivative gains, net	$	(22,428	)	$	3,098	$	36,597
Commodity price derivatives	Derivative gains, net	352,679			389,654		414,302
Total		$	330,251		$	392,752	$	450,899

AOCI - Hedging. The effective portions of discontinued cash flow hedge gains and losses, net of associated taxes, were reflected in AOCI - Hedging as of December 31, 2011 and 2010, and were transferred to oil revenue and to interest expense in the same periods in which the hedged transactions were recorded in earnings.

As of December 31, 2011, AOCI - Hedging was $3.1 million of net deferred losses. The AOCI - Hedging balance as of December 31, 2011 was comprised of $3.2 million and $1.7 million of net deferred losses on the effective portions of discontinued commodity and interest rate hedges, respectively, offset partially by $1.7 million of associated net deferred tax benefits. During 2012, the remaining net deferred hedge losses in AOCI - Hedging were transferred to earnings.

Derivative counterparties. 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.

93

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

The following table provides the Company's net derivative assets or liabilities by counterparty as of December 31, 2012:

	Net Assets (Liabilities)
	(in thousands)
Citibank, N.A.	$	72,218
JP Morgan Chase	48,606
Barclays Capital	36,736
BMO Financial Group	26,560
Credit Suisse	21,196
J. Aron & Company	20,138
BNP Paribas	19,420
Toronto Dominion	18,802
Merrill Lynch	17,136
Morgan Stanley	13,893
Den Norske Bank	7,487
Societe Generale	5,700
Wells Fargo Bank, N.A.	5,024
Macquarie Bank	380
Royal Bank of Canada	(97		)
Deutsche Bank	(327		)
Credit Agricole	(1,991		)
UBS	(2,228		)
Total	$	308,653

NOTE F.    Exploratory Well Costs

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

The following table reflects the Company's capitalized exploratory well and project activity during each of the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Beginning capitalized exploratory well costs	$	107,596		$	96,193		$	127,574
Additions to exploratory well costs pending the determination of proved reserves	926,084			524,313			238,905
Reclassification due to determination of proved reserves	(790,373		)	(480,716		)	(160,879		)
Disposition of assets sold	—			(28,938		)	(17,601		)
Exploratory well costs charged to exploration and abandonment expense	(30,637		)	(3,256		)	(91,806		)
Ending capitalized exploratory well costs	$	212,670		$	107,596		$	96,193

94

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

The following table provides an aging, as of December 31, 2012, 2011 and 2010 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed:

	Year Ended December 31,
	2012		2011		2010
	(in thousands, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	190,678	$	107,596	$	70,635
More than one year	21,992		—		25,558
	$	212,670	$	107,596	$	96,193
Number of projects with exploratory well costs that have been suspended for a period greater than one year	1		—		3

Alaska - Oooguruk.As of December 31, 2012, the Company has $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, sub-surface damages were sustained. The Company currently expects to recomplete the well in mid-2013.

NOTE G.     Long-term Debt and Interest Expense

Long-term debt, including the effects of net deferred fair value hedge losses and issuance discounts, consisted of the following components at December 31, 2012 and 2011:

	December 31,
	2012			2011
	(in thousands)
Outstanding debt principal balances:
Pioneer credit facility	$	474,000		$	—
Pioneer Southwest credit facility	126,000			32,000
5.875% senior notes due 2016	455,385			455,385
6.65% senior notes due 2017	485,100			485,100
6.875 % senior notes due 2018	449,500			449,500
7.500 % senior notes due 2020	450,000			450,000
3.95% senior notes due 2022	600,000			—
7.20% senior notes due 2028	250,000			250,000
2.875% convertible senior notes due 2038	479,907			479,930
	3,769,892			2,601,915
Issuance discounts	(47,309		)	(71,301		)
Net deferred fair value hedge losses	(1,390		)	(1,709		)
Total long-term debt	$	3,721,193		$	2,528,905

Credit Facility. During December 2012, the Company entered into the First Amendment to the Second Amended and Restated 5-Year Revolving Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that extended the maturity to December 20, 2017, unless extended in accordance with the terms of the Credit Facility, and increased the aggregate loan commitments from $1.25 billion to $1.5 billion. The Company accounted for the entry into the Credit Facility as a modification of the prior agreement and capitalized the debt issuance costs along with those unamortized issuance costs that remained from the issuance of the prior agreement. As of December 31, 2012, the Company had outstanding borrowings of $474.0 million under the Credit Facility and $2.2 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $1.0 billion of unused borrowing capacity under the Credit Facility.

Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $150 million. Revolving loans under the Credit Facility bear interest, at the option of the Company,

95

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National Association or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin, which is currently 0.5 percent based on the Company's debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the "Applicable Margin"), which is currently 1.50 percent and is also determined by the Company's debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the "ASK" rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company's debt rating (currently 0.25 percent). Borrowings under the Credit Facility are general unsecured obligations.

The Credit Facility requires the maintenance of a ratio of total debt to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset impairments not to exceed .60 to 1.0. As of December 31, 2012, the Company was in compliance with all of its debt covenants.

During March 2012, Pioneer Southwest entered into a $300 million Amended and Restated 5-Year Revolving Credit Agreement (the "Pioneer Southwest Credit Facility") with a syndicate of financial institutions that matures in March 2017, unless extended in accordance with the terms of the Pioneer Southwest Credit Facility. The Pioneer Southwest Credit Facility replaced Pioneer Southwest's 5-Year Revolving Credit Agreement entered into in May 2008. As of December 31, 2012, there were $126 million of outstanding borrowings under the Pioneer Southwest Credit Facility. Borrowings under the Pioneer Southwest Credit Facility are general unsecured obligations.

The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions. Borrowings under the Pioneer Southwest Credit Facility may be in the form of Eurodollar rate loans, base rate committed loans or swing line loans. Eurodollar rate loans bear interest annually at LIBOR, plus a margin (the "Applicable Rate") (currently 1.625 percent) that is determined by a reference grid based on Pioneer Southwest's consolidated leverage ratio. Base rate committed loans bear interest annually at a base rate equal to the higher of (i) the Federal Funds Rate plus 0.5 percent (ii) the one-month Eurodollar rate plus .01 or (iii) the Bank of America prime rate (the "Base Rate") plus a margin (currently 0.625 percent). Swing line loans bear interest annually at the Base Rate plus the Applicable Rate.

The Pioneer Southwest Credit Facility contains certain financial covenants, including (i) the maintenance of a quarter end consolidated leverage ratio (representing a ratio of consolidated indebtedness of Pioneer Southwest to consolidated earnings before depreciation, depletion and amortization; impairment of long-lived assets; exploration expense; accretion of discount on asset retirement obligations; interest expense; income taxes; gain or loss on the disposition of assets; noncash commodity derivative related activity; noncash equity-based compensation; and other noncash items) of not more than 3.5 to 1.0 and (ii) the maintenance of a ratio of the net present value of Pioneer Southwest's projected future cash flows from its oil and gas assets to total debt of at least 1.75 to 1.0. As of December 31, 2012, Pioneer Southwest was in compliance with all of its debt covenants.

The net present value covenant limits Pioneer Southwest's available borrowing capacity under the Pioneer Southwest Credit Facility to $134.7 million as of December 31, 2012, and may further limit Pioneer Southwest's borrowing capacity in the future. The variables on which the calculation of net present value is based (including assumed commodity prices and discount rate) are subject to adjustment by the lenders. As a result, a sustained decline in commodity prices could reduce Pioneer Southwest's borrowing capacity under the Pioneer Southwest Credit Facility. In addition, the Pioneer Southwest Credit Facility contains various covenants that limit, among other things, Pioneer Southwest's ability to grant liens, incur additional indebtedness, engage in a merger, enter into transactions with affiliates, pay distributions or repurchase equity, and sell its assets. If any default or event of default (as defined in the Pioneer Southwest Credit Facility) were to occur, the Pioneer Southwest Credit Facility would prohibit Pioneer Southwest from making distributions to unitholders. Such events of default include, among others, nonpayment of principal or interest, violations of covenants, bankruptcy and material judgments and liabilities.

Pioneer Southwest pays a commitment fee on the unused portion of the Pioneer Southwest Credit Facility. The commitment fee is variable based on Pioneer Southwest's consolidated leverage ratio. For the twelve months ended December 31, 2012, the commitment fee was 0.275 percent.

Senior notes. During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of $8.5 million of offering discounts and costs, of $591.5 million. The Company used the net proceeds from the issuance to reduce outstanding borrowings under the Credit Facility.

96

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

Convertible senior notes. During January 2008, the Company issued $500 million of 2.875% Convertible Senior Notes due 2038 (the "Convertible Senior Notes"). The Convertible Senior Notes mature on January 15, 2038 but are convertible under certain circumstances, using a net share settlement process, into a combination of cash and the Company's common stock pursuant to a formula. In general, upon conversion of a Convertible Senior Note, the holder of such note will receive cash equal to the principal amount of the Convertible Senior Note and the Company's common stock for the Convertible Senior Note's conversion value in excess of such principal amount. If at the time of conversion the applicable price of the Company's common stock exceeds the base conversion price, holders will receive up to an additional 8.9532 shares of the Company's common stock per $1,000 principal amount of notes, as determined pursuant to a specified formula.

The Company may redeem the Convertible Senior Notes for cash at any time on or after January 15, 2013 at a price equal to full principal amount plus accrued and unpaid interest. Holders of the Convertible Senior Notes may require the Company to purchase their Convertible Senior Notes for cash at a price equal to 100 percent of the principal amount plus accrued and unpaid interest if certain defined fundamental changes occur, as defined in the agreement, or on January 15, 2013, 2018, 2023, 2028 or 2033. On January 15, 2013, certain holders put $8 thousand principal amount of the Convertible Senior Notes to the Company and the Company paid $8 thousand, including accrued and unpaid interest, to settle the Convertible Senior Notes. Additionally, holders may convert their notes at their option in the following circumstances:

• Following defined periods during which the reported sales prices of the Company's common stock exceeds 130 percent of the base conversion price (initially $72.60 per share, which is equivalent to an initial base conversion rate of 13.7741 common shares per $1,000 principal amount of Convertible Senior Notes);

• During five-day periods following defined circumstances when the trading price of the Convertible Senior Notes is less than 97 percent of the price of the Company's common stock times a defined conversion rate;

• Upon notice of redemption by the Company; and

• During the period beginning October 15, 2037, and ending at the close of business on the business day immediately preceding the maturity date.

The Company's stock prices during each of December 2012, September 2012, March 2012 and March 2011 met the price threshold that caused the Convertible Senior Notes to become convertible at the option of the holders during the three months ended March 31, 2013, December 31, 2012, June 30, 2012 and June 30, 2011, respectively. Associated therewith, certain holders tendered $111 thousand and $70 thousand principal amount of the Convertible Senior Notes for conversion during the twelve months ended December 31, 2012 and 2011, respectively. During 2012 and 2011, the Company paid the tendering holders of the Convertible Senior Notes a total of $23 thousand and $71 thousand of cash and issued to the tendering holders 112 shares and 340 shares of the Company's common stock in accordance with the terms of the Convertible Senior Notes indenture supplement, respectively. For the remaining notes tendered during 2012, the Company paid $88 thousand in cash and issued 707 shares in 2013.

In January and February 2013, holders of $240.6 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. In general, upon conversion of a Convertible Senior Note, the holder will receive cash equal to the principal amount of the Convertible Senior Note and shares of the Company's common stock for the Convertible Senior Note's conversion value in excess of the principal amount. If all outstanding Convertible Senior Notes had been converted on December 31, 2012, the holders would have received $479.9 million of cash and approximately 3.4 million shares of the Company's common stock, which were valued at $358.8 million based on the closing price of the common stock on December 31, 2012.

Interest on the principal amount of the Convertible Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. Beginning on January 15, 2013, during any six-month period thereafter from January 15 to July 14 and from July 15 to January 14, if the average trading price (as defined in the Convertible Senior Notes indenture supplement) of a Convertible Senior Note for the five consecutive trading days immediately preceding the first day of the applicable six-month interest period equals or exceeds 120 percent of the principal amount of the note, interest on the principal amount of the Convertible Senior Notes will be 2.375 percent solely for the relevant interest period. 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, accordingly, the interest rate in effect during the January 15, 2013 to July 14, 2013 period is reduced to 2.375 percent.

As of December 31, 2012 and 2011, the Convertible Senior Notes had an unamortized discount, which is being amortized ratably through January 2013, of $753 thousand and $18.5 million, respectively, and a net carrying value of $479.2 million and $461.5 million, respectively. For the years ended December 31, 2012, 2011 and 2010, the Company recorded $33.5 million, $32.3

97

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

million and $31.1 million, respectively, of interest expense relating to the Convertible Senior Notes, which had an effective interest rate of 6.75 percent. As of December 31, 2012 and 2011, $49.5 million is recorded in Additional Paid-in Capital as the equity component of the Convertible Senior Notes.

The Company's senior notes and convertible senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes and Convertible Senior Notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company's senior notes and Convertible Senior Notes is payable semiannually.

Principal maturities. Principal maturities of long-term debt at December 31, 2012, are as follows (in thousands):

2013	$	479,907
2014	$	—
2015	$	—
2016	$	455,385
2017	$	1,085,100
Thereafter	$	1,749,500

The principal maturities during 2013 in the preceding table represent the Convertible Senior Notes, which were subject to repurchase at the option of both the holders and the Company in 2013. As the Company had the intent and ability to fund any required cash payments upon the conversion, redemption or repurchase of the Convertible Senior Notes with borrowing capacity under the Credit Facility, the Convertible Senior Notes are classified as long-term debt in the accompanying balance sheets.

Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Cash payments for interest	$	168,665		$	165,307		$	155,854
Accretion/amortization of discounts or premiums on loans	27,351			25,210			23,304
Accretion of discount on derivative obligations	—			—			521
Amortization of net deferred hedge losses (a)	2,018			573			517
Accretion of discount on postretirement benefit obligations	257			315			433
Amortization of capitalized loan fees	5,937			5,385			5,698
Net changes in accruals	10,842			(1,768		)	11,999
Interest incurred	215,070			195,022			198,326
Less capitalized interest	(10,848		)	(13,362		)	(15,242		)
Total interest expense	$	204,222		$	181,660		$	183,084

__________________

(a) Includes interest rate derivative hedges of $1.7 million, $282 thousand, and $1.7 million for the periods ended December 31, 2012, 2011 and 2010, respectively, that were reclassified from AOCI - Hedging into earnings upon expiration (see Note E).

NOTE H.     Incentive Plans

Retirement Plans

Deferred compensation retirement plan. In August 1997, the Compensation Committee of the Company's board of directors (the "Board") approved a deferred compensation retirement plan for the officers and certain key employees of the Company. Each officer and key employee is allowed to contribute up to 25 percent of their base salary and 100 percent of their annual bonus. The Company will provide a matching contribution of 100 percent of the officer's and key employee's contribution limited to the first ten percent of the officer's base salary and eight percent of the key employee's base salary. The Company's matching contribution

98

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

vests immediately. A trust fund has been established by the Company to accumulate the contributions made under this retirement plan. The Company's matching contributions were $2.4 million, $2.2 million and $1.9 million for the years ended December 31, 2012, 2011 and 2010, respectively.

401(k) plan. The Pioneer USA 401(k) and Matching Plan (the "401(k) Plan") is a defined contribution plan established under the Internal Revenue Code Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute an amount up to 80 percent of their annual salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a participant's contributions to the 401(k) Plan that are not in excess of five percent of the participant's base compensation (the "Matching Contribution"). Each participant's account is credited with the participant's contributions, Matching Contributions and allocations of the 401(k) Plan's earnings. Participants are fully vested in their account balances except for Matching Contributions and their proportionate share of 401(k) Plan earnings attributable to Matching Contributions, which proportionately vest over a four-year period that begins with the participant's date of hire. During the years ended December 31, 2012, 2011 and 2010, the Company recognized compensation expense of $24.7 million, $18.3 million and $13.4 million, respectively, as a result of Matching Contributions.

Stock-based compensation costs. In accordance with GAAP, the Company records stock-based compensation expense, equal to the fair value of share-based payments, ratably over the vesting periods of the Long-Term Incentive Plan ("LTIP") awards, the Series B unit awards issued by Sendero, the Pioneer Southwest Long-Term Incentive Plan ("Pioneer Southwest LTIP") awards and for payments associated with the Company's Employee Stock Purchase Plan ("ESPP").

The following table reflects stock-based compensation expense recorded for each type of incentive award and the associated income tax benefit for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Restricted stock-equity awards (a)	$	48,876	$	32,861	$	31,712
Restricted stock-liability awards	22,419		10,882		4,900
Stock options (b)	4,110		2,936		1,522
Performance unit awards	6,162		4,500		4,635
Pioneer Southwest LTIP	1,098		761		475
Sendero Series B units	982		1,020		1,020
ESPP	2,437		125		1,034
Total	$	86,084	$	53,085	$	45,298
Income tax benefit	$	27,901	$	22,084	$	14,019

 _____________________

(a) For the year ended December 31, 2010, stock-based compensation expense included a charge of $1.3 million for the modification of equity awards associated with termination agreements made with 12 employees affected by the divestiture of the Company's Tunisian subsidiaries. The modification accelerated vesting of all unvested equity awards for the 12 participants to the closing date of the transaction. The $1.3 million charge, net of the associated tax benefit, is included in income from discontinued operations, net of tax, in the accompanying consolidated statements of operations for the year ended December 31, 2010.

(b) Cash proceeds received from stock option exercises during 2012, 2011 and 2010 amounted to $3.1 million, $619 thousand and $4.8 million, respectively.

As of December 31, 2012, there was $131.1 million of unrecognized stock-based compensation expense related to unvested share and unit based compensation plans, including $24.5 million attributable to Liability Awards. The stock-based compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis.

99

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

Pioneer Long-Term Incentive Plan

In May 2006, the Company's stockholders approved the LTIP, which provides for the granting of various forms of awards, including stock options, stock appreciation rights, performance units, restricted stock and restricted stock units to directors, officers and employees of the Company. The LTIP provides for the issuance of 9.1 million shares pursuant to awards under the plan. The shares to be delivered under the LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company, including shares purchased on the open market.

The following table shows the number of shares available for issuance pursuant to awards under the Company's LTIP at December 31, 2012:

Approved and authorized awards	9,100,000
Awards issued after May 3, 2006	(6,134,118	)
Awards available for future grant	2,965,882

Restricted stock awards. During 2012, the Company awarded 1,153,029 restricted shares or units of the Company's common stock as compensation to directors, officers and employees of the Company (including 240,486 shares or units representing Liability Awards). The Company's issued shares, as reflected in the consolidated balance sheets as of December 31, 2012 do not include 304,260 of issued, but unvested shares awarded under stock-based compensation plans that have voting rights.

The following table reflects the restricted stock award activity for the year ended December 31, 2012:

	Equity Awards				Liability Awards
	Number of Shares		Weighted Average Grant- Date Fair Value		Number of Shares
Outstanding at beginning of year	1,857,612		$	39.95	322,925
Shares granted	912,543		$	113.02	240,486
Shares forfeited	(28,011	)	$	101.91	(29,060	)
Shares vested	(1,229,382	)	$	23.75	(128,435	)
Outstanding at end of year	1,512,762		$	96.22	405,916

The weighted average grant-date fair value of restricted stock equity awards awarded during 2012, 2011 and 2010 was $113.02, $97.52 and $48.32, respectively. The fair value of shares for which restrictions lapsed during 2012, 2011 and 2010 was $137.2 million, $98.6 million and $42.9 million, respectively, based on the market price on the vesting date.

As of December 31, 2012 and 2011, accounts payable – due to affiliates in the accompanying consolidated balance sheet includes $18.8 million and $9.2 million of liabilities attributable to the Liability Awards, representing the fair value of employee services performed under outstanding awards as of that date. The fair value of shares for which restrictions lapsed during 2012 and 2011 was $14.2 million and $6.7 million, respectively, based on the market price on the vesting date. There were no Liability Awards that vested during 2010.

Stock option awards. Certain employees may be granted options to purchase shares of the Company's common stock with an exercise price equal to the fair market value of Pioneer common stock on the date of grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Option awards have a ten-year contract life. The expected life of an option is estimated based on historical and expected exercise behavior. The volatility assumption was estimated based upon expectations of volatility over the life of the option as measured by historical volatility. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the option. The dividend yield was based upon a seven-year average dividend yield.

100

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

The Company used the following weighted-average assumptions to estimate the fair value of stock options granted during the years ended December 31, 2012, 2011 and 2010:

	2012		2011		2010
Expected option life - years	7.0		7.0		7.0
Volatility	49.4	%	47.6	%	46.8	%
Risk-free interest rate	1.5	%	2.9	%	3.4	%
Dividend yield	0.4	%	0.4	%	0.4	%

A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2012 is presented below:

	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
					(in years)	(in thousands)
Outstanding at beginning of year	564,044		$	34.90
Options awarded	98,819		$	113.76
Options exercised	(195,377	)	$	15.62
Outstanding and expected to vest, at end of year	467,486		$	59.63	7.39	$	22,663
Exercisable at end of year	171,644		$	16.72	6.17	$	15,425

The weighted average grant-date fair value of options awarded during 2012, 2011 and 2010 was $56.29, $49.61 and $23.79, respectively, using the Black-Scholes option-pricing model. The intrinsic value of options exercised during 2012, 2011 and 2010 was $17.2 million, $1.5 million and $6.9 million, respectively, based on the difference between the market price at the exercise date and the option exercise price.

Performance unit awards. During 2012, 2011 and 2010, the Company awarded performance units to certain of the Company's officers under the LTIP. The number of shares of common stock to be issued is determined by comparing the Company's total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The performance unit awards vest over a 34-month service period. The grant-date fair values per unit of the 2012, 2011 and 2010 performance unit awards are $172.57, $134.68 and $63.52, respectively, which amounts were determined using the Monte Carlo simulation method and are being recognized as stock-based compensation expense ratably over the performance period. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. Expected volatilities utilized in the model were estimated using a historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant. The Company used the following assumptions to estimate the fair value of performance unit awards granted during 2012, 2011 and 2010:

	2012				2011				2010
Risk-free interest rate	0.40%				1.32%				1.36%
Range of volatilities	33.6	%	-	49.0%	50.2	%	-	84.1%	50.4	%	-	83.0%

101

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

The following table summarizes the performance unit activity for the year ended December 31, 2012:

	Number of Units (a)		Weighted  Average Grant-Date Fair Value
Beginning performance unit awards	114,128		$	90.64
Units granted	47,875		$	172.57
Units vested (b)	(70,633	)	$	63.52
Ending performance unit awards	91,370		$	154.53

 _____________________

(a) These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date.

(b) On December 31, 2012, the service period lapsed on 70,633 of these performance unit awards. The lapsed units earned 2.5 shares for each vested award representing 176,585 aggregate shares of common stock issued in 2012.

The fair value of shares for which restrictions lapsed during 2012, 2011 and 2010 was $18.8 million, $44.7 million and $27.4 million, respectively, based on the market price on the vesting date.

Pioneer Southwest Long-Term Incentive Plan

In May 2008, the board of directors of the general partner (the "General Partner") of Pioneer Southwest adopted the Pioneer Southwest LTIP, which provides for the granting of various forms of unit-based awards, including options, unit appreciation rights, phantom units, restricted units, unit awards and other unit-based awards, to directors, employees and consultants of the General Partner and its affiliates who perform services for Pioneer Southwest. The Pioneer Southwest LTIP limits the number of units that may be delivered pursuant to unit-based awards granted under the plan to 3.0 million common units.

The following table shows the number of awards available under the Pioneer Southwest LTIP at December 31, 2012:

Approved and authorized awards	3,000,000
Awards issued after May 6, 2008	(151,235	)
Awards available for future grant	2,848,765

During 2012, the General Partner awarded 7,496 restricted common units as compensation to directors of the General Partner under the Pioneer Southwest LTIP, which vest in May 2013. During 2011, the General Partner awarded 6,812 restricted common units as compensation to directors of the General Partner under the Pioneer Southwest LTIP, which vested in May 2012. During 2010, the General Partner awarded 8,744 restricted common units to directors of the General Partner under the Pioneer Southwest LTIP, which vested in May 2011.

	Restricted Unit Awards				Phantom Unit Awards
	Number of Units		Weighted Average Grant-Date Fair Value		Number of Units	Weighted Average Grant-Date Fair Value
Outstanding at beginning of year	7,492		$	28.47	65,157	$	27.08
Units granted	7,496		$	26.68	37,487	$	28.00
Lapse of restrictions	(7,492	)	$	28.47	—	$	—
Outstanding at end of year	7,496		$	26.68	102,644	$	27.42

The weighted average grant-date fair value of restricted common units awarded during 2012, 2011 and 2010 was $26.68, $29.35 and $22.87, respectively. The fair value of common units for which restrictions lapsed on the restricted common units during 2012, 2011 and 2010 was $200 thousand, $342 thousand and $324 thousand, respectively, based on the market price at the vesting date.

102

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

During 2012, 2011 and 2010, the General Partner awarded phantom units to certain members of management of the General Partner under Pioneer Southwest's LTIP. The phantom units entitle the recipients to common units of Pioneer Southwest after a three-year vesting period. The weighted average grant-date fair value of phantom common units awarded during 2012, 2011 and 2010 was $28.00, $32.16 and $22.74, respectively. No restrictions have lapsed on the phantom units outstanding.

Subsidiary Issuances of Unit-Based Compensation

During 2010, Sendero entered into restricted unit agreements with two key employees, granting 1,000 Series B units in Sendero. The Series B unit awards had a grant date fair value of $5.1 million, vest ratably over a five year service period and do not earn equity rights unless certain defined performance conditions are achieved by Sendero.

Employee Stock Purchase Plan

The Company has an ESPP that allows eligible employees to annually purchase the Company's common stock at a discounted price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to 15 percent of an employee's pay (subject to certain ESPP limits) during the eight-month offering period (January 1 to August 31). Participants in the ESPP purchase the Company's common stock at a price that is 15 percent below the closing sales price of the Company's common stock on either the first day or the last day of each offering period, whichever closing sales price is lower.

The following table shows the number of shares available for issuance under the ESPP at December 31, 2012:

Approved and authorized shares	1,250,000
Shares issued	(678,882	)
Shares available for future issuance	571,118

Postretirement Benefit Obligations

At December 31, 2012 and 2011, the Company had $9.7 million and $7.5 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 two funded plans that the Company assumed sponsorship of in conjunction with the acquisition of Premier Silica. Other than the Company's retirement plan and the two legacy-Premier Silica plans, the participants of these plans are not current employees of the Company.

The unfunded plans had no assets as of December 31, 2012 or 2011. The Company's funding policy for the Premier Silica plans 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.

103

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

NOTE I.    Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. The following table summarizes the Company's asset retirement obligation activity during the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Beginning asset retirement obligations	$	136,742		$	152,291		$	166,434
Liabilities assumed in acquisitions	10,498			6			6
New wells placed on production	9,593			9,233			5,218
Changes in estimates (a)	51,536			7,490			24,075
Liabilities reclassified to discontinued operations held for sale	—			(29,892		)	(5,779		)
Disposition of wells	(2,536		)	(448		)	(30,693		)
Liabilities settled	(18,066		)	(12,880		)	(17,838		)
Accretion of discount on continuing operations	9,887			8,256			7,945
Accretion of discount from integrated services (b)	100			—			—
Accretion of discount on discontinued operations	—			2,686			2,923
Ending asset retirement obligations	$	197,754		$	136,742		$	152,291

 _____________________

(a) The changes in the 2012, 2011 and 2010 estimates are primarily due to increases in abandonment cost estimates based in part on recent actual costs incurred and declines in credit-adjusted risk-free discount rates used to value increases in asset retirement obligations. The increase in the 2012 estimate was also impacted by declines in oil, NGL and gas prices used to calculate proved reserves, which had the effect of shortening the economic life of certain wells and increasing what would otherwise have been the present value of future retirement obligations. The increases in 2011 and 2010 estimates were partially offset by higher oil and NGL prices, which had the effect of lengthening the economic life of certain wells and decreasing what would otherwise have been the present value of future retirement obligations. The increase in commodity prices was less substantial in 2011 as compared to 2010.

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

As of December 31, 2012 and 2011, the current portions of the Company's asset retirement obligations were $13.3 million$14.2 million, respectively.

NOTE J.    Commitments and Contingencies

Severance agreements. The Company has entered into severance and change in control agreements with its officers and certain key employees. The current annual salaries for the officers and key employees covered under such agreements total $43.9 million.

Indemnifications. The Company has agreed to indemnify its directors and certain of its officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.

Legal actions. 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 other 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.

Obligations following divestitures. In April 2006, the Company provided the purchaser of its Argentine assets certain indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject to

104

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

defined limitations, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The Company has also retained certain liabilities and indemnified buyers for certain matters in connection with other divestitures, including the sale of its Canadian assets in 2007, the sale of Pioneer Tunisia in February 2011 and the sale of Pioneer South Africa in August 2012, and in connection with sales of joint interests. The Company does not believe that these obligations are probable of having a material impact on its liquidity, financial position or future results of operations.

Drilling commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future. The Company also enters into agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which the well is drilled or rig services are performed.

Lease agreements. The Company leases equipment and office facilities under operating leases. Rent expense for the years ended December 31, 2012, 2011 and 2010 were $48.0 million, $35.4 million and $38.3 million, respectively. These payments include $67 thousand, $513 thousand and $7.2 million associated with discontinued operations for the years ended December 31, 2012, 2011 and 2010, respectively, which are included in income from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

Future minimum lease commitments under noncancellable operating leases at December 31, 2012 are as follows (in thousands):

2013	$	24,096
2014	$	17,434
2015	$	15,500
2016	$	14,202
2017	$	14,253
Thereafter	$	36,967

Gathering, processing and transportation agreements. The Company from time to time enters into, and as of December 31, 2012 is a party to, contractual commitments with midstream service companies and pipeline carriers for the future gathering, processing, transportation and fractionation. These commitments are normal and customary for the Company's business activities. Future minimum gathering, processing, transportation and fractionation commitments at December 31, 2012 are as follows (in thousands):

2013	$	264,213
2014	$	355,451
2015	$	404,890
2016	$	418,484
2017	$	306,894
Thereafter	$	1,255,520

Certain future minimum gathering, processing, transportation and fractionation fees are based upon rates and tariffs subject to change over the lives of the commitments.

NOTE K.     Related Party Transactions

The Company, through a wholly-owned subsidiary, (i) serves as operator of properties in which it and its affiliated partnerships have an interest and (ii) owns a noncontrolling interest in its unconsolidated affiliate, EFS Midstream, which it manages. Through these relationships, the Company is a party to transactions with the affiliated partnerships and EFS Midstream that represent related party transactions.

Transactions with affiliated partnerships. The Company receives producing well overhead and other fees related to the operation of the properties in which it and its affiliated partnerships have an interest. The affiliated partnerships also reimburse the Company for their allocated share of general and administrative charges. Reimbursements of fees are recorded as reductions to general and administrative expenses in the Company's consolidated statements of operations.

105

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

The related party transactions with affiliated partnerships are summarized below for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Receipt of lease operating and supervision charges in accordance with standard industry operating agreements	$	2,437	$	2,104	$	2,184
Reimbursement of general and administrative expenses	$	342	$	313	$	344

Transactions with EFS Midstream. The Company, through a wholly-owned subsidiary, (i) provides certain services as the manager of EFS Midstream in accordance with a Master Services Agreement and (ii) is the operator of Eagle Ford Shale properties for which EFS Midstream provides certain services under a Hydrocarbon Gathering and Handling Agreement (the "HGH Agreement").

Master Services Agreement. The terms of the Master Services Agreement provide that the Company will perform certain manager services for EFS Midstream and be compensated by monthly fixed payments and variable payments attributable to expenses incurred by employees whose time is substantially dedicated to EFS Midstream's business. During 2012, 2011 and 2010, the Company received $2.3 million, $2.2 million and $1.1 million of fixed payments and $11.8 million, $8.4 million and $1.9 million of variable payments, respectively, from EFS Midstream. The Company also paid $1.9 million to purchase rights of way from EFS Midstream during 2011 and received $1.1 million of proceeds from the sale of an amine plant to EFS Midstream during 2010.

Hydrocarbon Gathering and Handling Agreement. During June 2010, the Company entered into the HGH Agreement with EFS Midstream. In accordance with the terms of the HGH Agreement, EFS Midstream is obligated to construct certain equipment and facilities capable of gathering, treating and transporting oil and gas production from the Eagle Ford Shale properties operated by the Company. The HGH Agreement also obligates the Company and its Eagle Ford Shale working interest partners to use the EFS Midstream gathering, treating and transportation equipment and facilities. In accordance with the terms of the HGH Agreement, the Company paid EFS Midstream $58.5 million, $21.3 million and $404 thousand of gathering and treating fees during 2012, 2011 and 2010, respectively. Such amounts were expensed as oil and gas production costs in the accompanying consolidated statements of operations.

NOTE L.     Major Customers

The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts.

The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas revenues, including the revenues from discontinued operations, in at least one of the three years ended December 31, 2012. The loss of any one significant purchaser could have a material adverse effect on the ability of the Company to sell its oil and gas production. The table provides the percentages of the Company's consolidated oil, NGL and gas revenues represented by the purchasers during the periods presented:

	Year Ended December 31,
	2012		2011		2010
Plains Marketing LP	26	%	16	%	12	%
Enterprise Products Partners L.P.	15	%	12	%	10	%
Occidental Energy Marketing Inc	14	%	14	%	8	%

106

NOTE M.    Interest and Other Income

The following table provides the components of the Company's interest and other income during the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011		2010
	(in thousands)
Alaskan Petroleum Production Tax credits and refunds (a)	$	29,342		$	38,939	$	47,652
Other income	5,382			7,684		4,565
Equity interest in income (loss) of EFS Midstream	2,183			1,925		(819		)
Deferred compensation plan income	1,872			1,657		1,228
Interest income	1,465			697		4,177
Income (loss) from vertical integration services (b)	(11,934		)	15,978		169
Total interest and other income	$	28,310		$	66,880	$	56,972

 ______________________

(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 years ended December 31, 2012, 2011 and 2010, these net margins include $247.8 million, $50.9 million and $946 thousand of gross vertical integration revenues, respectively and $259.7 million, $34.9 million and $777 thousand of total vertical integration costs and expenses, respectively.

NOTE N.    Other Expense

The following table provides the components of the Company's other expense during the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Transportation commitment charge (a)	$	37,144	$	23,248	$	1,589
Above market and idle drilling and well service equipment rates (b)	33,211		20,132		50,581
Other	18,297		12,603		9,924
Terminated drilling rig contract charges (c)	15,747		—		—
Inventory impairment (d)	6,174		3,126		10,729
Premier Silica acquisition costs	2,337		—		—
Contingency and environmental accrual adjustments	478		4,057		5,581
Total other expense	$	113,388	$	63,166	$	78,404

 ____________________

(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 were above market rates and idle drilling rig and fracture stimulation fleet fees, neither of which were chargeable to joint operations.

(c) Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.

(d) Represents lower of cost or market impairment charges on excess materials and supplies inventories.

NOTE O.    Income Taxes

The Company and its eligible subsidiaries file a consolidated United States federal income tax return. Certain subsidiaries are not eligible to be included in the consolidated United States federal income tax return and separate provisions for income taxes

107

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject to examination by United States federal, state, local and foreign taxing authorities. The Company made current and estimated tax payments of $32.3 million, $22.3 million and $36.6 million (net of tax refunds) during 2012, 2011 and 2010, respectively. These payments and net refunds include tax payments related to Pioneer Tunisia's and Pioneer South Africa's operations of $9.8 million, $12.2 million and $17.8 million during 2012, 2011 and 2010, respectively.

The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and assesses the likelihood that the Company's net operating loss carryforwards ("NOLs") and other deferred tax attributes in the United States, state, local and foreign tax jurisdictions will be utilized prior to their expiration.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. As of December 31, 2012, the Company had no unrecognized tax benefits. With respect to income taxes, the Company's policy is to account for interest charges as interest expense and any penalties as other expense in the consolidated statements of operations. The Company files income tax returns in the United States federal jurisdiction, and various state and foreign jurisdictions. As of December 31, 2012, there are no proposed adjustments or uncertain positions in any jurisdiction that would have a significant effect on the Company's future results of operations or financial position. The Company's earliest open years in its key jurisdictions are as follows:

United States	2011
Various U.S. states	2007
Tunisia	2006
South Africa	2006

The Company's income tax provision and amounts separately allocated were attributable to the following items for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Income tax provision from continuing operations	$	(92,384	)	$	(197,644	)	$	(269,627	)
Income tax (provision) benefit from discontinued operations	(15,668		)	(257,950		)	270
Changes in goodwill – tax benefits related to stock-based compensation	—			40			453
Changes in stockholders' equity:
Net deferred hedge (loss) gain	(1,725		)	8,407			23,648
Excess tax benefit (provision) related to stock-based compensation	58,486			31,087			(153		)
Tax attributable to 2008 Pioneer Southwest initial public offering	(49,072		)	—			—
Tax attributable to 2009 and 2011 issuance of Pioneer Southwest common units	—			(23,711		)	—
Tax on Pioneer Southwest common units sold by the Company during 2011	—			(15,381		)	—

108

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

The Company's income provision attributable to income from continuing operations consisted of the following for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Current:
U.S. federal	$	(5,573	)	$	—		$	—
U.S. state	(1,352		)	(9,065		)	(9,864		)
	(6,925		)	(9,065		)	(9,864		)
Deferred:
U.S. federal	(78,790		)	(207,146		)	(263,063		)
U.S. state	(6,669		)	18,567			3,300
	(85,459		)	(188,579		)	(259,763		)
Income tax provision from continuing operations	$	(92,384	)	$	(197,644	)	$	(269,627	)

Reconciliations of the United States federal statutory tax rate to the Company's effective tax rate for income from continuing operations are as follows for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands, except percentages)
Income from continuing operations before income taxes	$	280,057		$	656,406		$	781,572
Less: Net income attributable to noncontrolling interests	(50,537		)	(47,425		)	(40,787		)
Income from continuing operations attributable to parent before income taxes	229,520			608,981			740,785
Federal statutory income tax rate	35		%	35		%	35		%
Provision for federal income taxes	(80,332		)	(213,143		)	(259,275		)
State income taxes (net of federal tax benefit)	(5,214		)	6,176			(4,267		)
Other	(6,838		)	9,323			(6,085		)
Income tax provision from continuing operations	$	(92,384	)	$	(197,644	)	$	(269,627	)
Effective income tax rate, excluding income attributable to the noncontrolling interest	40		%	32		%	36		%

109

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities related to continuing operations are as follows as of December 31, 2012 and 2011:

	December 31,
	2012			2011
	(in thousands)
Deferred tax assets:
Net operating loss carryforward (a)	$	498,441		$	—
Asset retirement obligations	69,214			47,860
Incentive plans	48,575			36,610
Other	104,714			46,218
Total deferred tax assets (b)	720,944			130,688
Deferred tax liabilities:
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes	(2,241,081		)	(1,692,317		)
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes	(255,943		)	(102,351		)
State taxes and other	(285,313		)	(191,621		)
Net deferred hedge gains	(165,504		)	(144,558		)
Total deferred tax liabilities	(2,947,841		)	(2,130,847		)
Net deferred tax liability	$	(2,226,897	)	$	(2,000,159	)
Reflected in accompanying consolidated balance sheets as:
Current deferred income tax liability	$	(86,481	)	$	(57,713	)
Noncurrent deferred income tax liability	(2,140,416		)	(1,942,446		)
Total	$	(2,226,897	)	$	(2,000,159	)

____________________

(a)    All net operating loss carryforwards as of December 31, 2012 expire in 2032.

(b)     The Company had no deferred tax valuation allowances at December 31, 2012 and 2011.

NOTE P.    Net Income Per Share Attributable To Common Stockholders

In the calculation of basic net income per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company's participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. The computation of diluted net income per share attributable to common stockholders reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. 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 not be dilutive to net loss per share and conversion into common stock is assumed not to occur. Diluted net income per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. For each of the three years in the period ended December 31, 2012, the two-class method of calculating the Company's diluted net income per share was more dilutive than the treasury stock method.

The Company's basic net income per share attributable to common stockholders is computed as (i) net income attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income per share attributable to common stockholders is computed as (i) basic net income attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding (excluding shares held in treasury).

110

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

The following table is a reconciliation of the Company's net income attributable to common stockholders to basic net income attributable to common stockholders and to diluted net income attributable to common stockholders for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31, 2012
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	137,136		$	55,149		$	192,285
Participating basic earnings (a)	(2,160		)	(869		)	(3,029		)
Basic income attributable to common stockholders	134,976			54,280			189,256
Reallocation of participating earnings (a)	115			46			161
Diluted income attributable to common stockholders	$	135,091		$	54,326		$	189,417

	Year Ended December 31, 2011
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	411,337		$	423,152		$	834,489
Participating basic earnings (a)	(7,482		)	(7,696		)	(15,178		)
Basic income attributable to common stockholders	403,855			415,456			819,311
Reallocation of participating earnings (a)	190			195			385
Diluted income attributable to common stockholders	$	404,045		$	415,651		$	819,696

	Year Ended December 31, 2010
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	471,158		$	134,050		$	605,208
Participating basic earnings (a)	(10,818		)	(3,078		)	(13,896		)
Basic net income attributable to common stockholders	460,340			130,972			591,312
Reallocation of participating earnings (a)	140			40			180
Diluted income attributable to common stockholders	$	460,480		$	131,012		$	591,492

 ______________________

(a) Unvested restricted stock awards and Pioneer Southwest phantom unit awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity owners of the Company or Pioneer Southwest, as applicable. Participating share- and unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually obligated to do so.

111

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012	2011	2010
	(in thousands)
Weighted average common shares outstanding:
Basic	122,966	116,904	115,062
Dilutive common stock options (a)	183	190	212
Contingently issuable—performance shares	180	424	646
Convertible Senior Notes dilution (b)	2,991	1,697	410
Diluted	126,320	119,215	116,330

______________________

(a) Options to purchase 129,918 shares of the Company's common stock were excluded from the diluted income per share calculations for the year ended December 31, 2012 because they would have been anti-dilutive to the calculation.

(b) Weighted average common shares outstanding have been increased to reflect the dilutive effect that would have resulted if the Convertible Senior Notes had qualified for and been converted during the years ended December 31, 2012, 2011 and 2010, respectively.

NOTE Q.     Subsequent Events

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 for consideration of $1.7 billion. At closing, Sinochem will pay $522.0 million in cash to Pioneer, 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 and third party approvals.

As discussed in Note G, in January and February 2013, holders of $240.6 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. In general, upon conversion of a Convertible Senior Note, the holder will receive cash equal to the principal amount of the Convertible Senior Note and shares of the Company's common stock for the Convertible Senior Note's conversion value in excess of the principal amount. In addition, pursuant to the terms of the Convertible Senior Notes, the annual interest rate for the Convertible Senior Notes has been reduced from 2.875 percent to 2.375 percent per annum for the six-month period from January 15, 2013 to July 14, 2013 because the Notes met certain trading price conditions.

112

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2012, 2011 and 2010

Oil & Gas Exploration and Production Activities

The Company has operations in one business and geographic segment, that being oil and gas exploration and production. See the Company's accompanying statements of operations for information about results of operations for oil and gas producing activities.

Capitalized Costs

	December 31,
	2012			2011 (a)
	(in thousands)
Oil and gas properties:
Proved	$	14,259,708		$	12,373,848
Unproved	231,555			235,527
Capitalized costs for oil and gas properties	14,491,263			12,609,375
Less accumulated depletion, depreciation and amortization	(4,412,913		)	(3,955,483		)
Net capitalized costs for oil and gas properties	$	10,078,350		$	8,653,892

 _____________________

(a) Includes $360.0 million of proved property and $307.0 million of accumulated depletion, depreciation and amortization related to Pioneer South Africa, which was classified as held for sale at December 31, 2011.

Costs Incurred for Oil and Gas Producing Activities(a)

		Year Ended December 31,
		2012		2011		2010
	(in thousands)
Property acquisition costs:
Proved		$	16,962	$	7,571	$	6,566
Unproved		140,515		124,326		175,007
Exploration costs		966,828		567,196		277,656
Development costs		1,881,459		1,474,393		727,326
Total costs incurred		$	3,005,764	$	2,173,486	$	1,186,555

 ___________________

(a) The costs incurred for oil and gas producing activities includes the following amounts of asset retirement obligations:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Proved property acquisition costs	$	24	$	6	$	6
Exploration costs	2,200		1,222		6,820
Development costs	56,648		18,274		14,369
Total	$	58,872	$	19,502	$	21,195

Reserve Quantity Information

The estimates of the Company's proved reserves as of December 31, 2012, 2011, and 2010 were based on evaluations prepared by the Company's engineers and audited by independent petroleum engineers with respect to the Company's major properties and prepared by the Company's engineers with respect to all other properties. Proved reserves were estimated in accordance with guidelines established by the United States Securities and Exchange Commission (the "SEC") and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions based upon an average of the first-day-of-the-month commodity price during the 12-month period ending on the balance sheet date with no provision for price and cost escalations except by contractual arrangements.

113

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2012, 2011 and 2010

Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

114

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2012, 2011 and 2010

The following table provides a rollforward of total proved reserves for the years ended December 31, 2012, 2011, and 2010. Oil and NGL volumes are expressed in thousands of BBLS ("MBBLs"), gas volumes are expressed in millions of cubic feet ("MMCF") and total volumes are expressed in thousands of barrels of oil equivalent ("MBOE").

	Year Ended December 31,
	2012								2011								2010
	Oil (MBBLs)		NGLs (MBBLs)		Gas (MMCF) (a)		Total (MBOE)		Oil (MBBLs)		NGLs (MBBLs)		Gas (MMCF) (a)		Total (MBOE)		Oil (MBBLs)		NGLs (MBBLs)		Gas (MMCF) (a)		Total (MBOE)
Balance, January 1	430,005		211,035		2,531,038		1,062,881		380,809		184,218		2,674,522		1,010,781		325,336		156,834		2,498,801		898,636
Production (b)	(22,990	)	(10,913	)	(161,197	)	(60,769	)	(15,219	)	(8,208	)	(150,932	)	(48,582	)	(12,303	)	(7,203	)	(151,560	)	(44,766	)
Revisions of previous estimates	(11,158	)	(17,417	)	(485,216	)	(109,444	)	8,938		(5,750	)	(247,196	)	(38,013	)	15,106		19,291		190,161		66,091
Extensions and discoveries	78,375		48,422		320,243		180,170		70,892		39,912		273,043		156,313		42,135		15,669		155,448		83,712
Sales of minerals-in-place	(275	)	(588	)	(16,845	)	(3,671	)	(19,619	)	—		(22,968	)	(23,447	)	(1,125	)	(928	)	(21,692	)	(5,668	)
Purchases of minerals-in-place	5,383		2,037		9,457		8,996		2,810		863		4,569		4,435		1,944		555		3,364		3,060
Improved recovery	7,498		—		—		7,498		1,394		—		—		1,394		9,716		—		—		9,716
Balance, December 31 (c)	486,838		232,576		2,197,480		1,085,661		430,005		211,035		2,531,038		1,062,881		380,809		184,218		2,674,522		1,010,781

 ______________________

(a) The proved gas reserves as of December 31, 2012, 2011 and 2010 include 280,344 MMCF, 301,123 MMCF and 303,748 MMCF, respectively, of gas that will be produced and utilized as field fuel. Field fuel is gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point.

(b) Production for 2012, 2011 and 2010 includes 18,930 MMCF, 17,727 MMCF and 17,289 MMCF of field fuel, respectively. Also, for 2012, 2011 and 2010, production includes 787 MBOE, 1,675 MBOE and 3,989 MBOE of production associated with discontinued operations. See Note C for corresponding information regarding the Company's discontinued operations.

(c) As of December 31, 2012, 2011 and 2010, the portions of the Company's proved reserves attributable to discontinued operations in South Africa and Tunisia were nil, 2,342 MBOE and 26,564 MBOE, respectively, and proved reserves attributable to noncontrolling interests in Pioneer Southwest were as follows:

	Year Ended December 31,
	2012				2011				2010
	Oil (MBBLs)	NGLs (MBBLs)	Gas (MMCF)	Total (MBOE)	Oil (MBBLs)	NGLs (MBBLs)	Gas (MMCF)	Total (MBOE)	Oil (MBBLs)	NGLs (MBBLs)	Gas (MMCF)	Total (MBOE)
Noncontrolling interest in proved reserves	14,652	5,440	20,376	23,488	14,747	5,699	22,012	24,114	11,852	4,753	18,843	19,745

115

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2012, 2011 and 2010

Revisions of previous estimates. At December 31, 2012, revisions of previous estimates are comprised of 82 MMBOE of negative price revisions and 27 MMBOE of negative revisions due to updated performance profiles and cost estimates. The December 31, 2012 NYMEX price used for oil and gas reserve preparation based upon SEC guidelines was $94.84 per barrel of oil and $2.76 per Mcf of gas, compared to $96.13 per barrel of oil and $4.12 per Mcf of gas at December 31, 2011.

At December 31, 2011, revisions of previous estimates were comprised of 28 MMBOE of negative price revisions and 10 MMBOE of negative revisions due to updated performance profiles and cost estimates. The December 31, 2011 NYMEX price used for oil and gas reserve preparation based upon SEC guidelines increased $16.85 per barrel of oil and decreased $0.25 per Mcf of gas from $79.28 per barrel of oil and $4.37 per Mcf of gas at December 31, 2010.

At December 31, 2010, revisions of previous estimates of 66 MBOE were comprised of 59 MMBOE of positive price revisions and 7 MMBOE of positive technical revisions. The December 31, 2010 NYMEX price for oil and gas reserves preparation based upon SEC guidelines increased $18.14 per barrel of oil and $0.50 per Mcf of gas from $61.14 per barrel of oil and $3.87 per Mcf of gas at December 31, 2009.

Extensions and discoveries. Extensions and discoveries at December 31, 2012 and 2011 are primarily comprised of discoveries and extensions in the Spraberry field and discoveries in the Eagle Ford Shale and Barnett Shale Combo plays. At December 31, 2010 extensions and discoveries were primarily due to extensions in the Spraberry field and discoveries in the Eagle Ford Shale and Tunisia.

Sales of minerals-in-place. Sales of minerals-in-place in 2012, 2011 and 2010 are primarily related to the divestment of Pioneer South Africa, Pioneer Tunisia and certain proved properties in the Eagle Ford Shale, respectively. See Note C for corresponding information regarding the Company's discontinued operations.

Purchases of minerals-in-place. Purchases of minerals-in-place during all years are primarily attributable to acquisitions in the Company's Spraberry field.

Improved recovery. Additions from improved recovery during 2012, 2011 and 2010 relate to recognizing secondary recovery reserves attributable to waterflooding the Nuiqsut horizon of the Alaskan Oooguruk development project.

The following table provides the Company's proved developed and proved undeveloped reserves for January 1, 2010 and for the years ended December 31, 2012, 2011 and 2010.

	Oil (MBBLs)	NGLs (MBBLs)	Gas (MMCF)	Total (MBOE)
Proved Developed Reserves:
January 1, 2010	144,263	93,015	1,719,722	523,899
December 31, 2010	172,816	108,785	1,775,611	577,537
December 31, 2011	190,206	120,405	1,853,363	619,506
December 31, 2012	230,700	134,637	1,605,209	632,872
	Oil (MBBLs)	NGLs (MBBLs)	Gas (MMCF)	Total (MBOE)
Proved Undeveloped Reserves:
January 1, 2010	181,073	63,819	779,079	374,737
December 31, 2010	207,993	75,433	898,911	433,244
December 31, 2011	239,799	90,630	677,675	443,375
December 31, 2012	256,138	97,939	592,271	452,789

116

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2012, 2011 and 2010

The following table summarizes the Company's proved undeveloped reserves activity during the year ended December 31, 2012 (in MBOE).

Beginning proved undeveloped reserves	443,375
Revisions of previous estimates	(64,919	)
Extensions and discoveries	116,742
Sales of minerals-in-place	(1,544	)
Purchases of minerals-in-place	8,844
Improved recovery	5,155
Transfers to proved developed	(54,864	)
Ending proved undeveloped reserves	452,789

As of December 31, 2012, the Company had 3,810 proved undeveloped well locations as compared to 4,599 and 4,727 at December 31, 2011 and 2010, respectively. The Company has 505 proved undeveloped well locations (representing 53 MMBOE of proved reserves) that are scheduled to be drilled more than five years from their original date of booking. All of these wells are scheduled to be drilled within five years of the December 31, 2009 effective date of the Commission's Final Rule on the Modernization of Oil and Gas Reporting.

The changes in proved undeveloped reserves during 2012 are comprised of the following items:

Revisions of previous estimates. Revisions of previous estimates are comprised of 27 MMBOE of negative price revisions associated with proved dry gas reserves that are no longer planned to be drilled in the next five years and 38 MMBOE of negative technical revisions, primarily in the Spraberry field.

Extensions and discoveries. Extensions and discoveries are primarily comprised of extensions and discoveries in the Wolfcamp, Strawn, Atoka and Mississippian horizons in the Spraberry field and discoveries in the Eagle Ford Shale and Barnett Shale Combo plays.

Sales of minerals-in-place. Sales of minerals-in-place are primarily related to sales in the Barnett Shale Combo play.

Purchases of minerals-in-place. Purchases of minerals-in-place are primarily attributable to acquisitions in the Company's Spraberry field.

Improved recovery. Additions from improved recovery relate to recognizing secondary recovery reserves attributable to waterflooding the Nuiqsut horizon of the Alaskan Oooguruk development project.

Transfers to proved developed. Transfers to proved developed reserves represents those undeveloped proved reserves that moved to proved developed as a result of development drilling during 2012. During 2012, the Company incurred $1.4 billion of development costs and developed 12 percent of its proved undeveloped reserves. See the table below for the Company's firm plans for future development expenditures.

As of December 31, 2012, the Company had 31 MMBOE of proved undeveloped reserves for locations that are more than one location removed from developed locations in the Spraberry field, 16 MMBOE of which were recorded during 2012. Within the Spraberry field, the Company uses both public and proprietary geologic data to establish continuity of the formation and its producing properties. This included seismic data and interpretations (2-D, 3-D and micro seismic); open hole log information (both vertical and horizontally collected) and petrophysical analysis of the log data; mud logs; gas sample analysis; drill cutting samples; measurements of total organic content; thermal maturity; sidewall cores and data measured from the Company's internal core analysis facility. After the geologic area was shown to be continuous, statistical analysis of existing producing wells was conducted to generate areas of reasonable certainty at distances from established production. As a result of this analysis, proved undeveloped reserves for drilling locations within these areas of reasonable certainty were recorded during 2012.

117

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2012, 2011 and 2010

While the Company expects, based on Management's Price Outlooks, that future operating cash flows will provide adequate funding for future development of its proved undeveloped reserves over the next five years, it may also use any combination of internally-generated cash flows, cash and cash equivalents on hand, availability under its credit facility, proceeds from the sale of joint interests and nonstrategic assets or external financing sources to fund these and other capital expenditures, including exploratory drilling and acquisitions. The following table represents the estimated timing and cash flows of developing the Company's proved undeveloped reserves as of December 31, 2012 (dollars in thousands):

Year Ended December 31, (a)	Estimated Future Production (MBOE)	Future Cash Inflows		Future Production Costs		Future Development Costs		Future Net Cash Flows
2013	6,296	$	423,745	$	52,029	$	1,445,947	$	(1,074,231	)
2014	16,922	1,043,836		139,260		1,491,933		(587,357		)
2015	24,660	1,458,550		228,735		1,783,818		(554,003		)
2016	32,171	1,963,717		317,856		2,117,725		(471,864		)
2017	35,831	2,199,003		383,555		1,595,912		219,536
Thereafter (b)	336,909	20,538,278		7,150,373		259,965		13,127,940
	452,789	$	27,627,129	$	8,271,808	$	8,695,300	$	10,660,021

______________________ 

(a) Production and cash flows represent the drilling results from the respective year plus the incremental effects of proved undeveloped drilling.

(b) The $260.0 million of future development costs includes (i) $35.9 million and $3.9 million of completion costs forecasted in 2018 and 2019, respectively, and (ii) $220.2 million of net abandonment costs in future years.

118

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2012, 2011 and 2010

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is computed by applying commodity prices used in determining proved reserves (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved reserves less estimated future expenditures (based on year-end estimated costs) to be incurred in developing and producing the proved reserves, discounted using a rate of ten percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and gas properties plus available carryforwards and credits and applying the current tax rates to the difference. The discounted future cash flow estimates do not include the effects of the Company's commodity derivative contracts. Utilizing the first-day-of-the-month commodity prices during the 12-month period ending on December 31, 2012, held constant over each derivative contract's term, the net present value of the Company's derivative contracts discounted at ten percent was an asset of $388.7 million at December 31, 2012.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following tables provide the standardized measure of discounted future cash flows as of December 31, 2012, 2011 and 2010, as well as a rollforward in total for each respective year:

	December 31,
	2012			2011			2010
	(in thousands)
Oil and gas producing activities:
Future cash inflows	$	56,692,889		$	59,220,357		$	45,995,152
Future production costs	(23,977,062		)	(21,154,016		)	(17,540,241		)
Future development costs (a)	(9,803,698		)	(8,466,407		)	(6,769,787		)
Future income tax expense	(6,600,395		)	(9,581,515		)	(7,235,123		)
	16,311,734			20,018,419			14,450,001
10% annual discount factor	(9,958,336		)	(12,205,396		)	(9,037,992		)
Standardized measure of discounted future cash flows (b)	$	6,353,398		$	7,813,023		$	5,412,009

 __________________

(a) Includes $840.0 million, $785.0 million and $823.5 million of undiscounted future asset retirement expenditures estimated as of December 31, 2012, 2011 and 2010, respectively, using current estimates of future abandonment costs. See Note I for corresponding information regarding the Company's discounted asset retirement obligations.

(b) Includes $40.7 million and $565.4 million as of December 31, 2011 and 2010, respectively, attributable to discontinued operations in South Africa and Tunisia. Also includes $282.6 million and $378.6 million attributable to a 48 percent noncontrolling interest in Pioneer Southwest for 2012 and 2011, respectively, and $214.2 million attributable to a 38 percent noncontrolling interest in Pioneer Southwest for 2010.

119

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2012, 2011 and 2010

Changes in Standardized Measure of Discounted Future Net Cash Flows

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Oil and gas sales, net of production costs	$	(2,038,353	)	$	(1,755,153	)	$	(1,373,943	)
Revisions of previous estimates:
Net changes in prices and production costs	(3,069,880		)	2,615,481			2,098,422
Changes in future development costs	(1,649,417		)	(1,280,213		)	(952,508		)
Revisions in quantities	(1,126,865		)	(442,120		)	626,693
Accretion of discount	1,109,022			800,468			437,523
Changes in production rates, timing and other (a)	743,212			1,660,419			1,415,999
Extensions, discoveries and improved recovery	1,731,465			1,676,866			1,017,597
Development costs incurred during the period	1,399,731			750,268			380,754
Sales of minerals-in-place	(38,106		)	(1,021,513		)	(42,043		)
Purchases of minerals-in-place	172,474			81,036			20,957
Change in present value of future net revenues	(2,766,717		)	3,085,539			3,629,451
Net change in present value of future income taxes	1,307,092			(684,525		)	(1,547,996		)
	(1,459,625		)	2,401,014			2,081,455
Balance, beginning of year	7,813,023			5,412,009			3,330,554
Balance, end of year	$	6,353,398		$	7,813,023		$	5,412,009

__________________

(a) The Company's changes in Standardized Measure attributable to production rates, timing and other primarily represent changes in the Company's estimates of when proved reserve quantities will be realized. During the twelve months ended December 31, 2012, 2011 and 2010, the Company increased its development drilling capital plans, which had the effect of accelerating the estimated timing of development and realization of undeveloped proved reserves.

120

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2012, 2011 and 2010

Selected Quarterly Financial Results

The following table provides selected quarterly financial results for the years ended December 31, 2012 and 2011:

	Quarter
	First		Second			Third		Fourth
	(in thousands, except per share data)
Year Ended December 31, 2012:
Oil and gas revenues:
As reported	$	718,956	$	641,737		$	695,422	$	734,640
Plus discontinued operations (a)	—		—			20,905		—
Adjusted	$	718,956	$	641,737		$	716,327	$	734,640
Total revenues:
As reported (b)	$	876,210	$	917,975		$	594,922	$	818,686
Plus discontinued operations (a)	—		—			20,515		—
Adjusted	$	876,210	$	917,975		$	615,437	$	818,686
Total costs and expenses:
As reported	$	548,244	$	1,014,615		$	599,487	$	769,973
Plus discontinued operations (a)	—		—			15,932		—
Adjusted (c)	$	548,244	$	1,014,615		$	615,419	$	769,973
Net income (loss)	$	220,958	$	(39,537	)	$	21,699	$	39,702
Net income (loss) attributable to common stockholders	$	214,619	$	(70,392	)	$	19,224	$	28,834
Net income (loss) attributable to common stockholders per share:
Basic	$	1.73	$	(0.57	)	$	0.15	$	0.23
Diluted	$	1.68	$	(0.57	)	$	0.15	$	0.22
Year Ended December 31, 2011:
Oil and gas revenues	$	475,728	$	562,412		$	591,147	$	664,776
Total revenues (b)	257,264		804,500			1,000,538		689,203
Total costs and expenses (d)	381,249		395,593			438,338		879,919
Net income (loss)	343,804		265,700			385,598		(113,188		)
Net income (loss) attributable to common stockholders	348,594		245,577			351,464		(111,146		)
Net income (loss) attributable to common stockholders per share:
Basic	2.96		2.07			2.96		(0.93		)
Diluted	2.96		2.03			2.95		(0.93		)

 _____________________

(a) During the third quarter of 2012, the Company committed to a plan to sell the Company's Barnett Shale assets and classified the results of operations as discontinued operations. As discussed in Note B, during the fourth quarter of 2012, the Company reclassified the Barnett Shale field to continuing operations. Accordingly, the Barnett Shale results of operations are classified as continuing operations in all quarters presented.

(b) The Company's total revenues include derivative gains and (losses), net, of $91.8 million, $275.8 million, $(124.0) million and $86.7 million during the first through fourth quarters of 2012, respectively, and $(244.4) million, $229.5 million, $401.1 million and $6.6 million during the first through fourth quarters of 2011, respectively.

(c) During the second quarter and fourth quarters of 2012, the Company's total costs and expenses include noncash pretax charges of $444.9 million and $159.5 million, respectively, to impair the carrying value of proved and unproved oil and gas properties in the Barnett Shale field.

(d) During the fourth quarter of 2011, the Company's total costs and expenses include pretax charges of $354.4 million to impair the carrying value of proved oil and gas properties in the Edwards and Austin Chalk fields of South Texas and a $30.4 million charge for the abandonment of unproved dry gas properties.

121

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. 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 December 31, 2012 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control over financial reporting is a process designed by or under the supervision of the Company's principal executive officer and principal financial officer and effected by the Board, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles.

The Company's management, with the participation of its principal executive officer and principal financial officer assessed the effectiveness, as of December 31, 2012, of the Company's internal control over financial reporting based on the criteria for effective internal control over financial reporting established in "Internal Control — Integrated Framework," issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting at a reasonable assurance level as of December 31, 2012, based on those criteria.

Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2012. The report, which expresses an unqualified opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2012, is included in this Item under the heading "Report of Independent Registered Public Accounting Firm."

122

REPORT OF INDEPENDENT REGISTERED PUBLIC

ACCOUNTING FIRM

The Board of Directors and Stockholders of

Pioneer Natural Resources Company

We have audited Pioneer Natural Resources Company's (the "Company") internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Pioneer Natural Resources Company's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed 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. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Pioneer Natural Resources Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pioneer Natural Resources Company as of December 31, 2012 and 2011 and the related consolidated statements of operations, comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2012, and our report dated February 13, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas

February 13, 2013

123

PIONEER NATURAL RESOURCES COMPANY

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2013 and is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2013 and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Securities Authorized for Issuance under Equity Compensation Plans

The following table summarizes information about the Company's equity compensation plans as of December 31, 2012:

	Number of securities  to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in first column) (b)
Equity compensation plans approved by security holders:
Pioneer Natural Resources Company:
2006 Long-Term Incentive Plan (c)	171,644	$	16.72	2,965,882
Long-Term Incentive Plan	—	—		—
Employee Stock Purchase Plan	—	—		571,118
Equity compensation plans not approved by security holders	—	—		—
Total:	171,644	$	16.72	3,537,000

 _______________________

(a) There are no outstanding warrants or equity rights awarded under the Company's equity compensation plans. The securities listed do not include restricted stock awarded under the Company's previous Long-Term Incentive Plan and the Company's 2006 Long-Term Incentive Plan.

(b) In May 2006, the stockholders of the Company approved the 2006 Long-Term Incentive Plan, which provided for the issuance of up to 9.1 million awards, as was supplementally approved by the stockholders of the Company during May 2009. Awards under the 2006 Long-Term Incentive Plan can be in the form of stock options, stock appreciation rights, performance units, restricted stock and restricted stock units. No additional awards may be made under the prior Long-Term Incentive Plan. The number of remaining securities available for future issuance under the Company's Employee Stock Purchase Plan is based on the original authorized issuance of 750,000 shares plus an additional 500,000 shares supplementally approved less 678,882 cumulative shares issued through December 31, 2012. See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a description of each of the Company's equity compensation plans.

(c) The number of securities remaining for future issuance has been reduced by the maximum number of shares that could be issued pursuant to outstanding grants of performance units at December 31, 2012.

The remaining information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2013 and is incorporated herein by reference.

124

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2013 and is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2013 and is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Listing of Financial Statements

Financial Statements

The following consolidated financial statements of the Company are included in "Item 8. Financial Statements and Supplementary Data":

• Report of Independent Registered Pubic Accounting Firm

• Consolidated Balance Sheets as of December 31, 2012 and 2011

• Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010

• Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010

• Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2012, 2011 and 2010

• Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010

• Notes to Consolidated Financial Statements

• Unaudited Supplementary Information

(b) Exhibits

The exhibits to this Report that are required to be filed pursuant to Item 15(b) are listed below and in the "Exhibit Index" attached hereto.

(c) Financial Statement Schedules

No financial statement schedules are required to be filed as part of this Report or they are inapplicable.

125

Exhibits

Exhibit Number		Description
2.1  *	—	Agreement for the Sale and Purchase of the Entire Issued Share Capital of Pioneer Natural Resources Anaguid Ltd. and Pioneer Natural Resources Tunisia Ltd. between Pioneer Natural Resources USA, Inc. and OMV (Tunesien) Production GmbH dated January 6, 2011 (incorporated by reference to Exhibit 2.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).
3.1	—	Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).
3.2	—	Certificate of Amendment of the Amended and Restated Certificate of Incorporation effective May 18, 2012 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).
3.3	—	Third Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).
4.1	—	Form of Certificate of Common Stock, par value $.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).
4.2	—	Indenture dated January 13, 1998, between the Company and The Bank of New York, as trustee (incorporated by reference to Exhibit 99.1 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).
4.3	—	First Supplemental Indenture dated as of January 13, 1998, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).
4.4	—	Second Supplemental Indenture dated as of April 11, 2000, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-13245).
4.5	—	Third Supplemental Indenture dated as of April 30, 2002, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 1-13245).
4.6	—	Fourth Supplemental Indenture dated as of July 15, 2004, among the Company and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).
4.7	—	Fifth Supplemental Indenture dated as of July 15, 2004, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).
4.8	—	Sixth Supplemental Indenture, dated as of May 1, 2006, among the Company, Pioneer USA and The Bank of New York Trust Company, N.A., as Trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 4, 2006).
4.9	—	Seventh Supplemental Indenture, dated as of March 12, 2007, among the Company, Pioneer USA, The Bank of New York Trust Company, N.A, as original trustee under the indenture, and Wells Fargo Bank, National Association, as series trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 12, 2007).
4.10	—	Indenture dated January 22, 2008 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).
4.11	—	First Supplemental Indenture dated January 22, 2008 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.10 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).

126

4.12	—	Second Supplemental Indenture dated November 9, 2009 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.19 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 13, 2009).
4.13	—	Indenture dated June 26, 2012 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
4.14	—	First Supplemental Indenture, dated June 26, 2012, by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
10.1 H	—	The Company's Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-35087, filed with the SEC on September 8, 1997).
10.2 H	—	First Amendment to the Company's Long-Term Incentive Plan, effective as of November 23, 1998 (incorporated by reference to Exhibit 10.72 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.3 H	—	Amendment No. 2 to the Company's Long-Term Incentive Plan, effective as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.4 H	—	Amendment No. 3 to the Company's Long-Term Incentive Plan, effective as of February 17, 2000 (incorporated by reference to Exhibit 10.76 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.5 H	—	Amendment No. 4 to the Company's Long-Term Incentive Plan, effective as of November 20, 2003 (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.6 H	—	Amendment No. 5 to the Company's Long-Term Incentive Plan, effective as of May 12, 2004 (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.7 H	—	Amendment No. 6 to the Company's Long-Term Incentive Plan, effective as of December 17, 2004 (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.8 H	—	Amendment No. 7 to the Company's Long Term Incentive Plan effective November 20, 2008 (incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.9 H	—	Form of Omnibus Nonstatutory Stock Option Agreement for Option Award Participants with respect to grants under the Company's Long-Term Incentive Plan (Group 1) (incorporated by reference to Exhibit 10.20 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.10 H	—	Pioneer Natural Resources Company Employee Stock Purchase Plan, as amended and restated effective September 1, 2007 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, File No. 1-13245).
10.11 H		First Amendment to Amended and Restated Pioneer Natural Resources Company Employee Stock Purchase Plan dated effective September 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. File No. 1-13245, filed with the SEC on May 18, 2012).
10.12 H	—	The Company's Executive Deferred Compensation Plan, Amended and Restated Effective as of August 1, 2002 (incorporated by reference to Exhibit 10.15 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.13 H	—	Amendment No. 1 to the Company's Executive Deferred Compensation Plan, effective as of January 1, 2007 (incorporated by reference to Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-13245).
10.14 H	—	Pioneer USA 401(k) and Matching Plan, Amended and Restated Effective as of January 1, 2008 (incorporated by reference to Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-13245).
10.15 H	—	First Amendment to the Pioneer USA 401(k) and Matching Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245).
10.16 H	—	Amendment No. 2 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-13245).

127

10.17 H	—	Amendment No. 3 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed October 28, 2009 effective as of the dates specified therein (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-13245).
10.18 H	—	Amendment No. 4 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, effective January 1, 2010 (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 2009, File No. 1-13245).
10.19 H	—	Amendment No. 5 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed December 12, 2011 (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011, File No. 1-13245).
10.20 H	—	Amendment No. 6 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed January 12, 2012 (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011, File No. 1-13245).
10.21 H  (a)	—	Amendment No. 7 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed April 2, 2012.
10.22	—	Second Amended and Restated 5-Year Revolving Credit Agreement dated as of March 31, 2011, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (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 April 5, 2011).
10.23	—	First Amendment to Second Amended and Restated 5-Year Revolving Credit Agreement dated as of December 20, 2012, among the Company, as the Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (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 December 20, 2012).
10.24 H	—	Indemnification Agreement between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its non-employee directors and executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (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 August 27, 2009).
10.25 H	—	Severance Agreement dated August 16, 2005, 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 Severance Agreement (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13245).
10.26 H	—	Change in Control Agreement, dated August 16, 2005, 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 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 17, 2005).
10.27 H	—	Change in Control Agreement, dated August 10, 2005, between the Company and William F. Hannes (incorporated by reference to Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 2005, File No. 1-13245).
10.28 H	—	Form of Change in Control Agreement dated September 10, 2005, between the Company and Jay P. Still (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 2008).
10.29 H	—	Pioneer Natural Resources Company 2006 Long-Term Incentive Plan (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 May 9, 2006).
10.30 H	—	First Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective November 20, 2008 (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.31 H	—	Second Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective May 28, 2009 (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 May 28, 2009).
10.32 H	—	Third Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (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 June 18, 2009).
10.33 H	—	Fourth Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).
10.34 H  (a)	—	Fifth Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective August 20, 2012.

128

10.35 H	—	Form of restricted stock unit Award Agreement for non-employee directors with respect to grants under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying substantially identical agreements between the Company and each of its non-employee directors identified on the schedule and identifying the material differences between each of those agreements and the filed Award Agreement (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 9, 2006).
10.36 H	—	Form of Restricted Stock Unit Agreement for Non-Employee Directors to be used in connection with annual equity awards under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 1-13245).
10.37 H	—	Form of Restricted Stock Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Restricted Stock Award Agreement (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 2, 2007).
10.38	—	First Amended and Restated Agreement of Limited Partnership of Pioneer Southwest Energy Partners L.P. dated May 6, 2008, between Pioneer Natural Resources GP LLC, as the General Partner, and Pioneer Natural Resources USA, Inc., as the Organizational Limited Partner, together with any other persons who become Partners (as defined in such agreement) in the Partnership (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of Pioneer Southwest Energy Partners L.P., File No. 001-34032, filed with the SEC on May 9, 2008).
10.39	—	Administrative Services Agreement, dated effective May 6, 2008, among Pioneer Natural Resources GP LLC, Pioneer Southwest Energy Partners L.P., Pioneer Southwest Energy Partners USA LLC, and Pioneer Natural Resources USA, Inc. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, of Pioneer Southwest Energy Partners L.P., File No. 001-34032, filed with the SEC on May 9, 2008).
10.40	—	Amended and Restated Credit Agreement entered into as of March 29, 2012, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Pioneer Southwest Energy Partners L.P., File No. 001-34032, filed with the SEC on April 3, 2012).
10.41 H	—	Severance Agreement, dated May 19, 2008, between the Company and Frank W. Hall (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-13245).
10.42 H	—	Change in Control Agreement, dated May 19, 2008, between the Company and Frank W. Hall (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-13245).
10.43 H	—	Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (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 November 25, 2008).
10.44 H	—	Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.45 H	—	Form of Amendment to Change in Control Agreement, dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.46 H	—	Form of Amendment to Change in Control Agreement, dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.47 H	—	Amended and Restated Executive Deferred Compensation Plan, effective as of January 1, 2009 (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.48 H	—	Amendment No. 1 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245).
10.49 H	—	Amendment No. 2 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2011 (incorporated by reference to Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).
10.50 H	—	Pioneer Southwest Energy Partners L.P. 2008 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-1 of Pioneer Southwest Energy Partners L.P., Registration No. 333-144868).

129

10.51 H	—	Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13245).
10.52 H	—	Form of Nonstatutory Stock Option Agreement between the Company and Scott D. Sheffield, with respect to awards made under the Company's 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13245).
10.53 H	—	Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to awards made under the Company's 2006 Long Term Incentive Plan. (incorporated by reference to Exhibit 10.64 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).
10.54 H	—	Form of Restricted Stock Award Agreement between the Company and Timothy L. Dove, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.55 H	—	Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.56 H	—	Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to annual awards made under the Company's 2006 Long Term Incentive Plan together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.57 H	—	Form of Nonstatutory Stock Option Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.58 H	—	Form of Restricted Stock Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.59 H	—	Form of Restricted Stock Unit Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
12.1  (a)	—	Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.
21.1  (a)	—	Subsidiaries of the registrant.
23.1  (a)	—	Consent of Ernst & Young LLP.
23.2  (a)	—	Consent of Netherland, Sewell & Associates, Inc.
23.3  (a)	—	Consent of Ryder Scott Company, L.P.
31.1  (a)	—	Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2  (a)	—	Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1  (b)	—	Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2  (b)	—	Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.

130

95.1 (a)	—	Mine Safety Disclosure pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.
99.1  (a)	—	Report of Netherland, Sewell & Associates, Inc.
99.2  (a)	—	Report of Ryder Scott Company, L.P.
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.
H	Executive Compensation Plan or Arrangement.
*	Pursuant to the rules of the Commission, certain of the schedules and similar attachments to the Agreement have not been filed. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.

131

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		PIONEER NATURAL RESOURCES COMPANY
Date:	February 13, 2013
		By:	/s/ Scott D. Sheffield
			Scott D. Sheffield, Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Scott D. Sheffield	Chairman of the Board and Chief Executive Officer (principal executive officer)	February 13, 2013
Scott D. Sheffield
/s/ Richard P. Dealy	Executive Vice President and Chief Financial Officer (principal financial officer)	February 13, 2013
Richard P. Dealy
/s/ Frank W. Hall	Vice President and Chief Accounting Officer (principal accounting officer)	February 13, 2013
Frank W. Hall
/s/ Thomas D. Arthur	Director	February 13, 2013
Thomas D. Arthur
/s/ Edison C. Buchanan	Director	February 13, 2013
Edison C. Buchanan
/s/ Andrew F. Cates	Director	February 13, 2013
Andrew F. Cates
/s/ R. Hartwell Gardner	Director	February 13, 2013
R. Hartwell Gardner
/s/ Charles E. Ramsey, Jr.	Director	February 13, 2013
Charles E. Ramsey, Jr.
/s/ Scott J. Reiman	Director	February 13, 2013
Scott J. Reiman
/s/ Frank A. Risch	Director	February 13, 2013
Frank A. Risch
/s/ J. Kenneth Thompson	Director	February 13, 2013
J. Kenneth Thompson
/s/ Jim A. Watson	Director	February 13, 2013
Jim A. Watson

132

Exhibit Index

Exhibit Number		Description
2.1  *	—	Agreement for the Sale and Purchase of the Entire Issued Share Capital of Pioneer Natural Resources Anaguid Ltd. and Pioneer Natural Resources Tunisia Ltd. between Pioneer Natural Resources USA, Inc. and OMV (Tunesien) Production GmbH dated January 6, 2011 (incorporated by reference to Exhibit 2.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).
3.1	—	Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).
3.2	—	Certificate of Amendment of the Amended and Restated Certificate of Incorporation effective May 18, 2012 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).
3.3	—	Third Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).
4.1	—	Form of Certificate of Common Stock, par value $.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).
4.2	—	Indenture dated January 13, 1998, between the Company and The Bank of New York, as trustee (incorporated by reference to Exhibit 99.1 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).
4.3	—	First Supplemental Indenture dated as of January 13, 1998, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).
4.4	—	Second Supplemental Indenture dated as of April 11, 2000, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-13245).
4.5	—	Third Supplemental Indenture dated as of April 30, 2002, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 1-13245).
4.6	—	Fourth Supplemental Indenture dated as of July 15, 2004, among the Company and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).
4.7	—	Fifth Supplemental Indenture dated as of July 15, 2004, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).
4.8	—	Sixth Supplemental Indenture, dated as of May 1, 2006, among the Company, Pioneer USA and The Bank of New York Trust Company, N.A., as Trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 4, 2006).
4.9	—	Seventh Supplemental Indenture, dated as of March 12, 2007, among the Company, Pioneer USA, The Bank of New York Trust Company, N.A, as original trustee under the indenture, and Wells Fargo Bank, National Association, as series trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 12, 2007).
4.10	—	Indenture dated January 22, 2008 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).
4.11	—	First Supplemental Indenture dated January 22, 2008 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.10 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).

133

4.12	—	Second Supplemental Indenture dated November 9, 2009 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.19 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 13, 2009).
4.13	—	Indenture dated June 26, 2012 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
4.14	—	First Supplemental Indenture, dated June 26, 2012, by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
10.1 H	—	The Company's Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-35087, filed with the SEC on September 8, 1997).
10.2 H	—	First Amendment to the Company's Long-Term Incentive Plan, effective as of November 23, 1998 (incorporated by reference to Exhibit 10.72 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.3 H	—	Amendment No. 2 to the Company's Long-Term Incentive Plan, effective as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.4 H	—	Amendment No. 3 to the Company's Long-Term Incentive Plan, effective as of February 17, 2000 (incorporated by reference to Exhibit 10.76 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.5 H	—	Amendment No. 4 to the Company's Long-Term Incentive Plan, effective as of November 20, 2003 (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.6 H	—	Amendment No. 5 to the Company's Long-Term Incentive Plan, effective as of May 12, 2004 (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.7 H	—	Amendment No. 6 to the Company's Long-Term Incentive Plan, effective as of December 17, 2004 (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.8 H	—	Amendment No. 7 to the Company's Long Term Incentive Plan effective November 20, 2008 (incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.9 H	—	Form of Omnibus Nonstatutory Stock Option Agreement for Option Award Participants with respect to grants under the Company's Long-Term Incentive Plan (Group 1) (incorporated by reference to Exhibit 10.20 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.10 H	—	Pioneer Natural Resources Company Employee Stock Purchase Plan, as amended and restated effective September 1, 2007 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, File No. 1-13245).
10.11 H		First Amendment to Amended and Restated Pioneer Natural Resources Company Employee Stock Purchase Plan dated effective September 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. File No. 1-13245, filed with the SEC on May 18, 2012).
10.12 H	—	The Company's Executive Deferred Compensation Plan, Amended and Restated Effective as of August 1, 2002 (incorporated by reference to Exhibit 10.15 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.13 H	—	Amendment No. 1 to the Company's Executive Deferred Compensation Plan, effective as of January 1, 2007 (incorporated by reference to Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-13245).
10.14 H	—	Pioneer USA 401(k) and Matching Plan, Amended and Restated Effective as of January 1, 2008 (incorporated by reference to Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-13245).
10.15 H	—	First Amendment to the Pioneer USA 401(k) and Matching Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245).
10.16 H	—	Amendment No. 2 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-13245).

134

10.17 H	—	Amendment No. 3 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed October 28, 2009 effective as of the dates specified therein (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-13245).
10.18 H	—	Amendment No. 4 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, effective January 1, 2010 (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 2009, File No. 1-13245).
10.19 H	—	Amendment No. 5 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed December 12, 2011 (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011, File No. 1-13245).
10.20 H	—	Amendment No. 6 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed January 12, 2012 (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011, File No. 1-13245).
10.21 H  (a)	—	Amendment No. 7 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed April 2, 2012.
10.22	—	Second Amended and Restated 5-Year Revolving Credit Agreement dated as of March 31, 2011, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (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 April 5, 2011).
10.23	—	First Amendment to Second Amended and Restated 5-Year Revolving Credit Agreement dated as of December 20, 2012, among the Company, as the Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (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 December 20, 2012).
10.24 H	—	Indemnification Agreement between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its non-employee directors and executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (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 August 27, 2009).
10.25 H	—	Severance Agreement dated August 16, 2005, 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 Severance Agreement (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13245).
10.26 H	—	Change in Control Agreement, dated August 16, 2005, 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 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 17, 2005).
10.27 H	—	Change in Control Agreement, dated August 10, 2005, between the Company and William F. Hannes (incorporated by reference to Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 2005, File No. 1-13245).
10.28 H	—	Form of Change in Control Agreement dated September 10, 2005, between the Company and Jay P. Still (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 2008).
10.29 H	—	Pioneer Natural Resources Company 2006 Long-Term Incentive Plan (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 May 9, 2006).
10.30 H	—	First Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective November 20, 2008 (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.31 H	—	Second Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective May 28, 2009 (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 May 28, 2009).
10.32 H	—	Third Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (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 June 18, 2009).
10.33 H	—	Fourth Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).
10.34 H (a)	—	Fifth Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective August 20, 2012.

135

10.35 H	—	Form of restricted stock unit Award Agreement for non-employee directors with respect to grants under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying substantially identical agreements between the Company and each of its non-employee directors identified on the schedule and identifying the material differences between each of those agreements and the filed Award Agreement (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 9, 2006).
10.36 H	—	Form of Restricted Stock Unit Agreement for Non-Employee Directors to be used in connection with annual equity awards under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 1-13245).
10.37 H	—	Form of Restricted Stock Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Restricted Stock Award Agreement (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 2, 2007).
10.38	—	First Amended and Restated Agreement of Limited Partnership of Pioneer Southwest Energy Partners L.P. dated May 6, 2008, between Pioneer Natural Resources GP LLC, as the General Partner, and Pioneer Natural Resources USA, Inc., as the Organizational Limited Partner, together with any other persons who become Partners (as defined in such agreement) in the Partnership (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of Pioneer Southwest Energy Partners L.P., File No. 001-34032, filed with the SEC on May 9, 2008).
10.39	—	Administrative Services Agreement, dated effective May 6, 2008, among Pioneer Natural Resources GP LLC, Pioneer Southwest Energy Partners L.P., Pioneer Southwest Energy Partners USA LLC, and Pioneer Natural Resources USA, Inc. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, of Pioneer Southwest Energy Partners L.P., File No. 001-34032, filed with the SEC on May 9, 2008).
10.40	—	Amended and Restated Credit Agreement entered into as of March 29, 2012, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Pioneer Southwest Energy Partners L.P., File No. 001-34032, filed with the SEC on April 3, 2012).
10.41 H	—	Severance Agreement, dated May 19, 2008, between the Company and Frank W. Hall (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-13245).
10.42 H	—	Change in Control Agreement, dated May 19, 2008, between the Company and Frank W. Hall (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-13245).
10.43 H	—	Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (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 November 25, 2008).
10.44 H	—	Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.45 H	—	Form of Amendment to Change in Control Agreement, dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.46 H	—	Form of Amendment to Change in Control Agreement, dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.47 H	—	Amended and Restated Executive Deferred Compensation Plan, effective as of January 1, 2009 (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.48 H	—	Amendment No. 1 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245).
10.49 H	—	Amendment No. 2 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2011 (incorporated by reference to Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).

136

10.50 H	—	Pioneer Southwest Energy Partners L.P. 2008 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-1 of Pioneer Southwest Energy Partners L.P., Registration No. 333-144868).
10.51 H	—	Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13245).
10.52 H	—	Form of Nonstatutory Stock Option Agreement between the Company and Scott D. Sheffield, with respect to awards made under the Company's 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13245).
10.53 H	—	Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to awards made under the Company's 2006 Long Term Incentive Plan. (incorporated by reference to Exhibit 10.64 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).
10.54 H	—	Form of Restricted Stock Award Agreement between the Company and Timothy L. Dove, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.55 H	—	Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.56 H	—	Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to annual awards made under the Company's 2006 Long Term Incentive Plan together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.57 H	—	Form of Nonstatutory Stock Option Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.58 H	—	Form of Restricted Stock Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.59 H	—	Form of Restricted Stock Unit Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
12.1  (a)	—	Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.
21.1  (a)	—	Subsidiaries of the registrant.
23.1  (a)	—	Consent of Ernst & Young LLP.
23.2  (a)	—	Consent of Netherland, Sewell & Associates, Inc.
23.3  (a)	—	Consent of Ryder Scott Company, L.P.
31.1  (a)	—	Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.

137

31.2  (a)	—	Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1  (b)	—	Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2  (b)	—	Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
95.1 (a)	—	Mine Safety Disclosure pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.
99.1  (a)	—	Report of Netherland, Sewell & Associates, Inc.
99.2  (a)	—	Report of Ryder Scott Company, L.P.
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.
H	Executive Compensation Plan or Arrangement.
*	Pursuant to the rules of the Commission, certain of the schedules and similar attachments to the Agreement have not been filed. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.

138

EX-10.21

EXHIBIT 10.21

AMENDMENT NO. 7 TO THEPIONEER NATURAL RESOURCES USA, INC.

401(k) AND MATCHING PLAN

(Amended and Restated Effective as of January 1, 2008)

THIS AMENDMENT NO. 7 is made and entered into by Pioneer Natural Resources USA, Inc. (the “Company”):

WITNESSETH:

WHEREAS, the Company maintains the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan (the “Plan”);

WHEREAS, pursuant to Section 8.3 of the Plan, the Benefit Plan Design Committee (the “Committee”) of the Company maintains the authority to amend the Plan at any time; and

WHEREAS, the Committee desires to amend the Plan to make certain discretionary changes including (i) adding a new participating employer; (ii) providing for prior service for purposes of eligibility and vesting; and (iii) allowing direct rollovers of outstanding loans.

NOW THEREFORE, the Plan is hereby amended effective April 2, 2012 as follows.

1.    Section 1.1(e) of the Plan is hereby amended in its entirety as follows:

“Basic Compensation” means, for all Participants who are not members of the Orange County Union and the Glass Rock/Millwood Union, the sum of (i) the base salary or wages and any overtime payable by an Employer to an Employee for personal services rendered to the Employer (including sick and vacation pay), but excluding any amount payable pursuant to an Employer’s salary continuation program, (ii) any contributions made by an Employer on behalf of the Employee to a qualified cash or deferred arrangement (within the meaning of Code Section 401(k)) maintained by such Employer, including any Catch-Up Contributions, Pre-Tax Contributions and Pre-Tax Bonus Contributions made by an Employer to this Plan on behalf of such Employee, (iii) any compensation reduction amounts elected by such Employee for the purchase of benefits pursuant to a cafeteria plan (within the meaning of Code Section 125(d)) maintained by an Employer, (iv) any elective amounts that are not includible in the gross income of an Employee by reason of Code Section 132(f)(4), and (v) any military differential wage payments made by the Employer; provided, however, that the Basic Compensation of an Employee taken into account under the Plan for any Plan Year shall not exceed $200,000 (as adjusted to take into account any cost-of-living increases authorized pursuant to Code Section 401(a)(17)(B)) and bonuses to be paid on April 15, 2012 for services performed for a previous employer and any quarterly bonus paid will be excluded.

For all Participants who are members of the Orange County Union and the Glass Rock/Millwood Union, “Basic Compensation” means

1

“Compensation” as defined under Section 1.1(k) of the Plan with the following exclusions:

(a)    reimbursements or other expense allowances, fringe benefits (cash and non-cash), moving expenses, deferred compensation, and welfare benefits;

(b)    amounts earned but not paid during the Plan Year solely because of the timing of pay periods and pay dates (the “administrative delay rule”);

(c)    salary continuation payments paid to a Participant who is permanently and totally disabled (as defined by Code Section 22(e)(3));

(d)    bonuses to be paid on April 15, 2012 for services performed for a previous employer; and

(e)    any quarterly bonus paid.

2.    The following sentence is hereby added to the first paragraph of Section 1.1(ff) of the Plan as follows:

Solely for the purpose of determining the Period of Service completed by a Covered Employee who was in the employ of Carmeuse Lime, Inc. (or a subsidiary thereof) on April 1, 2012, and who became an employee of an Employer on April 2, 2012 and a Participant in this Plan on April 2, 2012, service with Carmeuse Lime, Inc. or a subsidiary thereof prior to April 2, 2012 shall be considered to be service with an Employer.

3.    The following sentence is hereby added to the end of Section 1.1(iii) as follows:

Solely for the purpose of determining a Year of Eligibility Service completed by a Covered Employee who was in the employ of Carmeuse Lime, Inc. (of a subsidiary thereof) on April 1, 2012, and who became an employee of an Employer on April 2, 2012 and a Participant in this Plan on April 2, 2012, service with Carmeuse Lime, Inc. or a subsidiary thereof prior to April 2, 2012 shall be considered to be service with an Employer for purposes of determining eligibility to participate in the Plan.

4.    Section 3.9(a) of the Plan is hereby amended in its entirety as follows:

(a)    a direct rollover of an eligible rollover distribution, including a distribution consisting of Roth Rollover Property and outstanding loans only from the Carmeuse Lime Inc. 401(k) Plan, from: ((A) a qualified plan described in Code Section 401(a) or 403(a), including after tax employee contributions, ((A) an annuity contract described in Code Section 403(b), excluding after tax employee contributions, or ((A) an eligible plan under Code Section 457(b) which is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state; or

5.    Section 3.2(a) of the Plan shall be amended in its entirety as follows:

(a)    Unless provided otherwise in subsection (d) of the Section below, for each pay period an Employer shall make to the Plan for each Participant in its employ a Matching

2

Contribution equal to 200% of the Pre-Tax Contributions and Pre-Tax Contributions designated as Roth Contributions made by the Employer on such Participant’s behalf during such pay period which are not in excess of 5% of such Participant’s Basic Compensation for such pay period.

6.    Subsection (d) shall be added to Section 3.2 of the Plan as follows:

(d)    For each Participant who was employed by Carmeuse Lime, Inc. or a subsidiary thereof and part of a collective bargaining unit as of April 1, 2012, for each pay period an Employer shall make to the Plan for each such Participant in its employ a Matching Contribution as set forth below:

(i)    Orange County Union. A Matching Contribution equal to 100% of the first 4% and 50% of the next 2% of Pre-Tax Contributions and Pre-Tax Contributions designated as Roth Contributions made by the Employer on such Participant’s behalf during such pay period which are not in excess of 5% of such Participant’s Basic Compensation for such pay period.

(ii)    Glass Rock/Millwood Union. A Matching Contribution equal to 50% of the first 6% of Pre-Tax Contributions and Pre-Tax Contributions designated as Roth Contributions made by the Employer on such Participant’s behalf during such pay period which are not in excess of 3% of such Participant’s Basic Compensation for such pay period.     

7.    The introduction to the table in Section 5.2 of the Plan is hereby amended in its entirety as follows:

The amounts credited to the Employer Account and Matching Plan Account of a Participant shall become fully vested upon the occurrence of any of the following events while the Participant is in the employ of, on authorized leave of absence from an Employer or Affiliated Company: (1) the completion of an Hour of Service by the Participant on or after the date he or she attains age 60, (2) the Participant’s death, or (3) the Participant’s Permanent Disability. Further, the amounts credited to the Employer Account and Matching Plan Account of a Participant who dies while performing qualified military service (as defined in Code Section 414(u)) on or after January 1, 2007 also shall become fully vested as if an Employee. Unless sooner vested pursuant to the preceding sentence, and except as provided in subsections (b) and (c) of this Section and Section 5.3, the amounts credited to a Participant’s Employer Account and Matching Plan Account shall vest in accordance with the following schedule:

8.    Subsection (c) is hereby added to Section 5.2 of the Plan as follows:

(c)    Unless sooner vested pursuant to subsection (a) of this Section, for Participants who were employed by Carmeuse Lime, Inc. or a subsidiary thereof and part of a collective bargaining unit as of April 1, 2012, the amounts credited to that Participant’s Employer Account and Matching Plan Account shall vest in accordance with the following schedule:

3

Period of Service Completed by Participant	Percentage Vested
Less than 1 year	0%
1 year but less than 2 years	33%
2 years but less than 3 years	67%
3 or more years	100%

NOW, THEREFORE, be it further provided that except as provided above, the Plan shall continue to read in its current state.

* * * * * * * *

IN WITNESS WHEREOF, the Company has executed this Amendment No. 7 this 2nd day of April, 2012, to be effective as specified above.

PIONEER NATURAL RESOURCES COMPANY
By:	/s/ Larry N. Paulsen
	Name: Larry N. Paulsen
	Title: Vice President, Administration and Risk Management

US 1317671v.4

4

EX-10.34

EXHIBIT 10.34

FIFTH AMENDMENT TO THE

PIONEER NATURAL RESOURCES COMPANY

2006 LONG TERM INCENTIVE PLAN

THIS FIFTH AMENDMENT (the “Amendment”) to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan, as amended from time to time (the “Plan”), is effective August 20, 2012 (the “Effective Date”), and is made by Pioneer Natural Resources Company (the “Company”).

W I T N E S S E T H:

WHEREAS, the Company previously adopted the Plan, under which the Company is authorized to grant equity-based incentive awards to certain employees and service providers of the Company;

WHEREAS, pursuant to Section 3(a) of the Plan, the Compensation and Management Development Committee (“Committee”) of the Board of Directors of the Company has the authority, in its sole and absolute discretion, to terminate, modify or amend the Plan, subject to certain limitations set forth in the Plan; and

WHEREAS, the Committee has determined that it is desirable to amend the Plan in the manner contemplated hereby.

NOW, THEREFORE, the Plan shall be amended as of the Effective Date as set forth below.

1.     Section 10(a)(ii) of the Plan is hereby deleted and replaced in its entirety with the following:

(ii) Qualified Domestic Relations Orders. Except as may be expressly provided in the applicable Award Agreement, an Option, Stock Appreciation Right, Restricted Stock Unit Award or Restricted Stock Award may be transferred, to a Permitted Transferee, pursuant to a domestic relations order entered or approved by a court of competent jurisdiction upon delivery to the Company of written notice of such transfer and a certified copy of such order.

2.     Except as set forth above, the Plan shall continue to read in its current state.

IN WITNESS WHEREOF, the Company has caused the execution of this Amendment by its duly authorized officer, effective as of the Effective Date.

PIONEER NATURAL RESOURCES COMPANY

By:    /s/ Larry N. Paulsen

Larry N. Paulsen

Vice President, Administration and Risk Management

Date:    August 20, 2012

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:

	Year ended December 31,
	2012	2011	2010	2009	2008
Ratio of earnings to fixed charges (a)	1.99	4.01	4.63	(b)	2.08
Ratio of earnings to fixed charges and preferred stock (c)	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-21.1

EXHIBIT 21.1

SUBSIDIARIES OF THE COMPANY

Subsidiaries	State or Jurisdiction of Organization
Pioneer Natural Resources USA, Inc.	Delaware
DMLP CO.	Delaware
Long Canyon Gas Company, LLC	Colorado
Lorencito Gas Gathering, LLC	Colorado
Mesa Environmental Ventures Co.	Delaware
Petroleum South Cape (Pty) Ltd.	South Africa
Pioneer Natural Gas Company	Texas
Pioneer Natural Resources Alaska, Inc.	Delaware
Pioneer Natural Resources Foundation	Texas
Pioneer Natural Resources GP LLC	Delaware
Pioneer Natural Resources Midstream Holding LLC	Delaware
Pioneer Natural Resources Morocco Limited	Cayman Islands
Pioneer Natural Resources Pumping Services LLC	Delaware
Industrial Sands Holding Company	Delaware
Premier Silica LLC	California
Pioneer Natural Resources South Africa (Pty) Limited	South Africa
Pioneer Natural Resources (Tierra del Fuego) S.R.L.	Argentina
Pioneer Natural Resources UK Limited	England
Pioneer Natural Resources Well Services LLC	Delaware
Pioneer Natural Resources West Africa Limited	Cayman Islands
Pioneer Natural Resources Equatorial Guinea Limited	Cayman Islands
Pioneer Resources Africa Limited	Cayman Islands
Pioneer Natural Resources Nigeria Ltd.	Cayman Islands
Pioneer NR Nigeria (256) Limited	Nigeria
Pioneer Resources Gabon Limited	Bahamas
Pioneer Southwest Energy Partners L.P.	Delaware
Pioneer Southwest Energy Partners USA LLC	Delaware
PSE Finance Corporation	Delaware
Pioneer Uravan, Inc.	Texas
PNR Acquisitions LLC	Delaware
Sendero Holding Company, LLC	Delaware
Sendero Drilling Company, LLC	Delaware
Westpan Limited NGL LLC	Texas
Westpan Limited Resources LLC	Texas
Pioneer International Resources Company	Delaware
LF Holding Company LDC	Cayman Islands
Parker & Parsley Argentina, Inc.	Delaware
TDF Holding Company LDC	Cayman Islands
Parker & Parsley 87-A Conv., Ltd.	Texas
Parker & Parsley 90 Spraberry Private Development, L.P.	Delaware
Parker & Parsley Private Investment 88 L.P.	Delaware
Parker & Parsley Private Investment 89, L.P.	Delaware
Midkiff Development Drilling Program, Ltd.	Texas

Note: Inclusion in the list is not a representation that the subsidiary is a significant subsidiary.

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-3 No. 333-174402) of Pioneer Natural Resources Company and Pioneer Natural Resources USA, Inc. and in the related Prospectus,

(2) Registration Statement (Form S-3 No. 333-148655) of Pioneer Natural Resources Company and Pioneer Natural Resources USA, Inc. and in the related Prospectus,

(3) Registration Statement (Form S-8 No. 333-136488) pertaining to the Pioneer Natural Resources Company Executive Deferred Compensation Plan,

(4) Registration Statement (Form S-8 No. 333-136489) pertaining to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan,

(5) Registration Statement (Form S-8 No. 333-136490) pertaining to the Pioneer Natural Resources Company Long-Term Incentive Plan,

(6) Registration Statement (Form S-8 No. 333-88438) pertaining to the Pioneer Natural Resources Company Long-Term Incentive Plan,

(7) Registration Statement (Form S-8 No. 333-39153) pertaining to the Pioneer Natural Resources Company Deferred Compensation Retirement Plan,

(8) Registration Statement (Form S-8 No. 333-39249) pertaining to the Pioneer Natural Resources USA, Inc. Profit Sharing 401(k) Plan,

(9) Registration Statement (Form S-8 No. 333-35087) pertaining to the Pioneer Natural Resources Company Long-Term Incentive Plan,

(10) Registration Statement (Form S-8 No. 333-176712) pertaining to the Pioneer Natural Resources Company Employee Stock Purchase Plan,

(11) Registration Statement (Form S-8 No. 333-161283) pertaining to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan,

(12) Registration Statement (Form S-8 No. 333-178671) pertaining to the Pioneer Natural Resources USA, Inc. Profit Sharing 401(k) Plan, the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan and the Pioneer Natural Resources Company Executive Deferred Compensation Plan, and

(13) Registration Statement (Form S-8 No. 333-183379) pertaining to the Pioneer Natural Resources Company Employee Stock Purchase Plan,

of our reports dated February 13, 2013, with respect to the consolidated financial statements of Pioneer Natural Resources Company and the effectiveness of internal control over financial reporting of Pioneer Natural Resources Company included in this Annual Report (Form 10-K) of Pioneer Natural Resources Company for the year ended December 31, 2012.

/s/ Ernst & Young LLP

Dallas, Texas

February 13, 2013

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references to our firm, in the context in which they appear, and to the references to and the incorporation by reference of our audit letter dated February 4, 2013, included in the Annual Report on Form 10-K of Pioneer Natural Resources Company (the “Company”) for the fiscal year ended December 31, 2012, as well as in the notes to the financial statements included therein. We also hereby consent to the incorporation by reference of the references to our firm, in the context in which they appear, and to our audit letter dated February 4, 2013, into the Company’s previously filed Registration Statements on Form S-8 (No. 333-176712, No. 333-178671, No. 333-35087, No. 333-39153, No. 333-39249, No. 333-88438, No. 333-136488, No. 333-136489, No. 333-136490, No. 333-161283 and No. 333-183379) and on Form S-3 (No. 333-148655 and No. 333-174402) in accordance with the requirements of the Securities Act of 1933, as amended.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ C.H. (Scott) Rees III
	C.H. (Scott) Rees III, P.E. Chairman and Executive Vice President

Dallas, Texas

February 12, 2013

EX-23.3

EXHIBIT 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to the references to our firm, in the context in which they appear, and to the references to and the incorporation by reference of our audit letter dated February 11, 2013, included in the Annual Report on Form 10-K of Pioneer Natural Resources Company (the “Company”) for the fiscal year ended December 31, 2012, as well as in the notes to the financial statements included therein. We also hereby consent to the incorporation by reference of the references to our firm, in the context in which they appear, and to our audit letter dated February 11, 2013, into the Company’s previously filed Registration Statements on Form S-8 (No. 333-176712, No. 333-178671, No. 333-35087, No. 333-39153, No. 333-39249, No. 333-88438, No. 333-136488, No. 333-136489, No. 333-136490, No. 333-161283 and No. 333-183379) and on Form S-3 (No. 333-148655 and No. 333-174402) in accordance with the requirements of the Securities Act of 1933, as amended.

	By:	/s/ Ryder Scott Company, L.P.
		Ryder Scott Company, L.P. TBPE Firm Registration No. F-1580
Denver, Colorado
February 11, 2013

EX-31.1

EXHIBIT 31.1

CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Scott D. Sheffield, certify that:

1. I have reviewed this Annual Report on Form 10-K 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.

February 13, 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 Annual Report on Form 10-K 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.

February 13, 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 Annual Report on Form 10-K for the year ended December 31, 2012 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:	February 13, 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 Annual Report on Form 10-K for the year period ended December 31, 2012 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:	February 13, 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 year ended December 31, 2012 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 December 31, 2012) 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	12	—	—	—	—	$	7,354	—	No	No	—	—	—
Riverside Operation / 0404263	2	—	—	—	—	$	307	—	No	No	—	—	—
Colorado Springs Operation / 0503295	—	—	—	—	—	$	—	—	No	No	—	—	—
Glass Rock Operation / 3301354	21	—	—	—	1	$	4,859	—	No	No	—	—	—
Millwood Operation / 3301355	5	—	—	—	—	$	1,821	—	No	No	—	—	—
Voca Pit and Plant / 4101003	13	—	—	—	—	$	4,367	—	No	No	—	—	—
Brady Plant / 4101371	22	—	—	—	—	$	3,018	—	No	No	—	—	—
Voca West / 4103618	2	—	—	—	—	$	200	—	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.

EX-99.1

EXHIBIT 99.1

February 4, 2013

Mr. Kerry D. Scott

Pioneer Natural Resources Company

5205 North O'Connor Boulevard, Suite 200

Irving, Texas 75039-3746

Dear Mr. Scott:

In accordance with your request, we have audited the estimates prepared by Pioneer Natural Resources Company (Pioneer), as of December 31, 2012, of the proved reserves and future revenue to the Pioneer interest in certain oil and gas properties located in the United States. It is our understanding that the proved reserves estimates shown herein constitute approximately 91 percent of all of the proved reserves owned by Pioneer. These reserves include all proved reserves from its consolidated subsidiary, Pioneer Southwest Energy Partners, which is approximately 48 percent owned by public unit holders. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit on or about the date of this letter. This report has been prepared for Pioneer's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth Pioneer's estimates of the net reserves and future net revenue, as of December 31, 2012, for the audited properties:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	203,405	119,115	1,413,750	10,607,398	5,718,641
Proved Developed Non-Producing	12,937	4,775	120,333	878,875	349,171
Proved Undeveloped	222,112	83,928	500,466	9,693,216	1,511,895
Total Proved	438,453	207,819	2,034,549	21,179,488	7,579,707

Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on a field-by-field basis, some of the estimates of Pioneer are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. (NSAI). However, in our opinion the estimates of Pioneer's proved reserves and present worth discounted at 10 percent shown herein are, in the aggregate, reasonable and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by Pioneer in preparing the December 31, 2012, estimates of reserves and future

revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Pioneer.

The estimates shown herein are for proved reserves. Pioneer's estimates do not include probable or possible reserves that may exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Prices used by Pioneer are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2012. For oil and NGL volumes, the average of Platts Oil Daily West Texas Intermediate (Cushing) spot price of $94.839 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average Platts Gas Daily Henry Hub spot price of $2.757 per MMBTU is adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $89.84 per barrel of oil, $34.54 per barrel of NGL, and $2.53 per MCF of gas.

Operating costs used by Pioneer are based on historical operating expense records. For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Lease and well operating costs for the operated properties include direct lease- and field-level costs and Pioneer's estimate of the portion of its headquarters general and administrative overhead (G&A) expenses necessary to operate the properties. Pioneer's estimate of G&A expenses is included at the field area level for all areas except for Raton Basin, which is included at the lease level. Capital costs used by Pioneer are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Abandonment costs used are Pioneer's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Operating costs are held constant throughout the lives of the properties, and capital costs and abandonment costs are held constant to the date of expenditure.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of Pioneer and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of all the audited properties. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Pioneer with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of Pioneer's overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by Pioneer, are on file in our office. The technical persons responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
	/s/ C.H. (Scott) Rees III
By:
	C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer
	/s/ G. Lance Binder
By:
	G. Lance Binder, P.E., 61794 Executive Vice President
Date Signed: February 4, 2013

GLB:JLW

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-99.2

EXHIBIT 99.2

Pioneer Natural Resources Company

Estimated

Future Proved Reserves

Attributable to Certain

Interests

In Alaska

SEC Parameters

As of

December 31, 2012

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

February 11, 2013

Mr. Kerry Scott

Pioneer Natural Resources Company

5205 N. O’Connor Blvd., Suite 200

Irving, Texas, 75039-3764

Gentlemen:

At the request of Pioneer Natural Resources Company (Pioneer), Ryder Scott Company (Ryder Scott) has conducted a reserves audit of the estimates of the proved reservesas of December 31, 2012 prepared by Pioneer’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on December 12, 2012 and presented herein, was prepared for public disclosure by Pioneer in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Pioneer’s estimated net reserves attributable to certain interests of Pioneer in Alaska and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2012. The subject properties include the Oooguruk field including the Nuiqsut, Kuparuk, and Torok producing zones.

The properties reviewed by Ryder Scott account for 6 percent of the total net proved liquid hydrocarbon reserves and -0- percent of the total net proved gas reserves of Pioneer as of December 31, 2012.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”

Based on our review, including the data, technical processes and interpretations presented by Pioneer, it is our opinion that the overall procedures and methodologies utilized by Pioneer in preparing their estimates of the proved reserves as of December 31, 2012 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Pioneer are, in the aggregate, reasonable within the established audit tolerance guidelines set forth in the SPE auditing standards.

The estimated reserves presented in this report are related to hydrocarbon prices. Pioneer has informed us that in the preparation of their reserve and income projections, as of December 31, 2012, they used average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the

estimated quantities presented in this report. The net reserves as estimated by Pioneer attributable to Pioneer's interest in the properties that we reviewed are summarized as follows:

SEC PARAMETERS

Estimated Net Reserves

Attributable to Certain Interests of

Pioneer Natural Resources Company

Oooguruk Field

As of December 31, 2012
	Proved
			Total
	Developed	Undeveloped	Proved
Net Reserves of Properties Audited by Ryder Scott
Oil – MBO	12,680	31,278	43,957

The net remaining reserves shown herein are expressed in thousands of barrels on an equivalent barrel, BOE, basis. Liquid hydrocarbons, including hydrocarbons expressed in terms of BOE, are in standard 42 gallon barrels. BOE was calculated using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. At Pioneer’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are those 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. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves

may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered,could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable, or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties that we reviewed were estimated by a combination of volumetric and performance methods. The performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through November, 2012, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Pioneer and were considered sufficient for the purpose thereof. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Pioneer for our review that were available through November, 2012. The data utilized from analogues as wellas well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a

given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

A review of Pioneer’s economic model showed that it is suitable for cash flow estimates used in reserve reports and has been validated against existing economic models used in industry. Additional capabilities are incorporated into Pioneer’s economic model to handle the complex Alaska State Tax treatment. These capabilities were previously validated against Alaska Department of Revenue guidance, and to our knowledge have been accepted by the State as accurate. For these reasons, cash flows attributable to Ryder Scott’s estimates of future volumes were generated using Pioneer’s economic model.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Pioneer relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Pioneer for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The initial SEC hydrocarbon prices in effect on December 31, 2012 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Pioneer. The product prices which were actually used by Pioneer to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used by Pioneer were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Pioneer.

The table below summarizes Pioneer’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Pioneer’s “average realized prices.” The average realized prices shown in the table below were determined from Pioneer’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Pioneer’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

Geographic Area	Product	Price Reference	Avg Benchmark Prices	AvgProved Realized Prices
Alaska	Oil/Condensate	ANS	$103.64/Bbl	$103.64/Bbl

Operating costs furnished by Pioneer are based on the operating expense reports of Pioneer and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The

operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished by Pioneer were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Pioneer. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Pioneer are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Pioneer were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Pioneer. The estimated net cost of abandonment after salvage was included by Pioneer for properties where abandonment costs net of salvage were significant. Pioneer’s estimates of the net abandonment costs were accepted without independent verification.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Pioneer’s plans to develop these reserves as of December 31, 2012. The implementation of Pioneer’s development plans as presented to us is subject to the approval process adopted by Pioneer’s management. As the result of our inquires during the course of our review, Pioneer has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Pioneer’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Pioneer. Additionally, Pioneer has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Pioneer were held constant throughout the life of the properties.

Pioneer’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Pioneer to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Pioneer. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Pioneer’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

The reserves reported herein are limited to the period prior to expiration of current contracts providing the legal right to produce. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Pioneer’s representations regarding such contractual information should be construed as a legal opinion on this matter.

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Pioneer operates or has interests. Pioneer’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which Pioneer derives an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Pioneer for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Pioneer are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Pioneer has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Pioneer’s forecast of future proved production, we have relied upon data furnished by Pioneer with respect to property interests, production and well tests from examined wells, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Pioneer. We consider the factual data furnished to us by Pioneer to be appropriate and sufficient for the purpose of our review of Pioneer’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Pioneer and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Pioneer, it is our opinion that the overall procedures and methodologies utilized by Pioneer in preparing their estimates of the proved reserves, future production and discounted future net income as of December 31, 2012 comply with the current SEC regulations and that the overall proved reserves, future production and discounted future net income for the reviewed properties as estimated by Pioneer are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

We are in reasonable agreement with Pioneer's estimates of proved reserves, future production and discounted future net income for the properties which we reviewed. As a consequence, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Pioneer.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Pioneer. Neither we nor any of our employees have any interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical persons primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Pioneer.

Pioneer makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Pioneer has certain registration statements filed with the SEC under the 1933 Securities Actinto which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and/or S-8 of Pioneer of the references to our name as well as to the references to our third party report for Pioneer, which appears in the December 31, 2012 annual report on Form 10-Kof Pioneer. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Pioneer.

We have provided Pioneer with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Pioneer and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Scott James Wilson, P.E., M.B.A.

Senior Vice President

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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 price 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.

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

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Other Expense (Tables)

12 Months Ended

Dec. 31, 2012

Other Expense [Abstract]

Schedule Of Components Of Other Expense

The following table provides the components of the Company's other expense during the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Transportation commitment charge (a)	$	37,144	$	23,248	$	1,589
Above market and idle drilling and well service equipment rates (b)	33,211		20,132		50,581
Other	18,297		12,603		9,924
Terminated drilling rig contract charges (c)	15,747		—		—
Inventory impairment (d)	6,174		3,126		10,729
Premier Silica acquisition costs	2,337		—		—
Contingency and environmental accrual adjustments	478		4,057		5,581
Total other expense	$	113,388	$	63,166	$	78,404

 ____________________

(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 were above market rates and idle drilling rig and fracture stimulation fleet fees, neither of which were chargeable to joint operations.

(c) Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.

(d) Represents lower of cost or market impairment charges on excess materials and supplies inventories.

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Disclosures About Fair Value Measurements (Assets And Liabilities That Are Measured At Fair Value On A Recurring Basis) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities, Fair Value Disclosure	$ 278	$ 425
Derivative Assets	334,376	482,075
Deferred Compensation Plan Assets	49,685	39,904
Assets, Fair Value Disclosure	384,339	522,404
Liabilities, Fair Value Disclosure	25,723	107,976
Recurring Measurements, (Fair Value, Total)	358,616	414,428
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	15,999	92,322
Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	9,724	15,654
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	124	257
Derivative Assets	0	0
Deferred Compensation Plan Assets	49,685	39,904
Assets, Fair Value Disclosure	49,809	40,161
Liabilities, Fair Value Disclosure	0	0
Recurring Measurements, (Fair Value, Total)	49,809	40,161
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	0
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	0
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	154	168
Derivative Assets	334,376	482,075
Deferred Compensation Plan Assets	0	0
Assets, Fair Value Disclosure	334,530	482,243
Liabilities, Fair Value Disclosure	25,723	107,976
Recurring Measurements, (Fair Value, Total)	308,807	374,267
Significant Other Observable Inputs (Level 2) [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	15,999	92,322
Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	9,724	15,654
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities, Fair Value Disclosure	0	0
Derivative Assets	0	0
Deferred Compensation Plan Assets	0	0
Assets, Fair Value Disclosure	0	0
Liabilities, Fair Value Disclosure	0	0
Recurring Measurements, (Fair Value, Total)	0	0
Significant Unobservable Inputs (Level 3) [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	0
Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$ 0	$ 0

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Acquisitions and Divestitures (Fair Value of Assets Acquired and Liabilities Assumed) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Business Acquisition [Line Items]
Business Acquisition, Cost of Acquired Entity, Purchase Price	$ 297,100,000
Business Acquisition, Purchase Price Allocation, Assets Acquired	474,900,000
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment	460,300,000
Business Acquisition, Purchase Price Allocation, Liabilities Assumed	(177,800,000)
Business Acquisition, Purchase Price Allocation, Deferred Taxes Asset (Liability), Net, Noncurrent	(151,000,000)
Business Combination, Acquisition Related Costs	$ 2,337,000	$ 0	$ 0

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Schedule of Compensation Expense for Each Type of Incentive Award (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Modification Of Equity Awards Per Termination Agreement			$ 1,300,000
Deferred Compensation Arrangement with Individual, Compensation Expense	86,084,000	53,085,000	45,298,000
Income Tax Expense (Benefit)	92,384,000	197,644,000	269,627,000
Share-based Compensation Arrangement by Share-based Payment Award, Plan Modification, Number of Employees Affected			12
Number Of Participants Effected for Unvested Equity Awards			12
Proceeds from Issuance of Shares under Incentive and Share-based Compensation Plans, Including Stock Options	3,100,000	619,000	4,800,000
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	48,876,000	32,861,000	31,712,000
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	22,419,000	10,882,000	4,900,000
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	4,110,000	2,936,000	1,522,000
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	6,162,000	4,500,000	4,635,000
Pioneer Southwest Ltip [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	1,098,000	761,000	475,000
Sendero B Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	982,000	1,020,000	1,020,000
Employee Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	2,437,000	125,000	1,034,000
Compensation Expense For Incentive Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income Tax Expense (Benefit)	$ 27,901,000	$ 22,084,000	$ 14,019,000

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Disclosures About Fair Value Measurements (Measured On A Nonrecurring Basis) (Details) (USD $)	3 Months Ended		12 Months Ended
	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of oil and gas properties			$ 532,589,000	$ 354,408,000	$ 0
Management oil price outlook	87.10	87.09		92.69
Management gas price outlook	4.92	4.64		5.14
South Texas Edwards And Austin Chalk [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group				189,900,000
Impairment of oil and gas properties				354,400,000
Barnett Shale Field [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group	184,800,000	128,700,000	184,800,000
Impairment of oil and gas properties	$ 87,700,000	$ 444,900,000

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Incentive Plans (Schedule Of Integral Part Of Consolidated Financial Statements) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012
Phantom Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Outstanding at beginning of year	65,157
Number of Units granted	37,487
Number of Units Lapse of restrictions	0
Number of Shares/Units, Outstanding at end of year	102,644
Weighted Average Grant-Date Fair Value, Outstanding at beginning of year	$ 27.08
Weighted Average Grant-Date Fair Value, Shares granted	$ 28.00
Weighted Average Grant Date Fair Value Lapse of restrictions	$ 0
Weighted Average Grant-Date Fair Value, Outstanding at end of year	$ 27.42
Restricted Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Outstanding at beginning of year	7,492
Number of Units granted	7,496
Number of Units Lapse of restrictions	(7,492)
Number of Shares/Units, Outstanding at end of year	7,496
Weighted Average Grant-Date Fair Value, Outstanding at beginning of year	$ 28.47
Weighted Average Grant-Date Fair Value, Shares granted	$ 26.68
Weighted Average Grant Date Fair Value Lapse of restrictions	$ 28.47
Weighted Average Grant-Date Fair Value, Outstanding at end of year	$ 26.68

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Summary Of Significant Accounting Policies (Changes of Ownership Interest) (Details) (USD $) Share data in Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net Income (loss) attributable to common stockholders	$ 192,285,000	$ 834,489,000	$ 605,208,000
Increase in additional paid in capital for the sale of 1.8 million Pioneer Southwest common units on December 12, 2011, net of tax of $15.4 million	0		0
Increase in additional paid in capital	0		0
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Issuance of Equity by Subsidiary to Noncontrolling Interests, Tax Impact	(49,072,000)	0	0
Net transfers from noncontrolling interest	(49,072,000)	35,019,000	0
Net income (loss) attributable to common stockholders and transfers from noncontrolling interest	143,213,000	869,508,000
Issued Common Units		4.4
Units Issued, Tax		23,700,000
Sale of Common Units	9.5	1.8
Sale of Units, Tax		15,400,000
Pioneer Southwest [Member]
Increase in additional paid in capital for the sale of 1.8 million Pioneer Southwest common units on December 12, 2011, net of tax of $15.4 million		35,091,000
Increase in additional paid in capital		48,792,000
Issued Common Units		2.6
Additional Paid-In Capital [Member] | Pioneer Southwest [Member]
Increase in additional paid in capital for the sale of 1.8 million Pioneer Southwest common units on December 12, 2011, net of tax of $15.4 million		26,915,000
Increase in additional paid in capital		8,104,000
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Issuance of Equity by Subsidiary to Noncontrolling Interests, Tax Impact	$ (49,072,000)

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Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2012

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule Of Compensation Expense For Each Type Of Incentive Award

The following table reflects stock-based compensation expense recorded for each type of incentive award and the associated income tax benefit for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Restricted stock-equity awards (a)	$	48,876	$	32,861	$	31,712
Restricted stock-liability awards	22,419		10,882		4,900
Stock options (b)	4,110		2,936		1,522
Performance unit awards	6,162		4,500		4,635
Pioneer Southwest LTIP	1,098		761		475
Sendero Series B units	982		1,020		1,020
ESPP	2,437		125		1,034
Total	$	86,084	$	53,085	$	45,298
Income tax benefit	$	27,901	$	22,084	$	14,019

 _____________________

(a) For the year ended December 31, 2010, stock-based compensation expense included a charge of $1.3 million for the modification of equity awards associated with termination agreements made with 12 employees affected by the divestiture of the Company's Tunisian subsidiaries. The modification accelerated vesting of all unvested equity awards for the 12 participants to the closing date of the transaction. The $1.3 million charge, net of the associated tax benefit, is included in income from discontinued operations, net of tax, in the accompanying consolidated statements of operations for the year ended December 31, 2010.

(b) Cash proceeds received from stock option exercises during 2012, 2011 and 2010 amounted to $3.1 million, $619 thousand and $4.8 million, respectively.

Number Of Shares Available Under The Company's Long Term Incentive Plan

The following table shows the number of shares available for issuance pursuant to awards under the Company's LTIP at December 31, 2012:

Approved and authorized awards	9,100,000
Awards issued after May 3, 2006	(6,134,118	)
Awards available for future grant	2,965,882

Schedule Of Restricted Stock Award Activity

The following table reflects the restricted stock award activity for the year ended December 31, 2012:

	Equity Awards				Liability Awards
	Number of Shares		Weighted Average Grant- Date Fair Value		Number of Shares
Outstanding at beginning of year	1,857,612		$	39.95	322,925
Shares granted	912,543		$	113.02	240,486
Shares forfeited	(28,011	)	$	101.91	(29,060	)
Shares vested	(1,229,382	)	$	23.75	(128,435	)
Outstanding at end of year	1,512,762		$	96.22	405,916

Schedule Of Weighted-Average Assumptions To Estimate The Fair Value

The Company used the following weighted-average assumptions to estimate the fair value of stock options granted during the years ended December 31, 2012, 2011 and 2010:

	2012		2011		2010
Expected option life - years	7.0		7.0		7.0
Volatility	49.4	%	47.6	%	46.8	%
Risk-free interest rate	1.5	%	2.9	%	3.4	%
Dividend yield	0.4	%	0.4	%	0.4	%

Schedule Of Stock Options Awards Activity

A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2012 is presented below:

	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
					(in years)	(in thousands)
Outstanding at beginning of year	564,044		$	34.90
Options awarded	98,819		$	113.76
Options exercised	(195,377	)	$	15.62
Outstanding and expected to vest, at end of year	467,486		$	59.63	7.39	$	22,663
Exercisable at end of year	171,644		$	16.72	6.17	$	15,425

Schedule of Assumptions Used [Table Text Block]

The Company used the following assumptions to estimate the fair value of performance unit awards granted during 2012, 2011 and 2010:

	2012				2011				2010
Risk-free interest rate	0.40%				1.32%				1.36%
Range of volatilities	33.6	%	-	49.0%	50.2	%	-	84.1%	50.4	%	-	83.0%

Schedule Of Performance Unit Activity

The following table summarizes the performance unit activity for the year ended December 31, 2012:

	Number of Units (a)		Weighted  Average Grant-Date Fair Value
Beginning performance unit awards	114,128		$	90.64
Units granted	47,875		$	172.57
Units vested (b)	(70,633	)	$	63.52
Ending performance unit awards	91,370		$	154.53

 _____________________

(a) These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date.

(b) On December 31, 2012, the service period lapsed on 70,633 of these performance unit awards. The lapsed units earned 2.5 shares for each vested award representing 176,585 aggregate shares of common stock issued in 2012.

Number Of Awards Available Under PSE Long Term Incentive Plan

The following table shows the number of awards available under the Pioneer Southwest LTIP at December 31, 2012:

Approved and authorized awards	3,000,000
Awards issued after May 6, 2008	(151,235	)
Awards available for future grant	2,848,765

Schedule Of Integral Part Of Consolidated Financial Statements

	Restricted Unit Awards				Phantom Unit Awards
	Number of Units		Weighted Average Grant-Date Fair Value		Number of Units	Weighted Average Grant-Date Fair Value
Outstanding at beginning of year	7,492		$	28.47	65,157	$	27.08
Units granted	7,496		$	26.68	37,487	$	28.00
Lapse of restrictions	(7,492	)	$	28.47	—	$	—
Outstanding at end of year	7,496		$	26.68	102,644	$	27.42

Schedule Of Employee Stock Purchase Plan

The following table shows the number of shares available for issuance under the ESPP at December 31, 2012:

Approved and authorized shares	1,250,000
Shares issued	(678,882	)
Shares available for future issuance	571,118

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Incentive Plans (Schedule Of Employee Stock Purchase Plan) (Details) (Employee Stock [Member])	192 Months Ended
	Dec. 31, 2012
Employee Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized shares	1,250,000
Shares issued	(678,882)
Shares available for future issuance	571,118

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Incentive Plans (Schedule Of Weighted-Average Assumptions To Estimate The Fair Value) (Details) (Stock Options [Member])	12 Months Ended
	Dec. 31, 2012 Rate	Dec. 31, 2011 Rate	Dec. 31, 2010 Rate
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected option life - years	7 years 0 months 1 day	7 years 0 months 1 day	7 years 0 months 1 day
Volatility	49.40%	47.60%	46.80%
Risk-free interest rate	1.50%	2.90%	3.40%
Dividend yield	0.40%	0.40%	0.40%

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Income Taxes (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Loss Carryforwards [Line Items]
Payments for income taxes, net of tax refunds received	$ 32.3	$ 22.3	$ 36.6
Tunisia [Member]
Operating Loss Carryforwards [Line Items]
Payments for income taxes, net of tax refunds received	$ 9.8	$ 12.2	$ 17.8

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Derivative Financial Instruments (Narrative) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 NGL contract, in BBLS [Member] Two Thousand Thirteen Collar Contracts With Short Puts [Member] bbl	Dec. 31, 2012 NGL contract, in BBLS [Member] Two Thousand Fourteen Collar Contracts With Short Puts [Member] bbl	Dec. 31, 2012 NGL contracts, price per BBL [Member] Two Thousand Thirteen Collar Contracts With Short Puts [Member]	Dec. 31, 2012 NGL contracts, price per BBL [Member] Two Thousand Thirteen Collar Contracts With Short Puts [Member] Short Put [Member]	Dec. 31, 2012 NGL contracts, price per BBL [Member] Two Thousand Fourteen Collar Contracts With Short Puts [Member]	Dec. 31, 2012 NGL contracts, price per BBL [Member] Two Thousand Fourteen Collar Contracts With Short Puts [Member] Short Put [Member]	Feb. 13, 2013 Basic Index Swaps [Member] Two Thousand And Thirteen Basis Swap Contracts [Member] MMBTU	Dec. 31, 2012 Basic Index Swaps [Member] Two Thousand And Thirteen Basis Swap Contracts [Member] MMBTU
Schedule of Trading Securities and Other Trading Assets [Line Items]
Average Daily NGL Production Derivative Barrels Per Day			1,064	1,000
Derivative, Average Cap Price					105.28		109.50
Derivative, Average Floor Price					89.30		95.00
Derivative, Nonmonetary Notional Amount, Price Per Unit						75.20		80.00
Average Daily Index Swaps Volume									25,000	40,000
Average Daily Index Swaps Price Differential									0.35	0.25
Derivative fixed interest rate	3.21%
Derivative fixed interest rate term, years	10
Notional amount of debt	$ 250,000,000
Net deferred gains from hedging in AOCI	0	3,130,000
Net deferred losses on the effective portions of discontinued commodity hedges		3,200,000
Net deferred losses on the effective portions of discontinued interest rate hedges		1,700,000
Net deferred gains or losses associated to net deferred tax provisions		$ 1,700,000

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Incentive Plans (Schedule Of Performance Unit Activity) (Details) (USD $)			12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Performance Units [Member] Rate
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Outstanding at beginning of year			91,370
Number of Units granted			47,875
Awards vested			(70,633)
Number of Shares/Units, Outstanding at end of year			114,128
Weighted Average Grant-Date Fair Value, Outstanding at beginning of year			$ 154.53
Weighted Average Grant-Date Fair Value, Units granted			$ 172.57
Weighted Average Grant Date Fair Value, Units vested			$ 63.52
Weighted Average Grant-Date Fair Value, Outstanding at end of year			$ 90.64
Performance percentage of actual payout minimum			0.00%
Performance percentage to reach maximum			250.00%
Shares lapsed			70,633
Number of shares earned for each vested award			2.5
Common stock, shares issued	134,966,740	133,121,092	176,585

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Major Customers (Consolidated Oil, NGL And Gas Revenues) (Details)	12 Months Ended
	Dec. 31, 2012 Rate	Dec. 31, 2011 Rate	Dec. 31, 2010 Rate
Plains Marketing LP [Member]
Consolidated oil, NGL and gas revenues represented by the company's purchases	26.00%	16.00%	12.00%
Enterprise Products Partners L.P. [Member]
Consolidated oil, NGL and gas revenues represented by the company's purchases	15.00%	12.00%	10.00%
Occidental Energy Marketing Inc [Member]
Consolidated oil, NGL and gas revenues represented by the company's purchases	14.00%	14.00%	8.00%

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Commitments And Contingencies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Commitments And Contingencies [Line Items]
Current annual salaries of officers and key employees	$ 43,900,000
Lease payments associated with operating leases	48,000,000	35,400,000	38,300,000
Lease Payments Discontinued Operations [Member]
Commitments And Contingencies [Line Items]
Lease payments associated with operating leases	$ 67,000	$ 513,000	$ 7,200,000

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Interest And Other Income (Interest And Other Income) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Alaskan Petroleum Production Tax credits and refunds	$ 29,342	$ 38,939	$ 47,652
Other income	5,382	7,684	4,565
Equity interest in income (loss) of EFS Midstream	2,183	1,925	(819)
Deferred compensation plan income	1,872	1,657	1,228
Interest income	1,465	697	4,177
Third-party income from vertical integration services	(11,934)	15,978	169
Total interest and other income	28,310	66,880	56,972
GrossRevenuesIncludedInThirdPartyIncomeFromVerticalIntegrationServices	247,800	50,900	946
GrossExpensesIncludedInThirdPartyIncomeFromVerticalIntegrationServices	$ 259,700	$ 34,900	$ 777

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Incentive Plans (Number Of Awards Available Under Company's Long Term Incentive Plan) (Details) (Pioneer Southwest LTIP [Member])	56 Months Ended
	Dec. 31, 2012
Pioneer Southwest LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	3,000,000
Shares issued	(151,235)
Awards available for future grant	2,848,765

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Incentive Plans (Number Of Shares Available Under The Company's Long Term Incentive Plan) (Details) (Pioneer Long-Term Incentive Plan [Member])	80 Months Ended
	Dec. 31, 2012
Pioneer Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	9,100,000
Shares issued	(6,134,118)
Awards available for future grant	2,965,882

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Subsequent Events

12 Months Ended

Dec. 31, 2012

Subsequent Events [Abstract]

Subsequent Events

NOTE Q.     Subsequent Events

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 for consideration of $1.7 billion. At closing, Sinochem will pay $522.0 million in cash to Pioneer, 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 and third party approvals.

As discussed in Note G, in January and February 2013, holders of $240.6 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. In general, upon conversion of a Convertible Senior Note, the holder will receive cash equal to the principal amount of the Convertible Senior Note and shares of the Company's common stock for the Convertible Senior Note's conversion value in excess of the principal amount. In addition, pursuant to the terms of the Convertible Senior Notes, the annual interest rate for the Convertible Senior Notes has been reduced from 2.875 percent to 2.375 percent per annum for the six-month period from January 15, 2013 to July 14, 2013 because the Notes met certain trading price conditions.

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Acquisitions and Divestitures (Components of Discontinued Operations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and gas	$ 49,192,000	$ 100,275,000	$ 236,343,000
Interest and other	95,000	6,193,000	49,076,000
Gain on disposition of assets, net	28,546,000	645,241,000	36,000
Total revenues and other income from discontinued operations	77,833,000	751,709,000	285,455,000
Oil and gas production	2,254,000	5,519,000	14,754,000
Depletion, depreciation and amortization	0	41,916,000	98,495,000
Exploration and abandonments	70,000	4,268,000	15,908,000
General and administrative	1,975,000	10,286,000	5,697,000
Accretion of discount on asset retirement obligations	1,521,000	2,686,000	2,923,000
Interest	0	773,000	0
Other	1,196,000	5,159,000	13,898,000
Total costs and expenses from discontinued operations	7,016,000	70,607,000	151,675,000
Income from discontinued operations before income taxes	70,817,000	681,102,000	133,780,000
Current	(7,720,000)	(43,897,000)	(25,486,000)
Deferred	(7,948,000)	(214,053,000)	25,756,000
Income from discontinued operations	55,149,000	423,152,000	134,050,000
Pioneer Tunisia [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest and other		2,800,000
BOEMRE [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest and other		2,000,000
Recovery of excess royalties			$ 35,300,000

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Summary Of Significant Accounting Policies (Narrative) (Details) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	12 Months Ended				12 Months Ended		12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Sendero [Member]	Dec. 31, 2010 EFS Midstream [Member]	Jun. 30, 2010 EFS Midstream [Member] Rate	Dec. 31, 2012 Pioneer Southwest [Member]	Dec. 31, 2011 Pioneer Southwest [Member]	Dec. 31, 2012 Limited Partner Interest [Member] Rate	Dec. 31, 2010 Limited Partner Interest [Member] Rate	Dec. 31, 2012 General Partner Interest [Member] Rate
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable - trade	$ 316,854,000	$ 275,991,000
Allowances for doubtful accounts	1,500,000	1,100,000
Natural gas processing plants number	4
Treating facilities number	10
Operational natural gas processing plants	2
Operational treating facilities	10
Third party revenues, processing plants and treating facilities	39,400,000	46,000,000	34,000,000
Third party expenses, processing plants and treating facilities	27,100,000	22,700,000	14,300,000
Drilling rigs owned	15
Fracture stimulation fleets	10
Percentage of interest sold						49.90%
Proceeds from sale of interest in EFS Midstream					46,400,000
Deferred gain on sale of EFS midstream					46,200,000
EFS midstream deferred gain amortization period, years					20
Partnerships interest									52.40%	61.90%	0.10%
Issued Common Units		4.4						2.6
Issued common units, offering price		$ 29.20
Sale of Common Units	9.5	1.8
Number of operating drilling rigs				15
Noncontrolling interest in consolidating subsidiaries	177,954,000	162,344,000
Net income attributable to noncontrolling interests	(50,537,000)	(47,425,000)	(40,787,000)
Deferred Revenue, Revenue Recognized	42,100,000	45,000,000	90,200,000
Basis points added to variable interest rate							162.5
Unusual or Infrequent Item, Insurance Proceeds			$ 140,100,000

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Incentive Plans (Schedule Of Assumptions To Estimate The Fair Value) (Details) (Performance Units [Member])	12 Months Ended
	Dec. 31, 2012 Rate	Dec. 31, 2011 Rate	Dec. 31, 2010 Rate
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	0.40%	1.32%	1.36%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of volatilities	49.00%	84.10%	83.00%
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of volatilities	33.60%	50.20%	50.40%

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Subsequent Events (Details) (USD $)	1 Months Ended	12 Months Ended
	Feb. 13, 2013 Rate	Dec. 31, 2012 Rate	Dec. 31, 2011	Jan. 15, 2013 Rate
Subsequent Event [Line Items]
Principal amount of notes tendered for conversion	$ 240,600,000
2.875% Convertible Senior Notes Due 2038 [Member]
Subsequent Event [Line Items]
Principal amount of notes tendered for conversion	240,600,000	111,000	70,000
Stock price in excess of principal amount of note interest rate trigger		120.00%
Senior Notes, interest rate, percentage	2.375%	2.875%		2.375%
Wolfcamp [Member]
Subsequent Event [Line Items]
Joint Venture Investment Ownership Percentage	40.00%
Business Combination, Consideration Transferred	1,700,000,000
Proceeds from Divestiture of Interest in Consolidated Subsidiaries	522,000,000
Payments From Related Party For Exploration Drilling And Completion Costs Percent	75.00%
Maximum Payments From Related Party For Exploration Drilling And Completion Costs	$ 1,200,000,000

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Major Customers (Tables)

12 Months Ended

Dec. 31, 2012

Major Customers And Derivative Counterparties [Abstract]

Consolidated Oil, NGL And Gas Revenues

The table provides the percentages of the Company's consolidated oil, NGL and gas revenues represented by the purchasers during the periods presented:

	Year Ended December 31,
	2012		2011		2010
Plains Marketing LP	26	%	16	%	12	%
Enterprise Products Partners L.P.	15	%	12	%	10	%
Occidental Energy Marketing Inc	14	%	14	%	8	%

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Acquisitions and Divestitures (Discontinued Operations Balance Sheet) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Assets of Disposal Group, Including Discontinued Operation, Current		$ 10,465
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net		53,025
Disposal Group, Including Discontinued Operation, Deferred Tax Assets		9,816
Disposal Group, Including Discontinued Operation, Other Assets		43
Discontinued operations held for sale	0	73,349
Liabilities of Disposal Group, Including Discontinued Operation, Current		11,689
Discontinued Operations, Deferred Revenue		34,320
Disposal Group, Including Discontinued Operation, Other Liabilities		29,892
Liabilities of Disposal Group, Including Discontinued Operation	$ 0	$ 75,901

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Long-Term Debt (Principal Maturities Of Long-Term Debt) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Debt Disclosure [Abstract]
2013	$ 479,907
2014	0
2015	0
2016	455,385
2017	1,085,100
Thereafter	$ 1,749,500

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Derivative Financial Instruments (Derivative Obligations Under Terminated Hedge Arrangements) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	$ (4,855)	$ 32,636	$ 84,877
Amount of Gain (Loss) Recognized in Earnings on Derivatives	330,251	392,752	450,899
Interest Rate Derivatives [Member]
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	1,700	282	1,700
Interest Rate Derivatives [Member] | Interest Expense [Member]
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	1,699	282	1,698
Interest Rate Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	0	0	2,465
Amount of Gain (Loss) Recognized in Earnings on Derivatives	(22,428)	3,098	36,597
Commodity Price Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Amount of Gain (Loss) Recognized in Earnings on Derivatives	352,679	389,654	414,302
Commodity Price Derivatives [Member] | Oil And Gas revenue [Member]
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	$ 3,156	$ (32,918)	$ (89,040)

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Summary Of Significant Accounting Policies (Oil Entitlement Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Mcf	Dec. 31, 2011 Mcf
Oil Entitlement Assets and Liabilities [Line Items]
Gas Entitlement Assets Amount	$ 6.8	$ 7.6
Gas Entitlement Assets Volumes In Mmcf	2,870	3,024
Gas Entitlement Liabilities Amount	$ 1.9	$ 2.6
Gas Entitlement Liabilities Volumes In Mmcf	582	650

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Organization And Nature Of Operations

12 Months Ended

Dec. 31, 2012

Organization And Nature Of Operations [Abstract]

Organization And Nature Of Operations

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 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. The Company's objective is to maximize shareholder investment returns by maintaining financial flexibility, capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions.

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Schedule of Derivative Assets and Liabilities by Counterparty (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 308,653
Citibank, N.A. [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	72,218
JP Morgan Chase [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	48,606
BNP Paribas [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	19,420
Barclays Capital [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	36,736
Societe Generale [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	5,700
Credit Agricole [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(1,991)
Toronto Dominion [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	18,802
Credit Suisse [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	21,196
J. Aron & Company [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	20,138
BMO Financial Group [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	26,560
Wells Fargo Bank, N.A. [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	5,024
Macquarie Bank [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	380
Royal Bank of Canada [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(97)
Deutsche Bank [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(327)
Morgan Stanley [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	13,893
Den Norske Bank [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	7,487
Merrill Lynch [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	17,136
UBS [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (2,228)

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Summary of Significant Accounting Policies (Revision for Deferred Income Taxes) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011 Decrease in Current Deferred Tax Assets, Revision of Unrealized Current Derivative Gains, Net [Member] Restatement Adjustment [Member]	Dec. 31, 2011 Increase in Current Deferred Tax Liabilities, Revision of Unrealized Current Derivative Gains, Net [Member] Restatement Adjustment [Member]	Dec. 31, 2011 Decrease in Noncurrent Deferred Tax Liabilities, Revision of Unrealized Current Derivative Gains, Net [Member] Restatement Adjustment [Member]	Dec. 31, 2012 Pioneer Southwest Ltip [Member]
Subsidiary or Equity Method Investee, Deferred Income Tax Provision on Gain (Loss) Recognized, Amount	$ (49,072,000)				$ 49,100,000
Quantifying Misstatement in Current Year Financial Statements, Amount		$ 77,000,000	$ 57,700,000	$ 134,700,000

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Disclosures About Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Assets And Liabilities That Are Measured At Fair Value On A Recurring Basis

The following tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2012 and 2011 for each of the fair value hierarchy levels:

	Fair Value Measurements 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 December 31, 2012
	(in thousands)
Assets:
Trading securities	$	124	$	154	$	—	$	278
Commodity derivatives	—		334,376		—		334,376
Deferred compensation plan assets	49,685		—		—		49,685
Total assets	49,809		334,530		—		384,339
Liabilities:
Commodity derivatives	—		15,999		—		15,999
Interest rate derivatives	—		9,724		—		9,724
Total liabilities	—		25,723		—		25,723
Total recurring fair value measurements	$	49,809	$	308,807	$	—	$	358,616
	Fair Value Measurements 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 December 31, 2011
	(in thousands)
Assets:
Trading securities	$	257	$	168	$	—	$	425
Commodity derivatives	—		482,075		—		482,075
Deferred compensation plan assets	39,904		—		—		39,904
Total assets	40,161		482,243		—		522,404
Liabilities:
Commodity derivatives	—		92,322		—		92,322
Interest rate derivatives	—		15,654		—		15,654
Total liabilities	—		107,976		—		107,976
Total recurring fair value measurements	$	40,161	$	374,267	$	—	$	414,428

Fair Value Measurements, Nonrecurring [Table Text Block]

The following table presents the fair value and impairment (in millions) for each of the Company's 2012 and 2011 proved property impairments, as well as the oil price per barrel ("BBL") and gas price per British thermal unit ("MMBTU") utilized in respective Management's Price Outlooks:

		Fair				Management's Price Outlooks
		Value		Impairment		Oil		Gas
Edwards Trend/Austin Chalk	December 2011	$	189.9	$	354.4	$	92.69	$	5.14
Barnett Shale	June 2012	$	128.7	$	444.9	$	87.09	$	4.64
Barnett Shale	December 2012	$	184.8	$	87.7	$	87.10	$	4.92

Fair Value Measurements Using Significant Unobservable Inputs

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 December 31, 2012 and 2011 are as follows:

	December 31, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	3,721,193	$	4,555,770	$	2,528,905	$	3,105,585

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Acquisitions and Divestitures Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2012

Acquisitions and Divestitures [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

The following table represents the components of the Company's discontinued operations for the years ended December 31, 2012, 2011 and 2010 (principally related to the divestitures of the Company's net assets in Pioneer South Africa and Pioneer Tunisia):

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Revenues and other income:
Oil and gas	$	49,192		$	100,275		$	236,343
Interest and other (a)	95			6,193			49,076
Gain on disposition of assets, net (b)	28,546			645,241			36
	77,833			751,709			285,455
Costs and expenses:
Oil and gas production	2,254			5,519			14,754
Depletion, depreciation and amortization (b)	—			41,916			98,495
Exploration and abandonments	70			4,268			15,908
General and administrative	1,975			10,286			5,697
Accretion of discount on asset retirement obligations (b)	1,521			2,686			2,923
Interest	—			773			—
Other	1,196			5,159			13,898
	7,016			70,607			151,675
Income from discontinued operations before income taxes	70,817			681,102			133,780
Current tax provision	(7,720		)	(43,897		)	(25,486		)
Deferred tax (provision) benefit (b)	(7,948		)	(214,053		)	25,756
Income from discontinued operations	$	55,149		$	423,152		$	134,050

 ____________________

(a) Primarily comprised of (i) $35.3 million of interest on excess royalty payments received from Bureau of Ocean Energy Management, Regulation, and Enforcement during the second quarter of 2010, (ii) $2.0 million of additional interest received during the first quarter of 2011 associated with the 2010 recovery of the aforementioned excess royalties and (iii) $2.8 million of interest income associated with Pioneer Tunisia operations during the first quarter of 2011.

(b) Represents significant noncash components of discontinued operations.

Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Table Text Block]

As of December 31, 2011, the carrying values of Pioneer South Africa assets and liabilities, respectively, were included in discontinued operations held for sale in the accompanying consolidated balance sheet and were comprised of the following:

	December 31, 2011
	(in thousands)
Composition of assets included in discontinued operations held for sale:
Current assets (excluding cash and cash equivalents)	$	10,465
Property, plant and equipment	53,025
Deferred tax assets	9,816
Other assets, net	43
Total assets	$	73,349
Composition of liabilities included in discontinued operations held for sale:
Current liabilities	$	11,689
Deferred revenue	34,320
Other liabilities	29,892
Total liabilities	$	75,901

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Disclosures About Fair Value Measurements (Financial Assets and Liabilities Not Carried At Fair Value) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Long-term Debt	$ 3,721,193	$ 2,528,905
Carrying Value [Member]
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Long-term Debt	3,721,193	2,528,905
Fair Value [Member]
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items]
Long-term Debt	$ 4,555,770	$ 3,105,585

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Summary Of Significant Accounting Policies (Schedule of Inventory) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Inventory [Line Items]
Materials and supplies inventories	$ 258,962,000	$ 297,910,000
Commodities	5,446,000	4,453,000
Inventory, Drilling, Noncurrent	(67,352,000)	(60,754,000)
Inventories	197,056,000	241,609,000
Net materials and supplies inventories reserves	$ 4,600,000	$ 900,000

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Oil Derivative Contracts Volume And Weighted Average Price

The following table sets forth the volumes per day in BBLs that were outstanding as of December 31, 2012 under the Company's oil derivative contracts and the weighted average oil prices per BBL for those contracts:

	2013			2014		2015
Swap contracts:
Volume (BBL)	3,000			—		—
Average price per BBL	$	81.02		$	—	$	—
Collar contracts with short puts:
Volume (BBL) (a)	71,029			60,000		26,000
Average price per BBL:
Ceiling	$	119.76		$	117.06	$	104.45
Floor	$	92.27		$	92.67	$	95.00
Short put	$	74.28		$	76.58	$	80.00
Rollfactor adjustment swap contracts:
Volume (BBL) (a)	6,000			—		—
NYMEX roll price (b)	$	0.43		$	—	$	—
Basis swap contracts:
Index swap volume (BBL) (c)	2,055			—		—
Average price per BBL (d)	$	(5.75	)	$	—	$	—

 ____________________

(a) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional 2014 (i) collar contracts with short puts for 9,000 BBLs per day with a ceiling price of $104.13 per BBL, a floor price of $95.00 per BBL and a short put price of $80.00 per BBL and (ii) rollfactor swap contracts for 15,000 BBLs per day priced at $0.38 per BBL; and (iii) replaced 5,000 BBLs per day of 2014 collar contracts with short puts with a ceiling price of $124.00 per BBL, a floor price of $90.00 per BBL and short put price of $72.00 per BBL with 5,000 BBLs per day of 2014 collar contracts with short puts with a ceiling price of $105.74 per BBL, a floor price of $100.00 per BBL and short put price of $80.00 per BBL.

(b) 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.

(c) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional basis swap contracts for 1,000 BBLs per day of October through December 2013 production with a price differential between Cushing WTI and Louisiana Light Sweet crude of $7.60 per BBL.

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

Gas Volume And Weighted Average Price

The following table sets forth the volumes per day in MMBTUs that were outstanding as of December 31, 2012 under the Company's gas derivative contracts and the weighted average gas prices per MMBTU for those contracts:

	2013			2014			2015
Swap contracts:
Volume (MMBTU)	162,500			105,000			—
Price per MMBTU	$	5.13		$	4.03		$	—
Collar contracts:
Volume (MMBTU)	150,000			—			—
Price per MMBTU:
Ceiling	$	6.25		$	—		$	—
Floor	$	5.00		$	—		$	—
Collar contracts with short puts:
Volume (MMBTU)	—			25,000			225,000
Price per MMBTU:
Ceiling	$	—		$	4.70		$	5.09
Floor	$	—		$	4.00		$	4.00
Short put	$	—		$	3.00		$	3.00
Basis swap contracts:
Volume (MMBTU)	162,500			10,000			—
Price per MMBTU	$	(0.22	)	$	(0.19	)	$	—

Derivative Instruments

The following tables provide disclosure of the Company's derivative instruments for the years ended December 31, 2012 and 2011:

Fair Value of Derivative Instruments as of December 31, 2012
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	286,805	Derivatives - current	$	21,102
Commodity price derivatives	Derivatives - noncurrent	61,618		Derivatives - noncurrent	8,944
Interest rate derivatives	Derivatives - noncurrent	—		Derivatives - noncurrent	9,724
		$	348,423		$	39,770

Fair Value of Derivative Instruments as of December 31, 2011
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	248,809	Derivatives - current	$	68,735
Commodity price derivatives	Derivatives - noncurrent	257,368		Derivatives - noncurrent	47,689
Interest rate derivatives	Derivatives - current	—		Derivatives - current	15,654
		$	506,177		$	132,078

 _____________________

(a) Derivative assets and liabilities shown in the tables above are presented as gross assets and liabilities, without regard to master netting arrangements which are considered in the presentations of derivative assets and liabilities in the accompanying consolidated balance sheets.

Schedule of Derivative Obligations Under Terminated Hedge Arrangements [Table Text Block]

Derivatives in Cash Flow Hedging Relationships	Location of Gain/(Loss) Reclassified from AOCI into Earnings	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
		Year Ended December 31,
		2012			2011			2010
		(in thousands)
Interest rate derivatives	Interest expense	$	(1,699	)	$	(282	)	$	(1,698	)
Interest rate derivatives	Derivative gains, net	—			—			(2,465		)
Commodity price derivatives	Oil and gas revenue	(3,156		)	32,918			89,040
Total		$	(4,855	)	$	32,636		$	84,877

Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Earnings on Derivatives	Amount of Gain (Loss) Recognized in Earnings on Derivatives
		Year Ended December 31,
		2012			2011		2010
		(in thousands)
Interest rate derivatives	Derivative gains, net	$	(22,428	)	$	3,098	$	36,597
Commodity price derivatives	Derivative gains, net	352,679			389,654		414,302
Total		$	330,251		$	392,752	$	450,899

Schedule of Derivative Assets and Liabilities by Counterparty [Table Text Block]

The following table provides the Company's net derivative assets or liabilities by counterparty as of December 31, 2012:

	Net Assets (Liabilities)
	(in thousands)
Citibank, N.A.	$	72,218
JP Morgan Chase	48,606
Barclays Capital	36,736
BMO Financial Group	26,560
Credit Suisse	21,196
J. Aron & Company	20,138
BNP Paribas	19,420
Toronto Dominion	18,802
Merrill Lynch	17,136
Morgan Stanley	13,893
Den Norske Bank	7,487
Societe Generale	5,700
Wells Fargo Bank, N.A.	5,024
Macquarie Bank	380
Royal Bank of Canada	(97		)
Deutsche Bank	(327		)
Credit Agricole	(1,991		)
UBS	(2,228		)
Total	$	308,653

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Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2012

Exploratory Well Costs [Abstract]

Capitalized Exploratory Well And Project Activity

The following table reflects the Company's capitalized exploratory well and project activity during each of the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Beginning capitalized exploratory well costs	$	107,596		$	96,193		$	127,574
Additions to exploratory well costs pending the determination of proved reserves	926,084			524,313			238,905
Reclassification due to determination of proved reserves	(790,373		)	(480,716		)	(160,879		)
Disposition of assets sold	—			(28,938		)	(17,601		)
Exploratory well costs charged to exploration and abandonment expense	(30,637		)	(3,256		)	(91,806		)
Ending capitalized exploratory well costs	$	212,670		$	107,596		$	96,193

Capitalized Exploratory Costs And The Number Of Projects For Which Exploratory Costs Have Been Capitalized

The following table provides an aging, as of December 31, 2012, 2011 and 2010 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed:

	Year Ended December 31,
	2012		2011		2010
	(in thousands, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	190,678	$	107,596	$	70,635
More than one year	21,992		—		25,558
	$	212,670	$	107,596	$	96,193
Number of projects with exploratory well costs that have been suspended for a period greater than one year	1		—		3

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Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash flows from operating activities:
Net income (loss)	$ 242,822	$ 881,914	$ 645,995
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	810,191	578,268	499,856
Impairment of oil and gas properties	532,589	354,408	0
Exploration expenses, including dry holes	125,376	47,231	132,772
Hurricane activity, net	0	0	4,508
Deferred income taxes	85,459	188,579	259,763
(Gain) loss on disposition of assets, net	(58,087)	3,644	(19,074)
Accretion of discount on asset retirement obligations	9,887	8,256	7,945
Discontinued operations	(19,344)	(376,717)	77,158
Interest expense	35,563	31,483	30,472
Derivative related activity	68,604	(221,899)	(419,809)
Amortization of stock-based compensation	62,567	41,442	39,854
Amortization of deferred revenue	(42,069)	(44,951)	(90,216)
Other noncash items	(39,599)	6,725	25,102
Change in operating assets and liabilities
Accounts receivable, net	(28,206)	(47,331)	36,653
Income taxes receivable	(5,953)	29,406	(5,878)
Inventories	33,059	(137,401)	(26,281)
Prepaid expenses	1,447	(3,415)	(3,874)
Other current assets	14,291	1,957	(14,270)
Accounts payable	46,038	136,296	128,927
Interest payable	10,842	(1,768)	11,999
Income taxes payable	(9,580)	(7,623)	4,007
Other current liabilities	(38,320)	61,210	(40,586)
Net cash provided by operating activities	1,837,577	1,529,714	1,285,023
Cash flows from investing activities:
Proceeds from disposition of assets, net	95,564	819,044	313,780
Payments to Acquire Businesses, Net of Cash Acquired	(297,092)	0	0
Investment in unconsolidated subsidiary	0	(89,620)	(72,864)
Additions to oil and gas properties	(2,758,073)	(1,926,965)	(1,011,442)
Additions to other assets and other property and equipment, net	(296,809)	(363,246)	(184,330)
Net cash used in investing activities	(3,256,410)	(1,560,787)	(954,856)
Cash flows from financing activities:
Borrowings under long-term debt	1,776,618	196,616	292,342
Principal payments on long-term debt	(612,001)	(294,883)	(475,252)
Proceeds from issuance of common stock, net of issuance	0	484,160	0
Proceeds from issuance of partnership common units, net of issuance costs	0	122,976	0
Contributions from noncontrolling interests	0	0	1,151
Distributions to noncontrolling interests	(35,903)	(26,702)	(26,837)
Borrowings (payments) of other liabilities	(1,153)	(901)	(21,329)
Exercise of long-term incentive plan stock options and employee stock purchases	7,271	3,696	7,375
Purchase of treasury stock	(63,325)	(40,355)	(14,039)
Excess tax (costs) benefits from share-based payment arrangements	58,486	31,087	(153)
Payment of financing fees	(9,227)	(8,741)	(145)
Dividends paid	(10,021)	(9,556)	(9,488)
Net cash provided by (used in) financing activities	1,110,745	457,397	(246,375)
Net increase (decrease) in cash and cash equivalents	(308,088)	426,324	83,792
Cash and cash equivalents, beginning of period	537,484	111,160	27,368
Cash and cash equivalents, end of period	$ 229,396	$ 537,484	$ 111,160

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Components Of Long-Term Debt

Long-term debt, including the effects of net deferred fair value hedge losses and issuance discounts, consisted of the following components at December 31, 2012 and 2011:

	December 31,
	2012			2011
	(in thousands)
Outstanding debt principal balances:
Pioneer credit facility	$	474,000		$	—
Pioneer Southwest credit facility	126,000			32,000
5.875% senior notes due 2016	455,385			455,385
6.65% senior notes due 2017	485,100			485,100
6.875 % senior notes due 2018	449,500			449,500
7.500 % senior notes due 2020	450,000			450,000
3.95% senior notes due 2022	600,000			—
7.20% senior notes due 2028	250,000			250,000
2.875% convertible senior notes due 2038	479,907			479,930
	3,769,892			2,601,915
Issuance discounts	(47,309		)	(71,301		)
Net deferred fair value hedge losses	(1,390		)	(1,709		)
Total long-term debt	$	3,721,193		$	2,528,905

Principal Maturities Of Long-Term Debt

Principal maturities. Principal maturities of long-term debt at December 31, 2012, are as follows (in thousands):

2013	$	479,907
2014	$	—
2015	$	—
2016	$	455,385
2017	$	1,085,100
Thereafter	$	1,749,500

Interest Expense

Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Cash payments for interest	$	168,665		$	165,307		$	155,854
Accretion/amortization of discounts or premiums on loans	27,351			25,210			23,304
Accretion of discount on derivative obligations	—			—			521
Amortization of net deferred hedge losses (a)	2,018			573			517
Accretion of discount on postretirement benefit obligations	257			315			433
Amortization of capitalized loan fees	5,937			5,385			5,698
Net changes in accruals	10,842			(1,768		)	11,999
Interest incurred	215,070			195,022			198,326
Less capitalized interest	(10,848		)	(13,362		)	(15,242		)
Total interest expense	$	204,222		$	181,660		$	183,084

__________________

(a) Includes interest rate derivative hedges of $1.7 million, $282 thousand, and $1.7 million for the periods ended December 31, 2012, 2011 and 2010, respectively, that were reclassified from AOCI - Hedging into earnings upon expiration (see Note E).

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Commitments And Contingencies (Future Minimum Transportation Fees) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
2013	$ 264,213
2014	355,451
2015	404,890
2016	418,484
2017	306,894
Thereafter	$ 1,255,520

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Summary Of Open Tax Years, By Jurisdiction

The Company's earliest open years in its key jurisdictions are as follows:

United States	2011
Various U.S. states	2007
Tunisia	2006
South Africa	2006

Schedule Of Income Tax (Provision) Benefit Allocation

The Company's income tax provision and amounts separately allocated were attributable to the following items for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Income tax provision from continuing operations	$	(92,384	)	$	(197,644	)	$	(269,627	)
Income tax (provision) benefit from discontinued operations	(15,668		)	(257,950		)	270
Changes in goodwill – tax benefits related to stock-based compensation	—			40			453
Changes in stockholders' equity:
Net deferred hedge (loss) gain	(1,725		)	8,407			23,648
Excess tax benefit (provision) related to stock-based compensation	58,486			31,087			(153		)
Tax attributable to 2008 Pioneer Southwest initial public offering	(49,072		)	—			—
Tax attributable to 2009 and 2011 issuance of Pioneer Southwest common units	—			(23,711		)	—
Tax on Pioneer Southwest common units sold by the Company during 2011	—			(15,381		)	—

Income Tax (Provision) Benefit Attributable To Income From Continuing Operations

The Company's income provision attributable to income from continuing operations consisted of the following for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Current:
U.S. federal	$	(5,573	)	$	—		$	—
U.S. state	(1,352		)	(9,065		)	(9,864		)
	(6,925		)	(9,065		)	(9,864		)
Deferred:
U.S. federal	(78,790		)	(207,146		)	(263,063		)
U.S. state	(6,669		)	18,567			3,300
	(85,459		)	(188,579		)	(259,763		)
Income tax provision from continuing operations	$	(92,384	)	$	(197,644	)	$	(269,627	)

Schedule Of Effective Income Tax Rate Reconciliation

Reconciliations of the United States federal statutory tax rate to the Company's effective tax rate for income from continuing operations are as follows for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands, except percentages)
Income from continuing operations before income taxes	$	280,057		$	656,406		$	781,572
Less: Net income attributable to noncontrolling interests	(50,537		)	(47,425		)	(40,787		)
Income from continuing operations attributable to parent before income taxes	229,520			608,981			740,785
Federal statutory income tax rate	35		%	35		%	35		%
Provision for federal income taxes	(80,332		)	(213,143		)	(259,275		)
State income taxes (net of federal tax benefit)	(5,214		)	6,176			(4,267		)
Other	(6,838		)	9,323			(6,085		)
Income tax provision from continuing operations	$	(92,384	)	$	(197,644	)	$	(269,627	)
Effective income tax rate, excluding income attributable to the noncontrolling interest	40		%	32		%	36		%

Schedule Of Deferred Tax Assets And Deferred Tax Liabilities

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities related to continuing operations are as follows as of December 31, 2012 and 2011:

	December 31,
	2012			2011
	(in thousands)
Deferred tax assets:
Net operating loss carryforward (a)	$	498,441		$	—
Asset retirement obligations	69,214			47,860
Incentive plans	48,575			36,610
Other	104,714			46,218
Total deferred tax assets (b)	720,944			130,688
Deferred tax liabilities:
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes	(2,241,081		)	(1,692,317		)
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes	(255,943		)	(102,351		)
State taxes and other	(285,313		)	(191,621		)
Net deferred hedge gains	(165,504		)	(144,558		)
Total deferred tax liabilities	(2,947,841		)	(2,130,847		)
Net deferred tax liability	$	(2,226,897	)	$	(2,000,159	)
Reflected in accompanying consolidated balance sheets as:
Current deferred income tax liability	$	(86,481	)	$	(57,713	)
Noncurrent deferred income tax liability	(2,140,416		)	(1,942,446		)
Total	$	(2,226,897	)	$	(2,000,159	)

____________________

(a)    All net operating loss carryforwards as of December 31, 2012 expire in 2032.

(b)     The Company had no deferred tax valuation allowances at December 31, 2012 and 2011.

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Disclosures About Fair Value Measurements (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended	3 Months Ended
	Dec. 31, 2012 Rate	Dec. 31, 2012 Barnett Shale Field [Member]
discount rate used in impairment calculation	10.00%
Impairment of Long-Lived Assets Held-for-use		$ 71.8

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Incentive Plans (Schedule Of Restricted Stock Award Activity) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares/Units, Outstanding at beginning of year	1,857,612
Number of Shares granted	912,543
Forfeitures, number of shares	(28,011)
Awards vested	(1,229,382)
Number of Shares/Units, Outstanding at end of year	1,512,762	1,857,612
Weighted Average Grant-Date Fair Value, Outstanding at beginning of year	$ 39.95
Weighted Average Grant-Date Fair Value, Shares granted	$ 113.02	$ 97.52	$ 48.32
Weighted Average Grant-Date Fair Value, Shares forfeited	$ 101.91
Weighted Average Grant-Date Fair Value, Shares vested	$ 23.75
Weighted Average Grant-Date Fair Value, Outstanding at end of year	$ 96.22	$ 39.95
Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Liability Awards Unvested Number	405,916	322,925
ShareBasedCompensationArrangementByShareBasedPaymentAwardLiabilityAwardsGrantsInPeriod	240,486
Share Based Compensation Arrangement By Share Based Payment Award Liability Awards Forfeitures In Period	(29,060)
Share Based Compensation Arrangement By Share Based Payment Award Liability Awards Vested In Period	(128,435)

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 229,396	$ 537,484
Accounts receivable:
Trade, net of allowance for doubtful accounts of $848 and $806 as of December 31, 2012 and December 31, 2011, respectively	316,854	275,991
Due from affiliates	3,299	7,822
Income taxes receivable	7,447	3
Inventories	197,056	241,609
Prepaid expenses	13,438	14,263
Discontinued operations held for sale	0	73,349
Other current assets:
Derivatives	279,119	238,835
Other	3,746	12,936
Total current assets	1,050,355	1,402,292
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	14,259,708	12,013,805
Unproved properties	231,555	235,527
Accumulated depletion, depreciation and amortization	(4,412,913)	(3,648,465)
Total property, plant and equipment	10,078,350	8,600,867
Goodwill	298,142	298,142
Other property and equipment, net	1,217,694	573,075
Other assets:
Investment in unconsolidated affiliate	204,129	169,532
Derivatives	55,257	243,240
Other, net of allowance for doubtful accounts of $629 and $340 as of December 31, 2012 and December 31, 2011, respectively	165,103	160,008
Assets, Total	13,069,030	11,447,156
Accounts payable:
Trade	729,942	647,455
Due to affiliates	96,935	68,756
Interest payable	68,083	57,240
Income taxes payable	208	9,788
Deferred income taxes	86,481	57,713
Liabilities of Disposal Group, Including Discontinued Operation	0	75,901
Other current liabilities:
Derivatives	13,416	74,415
Deferred revenue	0	42,069
Other	39,725	36,174
Total current liabilities	1,034,790	1,069,511
Long-term debt	3,721,193	2,528,905
Derivatives	12,307	33,561
Deferred income taxes	2,140,416	1,942,446
Other liabilities	293,016	221,595
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 133,121,092 and 126,212,256 shares issued at December 31, 2011 and 2010, respectively	1,350	1,331
Additional paid-in capital	3,683,934	3,613,808
Treasury stock, at cost: 11,264,936 and 10,903,743 shares at December 31, 2011 and 2010, respectively	(510,570)	(458,281)
Retained earnings	2,514,640	2,335,066
Accumulated other comprehensive income (loss) - net deferred hedge gains (losses), net of tax	0	(3,130)
Total stockholders' equity attributable to common stockholders	5,689,354	5,488,794
Noncontrolling interest in consolidating subsidiaries	177,954	162,344
Total stockholders' equity	5,867,308	5,651,138
Liabilities and Stockholders' Equity, Total	$ 13,069,030	$ 11,447,156

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Summary of Significant Accounting Policies (Schedule of Other Property Plant and Equipment) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 1,217,694,000	$ 573,075,000
Accumulated depreciation property, plant and equipment, other assets	395,900,000	297,600,000
Proved and Unproved Sand Leaseholds [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	457,033,000	0
Wells and Related Equipment and Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	385,887,000	329,157,000
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	259,629,000	160,795,000
Transportation Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	44,928,000	28,108,000
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	43,614,000	34,567,000
Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 26,603,000	$ 20,448,000

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Net Income (Loss) Per Share Attributable To Common Stockholders (Reconciliation Of Basic To Diluted Weighted Average Common Shares Outstanding) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Weighted Average Number of Shares Outstanding Reconciliation [Line Items]
Basic	122,966,000	116,904,000	115,062,000
Dilutive common stock options	183,000	190,000	212,000
Contingently issuable - performance shares	180,000	424,000	646,000
Convertible notes dilution	2,991,000	1,697,000	410,000
Diluted	126,320,000	119,215,000	116,330,000
Antidilutive securities excluded from computation of earnings per share, amount	129,918
Convertible Senior Notes issued	$ 3,769,892	$ 2,601,915

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Consolidated Statements Of Stockholders' 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]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]	Pioneer Southwest [Member]	Pioneer Southwest [Member] Additional Paid-In Capital [Member]	Pioneer Southwest [Member] Noncontrolling Interests [Member]
Beginning Balance at Dec. 31, 2009	$ 3,643,031	$ 1,252	$ 2,981,450	$ (415,211)	$ 917,688	$ 51,009	$ 106,843
Beginning Balance, shares at Dec. 31, 2009	114,375,000
Sale of Pioneer Southwest common units, net of tax	0
Issuance of Pioneer Southwest common units, net of tax	0
Dividends declared ($0.08 per share)	(9,455)				(9,455)
Exercise of long-term incentive plan stock options and employee stock purchases, shares	266,000
Exercise of long-term incentive plan stock options and employee stock purchases	7,375	1	2,577	7,811	(3,014)
Purchase of treasury stock	(14,039)			(13,835)			(204)
Purchase of treasury stock, shares	(278,000)
Tax benefits related to stock-based compensation	(153)		(153)
Compensation costs:
Vested compensation awards, net	1	9	(8)
Vested compensation awards, net, shares	946,000
Allocated Share-based Compensation Expense	40,185		38,902				1,283
Cash contributions from noncontrolling interests	1,151						1,151
Cash distributions to noncontrolling interests	(26,837)						(26,837)
Net income (loss)	645,995				605,208		40,787
Deferred hedging activity, net of tax:
Net hedge gains included in continuing operations	(61,229)					(43,648)	(17,581)
Ending Balance at Dec. 31, 2010	4,226,025	1,262	3,022,768	(421,235)	1,510,427	7,361	105,442
Ending Balance, shares at Dec. 31, 2010	115,309,000
Common stock, issued	5,500,000
Sale of Pioneer Southwest common units, net of tax								35,091	26,915	8,176
Issuance of Pioneer Southwest common units, net of tax								48,792	8,104	40,688
Dividends declared ($0.08 per share)	(9,498)				(9,498)
Exercise of long-term incentive plan stock options and employee stock purchases, shares	76,000
Exercise of long-term incentive plan stock options and employee stock purchases	3,696		951	3,097	(352)
Purchase of treasury stock	(40,355)			(40,157)			(198)
Purchase of treasury stock, shares	(439,000)
Conversion of 2.875% senior convertible notes	(6)		(20)	14
Tax benefits related to stock-based compensation	31,087		31,087
Disposition of subsidiary	(510)		(510)
Compensation costs:
Vested compensation awards, net		14	(14)
Vested compensation awards, net, shares	1,410,000
Allocated Share-based Compensation Expense	41,673		40,422				1,251
Issuance of Common Stock	484,160	55	484,105
Cash distributions to noncontrolling interests	(26,702)						(26,702)
Net income (loss)	881,914				834,489		47,425
Deferred hedging activity, net of tax:
Net hedge gains included in continuing operations	(24,229)					(10,491)	(13,738)
Ending Balance at Dec. 31, 2011	5,651,138	1,331	3,613,808	(458,281)	2,335,066	(3,130)	162,344
Ending Balance, shares at Dec. 31, 2011	121,856,000
Sale of Pioneer Southwest common units, net of tax	0
Issuance of Pioneer Southwest common units, net of tax	0
Dividends declared ($0.08 per share)	(9,989)				(9,989)
Exercise of long-term incentive plan stock options and employee stock purchases, shares	195,000
Exercise of long-term incentive plan stock options and employee stock purchases	7,271		(849)	10,842	(2,722)
Purchase of treasury stock	(63,325)			(63,136)			(189)
Purchase of treasury stock, shares	(542,000)
Conversion of 2.875% senior convertible notes	0		(5)	5
Tax benefits related to stock-based compensation	58,486		58,486
Subsidiary or Equity Method Investee, Deferred Income Tax Provision on Gain (Loss) Recognized, Amount	(49,072)								(49,072)
Compensation costs:
Vested compensation awards, net	0	19	(19)
Vested compensation awards, net, shares	1,847,000
Allocated Share-based Compensation Expense	62,750		61,585				1,165
Cash distributions to noncontrolling interests	(35,903)						(35,903)
Net income (loss)	242,822				192,285		50,537
Deferred hedging activity, net of tax:
Net hedge gains included in continuing operations	3,130					3,130
Ending Balance at Dec. 31, 2012	$ 5,867,308	$ 1,350	$ 3,683,934	$ (510,570)	$ 2,514,640	$ 0	$ 177,954
Ending Balance, shares at Dec. 31, 2012	123,356,000

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Income Taxes (Schedule Of Deferred Tax Assets And Deferred Tax Liabilities) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]
Net operating loss carryforward	$ 498,441	$ 0
Asset retirement obligations	69,214	47,860
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	48,575	36,610
Other	104,714	46,218
Total deferred tax assets	720,944	130,688
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes	(2,241,081)	1,692,317
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes	(255,943)	(102,351)
State taxes and other	(285,313)	(191,621)
Net deferred hedge gains	(165,504)	(144,558)
Total deferred tax liabilities	(2,947,841)	(2,130,847)
Net deferred tax liability	(2,226,897)	(2,000,159)
Current deferred income tax liability	(86,481)	(57,713)
Non-current deferred income tax liability	$ (2,140,416)	$ (1,942,446)

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Derivative Financial Instruments (Gas Volume And Weighted Average Price) (Details)	Dec. 31, 2012 MMBTU
Gas contracts, in MMBTU [Member] | 2013 - Swap Contracts [Member]
Derivative [Line Items]
Volume (MMBtu)	162,500
Gas contracts, in MMBTU [Member] | 2013 - Collar Contracts [Member]
Derivative [Line Items]
Volume (MMBtu)	150,000
Gas contracts, in MMBTU [Member] | Two Thousand Thirteen Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Volume (MMBtu)	0
Gas contracts, in MMBTU [Member] | Two Thousand And Thirteen Basis Swap Contracts [Member]
Derivative [Line Items]
Volume (MMBtu)	162,500
Gas contracts, in MMBTU [Member] | Two Thousand Fourteen Swap Contracts [Member]
Derivative [Line Items]
Volume (MMBtu)	105,000
Gas contracts, in MMBTU [Member] | Two Thousand Fifteen Swap Contracts [Member]
Derivative [Line Items]
Volume (MMBtu)	0
Gas contracts, in MMBTU [Member] | 2014 - Collar Contracts [Member]
Derivative [Line Items]
Volume (MMBtu)	0
Gas contracts, in MMBTU [Member] | Two Thousand Fourteen Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Volume (MMBtu)	25,000
Gas contracts, in MMBTU [Member] | Two Thousand Fourteen Basis Swap Contracts [Member]
Derivative [Line Items]
Volume (MMBtu)	10,000
Gas contracts, in MMBTU [Member] | Two Thousand Fifteen Basis Swap Contracts [Member]
Derivative [Line Items]
Volume (MMBtu)	0
Gas contracts, in MMBTU [Member] | 2015 - Collar Contracts [Member]
Derivative [Line Items]
Volume (MMBtu)	0
Gas contracts, in MMBTU [Member] | Two Thousand Fifteen Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Volume (MMBtu)	225,000
Gas contracts, price per MMBTU [Member] | 2013 - Swap Contracts [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	5.13
Gas contracts, price per MMBTU [Member] | 2013 - Collar Contracts [Member]
Derivative [Line Items]
Derivative, Average Cap Price	6.25
Derivative, Average Floor Price	5.00
Gas contracts, price per MMBTU [Member] | Two Thousand Thirteen Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Derivative, Average Cap Price	0.00
Derivative, Average Floor Price	0.00
Gas contracts, price per MMBTU [Member] | Two Thousand Thirteen Collar Contracts With Short Puts [Member] | Short Put [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	0.00
Gas contracts, price per MMBTU [Member] | Two Thousand And Thirteen Basis Swap Contracts [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.22)
Gas contracts, price per MMBTU [Member] | Two Thousand Fourteen Swap Contracts [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	4.03
Gas contracts, price per MMBTU [Member] | Two Thousand Fifteen Swap Contracts [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	0.00
Gas contracts, price per MMBTU [Member] | 2014 - Collar Contracts [Member]
Derivative [Line Items]
Derivative, Average Cap Price	0.00
Derivative, Average Floor Price	0.00
Gas contracts, price per MMBTU [Member] | Two Thousand Fourteen Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Derivative, Average Cap Price	4.70
Derivative, Average Floor Price	4.00
Gas contracts, price per MMBTU [Member] | Two Thousand Fourteen Collar Contracts With Short Puts [Member] | Short Put [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	3.00
Gas contracts, price per MMBTU [Member] | Two Thousand Fourteen Basis Swap Contracts [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.19)
Gas contracts, price per MMBTU [Member] | Two Thousand Fifteen Basis Swap Contracts [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	0.00
Gas contracts, price per MMBTU [Member] | 2015 - Collar Contracts [Member]
Derivative [Line Items]
Derivative, Average Cap Price	0.00
Derivative, Average Floor Price	0.00
Gas contracts, price per MMBTU [Member] | Two Thousand Fifteen Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Derivative, Average Cap Price	5.09
Derivative, Average Floor Price	4.00
Gas contracts, price per MMBTU [Member] | Two Thousand Fifteen Collar Contracts With Short Puts [Member] | Short Put [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Price Per Unit	3.00

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Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Future Minimum Lease Commitments

Future minimum lease commitments under noncancellable operating leases at December 31, 2012 are as follows (in thousands):

2013	$	24,096
2014	$	17,434
2015	$	15,500
2016	$	14,202
2017	$	14,253
Thereafter	$	36,967

Future Minimum Gathering, Processing And Transportation Fees

Future minimum gathering, processing, transportation and fractionation commitments at December 31, 2012 are as follows (in thousands):

2013	$	264,213
2014	$	355,451
2015	$	404,890
2016	$	418,484
2017	$	306,894
Thereafter	$	1,255,520

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Long-Term Debt (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended					12 Months Ended			12 Months Ended			1 Months Ended	12 Months Ended					12 Months Ended		12 Months Ended					1 Months Ended		12 Months Ended
	Feb. 13, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Pioneer Southwest Credit Facility [Member] Rate	Dec. 31, 2011 Pioneer Southwest Credit Facility [Member]	Dec. 31, 2012 Pioneer Credit Facility [Member] Rate	Sep. 30, 2012 Pioneer Credit Facility [Member]	Dec. 31, 2011 Pioneer Credit Facility [Member]	Dec. 31, 2012 Swing Line Loans [Member] Pioneer Credit Facility [Member]	Dec. 31, 2012 7.500% Senior Notes Due 2020 [Member] Rate	Dec. 31, 2011 7.500% Senior Notes Due 2020 [Member]	Feb. 13, 2013 2.875% Convertible Senior Notes Due 2038 [Member] Rate	Dec. 31, 2012 2.875% Convertible Senior Notes Due 2038 [Member] Rate	Dec. 31, 2011 2.875% Convertible Senior Notes Due 2038 [Member]	Dec. 31, 2010 2.875% Convertible Senior Notes Due 2038 [Member]	Jan. 15, 2013 2.875% Convertible Senior Notes Due 2038 [Member] Rate	Jan. 31, 2008 2.875% Convertible Senior Notes Due 2038 [Member]	Dec. 31, 2012 3.95% Senior Notes Due 2022 [Member] Rate	Dec. 31, 2011 3.95% Senior Notes Due 2022 [Member]	Dec. 31, 2012 If Converted [Member] 2.875% Convertible Senior Notes Due 2038 [Member]	Dec. 31, 2012 Company's Oil And Gas Properties To Total Debt [Member] Pioneer Southwest Credit Facility [Member]	Dec. 31, 2012 Total Debt To Book Capitalization [Member] Pioneer Credit Facility [Member]	Dec. 31, 2012 Maximum Leverage Ratio [Member] Pioneer Southwest Credit Facility [Member]	Dec. 31, 2012 Noncash [Member] If Converted [Member] 2.875% Convertible Senior Notes Due 2038 [Member]	Mar. 31, 2012 Revolving Credit Facility [Member]	May 31, 2008 Expired Credit Facility [Member]	Dec. 31, 2012 Eurodollar Rate Loan [Member] Revolving Credit Facility [Member]	Dec. 31, 2012 Interest Rate Option1 [Member] Base Rate Committed Loan [Member] Revolving Credit Facility [Member]	Dec. 31, 2012 Interest Rate Option2 [Member] Base Rate Committed Loan [Member] Revolving Credit Facility [Member]	Dec. 31, 2012 Interest Rate Option3 [Member] Base Rate Committed Loan [Member] Revolving Credit Facility [Member]
Debt Instrument, Basis Spread on Variable Rate																														1.00%
Debt Instrument, Description of Variable Rate Basis																												LIBOR	Federal Funds Rate	one-month Eurodollar rate	Bank of America prime rate
Borrowings under long-term debt		$ 1,776,618,000	$ 196,616,000	$ 292,342,000															$ 591,500,000
Line of credit facility, maximum borrowing capacity					300,000,000		1,500,000,000	1,250,000,000
Line of Credit Facility, Agreement Term, Duration																										5 years	5 years
Outstanding borrowings under the Credit Facility					126,000,000		474,000,000			150,000,000
Outstanding borrowings under the Credit Facility					126,000,000	32,000,000	474,000,000		0
Undrawn letters of credit							2,200,000
Unused borrowing capacity					134,700,000		1,000,000,000
Commitment fee percentage					0.275%
Debt instrument covenant description																						1.75	.60	3.5
Alternate base rate spread					0.625%		0.50%
Applicable margin					1.625%		1.50%
Letters of credit outstanding under the Credit Facility, interest percentage							0.125%
Unused portion, fee percentage							0.25%
Value of shares received for conversion of debt																									358,800,000
Stock price in excess of principal amount of note interest rate trigger														120.00%
Shares received for conversion of debt													707	112	340						3,400,000
Cash received from note holders																					479,900,000
Federal fund rate					0.50%		0.50%
Issuance of senior notes											450,000,000	450,000,000							600,000,000	0
Senior Notes, interest rate, percentage											7.50%		2.375%	2.875%			2.375%		3.95%
Senior notes offering discounts and cost														753,000	18,500,000				8,500,000
Convertible debt														479,907,000	479,930,000			500,000,000
Additional Shares On Debt Instrument Convertible Carrying Amount Of The Equity Component		8.9532
Senior convertible notes, outstanding		3,769,892,000	2,601,915,000
Initial base conversion price														$ 72.60
Base conversion rate, shares per thousand dollars														0
Common shares principal amount of convertible notes		1,000												1,000
Principal amount of notes put for conversion													8,000
Cash paid for convertible notes put													8,000
Base conversion price percentage														130.00%
Conversion rate of notes to common stock														97.00%
Unamortized discount														753,000	18,500,000				8,500,000
Debt instrument, effective interest rate, percentage														6.75%
Net carrying value														479,200,000	461,500,000
Interest expense relating to the contractual interest coupon and unamortized discount														33,500,000	32,300,000	31,100,000
Additional Paid-in Capital as the equity component														49,500,000
Principal amount of notes tendered for conversion	240,600,000												240,600,000	111,000	70,000
Cash Paid To Conversion Of Convertible Senior Notes													$ 88,000	$ 23,000	$ 71,000

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Other Expense

12 Months Ended

Dec. 31, 2012

Other Expense [Abstract]

Other Expense

NOTE N.    Other Expense

The following table provides the components of the Company's other expense during the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Transportation commitment charge (a)	$	37,144	$	23,248	$	1,589
Above market and idle drilling and well service equipment rates (b)	33,211		20,132		50,581
Other	18,297		12,603		9,924
Terminated drilling rig contract charges (c)	15,747		—		—
Inventory impairment (d)	6,174		3,126		10,729
Premier Silica acquisition costs	2,337		—		—
Contingency and environmental accrual adjustments	478		4,057		5,581
Total other expense	$	113,388	$	63,166	$	78,404

 ____________________

(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 were above market rates and idle drilling rig and fracture stimulation fleet fees, neither of which were chargeable to joint operations.

(c) Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.

(d) Represents lower of cost or market impairment charges on excess materials and supplies inventories.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2012

Related Party Transactions [Abstract]

Schedule Of Related Party Transactions

The related party transactions with affiliated partnerships are summarized below for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Receipt of lease operating and supervision charges in accordance with standard industry operating agreements	$	2,437	$	2,104	$	2,184
Reimbursement of general and administrative expenses	$	342	$	313	$	344

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Net Income (Loss) Per Share Attributable To Common Stockholders

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Net Income (Loss) Per Share Attributable To Common Stockholders

NOTE P.    Net Income Per Share Attributable To Common Stockholders

In the calculation of basic net income per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company's participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. The computation of diluted net income per share attributable to common stockholders reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. 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 not be dilutive to net loss per share and conversion into common stock is assumed not to occur. Diluted net income per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. For each of the three years in the period ended December 31, 2012, the two-class method of calculating the Company's diluted net income per share was more dilutive than the treasury stock method.

The Company's basic net income per share attributable to common stockholders is computed as (i) net income attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income per share attributable to common stockholders is computed as (i) basic net income attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding (excluding shares held in treasury).

The following table is a reconciliation of the Company's net income attributable to common stockholders to basic net income attributable to common stockholders and to diluted net income attributable to common stockholders for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31, 2012
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	137,136		$	55,149		$	192,285
Participating basic earnings (a)	(2,160		)	(869		)	(3,029		)
Basic income attributable to common stockholders	134,976			54,280			189,256
Reallocation of participating earnings (a)	115			46			161
Diluted income attributable to common stockholders	$	135,091		$	54,326		$	189,417

	Year Ended December 31, 2011
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	411,337		$	423,152		$	834,489
Participating basic earnings (a)	(7,482		)	(7,696		)	(15,178		)
Basic income attributable to common stockholders	403,855			415,456			819,311
Reallocation of participating earnings (a)	190			195			385
Diluted income attributable to common stockholders	$	404,045		$	415,651		$	819,696

	Year Ended December 31, 2010
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	471,158		$	134,050		$	605,208
Participating basic earnings (a)	(10,818		)	(3,078		)	(13,896		)
Basic net income attributable to common stockholders	460,340			130,972			591,312
Reallocation of participating earnings (a)	140			40			180
Diluted income attributable to common stockholders	$	460,480		$	131,012		$	591,492

 ______________________

(a) Unvested restricted stock awards and Pioneer Southwest phantom unit awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity owners of the Company or Pioneer Southwest, as applicable. Participating share- and unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually obligated to do so.

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012	2011	2010
	(in thousands)
Weighted average common shares outstanding:
Basic	122,966	116,904	115,062
Dilutive common stock options (a)	183	190	212
Contingently issuable—performance shares	180	424	646
Convertible Senior Notes dilution (b)	2,991	1,697	410
Diluted	126,320	119,215	116,330

______________________

(a) Options to purchase 129,918 shares of the Company's common stock were excluded from the diluted income per share calculations for the year ended December 31, 2012 because they would have been anti-dilutive to the calculation.

(b) Weighted average common shares outstanding have been increased to reflect the dilutive effect that would have resulted if the Convertible Senior Notes had qualified for and been converted during the years ended December 31, 2012, 2011 and 2010, respectively.

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Long-Term Debt (Interest Expenses) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash payments for interest	$ 168,665	$ 165,307	$ 155,854
Accretion/amortization of discounts or premiums on loans	27,351	25,210	23,304
Amortization of net deferred hedge losses (see Note I)	2,018	573	517
Accretion of discount on postretirement benefit obligations	257	315	433
Amortization of capitalized loan fees	5,937	5,385	5,698
Net changes in accruals	10,842	(1,768)	11,999
Interest incurred	215,070	195,022	198,326
Less capitalized interest	(10,848)	(13,362)	(15,242)
Interest expense	204,222	181,660	183,084
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, before Tax	4,855	(32,636)	(84,877)
Derivative Obligations [Member]
Accretion of discount on derivative obligations	0	0	521
Interest Rate Derivatives [Member]
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, before Tax	$ (1,700)	$ (282)	$ (1,700)

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Consolidated Statements Of Stockholders' Equity (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statement of Stockholders' Equity [Abstract]
Dividends declared, per share	$ 0.08	$ 0.08	$ 0.08

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Statement of Financial Position [Abstract]
Trade, allowance for doubtful accounts	$ 848	$ 806
Other, allowance for doubtful accounts	$ 629	$ 340
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	134,966,740	133,121,092
Treasury stock, shares	11,611,093	11,264,936

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

NOTE I.    Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. The following table summarizes the Company's asset retirement obligation activity during the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Beginning asset retirement obligations	$	136,742		$	152,291		$	166,434
Liabilities assumed in acquisitions	10,498			6			6
New wells placed on production	9,593			9,233			5,218
Changes in estimates (a)	51,536			7,490			24,075
Liabilities reclassified to discontinued operations held for sale	—			(29,892		)	(5,779		)
Disposition of wells	(2,536		)	(448		)	(30,693		)
Liabilities settled	(18,066		)	(12,880		)	(17,838		)
Accretion of discount on continuing operations	9,887			8,256			7,945
Accretion of discount from integrated services (b)	100			—			—
Accretion of discount on discontinued operations	—			2,686			2,923
Ending asset retirement obligations	$	197,754		$	136,742		$	152,291

 _____________________

(a) The changes in the 2012, 2011 and 2010 estimates are primarily due to increases in abandonment cost estimates based in part on recent actual costs incurred and declines in credit-adjusted risk-free discount rates used to value increases in asset retirement obligations. The increase in the 2012 estimate was also impacted by declines in oil, NGL and gas prices used to calculate proved reserves, which had the effect of shortening the economic life of certain wells and increasing what would otherwise have been the present value of future retirement obligations. The increases in 2011 and 2010 estimates were partially offset by higher oil and NGL prices, which had the effect of lengthening the economic life of certain wells and decreasing what would otherwise have been the present value of future retirement obligations. The increase in commodity prices was less substantial in 2011 as compared to 2010.

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

As of December 31, 2012 and 2011, the current portions of the Company's asset retirement obligations were $13.3 million$14.2 million, respectively.

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Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 Rate	Dec. 31, 2011 Rate	Dec. 31, 2010 Rate
Income Tax Disclosure [Abstract]
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	$ 280,057	$ 656,406	$ 781,572
Net Income (Loss) Attributable to Noncontrolling Interest	(50,537)	(47,425)	(40,787)
Income loss from continuing operations before tax	229,520	608,981	740,785
U.S. federal statutory tax rate	35.00%	35.00%	35.00%
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	(80,332)	(213,143)	(259,275)
Income Tax Reconciliation, State and Local Income Taxes	(5,214)	6,176	(4,267)
Income Tax Reconciliation, Other Adjustments	(6,838)	9,323	(6,085)
Income Tax Expense (Benefit)	$ (92,384)	$ (197,644)	$ (269,627)
Effective Income Tax Rate, Continuing Operations	40.00%	32.00%	36.00%

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Income Taxes (Schedule Of Income Tax (Provision) Benefit Allocation) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Disclosure [Abstract]
Income tax benefit (provision)	$ (92,384)	$ (197,644)	$ (269,627)
Income tax from discontinued operations	(15,668)	(257,950)	270
Changes in goodwill - tax benefits related to stock-based compensation	0	(40)	(453)
Net deferred hedge gains	(1,725)	8,407	23,648
Tax benefits related to stock-based compensation	58,486	31,087	(153)
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Issuance of Equity by Subsidiary to Noncontrolling Interests, Tax Impact	(49,072)	0	0
Tax attributable to issuance of common units	0	(23,711)	0
Tax on Pioneer Southwest common units sold by the Company on December 12, 2011	$ 0	$ (15,381)	$ 0

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Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2012	Feb. 08, 2013	Jun. 30, 2012
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Trading Symbol	PXD
Entity Registrant Name	Pioneer Natural Resources Company
Entity Central Index Key	0001038357
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		123,360,341
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 10,710,145,448

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

NOTE J.    Commitments and Contingencies

Severance agreements. The Company has entered into severance and change in control agreements with its officers and certain key employees. The current annual salaries for the officers and key employees covered under such agreements total $43.9 million.

Indemnifications. The Company has agreed to indemnify its directors and certain of its officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.

Legal actions. 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 other 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.

Obligations following divestitures. In April 2006, the Company provided the purchaser of its Argentine assets certain indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject to defined limitations, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The Company has also retained certain liabilities and indemnified buyers for certain matters in connection with other divestitures, including the sale of its Canadian assets in 2007, the sale of Pioneer Tunisia in February 2011 and the sale of Pioneer South Africa in August 2012, and in connection with sales of joint interests. The Company does not believe that these obligations are probable of having a material impact on its liquidity, financial position or future results of operations.

Drilling commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future. The Company also enters into agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which the well is drilled or rig services are performed.

Lease agreements. The Company leases equipment and office facilities under operating leases. Rent expense for the years ended December 31, 2012, 2011 and 2010 were $48.0 million, $35.4 million and $38.3 million, respectively. These payments include $67 thousand, $513 thousand and $7.2 million associated with discontinued operations for the years ended December 31, 2012, 2011 and 2010, respectively, which are included in income from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

Future minimum lease commitments under noncancellable operating leases at December 31, 2012 are as follows (in thousands):

2013	$	24,096
2014	$	17,434
2015	$	15,500
2016	$	14,202
2017	$	14,253
Thereafter	$	36,967

Gathering, processing and transportation agreements. The Company from time to time enters into, and as of December 31, 2012 is a party to, contractual commitments with midstream service companies and pipeline carriers for the future gathering, processing, transportation and fractionation. These commitments are normal and customary for the Company's business activities. Future minimum gathering, processing, transportation and fractionation commitments at December 31, 2012 are as follows (in thousands):

2013	$	264,213
2014	$	355,451
2015	$	404,890
2016	$	418,484
2017	$	306,894
Thereafter	$	1,255,520

Certain future minimum gathering, processing, transportation and fractionation fees are based upon rates and tariffs subject to change over the lives of the commitments.

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Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Asset Retirement Obligation [Abstract]
AssetRetirementObligationLiabilitiesAcquiredInBusinessCombination	$ 10,498,000	$ 6,000	$ 6,000
Liabilities incurred	9,593,000	9,233,000	5,218,000
Changes in estimates	51,536,000	7,490,000	24,075,000
Liabilities reclassified to discontinued operations held for sale	0	(29,892,000)	(5,779,000)
Disposition of wells	(2,536,000)	(448,000)	(30,693,000)
Liabilities settled	(18,066,000)	(12,880,000)	(17,838,000)
Accretion of discount on continuing operations	9,887,000	8,256,000	7,945,000
Asset Retirement Obligation Accretion Expense Integrated Services	100,000	0	0
Accretion of discount on discontinued operations	0	2,686,000	2,923,000
Ending asset retirement obligations	197,754,000	136,742,000	152,291,000	166,434,000
Asset retirement obligations, current portion	$ 13,300,000	$ 14,200,000

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Income Taxes (Summary Of Open Tax Years, By Jurisdiction) (Details)	12 Months Ended
	Dec. 31, 2012
United States [Member]
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2011
Various U.S. States [Member]
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2007
Tunisia [Member]
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2006
South Africa [Member]
Income Tax Contingency [Line Items]
Open tax years, by jurisdiction	2006

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Consolidated Statements Of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues and other income:
Oil and gas	$ 2,811,660	$ 2,294,063	$ 1,718,297
Interest and other	28,310	66,880	56,972
Derivative gains (losses), net	330,251	392,752	448,434
Gain (loss) on disposition of assets, net	58,087	(3,644)	19,074
Hurricane activity, net	0	1,454	138,918
Revenues and other income	3,228,308	2,751,505	2,381,695
Costs and expenses:
Oil and gas production	635,644	447,142	364,764
Production and ad valorem taxes	187,757	147,664	112,141
Depletion, depreciation and amortization	810,191	578,268	499,856
Impairment of oil and gas properties	532,589	354,408	0
Exploration and abandonments	206,291	121,320	189,597
General and administrative	248,282	193,215	164,332
Accretion of discount on asset retirement obligations	9,887	8,256	7,945
Interest expense	204,222	181,660	183,084
Other	113,388	63,166	78,404
Costs and expenses, Total	2,948,251	2,095,099	1,600,123
Income (loss) from continuing operations before income taxes	280,057	656,406	781,572
Income tax benefit (provision)	(92,384)	(197,644)	(269,627)
Income (loss) from continuing operations	187,673	458,762	511,945
Income from discontinued operations, net of tax	55,149	423,152	134,050
Net income (loss)	242,822	881,914	645,995
Net income attributable to noncontrolling interests	(50,537)	(47,425)	(40,787)
Net income (loss) attributable to common stockholders	192,285	834,489	605,208
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$ 1.10	$ 3.45	$ 4.00
Income from discontinued operations attributable to common stockholders	$ 0.44	$ 3.56	$ 1.14
Net income (loss) attributable to common stockholders	$ 1.54	$ 7.01	$ 5.14
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$ 1.07	$ 3.39	$ 3.96
Income from discontinued operations attributable to common stockholders	$ 0.43	$ 3.49	$ 1.12
Net income (loss) attributable to common stockholders	$ 1.50	$ 6.88	$ 5.08
Weighted average shares outstanding:
Basic	122,966	116,904	115,062
Diluted	126,320	119,215	116,330
Amounts attributable to common stockholders:
Income (loss) from continuing operations, net of tax	137,136	411,337	471,158
Discontinued operations, net of tax	55,149	423,152	134,050
Net income (loss)	$ 192,285	$ 834,489	$ 605,208

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Disclosures About Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Disclosures About Fair Value Measurements

NOTE D.    Fair Value Measurements

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

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

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

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

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

The following tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2012 and 2011 for each of the fair value hierarchy levels:

	Fair Value Measurements 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 December 31, 2012
	(in thousands)
Assets:
Trading securities	$	124	$	154	$	—	$	278
Commodity derivatives	—		334,376		—		334,376
Deferred compensation plan assets	49,685		—		—		49,685
Total assets	49,809		334,530		—		384,339
Liabilities:
Commodity derivatives	—		15,999		—		15,999
Interest rate derivatives	—		9,724		—		9,724
Total liabilities	—		25,723		—		25,723
Total recurring fair value measurements	$	49,809	$	308,807	$	—	$	358,616
	Fair Value Measurements 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 December 31, 2011
	(in thousands)
Assets:
Trading securities	$	257	$	168	$	—	$	425
Commodity derivatives	—		482,075		—		482,075
Deferred compensation plan assets	39,904		—		—		39,904
Total assets	40,161		482,243		—		522,404
Liabilities:
Commodity derivatives	—		92,322		—		92,322
Interest rate derivatives	—		15,654		—		15,654
Total liabilities	—		107,976		—		107,976
Total recurring fair value measurements	$	40,161	$	374,267	$	—	$	414,428

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 December 31, 2012 and 2011, 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, NGL and gas swap contracts, collar contracts and collar contracts with short puts. The Company's oil, NGL and gas swap, collar and collar contracts with short puts asset and liability measurements represent Level 2 inputs in the hierarchy priority. 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 which 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 December 31, 2012 and 2011 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 December 31, 2012 and 2011 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted 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 priority.

Assets and liabilities measured at fair value on a nonrecurring basis. During 2012 and 2011, reductions in management's longer-term commodity price outlooks ("Management's Price Outlooks") provided indications of possible impairment of the Company's predominately dry gas properties in the Edwards Trend and Austin Chalk fields in South Texas, the Barnett Shale field in North Texas and the Raton field in southeastern Colorado. As a result of management's assessments, during June 2012 and December 2011, the Company recognized impairment charges to reduce the carrying values of the Barnett Shale field and the Edwards Trend/Austin Chalk fields, respectively, to their fair values.

As discussed in Note C, during December 2012, the Barnett Shale field assets were reclassified from held for sale to held and used. This reclassification triggered an additional assessment to determine whether an impairment charge was necessary to adjust the carrying value of Barnett Shale field proved and unproved properties to the lower of their fair value or carrying value. Based upon this assessment, the Company recognized impairment charges to reduce the carrying value of the Barnett Shale field proved and unproved properties to their fair values during December 2012.

The Company calculated the fair values of the Barnett Shale field and the Edwards Trend/Austin Chalk fields proved properties using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included Management's Price Outlooks and management's outlooks for (i) production costs, (ii) capital expenditures, (iii) production and (iv) estimated proved reserves and risk-adjusted probable reserves. Management's Price Outlooks are developed based on third-party commodity futures price outlooks as of a measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value. The following table presents the fair value and impairment (in millions) for each of the Company's 2012 and 2011 proved property impairments, as well as the oil price per barrel ("BBL") and gas price per British thermal unit ("MMBTU") utilized in respective Management's Price Outlooks:

		Fair				Management's Price Outlooks
		Value		Impairment		Oil		Gas
Edwards Trend/Austin Chalk	December 2011	$	189.9	$	354.4	$	92.69	$	5.14
Barnett Shale	June 2012	$	128.7	$	444.9	$	87.09	$	4.64
Barnett Shale	December 2012	$	184.8	$	87.7	$	87.10	$	4.92

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 Price Outlooks and (iv) increases or decreases in production and capital costs associated with these fields.

During December 2012, the Company recorded an impairment charge to reduce the carrying value of unproved properties in the Barnett Shale field of $71.8 million. The Company calculated the estimated fair value of the Barnett Shale unproved properties using significant Level 3 assumptions based on average lease bonuses per acre for its Barnett liquid-rich acreage, allocating no value to dry gas acreage as the Company does not intend to develop that acreage.

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 December 31, 2012 and 2011 are as follows:

	December 31, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	3,721,193	$	4,555,770	$	2,528,905	$	3,105,585

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 Pioneer Southwest's 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, short-term receivables, prepaids, 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.

Concentrations of credit risk. As of December 31, 2012, the Company's primary concentration of credit risks are the risks of collecting accounts receivable – trade and the risk of counterparties' failure to perform under derivative obligations. See Note L for information regarding the Company's major customers.

The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note E for additional information regarding the Company's derivative activities and information regarding derivative net assets and liabilities by counterparty.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2012

Acquisitions and Divestitures [Abstract]

Acquisition and Divestitures [Text Block]

NOTE C. Acquisitions and Divestitures

Premier Silica Business Combination

During April 2012, a wholly-owned subsidiary of Pioneer acquired 100 percent of the share capital of Industrial Sands Holding Company and its wholly-owned subsidiary, Oglebay Norton Industrial Sands, LLC (the "Sand Acquisition"). Subsequent to the acquisition, the Company changed the name of Oglebay Norton Industrial Sands, LLC to Premier Silica LLC ("Premier Silica"). Premier Silica's core business is the operation of mines and processing facilities that produce, process and sell sand, primarily to upstream oil and gas companies for proppant used in the fracture stimulation of oil and gas wells in the United States. Premier Silica's business is supportive to the Company's vertical integration strategy of controlling major cost components of the Company's drilling and production activities in the areas where the Company has a significant inventory of drilling locations. The aggregate purchase price of Premier Silica was $297.1 million, including normal closing adjustments, and was funded from available cash and borrowings under the Company's credit facility.

The Sand Acquisition was accounted for as a business combination which, among other things, requires that assets acquired and liabilities assumed be measured at their acquisition date fair values. The fair value of the assets acquired totaled $474.9 million and were primarily comprised of proved sand reserves, probable sand reserves and mine processing facilities and equipment of $460.3 million. The fair value of liabilities assumed totaled $177.8 million and were primarily comprised of deferred income taxes of $151.0 million.

The Company recognized $2.3 million of acquisition-related costs associated with the Sand Acquisition that were expensed during the year ended December 31, 2012. These costs are included in other expense in the accompanying consolidated statements of operations for the year ended December 31, 2012, as presented in Note N.

Discontinued Operations

Barnett Shale. During the third quarter of 2012, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas. The Company classified its (i) Barnett Shale assets and liabilities as discontinued operations held for sale in the consolidated balance sheet as of September 30, 2012, and (ii) Barnett Shale results of operations as income or loss from discontinued operations, net of tax, in the consolidated statements of operations for the three and nine months ended September 30, 2012 and 2011 (representing a recasting of the Barnett Shale results of operations for the three and nine months ended September 30, 2011, which were originally classified as continuing operations).

The Company retained a capital markets advisor during the third quarter of 2012 and actively solicited offers from interested purchasers of the Barnett Shale field assets. Those efforts were unsuccessful in attracting binding offers under acceptable terms to the Company. Since the Company was unable to dispose of its Barnett Shale field assets under acceptable terms, in December 2012, the Company decided to retain the assets; therefore, the Barnett Shale assets and liabilities no longer qualified as held for sale or discontinued operations. Accordingly, all amounts related to the Barnett Shale that were previously reported as (i) discontinued operations held for sale were reclassified to continuing operations at December 31, 2012, (ii) results from the Barnett Shale operations was recorded to continuing operations for the quarter ended December 31, 2012 and results included in discontinued operations were reclassified to income from continuing operations for the nine months ended September 30, 2012, and (iii) amounts in periods prior to 2012 that were reflected in discontinued operations were reclassified to continuing operations.

Assets classified as held for sale must be assessed for impairment at the point in time when they no longer qualify as held for sale and their carrying values (adjusted for any depreciation, depletion or amortization that would have been recognized had the asset been continuously classified as held and used) cannot exceed the lower of fair value or carrying value. Accordingly, the Company assessed its Barnett Shale field proved and unproved oil and gas properties for impairment during the fourth quarter of 2012. As a result of those assessments, the Company reduced the carrying value of its Barnett Shale field proved properties by $87.7 million and its Barnett Shale field unproved properties by $71.8 million. The reductions in the carrying values of the proved and unproved properties are included in impairment of oil and gas properties and exploration abandonments, respectively, in the Company's accompanying consolidated statements of operations for the year ended December 31, 2012. See Note D for further information about the fair values used to calculate the Barnett Shale impairment.

South Africa. During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest its net assets in South Africa ("Pioneer South Africa"). During the first quarter of 2012, the Company agreed to sell its net assets in 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 pretax gain of $28.6 million. The Company classified (i) Pioneer South Africa's assets and liabilities as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2011 and (ii) Pioneer South Africa's results of operations prior to the completion of the sale as income from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

Tunisia. In February 2011, the Company sold 100 percent of the Company's share holdings in Pioneer Natural Resources Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as "Pioneer Tunisia") to an unaffiliated third party for cash proceeds of $802.5 million, including normal closing adjustments and excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million. Accordingly, the Company has classified the results of operations of Pioneer Tunisia, prior to its sale, as discontinued operations, net of tax, in the accompanying consolidated statements of operations.

The following table represents the components of the Company's discontinued operations for the years ended December 31, 2012, 2011 and 2010 (principally related to the divestitures of the Company's net assets in Pioneer South Africa and Pioneer Tunisia):

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Revenues and other income:
Oil and gas	$	49,192		$	100,275		$	236,343
Interest and other (a)	95			6,193			49,076
Gain on disposition of assets, net (b)	28,546			645,241			36
	77,833			751,709			285,455
Costs and expenses:
Oil and gas production	2,254			5,519			14,754
Depletion, depreciation and amortization (b)	—			41,916			98,495
Exploration and abandonments	70			4,268			15,908
General and administrative	1,975			10,286			5,697
Accretion of discount on asset retirement obligations (b)	1,521			2,686			2,923
Interest	—			773			—
Other	1,196			5,159			13,898
	7,016			70,607			151,675
Income from discontinued operations before income taxes	70,817			681,102			133,780
Current tax provision	(7,720		)	(43,897		)	(25,486		)
Deferred tax (provision) benefit (b)	(7,948		)	(214,053		)	25,756
Income from discontinued operations	$	55,149		$	423,152		$	134,050

 ____________________

(a) Primarily comprised of (i) $35.3 million of interest on excess royalty payments received from Bureau of Ocean Energy Management, Regulation, and Enforcement during the second quarter of 2010, (ii) $2.0 million of additional interest received during the first quarter of 2011 associated with the 2010 recovery of the aforementioned excess royalties and (iii) $2.8 million of interest income associated with Pioneer Tunisia operations during the first quarter of 2011.

(b) Represents significant noncash components of discontinued operations.

As of December 31, 2011, the carrying values of Pioneer South Africa assets and liabilities, respectively, were included in discontinued operations held for sale in the accompanying consolidated balance sheet and were comprised of the following:

	December 31, 2011
	(in thousands)
Composition of assets included in discontinued operations held for sale:
Current assets (excluding cash and cash equivalents)	$	10,465
Property, plant and equipment	53,025
Deferred tax assets	9,816
Other assets, net	43
Total assets	$	73,349
Composition of liabilities included in discontinued operations held for sale:
Current liabilities	$	11,689
Deferred revenue	34,320
Other liabilities	29,892
Total liabilities	$	75,901

As of December 31, 2012, there are no assets and liabilities held for sale.

Divestitures Recorded in Continuing Operations

The Company recorded net gains on disposition of assets in continuing operations of $58.1 million and $19.1 million during the years ended December 31, 2012 and 2010, respectively, and a net loss on disposition of assets in continuing operations of $3.6 million during the year ended December 31, 2011. The following describes the significant divestitures of continuing operations:

• Alaska. In August 2012, the Company completed the sale of its interest in the Cosmopolitan Unit in the Cook Inlet of Alaska to unaffiliated third parties for cash proceeds of $10.1 million, which, together with certain Company obligations assumed by the purchasers, resulted in a pretax gain of $12.6 million.

• Eagle Ford Shale. In January 2012, the Company sold a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale play to unaffiliated third parties for cash proceeds of $54.7 million, which resulted in a pretax gain of $42.6 million.

In June 2010, the Company entered into an Eagle Ford Shale joint venture and associated therewith the Company sold 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds, resulting in a pretax gain of $6.0 million in 2010.

• Uinta/Piceance. During 2010, the Company sold certain proved and unproved oil and gas properties in the Uinta/Piceance area for net proceeds of $11.8 million and the assumption by the purchaser of certain asset retirement obligations, resulting in a pretax gain of $17.3 million.

• Other Assets. During 2012, 2011 and 2010, the Company sold unproved leaseholds, inventory and other property and equipment and recorded a pretax net loss of $1.1 million, $5.1 million and $4.2 million, respectively.

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Income Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Income Taxes

NOTE O.    Income Taxes

The Company and its eligible subsidiaries file a consolidated United States federal income tax return. Certain subsidiaries are not eligible to be included in the consolidated United States federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject to examination by United States federal, state, local and foreign taxing authorities. The Company made current and estimated tax payments of $32.3 million, $22.3 million and $36.6 million (net of tax refunds) during 2012, 2011 and 2010, respectively. These payments and net refunds include tax payments related to Pioneer Tunisia's and Pioneer South Africa's operations of $9.8 million, $12.2 million and $17.8 million during 2012, 2011 and 2010, respectively.

The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and assesses the likelihood that the Company's net operating loss carryforwards ("NOLs") and other deferred tax attributes in the United States, state, local and foreign tax jurisdictions will be utilized prior to their expiration.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. As of December 31, 2012, the Company had no unrecognized tax benefits. With respect to income taxes, the Company's policy is to account for interest charges as interest expense and any penalties as other expense in the consolidated statements of operations. The Company files income tax returns in the United States federal jurisdiction, and various state and foreign jurisdictions. As of December 31, 2012, there are no proposed adjustments or uncertain positions in any jurisdiction that would have a significant effect on the Company's future results of operations or financial position. The Company's earliest open years in its key jurisdictions are as follows:

United States	2011
Various U.S. states	2007
Tunisia	2006
South Africa	2006

The Company's income tax provision and amounts separately allocated were attributable to the following items for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Income tax provision from continuing operations	$	(92,384	)	$	(197,644	)	$	(269,627	)
Income tax (provision) benefit from discontinued operations	(15,668		)	(257,950		)	270
Changes in goodwill – tax benefits related to stock-based compensation	—			40			453
Changes in stockholders' equity:
Net deferred hedge (loss) gain	(1,725		)	8,407			23,648
Excess tax benefit (provision) related to stock-based compensation	58,486			31,087			(153		)
Tax attributable to 2008 Pioneer Southwest initial public offering	(49,072		)	—			—
Tax attributable to 2009 and 2011 issuance of Pioneer Southwest common units	—			(23,711		)	—
Tax on Pioneer Southwest common units sold by the Company during 2011	—			(15,381		)	—

The Company's income provision attributable to income from continuing operations consisted of the following for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Current:
U.S. federal	$	(5,573	)	$	—		$	—
U.S. state	(1,352		)	(9,065		)	(9,864		)
	(6,925		)	(9,065		)	(9,864		)
Deferred:
U.S. federal	(78,790		)	(207,146		)	(263,063		)
U.S. state	(6,669		)	18,567			3,300
	(85,459		)	(188,579		)	(259,763		)
Income tax provision from continuing operations	$	(92,384	)	$	(197,644	)	$	(269,627	)

Reconciliations of the United States federal statutory tax rate to the Company's effective tax rate for income from continuing operations are as follows for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands, except percentages)
Income from continuing operations before income taxes	$	280,057		$	656,406		$	781,572
Less: Net income attributable to noncontrolling interests	(50,537		)	(47,425		)	(40,787		)
Income from continuing operations attributable to parent before income taxes	229,520			608,981			740,785
Federal statutory income tax rate	35		%	35		%	35		%
Provision for federal income taxes	(80,332		)	(213,143		)	(259,275		)
State income taxes (net of federal tax benefit)	(5,214		)	6,176			(4,267		)
Other	(6,838		)	9,323			(6,085		)
Income tax provision from continuing operations	$	(92,384	)	$	(197,644	)	$	(269,627	)
Effective income tax rate, excluding income attributable to the noncontrolling interest	40		%	32		%	36		%

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities related to continuing operations are as follows as of December 31, 2012 and 2011:

	December 31,
	2012			2011
	(in thousands)
Deferred tax assets:
Net operating loss carryforward (a)	$	498,441		$	—
Asset retirement obligations	69,214			47,860
Incentive plans	48,575			36,610
Other	104,714			46,218
Total deferred tax assets (b)	720,944			130,688
Deferred tax liabilities:
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes	(2,241,081		)	(1,692,317		)
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes	(255,943		)	(102,351		)
State taxes and other	(285,313		)	(191,621		)
Net deferred hedge gains	(165,504		)	(144,558		)
Total deferred tax liabilities	(2,947,841		)	(2,130,847		)
Net deferred tax liability	$	(2,226,897	)	$	(2,000,159	)
Reflected in accompanying consolidated balance sheets as:
Current deferred income tax liability	$	(86,481	)	$	(57,713	)
Noncurrent deferred income tax liability	(2,140,416		)	(1,942,446		)
Total	$	(2,226,897	)	$	(2,000,159	)

____________________

(a)    All net operating loss carryforwards as of December 31, 2012 expire in 2032.

(b)     The Company had no deferred tax valuation allowances at December 31, 2012 and 2011.

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Related Party Transactions

12 Months Ended

Dec. 31, 2012

Related Party Transactions [Abstract]

Related Party Transactions

NOTE K.     Related Party Transactions

The Company, through a wholly-owned subsidiary, (i) serves as operator of properties in which it and its affiliated partnerships have an interest and (ii) owns a noncontrolling interest in its unconsolidated affiliate, EFS Midstream, which it manages. Through these relationships, the Company is a party to transactions with the affiliated partnerships and EFS Midstream that represent related party transactions.

Transactions with affiliated partnerships. The Company receives producing well overhead and other fees related to the operation of the properties in which it and its affiliated partnerships have an interest. The affiliated partnerships also reimburse the Company for their allocated share of general and administrative charges. Reimbursements of fees are recorded as reductions to general and administrative expenses in the Company's consolidated statements of operations.

The related party transactions with affiliated partnerships are summarized below for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Receipt of lease operating and supervision charges in accordance with standard industry operating agreements	$	2,437	$	2,104	$	2,184
Reimbursement of general and administrative expenses	$	342	$	313	$	344

Transactions with EFS Midstream. The Company, through a wholly-owned subsidiary, (i) provides certain services as the manager of EFS Midstream in accordance with a Master Services Agreement and (ii) is the operator of Eagle Ford Shale properties for which EFS Midstream provides certain services under a Hydrocarbon Gathering and Handling Agreement (the "HGH Agreement").

Master Services Agreement. The terms of the Master Services Agreement provide that the Company will perform certain manager services for EFS Midstream and be compensated by monthly fixed payments and variable payments attributable to expenses incurred by employees whose time is substantially dedicated to EFS Midstream's business. During 2012, 2011 and 2010, the Company received $2.3 million, $2.2 million and $1.1 million of fixed payments and $11.8 million, $8.4 million and $1.9 million of variable payments, respectively, from EFS Midstream. The Company also paid $1.9 million to purchase rights of way from EFS Midstream during 2011 and received $1.1 million of proceeds from the sale of an amine plant to EFS Midstream during 2010.

Hydrocarbon Gathering and Handling Agreement. During June 2010, the Company entered into the HGH Agreement with EFS Midstream. In accordance with the terms of the HGH Agreement, EFS Midstream is obligated to construct certain equipment and facilities capable of gathering, treating and transporting oil and gas production from the Eagle Ford Shale properties operated by the Company. The HGH Agreement also obligates the Company and its Eagle Ford Shale working interest partners to use the EFS Midstream gathering, treating and transportation equipment and facilities. In accordance with the terms of the HGH Agreement, the Company paid EFS Midstream $58.5 million, $21.3 million and $404 thousand of gathering and treating fees during 2012, 2011 and 2010, respectively. Such amounts were expensed as oil and gas production costs in the accompanying consolidated statements of operations.

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Related Party Transactions (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Proceeds from disposition of assets, net	$ 95,564,000	$ 819,044,000	$ 313,780,000
EFS Midstream [Member]
Cost reimbursement fixed	2,300,000	2,200,000	1,100,000
Cost reimbursement variable	11,800,000	8,400,000	1,900,000
Proceeds from disposition of assets, net			1,100,000
Gathering And Treating Fees [Member] | EFS Midstream [Member]
Related party transaction expenses paid	58,500,000	21,300,000	404,000
Right Of Way [Member] | EFS Midstream [Member]
Related party transaction expenses paid		$ 1,900,000

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Long-Term Debt

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Long-Term Debt

NOTE G.     Long-term Debt and Interest Expense

Long-term debt, including the effects of net deferred fair value hedge losses and issuance discounts, consisted of the following components at December 31, 2012 and 2011:

	December 31,
	2012			2011
	(in thousands)
Outstanding debt principal balances:
Pioneer credit facility	$	474,000		$	—
Pioneer Southwest credit facility	126,000			32,000
5.875% senior notes due 2016	455,385			455,385
6.65% senior notes due 2017	485,100			485,100
6.875 % senior notes due 2018	449,500			449,500
7.500 % senior notes due 2020	450,000			450,000
3.95% senior notes due 2022	600,000			—
7.20% senior notes due 2028	250,000			250,000
2.875% convertible senior notes due 2038	479,907			479,930
	3,769,892			2,601,915
Issuance discounts	(47,309		)	(71,301		)
Net deferred fair value hedge losses	(1,390		)	(1,709		)
Total long-term debt	$	3,721,193		$	2,528,905

Credit Facility. During December 2012, the Company entered into the First Amendment to the Second Amended and Restated 5-Year Revolving Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that extended the maturity to December 20, 2017, unless extended in accordance with the terms of the Credit Facility, and increased the aggregate loan commitments from $1.25 billion to $1.5 billion. The Company accounted for the entry into the Credit Facility as a modification of the prior agreement and capitalized the debt issuance costs along with those unamortized issuance costs that remained from the issuance of the prior agreement. As of December 31, 2012, the Company had outstanding borrowings of $474.0 million under the Credit Facility and $2.2 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $1.0 billion of unused borrowing capacity under the Credit Facility.

Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $150 million. Revolving loans under the Credit Facility bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National Association or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin, which is currently 0.5 percent based on the Company's debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the "Applicable Margin"), which is currently 1.50 percent and is also determined by the Company's debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the "ASK" rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company's debt rating (currently 0.25 percent). Borrowings under the Credit Facility are general unsecured obligations.

The Credit Facility requires the maintenance of a ratio of total debt to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset impairments not to exceed .60 to 1.0. As of December 31, 2012, the Company was in compliance with all of its debt covenants.

During March 2012, Pioneer Southwest entered into a $300 million Amended and Restated 5-Year Revolving Credit Agreement (the "Pioneer Southwest Credit Facility") with a syndicate of financial institutions that matures in March 2017, unless extended in accordance with the terms of the Pioneer Southwest Credit Facility. The Pioneer Southwest Credit Facility replaced Pioneer Southwest's 5-Year Revolving Credit Agreement entered into in May 2008. As of December 31, 2012, there were $126 million of outstanding borrowings under the Pioneer Southwest Credit Facility. Borrowings under the Pioneer Southwest Credit Facility are general unsecured obligations.

The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions. Borrowings under the Pioneer Southwest Credit Facility may be in the form of Eurodollar rate loans, base rate committed loans or swing line loans. Eurodollar rate loans bear interest annually at LIBOR, plus a margin (the "Applicable Rate") (currently 1.625 percent) that is determined by a reference grid based on Pioneer Southwest's consolidated leverage ratio. Base rate committed loans bear interest annually at a base rate equal to the higher of (i) the Federal Funds Rate plus 0.5 percent (ii) the one-month Eurodollar rate plus .01 or (iii) the Bank of America prime rate (the "Base Rate") plus a margin (currently 0.625 percent). Swing line loans bear interest annually at the Base Rate plus the Applicable Rate.

The Pioneer Southwest Credit Facility contains certain financial covenants, including (i) the maintenance of a quarter end consolidated leverage ratio (representing a ratio of consolidated indebtedness of Pioneer Southwest to consolidated earnings before depreciation, depletion and amortization; impairment of long-lived assets; exploration expense; accretion of discount on asset retirement obligations; interest expense; income taxes; gain or loss on the disposition of assets; noncash commodity derivative related activity; noncash equity-based compensation; and other noncash items) of not more than 3.5 to 1.0 and (ii) the maintenance of a ratio of the net present value of Pioneer Southwest's projected future cash flows from its oil and gas assets to total debt of at least 1.75 to 1.0. As of December 31, 2012, Pioneer Southwest was in compliance with all of its debt covenants.

The net present value covenant limits Pioneer Southwest's available borrowing capacity under the Pioneer Southwest Credit Facility to $134.7 million as of December 31, 2012, and may further limit Pioneer Southwest's borrowing capacity in the future. The variables on which the calculation of net present value is based (including assumed commodity prices and discount rate) are subject to adjustment by the lenders. As a result, a sustained decline in commodity prices could reduce Pioneer Southwest's borrowing capacity under the Pioneer Southwest Credit Facility. In addition, the Pioneer Southwest Credit Facility contains various covenants that limit, among other things, Pioneer Southwest's ability to grant liens, incur additional indebtedness, engage in a merger, enter into transactions with affiliates, pay distributions or repurchase equity, and sell its assets. If any default or event of default (as defined in the Pioneer Southwest Credit Facility) were to occur, the Pioneer Southwest Credit Facility would prohibit Pioneer Southwest from making distributions to unitholders. Such events of default include, among others, nonpayment of principal or interest, violations of covenants, bankruptcy and material judgments and liabilities.

Pioneer Southwest pays a commitment fee on the unused portion of the Pioneer Southwest Credit Facility. The commitment fee is variable based on Pioneer Southwest's consolidated leverage ratio. For the twelve months ended December 31, 2012, the commitment fee was 0.275 percent.

Senior notes. During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of $8.5 million of offering discounts and costs, of $591.5 million. The Company used the net proceeds from the issuance to reduce outstanding borrowings under the Credit Facility.

Convertible senior notes. During January 2008, the Company issued $500 million of 2.875% Convertible Senior Notes due 2038 (the "Convertible Senior Notes"). The Convertible Senior Notes mature on January 15, 2038 but are convertible under certain circumstances, using a net share settlement process, into a combination of cash and the Company's common stock pursuant to a formula. In general, upon conversion of a Convertible Senior Note, the holder of such note will receive cash equal to the principal amount of the Convertible Senior Note and the Company's common stock for the Convertible Senior Note's conversion value in excess of such principal amount. If at the time of conversion the applicable price of the Company's common stock exceeds the base conversion price, holders will receive up to an additional 8.9532 shares of the Company's common stock per $1,000 principal amount of notes, as determined pursuant to a specified formula.

The Company may redeem the Convertible Senior Notes for cash at any time on or after January 15, 2013 at a price equal to full principal amount plus accrued and unpaid interest. Holders of the Convertible Senior Notes may require the Company to purchase their Convertible Senior Notes for cash at a price equal to 100 percent of the principal amount plus accrued and unpaid interest if certain defined fundamental changes occur, as defined in the agreement, or on January 15, 2013, 2018, 2023, 2028 or 2033. On January 15, 2013, certain holders put $8 thousand principal amount of the Convertible Senior Notes to the Company and the Company paid $8 thousand, including accrued and unpaid interest, to settle the Convertible Senior Notes. Additionally, holders may convert their notes at their option in the following circumstances:

• Following defined periods during which the reported sales prices of the Company's common stock exceeds 130 percent of the base conversion price (initially $72.60 per share, which is equivalent to an initial base conversion rate of 13.7741 common shares per $1,000 principal amount of Convertible Senior Notes);

• During five-day periods following defined circumstances when the trading price of the Convertible Senior Notes is less than 97 percent of the price of the Company's common stock times a defined conversion rate;

• Upon notice of redemption by the Company; and

• During the period beginning October 15, 2037, and ending at the close of business on the business day immediately preceding the maturity date.

The Company's stock prices during each of December 2012, September 2012, March 2012 and March 2011 met the price threshold that caused the Convertible Senior Notes to become convertible at the option of the holders during the three months ended March 31, 2013, December 31, 2012, June 30, 2012 and June 30, 2011, respectively. Associated therewith, certain holders tendered $111 thousand and $70 thousand principal amount of the Convertible Senior Notes for conversion during the twelve months ended December 31, 2012 and 2011, respectively. During 2012 and 2011, the Company paid the tendering holders of the Convertible Senior Notes a total of $23 thousand and $71 thousand of cash and issued to the tendering holders 112 shares and 340 shares of the Company's common stock in accordance with the terms of the Convertible Senior Notes indenture supplement, respectively. For the remaining notes tendered during 2012, the Company paid $88 thousand in cash and issued 707 shares in 2013.

In January and February 2013, holders of $240.6 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. In general, upon conversion of a Convertible Senior Note, the holder will receive cash equal to the principal amount of the Convertible Senior Note and shares of the Company's common stock for the Convertible Senior Note's conversion value in excess of the principal amount. If all outstanding Convertible Senior Notes had been converted on December 31, 2012, the holders would have received $479.9 million of cash and approximately 3.4 million shares of the Company's common stock, which were valued at $358.8 million based on the closing price of the common stock on December 31, 2012.

Interest on the principal amount of the Convertible Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. Beginning on January 15, 2013, during any six-month period thereafter from January 15 to July 14 and from July 15 to January 14, if the average trading price (as defined in the Convertible Senior Notes indenture supplement) of a Convertible Senior Note for the five consecutive trading days immediately preceding the first day of the applicable six-month interest period equals or exceeds 120 percent of the principal amount of the note, interest on the principal amount of the Convertible Senior Notes will be 2.375 percent solely for the relevant interest period. 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, accordingly, the interest rate in effect during the January 15, 2013 to July 14, 2013 period is reduced to 2.375 percent.

As of December 31, 2012 and 2011, the Convertible Senior Notes had an unamortized discount, which is being amortized ratably through January 2013, of $753 thousand and $18.5 million, respectively, and a net carrying value of $479.2 million and $461.5 million, respectively. For the years ended December 31, 2012, 2011 and 2010, the Company recorded $33.5 million, $32.3 million and $31.1 million, respectively, of interest expense relating to the Convertible Senior Notes, which had an effective interest rate of 6.75 percent. As of December 31, 2012 and 2011, $49.5 million is recorded in Additional Paid-in Capital as the equity component of the Convertible Senior Notes.

The Company's senior notes and convertible senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes and Convertible Senior Notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company's senior notes and Convertible Senior Notes is payable semiannually.

Principal maturities. Principal maturities of long-term debt at December 31, 2012, are as follows (in thousands):

2013	$	479,907
2014	$	—
2015	$	—
2016	$	455,385
2017	$	1,085,100
Thereafter	$	1,749,500

The principal maturities during 2013 in the preceding table represent the Convertible Senior Notes, which were subject to repurchase at the option of both the holders and the Company in 2013. As the Company had the intent and ability to fund any required cash payments upon the conversion, redemption or repurchase of the Convertible Senior Notes with borrowing capacity under the Credit Facility, the Convertible Senior Notes are classified as long-term debt in the accompanying balance sheets.

Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Cash payments for interest	$	168,665		$	165,307		$	155,854
Accretion/amortization of discounts or premiums on loans	27,351			25,210			23,304
Accretion of discount on derivative obligations	—			—			521
Amortization of net deferred hedge losses (a)	2,018			573			517
Accretion of discount on postretirement benefit obligations	257			315			433
Amortization of capitalized loan fees	5,937			5,385			5,698
Net changes in accruals	10,842			(1,768		)	11,999
Interest incurred	215,070			195,022			198,326
Less capitalized interest	(10,848		)	(13,362		)	(15,242		)
Total interest expense	$	204,222		$	181,660		$	183,084

__________________

(a) Includes interest rate derivative hedges of $1.7 million, $282 thousand, and $1.7 million for the periods ended December 31, 2012, 2011 and 2010, respectively, that were reclassified from AOCI - Hedging into earnings upon expiration (see Note E).

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Derivative Financial Instruments (Derivative Instruments) (Details) (Not Designated As Hedging Instruments [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]
Total derivatives, Asset	$ 348,423	$ 506,177
Total derivatives, Liability	39,770	132,078
Interest Rate Derivatives [Member]
Derivative [Line Items]
Total derivatives, Asset	0	0
Total derivatives, Liability	9,724	15,654
Derivatives - Current [Member] | Commodity Price Derivatives [Member]
Derivative [Line Items]
Total derivatives, Asset	286,805	248,809
Total derivatives, Liability	21,102	68,735
Derivatives - Noncurrent [Member] | Commodity Price Derivatives [Member]
Derivative [Line Items]
Total derivatives, Asset	61,618	257,368
Total derivatives, Liability	$ 8,944	$ 47,689

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

NOTE E.     Derivative Financial Instruments

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

Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices.

The following table sets forth the volumes per day in BBLs that were outstanding as of December 31, 2012 under the Company's oil derivative contracts and the weighted average oil prices per BBL for those contracts:

	2013			2014		2015
Swap contracts:
Volume (BBL)	3,000			—		—
Average price per BBL	$	81.02		$	—	$	—
Collar contracts with short puts:
Volume (BBL) (a)	71,029			60,000		26,000
Average price per BBL:
Ceiling	$	119.76		$	117.06	$	104.45
Floor	$	92.27		$	92.67	$	95.00
Short put	$	74.28		$	76.58	$	80.00
Rollfactor adjustment swap contracts:
Volume (BBL) (a)	6,000			—		—
NYMEX roll price (b)	$	0.43		$	—	$	—
Basis swap contracts:
Index swap volume (BBL) (c)	2,055			—		—
Average price per BBL (d)	$	(5.75	)	$	—	$	—

 ____________________

(a) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional 2014 (i) collar contracts with short puts for 9,000 BBLs per day with a ceiling price of $104.13 per BBL, a floor price of $95.00 per BBL and a short put price of $80.00 per BBL and (ii) rollfactor swap contracts for 15,000 BBLs per day priced at $0.38 per BBL; and (iii) replaced 5,000 BBLs per day of 2014 collar contracts with short puts with a ceiling price of $124.00 per BBL, a floor price of $90.00 per BBL and short put price of $72.00 per BBL with 5,000 BBLs per day of 2014 collar contracts with short puts with a ceiling price of $105.74 per BBL, a floor price of $100.00 per BBL and short put price of $80.00 per BBL.

(b) 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.

(c) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional basis swap contracts for 1,000 BBLs per day of October through December 2013 production with a price differential between Cushing WTI and Louisiana Light Sweet crude of $7.60 per BBL.

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

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 posted prices.

As of December 31, 2012, the Company had NGL collar contracts with short put derivatives for 1,064 BBLs per day of 2013 production with a ceiling price of $105.28 per BBL, a floor price of $89.30 per BBL and short put price of $75.20 per BBL and 1,000 BBLs per day of 2014 production with a ceiling price of $109.50 per BBL, a floor price of $95.00 per BBL and short put price of $80.00 per BBL.

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

The following table sets forth the volumes per day in MMBTUs that were outstanding as of December 31, 2012 under the Company's gas derivative contracts and the weighted average gas prices per MMBTU for those contracts:

	2013			2014			2015
Swap contracts:
Volume (MMBTU)	162,500			105,000			—
Price per MMBTU	$	5.13		$	4.03		$	—
Collar contracts:
Volume (MMBTU)	150,000			—			—
Price per MMBTU:
Ceiling	$	6.25		$	—		$	—
Floor	$	5.00		$	—		$	—
Collar contracts with short puts:
Volume (MMBTU)	—			25,000			225,000
Price per MMBTU:
Ceiling	$	—		$	4.70		$	5.09
Floor	$	—		$	4.00		$	4.00
Short put	$	—		$	3.00		$	3.00
Basis swap contracts:
Volume (MMBTU)	162,500			10,000			—
Price per MMBTU	$	(0.22	)	$	(0.19	)	$	—

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

As of December 31, 2012 the Company had marketing derivative gas index swap contracts outstanding for 40,000 MMBTU of January through March 2013 volumes with a price differential of $0.25 per MMBTU. During the period from January 1, 2013 to February 8, 2013, the Company entered into additional marketing derivative gas index swap contracts for 25,000 MMBTU per day of April 2013 volumes with a price differential of $0.35 per MMBTU.

Interest rates. As of December 31, 2012, 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 during December 2015.

Tabular disclosure of derivative fair value. Since February 2009, all of the Company's derivatives have been accounted for as non-hedge derivatives. The following tables provide disclosure of the Company's derivative instruments for the years ended December 31, 2012 and 2011:

Fair Value of Derivative Instruments as of December 31, 2012
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	286,805	Derivatives - current	$	21,102
Commodity price derivatives	Derivatives - noncurrent	61,618		Derivatives - noncurrent	8,944
Interest rate derivatives	Derivatives - noncurrent	—		Derivatives - noncurrent	9,724
		$	348,423		$	39,770

Fair Value of Derivative Instruments as of December 31, 2011
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	248,809	Derivatives - current	$	68,735
Commodity price derivatives	Derivatives - noncurrent	257,368		Derivatives - noncurrent	47,689
Interest rate derivatives	Derivatives - current	—		Derivatives - current	15,654
		$	506,177		$	132,078

 _____________________

(a) Derivative assets and liabilities shown in the tables above are presented as gross assets and liabilities, without regard to master netting arrangements which are considered in the presentations of derivative assets and liabilities in the accompanying consolidated balance sheets.

Derivatives in Cash Flow Hedging Relationships	Location of Gain/(Loss) Reclassified from AOCI into Earnings	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
		Year Ended December 31,
		2012			2011			2010
		(in thousands)
Interest rate derivatives	Interest expense	$	(1,699	)	$	(282	)	$	(1,698	)
Interest rate derivatives	Derivative gains, net	—			—			(2,465		)
Commodity price derivatives	Oil and gas revenue	(3,156		)	32,918			89,040
Total		$	(4,855	)	$	32,636		$	84,877

Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Earnings on Derivatives	Amount of Gain (Loss) Recognized in Earnings on Derivatives
		Year Ended December 31,
		2012			2011		2010
		(in thousands)
Interest rate derivatives	Derivative gains, net	$	(22,428	)	$	3,098	$	36,597
Commodity price derivatives	Derivative gains, net	352,679			389,654		414,302
Total		$	330,251		$	392,752	$	450,899

AOCI - Hedging. The effective portions of discontinued cash flow hedge gains and losses, net of associated taxes, were reflected in AOCI - Hedging as of December 31, 2011 and 2010, and were transferred to oil revenue and to interest expense in the same periods in which the hedged transactions were recorded in earnings.

As of December 31, 2011, AOCI - Hedging was $3.1 million of net deferred losses. The AOCI - Hedging balance as of December 31, 2011 was comprised of $3.2 million and $1.7 million of net deferred losses on the effective portions of discontinued commodity and interest rate hedges, respectively, offset partially by $1.7 million of associated net deferred tax benefits. During 2012, the remaining net deferred hedge losses in AOCI - Hedging were transferred to earnings.

Derivative counterparties. 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.

The following table provides the Company's net derivative assets or liabilities by counterparty as of December 31, 2012:

	Net Assets (Liabilities)
	(in thousands)
Citibank, N.A.	$	72,218
JP Morgan Chase	48,606
Barclays Capital	36,736
BMO Financial Group	26,560
Credit Suisse	21,196
J. Aron & Company	20,138
BNP Paribas	19,420
Toronto Dominion	18,802
Merrill Lynch	17,136
Morgan Stanley	13,893
Den Norske Bank	7,487
Societe Generale	5,700
Wells Fargo Bank, N.A.	5,024
Macquarie Bank	380
Royal Bank of Canada	(97		)
Deutsche Bank	(327		)
Credit Agricole	(1,991		)
UBS	(2,228		)
Total	$	308,653

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Exploratory Well Costs

12 Months Ended

Dec. 31, 2012

Exploratory Well Costs [Abstract]

Exploratory Well Costs

NOTE F.    Exploratory Well Costs

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

The following table reflects the Company's capitalized exploratory well and project activity during each of the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Beginning capitalized exploratory well costs	$	107,596		$	96,193		$	127,574
Additions to exploratory well costs pending the determination of proved reserves	926,084			524,313			238,905
Reclassification due to determination of proved reserves	(790,373		)	(480,716		)	(160,879		)
Disposition of assets sold	—			(28,938		)	(17,601		)
Exploratory well costs charged to exploration and abandonment expense	(30,637		)	(3,256		)	(91,806		)
Ending capitalized exploratory well costs	$	212,670		$	107,596		$	96,193

The following table provides an aging, as of December 31, 2012, 2011 and 2010 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed:

	Year Ended December 31,
	2012		2011		2010
	(in thousands, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	190,678	$	107,596	$	70,635
More than one year	21,992		—		25,558
	$	212,670	$	107,596	$	96,193
Number of projects with exploratory well costs that have been suspended for a period greater than one year	1		—		3

Alaska - Oooguruk.As of December 31, 2012, the Company has $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, sub-surface damages were sustained. The Company currently expects to recomplete the well in mid-2013.

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Incentive Plans

12 Months Ended

Dec. 31, 2012

Incentive Plans [Abstract]

Incentive Plans

NOTE H.     Incentive Plans

Retirement Plans

Deferred compensation retirement plan. In August 1997, the Compensation Committee of the Company's board of directors (the "Board") approved a deferred compensation retirement plan for the officers and certain key employees of the Company. Each officer and key employee is allowed to contribute up to 25 percent of their base salary and 100 percent of their annual bonus. The Company will provide a matching contribution of 100 percent of the officer's and key employee's contribution limited to the first ten percent of the officer's base salary and eight percent of the key employee's base salary. The Company's matching contribution vests immediately. A trust fund has been established by the Company to accumulate the contributions made under this retirement plan. The Company's matching contributions were $2.4 million, $2.2 million and $1.9 million for the years ended December 31, 2012, 2011 and 2010, respectively.

401(k) plan. The Pioneer USA 401(k) and Matching Plan (the "401(k) Plan") is a defined contribution plan established under the Internal Revenue Code Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute an amount up to 80 percent of their annual salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a participant's contributions to the 401(k) Plan that are not in excess of five percent of the participant's base compensation (the "Matching Contribution"). Each participant's account is credited with the participant's contributions, Matching Contributions and allocations of the 401(k) Plan's earnings. Participants are fully vested in their account balances except for Matching Contributions and their proportionate share of 401(k) Plan earnings attributable to Matching Contributions, which proportionately vest over a four-year period that begins with the participant's date of hire. During the years ended December 31, 2012, 2011 and 2010, the Company recognized compensation expense of $24.7 million, $18.3 million and $13.4 million, respectively, as a result of Matching Contributions.

Stock-based compensation costs. In accordance with GAAP, the Company records stock-based compensation expense, equal to the fair value of share-based payments, ratably over the vesting periods of the Long-Term Incentive Plan ("LTIP") awards, the Series B unit awards issued by Sendero, the Pioneer Southwest Long-Term Incentive Plan ("Pioneer Southwest LTIP") awards and for payments associated with the Company's Employee Stock Purchase Plan ("ESPP").

The following table reflects stock-based compensation expense recorded for each type of incentive award and the associated income tax benefit for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Restricted stock-equity awards (a)	$	48,876	$	32,861	$	31,712
Restricted stock-liability awards	22,419		10,882		4,900
Stock options (b)	4,110		2,936		1,522
Performance unit awards	6,162		4,500		4,635
Pioneer Southwest LTIP	1,098		761		475
Sendero Series B units	982		1,020		1,020
ESPP	2,437		125		1,034
Total	$	86,084	$	53,085	$	45,298
Income tax benefit	$	27,901	$	22,084	$	14,019

 _____________________

(a) For the year ended December 31, 2010, stock-based compensation expense included a charge of $1.3 million for the modification of equity awards associated with termination agreements made with 12 employees affected by the divestiture of the Company's Tunisian subsidiaries. The modification accelerated vesting of all unvested equity awards for the 12 participants to the closing date of the transaction. The $1.3 million charge, net of the associated tax benefit, is included in income from discontinued operations, net of tax, in the accompanying consolidated statements of operations for the year ended December 31, 2010.

(b) Cash proceeds received from stock option exercises during 2012, 2011 and 2010 amounted to $3.1 million, $619 thousand and $4.8 million, respectively.

As of December 31, 2012, there was $131.1 million of unrecognized stock-based compensation expense related to unvested share and unit based compensation plans, including $24.5 million attributable to Liability Awards. The stock-based compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis.

Pioneer Long-Term Incentive Plan

In May 2006, the Company's stockholders approved the LTIP, which provides for the granting of various forms of awards, including stock options, stock appreciation rights, performance units, restricted stock and restricted stock units to directors, officers and employees of the Company. The LTIP provides for the issuance of 9.1 million shares pursuant to awards under the plan. The shares to be delivered under the LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company, including shares purchased on the open market.

The following table shows the number of shares available for issuance pursuant to awards under the Company's LTIP at December 31, 2012:

Approved and authorized awards	9,100,000
Awards issued after May 3, 2006	(6,134,118	)
Awards available for future grant	2,965,882

Restricted stock awards. During 2012, the Company awarded 1,153,029 restricted shares or units of the Company's common stock as compensation to directors, officers and employees of the Company (including 240,486 shares or units representing Liability Awards). The Company's issued shares, as reflected in the consolidated balance sheets as of December 31, 2012 do not include 304,260 of issued, but unvested shares awarded under stock-based compensation plans that have voting rights.

The following table reflects the restricted stock award activity for the year ended December 31, 2012:

	Equity Awards				Liability Awards
	Number of Shares		Weighted Average Grant- Date Fair Value		Number of Shares
Outstanding at beginning of year	1,857,612		$	39.95	322,925
Shares granted	912,543		$	113.02	240,486
Shares forfeited	(28,011	)	$	101.91	(29,060	)
Shares vested	(1,229,382	)	$	23.75	(128,435	)
Outstanding at end of year	1,512,762		$	96.22	405,916

The weighted average grant-date fair value of restricted stock equity awards awarded during 2012, 2011 and 2010 was $113.02, $97.52 and $48.32, respectively. The fair value of shares for which restrictions lapsed during 2012, 2011 and 2010 was $137.2 million, $98.6 million and $42.9 million, respectively, based on the market price on the vesting date.

As of December 31, 2012 and 2011, accounts payable – due to affiliates in the accompanying consolidated balance sheet includes $18.8 million and $9.2 million of liabilities attributable to the Liability Awards, representing the fair value of employee services performed under outstanding awards as of that date. The fair value of shares for which restrictions lapsed during 2012 and 2011 was $14.2 million and $6.7 million, respectively, based on the market price on the vesting date. There were no Liability Awards that vested during 2010.

Stock option awards. Certain employees may be granted options to purchase shares of the Company's common stock with an exercise price equal to the fair market value of Pioneer common stock on the date of grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Option awards have a ten-year contract life. The expected life of an option is estimated based on historical and expected exercise behavior. The volatility assumption was estimated based upon expectations of volatility over the life of the option as measured by historical volatility. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the option. The dividend yield was based upon a seven-year average dividend yield.

The Company used the following weighted-average assumptions to estimate the fair value of stock options granted during the years ended December 31, 2012, 2011 and 2010:

	2012		2011		2010
Expected option life - years	7.0		7.0		7.0
Volatility	49.4	%	47.6	%	46.8	%
Risk-free interest rate	1.5	%	2.9	%	3.4	%
Dividend yield	0.4	%	0.4	%	0.4	%

A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2012 is presented below:

	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
					(in years)	(in thousands)
Outstanding at beginning of year	564,044		$	34.90
Options awarded	98,819		$	113.76
Options exercised	(195,377	)	$	15.62
Outstanding and expected to vest, at end of year	467,486		$	59.63	7.39	$	22,663
Exercisable at end of year	171,644		$	16.72	6.17	$	15,425

The weighted average grant-date fair value of options awarded during 2012, 2011 and 2010 was $56.29, $49.61 and $23.79, respectively, using the Black-Scholes option-pricing model. The intrinsic value of options exercised during 2012, 2011 and 2010 was $17.2 million, $1.5 million and $6.9 million, respectively, based on the difference between the market price at the exercise date and the option exercise price.

Performance unit awards. During 2012, 2011 and 2010, the Company awarded performance units to certain of the Company's officers under the LTIP. The number of shares of common stock to be issued is determined by comparing the Company's total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The performance unit awards vest over a 34-month service period. The grant-date fair values per unit of the 2012, 2011 and 2010 performance unit awards are $172.57, $134.68 and $63.52, respectively, which amounts were determined using the Monte Carlo simulation method and are being recognized as stock-based compensation expense ratably over the performance period. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. Expected volatilities utilized in the model were estimated using a historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant. The Company used the following assumptions to estimate the fair value of performance unit awards granted during 2012, 2011 and 2010:

	2012				2011				2010
Risk-free interest rate	0.40%				1.32%				1.36%
Range of volatilities	33.6	%	-	49.0%	50.2	%	-	84.1%	50.4	%	-	83.0%

The following table summarizes the performance unit activity for the year ended December 31, 2012:

	Number of Units (a)		Weighted  Average Grant-Date Fair Value
Beginning performance unit awards	114,128		$	90.64
Units granted	47,875		$	172.57
Units vested (b)	(70,633	)	$	63.52
Ending performance unit awards	91,370		$	154.53

 _____________________

(a) These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date.

(b) On December 31, 2012, the service period lapsed on 70,633 of these performance unit awards. The lapsed units earned 2.5 shares for each vested award representing 176,585 aggregate shares of common stock issued in 2012.

The fair value of shares for which restrictions lapsed during 2012, 2011 and 2010 was $18.8 million, $44.7 million and $27.4 million, respectively, based on the market price on the vesting date.

Pioneer Southwest Long-Term Incentive Plan

In May 2008, the board of directors of the general partner (the "General Partner") of Pioneer Southwest adopted the Pioneer Southwest LTIP, which provides for the granting of various forms of unit-based awards, including options, unit appreciation rights, phantom units, restricted units, unit awards and other unit-based awards, to directors, employees and consultants of the General Partner and its affiliates who perform services for Pioneer Southwest. The Pioneer Southwest LTIP limits the number of units that may be delivered pursuant to unit-based awards granted under the plan to 3.0 million common units.

The following table shows the number of awards available under the Pioneer Southwest LTIP at December 31, 2012:

Approved and authorized awards	3,000,000
Awards issued after May 6, 2008	(151,235	)
Awards available for future grant	2,848,765

During 2012, the General Partner awarded 7,496 restricted common units as compensation to directors of the General Partner under the Pioneer Southwest LTIP, which vest in May 2013. During 2011, the General Partner awarded 6,812 restricted common units as compensation to directors of the General Partner under the Pioneer Southwest LTIP, which vested in May 2012. During 2010, the General Partner awarded 8,744 restricted common units to directors of the General Partner under the Pioneer Southwest LTIP, which vested in May 2011.

	Restricted Unit Awards				Phantom Unit Awards
	Number of Units		Weighted Average Grant-Date Fair Value		Number of Units	Weighted Average Grant-Date Fair Value
Outstanding at beginning of year	7,492		$	28.47	65,157	$	27.08
Units granted	7,496		$	26.68	37,487	$	28.00
Lapse of restrictions	(7,492	)	$	28.47	—	$	—
Outstanding at end of year	7,496		$	26.68	102,644	$	27.42

The weighted average grant-date fair value of restricted common units awarded during 2012, 2011 and 2010 was $26.68, $29.35 and $22.87, respectively. The fair value of common units for which restrictions lapsed on the restricted common units during 2012, 2011 and 2010 was $200 thousand, $342 thousand and $324 thousand, respectively, based on the market price at the vesting date.

During 2012, 2011 and 2010, the General Partner awarded phantom units to certain members of management of the General Partner under Pioneer Southwest's LTIP. The phantom units entitle the recipients to common units of Pioneer Southwest after a three-year vesting period. The weighted average grant-date fair value of phantom common units awarded during 2012, 2011 and 2010 was $28.00, $32.16 and $22.74, respectively. No restrictions have lapsed on the phantom units outstanding.

Subsidiary Issuances of Unit-Based Compensation

During 2010, Sendero entered into restricted unit agreements with two key employees, granting 1,000 Series B units in Sendero. The Series B unit awards had a grant date fair value of $5.1 million, vest ratably over a five year service period and do not earn equity rights unless certain defined performance conditions are achieved by Sendero.

Employee Stock Purchase Plan

The Company has an ESPP that allows eligible employees to annually purchase the Company's common stock at a discounted price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to 15 percent of an employee's pay (subject to certain ESPP limits) during the eight-month offering period (January 1 to August 31). Participants in the ESPP purchase the Company's common stock at a price that is 15 percent below the closing sales price of the Company's common stock on either the first day or the last day of each offering period, whichever closing sales price is lower.

The following table shows the number of shares available for issuance under the ESPP at December 31, 2012:

Approved and authorized shares	1,250,000
Shares issued	(678,882	)
Shares available for future issuance	571,118

Postretirement Benefit Obligations

At December 31, 2012 and 2011, the Company had $9.7 million and $7.5 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 two funded plans that the Company assumed sponsorship of in conjunction with the acquisition of Premier Silica. Other than the Company's retirement plan and the two legacy-Premier Silica plans, the participants of these plans are not current employees of the Company.

The unfunded plans had no assets as of December 31, 2012 or 2011. The Company's funding policy for the Premier Silica plans 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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Exploratory Well Costs (Capitalized Exploratory Costs And the Number Of Projects For Which Exploratory Costs Have Been Capitalized) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Exploratory Well Costs [Abstract]
One year or less	$ 190,678	$ 107,596	$ 70,635
More than one year	21,992	0	25,558
Capitalized exploratory well costs, total suspended	$ 212,670	$ 107,596	$ 96,193	$ 127,574
Number of projects with exploratory well costs that have been suspended for a period greater than one year	1	0	3

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Related Party Transactions (Schedule Of Related Party Transactions) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transactions [Abstract]
Receipt of lease operating and supervision charges in accordance with standard industry operating agreements	$ 2,437	$ 2,104	$ 2,184
Reimbursement of general and administrative expenses	$ 342	$ 313	$ 344

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Long-Term Debt (Components Of Long-Term Debt) (Details) (USD $) In Thousands, unless otherwise specified	Feb. 13, 2013	Jan. 15, 2013 Rate	Dec. 31, 2012 Rate	Dec. 31, 2011	Jan. 31, 2008
Debt Instrument [Line Items]
Outstanding debt principal balances, gross			3,769,892	$ 2,601,915
Issuance discounts and premiums, net			(47,309)	(71,301)
Net deferred fair value hedge losses			(1,390)	(1,709)
Long-term Debt			3,721,193	2,528,905
Pioneer Credit Facility [Member]
Debt Instrument [Line Items]
Outstanding borrowing			474,000	0
Pioneer Southwest Credit Facility [Member]
Debt Instrument [Line Items]
Outstanding borrowing			126,000	32,000
5.875% Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Issuance of senior notes			455,385	455,385
Senior notes, interest rate			5.875%
6.65% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Issuance of senior notes			485,100	485,100
Senior notes, interest rate			6.65%
6.875% Senior Notes Due 2018 [Member]
Debt Instrument [Line Items]
Issuance of senior notes			449,500	449,500
Senior notes, interest rate			6.875%
7.500% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Issuance of senior notes			450,000	450,000
Senior notes, interest rate			7.50%
3.95% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Issuance of senior notes			600,000	0
Senior notes, interest rate			3.95%
7.20% Senior Notes Due 2028 [Member]
Debt Instrument [Line Items]
Issuance of senior notes			250,000	250,000
Senior notes, interest rate			7.20%
2.875% Convertible Senior Notes Due 2038 [Member]
Debt Instrument [Line Items]
Convertible debt			479,907	$ 479,930	$ 500,000
Senior notes, interest rate	2.375%	2.375%	2.875%

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Exploratory Well Costs (Capitalized Exploratory Well And Project Activity) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Exploratory Well Costs [Abstract]
Additions to exploratory well costs pending the determination of proved reserves	$ 926,084	$ 524,313	$ 238,905
Reclassification due to determination of proved reserves	(790,373)	(480,716)	(160,879)
Disposition of assets sold	0	(28,938)	(17,601)
Exploratory well costs charged to exploration expense	(30,637)	(3,256)	(91,806)
Ending capitalized exploratory well costs	$ 212,670	$ 107,596	$ 96,193	$ 127,574

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Income Taxes (Income Tax (Provision) Benefit Attributable To Income From Continuing Operations) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Disclosure [Abstract]
U.S. federal	$ (5,573)	$ 0	$ 0
U.S. state	(1,352)	(9,065)	(9,864)
Current income tax (provision) benefit	(6,925)	(9,065)	(9,864)
U.S. federal	(78,790)	(207,146)	(263,063)
U.S. state	(6,669)	18,567	3,300
Deferred income tax (provision) benefit	(85,459)	(188,579)	(259,763)
Income tax (provision) benefit	$ (92,384)	$ (197,644)	$ (269,627)

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation [Abstract]

Schedule Of Asset Retirement Obligations

The following table summarizes the Company's asset retirement obligation activity during the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Beginning asset retirement obligations	$	136,742		$	152,291		$	166,434
Liabilities assumed in acquisitions	10,498			6			6
New wells placed on production	9,593			9,233			5,218
Changes in estimates (a)	51,536			7,490			24,075
Liabilities reclassified to discontinued operations held for sale	—			(29,892		)	(5,779		)
Disposition of wells	(2,536		)	(448		)	(30,693		)
Liabilities settled	(18,066		)	(12,880		)	(17,838		)
Accretion of discount on continuing operations	9,887			8,256			7,945
Accretion of discount from integrated services (b)	100			—			—
Accretion of discount on discontinued operations	—			2,686			2,923
Ending asset retirement obligations	$	197,754		$	136,742		$	152,291

 _____________________

(a) The changes in the 2012, 2011 and 2010 estimates are primarily due to increases in abandonment cost estimates based in part on recent actual costs incurred and declines in credit-adjusted risk-free discount rates used to value increases in asset retirement obligations. The increase in the 2012 estimate was also impacted by declines in oil, NGL and gas prices used to calculate proved reserves, which had the effect of shortening the economic life of certain wells and increasing what would otherwise have been the present value of future retirement obligations. The increases in 2011 and 2010 estimates were partially offset by higher oil and NGL prices, which had the effect of lengthening the economic life of certain wells and decreasing what would otherwise have been the present value of future retirement obligations. The increase in commodity prices was less substantial in 2011 as compared to 2010.

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

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Acquisitions and Divestitures (Gain Loss on Sale of Assets from Continuing Operations) (Details) (USD $)	12 Months Ended			3 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2012 Alaska [Member]	Sep. 30, 2011 Alaska [Member]	Sep. 30, 2012 Eagle Ford Shale [Member]	Dec. 31, 2010 Eagle Ford Shale [Member] Rate	Dec. 31, 2010 Uinta Piceance [Member]
Asset Divestitures [Line Items]
Gains (Losses) on Sales of Assets	$ 58,087,000	$ (3,644,000)	$ 19,074,000		$ 12,600,000	$ 42,600,000	$ 6,000,000	$ 17,300,000
Proceeds from disposition of assets, net	95,564,000	819,044,000	313,780,000	10,100,000		54,700,000	212,000,000	11,800,000
Joint Venture Investment Ownership Percentage							45.00%
Gains (Losses) on Sales of Other Assets	$ 1,100,000	$ 5,100,000	$ 4,200,000

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Interest And Other Income

12 Months Ended

Dec. 31, 2012

Interest and Other Income [Abstract]

Interest And Other Income

NOTE M.    Interest and Other Income

The following table provides the components of the Company's interest and other income during the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011		2010
	(in thousands)
Alaskan Petroleum Production Tax credits and refunds (a)	$	29,342		$	38,939	$	47,652
Other income	5,382			7,684		4,565
Equity interest in income (loss) of EFS Midstream	2,183			1,925		(819		)
Deferred compensation plan income	1,872			1,657		1,228
Interest income	1,465			697		4,177
Income (loss) from vertical integration services (b)	(11,934		)	15,978		169
Total interest and other income	$	28,310		$	66,880	$	56,972

 ______________________

(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 years ended December 31, 2012, 2011 and 2010, these net margins include $247.8 million, $50.9 million and $946 thousand of gross vertical integration revenues, respectively and $259.7 million, $34.9 million and $777 thousand of total vertical integration costs and expenses, respectively.

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Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Principles Of Consolidation

Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. In accordance with generally accepted accounting principles in the United States ("GAAP"), the Company proportionately consolidates certain affiliate partnerships that are less than wholly-owned and are involved in oil and gas producing activities. All material intercompany balances and transactions have been eliminated.

Certain reclassifications have been made to the 2011 and 2010 financial statement and footnote amounts in order to conform them to the 2012 presentations.

Use Of Estimates In The Preparation Of Financial Statements

Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized.

Cash Equivalents

Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less.

Accounts Receivable

Accounts receivable. As of December 31, 2012 and 2011, the Company had accounts receivable – trade, net of allowances for bad debts, of $316.9 million and $276.0 million, respectively. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivable, joint interest receivables and other receivables for which the Company does not require collateral security.

As of December 31, 2012 and 2011, the Company's allowances for doubtful accounts totaled $1.5 million and $1.1 million, respectively. The Company establishes allowances for bad debts equal to the estimable portions of accounts and notes receivables for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable.

Inventories

Inventories. The Company's inventories consist of materials and supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. "Market," in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. Valuation reserve allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supply inventories in the Company's consolidated balance sheets and as other expense in the accompanying consolidated statements of operations.

Commodities inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company's commodities inventories consist of oil held in storage and natural gas liquids ("NGLs") and gas pipeline fill volumes. Any valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations.

The following table presents the Company's materials and supplies and commodities inventories as of December 31, 2012 and 2011:

	Year Ended December 31,
	2012			2011
	(in thousands)
Materials and supplies (a)	$	258,962		$	297,910
Commodities	5,446			4,453
Less: Noncurrent materials and supplies (b)	(67,352		)	(60,754		)
	$	197,056		$	241,609

____________________

(a) As of December 31, 2012 and 2011, the Company's materials and supplies inventories were net of valuation reserve allowances of $4.6 million and $0.9 million, respectively.

(b) Included in other noncurrent assets in the Company's accompanying consolidated balance sheet.

Oil And Gas Properties

Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. For large development projects requiring significant upfront development costs to support the drilling and production of a planned group of wells, the Company continues to capitalize interest on the portion of the development costs attributable to the planned wells yet to be drilled.

The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:

(i) The well has found a sufficient quantity of reserves to justify its completion as a producing well.

(ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note F for additional information regarding the Company's suspended exploratory well costs.

The Company owns interests in four gas processing plants and ten treating facilities. The Company is the operator of two of the gas processing plants and all ten of the treating facilities. The Company's ownership interests in the gas processing plants and treating facilities is primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third party revenues generated from the processing plants and treating facilities for the three years ended December 31, 2012, 2011 and 2010 were $39.4 million, $46.0 million and $34.0 million, respectively. Third party expenses attributable to the processing plants and treating facilities for the same respective periods were $27.1 million, $22.7 million and $14.3 million. The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service.

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base.

The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note D for additional information regarding the Company's proved property impairment provisions.

Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time.

Goodwill

Goodwill. During 2004, the Company recorded goodwill associated with a business combination, which represents the cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2012, the Company performed a qualitative assessment of goodwill. Financial Accounting Standards Board ("FASB") Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350) permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. Based upon the results of the assessment, the Company determined that it was not likely that the Company's goodwill was impaired.

Other Property And Equipment, Net

Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2012 and 2011, respectively, the net carrying value of other property and equipment consisted of the following:

	Year Ended December 31,
	2012 (a)		2011 (a)
	(in thousands)
Proved and unproved sand properties	$	457,033	$	—
Equipment and rigs (b)	385,887		329,157
Land and buildings	259,629		160,795
Transportation equipment	44,928		28,108
Furniture and fixtures	43,614		34,567
Leasehold improvements	26,603		20,448
	$	1,217,694	$	573,075

____________________

(a) At December 31, 2012 and 2011, other property and equipment was net of accumulated depreciation of $395.9 million and $297.6 million, respectively.

(b) Includes drilling rigs, well servicing rigs and equipment and fracture stimulation equipment.

The Company's proved and unproved sand properties include sand mines, sales facilities and unproved leaseholds that primarily provide the Company and other unrelated customers with proppant used in the fracture stimulation of oil and gas wells. See Note C for additional information about the Company's sand mine operations. The Company's equipment and rigs include assets owned by subsidiaries that provide drilling, pumping and well services on Company-operated properties. The primary purposes of the Company's sand mines and drilling, pumping and well services operations are to accommodate the Company's drilling and producing operations by increasing the availability of supplies, equipment and services, rather than being dependent on third-party availability, and to contain associated costs. As of December 31, 2012, the Company owned 15 drilling rigs, ten fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. All intercompany gains or losses of the Company's sand mines and drilling, pumping and well services operations are eliminated. Earnings from sales of proppant and from providing drilling, pumping and well services to third-party customers and working interest owners in Company-operated properties are included in interest and other income in the accompanying consolidated statements of operations.

The capitalized costs of proved sand properties are depleted using the unit-of-production method based on proved sand reserves. Equipment items are generally depreciated by individual component on a straight line basis over their economic useful lives, which are generally from two to 12 years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases.

The Company evaluates other property and equipment for potential impairment whenever indicators of impairment are present. Circumstances that could indicate potential impairment include: significant adverse changes in industry trends and the economic outlook; legal actions; regulatory changes; and significant declines in utilization rates or oil and gas prices. If it is determined that other property and equipment is potentially impaired, the Company performs an impairment evaluation by estimating the future undiscounted net cash flow from the use and eventual disposition of other property and equipment grouped at the lowest level that cash flows can be identified. If the sum of the future undiscounted net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the assets' net book value over its estimated fair value.

Investment In Unconsolidated Affiliate

Investment in unconsolidated affiliate. During 2010, the Company formed EFS Midstream LLC ("EFS Midstream") to own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play in South Texas. During June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an unaffiliated third party for $46.4 million of cash proceeds. Associated therewith, the Company recorded a $46.2 million deferred gain that is being amortized as a reduction in production costs over a 20 year period, representing the term of a continuing commitment of Pioneer to deliver production volumes through EFS Midstream handling and gathering facilities. The deferred gain is included in other current and noncurrent liabilities in the Company's accompanying consolidated balance sheet.

The Company does not have voting control of EFS Midstream. Consequently, the Company accounts for this investment under the equity method of accounting for investments in unconsolidated affiliates. Under the equity method, the Company's investment in unconsolidated affiliates is increased for investments made and the investor's share of the investee's net income, and decreased for distributions received, the carrying value of member interests sold and the investor's share of the investee's net losses.

The Company's equity interest in the net income or loss of EFS Midstream is recorded in interest and other income, net of eliminations of the profit associated with gathering, treating and transportation fees charged to the Company by EFS Midstream, in the accompanying consolidated statements of operations. See Note M for the Company's equity interest in the net income or loss of EFS Midstream for the years ended December 31, 2012, 2011 and 2010.

Asset Retirement Obligations

Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated.

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 and expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note I for additional information about the Company's asset retirement obligations.

Treasury Stock

Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.

Noncontrolling Interest In Consolidated Subsidiaries

Noncontrolling interest in consolidated subsidiaries. At December 31, 2012, the Company owned a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest. Pioneer Southwest owns interests in proved and unproved 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. On December 12, 2011, Pioneer Southwest completed the public offering of 4.4 million common units of Pioneer Southwest, representing limited partnership interests, at a per-unit offering price to the public of $29.20. Of the 4.4 million common units, Pioneer sold 1.8 million of its Pioneer Southwest common unit holdings and Pioneer Southwest issued 2.6 million of new common units. The common unit sale resulted in the Company's limited partnership interest in Pioneer Southwest decreasing from 61.9 percent to 52.4 percent.

In accordance with GAAP, the Company records transfers of any gains or losses, net of taxes, from noncontrolling interests in consolidated subsidiaries to additional paid in capital proportionate to the ownership after giving effect to the sale of common units. The following table presents the Company's net income or loss attributable to common stockholders adjusted for transfers from noncontrolling interest in consolidated subsidiaries to additional paid in capital attributable to Pioneer Southwest's common unit offerings:

	Year Ended December 31,
	2012			2011		2010
	(in thousands)
Net income attributable to common stockholders	$	192,285		$	834,489	$	605,208
Transfers from the noncontrolling interest in consolidated subsidiaries:
Increase in additional paid in capital from the sale of 1.8 million Pioneer Southwest common units during 2011, net of tax of $15.4 million	—			26,915		—
Increase in additional paid in capital from Pioneer Southwest's offering of 2.6 million common units during 2011, net of tax of $23.7 million	—			8,104		—
Decrease in additional paid in capital for deferred taxes recognized attributable to Pioneer Southwest's 2008 initial public offering of 9.5 million common units	(49,072		)	—		—
Net transfers from noncontrolling interest	(49,072		)	35,019		—
Net income attributable to common stockholders and transfers from noncontrolling interest	$	143,213		$	869,508	$	605,208

During January 2010, Pioneer Natural Resources USA, Inc. ("Pioneer USA," a wholly-owned subsidiary of the Company) formed Sendero Drilling Company, LLC ("Sendero"). Sendero was formed to own and operate land-based drilling rigs in the United States. As of December 31, 2012, Sendero owned 15 drilling rigs operating under contract to Pioneer USA in the Spraberry field. Pioneer USA is the majority owner of Sendero.

The Company also owns the majority interests in certain other subsidiaries with operations in the United States. Noncontrolling interests in the net assets of consolidated subsidiaries totaled $178.0 million and $162.3 million as of December 31, 2012 and 2011, respectively. The Company recorded net income attributable to the noncontrolling interests of $50.5 million, $47.4 million and $40.8 million for the years ended December 31, 2012, 2011 and 2010 (principally related to Pioneer Southwest), respectively.

Revenue Recognition

Revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets.

The Company had no material oil or NGL entitlement assets or liabilities as of December 31, 2012 or 2011. The following table presents the Company's gas entitlement assets and liabilities with their associated volumes as of December 31, 2012 and 2011. Gas volumes are presented in millions of cubic feet ("MMCF").

	December 31,
	2012			2011
	Amount		Volume	Amount		Volume
	(dollars in millions)
Gas entitlement assets	$	6.8	2,870	$	7.6	3,024
Gas entitlement liabilities	$	1.9	582	$	2.6	650

The Company recognized revenue of $42.1 million, $45.0 million and $90.2 million during 2012, 2011 and 2010, respectively from volumetric production payment ("VPP") agreements which represented limited-term overriding royalty interests in oil reserves that: (i) entitled the purchaser to receive production volumes over a period of time from specific lease interests, (ii) were free and clear of all associated future production costs and capital expenditures associated with the reserves, (iii) were nonrecourse to the Company (i.e., the purchaser's only recourse was to the reserves acquired), (iv) transferred title of the reserves to the purchaser and (v) allowed the Company to retain the remaining reserves after the VPPs volumetric quantities had been delivered. All VPP production volumes have been delivered and thus there are no further obligations under VPP contracts or deferred revenue as of December 31, 2012.

Derivatives And Hedging

Derivatives. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts. The effective portions of the discontinued deferred hedges as of February 1, 2009 were included in accumulated other comprehensive income (loss) – net deferred hedge gains (losses), net of tax ("AOCI - Hedging") and were transferred to earnings during the same periods in which the forecasted hedged transactions were recognized in the Company's earnings. During 2012, the remaining AOCI - Hedging was transferred to earnings. Since discontinuing hedge accounting, the Company has recognized all changes in the fair values of its derivative contracts 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 as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's and Pioneer Southwest's credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. Pioneer Southwest's credit-adjusted risk-free rate curve is based on independent market-quoted forward London Interbank Offered Rate ("LIBOR") curves plus 162.5 basis points, representing Pioneer Southwest's estimated borrowing rate.

Hurricane Activity

Hurricane activity, net. As a result of Hurricane Rita in September 2005, the Company's East Cameron 322 facility, located on the Gulf of Mexico shelf, was completely destroyed. Operations to reclaim and abandon the East Cameron 322 facility began in 2006 and were completed during 2011.

In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues for the cost of reclamation and abandonment of the East Cameron 322 facility. During 2010, the Company and the insurance carriers agreed to settle the insurance policy dispute, resulting in an additional payment to the Company of $140.1 million during November 2010.

Environmental

Environmental. The Company's environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs.

Stock-Based Compensation

Stock-based compensation. For stock-based compensation awards granted or modified, stock-based compensation expense is being recognized in the Company's financial statements on a straight line basis over the awards' vesting periods based on their fair values on the dates of grant. The stock-based compensation awards generally vest over a period not exceeding three years. The amount of stock-based compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant for the fair value of restricted stock, restricted stock units, partnership unit awards or phantom unit awards that are expected to be settled in the Company's common stock or Pioneer Southwest common units ("Equity Awards"), (iii) the Monte Carlo simulation method for the fair value of performance unit awards and (iv) a probabilistic forecasted fair value method for Series B unit awards issued by Sendero.

Stock-based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity shares or units ("Liability Awards"). Stock-based Liability Awards are recorded as accounts payable—affiliates based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to stock-based compensation expense.

Segment Reporting, Policy [Policy Text Block]

Segments. Operating segments are defined as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

Based upon how the Company is organized and managed, the Company has only one reportable operating segment, which is oil and gas exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.

Discontinued Operations

Assets held for sale and discontinued operations. On the date at which the Company meets all the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the assets or asset group to be sold and reclassifies the assets and related liabilities to be sold as held for sale on the accompanying consolidated balance sheets. The assets and liabilities are measured at the lower of their carrying amount or estimated fair value less cost to sell.

In addition, after determining that held for sale criteria has been met, the Company considers whether the held for sale assets meet the criteria to be considered discontinued operations. If the assets held for sale are considered discontinued operations, the Company classifies the results of operations from the assets held for sale as income or loss from discontinued operations, net of tax, in the accompanying consolidated statements of operations for the current period and all prior periods. See Note C for additional information about the Company's divestitures.

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Net Income (Loss) Per Share Attributable To Common Stockholders (Reconciliation Of Earnings Attributable To Common Stockholders, Basic And Diluted) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statement Operating Activities Segment [Line Items]
Income (loss) as reported, Continuing Operations	$ 187,673	$ 458,762	$ 511,945
Income (loss) as reported, Discontinued Operations	55,149	423,152	134,050
Income (loss) as reported	192,285	834,489	605,208
Net income attributable to noncontrolling interests	(50,537)	(47,425)	(40,787)
Participating basic earnings	3,029	15,178	13,896
Basic income (loss) attributable to common stockholders	189,256	819,311	591,312
Reallocation of participating earnings	161	385	180
Diluted income (loss) attributable to common stockholders	189,417	819,696	591,492
Segment, Continuing Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) as reported, Continuing Operations	137,136	411,337	471,158
Participating basic earnings	2,160	7,482	10,818
Basic income (loss) attributable to common stockholders	134,976	403,855	460,340
Reallocation of participating earnings	115	190	140
Diluted income (loss) attributable to common stockholders	135,091	404,045	460,480
Segment, Discontinued Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) as reported, Discontinued Operations	55,149	423,152	134,050
Participating basic earnings	869	7,696	3,078
Basic income (loss) attributable to common stockholders	54,280	415,456	130,972
Reallocation of participating earnings	46	195	40
Diluted income (loss) attributable to common stockholders	$ 54,326	$ 415,651	$ 131,012

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Acquisitions and Divestitures (Discontinued Operations Narrative) (Details) (USD $)	12 Months Ended			3 Months Ended		12 Months Ended		12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Barnett Shale Field [Member]	Jun. 30, 2012 Barnett Shale Field [Member]	Dec. 31, 2012 Pioneer South Africa [Member]	Mar. 31, 2012 Pioneer South Africa [Member]	Dec. 31, 2012 Pioneer Tunisia [Member]
Discontinued Operations Assets and Liabilities Included in Assets and Liabilities Held for Sale [Line Items]
Impairment of oil and gas properties	$ 532,589,000	$ 354,408,000	$ 0	$ 87,700,000	$ 444,900,000
Impairment of Long-Lived Assets Held-for-use				71,800,000
Business Combination, Consideration Transferred							60,000,000
Proceeds from Divestiture of Interest in Consolidated Subsidiaries						15,900,000		802,500,000
Gains Losses On Sales Of Assets Discontinued Operations	$ 28,546,000	$ 645,241,000	$ 36,000			$ 28,600,000		$ 645,200,000

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Net Income (Loss) Per Share Attributable To Common Stockholders (Tables)

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Reconciliation Of Earnings Attributable To Common Stockholders, Basic And Diluted

The following table is a reconciliation of the Company's net income attributable to common stockholders to basic net income attributable to common stockholders and to diluted net income attributable to common stockholders for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31, 2012
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	137,136		$	55,149		$	192,285
Participating basic earnings (a)	(2,160		)	(869		)	(3,029		)
Basic income attributable to common stockholders	134,976			54,280			189,256
Reallocation of participating earnings (a)	115			46			161
Diluted income attributable to common stockholders	$	135,091		$	54,326		$	189,417

	Year Ended December 31, 2011
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	411,337		$	423,152		$	834,489
Participating basic earnings (a)	(7,482		)	(7,696		)	(15,178		)
Basic income attributable to common stockholders	403,855			415,456			819,311
Reallocation of participating earnings (a)	190			195			385
Diluted income attributable to common stockholders	$	404,045		$	415,651		$	819,696

	Year Ended December 31, 2010
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	471,158		$	134,050		$	605,208
Participating basic earnings (a)	(10,818		)	(3,078		)	(13,896		)
Basic net income attributable to common stockholders	460,340			130,972			591,312
Reallocation of participating earnings (a)	140			40			180
Diluted income attributable to common stockholders	$	460,480		$	131,012		$	591,492

 ______________________

(a) Unvested restricted stock awards and Pioneer Southwest phantom unit awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity owners of the Company or Pioneer Southwest, as applicable. Participating share- and unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually obligated to do so.

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 years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012	2011	2010
	(in thousands)
Weighted average common shares outstanding:
Basic	122,966	116,904	115,062
Dilutive common stock options (a)	183	190	212
Contingently issuable—performance shares	180	424	646
Convertible Senior Notes dilution (b)	2,991	1,697	410
Diluted	126,320	119,215	116,330

______________________

(a) Options to purchase 129,918 shares of the Company's common stock were excluded from the diluted income per share calculations for the year ended December 31, 2012 because they would have been anti-dilutive to the calculation.

(b) Weighted average common shares outstanding have been increased to reflect the dilutive effect that would have resulted if the Convertible Senior Notes had qualified for and been converted during the years ended December 31, 2012, 2011 and 2010, respectively.

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Consolidated Statements Of Comprehensive Income (Loss) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statement of Other Comprehensive Income [Abstract]
Net income (loss)	$ 242,822	$ 881,914	$ 645,995
Other comprehensive activity:
Net hedge gains included in continuing operations	4,855	(32,636)	(84,877)
Income tax provision	(1,725)	8,407	23,648
Other comprehensive activity	3,130	(24,229)	(61,229)
Comprehensive income (loss)	245,952	857,685	584,766
Comprehensive (income) loss attributable to the noncontrolling interests	(50,537)	(33,687)	(23,206)
Comprehensive income (loss) attributable to common stockholders	$ 195,415	$ 823,998	$ 561,560

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Other Expense (Schedule Of Components Of Other Expense) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Other Expense [Abstract]
Transportation commitment charge	$ 37,144	$ 23,248	$ 1,589
Above market drilling and rig termination costs	33,211	20,132	50,581
Other	18,297	12,603	9,924
Terminated Drilling Rig Expense	15,747	0	0
Inventory impairment	6,174	3,126	10,729
Business Combination, Acquisition Related Costs	2,337	0	0
Contingency and environmental accrual adjustments	478	4,057	5,581
Total other expense	$ 113,388	$ 63,166	$ 78,404

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Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

NOTE B.    Summary of Significant Accounting Policies

Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. In accordance with generally accepted accounting principles in the United States ("GAAP"), the Company proportionately consolidates certain affiliate partnerships that are less than wholly-owned and are involved in oil and gas producing activities. All material intercompany balances and transactions have been eliminated.

Certain reclassifications have been made to the 2011 and 2010 financial statement and footnote amounts in order to conform them to the 2012 presentations.

On May 6, 2008, the Company recognized a noncash gain on the sale of common units of Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest," a majority-owned and consolidated subsidiary) as a component of additional paid-in capital in stockholders' equity. In accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification Topic 740 Income Taxes, deferred income taxes of $49.1 million should be recognized for the future tax effects arising from the noncash gain on the sale of the Pioneer Southwest common units, with a corresponding decrease to additional paid-in capital. The Company recorded the deferred income taxes associated with this transaction in 2012. The effect of this adjustment is immaterial to the accompanying financial statements.

The accompanying consolidated balance sheet as of December 31, 2011 has been revised for a change in the classification of deferred income taxes associated with the Company's unrealized current derivative net gains as of December 31, 2011. The noncash revisions resulted in a $77.0 million decrease in current deferred tax assets, a $57.7 million increase in current deferred tax liabilities and a $134.7 million decrease in noncurrent deferred tax liabilities from the amounts previously reported at December 31, 2011. These revisions were made to appropriately reflect the impact on deferred income taxes based on the expected settlement periods related to derivatives, which remained subject to market risk as of December 31, 2011.

Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized.

Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less.

Accounts receivable. As of December 31, 2012 and 2011, the Company had accounts receivable – trade, net of allowances for bad debts, of $316.9 million and $276.0 million, respectively. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivable, joint interest receivables and other receivables for which the Company does not require collateral security.

As of December 31, 2012 and 2011, the Company's allowances for doubtful accounts totaled $1.5 million and $1.1 million, respectively. The Company establishes allowances for bad debts equal to the estimable portions of accounts and notes receivables for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable.

Inventories. The Company's inventories consist of materials and supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. "Market," in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. Valuation reserve allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supply inventories in the Company's consolidated balance sheets and as other expense in the accompanying consolidated statements of operations.

Commodities inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company's commodities inventories consist of oil held in storage and natural gas liquids ("NGLs") and gas pipeline fill volumes. Any valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations.

The following table presents the Company's materials and supplies and commodities inventories as of December 31, 2012 and 2011:

	Year Ended December 31,
	2012			2011
	(in thousands)
Materials and supplies (a)	$	258,962		$	297,910
Commodities	5,446			4,453
Less: Noncurrent materials and supplies (b)	(67,352		)	(60,754		)
	$	197,056		$	241,609

____________________

(a) As of December 31, 2012 and 2011, the Company's materials and supplies inventories were net of valuation reserve allowances of $4.6 million and $0.9 million, respectively.

(b) Included in other noncurrent assets in the Company's accompanying consolidated balance sheet.

Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. For large development projects requiring significant upfront development costs to support the drilling and production of a planned group of wells, the Company continues to capitalize interest on the portion of the development costs attributable to the planned wells yet to be drilled.

The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:

(i) The well has found a sufficient quantity of reserves to justify its completion as a producing well.

(ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note F for additional information regarding the Company's suspended exploratory well costs.

The Company owns interests in four gas processing plants and ten treating facilities. The Company is the operator of two of the gas processing plants and all ten of the treating facilities. The Company's ownership interests in the gas processing plants and treating facilities is primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third party revenues generated from the processing plants and treating facilities for the three years ended December 31, 2012, 2011 and 2010 were $39.4 million, $46.0 million and $34.0 million, respectively. Third party expenses attributable to the processing plants and treating facilities for the same respective periods were $27.1 million, $22.7 million and $14.3 million. The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service.

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base.

The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note D for additional information regarding the Company's proved property impairment provisions.

Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time. See Note D for additional information regarding impairment of Barnett Shale unproved properties.

Goodwill. During 2004, the Company recorded goodwill associated with a business combination, which represents the cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2012, the Company performed a qualitative assessment of goodwill. Financial Accounting Standards Board ("FASB") Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350) permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. Based upon the results of the assessment, the Company determined that it was not likely that the Company's goodwill was impaired.

Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2012 and 2011, respectively, the net carrying value of other property and equipment consisted of the following:

	Year Ended December 31,
	2012 (a)		2011 (a)
	(in thousands)
Proved and unproved sand properties	$	457,033	$	—
Equipment and rigs (b)	385,887		329,157
Land and buildings	259,629		160,795
Transportation equipment	44,928		28,108
Furniture and fixtures	43,614		34,567
Leasehold improvements	26,603		20,448
	$	1,217,694	$	573,075

____________________

(a) At December 31, 2012 and 2011, other property and equipment was net of accumulated depreciation of $395.9 million and $297.6 million, respectively.

(b) Includes drilling rigs, well servicing rigs and equipment and fracture stimulation equipment.

The Company's proved and unproved sand properties include sand mines, sales facilities and unproved leaseholds that primarily provide the Company and other unrelated customers with proppant used in the fracture stimulation of oil and gas wells. See Note C for additional information about the Company's sand mine operations. The Company's equipment and rigs include assets owned by subsidiaries that provide drilling, pumping and well services on Company-operated properties. The primary purposes of the Company's sand mines and drilling, pumping and well services operations are to accommodate the Company's drilling and producing operations by increasing the availability of supplies, equipment and services, rather than being dependent on third-party availability, and to contain associated costs. As of December 31, 2012, the Company owned 15 drilling rigs, ten fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. All intercompany gains or losses of the Company's sand mines and drilling, pumping and well services operations are eliminated. Earnings from sales of proppant and from providing drilling, pumping and well services to third-party customers and working interest owners in Company-operated properties are included in interest and other income in the accompanying consolidated statements of operations.

The capitalized costs of proved sand properties are depleted using the unit-of-production method based on proved sand reserves. Equipment items are generally depreciated by individual component on a straight line basis over their economic useful lives, which are generally from two to 12 years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases.

The Company evaluates other property and equipment for potential impairment whenever indicators of impairment are present. Circumstances that could indicate potential impairment include: significant adverse changes in industry trends and the economic outlook; legal actions; regulatory changes; and significant declines in utilization rates or oil and gas prices. If it is determined that other property and equipment is potentially impaired, the Company performs an impairment evaluation by estimating the future undiscounted net cash flow from the use and eventual disposition of other property and equipment grouped at the lowest level that cash flows can be identified. If the sum of the future undiscounted net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the assets' net book value over its estimated fair value.

Investment in unconsolidated affiliate. During 2010, the Company formed EFS Midstream LLC ("EFS Midstream") to own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play in South Texas. During June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an unaffiliated third party for $46.4 million of cash proceeds. Associated therewith, the Company recorded a $46.2 million deferred gain that is being amortized as a reduction in production costs over a 20 year period, representing the term of a continuing commitment of Pioneer to deliver production volumes through EFS Midstream handling and gathering facilities. The deferred gain is included in other current and noncurrent liabilities in the Company's accompanying consolidated balance sheet.

The Company does not have voting control of EFS Midstream. Consequently, the Company accounts for this investment under the equity method of accounting for investments in unconsolidated affiliates. Under the equity method, the Company's investment in unconsolidated affiliates is increased for investments made and the investor's share of the investee's net income, and decreased for distributions received, the carrying value of member interests sold and the investor's share of the investee's net losses.

The Company's equity interest in the net income or loss of EFS Midstream is recorded in interest and other income, net of eliminations of the profit associated with gathering, treating and transportation fees charged to the Company by EFS Midstream, in the accompanying consolidated statements of operations. See Note M for the Company's equity interest in the net income or loss of EFS Midstream for the years ended December 31, 2012, 2011 and 2010.

Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated.

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 and expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note I for additional information about the Company's asset retirement obligations.

Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.

Noncontrolling interest in consolidated subsidiaries. At December 31, 2012, the Company owned a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest. Pioneer Southwest owns interests in proved and unproved 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. On December 12, 2011, Pioneer Southwest completed the public offering of 4.4 million common units of Pioneer Southwest, representing limited partnership interests, at a per-unit offering price to the public of $29.20. Of the 4.4 million common units, Pioneer sold 1.8 million of its Pioneer Southwest common unit holdings and Pioneer Southwest issued 2.6 million of new common units. The common unit sale resulted in the Company's limited partnership interest in Pioneer Southwest decreasing from 61.9 percent to 52.4 percent.

In accordance with GAAP, the Company records transfers of any gains or losses, net of taxes, from noncontrolling interests in consolidated subsidiaries to additional paid in capital proportionate to the ownership after giving effect to the sale of common units. The following table presents the Company's net income or loss attributable to common stockholders adjusted for transfers from noncontrolling interest in consolidated subsidiaries to additional paid in capital attributable to Pioneer Southwest's common unit offerings:

	Year Ended December 31,
	2012			2011		2010
	(in thousands)
Net income attributable to common stockholders	$	192,285		$	834,489	$	605,208
Transfers from the noncontrolling interest in consolidated subsidiaries:
Increase in additional paid in capital from the sale of 1.8 million Pioneer Southwest common units during 2011, net of tax of $15.4 million	—			26,915		—
Increase in additional paid in capital from Pioneer Southwest's offering of 2.6 million common units during 2011, net of tax of $23.7 million	—			8,104		—
Decrease in additional paid in capital for deferred taxes recognized attributable to Pioneer Southwest's 2008 initial public offering of 9.5 million common units	(49,072		)	—		—
Net transfers from noncontrolling interest	(49,072		)	35,019		—
Net income attributable to common stockholders and transfers from noncontrolling interest	$	143,213		$	869,508	$	605,208

During January 2010, Pioneer Natural Resources USA, Inc. ("Pioneer USA," a wholly-owned subsidiary of the Company) formed Sendero Drilling Company, LLC ("Sendero"). Sendero was formed to own and operate land-based drilling rigs in the United States. As of December 31, 2012, Sendero owned 15 drilling rigs operating under contract to Pioneer USA in the Spraberry field. Pioneer USA is the majority owner of Sendero.

The Company also owns the majority interests in certain other subsidiaries with operations in the United States. Noncontrolling interests in the net assets of consolidated subsidiaries totaled $178.0 million and $162.3 million as of December 31, 2012 and 2011, respectively. The Company recorded net income attributable to the noncontrolling interests of $50.5 million, $47.4 million and $40.8 million for the years ended December 31, 2012, 2011 and 2010 (principally related to Pioneer Southwest), respectively.

Revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets.

The Company had no material oil or NGL entitlement assets or liabilities as of December 31, 2012 or 2011. The following table presents the Company's gas entitlement assets and liabilities with their associated volumes as of December 31, 2012 and 2011. Gas volumes are presented in millions of cubic feet ("MMCF").

	December 31,
	2012			2011
	Amount		Volume	Amount		Volume
	(dollars in millions)
Gas entitlement assets	$	6.8	2,870	$	7.6	3,024
Gas entitlement liabilities	$	1.9	582	$	2.6	650

The Company recognized revenue of $42.1 million, $45.0 million and $90.2 million during 2012, 2011 and 2010, respectively from volumetric production payment ("VPP") agreements which represented limited-term overriding royalty interests in oil reserves that: (i) entitled the purchaser to receive production volumes over a period of time from specific lease interests, (ii) were free and clear of all associated future production costs and capital expenditures associated with the reserves, (iii) were nonrecourse to the Company (i.e., the purchaser's only recourse was to the reserves acquired), (iv) transferred title of the reserves to the purchaser and (v) allowed the Company to retain the remaining reserves after the VPPs volumetric quantities had been delivered. All VPP production volumes have been delivered and thus there are no further obligations under VPP contracts or deferred revenue as of December 31, 2012.

Derivatives. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts. The effective portions of the discontinued deferred hedges as of February 1, 2009 were included in accumulated other comprehensive income (loss) – net deferred hedge gains (losses), net of tax ("AOCI - Hedging") and were transferred to earnings during the same periods in which the forecasted hedged transactions were recognized in the Company's earnings. During 2012, the remaining AOCI - Hedging was transferred to earnings. Since discontinuing hedge accounting, the Company has recognized all changes in the fair values of its derivative contracts 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 as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's and Pioneer Southwest's credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. Pioneer Southwest's credit-adjusted risk-free rate curve is based on independent market-quoted forward London Interbank Offered Rate ("LIBOR") curves plus 162.5 basis points, representing Pioneer Southwest's estimated borrowing rate. See Note E for additional information about the Company's derivative instruments.

Hurricane activity, net. As a result of Hurricane Rita in September 2005, the Company's East Cameron 322 facility, located on the Gulf of Mexico shelf, was completely destroyed. Operations to reclaim and abandon the East Cameron 322 facility began in 2006 and were completed during 2011.

In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues for the cost of reclamation and abandonment of the East Cameron 322 facility. During 2010, the Company and the insurance carriers agreed to settle the insurance policy dispute, resulting in an additional payment to the Company of $140.1 million during November 2010. Hurricane activity reclamation and abandonment charges were recorded when changes occurred in management's estimates of total reclamation and abandonment costs. Associated insurance recoveries were credited to net hurricane activity in the accompanying consolidated statement of operations in the periods in which claims recoveries were received.

Environmental. The Company's environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs.

Stock-based compensation. For stock-based compensation awards granted or modified, stock-based compensation expense is being recognized in the Company's financial statements on a straight line basis over the awards' vesting periods based on their fair values on the dates of grant. The stock-based compensation awards generally vest over a period not exceeding three years. The amount of stock-based compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant for the fair value of restricted stock, restricted stock units, partnership unit awards or phantom unit awards that are expected to be settled in the Company's common stock or Pioneer Southwest common units ("Equity Awards"), (iii) the Monte Carlo simulation method for the fair value of performance unit awards and (iv) a probabilistic forecasted fair value method for Series B unit awards issued by Sendero.

Stock-based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity shares or units ("Liability Awards"). Stock-based Liability Awards are recorded as accounts payable—affiliates based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to stock-based compensation expense.

Segments. Operating segments are defined as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

Based upon how the Company is organized and managed, the Company has only one reportable operating segment, which is oil and gas exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.

Assets held for sale and discontinued operations. On the date at which the Company meets all the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the assets or asset group to be sold and reclassifies the assets and related liabilities to be sold as held for sale on the accompanying consolidated balance sheets. The assets and liabilities are measured at the lower of their carrying amount or estimated fair value less cost to sell.

In addition, after determining that held for sale criteria has been met, the Company considers whether the held for sale assets meet the criteria to be considered discontinued operations. If the assets held for sale are considered discontinued operations, the Company classifies the results of operations from the assets held for sale as income or loss from discontinued operations, net of tax, in the accompanying consolidated statements of operations for the current period and all prior periods. See Note C for additional information about the Company's divestitures.

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Derivative Financial Instruments (Oil Derivative Contracts Volume And Weighted Average Price) (Details)	12 Months Ended
	Dec. 31, 2012 Rollfactor Swap Contracts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] 2013 - Swap Contracts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Fourteen Swap Contracts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Fifteen Swap Contracts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Thirteen Collar Contracts With Short Puts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Thirteen Collar Contracts With Short Puts [Member] Short Put [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Fourteen Collar Contracts With Short Puts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Fourteen Collar Contracts With Short Puts [Member] Short Put [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Fifteen Collar Contracts With Short Puts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Fifteen Collar Contracts With Short Puts [Member] Short Put [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Thirteen Rollfactor Swap Contracts [Member]	Feb. 13, 2013 Oil contracts, price per bbl [Member] Two Thousand Fourteen Rollfactor Swap Contracts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Fourteen Rollfactor Swap Contracts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Fifteen Rollfactor Swap Contracts [Member]	Feb. 13, 2013 Oil contracts, price per bbl [Member] Two Thousand And Thirteen Basis Swap Contracts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand And Thirteen Basis Swap Contracts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Fourteen Basis Swap Contracts [Member]	Dec. 31, 2012 Oil contracts, price per bbl [Member] Two Thousand Fifteen Basis Swap Contracts [Member]	Dec. 31, 2012 Oil contracts [Member] 2013 - Swap Contracts [Member] bbl	Dec. 31, 2012 Oil contracts [Member] Two Thousand Fourteen Swap Contracts [Member] bbl	Dec. 31, 2012 Oil contracts [Member] Two Thousand Fifteen Swap Contracts [Member] bbl	Dec. 31, 2012 Oil contracts [Member] Two Thousand Thirteen Collar Contracts With Short Puts [Member] bbl	Feb. 13, 2013 Oil contracts [Member] Two Thousand Fourteen Collar Contracts With Short Puts [Member] bbl	Dec. 31, 2012 Oil contracts [Member] Two Thousand Fourteen Collar Contracts With Short Puts [Member] bbl	Feb. 13, 2013 Oil contracts [Member] Two Thousand Fourteen Collar Contracts With Short Puts [Member] Short Put [Member]	Dec. 31, 2012 Oil contracts [Member] Two Thousand Fifteen Collar Contracts With Short Puts [Member] bbl	Dec. 31, 2012 Oil contracts [Member] Two Thousand Thirteen Rollfactor Swap Contracts [Member] bbl	Feb. 13, 2013 Oil contracts [Member] Two Thousand Fourteen Rollfactor Swap Contracts [Member] bbl	Dec. 31, 2012 Oil contracts [Member] Two Thousand Fourteen Rollfactor Swap Contracts [Member] bbl	Feb. 13, 2013 Oil contracts [Member] Two Thousand Fourteen Collar Contracts With Short Puts Replaced [Member] bbl	Dec. 31, 2012 Oil contracts [Member] Two Thousand Fourteen Collar Contracts With Short Puts Replaced [Member] bbl	Feb. 13, 2013 Oil contracts [Member] Two Thousand Fourteen Collar Contracts With Short Puts Replaced [Member] Short Put [Member]	Dec. 31, 2012 Oil contracts [Member] Two Thousand Fourteen Collar Contracts With Short Puts Replaced [Member] Short Put [Member]	Dec. 31, 2012 Oil contracts [Member] Two Thousand Fifteen Rollfactor Swap Contracts [Member] bbl	Feb. 13, 2013 Oil contracts [Member] Two Thousand And Thirteen Basis Swap Contracts [Member] bbl	Dec. 31, 2012 Oil contracts [Member] Two Thousand And Thirteen Basis Swap Contracts [Member] bbl	Dec. 31, 2012 Oil contracts [Member] Two Thousand Fourteen Basis Swap Contracts [Member] bbl	Dec. 31, 2012 Oil contracts [Member] Two Thousand Fifteen Basis Swap Contracts [Member] bbl
Trading Activity, Gains and Losses, Net [Line Items]
Average daily oil production derivative barrels per day																			3,000	0	0	71,029	9,000	60,000		26,000	6,000	15,000	0	5,000	5,000			0	1,000	2,055	0	0
Derivative, Swap Type, Average Fixed Price		81.02	0.00	0.00
Derivative, Average Cap Price					119.76		117.06		104.45														104.13							105.74	124.00
Derivative, Average Floor Price					92.27		92.67		95.00														95.00							100.00	90.00
Swap Multiple Second Nearby Month	0.6667
Swap Multiple Third Nearby Month	0.3333
Derivative, Nonmonetary Notional Amount, Price Per Unit						74.28		76.58		80.00	0.43	0.38	0.00	0.00	7.60	(5.75)	0.00	0.00							80.00							80.00	72.00

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Commitments And Contingencies (Future Minimum Lease Commitments) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
2013	$ 24,096
2014	17,434
2015	15,500
2016	14,202
2017	14,253
Thereafter	$ 36,967

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Incentive Plans (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012 Rate	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Participants annual salary contributions to 401(k) Plan, percentage	80.00%
Matching contributions percent	200.00%
Participants contribution limit for matching contribution, percentage	5.00%
Matching contributions vesting period in years	4
Compensation expense recognized as a result of matching contributions	$ 24,700,000	$ 18,300,000	$ 13,400,000
Unrecognized share-based compensation expense	131,100,000
Unvested share and unit based compensation plans, including attributable to Liability Awards	24,500,000
Restricted Units Vesting Schedule	3
Allocated Share-based Compensation Expense	62,750,000	41,673,000	40,185,000
Unfunded accumulated postretirement benefit obligations determined by actuaries	9,700,000	7,500,000
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option awards contract life	10
Average dividend yield	7
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercised, Intrinsic Value	17,200,000	1,500,000	6,900,000
Expected volatilities utilized remaining period	7 years 4 months 21 days
Weighted Average Grant-Date Fair Value, Shares granted	$ 56.29	$ 49.61	$ 23.79
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares or units as compensation to directors	1,153,029
Shares or units representing Liability Awards	240,486
Number of unvested shares	304,260
Fair value of shares for which restrictions lapsed	137,200,000	98,600,000	42,900,000
Amount of liabilities attributable to liability awards included in accounts payable	18,800,000	9,200,000
Fair value of shares-restrictions lapsed	14,200,000	6,700,000
Number of Units granted	912,543
Weighted Average Grant-Date Fair Value, Shares granted	$ 113.02	$ 97.52	$ 48.32
Performance Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of shares for which restrictions lapsed	18,800,000	44,700,000	27,400,000
Aggregate grant date fair values of the outstanding performance unit awards, per unit	$ 172.57	$ 134.68	$ 63.52
Service period for the performance unit awards, years	34
Pioneer Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	9,100,000
Pioneer Southwest LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	3,000,000
Restricted units to directors	7,496	6,812	8,744
Lapse of restrictions	200,000	342,000	324,000
Weighted Average Grant-Date Fair Value, Shares granted	$ 26.68	$ 29.35	$ 22.87
Deferred Compensation Retirement Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Each officer and key employee allowed contribution percent, base salary	25.00%
Each officer and key employee allowed contribution percent, annual bonus	100.00%
Matching contribution percentage	100.00%
Officer's contribution limit for matching contribution	10.00%
Key employee's contribution limit for matching contribution	8.00%
Matching contributions	2,400,000	2,200,000	1,900,000
Pioneer Southwest Ltip Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Grant-Date Fair Value, Shares granted	$ 28.00	$ 32.16	$ 22.74
Sendero B Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of key employees participated in restricted unit agreements			2
Number of Units granted			1,000
Grant date fair value			$ 5,100,000
Employee Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	1,250,000
Employee stock purchase plan contribution limit	15.00%
Employee stock purchase plan participants purchase price percent	15.00%

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Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Schedule of Inventory, Current [Table Text Block]

The following table presents the Company's materials and supplies and commodities inventories as of December 31, 2012 and 2011:

	Year Ended December 31,
	2012			2011
	(in thousands)
Materials and supplies (a)	$	258,962		$	297,910
Commodities	5,446			4,453
Less: Noncurrent materials and supplies (b)	(67,352		)	(60,754		)
	$	197,056		$	241,609

____________________

(a) As of December 31, 2012 and 2011, the Company's materials and supplies inventories were net of valuation reserve allowances of $4.6 million and $0.9 million, respectively.

Other Property Plant and Equipment [Table Text Block]

Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2012 and 2011, respectively, the net carrying value of other property and equipment consisted of the following:

	Year Ended December 31,
	2012 (a)		2011 (a)
	(in thousands)
Proved and unproved sand properties	$	457,033	$	—
Equipment and rigs (b)	385,887		329,157
Land and buildings	259,629		160,795
Transportation equipment	44,928		28,108
Furniture and fixtures	43,614		34,567
Leasehold improvements	26,603		20,448
	$	1,217,694	$	573,075

____________________

(a) At December 31, 2012 and 2011, other property and equipment was net of accumulated depreciation of $395.9 million and $297.6 million, respectively.

(b) Includes drilling rigs, well servicing rigs and equipment and fracture stimulation equipment.

Schedule of Other Ownership Interests [Table Text Block]

The following table presents the Company's net income or loss attributable to common stockholders adjusted for transfers from noncontrolling interest in consolidated subsidiaries to additional paid in capital attributable to Pioneer Southwest's common unit offerings:

	Year Ended December 31,
	2012			2011		2010
	(in thousands)
Net income attributable to common stockholders	$	192,285		$	834,489	$	605,208
Transfers from the noncontrolling interest in consolidated subsidiaries:
Increase in additional paid in capital from the sale of 1.8 million Pioneer Southwest common units during 2011, net of tax of $15.4 million	—			26,915		—
Increase in additional paid in capital from Pioneer Southwest's offering of 2.6 million common units during 2011, net of tax of $23.7 million	—			8,104		—
Decrease in additional paid in capital for deferred taxes recognized attributable to Pioneer Southwest's 2008 initial public offering of 9.5 million common units	(49,072		)	—		—
Net transfers from noncontrolling interest	(49,072		)	35,019		—
Net income attributable to common stockholders and transfers from noncontrolling interest	$	143,213		$	869,508	$	605,208

Oil Entitlement Assets and Liabilities [Table Text Block]

The following table presents the Company's gas entitlement assets and liabilities with their associated volumes as of December 31, 2012 and 2011. Gas volumes are presented in millions of cubic feet ("MMCF").

	December 31,
	2012			2011
	Amount		Volume	Amount		Volume
	(dollars in millions)
Gas entitlement assets	$	6.8	2,870	$	7.6	3,024
Gas entitlement liabilities	$	1.9	582	$	2.6	650

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Incentive Plans (Schedule Of Stock Options Awards Activity) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options exercised	(195,000)	(76,000)	(266,000)
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares, Outstanding at beginning of year	564,044
Number of Options awarded	98,819
Options exercised	(195,377)
Number of Shares, Outstanding and expected to vest at end of year	467,486
Number of Shares, Exercisable at end of year	171,644
Weighted Average Exercise Price, Outstanding at beginning of year	34.90
Weighted Average Exercise Price, Options awarded	113.76
Weighted Average Exercise Price, Options exercised	15.62
Weighted Average Exercise Price, Outstanding and expected to vest at end of year	59.63
Weighted Average Exercise Price, Exercisable at end of year	16.72
Weighted Average Remaining Contractual Life, Outstanding and expected to vest at end of year	7 years 4 months 21 days
Weighted Average Remaining Contractual Life, Exercisable at end of year	6 years 2 months 1 day
Aggregate Intrinsic Value, Outstanding and expected to vest at end of year	22,663
Aggregate Intrinsic Value, Exercisable at end of year	15,425

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Interest And Other Income (Tables)

12 Months Ended

Dec. 31, 2012

Interest and Other Income [Abstract]

Interest And Other Income

The following table provides the components of the Company's interest and other income during the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011		2010
	(in thousands)
Alaskan Petroleum Production Tax credits and refunds (a)	$	29,342		$	38,939	$	47,652
Other income	5,382			7,684		4,565
Equity interest in income (loss) of EFS Midstream	2,183			1,925		(819		)
Deferred compensation plan income	1,872			1,657		1,228
Interest income	1,465			697		4,177
Income (loss) from vertical integration services (b)	(11,934		)	15,978		169
Total interest and other income	$	28,310		$	66,880	$	56,972

 ______________________

(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 years ended December 31, 2012, 2011 and 2010, these net margins include $247.8 million, $50.9 million and $946 thousand of gross vertical integration revenues, respectively and $259.7 million, $34.9 million and $777 thousand of total vertical integration costs and expenses, respectively.

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Major Customer

12 Months Ended

Dec. 31, 2012

Major Customers And Derivative Counterparties [Abstract]

Major Customers

NOTE L.     Major Customers

The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts.

The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas revenues, including the revenues from discontinued operations, in at least one of the three years ended December 31, 2012. The loss of any one significant purchaser could have a material adverse effect on the ability of the Company to sell its oil and gas production. The table provides the percentages of the Company's consolidated oil, NGL and gas revenues represented by the purchasers during the periods presented:

	Year Ended December 31,
	2012		2011		2010
Plains Marketing LP	26	%	16	%	12	%
Enterprise Products Partners L.P.	15	%	12	%	10	%
Occidental Energy Marketing Inc	14	%	14	%	8	%