Form 10-K

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

10-K 1 d270523d10k.htm FORM 10-K Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2011

¨	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		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 x 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 x

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 x 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 x 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. x

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

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


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	$	10,243,708,609

Number of shares of Common Stock outstanding as of February 24, 2012	123,260,358

DOCUMENTS INCORPORATED BY REFERENCE:

(1)	Proxy Statement for the 2012 Annual Meeting of Shareholders to be held during May 2012 — Referenced in 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		28

Item 2.	Properties		28

	Reserve Rule Changes		28

	Reserve Estimation Procedures and Audits		28

	Proved Reserves		30

	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		46

	Financial and Operating Performance		46

	First Quarter 2012 Continuing Operations Outlook		47

	2012 Capital Budget		47

	Acquisitions		48

	Divestitures and Discontinued Operations		48

	Results of Operations		49

	Capital Commitments, Capital Resources and Liquidity		56

	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		70

	Index to Consolidated Financial Statements		70

	Report of Independent Registered Public Accounting Firm		71

	Consolidated Financial Statements		72

	Notes to Consolidated Financial Statements		79

	Unaudited Supplementary Information		119

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		127

Item 9A.	Controls and Procedures		127

	Management’s Report on Internal Control Over Financial Reporting		127

	Report of Independent Registered Public Accounting Firm		128

Item 9B.	Other Information		129

TABLE OF CONTENTS


PART III

Item 10.	Directors, Executive Officers and Corporate Governance	129

Item 11.	Executive Compensation	129

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	129

	Securities Authorized for Issuance Under Equity Compensation Plans	129

Item 13.	Certain Relationships and Related Transactions, and Director Independence	130

Item 14.	Principal Accounting Fees and Services	130

PART IV

Item 15.	Exhibits, Financial Statement Schedules	130

Signatures		137

Exhibit Index		138

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.

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“Bcf” means one billion cubic feet.

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“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.

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“BOEPD” means BOE per day.

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“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.

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“CBM” means coal bed methane.

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

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“DD&A” means depletion, depreciation and amortization.

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

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“GAAP” means accounting principles that are generally accepted in the United States of America.

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“LIBOR” means London Interbank Offered Rate, which is a market rate of interest.

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“LNG” means liquefied natural gas.

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“MBbl” means one thousand Bbls.

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“MBOE” means one thousand BOEs.

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“Mcf” means one thousand cubic feet and is a measure of gas volume.

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“MMBbl” means one million Bbls.

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“MMBOE” means one million BOEs.

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“MMBtu” means one million Btus.

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“MMcf” means one million cubic feet.

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“Mont Belvieu–posted-price” means the daily average natural gas liquids components as priced in Oil Price Information Service (“OPIS”) in the table “U.S. and Canada LP – Gas Weekly Averages” at Mont Belvieu, Texas.

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“NGL” means natural gas liquid.

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“NYMEX” means the New York Mercantile Exchange.

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“NYSE” means the New York Stock Exchange.

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“Pioneer” or the “Company” means Pioneer Natural Resources Company and its subsidiaries.

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“Pioneer Southwest” means Pioneer Southwest Energy Partners L.P. and its subsidiaries.

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“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 (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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“SEC” means the United States Securities and Exchange Commission.

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“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.

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“U.S.” means United States.

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“VPP” means volumetric production payment.

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

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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.

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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. 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, 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.

PIONEER NATURAL RESOURCES COMPANY

PART I

ITEM 1.

BUSINESS

General

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

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; Midland, Texas and Capetown, South Africa. At December 31, 2011, the Company had 3,304 employees, 2,282 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 Report 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 approximately 93 percent of the Company’s proved oil and gas reserves as of December 31, 2011.

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. Oil and NGL prices have steadily improved since the beginning of 2009, while gas prices have remained volatile and have generally trended lower since 2009. The decline in gas prices is primarily a result of growing gas production associated with discoveries of significant gas reserves in United States shale plays, combined with the warmer than normal 2011/2012 winter, which has resulted in gas storage levels being at historically high levels, and minimal economic demand growth in the United States.

PIONEER NATURAL RESOURCES COMPANY

During 2009, 2010 and 2011, economic stimulus initiatives implemented in the United States and worldwide served to stabilize the United States and certain other economies in the world with resulting improvements in industrial demand and consumer confidence. However, other economies, such as those of certain European Union (or “Eurozone”) nations, continue to face economic struggles. The outlook for a continued worldwide economic recovery is cautiously optimistic, but remains 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, especially North American gas prices, will continue to be volatile during 2012.

Significant factors that will impact 2012 commodity prices include: the ongoing impact of economic stimulus initiatives in the United States and worldwide and continuing economic struggles in Eurozone nations’ economies; 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 impact 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 impact the Company’s liquidity, financial position and future results of operations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Notes I and J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the impact to oil and gas revenues during 2011, 2010 and 2009 from the Company’s derivative price risk management activities and the Company’s open derivative positions as of December 31, 2011.

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. Additionally, the Company has a team of dedicated employees that represent the professional disciplines and sciences that 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 United States and South Africa subsidiaries that explore for, develop and produce proved reserves. The Company’s continuing operations are principally located in the United States 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, 2011, the Company’s production from continuing operations, excluding field fuel usage, of 44.0 MMBOE represented a 16 percent increase over production from continuing operations during 2010. Production, price and cost information with respect to the Company’s properties for 2011, 2010 and 2009 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, 2011, the Company drilled 1,236 gross (1,112 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 $2.5 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, 2011 include proved

PIONEER NATURAL RESOURCES COMPANY

undeveloped reserves and proved developed reserves that are behind pipe of 259.0 MMBbls of oil, 98.7 MMBbls of NGLs and 850.8 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 portfolio of lower-risk exploration opportunities. Exploratory and extension drilling involve greater risks of dry holes or failure to find 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 costs and support the execution of its accelerating drilling program. The Company has 15 owned drilling rigs operating in the Spraberry field, and at the end of 2011, had Company-owned fracture stimulation fleets totaling 250,000 horsepower supporting drilling operations in the Spraberry, Eagle Ford Shale and Barnett Shale Combo areas. 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 2011, 2010 and 2009, the Company spent $131.9 million, $181.6 million and $88.9 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.

During December 2011, the Company committed to a plan to divest its South Africa assets (“Pioneer South Africa”). The plan is expected to result in the sale of Pioneer South Africa assets during 2012. In accordance with GAAP, the Company has classified its South Africa assets and liabilities as discontinued operations held for sale in the Company’s accompanying consolidated balance sheet as of December 31, 2011, and has recast Pioneer South Africa’s results of operations as income from discontinued operations, net of tax in the Company’s accompanying consolidated statements of operations.

During February 2011, the Company completed the sale of its share holdings in Pioneer Natural Resources Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as “Pioneer Tunisia”) for cash proceeds of $853.6 million, including normal closing adjustments. As a result of having committed to a plan to sell the Tunisian subsidiaries during 2010, the Company classified its Tunisian assets and liabilities as discontinued operations held for sale in the Company’s accompanying consolidated balance sheet as of December 31, 2010, and recorded the historical results of operations of its Tunisian assets as income from discontinued operations, net of tax in the Company’s 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

PIONEER NATURAL RESOURCES COMPANY

improve profitability. See Notes M and U 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 planned 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 2011, the Company’s significant purchasers of oil, NGLs and gas were Plains Marketing LP (16 percent), Occidental Energy Marketing Inc. (14 percent) and Enterprise Products Partners L.P. (12 percent). The Company believes that the loss of any one purchaser would not have an adverse effect on its ability to sell its oil, NGL and gas production.

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, (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. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts and began accounting 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 I 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 2011, 2010 and 2009, as well as the Company’s open commodity derivative positions at December 31, 2011.

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 of the Company’s common stock. Compliance with some of these rules and regulations is costly, and regulations are subject to change or reinterpretation.

PIONEER NATURAL RESOURCES COMPANY

Environmental matters and regulations. The Company’s operations are subject to stringent and complex foreign, federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

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require the acquisition of various permits before drilling commences;

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enjoin some or all of the operations of facilities deemed in non-compliance with permits;

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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;

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

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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 United States Congress and state legislatures, federal and state regulatory agencies and foreign government and agencies frequently revise environmental laws and regulations, and the clear 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 impact on the Company’s operating costs.

The following is a summary of some of the laws, rules and regulations to which the Company’s business operations are or may be subject.

Waste handling. The 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. Certain processes used to produce oil and gas may enhance the radioactivity of NORM, which may be present in oilfield wastes. 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 Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes 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.

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 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 disposal. In addition, some of the Company’s properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons were not under the Company’s control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by the Company. These 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.

Water discharges and use. The 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. 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. Spill prevention, control and countermeasure 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 non-compliance 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.

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 many of its drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions. The EPA, however, recently asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the SDWA Underground Injection Control Program. In addition, legislation has been introduced before the United States Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. The Company believes that it follows applicable standard industry practices and legal requirements for groundwater protection in its hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the

PIONEER NATURAL RESOURCES COMPANY

Company operates, the Company could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or proposed 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 a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results 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 ongoing or proposed 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.

To the Company’s knowledge, there have been no citations, suits or contamination of potable drinking water arising from its fracturing operations. The Company does not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, the Company believes its existing insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses, subject to the terms of such policies.

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 Federal Clean Air Act (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 non-compliance 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. In addition, 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. Gas and oil exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

PIONEER NATURAL RESOURCES COMPANY

In July 2011, the EPA issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs. The EPA’s proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with the flaring of gas. If finalized, these rules could require a number of modifications to the Company’s operations, including the installation of new equipment. Compliance with such rules could result in significant new costs to the Company and make it more costly and time-consuming to complete oil and gas wells. Any delay or decrease in the completion of new oil and gas wells could have a material adverse effect on the Company’s liquidity, results of operations and financial condition. Moreover, 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. The TCEQ may expand the application of the requirements to facilities in other areas of the state in 2012. These new requirements could increase the cost and time associated with drilling wells in the Barnett Shale or other areas of the state in the future. 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 the state that result in more stringent drilling or operating conditions or limit or prohibit the drilling of new gas wells for any extended period of time could increase the Company’s costs and/or reduce its production, which could have a material adverse effect on the Company’s results of operations and cash flows.

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 and/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 of or limitations on the Company’s ability to perform operations and thus have an adverse effect on the Company’s business.

The United States Fish and Wildlife Service has proposed listing the Dunes Sagebrush Lizard as endangered under the ESA and expects to make a final determination on the listing by June 2012. Some of the Company’s operations in the Permian Basin are located in or near areas that may potentially be designated as Dunes Sagebrush Lizard habitat. If the lizard is classified as an endangered species, the Company’s operations in any area that is designated as the lizard’s habitat may be limited, delayed or, in some circumstances, prohibited, and the Company may be required to comply with expensive mitigation measures intended to protect the lizard and its habitat. 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 under the ESA and issue decisions with respect to the 250 candidate species over the next several years. The designation of previously unprotected species in areas where the Company operates as threatened or endangered 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 reserves.

Health and safety. The Company’s operations are subject to the requirements of the federal Occupational Safety and Health Act (the “OSH Act”) and comparable state statutes. These laws and the related regulations strictly govern the protection of the health and safety of employees. The OSH Act 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. The Company believes that it is in substantial compliance with these applicable requirements and with other OSH Act 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,” or “GHGs,” present an endangerment to public

PIONEER NATURAL RESOURCES COMPANY

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. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA adopted two sets of rules that regulate greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources. The EPA has also adopted rules requiring the reporting, on an annual basis, of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries, as well as certain oil and gas production facilities. The Company is monitoring GHG emissions from its operations in accordance with the GHG emissions reporting rule and believes its monitoring activities are in substantial compliance with applicable reporting obligations.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. 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. It should be noted that 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.

Finally, other nations have been seeking to reduce emissions of GHGs pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of GHGs. Depending on the particular jurisdiction in which the Company’s operations are located, it could be required to purchase and surrender allowances for GHG emissions resulting from the Company’s operations.

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 instance, the Company did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2011. Additionally, the Company is not aware of any environmental issues or claims that will require material capital expenditures during 2012. However, 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.

Other regulation of the oil and gas industry. The oil and gas industry is regulated by numerous foreign, 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, state and foreign 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 foreign, federal, state and local levels. These types of regulation include requiring permits for the

PIONEER NATURAL RESOURCES COMPANY

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:

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the location of wells;

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the method of drilling and casing wells;

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the method and ability to fracture stimulate wells;

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

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the plugging and abandoning of wells; and

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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.

Regulation of transportation and sale of gas. The availability, terms and cost of transportation significantly affect sales of gas. Foreign, 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, including the Railroad Commission of Texas (the “TRRC”). 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”). Since 1985, FERC has endeavored to make gas transportation more accessible to gas buyers and sellers on an open 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 for violations of the NGA up to $1.0 million per day per violation. The anti-manipulation rule applies to activities of otherwise non-jurisdictional entities 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 rules (“Order 704”) requiring that 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 during a calendar year annually report such sales and purchases to FERC. 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.

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

PIONEER NATURAL RESOURCES COMPANY

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 impacted by the rates charged by such third parties for gathering services. To the extent that changes in foreign, federal and/or state regulation affect the rates charged for gathering services, the Company also may be affected by such 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 availability, terms and cost of transportation significantly affect sales of oil and NGLs. Foreign, federal and state regulations govern the price and terms for access to pipeline transportation of oil and NGLs. Intrastate pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies, including the TRRC. Interstate common carrier pipeline operations are subject to rate regulation by FERC under the Interstate Commerce Act (the “ICA”). The ICA requires that tariff rates for petroleum pipelines, which include both oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory.

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 United States 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 United States 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 Pioneer’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:

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

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

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gas inventory levels in the United States;

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weather conditions;

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overall domestic and global political and economic conditions;

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

PIONEER NATURAL RESOURCES COMPANY

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the effect of LNG deliveries to the United States;

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technological advances affecting energy consumption and energy supply;

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domestic and foreign governmental regulations and taxation;

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the effect of energy conservation efforts;

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

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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 2011, oil prices fluctuated from a high of $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. During 2010, oil prices fluctuated from a low of $68.01 per Bbl in May to a high of $91.51 per Bbl in December, while gas prices fluctuated from a high of $6.01 per Mcf in January to a low of $3.29 per Mcf in October. 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.

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 statement of operations each quarter, which may result in significant net gains or losses. These derivative contracts may also expose the Company to risk of financial loss in certain circumstances, including when:

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production is less than the contracted derivative volumes;

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

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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 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.

PIONEER NATURAL RESOURCES COMPANY

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:

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unexpected drilling conditions;

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unexpected pressure or irregularities in formations;

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equipment failures or accidents;

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fracture stimulation accidents or failures;

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adverse weather conditions;

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restricted access to land for drilling or laying pipelines; and

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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 2012.

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 estimated fair value. For example, during 2011 and 2009, the Company recognized impairment charges of $354.4 million and $21.1 million, respectively, due to the impairment of the Company’s Edwards and Austin Chalk gas fields in South Texas and the Uinta/Piceance area in Colorado, 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, 2011, the Company carried unproved property costs of $235.5 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, 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 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:

PIONEER NATURAL RESOURCES COMPANY

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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;

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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;

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the validity of assumptions about costs, including synergies;

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the impact on the Company’s liquidity or financial leverage of using available cash or debt to finance acquisitions;

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

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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 may be unable to dispose of nonstrategic assets on attractive terms, and may be required to retain liabilities for certain matters.

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 nonstrategic assets or complete announced dispositions, including the availability of purchasers willing to purchase the nonstrategic assets at prices acceptable to the Company. 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 sale, 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 periodically evaluates its goodwill for impairment and could be required to recognize noncash charges in the earnings of future periods.

At December 31, 2011, the Company carried goodwill of $298.1 million associated with its United States reporting unit. 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 related to the Company’s United States reporting unit. 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 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’s gas processing operations are subject to operational risks, which could result in significant damages and the loss of revenue.

As of December 31, 2011, the Company owned interests in four gas processing plants and ten treating facilities. The Company operates 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.

PIONEER NATURAL RESOURCES COMPANY

The Company’s operations involve many operational risks, some of which could result in substantial losses to the Company and unforeseen interruptions to the Company’s operations 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:

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blowouts, cratering, explosions and fires;

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adverse weather effects;

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environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases, brine, well stimulation and completion fluids or other pollutants in to the surface and subsurface environment;

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high costs, shortages or delivery delays of equipment, labor or other services;

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facility or equipment malfunctions, failures or accidents;

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title problems;

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pipe or cement failures or casing collapses;

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compliance with environmental and other governmental requirements;

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lost or damaged oilfield workover and service tools;

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

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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. 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, gas gathering, transportation, storage and processing facilities to market its oil, NGL and gas production.

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 and refining facilities, as well as the existence of adequate markets. If there were insufficient capacity available on these systems, or if these systems were unavailable to the Company, 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 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 processing facilities to the Company, especially in areas of planned expansion where such facilities do not currently exist.

PIONEER NATURAL RESOURCES COMPANY

The nature of the Company’s assets and operations exposes it to significant costs and liabilities with respect to environmental and operational 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 and ruptures and discharges of substances or gases that could expose the Company to substantial liability due to pollution and other environmental damage. A variety of United States federal, state and local, as well as foreign 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 matters and regulations” above for additional discussion related to environmental risks.

No assurance can be given that existing or future environmental laws 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. Pollution and similar environmental risks generally are not fully insurable.

The Company’s credit facility 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, senior convertible notes and a credit facility. The terms of the Company’s borrowings under the senior notes, senior convertible notes and the credit facility 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 E 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, 2011 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.

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:

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

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marketing oil, NGL and gas production; and

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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, local and foreign laws and regulations. For instance, the TCEQ recently adopted rules establishing new air emissions limitations and permitting requirements for oil and gas activities in the Barnett Shale area, which may increase the cost and time associated with drilling wells in that area. In addition, 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 and NGLs, and any derivative activities related to such energy commodities, expose the Company to potential regulatory risks.

FERC, the Federal Trade Commission and the Commodity Futures Trading Commission (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 and NGLs, 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 financial condition or results of operations.

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:

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

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the quality and quantity of available data;

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the interpretation of that data;

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the assumed effects of regulations by governmental agencies;

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assumptions concerning future commodity prices; and

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

PIONEER NATURAL RESOURCES COMPANY

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:

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the quantities of oil and gas that are ultimately recovered;

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the production costs incurred to recover the reserves;

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the amount and timing of future development expenditures; and

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future commodity prices.

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:

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the amount and timing of actual production;

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levels of future capital spending;

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

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changes in governmental regulations or taxation.

The Company reports all proved reserves held under concessions utilizing the “economic interest” method, which excludes the host country’s share of proved reserves. Estimated quantities reported under the “economic interest” method are subject to fluctuations in commodity prices and recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices.

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.

PIONEER NATURAL RESOURCES COMPANY

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% limited partner interest and a 0.1% 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 United States Congress have from time to time considered substantive changes to the existing federal income tax laws that 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 was 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 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.

PIONEER NATURAL RESOURCES COMPANY

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 markets, the availability of credit and the equity markets have improved during 2010 and 2011, the economic outlook for 2012 remains uncertain. 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 United States 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 the Eurozone 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 United States 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 United States tax laws, including elimination of certain key United States 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 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 United States 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.

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

During 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 two sets of rules that regulate greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources. The EPA has also adopted rules requiring the reporting, on an annual basis, of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries as well as certain oil and gas production facilities. The Company is monitoring GHG emissions from its operations in accordance with the GHG emissions reporting rule and believes that its monitoring activities are in substantial compliance with applicable reporting obligations.

PIONEER NATURAL RESOURCES COMPANY

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. 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. Finally, it should be noted that 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.”

The recent adoption of derivatives legislation by the United States Congress 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 United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President in July 2010 and requires the CFTC and the SEC to promulgate rules and regulations to implement the new legislation. In December 2011, the CFTC extended temporary exemptive relief from certain regulations applicable to swaps until no later than July 16, 2012. 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. It is not possible at this time to predict when the CFTC will make these regulations effective. The financial reform legislation may also require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivatives activities, although the application of those provisions to the Company is uncertain at this time. The financial reform legislation may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The legislation 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 legislation and regulations, 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 legislation 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 legislation and 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 and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

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 many of its drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions. The EPA, however, recently asserted federal regulatory authority over hydraulic fracturing involving diesels under the SDWA’s Underground Injection Control Program. Moreover, the EPA issued proposed rules in July 2011 that would subject oil and gas production activities to regulation under the NSPS air emissions program, including, among other things, the implementation of standards for reduced emission completion techniques to be used during hydraulic fracturing activities. In addition, legislation has been introduced before the United States Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the

PIONEER NATURAL RESOURCES COMPANY

chemicals used in the fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Company operates, it could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed 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 a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results 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 ongoing or proposed 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.

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 impact 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 strategy is to expand drilling activity in areas in which industry activity has increased rapidly, particularly in the Spraberry field area, the Eagle Ford Shale play in South Texas and the Barnett Shale Combo play in North Texas. As a result, demand for personnel, equipment, hydraulic fracturing services, proppant for fracture stimulation operations, water and other services and resources, as well as access to transportation, processing and refining facilities in these areas has increased, as has the costs for those items. A delay or inability to secure the personnel, equipment, services, resources and facilities access necessary for the Company to complete its development activities as planned could result in a rate of oil and gas production below the rate forecasted, and significant increases in costs would impact 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 state and federal 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 United States 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 may seek damages and, in some cases, criminal penalties. The United States Fish and Wildlife Service has proposed listing the Dunes Sagebrush Lizard as endangered under the ESA and expects to make a final determination on the listing by June 2012. Some of the Company’s operations in the Permian Basin are located in or near areas that may potentially be designated as Dunes Sagebrush Lizard habitat. If the lizard is

PIONEER NATURAL RESOURCES COMPANY

classified as an endangered species, the Company’s operations in any area that is designated as the lizard’s habitat may be limited, delayed or, in some circumstances, prohibited, and the Company may be required to comply with expensive mitigation measures intended to protect the lizard and its habitat.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

As of December 31, 2011, the Company did not have any SEC staff comments that have been unresolved for more than 180 days.

ITEM 2.

PROPERTIES

Reserve Rule Changes

During 2009, the SEC issued its final rule on the modernization of oil and gas reporting (the “Reserve Ruling”) and, during 2010, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update No. 2010-03 (“ASU 2010-03”) “Extractive Industries – Oil and Gas,” which aligned the estimation and disclosure requirements of FASB Accounting Standards Codification Topic 932 with the Reserve Ruling. The Reserve Ruling and ASU 2010-03 became effective for Annual Reports on Form 10-K for fiscal years ending on or after December 31, 2009. The key provisions of the Reserve Ruling and ASU 2010-03 are as follows:

•

Expanding the definition of oil- and gas-producing activities to include the extraction of saleable hydrocarbons, in the solid, liquid or gaseous state, from oil sands, coalbeds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction;

•

Amending the definition of proved oil and gas reserves to require the use of an average of the first-day-of-the-month commodity prices during the 12-month period ending on the balance sheet date rather than period-end commodity prices;

•

Adding to and amending other definitions used in estimating proved oil and gas reserves, such as “reliable technology” and “reasonable certainty;”

•

Broadening the types of technology that a reporter may use to establish reserves estimates and categories; and

•

Changing disclosure requirements and providing formats for tabular reserve disclosures.

Reserve Estimation Procedures and Audits

The information included in this Report about the Company’s proved reserves as of December 31, 2011, 2010 and 2009, which were located in the United States, South Africa and Tunisia, is based on evaluations prepared by (i) the Company’s engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), with respect to the Company’s major properties, and (ii) the Company’s engineers, with respect to all other properties. 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 Notes B and U 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, which owned the Company’s Tunisia proved reserves.

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.

The management of Pioneer’s oil and gas assets is decentralized geographically by individual asset teams who are responsible for the oil and gas activities in each of the Company’s Permian Basin, Rockies, Mid-Continent, South Texas—Eagle Ford Shale, South Texas—Edwards, Barnett Shale, Alaska and Africa asset teams (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 Chief Operating Officer (“COO”) and management committee (“MC”). The Company’s MC is comprised of its Chief Executive Officer, COO, 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.

PIONEER NATURAL RESOURCES COMPANY

The reserve estimates are summarized in reserve reconciliations that quantify reserve changes since the previous year end by 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 NSAI (for the portion of the reserves audited by NSAI) 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 on the Reserve Ruling 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 in the aggregate represented 90 percent, 90 percent and 93 percent of the Company’s 2011, 2010 and 2009 proved reserves, respectively; and, 91 percent, 79 percent and 86 percent of the Company’s 2011, 2010 and 2009 associated pre-tax present value of proved reserves discounted at ten percent, respectively.

NSAI follows 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 its external and internal engineering and geoscience technical data and analyses. Following NSAI’s review of that data, it had the option of honoring Pioneer’s interpretation, or making its own interpretation. No data was withheld from NSAI. NSAI 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 its evaluation something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.

In the course of its evaluations, NSAI prepared, for all of the audited properties, its own estimates of the Company’s proved reserves and the pre-tax present value of such reserves discounted at ten percent. NSAI reviewed its audit differences with the Company, and, in a number of cases, held joint meetings with the Company to review additional reserves work performed by the 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. NSAI’s 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 NSAI and some were less than the estimates of NSAI. When such differences do not exceed ten percent in the aggregate and NSAI is satisfied that the proved reserves and pre-tax

PIONEER NATURAL RESOURCES COMPANY

present value of such reserves discounted at ten percent are reasonable and that its audit objectives have been met, NSAI 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 NSAI. At the conclusion of the audit process, it was NSAI’s opinion, as set forth in its audit letter, which is included as an exhibit to this Report, that Pioneer’s estimates of the Company’s proved oil and gas reserves and associated pre-tax present value 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 34 years of experience as a petroleum engineer, with 27 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 (“CFA”) and a member of the Oil and Gas Reserves Committee of the SPE.

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 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 33 years of practical experience in petroleum engineering, including 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.

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 is 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.

Proved Reserves

The Company’s proved reserves totaled 1,063 MMBOE, 1,011 MMBOE and 899 MMBOE at December 31, 2011, 2010 and 2009, respectively, representing $7.8 billion, $5.4 billion and $3.3 billion, respectively, of Standardized Measure. The Company’s proved reserves include field fuel, which is gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point.

PIONEER NATURAL RESOURCES COMPANY

The following table shows the changes in the Company’s proved reserve volumes by geographic area during the year ended December 31, 2011 (in MBOE):


	Production			Extensions and Discoveries		Improved Recovery		Purchases of Minerals-in- Place		Sales of Minerals-in- Place			Revisions of Previous Estimates
United States		(46,907	)		155,728		1,394		4,435		—			(38,328	)
South Africa		(1,445	)		585		—		—		—			315
Tunisia		(230	)		—		—		—		(23,447	)		—

Total		(48,582	)		156,313		1,394		4,435		(23,447	)		(38,013	)

Production. Production volumes include 2,954 MBOE of field fuel.

Extensions and discoveries. Extensions and discoveries are primarily comprised of extensions in the Spraberry field and discoveries in the Eagle Ford Shale and Barnett Shale Combo plays.

Improved recovery. Additions from improved recovery relate to recognizing secondary recovery reserves attributable to waterflooding the Nuiqsut horizon of the Alaskan Oooguruk development project.

Purchases of minerals-in-place. Purchases of minerals-in-place are primarily attributable to acquisitions in the Company’s Spraberry field.

Sales of minerals-in-place. Sales of minerals-in-place are related to the divestment of Pioneer Tunisia. See Notes M and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

Revisions of previous estimates. Revisions of previous estimates are comprised of 28 MMBOE of negative price revisions and 10 MMBOE of negative revisions due to updated performance profiles and cost estimates. The Company’s proved reserves at December 31, 2011 were determined using an average of the NYMEX spot prices for sales of oil and gas on the first calendar day of each month during 2011. On this basis, the NYMEX price for oil and gas for proved reserve reporting purposes at December 31, 2011 was $96.13 per barrel of oil and $4.12 per Mcf of gas, compared to the comparable average NYMEX prices of $79.28 per barrel of oil and $4.37 per Mcf of gas at December 31, 2010.

Tabular proved reserves disclosures. On a BOE basis, 58 percent of the Company’s total proved reserves at December 31, 2011 were proved developed reserves.

The following table provides information regarding the Company’s proved reserves and standardized measure by geographic area as of and for the year ended December 31, 2011:


	Summary of Oil and Gas Reserves as of December 31, 2011 Based on Average Fiscal Year Prices
	Oil (MBbls)		NGLs (MBbls)		Gas (MMcf) (a)		MBOE		Standardized Measure
	(in thousands)
Developed:
United States		189,975		120,405		1,840,697		617,164	$	5,453,321
South Africa		231		—		12,666		2,342		40,686

		190,206		120,405		1,853,363		619,506		5,494,007

Undeveloped:
United States		239,799		90,630		677,675		443,375		2,319,016

Total Proved		430,005		211,035		2,531,038		1,062,881	$	7,813,023

(a)	The gas reserves contain 301,123 MMcf of gas that will be produced and utilized as field fuel.

PIONEER NATURAL RESOURCES COMPANY

Proved undeveloped reserves. The following table summarizes the Company’s proved undeveloped reserves activity during the year ended December 31, 2011 (in MBOE):


Beginning proved undeveloped reserves	433,244
Extensions and discoveries	103,224
Purchases of minerals-in-place	4,345
Improved recovery	1,274
Revisions of previous estimates	(28,582	)
Transfers to proved developed	(62,436	)
Sales of minerals-in-place	(7,694	)

Ending proved undeveloped reserves	443,375

As of December 31, 2011, the Company had 4,599 proved undeveloped well locations (all of which are expected to be developed during the five year period ending December 31, 2016), as compared to 4,727 and 4,582 at December 31, 2010 and 2009, respectively. The changes in proved undeveloped reserves during 2011 are comprised of the following items:

Extensions and discoveries. Extensions and discoveries are primarily comprised of extensions in the Spraberry field and discoveries in the Eagle Ford Shale and Barnett Shale Combo plays.

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.

Revisions of previous estimates. Revisions of previous estimates are comprised of 34 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 5 MMBOE of positive technical revisions, primarily in the Spraberry field.

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 2011.

Sales of minerals-in-place. Sales of minerals-in-place are primarily related to the divestment of Pioneer Tunisia.

During 2011, the Company added approximately 32 MMBOE of proved undeveloped reserves for locations that are more than one location removed from developed locations in the Spraberry field. 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 our internal core analysis facility. After the geologic area was shown to be continuous, statistical analysis of existing producing wells was conducted to generate area of reasonable certainty at distances from established production. As a result of this analysis, proved undeveloped reserves for drilling locations within this area of reasonable certainty were recorded during 2011.

The Company’s proved undeveloped reserves and well locations that have remained undeveloped for five years or more decreased during the year ended December 31, 2011 by 38 percent and 42 percent, respectively, to 80 MMBOE of proved undeveloped reserves and 858 well locations compared to 130 MMBOE and 1,467 locations at year end 2010. The Company’s inventory of proved undeveloped reserves and well locations that have remained undeveloped for five years or more is decreasing as a result of the Company’s annual increases in its capital expenditures since 2009. The Company’s proved undeveloped reserves and well locations that have remained undeveloped for five years or more are all located in the Spraberry field where approximately 70 percent of the Company’s $2.5 billion capital budget for 2012 is expected to be spent.

PIONEER NATURAL RESOURCES COMPANY

Based on management’s commodity price outlook, the Company expects that future operating cash flows will provide adequate funding for future development of its proved undeveloped reserves within the next five years. The following table represents the estimated timing and cash flows of developing the Company’s proved undeveloped reserves as of December 31, 2011 (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
2012		5,193	$	385,942	$	55,517	$	1,152,395	$	(821,970	)
2013		15,707		1,118,140		160,479		1,488,576		(530,915	)
2014		23,504		1,609,820		251,653		1,577,529		(219,362	)
2015		29,475		1,997,551		336,961		1,546,016		114,574
2016		33,783		2,229,206		411,086		1,466,408		351,712
Thereafter (b)		335,713		21,710,831		6,501,238		321,791		14,887,802

		443,375	$	29,051,490	$	7,716,934	$	7,552,715	$	13,781,841

(a)	Production and cash flows represent the drilling results from the respective year plus the incremental effects of proved undeveloped drilling.

(b)	The $321.8 million of future development costs includes (i) $125.3 million of completion costs forecasted in 2017 and (ii) $196.5 million of net abandonment costs in future years.

Description of Properties

United States

Approximately 83 percent of the Company’s proved reserves at December 31, 2011 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, Raton field, Eagle Ford Shale play, Barnett Shale Combo play and Alaska.

The following tables summarize the Company’s United States development and exploration/extension drilling activities during 2011:


	Development Drilling
	Beginning Wells In Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Ending Wells In Progress
Permian Basin		144		696		668		11		161
Mid-Continent		—		2		2		—		—
Raton Basin		—		57		52		—		5
South Texas—Edwards and Austin Chalk		1		1		2		—		—
Alaska		1		1		1		—		1

Total United States		146		757		725		11		167

PIONEER NATURAL RESOURCES COMPANY


	Exploration/Extension Drilling
	Beginning Wells In Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Ending Wells In Progress
Permian Basin		3		24		27		—		—
Mid-Continent		—		5		—		—		5
South Texas—Eagle Ford Shale		22		111		94		—		39
South Texas—Edwards and Austin Chalk		2		1		2		1		—
Barnett Shale		11		59		44		—		26
Alaska		—		1		—		—		1

Total United States		38		201		167		1		71

The following table summarizes the Company’s United States average daily oil, NGL, gas and total production by asset area during 2011:


	Oil (Bbls)		NGLs (Bbls)		Gas (Mcf) (a)		Total (BOE)
Permian Basin		27,514		11,027		47,600		46,475
Mid-Continent		3,593		7,107		51,291		19,249
Raton Basin		—		—		160,550		26,758
Barnett Shale		598		1,369		11,013		3,803
South Texas—Eagle Ford Shale		4,383		2,982		28,020		12,035
South Texas—Edwards and Austin Chalk		93		1		45,324		7,648
Alaska		4,432		—		—		4,432
Other		5		1		81		18

Total United States		40,618		22,487		343,879		120,418

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

The following table summarizes the Company’s United States costs incurred by geographic area during 2011:


	Property Acquisition Costs				Exploration		Development			Asset Retirement
	Proved		Unproved		Costs		Costs			Obligations			Total
	(in thousands)
Permian Basin	$	7,252	$	30,954	$	98,318	$	1,254,454		$	3,902		$	1,394,880
Mid-Continent		14		9,955		7,112		15,710			1,797			34,588
Raton Basin		210		25		7,401		58,107			(698	)		65,045
South Texas—Eagle Ford Shale		—		26,263		136,985		4,793			5,959			174,000
South Texas—Edwards and Austin Chalk		—		1,707		13,628		10,881			6,239			32,455
Barnett Shale		69		44,006		258,446		14,421			3,042			319,984
Alaska		20		32		32,140		90,120	(a)		3,319			125,631
Other		—		11,384		4,784		—			(456	)		15,712

Total United States	$	7,565	$	124,326	$	558,814	$	1,448,486		$	23,104		$	2,162,295

(a)	Includes $13.4 million of capitalized interest related to the Oooguruk 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

PIONEER NATURAL RESOURCES COMPANY

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

During 2011, the Company drilled 706 wells in the Spraberry field and its total acreage position now approximates 820,000 gross acres (691,000 net acres). For 2012, the Company plans to drill approximately 750 vertical wells. The Company currently has 44 rigs operating, of which 41 are drilling vertical wells and three are drilling horizontal wells, but plans to reduce its vertical rig count to approximately 30 rigs by year-end 2012 and increase its horizontal Wolfcamp Shale rig count to seven by year end. In approximately 50 percent of the planned 750 well vertical drilling program, the Wolfcamp interval will be the deepest interval completed. Of the remaining 50 percent of the wells, 20 percent are planned to be deepened to the Strawn interval, 20 percent to the Atoka interval and 10 percent to the Mississippian interval.

The Company recently completed its second successful horizontal well in the Upper/Middle Wolfcamp Shale in Upton County, Texas with a 30-stage fracture stimulation in a 5,800-foot lateral section. This well is performing similarly to the Company’s first horizontal well in the area. The first horizontal well has produced over 45 MBOE in its first 90 days of production, which is approximately seven times the production from a typical Spraberry vertical well over the same time period. These wells continue to flow naturally and are producing to sales.

Based on this successful drilling activity and Pioneer’s extensive geologic interpretation of the Upper/Middle Wolfcamp Shale, the Company believes it has significant horizontal potential within its acreage. Pioneer is the largest acreage holder in the play with more than 400,000 prospective acres.

The Company is currently focusing its horizontal efforts on more than 200,000 acres in the southern part of the field to hold acreage that would otherwise expire by year-end 2013. Current plans call for drilling 80 to 90 horizontal wells in this area by the end of 2013, with 30 to 35 horizontal wells expected to be drilled in 2012.

The Company continues to test downspacing in the Spraberry field from 40 acres to 20 acres. Sixteen 20-acre wells were drilled in 2011, with 10 of these wells having been placed on production. These 20-acre wells were mostly drilled to the Lower Wolfcamp interval, with a few deepened to the Strawn interval. The Company plans to drill approximately 50 additional 20-acre downspaced wells during 2012.

The Company continues to expand its integrated services to control drilling costs and support the execution of its accelerating drilling program. The Company has increased its owned drilling rigs to 15 and has five Company-owned fracture stimulation fleets totaling 100,000 horsepower currently operating in the Spraberry field supporting vertical drilling operations. Two additional fleets totaling 70,000 horsepower will be added by mid-year 2012 to support Pioneer’s horizontal drilling program in the Wolfcamp Shale. 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, the Company has contracted for tubular and pumping unit requirements through 2012 and well cementing services through 2016.

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 approximately 284,000 gross acres (245,000 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

PIONEER NATURAL RESOURCES COMPANY

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 680 wells on more than 259,000 gross acres (252,000 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

The Raton Basin properties are located in the southeast portion of Colorado. The Company owns approximately 227,000 gross acres (201,000 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 2011 were primarily focused on delineation and development of Pioneer’s substantial acreage position in the Eagle Ford Shale play. The Company drilled 94 horizontal Eagle Ford Shale wells during 2011, with average lateral lengths of approximately 5,500 feet and 13-stage fracture stimulations. The Company plans to utilize 12 rigs in 2012 and drill approximately 125 wells. The 2012 drilling program will continue to focus on liquids-rich drilling, with only 15 percent of the wells designated to hold strategic dry gas acreage.

To improve the execution of its drilling and completions program in 2012 and reduce costs, the Company will operate two Company-owned fracture stimulation fleets totaling 100,000 horsepower. One fleet was placed in service in April 2011 and the other is expected to be operational during the first quarter of 2012. The Company is also utilizing a dedicated third-party fracture stimulation fleet, which commenced operating in April 2011 under a two-year contract.

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. Early well performance has been similar to direct offset ceramic-stimulated wells. The Company plans to continue to monitor the performance of these wells and plans to use white sand in 50 percent of its 2012 drilling program.

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, including normal closing adjustments. The terms of the transaction also provided that the purchaser will pay 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. As of December 31, 2011, $398.2 million of the carry obligation had been paid by the purchaser and the Company expects that the purchaser’s obligation will be satisfied by the end of 2012. 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 gathering facilities in the Eagle Ford Shale area, 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 2013. Eight of the 12 planned central gathering plants (“CGPs”) were completed as of December 31, 2011. EFS Midstream plans to build three additional CGPs in 2012. As construction of CGPs is completed, EFS Midstream will provide gathering, treating and transportation services for the Company during a 20-year contractual term. The Company has invested $169.5 million of capital in EFS Midstream, $97.5 million of which was contributed during 2011. During June 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.

PIONEER NATURAL RESOURCES COMPANY

Barnett Shale

During 2011, the Company continued to increase its acreage position in the liquid-rich Barnett Shale Combo area in North Texas. In total, the Company has accumulated approximately 92,000 gross acres in the liquid-rich area of the field and has acquired approximately 340 square miles of proprietary 3-D seismic covering its acreage. The Company’s total lease holdings in the Barnett Shale play now approximate 142,000 gross acres (108,000 net acres).

During 2011, the Company had two drilling rigs operating and drilled 44 Barnett Shale Combo wells. Pioneer plans to utilize two rigs during 2012 and is utilizing the 3-D seismic to high-grade its drilling location selections. The Company also commenced operating a Company-owned fracture stimulation fleet in the area during the second quarter of 2011.

Alaska

The Company owns a 70 percent working interest and is the operator of the Oooguruk development project. The Company has drilled 12 production wells and eight injection wells of the estimated 17 production and 16 injection wells planned to fully develop this project. The Company’s winter drilling program calls for two exploration wells (“Nuna #1” and “Sikumi #1”) to be drilled during the first quarter of 2012. The Nuna #1 well will be drilled from an onshore location to further evaluate the productivity of the Torok formation and the feasibility of future development expansion to the south. The Sikumi #1 well will be drilled from an ice pad on the west side of the Oooguruk unit to test the deeper Ivishak zone, which is the main producing horizon in the Prudhoe Bay field.

International

During 2011, the Company’s international operations were located in Tunisia and offshore South Africa. During February 2011, the Company completed the sale of the Company’s share holdings in Pioneer Tunisia to an unaffiliated third party. During December 2011, the Company committed to a plan to divest Pioneer South Africa during 2012. See Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the sale of Pioneer Tunisia and the planned sale of Pioneer South Africa.

Selected Oil and Gas Information

The following tables set forth selected oil and gas information from continuing operations for the Company as of and for each of the years ended December 31, 2011, 2010 and 2009. 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.

Production, price and cost data. The price that the Company receives for the oil and gas produced is largely a function of market supply and demand. Demand is impacted 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 2011, 2010 and 2009. 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 agree to the reserve volume tables in the “Unaudited Supplementary Information” section included in “Item 8. Financial Statements and Supplementary Data” due to field fuel volumes being included in the reserve volume tables.

PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA


	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	$	8.09	$	2.35	$	7.61		$	7.90
Third-party transportation charges		—			3.01		1.26		—		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	$	10.32	$	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. As of December 31, 2011, the Company had an obligation to deliver 1.3 million Bbls of oil under the VPP obligation. See Notes H and S of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information about the Company’s gathering, processing, transportation and fractionation agreements and VPP obligation, respectively.

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.

PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA - (Continued)


	Year Ended December 31, 2009
	United States							South Africa		Tunisia		Total
	Spraberry Field			Raton Field		Total
Production information:
Annual sales volumes:
Oil (MBbls)		5,836			—		9,113		137		2,384		11,634
NGLs (MBbls)		3,454			—		7,183		—		—		7,183
Gas (MMcf)		15,313			67,991		128,753		9,321		609		138,683
Total (MBOE)		11,842			11,332		37,756		1,690		2,485		41,931
Average daily sales volumes:
Oil (Bbls)		15,989			—		24,968		375		6,531		31,874
NGLs (Bbls)		9,461			—		19,680		—		—		19,680
Gas (Mcf)		41,954			186,278		352,749		25,538		1,668		379,955
Total (BOE)		32,443			31,046		103,440		4,631		6,809		114,880
Average prices, including hedge results and amortization of deferred VPP revenue (a):
Oil (per Bbl)	$	73.12		$	—	$	75.60	$	65.94	$	60.98	$	72.49
NGL (per Bbl)	$	25.91		$	—	$	29.76	$	—	$	—	$	29.76
Gas (per Mcf)	$	2.84		$	3.26	$	3.88	$	5.17	$	8.14	$	3.99
Revenue (per BOE)	$	47.27		$	19.59	$	37.15	$	33.85	$	60.49	$	38.40
Average prices, excluding hedge results and amortization of deferred VPP revenue (a):
Oil (per Bbl)	$	56.25		$	—	$	55.04	$	65.94	$	60.98	$	56.38
NGL (per Bbl)	$	25.91		$	—	$	28.45	$	—	$	—	$	28.45
Gas (per Mcf)	$	2.84		$	3.26	$	3.32	$	5.17	$	8.14	$	3.47
Revenue (per BOE)	$	38.96		$	19.59	$	30.02	$	33.85	$	60.49	$	31.98
Average costs (per BOE):
Production costs:
Lease operating	$	10.47		$	5.14	$	7.39	$	3.26	$	7.38	$	7.22
Third-party transportation charges		—			2.39		0.95		—		1.69		0.96
Net natural gas plant/gathering		(1.23	)		1.79		0.27		—		—		0.25
Workover		1.30			0.10		0.55		—		2.58		0.65

Total	$	10.54		$	9.42	$	9.16	$	3.26	$	11.65	$	9.08

Production and ad valorem taxes:
Ad valorem	$	2.10		$	0.39	$	1.51	$	—	$	—	$	1.36
Production		2.72			0.12		1.10		—		—		0.99

Total	$	4.82		$	0.51	$	2.61	$	—	$	—	$	2.35

Depletion expense	$	8.69		$	18.19	$	14.20	$	38.33	$	8.77	$	14.85

(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.

PIONEER NATURAL RESOURCES COMPANY

Productive wells. The following table sets forth the number of productive oil and gas wells attributable to the Company’s properties as of December 31, 2011, 2010 and 2009:

PRODUCTIVE WELLS (a)

		000000000		000000000		000000000		000000000		000000000		000000000
	Gross Productive Wells						Net Productive Wells
	Oil		Gas		Total		Oil		Gas		Total
As of December 31, 2011:
United States		6,111		5,268		11,379		5,525		4,502		10,027
South Africa		—		6		6		—		3		3

Total		6,111		5,274		11,385		5,525		4,505		10,030

As of December 31, 2010:
United States		5,533		4,836		10,369		4,769		4,347		9,116
South Africa		—		6		6		—		3		3
Tunisia		33		—		33		10		—		10

Total		5,566		4,842		10,408		4,779		4,350		9,129

As of December 31, 2009:
United States		5,332		5,021		10,353		4,566		4,604		9,170
South Africa		—		6		6		—		3		3
Tunisia		29		—		29		9		—		9

Total		5,361		5,027		10,388		4,575		4,607		9,182

(a)

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. If any well in which one of the multiple completions is an oil completion, then the well is classified as an oil well. As of December 31, 2011, the Company owned interests in two gross wells containing multiple completions.

Leasehold acreage. The following table sets forth information about the Company’s developed, undeveloped and royalty leasehold acreage as of December 31, 2011:

LEASEHOLD ACREAGE


	Developed Acreage				Undeveloped Acreage				Royalty
	Gross Acres		Net Acres		Gross Acres		Net Acres		Acreage
United States:
Onshore		1,603,656		1,348,040		1,459,058		964,537		302,316
Offshore		—		—		—		—		5,000

		1,603,656		1,348,040		1,459,058		964,537		307,316
South Africa		119,579		53,281		3,508,421		1,578,789		—

Total		1,723,235		1,401,321		4,967,479		2,543,326		307,316

PIONEER NATURAL RESOURCES COMPANY

The following table sets forth the expiration dates of the leases on the Company’s gross and net undeveloped acres as of December 31, 2011:


	Acres Expiring (a)
	Gross		Net
2012 (b)		258,119		217,103
2013		157,758		112,063
2014		85,759		57,992
2015		40,974		23,866
2016		831,714		484,074
Thereafter		3,593,155		1,648,228

Total		4,967,479		2,543,326

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

(b)

All acres subject to expiration during 2012 are in the United States. The Company may extend the leases prior to their expiration based upon 2012 planned activities or for other business reasons. In certain leases, the extension is only subject to the Company’s election to extend and the fulfillment of certain capital expenditures commitments. In other cases, the extensions are subject to the consent of third parties, and no assurance can be given that the requested extensions will be granted. See “Description of Properties” above for information regarding the Company’s drilling operations.

Drilling and other exploratory and development activities. The following table sets forth the number of gross and net wells drilled by the Company during 2011, 2010 and 2009 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,
	2011			2010			2009			2011			2010			2009
United States:
Productive wells:
Development		725			433			60			661			378			58
Exploratory		167			34			13			115			22			7
Dry holes:
Development		11			3			—			10			3			—
Exploratory		1			3			2			1			1			2

		904			473			75			787			404			67

Tunisia:
Productive wells:
Development		—			3			1			—			2			—
Exploratory		—			5			—			—			2			—
Dry holes:
Development		—			—			—			—			—			—
Exploratory		—			—			2			—			—			1

		—			8			3			—			4			1

Total		904			481			78			787			408			68

Success ratio (a)		99	%		99	%		95	%		99	%		99	%		96	%

(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.

PIONEER NATURAL RESOURCES COMPANY

Present activities. The following table sets forth information about the Company’s wells that were in process of being drilled as of December 31, 2011:


	Gross Wells		Net Wells
Development		167		153
Exploratory		71		49

Total		238		202

ITEM 3.

LEGAL PROCEEDINGS

The Company is party to a legal proceeding that is described under “Legal actions” in Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.” The Company is also party to other 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.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

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 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, 2011 and 2010. 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, 2011 and 2010:


	High		Low		Dividends Declared Per Share
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
Year ended December 31, 2010
Fourth quarter	$	88.00	$	64.97	$	—
Third quarter	$	67.77	$	54.89	$	0.04
Second quarter	$	74.00	$	54.72	$	—
First quarter	$	56.88	$	41.88	$	0.04

On February 24, 2012, the last reported sales price of the Company’s common stock, as reported in the NYSE composite transactions, was $116.24 per share.

As of February 24, 2012, the Company’s common stock was held by approximately 15,217 holders of record.

On February 23, 2012, the Board declared a cash dividend of $.04 per share on the Company’s outstanding common stock. The dividend is payable April 12, 2012 to stockholders of record at the close of business on March 30, 2012.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company’s purchases of treasury stock during the three months ended December 31, 2011:


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 2011		63	$	71.98		—
November 2011		58	$	87.46		—
December 2011		155	$	89.01		—

Total		276	$	84.80		—	$	—

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

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, 2011 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,
	2011		2010		2009			2008		2007
	(in millions, except per share data)
Statements of Operations Data:
Oil and gas revenues (a)	$	2,294.1	$	1,718.3	$	1,402.4		$	1,893.4	$	1,507.2
Total revenues (b)	$	2,786.6	$	2,381.7	$	1,290.4		$	1,920.1	$	1,533.1
Total costs and expenses (c)	$	2,130.2	$	1,600.1	$	1,515.6		$	1,675.3	$	1,299.3
Income (loss) from continuing operations	$	458.8	$	511.9	$	(142.0	)	$	144.8	$	162.2
Income from discontinued operations, net of tax (d)	$	423.2	$	134.1	$	99.7		$	86.8	$	210.2
Net income (loss) attributable to common stockholders	$	834.5	$	605.2	$	(52.1	)	$	210.0	$	372.7
Income (loss) from continuing operations attributable to common stockholders per share:
Basic	$	3.45	$	4.00	$	(1.33	)	$	1.02	$	1.30

Diluted	$	3.39	$	3.96	$	(1.33	)	$	1.02	$	1.30

Net income (loss) attributable to common stockholders per share:
Basic	$	7.01	$	5.14	$	(0.46	)	$	1.76	$	3.05

Diluted	$	6.88	$	5.08	$	(0.46	)	$	1.76	$	3.04

Dividends declared per share	$	0.08	$	0.08	$	0.08		$	0.30	$	0.27


Balance Sheet Data (as of December 31):
Total assets	$	11,524.2	$	9,679.1	$	8,867.3		$	9,161.8	$	8,617.0
Long-term obligations	$	4,861.2	$	4,683.9	$	4,653.0		$	4,787.2	$	4,568.1
Total stockholders’ equity	$	5,651.1	$	4,226.0	$	3,643.0		$	3,679.6	$	3,054.7

(a)

The Company’s oil and gas revenues for 2011, as compared to those of 2010, increased by $575.8 million (or 34 percent) due to increases in average oil and NGL sales prices and United States 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 $392.8 million of net derivative gains in its total revenues for 2011, including $225.5 million of noncash MTM gains, as compared to $448.4 million of net derivative gains during 2010, including $364.4 million of noncash MTM gains. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Notes B and I 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 T 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 2011, the Company recorded an impairment charge of $354.4 million related to its Edwards and Austin Chalk net assets in South Texas. During 2009 and 2008, the Company recorded impairment charges of $21.1 million and $89.8 million, respectively, to its Uinta/Piceance net assets in Colorado. During 2007, the Company recorded charges of $10.2 million on Block 320 in Nigeria, $10.3 million related to Block H in Equatorial Guinea and $5.7 million related to properties in the United States for a total of $26.2 million. See Note R of Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

(d)

During December 2011, the Company committed to a plan to divest Pioneer South Africa. In accordance with GAAP, the Company has classified the Pioneer South Africa results of operations as discontinued operations in each of the years presented, rather than as a component of continuing operations. 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 $853.6 million, including normal post-closing adjustments, resulting in a pretax gain of $645.2 million. During 2010, the Company received $35.3 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 Company’s Gulf of Mexico shelf properties were sold effective July 1, 2009. 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 Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information about the Company’s discontinued operations.

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 2011 included the following highlights:

•

Earnings attributable to common stockholders increased to $834.5 million ($6.88 per diluted share), as compared to $605.2 million ($5.08 per diluted share) in 2010. The increase in earnings attributable to common stockholders is primarily due to:

•

A $575.8 million increase in oil and gas revenues as a result of increasing sales volumes and higher average oil and NGL sales prices;

•

A $289.1 million increase 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; and

•

A $68.3 million decrease in exploration and abandonments expense, primarily due to a reduction in exploratory dry hole provisions; partially offset by:

•

A $354.4 million impairment provision on dry gas properties in the Edwards and Austin Chalk fields in South Texas;

•

A $137.5 million decrease in net hurricane activity due to the receipt in 2010 of $140 million of insurance proceeds;

•

A $107.5 million increase in DD&A, primarily due to increased sales volumes;

•

An $88.3 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; and

•

A $55.7 million decrease in net derivative gains, primarily due to reduced interest rate derivative gains during 2011;

•

Daily sales volumes from continuing operations increased on a BOE basis by 16 percent to 120,418 BOEPD during 2011, as compared to 103,823 BOEPD during 2010, primarily due to the success of the Company’s drilling programs;

•

Average reported oil and NGL prices from continuing operations increased during 2011 to $96.60 and $46.27 per Bbl, respectively, as compared to respective average reported prices of $90.56 and $38.14 per Bbl during 2010. Partially offsetting the increases in average reported oil and NGL prices was a decrease in average reported gas prices to $3.84 per Mcf during 2011, as compared to $4.18 per Mcf during 2010;

•

Average oil and gas production costs and total ad valorem and production taxes per BOE from continuing operations increased during 2011 to $10.32 and $3.35, respectively, as compared to respective per BOE costs of $9.61 and $2.96 during 2010, primarily as a result of inflation of well servicing costs, increased transportation and treating costs and higher commodity prices;

•

Net cash provided by operating activities increased by $244.7 million, or 19 percent, to $1.5 billion for 2011, as compared to $1.3 billion during 2010, primarily due to the increases in oil and gas sales volumes, oil and NGL prices and realized derivative gains;

•

Long-term debt was reduced by $72.8 million and the Company’s cash and cash equivalents increased by $426.3 million during 2011;

•

During November 2011, the Company completed an offering of 5.5 million shares of its common stock at a per-share offering price of $92.03 and realized $484.2 million of associated proceeds, net of offering costs. The Company is using the net proceeds from this offering for general corporate purposes, including expansion of its drilling in the horizontal Wolfcamp Shale play in the Spraberry field;

•

During 2011, the Company continued to expand its integrated services to control drilling and completion costs and support the execution of its accelerated drilling program. The Company has increased its owned drilling rigs to 15 and increased its owned fracture stimulation fleets to ten during 2011;

PIONEER NATURAL RESOURCES COMPANY

•

During December 2011, Pioneer Southwest completed a public offering of 4.4 million common units, including 1.8 million common units owned by Pioneer, at a per-unit offering price of $29.20. The Company realized $123.0 million of consolidated proceeds, net of offering costs, associated with this offering;

•

During December 2011, the Company committed to a plan to sell Pioneer South Africa. The Company expects to complete the sale of Pioneer South Africa during 2012. In accordance with GAAP, the Company has classified Pioneer South Africa assets and liabilities as discontinued operations held for sale in the Company’s accompanying consolidated balance sheet as of December 31, 2011, and has recast Pioneer South Africa’s results of operations as income from discontinued operations, net of associated income taxes, in the accompanying consolidated statements of operations included in “Item 8. Financial Statements and Supplementary Data”; and

•

As of December 31, 2011, the Company’s net debt to book capitalization was 26 percent, as compared to 37 percent as of December 31, 2011. The Company was upgraded to investment grade by one of its debt rating agencies during the fourth quarter of 2011.

First Quarter 2012 Continuing Operations Outlook

Based on current estimates, the Company expects that first quarter 2012 production will average 141,000 to 146,000 BOEPD, reflecting increased 2012 drilling activity.

First quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $13.00 to $15.00 per BOE, based on current NYMEX strip prices for oil and gas. DD&A expense is expected to average $13.00 to $15.00 per BOE.

Total exploration and abandonment expense for the quarter is expected to be $35 million to $60 million, the higher limit of which reflects the potential dry hole costs associated with two exploration wells being drilled in Alaska. General and administrative expense is expected to be $49 million to $54 million. Interest expense is expected to be $45 million to $49 million, and other expense is expected to be $20 million to $30 million. Accretion of discount on asset retirement obligations from continuing operations 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 $9 million to $12 million, primarily reflecting the public ownership in Pioneer Southwest.

During January 2012, the Company sold a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale to unaffiliated third parties for $54.8 million. The Company expects to record a pretax gain of $40 million to $43 million attributable to this transaction during the three months ended March 31, 2012.

The Company’s first quarter effective income tax rate from continuing operations 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 $5 million and are primarily attributable to state taxes.

2012 Capital Budget

Pioneer’s capital program for 2012 totals $2.5 billion, consisting of $2.4 billion for drilling operations, including budgeted land capital for existing assets, and $100 million for vertical integration. The 2012 budget excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical general and administrative expense.

The 2012 drilling capital of $2.4 billion continues to be focused on oil- and liquids-rich drilling, with 89 percent of the capital allocated to the Spraberry field, including the horizontal Wolfcamp Shale play, the Eagle Ford Shale play and the Barnett Shale Combo play. Following is a breakdown of the forecasted spending by asset area:

•

Spraberry field, excluding Horizontal Wolfcamp Shale – $1.5 billion;

•

Horizontal Wolfcamp Shale – $275 million;

•

Eagle Ford Shale – $130 million (reflecting 25 percent of anticipated 2011 drilling costs, with the remaining 75 percent to be funded by a contractual drilling carry benefit);

PIONEER NATURAL RESOURCES COMPANY

•

Barnett Shale Combo play – $215 million;

•

Alaska – $135 million; and

•

Other spending –$120 million, including land capital for existing assets.

Funds for the expansion of Pioneer’s integrated fracture stimulation and well service operations are budgeted at $100 million in 2012.

The 2012 capital budget is expected to be funded from cash and cash equivalents and forecasted operating cash flow.

Acquisitions

During 2011, 2010 and 2009, the Company spent $131.9 million, $181.6 million and $88.9 million, respectively, to acquire primarily undeveloped acreage for future exploitation and exploration activities. 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. The 2009 acquisitions primarily increased the Company’s acreage positions in the South Texas Eagle Ford Shale play.

Divestitures and Discontinued Operations

Pioneer South Africa. As referred to in Financial and Operating Performance above, in December 2011 the Company committed to a plan 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 and the results of operations of Pioneer South Africa are reported as income from discontinued operations, net of tax in all periods presented in the Company’s accompanying consolidated statements of operations (see Notes B and U 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 Tunisia. During December 2010, the Company committed to a plan to sell Pioneer Tunisia. The assets and liabilities of Pioneer Tunisia are classified as discontinued operations held for sale in the Company’s accompanying consolidated balance sheet as of December 31, 2010. In February 2011 the Company sold its share holdings in Pioneer Tunisia for net proceeds of $853.6 million and recorded an associated pretax gain of $645.2 million during the year ended December 31, 2011. 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, including normal closing adjustments. Under the terms of the transaction, the purchaser is also paying 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. As of December 31, 2011, the purchaser had satisfied $398.2 million of the obligation to pay 75 percent of the Company’s defined exploration, drilling and completion costs attributable to Eagle Ford Shale assets and continues to be obligated to pay $488.6 million of the Company’s future qualifying costs. The Company’s current expectations are that the purchaser’s obligation to pay 75 percent of the Company’s defined exploration, drilling and completion costs attributable to Eagle Ford Shale assets will be satisfied by the end of 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. The historical results and the related gain on disposition are reported as discontinued operations, net of tax.

Mississippi and Gulf of Mexico Shelf. During June and August 2009, the Company sold its Mississippi and shelf properties in the Gulf of Mexico, respectively, for aggregate net proceeds of $23.6 million, resulting in a pretax gain of $17.5 million. The historical results and the related gain on disposition are reported as discontinued operations, net of tax.

PIONEER NATURAL RESOURCES COMPANY

Results of Operations

Oil and gas revenues. Oil and gas revenues from continuing operations totaled $2.3 billion, $1.7 billion and $1.4 billion during 2011, 2010 and 2009, 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; partially offset by an eight percent decrease in average reported gas prices.

The increase in 2010 oil and gas revenues relative to 2009 is reflective of 20 percent, 28 percent and eight percent increases in average reported oil, NGL and gas prices, respectively and a 13 percent increase in oil volumes; partially offset by a five percent decrease in gas volumes.

The following table provides average daily sales volumes from continuing operations for 2011, 2010 and 2009:


	Year Ended December 31,
	2011		2010		2009
Oil (Bbls)		40,618		28,211		24,968
NGLs (Bbls)		22,487		19,736		19,680
Gas (Mcf)		343,879		335,256		352,749
Total (BOE)		120,418		103,823		103,440

Average daily BOE sales volumes in 2011 increased by 16 percent as compared to 2010 principally due to the Company’s successful United States drilling program and declines in scheduled VPP deliveries. Oil volumes delivered under the Company’s VPPs decreased by 45 percent from 2010 to 2011. The Company’s only remaining obligations under VPP agreement are to deliver 1,281,000 Bbls of oil during 2012.

The following table provides average daily sales volumes from discontinued operations by geographic area and in total during 2011, 2010 and 2009:


	Year Ended December 31,
	2011		2010		2009
Oil (Bbls):
United States		—		—		554
South Africa		530		616		375
Tunisia		547		4,880		6,531

Worldwide		1,077		5,496		7,460

NGLs (Bbls):
United States		—		—		29

Gas (Mcf):
United States		—		—		1,899
South Africa		20,570		29,760		25,538
Tunisia		496		2,849		1,668

Worldwide		21,066		32,609		29,105

Total (BOE):
United States		—		—		900
South Africa		3,958		5,576		4,631
Tunisia		630		5,355		6,809

Worldwide		4,588		10,931		12,340

In South Africa, sales volumes in 2011 declined by 29 percent from 2010, primarily due to unplanned production curtailments resulting from third-party gas-to-liquid plant downtime and normal well declines. In Tunisia, sales volumes in 2011 decreased from those of 2010, due to the sale of Pioneer Tunisia during February 2011.

PIONEER NATURAL RESOURCES COMPANY

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 2011, 2010 and 2009:


	Year Ended December 31,
	2011		2010		2009
Average reported prices:
Oil (per Bbl)	$	96.60	$	90.56	$	75.60
NGL (per Bbl)	$	46.27	$	38.14	$	29.76
Gas (per Mcf)	$	3.84	$	4.18	$	3.88
Total (per BOE)	$	52.19	$	45.34	$	37.15
Average realized prices:
Oil (per Bbl)	$	91.35	$	74.21	$	55.04
NGL (per Bbl)	$	46.27	$	37.12	$	28.45
Gas (per Mcf)	$	3.84	$	4.15	$	3.32
Total (per BOE)	$	50.42	$	40.61	$	30.02

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 hedge 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 stockholders’ equity section of the Company’s accompanying consolidated balance sheets, and are being transferred to earnings during the same periods in which the hedged transactions are 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.

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, 2011, 2010 and 2009 (in thousands):


	Year Ended December 31,
	2011		2010		2009
Increase to oil revenue from AOCI—Hedging transfers	$	32,918	$	78,052	$	88,873
Increase to NGL revenue from AOCI—Hedging transfers		—		7,297		9,402
Increase to gas revenue from AOCI—Hedging transfers		—		3,691		22,791

Total	$	32,918	$	89,040	$	121,066

The Company will transfer $3.1 million of deferred hedge losses to oil revenues during the year ended December 31, 2012, which transfer represents the remaining deferred hedge losses recorded in AOCI – Hedging as of December 31, 2011. See Note I of Notes to Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data” for further information concerning the Company’s commodity derivatives and scheduled amortization of net deferred losses on discontinued commodity hedges that will be recognized as decreases to future oil revenues.

PIONEER NATURAL RESOURCES COMPANY

Deferred revenue. During 2011 and 2010, the Company’s amortization of deferred VPP revenue increased annual oil revenues by $45.0 million and $90.2 million, respectively, and during 2009, increased oil and gas revenues by $147.9 million. The Company’s amortization of deferred VPP revenue will increase 2012 annual oil revenues by $42.1 million, representing the remaining deferred revenues associated with VPP that is recorded in the Company’s accompanying balance sheet as of December 31, 2011. See Note S 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 $102.0 million, $57.0 million and $101.6 million during 2011, 2010 and 2009, respectively. The $45.0 million increase during 2011, as compared to 2010, is primarily attributable to a $45.0 million increase in third-party income associated with vertical integration services provided by the Company on operated wells and an $8.7 million increase in equity earnings from EFS Midstream, partially offset by an $8.7 million decrease in Alaskan Petroleum Production Tax (“PPT”) credit recoveries. The $44.6 million decrease in interest and other income during 2010, as compared to 2009, is primarily attributable to a $47.3 million decrease in PPT credit recoveries and a $2.2 million increase in interest income.

Derivative gains (losses), net. The following table summarizes the Company’s net derivative gains or losses for the years ending December 31, 2011, 2010 and 2009 (in thousands):


	Year Ended December 31,
	2011			2010			2009
Unrealized mark-to-market changes in fair value:
Oil derivative gains (losses)	$	68,376		$	41,094		$	(150,799	)
NGL derivative gains (losses)		10,243			10,690			(20,206	)
Gas derivative gains (losses)		179,787			277,585			(6,612	)
Diesel derivative gains		270			—			—
Interest rate derivative gains (losses)		(33,206	)		35,040			(13,928	)

Total unrealized mark-to-market derivative gains (losses), net (a)		225,470			364,409			(191,545	)


Cash settled changes in fair value:
Oil derivative losses		(36,664	)		(27,305	)		(60,604	)
NGL derivative losses		(15,418	)		(7,180	)		(8,340	)
Gas derivative gains		182,993			119,417			66,428
Diesel derivative gains		67			—			—
Interest rate derivative gains (losses)		36,304			(907	)		(1,496	)

Total cash derivative gains (losses), net		167,282			84,025			(4,012	)

Total derivative gains (losses), net	$	392,752		$	448,434		$	(195,557	)

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

Gain (loss) on disposition of assets. The Company recorded a net loss on the disposition of assets of $3.6 million during 2011, a net gain of $19.1 million during 2010 and a net loss of $774 thousand during 2009.

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 and recorded net hurricane activity expenses of $17.3 million during 2009.

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.

PIONEER NATURAL RESOURCES COMPANY

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 the insurance policy dispute, resulting in an additional payment to the Company of $140 million during November 2010. See Note T of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for specific information regarding the Company’s East Cameron platform facilities reclamation and abandonment.

Oil and gas production costs. The Company’s oil and gas production costs from continuing operations totaled $453.1 million, $364.8 million and $345.9 million during 2011, 2010 and 2009, 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.

During 2011, total production costs per BOE increased by seven 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.

During 2010, total production costs per BOE increased by five percent as compared to 2009. The increase in production costs per BOE during 2010 was primarily due to (i) inflation in well servicing costs and (ii) increases in workover expenditures incurred to mitigate production declines, partially offset by the expiration of a portion of the Company’s VPP delivery commitments.

The following table provides the components of the Company’s total production costs per BOE for 2011, 2010 and 2009:


	Year Ended December 31,
	2011		2010		2009
Lease operating expenses	$	8.09	$	7.74	$	7.39
Third-party transportation charges		1.26		0.87		0.95
Net natural gas plant/gathering charges		0.15		0.08		0.27
Workover costs		0.82		0.92		0.55


Total production costs	$	10.32	$	9.61	$	9.16

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $147.7 million during 2011, as compared to $112.1 million and $98.4 million for 2010 and 2009, 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 2011, the Company’s production taxes per BOE increased by 44 percent as compared to 2010, primarily reflecting the impact of higher oil and NGL prices on production taxes. On a per BOE basis, ad valorem taxes decreased 17 percent as compared to 2010, which is primarily a result of an increase in sales volumes from new wells first brought on production during 2011. During 2010, the Company’s production taxes per BOE increased 34 percent over 2009, reflecting the year-to-year increase in commodity prices, while ad valorem taxes decreased by one percent.

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 2011, 2010 and 2009:


	Year Ended December 31,
	2011		2010		2009
Ad valorem taxes	$	1.24	$	1.49	$	1.51
Production taxes		2.11		1.47		1.10


Total ad valorem and production taxes	$	3.35	$	2.96	$	2.61

PIONEER NATURAL RESOURCES COMPANY

Depletion, depreciation and amortization expense. The Company’s total DD&A expense from continuing operations was $607.4 million ($13.82 per BOE), $499.9 million ($13.19 per BOE), and $564.1 million ($14.94 per BOE) for 2011, 2010 and 2009, respectively. Depletion expense on oil and gas properties, the largest component of DD&A expense, was $12.55, $12.40 and $14.20 per BOE during 2011, 2010 and 2009, respectively.

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 Combo play, 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 are carried by a third party. During 2010, the decrease in per BOE depletion expense was primarily due to (i) proved reserve additions associated with the Company’s successful 2010 capital expenditures program and (ii) adding end-of-life reserves that became economic as a result of commodity price increases since 2009.

During the fourth quarter of 2009, the Company adopted the provisions of the Reserve Ruling and ASU 2010-03. The provisions of the Reserve Ruling and ASU 2010-03, which became effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, changed the definition of proved oil and gas reserves to require the use of an average of the first-day-of-the-month commodity prices during the 12-month period ending on the balance sheet date rather than the period-end commodity prices; added to and amended certain definitions used in estimating proved oil and gas reserves, such as “reliable technology” and “reasonable certainty;” and broadened the types of technology that an issuer may use to establish reserves estimates and categories. The adoption of the provisions of the Reserve Ruling and ASU 2010-03 reduced the Company’s total proved reserves by 11 percent as of December 31, 2009.

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

During the third and fourth quarters of 2011, events and circumstances provided indications of possible impairment of certain of the Company’s dry gas assets, including oil and gas proved properties in the Company’s Edwards, Austin Chalk, Raton and Barnett Shale fields. The events and circumstances indicating possible impairment of these fields are primarily related to reductions in management’s gas price outlooks that led to a decrease in estimated future undiscounted net cash flows attributable to each field’s proved reserves. 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 Outlook”). During the fourth quarter of 2011, the estimate of undiscounted future net cash flows attributable to the Company’s Edwards and Austin Chalk fields in South Texas indicated that their carrying amounts were partially unrecoverable. Consequently, the Company recorded $354.4 million of impairment charges to reduce the carrying values of these fields to their estimated fair values.

The Company’s estimates of undiscounted future net cash flows attributable to the Raton and Barnett Shale fields’ oil and gas properties indicated on December 31, 2011 that their carrying amounts were expected to be recovered, but continue 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 Outlook, of approximately $5.15 per Mcf as of December 31, 2011, were to decline by approximately $0.50 to $0.60 per Mcf. Similarly, the Company estimates that the carrying value of the Barnett Shale field may become partially impaired if the average price of gas in Management’s Price Outlook were to decline by approximately $0.80 to $1.20 per Mcf. The Company’s Raton and Barnett Shale fields are relatively long-lived assets that had carrying values of $2.3 billion and $456.8 million, respectively, as of December 31, 2011. If the Raton and Barnett Shale fields were to become impaired in a future quarter, the Company would recognize impairment charges in that period and such noncash pretax charges could range from $1.6 billion to $1.8 billion for the Raton field and $250 million to $350 million for the Barnett Shale field.

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

PIONEER NATURAL RESOURCES COMPANY

During the year ended December 31, 2009, the Company recognized impairment charges of $21.1 million to reduce the carrying value of the Company’s oil and gas properties in the Uinta/Piceance areas. Declines in gas prices and downward adjustments to the economically recoverable resource potential of these properties led to the impairment charges.

See Notes B and R of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information about the Company’s impairment assessments.

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 2011, 2010 and 2009 (in thousands):


	Year Ended December 31,
	2011		2010		2009
Geological and geophysical	$	73,552	$	58,016	$	40,919
Exploratory dry holes		3,112		91,922		6,873
Leasehold abandonments and other		44,656		39,659		31,303

	$	121,320	$	189,597	$	79,095

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.

During 2009, the Company’s exploration and abandonment expense was primarily attributable to geological and geophysical costs, dry hole expense in the South Texas, Lay Creek and Raton Basin areas and unproved property abandonments in the Permian Basin, Barnett Shale and Raton Basin areas. The significant components of the Company’s 2009 exploratory dry hole provisions and leasehold abandonments expense included (i) $6.9 million of dry hole provisions, primarily associated with the write off of suspended well costs and (ii) $29.4 million of unproved property abandonments. During 2009, the Company completed and evaluated 15 exploration/extension wells, 13 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense from continuing operations totaled $193.2 million, $164.3 million and $130.9 million during 2011, 2010 and 2009, respectively. The increase in general and administrative expense during 2011, as compared to 2010, was primarily due to increases in compensation, occupancy and contract labor expenses related to staffing increases in support of the Company’s capital expansion initiatives and vertical integration efforts, partially offset by an increase in producing, drilling and other overhead recoveries. In support of the Company’s strategic growth initiatives, the Company anticipates continued growth in total employees and compensation-related expenses.

The increase in general and administrative expense during 2010, as compared to 2009, was primarily due to increases in performance-related compensation expense and staffing increases to support the Company’s increased activity level during 2010.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations from continuing operations was $8.3 million, $7.9 million and $8.1 million during 2011, 2010 and 2009,

PIONEER NATURAL RESOURCES COMPANY

respectively. Accretion of discount on asset retirement obligations increased slightly during 2011, as compared to 2010 and 2009, primarily due to additional well completions resulting from the Company’s drilling activities. See Note K 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 $181.7 million, $183.1 million and $173.4 million during 2011, 2010 and 2009, respectively. The weighted average interest rate on the Company’s indebtedness for the year ended December 31, 2011 was 7.2 percent, as compared to 7.1 percent and 5.7 percent for the years ended December 31, 2010 and 2009, respectively.

The $9.7 million increase in interest expense during the year ended December 31, 2010, as compared to 2009, was primarily due to (i) a $29.0 million increase in cash interest expense on senior notes due to an increase in average senior note borrowings, which was primarily attributable to the issuance of $450 million of 7.5% Senior Notes during November 2009, partially offset by (ii) a $10.6 million decrease in cash interest expense on credit facility indebtedness and (iii) a $5.6 million increase in capitalized interest related to the Oooguruk project in Alaska as a result of the Company’s weighted average interest rate increasing.

See Notes B and E 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 $63.2 million during 2011, as compared to $78.4 million during 2010 and $94.7 million during 2009. The $15.2 million decrease in other expense during 2011, as compared to 2010, is primarily due to a $17.4 million decrease in charges recorded for the difference between Pioneer contracted rig rates and market rig rates that are charged to joint operations and idle rig costs, a $13.1 million decrease in idle well servicing operations 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.

The $16.3 million decrease in other expense during 2010, as compared to 2009, is primarily due to a $16.7 million decrease in excess and terminated rig-related costs, a $5.3 million decrease in transportation commitment charges, a $4.8 million decrease in bad debt expense and a $2.2 million decrease in contingency and environmental accrual adjustments, partially offset by an $8.5 million increase in inventory impairment and a $3.3 million increase in tax penalties and adjustments.

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 benefit (provision). The Company recognized income tax provisions attributable to earnings from continuing operations of $197.6 million and $269.6 during 2011 and 2010, respectively and an income tax benefit of $83.2 million during 2009. The Company’s effective tax rates on earnings from continuing operations, excluding income from noncontrolling interest, for 2011, 2010 and 2009 were 33 percent, 36 percent and 35 percent, respectively, as compared to the combined United States federal and state statutory rates of approximately 37 percent.

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 attributes.

Income (loss) from discontinued operations, net of tax. During December 2011, the Company committed to a plan to sell Pioneer South Africa. The plan is expected to result in the sale of the Pioneer South Africa during 2012. In accordance with GAAP, the Company classified Pioneer South Africa assets and liabilities as discontinued operations held for sale in the Company’s accompanying consolidated balance sheet as of December 31, 2011, and has recast the Pioneer South Africa’s results of operations as income from discontinued operations, net of tax in the 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 net cash proceeds of $853.6 million, including normal post-closing adjustments, resulting in a pretax gain of $645.2 million. Accordingly, the Company classified the assets and liabilities of Pioneer Tunisia as discontinued operations held for sale in the accompanying balance sheet as of December 31, 2010 and classified the results of operations of Pioneer Tunisia as income from

PIONEER NATURAL RESOURCES COMPANY

discontinued operations, net of tax in the accompanying consolidated statements of operations. During 2009, the Company sold its oil and gas properties in Mississippi and substantially all of its shelf properties in the Gulf of Mexico. The results of operations of these assets and the related gains on disposition are reported as discontinued operations in the accompanying consolidated statements of operations.

The Company recognized income from discontinued operations, net of tax of $423.2 million for 2011 as compared to income of $134.1 million for 2010 and $99.7 million for 2009. 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.

The $34.3 million increase in income from discontinued operations, net of tax during 2010, as compared to 2009 is attributable to (i) the after tax impact of the 2010 receipt of $35.3 million of interest associated with the recovery of excess deepwater Gulf of Mexico oil and gas royalties paid during 2003 through 2005, (ii) a $24.0 million increase in Tunisian income from discontinued operations, (iii) a 2010 deferred tax benefit adjustment related to Tunisia of $56.5 million and (iv) a $21.4 million increase in Pioneer South Africa’s income from discontinued operations, partially offset by (v) the after tax impact of the 2009 recognition of $119.3 million of pretax gain from the aforementioned excess royalty recovery. See Note U 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 $47.4 million, $40.8 million and $9.8 million for the years ended December 31, 2011, 2010 and 2009, 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 $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.

The $31.0 million increase in net income attributable to noncontrolling interest in 2010, compared to 2009, is primarily due to an increase in Pioneer Southwest’s noncash mark-to-market derivative gains. 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, including EFS Midstream capital funding requirements in excess of its ability to internally fund capital commitments, dividends/distributions and working capital obligations. Funding for these cash needs, which is mitigated by the $488.6 million third-party obligation to pay 75 percent of the Company’s future qualifying Eagle Ford Shale costs, may be provided by any combination of internally-generated cash flow, cash and cash equivalents on hand, proceeds from the disposition of nonstrategic assets or external financing sources as discussed in “Capital resources” below. During 2012, the Company expects that it will be able to fund its needs for cash (excluding acquisitions) with internally-generated cash flows and cash and cash equivalents on hand. Although the Company expects that internal operating cash flows and cash and cash equivalents on hand will be adequate to fund capital expenditures and dividend/distribution payments, and that available borrowing capacity under the Company’s credit facility will 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 2012, the Company plans to continue to focus its capital spending primarily on liquids-rich drilling activities. The Company’s 2012 capital budget totals $2.5 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream capital contributions), consisting of $2.4 billion for drilling operations and $100 million for vertical integration additions. Based on the Company’s current commodity prices outlook, Pioneer expects its net cash flows from operating activities, together with approximately $300 million of cash and cash equivalents on hand, to be sufficient to fund its planned capital expenditures and contractual obligations.

Investing activities. Net cash used in investing activities during 2011 was $1.6 billion, as compared to net cash used in investing activities of $954.9 million and $411.0 million during 2010 and 2009, respectively. The

PIONEER NATURAL RESOURCES COMPANY

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 the Company’s share holdings in Pioneer Tunisia during February 2011). The increase in net cash flow used in investing activities during 2010, as compared to 2009, was comprised of a $574.2 million increase in additions to oil and gas properties, a $159.0 million increase in additions to other assets and other property and equipment and a $72.9 million increase in investment in unconsolidated subsidiaries, partially offset by an increase of $262.2 million in proceeds from disposition of assets. During 2010, the $313.8 million of proceeds from disposition of assets was mainly comprised of $212.0 million of joint venture cash proceeds from the sale of a 45 percent interest in the Company’s Eagle Ford Shale properties, $23.7 million of past cost recoveries from Enterprise Tunisiene d’Activities Petrolieres (“ETAP”) associated with its participation in the Cherouq concession and $77.4 million of net proceeds from the sale of other assets. See “Results of Operations” above and Note M 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, 2011, 2010 and 2009, the Board declared semiannual dividends of $0.04 per common share. Associated therewith, the Company paid $9.6 million, $9.5 million and $9.4 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 2011, the board of directors of the general partner of Pioneer Southwest (the “Pioneer Southwest Board”) declared quarterly distributions of $0.50, $0.51, $0.51, and $0.51 per limited partner unit, respectively. During January, April, July and October of 2010 and 2009, the Pioneer Southwest Board declared quarterly distributions of $0.50 per limited partner unit. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $25.6 million, $25.2 million and $19.0 million during the years ended December 31, 2011, 2010 and 2009, 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.

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, 2011, 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) VPP obligations (to physically deliver volumes and pay related lease operating expenses and capital costs in the future), (v) open purchase commitments, (vi) EFS Midstream capital funding commitments, (vii) take-or-pay obligations that allow the payer to recover make up volumes in the future and (viii) 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 and transportation commitments on uncertain volumes of future throughput. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other 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 commitments, minimum annual gathering, treating and transportation commitments, and VPP obligations. The Company’s contractual obligations include obligations to purchase goods and services for properties that the Company operates, including certain drilling commitments, open purchase commitments and firm gathering, processing and transportation commitments. Other joint owners in the properties operated by the Company will incur portions of the costs represented by these commitments, including qualifying Eagle Ford Shale costs that are subject to a counterparty’s obligation to carry up to 75 percent of the Company’s costs (see “Financial and Operating Performance” and Note M of Notes to Consolidated Financial Statements included in “Item 8. Consolidated Financial Statements and Supplementary Data”).

PIONEER NATURAL RESOURCES COMPANY

The following table summarizes by period the payments due by the Company for contractual obligations estimated as of December 31, 2011:


	Payments Due by Year
	2012		2013 and 2014		2015 and 2016		Thereafter
	(in thousands)
Long-term debt (a)	$	—	$	511,930	$	455,385	$	1,634,600
Operating leases (b)		26,843		39,729		24,931		41,459
Drilling commitments (c)		367,897		100,106		510		—
Derivative obligations (d)		74,415		33,561		—		—
Open purchase commitments (e)		381,398		16,990		—		—
Other liabilities (f)		36,174		23,058		21,183		177,354
Firm gathering, processing and transportation commitments (g)		151,640		480,505		640,908		1,069,159
VPP obligations (h)		42,069		—		—		—

	$	1,080,436	$	1,205,879	$	1,142,917	$	2,922,572

(a)

Long-term debt includes $479.9 million principal amount of the Company’s 2.875% Convertible Senior Notes due 2038 (the “2.875% Convertible Senior Notes”). Holders of the 2.875% Convertible Senior Notes may elect to convert their notes if the last reported sale price of the Company’s common stock is greater than 130 percent of the base conversion price as defined in the indenture. The price of the Company’s common stock has recently been trading at prices above 130 percent of the base conversion price and, accordingly, if the common stock continues to trade above 130 percent of the base conversion price, the holders of the 2.875% Convertible Senior Notes may, at their option, be able to convert the notes as early as the second quarter of 2012. If any holders elect to convert, the Company expects that the cash portion of the conversion payment will be available from cash on hand and that the conversion of the 2.875% Convertible Senior Notes would not have a material adverse effect on the Company’s liquidity. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for information regarding estimated future interest payment obligations under long-term debt obligations and Note E of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.” The amounts included in the table above represent principal maturities only.

(b)	See Note H 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, 2011.

(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, 2011. 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 I 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, 2011.

(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 G, H and K of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s postretirement benefit obligations, litigation and environmental contingencies and asset retirement obligations, respectively.

(g)

Gathering, processing and transportation commitments represent estimated fees on production throughput commitments. See “Item 2. Properties” and Note H 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.

(h)

VPP obligations represent the amortization of the deferred revenue associated with the Company’s remaining VPP. The Company’s ongoing obligation is to deliver the specified volumes sold under the VPP free and clear of all associated production costs and capital expenditures. See Note S of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

Capital resources. The Company’s primary capital resources are cash and cash equivalents, net cash provided by operating activities, proceeds from sales of nonstrategic assets and proceeds from financing activities (principally borrowings under the Company’s credit facility). If cash and cash equivalents together with internal cash flows do not meet the Company’s expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its credit facility, issuances of debt or equity securities or from other sources, such as asset sales or joint ventures.

PIONEER NATURAL RESOURCES COMPANY

Operating activities. Net cash provided by operating activities for the years ended December 31, 2011, 2010 and 2009 was $1.5 billion, $1.3 billion and $543.1 million, respectively. The increase in net cash flow provided by operating activities in 2011, as compared to 2010, is primarily due to increases in oil and gas sales volumes, oil and NGL prices and cash derivative gains. The increase in net cash flow provided by operating activities in 2010, as compared to 2009, was primarily due to increases in average oil, NGL and gas prices, an increase in cash derivative gains and working capital changes, partially offset by decreases in NGL and gas sales volumes.

Asset divestitures. During December 2011, the Company committed to a plan to sell Pioneer South Africa and expects to complete a sale of the assets during 2012. During 2011, the Company completed the sale of the Company’s share holdings in Pioneer Tunisia to an unaffiliated party for net cash proceeds of $853.6 million, including normal post-closing adjustments, resulting in a pretax gain of $645.2 million.

During 2010 the Company (i) sold certain proved and unproved oil and gas properties associated with an Eagle Ford Shale joint venture transaction for net proceeds of $212.0 million, (ii) sold certain proved and unproved properties in the Uinta/Piceance area for net proceeds of $11.8 million and (iii) received $23.7 million from ETAP as contractual reimbursement of a portion of the Company’s past capital costs incurred in Tunisia. See Note M 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 2011 was $457.4 million, as compared to net cash used in financing activities during 2010 and 2009 of $246.4 million and $153.0 million, respectively. 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. During 2009, significant components of financing activities included $159.9 million of net principal payments on long-term debt and $63.3 million of payments associated with dividends, distributions to noncontrolling interests, financing fees and stock repurchases, partially offset by $61.0 million of net proceeds from a secondary unit offering by Pioneer Southwest.

The following provides a description of the Company’s significant financing activities during 2011, 2010 and 2009:

•

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;

•

During November 2011, the Company completed the sale of 5.5 million shares of its common stock for $484.2 million of net proceeds (the “Equity Offering”). The Company used the net proceeds to increase cash and cash equivalents, a portion of which will be used during 2012 to fund the Company’s planned drilling program;

•

The Company’s stock price during March 2011 caused the Company’s 2.875% Convertible Senior Notes to be convertible at the option of the holders during the three months ended June 30, 2011. Associated therewith, holders of the 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for conversion during the three months ended June 30, 2011. During July and August 2011, the Company paid the holders a total of $71 thousand of cash and issued 340 shares of the Company’s common stock. The Company’s 2.875% Convertible Senior Notes may become convertible in future quarters depending on the Company’s stock price performance or under certain other conditions. The price of the Company’s common stock has recently been trading at prices above 130 percent of the base conversion price of the 2.875% Convertible Senior Notes and, accordingly, if the common stock continues to trade above 130 percent of the base conversion price, the holders, at their option, will be able to convert the notes as early as the second quarter of 2012. The Company intends to fund the cash portion of future conversion payments, if any, with cash on hand;

PIONEER NATURAL RESOURCES COMPANY

•

During March 2011, the Company entered into a Second Amended and Restated 5-Year Revolving Credit Agreement (the “Credit Facility”) with a syndicate of financial institutions that matures in March 2016, unless extended in accordance with the terms of the Credit Facility. The Credit Facility replaces the Company’s Amended and Restated 5-Year Revolving Credit Agreement entered into in April 2007 and provides for aggregate loan commitments of $1.25 billion;

•

During March 2010, the Company redeemed for cash all of its outstanding 5.875% senior notes due 2012 for a price equal to the principal amount plus accrued and unpaid interest. Associated therewith, the Company paid $6.3 million;

•

During November 2009, the Company issued 7.50% senior notes due 2020 and received net proceeds of $438.6 million. The Company used the net proceeds to reduce outstanding borrowings under its credit facility; and

•

During November 2009, Pioneer Southwest completed a public offering of 3.1 million common units for $61.0 million of net proceeds. Pioneer Southwest used the net proceeds to repay amounts outstanding under its credit facility.

See Note E 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. There were no outstanding borrowings under the Credit Facility as of December 31, 2011. Including $65.1 million of undrawn and outstanding letters of credit under the Credit Facility, the Company had $1.2 billion of unused borrowing capacity under the Credit Facility as of December 31, 2011. If cash and cash equivalents together with internal cash flows 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 from other sources, such as asset sales or joint ventures. The Company cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that internal cash flows and cash and cash equivalents on hand will be adequate to fund capital expenditures and dividend payments, and that available borrowing capacity under the Credit Facility will provide adequate liquidity, no assurances can be given that such funding sources will be adequate to meet the Company’s future needs. For instance, the amount that the Company may borrow under the Credit Facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items.

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 impact the Company’s ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. In November 2011, the Company achieved an investment grade rating with one of the credit rating agencies.

Book capitalization and current ratio. The Company’s net book capitalization at December 31, 2011 was $7.6 billion, consisting of $537.5 million of cash and cash equivalents, debt of $2.5 billion and stockholders’ equity of $5.7 billion. The Company’s debt to book capitalization decreased to 26 percent at December 31, 2011 from 37 percent at December 31, 2010, primarily due to a decrease in indebtedness, an increase in cash and cash equivalents and stockholders’ equity as a result of the Equity Offering completed in November 2011 and $834.5 million of net income attributable to common stockholders during 2011. The Company’s ratio of current assets to current liabilities was 1.46 to 1.00 at December 31, 2011, as compared to 1.56 to 1.00 at December 31, 2010.

PIONEER NATURAL RESOURCES COMPANY

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 K 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 2011, 2010 and 2009, the Company recognized exploration, abandonment, geological and geophysical expense from continuing operations of $121.3 million, $189.6 million and $79.1 million, respectively. During 2011, 2010 and 2009, the Company recognized exploration, abandonment, geological and geophysical expense from discontinued operations of $4.3 million, $15.9 million and $19.2 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, 2011, 2010 and 2009 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.

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.

PIONEER NATURAL RESOURCES COMPANY

It should not be assumed that the Standardized Measure included in this Report as of December 31, 2011 is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the 2011 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, its outlook of future commodity prices, 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 Note R 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, 2011, the Company carried unproved property costs of $235.5 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, commodity price outlooks, 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 oil and gas 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 C 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 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.

PIONEER NATURAL RESOURCES COMPANY

Goodwill impairment. The Company reviews its goodwill for impairment at least annually. This requires the Company 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, 2010 and 2009. 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 H 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.

Valuations of defined benefit pension and postretirement plans. The Company is the sponsor of certain defined benefit pension and postretirement plans. In accordance with GAAP, the Company is required to estimate the present value of its unfunded pension and accumulated postretirement benefit obligations. Based on those values, the Company records the unfunded obligations of those plans and records ongoing service costs and associated interest expense. The valuation of the Company’s pension and accumulated postretirement benefit obligations requires management assumptions and judgments as to benefit cost inflation factors, mortality rates and discount factors. Changes in these factors may materially change future benefit costs and pension and accumulated postretirement benefit obligations. See Note G of Notes to Consolidated Financial Statements included in “Item 8. Consolidated Financial Statements and Supplementary Data” for additional information regarding the Company’s pension and accumulated postretirement benefit obligations.

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 G 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 reports 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

The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

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, 2011, and from which the Company may incur future gains or losses from changes in commodity prices, interest rates or foreign exchange 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, 2011, 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 I of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s derivative contracts, including deferred gains and losses on terminated derivative contracts. The following table reconciles the changes that occurred in the fair values of the Company’s open derivative contracts during 2011:


	Derivative Contract Net Assets (Liabilities) (a)
	Commodities			Interest Rate			Total
	(in thousands)
Fair value of contracts outstanding as of December 31, 2010	$	167,567		$	17,552		$	185,119
Changes in contract fair values (b)		389,654			3,098			392,752
Contract maturities		(167,468	)		(36,304	)		(203,772	)

Fair value of contracts outstanding as of December 31, 2011	$	389,753		$	(15,654	)	$	374,099

(a)	Represents the fair values of open derivative contracts subject to market risk.

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

Quantitative Disclosures

Interest rate sensitivity. The following tables provide information about financial instruments to which the Company was a party as of December 31, 2011 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, 2011. 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 24, 2012.

PIONEER NATURAL RESOURCES COMPANY

INTEREST RATE SENSITIVITY

DEBT OBLIGATIONS AND DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2011


	Year Ending December 31,																				Liability Fair Value at December 31,
	2012			2013			2014			2015			2016			Thereafter			Total		2011
Total Debt:
Fixed rate principal maturities (a)	$	—		$	479,930		$	—		$	—		$	455,385		$	1,634,600		$	2,569,915	$	(3,073,192	)
Weighted average interest rate		6.05	%		6.74	%		6.78	%		6.78	%		6.88	%		7.13	%
Variable rate principal maturities:
Pioneer Southwest credit facility	$	—		$	32,000		$	—		$	—		$	—		$	—		$	32,000	$	(32,393	)
Weighted average interest rate		1.41	%		1.56	%
Interest Rate Swaps:
Notional debt amount (b)	$	117,222		$	—		$	—		$	—		$	—		$	—				$	(15,654	)
Fixed rate payable (%)		3.06	%		—			—			—			—			—
Variable rate receivable (%) (c)		0.52	%		—			—			—			—			—

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

(b)	Represents weighted average notional contract amounts of interest rate derivatives.

(c)	Represents forward six-month LIBOR received by the Company.

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, 2011. Declines in commodity prices would reduce Pioneer’s revenues and increases in diesel prices would increase the Company’s internally-provided services costs, 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”) 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.

The Company uses “roll adjustment” swap derivatives to mitigate the timing risk associated with the sales price of oil in the Permian Basin. In the Permian Basin, the Company generally sells its oil at a sales price based on the calendar month average NYMEX price of oil during that month, plus an adjustment calculated as the weighted average spread between the NYMEX price for that delivery month and (i) the next month and (ii) the following month during the period when the delivery month is prompt.

The Company purchases diesel derivative swap contracts to mitigate fuel price risk. The diesel derivative swap contracts that the Company enters into are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs, fracture stimulation fleet equipment and well servicing equipment.

See Notes B, D and I 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, diesel or gas prices.

PIONEER NATURAL RESOURCES COMPANY

OIL PRICE SENSITIVITY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2011


	Year Ending December 31,						Asset (Liability) Fair Value at December 31,
	2012		2013		2014		2011
							(in thousands)
Oil Derivatives:
Average daily notional Bbl volumes (a):
Swap contracts		3,000		3,000		—	$	(36,518	)
Weighted average fixed price per Bbl	$	79.32	$	81.02	$	—
Collar contracts		2,000		—		—	$	2,217
Weighted average ceiling price per Bbl	$	127.00	$	—	$	—
Weighted average floor price per Bbl	$	90.00	$	—	$	—
Collar contracts with short puts		41,610		34,000		10,000	$	(34,375	)
Weighted average ceiling price per Bbl	$	118.24	$	119.38	$	127.46
Weighted average floor price per Bbl	$	82.36	$	84.35	$	87.50
Weighted average short put price per Bbl	$	66.52	$	66.56	$	72.50
Average forward NYMEX oil prices (b)	$	110.31	$	106.86	$	100.34
Roll Adjustment Swap contracts (c)		750		3,000		—	$	181
Weighted average fixed price per Bbl	$	0.28	$	0.43	$	—
Average forward NYMEX roll adjustment prices (d)	$	0.06	$	0.69	$	—

(a)

During the period from January 1, 2012 to February 24, 2012, the Company entered into additional collar contracts with short puts for (i) 8,500 Bbls per day of the Company’s July through December 2012 production with a ceiling price of $120.47 per Bbl, a floor price of $95.00 per Bbl and a short put price of $80.00 per Bbl, (ii) 11,500 Bbls per day of the Company’s October through December 2012 production with a ceiling price of $121.10 per Bbl, a floor price of $95.00 per Bbl and a short put price of $80.00 per Bbl, (iii) 32,250 Bbls per day of the Company’s 2013 production with a ceiling price of $121.62 per Bbl, a floor price of $93.45 per Bbl and a short put price of $76.90 per Bbl and (iv) 13,000 Bbls per day of the Company’s 2014 production with a ceiling price of $118.78 per Bbl, a floor price of $90.00 per Bbl and a short put price of $70.00 per Bbl.

(b)	The average forward NYMEX oil prices are based on February 24, 2012 market quotes.

(c)	During the period from January 1, 2012 to February 24, 2012, the Company entered into additional roll adjustment swap derivatives for 3,000 Bbls per day of 2013 oil sales, under which the Company pays the periodic variable roll adjustments and receives a fixed price of $0.43 per Bbl.

(d)	The average forward roll adjustment prices were calculated from forward NYMEX oil prices.

PIONEER NATURAL RESOURCES COMPANY

NGL AND DIESEL PRICE SENSITIVITY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2011


	Year Ending December 31,		Asset (Liability) Fair Value at December 31,
	2012		2011
			(in thousands)
NGL and Diesel Derivatives:
Average daily notional Bbl volumes:
NGL Swap contracts		750	$	(4,995	)
Weighted average fixed price per Bbl	$	35.03
NGL Collar contracts with short puts		3,000	$	5,682
Weighted average ceiling price per Bbl	$	79.99
Weighted average floor price per Bbl	$	67.70
Weighted average short put price per Bbl	$	55.76
Average forward NGL prices (a)	$	65.65
Diesel Swap contracts (b)		500	$	270
Weighted average fixed price per Bbl	$	119.49
Average forward Diesel prices (c)	$	137.70

(a)	Forward component NGL prices are derived from active-market NGL component price quotes. The forward prices represent estimates as of February 24, 2012 provided by third parties who actively trade in NGL derivatives.

(b)	Subsequent to December 31, 2011, the Company terminated all diesel derivative swap contracts and received cash proceeds of $1.8 million associated therewith.

(c)	The average forward diesel price is based on February 24, 2012 market quotes.

PIONEER NATURAL RESOURCES COMPANY

GAS PRICE SENSITIVITY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2011


	Year Ending December 31,											Asset (Liability) Fair Value at December 31,
	2012			2013			2014			2015		2011
												(in thousands)
Gas Derivatives:
Average daily notional MMBtu volumes:
Swap contracts (a)		105,000			67,500			50,000			—	$	178,138
Weighted average fixed price per MMBtu	$	5.82		$	6.11		$	6.05		$	—
Collar contracts		65,000			150,000			140,000			50,000	$	158,795
Weighted average ceiling price per MMBtu	$	6.60		$	6.25		$	6.44		$	7.92
Weighted average floor price per MMBtu	$	5.00		$	5.00		$	5.00		$	5.00
Collar contracts with short puts (a)		170,000			45,000			60,000			30,000	$	137,727
Weighted average ceiling price per MMBtu	$	7.92		$	7.49		$	7.80		$	7.11
Weighted average floor price per MMBtu	$	6.07		$	6.00		$	5.83		$	5.00
Weighted average short put price per MMBtu	$	4.50		$	4.50		$	4.42		$	4.00
Average forward NYMEX gas prices (b)	$	2.98		$	3.79		$	4.18		$	4.43
Basis swap contracts		136,000			142,500			115,000			—	$	(17,369	)
Weighted average fixed price per MMBtu	$	(0.34	)	$	(0.22	)	$	(0.23	)	$	—
Average forward basis differential prices (c)	$	(0.16	)	$	(0.16	)	$	(0.17	)	$	—

(a)

During the period from January 1, 2012 to February 24, 2012, the Company (i) entered into offsetting swap contracts for 20,000 MMBtus per day of the Company’s March 2012 production with a fixed price of $2.41, (ii) converted 95,000 MMBtus per day of the Company’s February through December 2012 collar contracts with short puts to swap contracts with a fixed price of $4.47 per MMBtu, (iii) converted 75,000 MMBtus per day of the Company’s March through December 2012 collar contracts with short puts to swap contracts with a fixed price of $4.41 per MMBtu and (iv) converted 45,000 MMBtus per day of the Company’s 2013 collar contracts with short puts to swap contracts with a fixed price of $4.88 per MMBtu.

(b)	The average forward NYMEX gas prices are based on February 24, 2012 market quotes.

(c)	The average forward basis differential prices are based on February 24, 2012 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, interest rates and foreign exchange rates. These risks did not change materially from December 31, 2010 to December 31, 2011.

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 E 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, interest rate and foreign exchange rate derivative contracts to mitigate commodity price, interest rate and foreign exchange 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.

Foreign currency, operations and price risk. International investments represent a portion of the Company’s total assets. Pioneer currently has international discontinued operations in South Africa with a plan to sell Pioneer South Africa during 2012. The Company has reflected all Pioneer South Africa assets and liabilities as of December 31, 2011 and Pioneer South Africa’s historical results of operations as discontinued operations (see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information about the planned sale of Pioneer South Africa.

PIONEER NATURAL RESOURCES COMPANY

The Company’s financial results and Pioneer South Africa results of operations could be affected by factors impacting foreign operations such as changes in foreign currency exchange rates, changes in the legal or regulatory environment, economic conditions or changes in political or economic climates and other factors. For example:

•

Local political and economic developments could restrict, or increase the cost of, Pioneer’s foreign operations;

•

Exchange controls and currency fluctuations could result in financial losses;

•

Royalty and tax increases and retroactive tax claims could increase costs of the Company’s foreign operations;

•

Expropriation of the Company’s property could result in loss of revenue, property and equipment;

•

Civil uprising, riots, terrorist attacks and wars could make it impractical to continue operations, resulting in financial losses;

•

Compliance with applicable U.S. law could be in conflict with the Company’s contractual obligations, the laws of foreign governments or local customs;

•

Import and export regulations and other foreign laws or policies could result in loss of revenues;

•

Repatriation levels for export revenues could restrict the availability of cash to fund operations outside a particular foreign country; and

•

Laws and policies of the U.S. affecting foreign trade, taxation and investment could restrict the Company’s ability to fund foreign operations or may make foreign operations more costly.

The Company does not currently maintain political risk insurance for Pioneer South Africa.

Africa. The Company views the operating environment in South Africa as stable and the economic stability as good. While the value of South Africa’s currency fluctuates in relation to the U.S. dollar, the Company believes that any currency risk associated with Pioneer South Africa’s operations prior to its sale in 2012 would not have a material impact on the Company’s reported discontinued operations given that Pioneer South Africa’s revenues are closely tied to oil prices, which are denominated in U.S. dollars.

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		71
Consolidated Balance Sheets as of December 31, 2011 and 2010		72
Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009		74
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2011, 2010 and 2009		75
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2011, 2010 and 2009		76
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		77
Notes to Consolidated Financial Statements		79
Unaudited Supplementary Information		119

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, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2011. 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, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

As discussed in Note B to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserves estimation and disclosure requirements resulting from Accounting Standards Update No. 2010-03, “Oil and Gas Reserve Estimation and Disclosures,” effective December 31, 2009.

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, 2011, 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 29, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas

February 29, 2012

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands)


	December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	537,484		$	111,160
Accounts receivable:
Trade, net of allowance for doubtful accounts of $806 and $1,155 as of December 31, 2011 and 2010, respectively		275,991			237,511
Due from affiliates		7,822			7,792
Income taxes receivable		3			30,901
Inventories		241,609			173,615
Prepaid expenses		14,263			11,441
Deferred income taxes		77,005			156,650
Discontinued operations held for sale		73,349			281,741
Other current assets:
Derivatives		238,835			171,679
Other		12,936			14,693

Total current assets		1,479,297			1,197,183

Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties		12,013,805			10,739,114
Unproved properties		235,527			191,112
Accumulated depletion, depreciation and amortization		(3,648,465	)		(3,366,440	)

Total property, plant and equipment		8,600,867			7,563,786

Goodwill		298,142			298,182
Other property and equipment, net		573,075			283,542
Other assets:
Investment in unconsolidated affiliate		169,532			72,045
Derivatives		243,240			151,011
Other, net of allowance for doubtful accounts of $340 and $2,519 as of
December 31, 2011 and 2010, respectively		160,008			113,353

	$	11,524,161		$	9,679,102

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (Continued)

(in thousands, except share data)


	December 31,
	2011			2010
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	647,455		$	354,890
Due to affiliates		68,756			64,260
Interest payable		57,240			59,008
Income taxes payable		9,788			19,168
Deferred income taxes		—			1,144
Discontinued operations held for sale		75,901			108,592
Other current liabilities:
Derivatives		74,415			80,997
Deferred revenue		42,069			44,951
Other		36,174			36,210

Total current liabilities		1,011,798			769,220

Long-term debt		2,528,905			2,601,670
Derivatives		33,561			56,574
Deferred income taxes		2,077,164			1,751,310
Deferred revenue		—			42,069
Other liabilities		221,595			232,234
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		1,331			1,262
Additional paid-in capital		3,613,808			3,022,768
Treasury stock, at cost: 11,264,936 and 10,903,743 shares at December 31, 2011 and 2010, respectively		(458,281	)		(421,235	)
Retained earnings		2,335,066			1,510,427
Accumulated other comprehensive income (loss)—net deferred hedge gains (losses), net of tax		(3,130	)		7,361

Total stockholders’ equity attributable to common stockholders		5,488,794			4,120,583
Noncontrolling interest in consolidating subsidiaries		162,344			105,442

Total stockholders’ equity		5,651,138			4,226,025
Commitments and contingencies

	$	11,524,161		$	9,679,102

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)


	Year Ended December 31,
	2011			2010			2009
Revenues and other income:
Oil and gas	$	2,294,063		$	1,718,297		$	1,402,436
Interest and other		101,960			56,972			101,589
Derivative gains (losses), net		392,752			448,434			(195,557	)
Gain (loss) on disposition of assets, net		(3,644	)		19,074			(774	)
Hurricane activity, net		1,454			138,918			(17,313	)

		2,786,585			2,381,695			1,290,381

Costs and expenses:
Oil and gas production		453,085			364,764			345,885
Production and ad valorem taxes		147,664			112,141			98,371
Depletion, depreciation and amortization		607,405			499,856			564,149
Impairment of oil and gas properties		354,408			—			21,091
Exploration and abandonments		121,320			189,597			79,095
General and administrative		193,215			164,332			130,863
Accretion of discount on asset retirement obligations		8,256			7,945			8,050
Interest		181,660			183,084			173,353
Other		63,166			78,404			94,702

		2,130,179			1,600,123			1,515,559

Income (loss) from continuing operations before income taxes		656,406			781,572			(225,178	)
Income tax benefit (provision)		(197,644	)		(269,627	)		83,195

Income (loss) from continuing operations		458,762			511,945			(141,983	)
Income from discontinued operations, net of tax		423,152			134,050			99,716

Net income (loss)		881,914			645,995			(42,267	)
Net income attributable to noncontrolling interests		(47,425	)		(40,787	)		(9,839	)

Net income (loss) attributable to common stockholders	$	834,489		$	605,208		$	(52,106	)

Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	3.45		$	4.00		$	(1.33	)
Income from discontinued operations attributable to common stockholders		3.56			1.14			0.87

Net income (loss) attributable to common stockholders	$	7.01		$	5.14		$	(0.46	)

Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	3.39		$	3.96		$	(1.33	)
Income from discontinued operations attributable to common stockholders		3.49			1.12			0.87

Net income (loss) attributable to common stockholders	$	6.88		$	5.08		$	(0.46	)

Weighted average shares outstanding:
Basic		116,904			115,062			114,176

Diluted		119,215			116,330			114,176

Amounts attributable to common stockholders:
Income (loss) from continuing operations, net of tax	$	411,337		$	471,158		$	(151,822	)
Discontinued operations, net of tax		423,152			134,050			99,716

Net income (loss)	$	834,489		$	605,208		$	(52,106	)

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)


	Year Ended December 31,
	2011			2010			2009
Net income (loss)	$	881,914		$	645,995		$	(42,267	)

Other comprehensive activity:
Hedge fair value changes, net		—			—			12,974
Net hedge gains included in continuing operations		(32,636	)		(84,877	)		(114,231	)
Income tax provision		8,407			23,648			50,059

Other comprehensive activity		(24,229	)		(61,229	)		(51,198	)

Comprehensive income (loss)		857,685			584,766			(93,465	)

Comprehensive (income) loss attributable to the noncontrolling interests		(33,687	)		(23,206	)		9,424

Comprehensive income (loss) attributable to common stockholders	$	823,998		$	561,560		$	(84,041	)

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands, except dividends per share)


				Stockholders’ 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 Stockholders’ Equity
Balance as of December 31, 2008		114,546		$	1,246	$	2,909,735		$	(411,659	)	$	988,786		$	88,788		$	102,717		$	3,679,613
Dividends declared ($0.08 per share)		—			—		—			—			(9,388	)		—			—			(9,388	)
Exercise of long-term incentive plan stock options and employee stock purchases		468			—		—			18,110			(9,604	)		—			—			8,506
Purchase of treasury stock		(1,276	)		—		—			(21,662	)		—			—			(259	)		(21,921	)
Tax benefits related to stock-based compensation		—			—		1			—			—			—			—			1
Compensation costs:
Vested compensation awards, net		637			6		(6	)		—			—			—			—			—
Compensation costs included in net loss		—			—		38,332			—			—			—			232			38,564
Issuance of Pioneer Southwest common units		—			—		33,388			—			—			(5,844	)		33,439			60,983
Cash contributions from noncontrolling interests							—												150			150
Cash distributions to noncontrolling interests		—			—		—			—			—			—			(20,012	)		(20,012	)
Net income (loss)		—			—		—			—			(52,106	)		—			9,839			(42,267	)
Other comprehensive income (loss):
Deferred hedging activity, net of tax:
Hedge fair value changes, net		—			—		—			—			—			10,477			3,692			14,169
Net hedge gains included in continuing operations		—			—		—			—			—			(42,412	)		(22,955	)		(65,367	)

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

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (continued)

(in thousands, except dividends per share)


				Stockholders’ 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 Stockholders’ Equity
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% senior convertible 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.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended December 31,
	2011			2010			2009
Cash flows from operating activities:
Net income (loss)	$	881,914		$	645,995		$	(42,267	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		607,405			499,856			564,149
Impairment of oil and gas properties		354,408			—			21,091
Exploration expenses, including dry holes		47,231			132,772			37,375
Hurricane activity, net		—			4,508			19,850
Deferred income taxes		188,579			259,763			(72,042	)
(Gain) loss on disposition of assets, net		3,644			(19,074	)		774
Accretion of discount on asset retirement obligations		8,256			7,945			8,050
Discontinued operations		(376,717	)		77,158			38,386
Interest expense		31,483			30,472			27,996
Derivative related activity		(221,899	)		(419,809	)		75,633
Amortization of stock-based compensation		41,442			39,854			37,638
Amortization of deferred revenue		(44,951	)		(90,216	)		(147,905	)
Other noncash items		(22,412	)		25,102			30,623
Change in operating assets and liabilities
Accounts receivable, net		(47,331	)		36,653			16,293
Income taxes receivable		29,406			(5,878	)		36,030
Inventories		(137,401	)		(26,281	)		(46,708	)
Prepaid expenses		(3,415	)		(3,874	)		(3,387	)
Other current assets		1,957			(14,270	)		87,642
Accounts payable		136,296			128,927			(65,862	)
Interest payable		(1,768	)		11,999			3,762
Income taxes payable		(7,623	)		4,007			13,793
Other current liabilities		61,210			(40,586	)		(97,855	)

Net cash provided by operating activities		1,529,714			1,285,023			543,059

Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold		819,044			313,780			51,600
Investment in unconsolidated subsidiary		(89,620	)		(72,864	)		—
Additions to oil and gas properties		(1,926,965	)		(1,011,442	)		(437,240	)
Additions to other assets and other property and equipment, net		(363,246	)		(184,330	)		(25,345	)

Net cash used in investing activities		(1,560,787	)		(954,856	)		(410,985	)

Cash flows from financing activities:
Borrowings under long-term debt		196,616			292,342			1,015,842
Principal payments on long-term debt		(294,883	)		(475,252	)		(1,175,703	)
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			—			60,983
Contributions from noncontrolling interests		—			1,151			150
Distributions to noncontrolling interests		(26,702	)		(26,837	)		(20,012	)
Borrowings (payments) of other liabilities		(901	)		(21,329	)		486
Exercise of long-term incentive plan stock options and employee stock purchases		3,696			7,375			8,506
Purchase of treasury stock		(40,355	)		(14,039	)		(21,921	)
Excess tax (costs) benefits from share-based payment arrangements		31,087			(153	)		1
Payment of financing fees		(8,741	)		(145	)		(12,005	)
Dividends paid		(9,556	)		(9,488	)		(9,370	)

Net cash provided by (used in) financing activities		457,397			(246,375	)		(153,043	)

Net increase (decrease) in cash and cash equivalents		426,324			83,792			(20,969	)
Cash and cash equivalents, beginning of period		111,160			27,368			48,337

Cash and cash equivalents, end of period	$	537,484		$	111,160		$	27,368

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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

NOTE A. Organization and Nature of Operations

Pioneer 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 with continuing operations in the United States.

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 2010 and 2009 financial statement and footnote amounts in order to conform to the 2011 presentations.

Discontinued operations. During December 2011, the Company committed to a plan to sell all of the assets and liabilities of its South Africa operations (“Pioneer South Africa”). The plan is expected to result in the sale of Pioneer South Africa during 2012. In accordance with GAAP, the Company has classified the Pioneer South Africa assets and liabilities as discontinued operations held for sale in the Company’s accompanying consolidated balance sheet as of December 31, 2011, and Pioneer South Africa’s results of operations as income from discontinued operations, net of tax in the accompanying consolidated statements of operations.

During December 2010, the Company committed to a plan to divest the capital stock of the Company’s Tunisian subsidiaries (“Pioneer Tunisia”), which owned all of the Company’s oil and gas properties in Tunisia. The Company completed the sale of Pioneer Tunisia during February 2011. Accordingly, the Company classified the assets and liabilities of Pioneer Tunisia as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2010. The results of operations of Pioneer Tunisia are reported as income from discontinued operations, net of tax in the accompanying consolidated statements of operations.

During 2009, the Company sold its oil and gas properties in Mississippi and substantially all of its shelf properties in the Gulf of Mexico. The Company classified the results of operations attributable to these divestitures as discontinued operations, net of tax in the accompanying consolidated statement of operations.

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; commodity price outlooks; foreign laws, restrictions and currency exchange rates; and export and excise taxes. Actual results could differ from the estimates and assumptions utilized.

Cash equivalents. The Company’s 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, 2011 and 2010, the Company had accounts receivable – trade, net of allowances for bad debts, of $276.0 million and $237.5 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, 2011 and 2010, the Company’s allowances for doubtful accounts totaled $1.1 million and $3.7 million, respectively. The Company establishes allowances for bad debts equal to the estimable portions of

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

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.


	Year Ended December 31,
	2011			2010
	(in thousands)

Beginning allowance for doubtful accounts balance	$	3,674		$	14,299
Amount credited to costs and expenses, net		(1,693	)		(442	)
Other net decreases		(835	)		(10,183	)


Ending allowance for doubtful accounts balance	$	1,146		$	3,674

Investments. Investments in unaffiliated equity securities that have a readily determinable fair value are classified as “trading securities” if management’s current intent is to hold them for the near term; otherwise, they are accounted for as “available-for-sale” securities. The Company reevaluates the classification of investments in unaffiliated equity securities at each balance sheet date. The carrying value of trading securities and available-for-sale securities are adjusted to fair value as of each balance sheet date and are included in other noncurrent assets in the accompanying balance sheets.

Unrealized holding gains are recognized for trading securities in interest and other income, and unrealized holding losses are recognized in other expense during the periods in which changes in fair value occur.

Unrealized holding gains and losses are recognized for available-for-sale securities as credits or charges to stockholders’ equity and other comprehensive income (loss) during the periods in which changes in fair value occur. Realized gains and losses on the divestiture of available-for-sale securities are determined using the average cost method. The Company had no investments in available-for-sale securities as of December 31, 2011 or 2010.

Investments in unaffiliated equity securities that do not have a readily determinable fair value are measured at the lower of their original cost or the net realizable value of the investment. The Company had no significant equity security investments that did not have a readily determinable fair value as of December 31, 2011 or 2010.

Noncontrolling interest in consolidated subsidiaries. At December 31, 2011, the Company owns a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest Energy Partners L.P. (“Pioneer Southwest”). Pioneer Southwest owns interests in certain oil and gas properties previously owned by the Company 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 new common units. The common unit sale resulted in the Company’s limited ownership 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

The following table presents the Company’s net income (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 during the years ended December 31, 2011 and 2009:


	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Net income (loss) attributable to common stockholders	$	834,489	$	605,208	$	(52,106	)


Transfers from the noncontrolling interest in consolidated subsidiaries:
Increase in additional paid in capital for Pioneer Southwest offering of 3.1 million common units issued on November 16, 2009		—		—		33,388

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		—		—

Increase in additional paid in capital for Pioneer Southwest offering of 2.6 million common units issued on December 12, 2011, net of tax of $23.7 million		8,104		—		—


Net transfers from noncontrolling interest		35,019		—		33,388


Net income (loss) attributable to common stockholders and transfers from noncontrolling interest	$	869,508	$	605,208	$	(18,718	)

During January 2010, Pioneer Natural Resources USA, Inc. (“PNR 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, 2011, Sendero owned 15 drilling rigs operating under contract to PNR USA in the Spraberry field. PNR 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 $162.3 million and $105.4 million as of December 31, 2011 and 2010, respectively. The Company recorded net income attributable to the noncontrolling interests of $47.4 million, $40.8 million and $9.8 million for the years ended December 31, 2011, 2010 and 2009 (principally related to Pioneer Southwest), respectively.

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 area of 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 in the Company’s accompanying consolidated statement of operations.

See Note L for a detail of the Company’s equity interest in the net income (loss) of EFS Midstream for the years ended December 31, 2011 and 2010.

Inventories. Inventories were comprised of $297.9 million and $183.4 million of materials and supplies and $4.5 million and $3.9 million of commodities as of December 31, 2011 and 2010, respectively. The Company’s materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing,

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

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. As of December 31, 2011 and 2010, the Company’s materials and supplies inventory was net of $0.9 million and $3.6 million, respectively, of valuation reserve allowances. As of December 31, 2011 and 2010, the Company estimated that $60.8 million and $13.7 million, respectively, of its materials and supplies inventory would not be utilized within one year. Accordingly, those inventory values have been classified as other noncurrent assets in the accompanying consolidated balance sheets as of December 31, 2011 and 2010. At December 31, 2010, the Company had inventory totaling $13.6 million classified as discontinued operations held for sale in the accompanying consolidated balance sheets, representing the inventory of Tunisia. At December 31, 2011, the Company had no inventory balance related to Pioneer South Africa.

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 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.

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.

(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 proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note C 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 operates 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, 2011, 2010 and 2009 were $46.0 million, $34.0 million and $26.5 million, respectively. Third party expenses

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

attributable to the processing plants and treating facilities for the same respective periods were $22.7 million, $14.3 million and $13.7 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.

Capitalized costs relating to 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 such time as 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 the 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 reviews 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. Estimates of the sum of expected future cash flows requires management to estimate future recoverable proved and risk-adjusted probable and possible reserves, and forecast future commodity prices (“Management’s Price Outlook”), production timing, drilling and production cost estimates and discount rates. Management’s Price Outlooks represent longer-term outlooks that are developed based on observable third-party futures price outlooks as of a measurement date. Uncertainties about these future cash flow variables cause impairment estimates to be inherently imprecise. See Note R for additional information regarding the Company’s impairment assessments.

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. During 2004, the Company recorded $327.8 million of goodwill associated with a business combination. The goodwill was recorded to the Company’s United States reporting unit. The Company has reduced goodwill by $29.7 million since the date of the business combination. The Company reduced the carrying value of goodwill by $10.6 million and $1.3 million during 2010 and 2009, respectively, as a charge to the gain from the sale of a portion of its United States reporting unit. The remaining $17.8 million reduction in goodwill was primarily for tax benefits associated with the exercise of fully-vested stock options assumed in conjunction with the business combination. 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 2011, the Company performed its annual assessment of goodwill for impairment and determined that there was no impairment. See Note R for additional information regarding the Company’s impairment assessments.

Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2011 and 2010, respectively, the net carrying value of other property and equipment consisted of $160.8 million and $78.1 million of owned land and buildings, $326.0 million and $155.9 million of heavy equipment and rigs, including drilling rigs, well servicing rigs and fracture stimulation equipment, $28.1 million and $12.9 million of transportation equipment, $34.6 million and $22.3 million of furniture and fixtures, $20.5 million and $14.3 million of leasehold improvements and $3.1 million and nil of other well servicing equipment. At December 31, 2011 and 2010, other property and equipment was net of accumulated depreciation of $297.5 million and $235.3 million, respectively.

The Company’s heavy equipment and rigs include assets owned by subsidiaries that provide pumping and well services on Company-operated properties. The primary purposes of the Company’s pumping and well services

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

operations are to accommodate the Company’s drilling and producing operations by increasing the availability of equipment and services, rather than being limited to third-party availability, and to contain services costs. As of December 31, 2011, the Company owns 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 pumping and well services operations are eliminated. Earnings from providing pumping and well services to third-party working interest owners in Company-operated properties are included in interest and other income in the accompanying consolidated statements of operations.

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, 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.

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. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated.

Asset retirement obligation expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows.

Derivatives and hedging. 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 are included in accumulated other comprehensive income (loss) – net deferred hedge gains (losses), net of tax (“AOCI—Hedging”) and are being transferred to earnings during the same periods in which the forecasted hedged transactions are recognized in the Company’s earnings. Since February 1, 2009, the Company has recognized 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 225 basis points, representing Pioneer Southwest’s estimated borrowing rate.

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 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

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.

Issuance of common stock. In November 2011, the Company issued 5.5 million shares of its common stock and realized $484.2 million of proceeds, net of associated offering costs.

Revenue recognition. The Company does not recognize revenues until they are 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, natural gas liquids (“NGL”) 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 entitlement assets or NGL entitlement assets or liabilities as of December 31, 2011 or 2010. The following table presents the Company’s oil entitlement liabilities and gas entitlement assets and liabilities with their associated volumes as of December 31, 2011 and 2010:


	December 31,
	2011				2010
	Amount		Volume		Amount		Volume
	(dollars in millions)
Oil entitlement liabilities (volumes in MBbls)	$	—		—	$	1.2		13
Gas entitlement assets (volumes in MMcf)	$	7.6		3,024	$	7.6		3,015
Gas entitlement liabilities (volumes in MMcf)	$	2.6		650	$	1.6		439

Stock-based compensation. For stock-based compensation awards granted or modified, 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 vest over a period not exceeding three years. The amount of 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 compensation expense.

New accounting pronouncements. Effective December 31, 2009, the Company adopted the SEC’s final rule on “Modernization of Oil and Gas Reporting” (the “Reserve Ruling”) and the Financial Accounting Standards Board’s (the “FASB”) Accounting Standards Update (“ASU”) 2010-03, which conforms Accounting Standards Codification (“ASC”) 932 to the Reserve Ruling. The Reserve Ruling revises oil and gas reporting disclosures, permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes and allows companies the option to disclose probable and possible oil and gas reserves. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor, (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit and (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than a period-end price. See Unaudited Supplementary Information for information regarding the adoption of the Reserve Ruling and ASU 2010-03.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

During December 2010, the FASB issued ASU 2010-28, “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts.” ASU No. 2010-28 modifies step one of the goodwill impairment test for reporting units with zero or negative carrying amounts, requiring that an entity perform step two of the goodwill impairment test if it is more likely than not that a goodwill impairment exists for those reporting units. ASU No. 2010-28 became effective and was adopted by the Company on January 1, 2011. The adoption of ASU No. 2010-28 did not have an impact on the goodwill impairment test performed by the Company.

In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRSs.” ASU 2011-04 amended Accounting Standards Codification (“ASC”) 820 to converge the fair value measurement guidance in GAAP and International Financial Reporting Standards. Certain of the amendments clarify the application of existing fair value measurement requirements, while other amendments change a particular principle in ASC 820. In addition, ASU 2011-04 requires additional fair value disclosures. The amendments will be applied prospectively and are effective for annual periods beginning after December 15, 2011. The Company does not believe the adoption of this guidance will have a material impact on its future financial position, results of operation or liquidity.

In September 2011, the FASB issued ASU No. 2011-08, “Testing Goodwill for Impairment.” ASU 2011-08 amends ASC 350 to permit 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 more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 will not have a material impact on the future carrying value of the Company’s goodwill. See “Goodwill” above for more information about the Company’s policy for assessing goodwill for impairment.

During December 2011, the FASB issued ASU 2011-11, “Disclosures about offsetting Assets and Liabilities” requiring additional disclosure about offsetting and related arrangements. ASU 2011-11 is effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of ASU 2011-11 will not impact the Company’s future financial position, results of operation or liquidity.

NOTE C. Exploratory Well Costs

The Company’s capitalized exploratory well and project costs are presented in proved properties in the 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, 2011, 2010 and 2009:


	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Beginning capitalized exploratory well costs	$	96,193		$	127,574		$	124,014
Additions to exploratory well costs pending the determination of proved reserves		524,313			238,905			80,222
Reclassification due to determination of proved reserves		(480,716	)		(160,879	)		(58,792	)
Disposition of assets sold		(28,938	)		(17,601	)		—
Exploratory well costs charged to exploration expense (a)		(3,256	)		(91,806	)		(17,870	)

Ending capitalized exploratory well costs	$	107,596		$	96,193		$	127,574

(a)	Includes an exploratory well credit included in discontinued operations of $117 thousand in 2010, and exploratory well costs included in discontinued operations of $9.9 million in 2009.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

During the fourth quarter of 2010, the Company determined that further appraisal drilling in its Cosmopolitan Unit in the Cook Inlet of Alaska would not be funded based on the project’s limited impact to the Company’s future Alaskan and overall growth profile. As a result, an exploration and abandonment charge of $97.7 million was recorded in the fourth quarter of 2010 to write off the Cosmopolitan project’s carrying value. Included in the write off was suspended well costs of $76.0 million, $14.3 million of acreage costs, $6.4 million of estimated property abandonment costs and $1.0 million of inventory impairment charges to reduce the carrying value of its pipe inventory to its resale value.

The following table provides an aging, as of December 31, 2011, 2010 and 2009 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,
	2011		2010		2009
	(in thousands, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	107,596	$	70,635	$	21,634
More than one year		—		25,558		105,940


	$	107,596	$	96,193	$	127,574


Number of projects with exploratory well costs that have been suspended for a period greater than one year		—		3		8

NOTE D. Disclosures About Fair Value Measurements

In accordance with GAAP, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. 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. These two types of inputs are further prioritized into the following fair value input hierarchy:

•

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.

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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2011 and 2010 for each of the fair value hierarchy levels:


	Fair Value Measurements at Reporting Date 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
Liability Awards		9,207		—		—		9,207

Total liabilities	$	9,207	$	107,976	$	—	$	117,183


	Fair Value Measurements at Reporting Date 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, 2010
	(in thousands)
Assets:
Trading securities	$	316	$	151	$	—	$	467
Commodity derivatives		—		304,434		—		304,434
Interest rate derivatives		—		18,256		—		18,256
Deferred compensation plan assets		36,162		—		—		36,162

Total assets	$	36,478	$	322,841	$	—	$	359,319


Liabilities:
Commodity derivatives	$	—	$	127,311	$	9,556	$	136,867
Interest rate derivatives		—		704		—		704
Liability Awards		4,900		—		—		4,900

Total liabilities	$	4,900	$	128,015	$	9,556	$	142,471

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

The following table presents the changes in the fair values of the Company’s net commodity derivative liabilities classified as Level 3 in the fair value hierarchy for the year ended December 31, 2011:


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Year Ended December 31, 2011
	(in thousands)
Beginning liability balance	$	(9,556	)
Fair value changes (a):
Net unrealized gains included in earnings		188
Net realized losses included in earnings		(11,803	)
Settlement payments		11,803
Transfers out of Level 3 (b)		9,368

Ending liability balance	$	—

(a)	Changes in fair value are included in derivative gains (losses), net in the accompanying consolidated statements of operations.

(b)	The values related to NGL swap and collar contracts were transferred from Level 3 to Level 2 as a result of the Company’s ability to obtain independent market-quoted NGL data. The Company recognized the transfer between Level 3 and Level 2 at the end of the reporting period of transfer.

The following table presents the carrying amounts and fair values of the Company’s financial instruments as of December 31, 2011 and 2010:


	December 31, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Assets:
Commodity price derivatives	$	482,075	$	482,075	$	304,434	$	304,434
Interest rate derivatives	$	—	$	—	$	18,256	$	18,256
Trading securities	$	425	$	425	$	467	$	467
Deferred compensation plan assets	$	39,904	$	39,904	$	36,162	$	36,162

Liabilities:
Commodity price derivatives	$	92,322	$	92,322	$	136,867	$	136,867
Interest rate derivatives	$	15,654	$	15,654	$	704	$	704
Liability Awards	$	9,207	$	9,207	$	4,900	$	4,900
Pioneer credit facility	$	—	$	—	$	49,000	$	58,382
Pioneer Southwest credit facility	$	32,000	$	32,393	$	81,200	$	77,241
5.875 % senior notes due 2016	$	405,388	$	488,445	$	396,880	$	475,194
6.65 % senior notes due 2017	$	484,185	$	546,931	$	484,045	$	516,632
6.875 % senior notes due 2018	$	449,225	$	505,688	$	449,192	$	480,969
7.50 % senior notes due 2020	$	446,716	$	523,373	$	446,433	$	494,145
7.20 % senior notes due 2028	$	249,928	$	269,125	$	249,925	$	259,350
2.875% convertible senior notes due 2038 (a)	$	461,463	$	739,630	$	444,994	$	728,400

(a)	The fair value of the 2.875% convertible senior notes include the fair value of the conversion privilege.

Trading securities and deferred compensation plan assets. The Company’s trading securities are comprised of securities that are 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. As of December 31, 2011, all significant inputs to these exchange-traded asset values represented Level 1 independent active exchange market price inputs except inputs for certain trading securities that are not actively traded on major exchanges, which were provided by broker quotes representing Level 2 inputs.

Interest rate derivatives. The Company’s interest rate derivative assets and liabilities as of December 31, 2011 represent interest rate swap contracts that, at their inception, locked in a fixed forward 10-year annual rate of 3.06 percent on $200 million notional amount of debt for a period of one year. The Company’s interest rate derivative assets and liabilities as of December 31, 2010 represent (i) swap contracts for $189 million notional amount of debt whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate and (ii) swap contracts for $470 million notional amount of debt, respectively, whereby the Company pays a variable LIBOR-based rate and the counterparty pays a fixed rate of interest. During July 2011, the Company terminated $470 million notional amount of fixed-for-variable interest rate derivative contracts and received $26.1 million of cash proceeds.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

The net derivative asset and liability values attributable to the Company’s interest rate derivative contracts as of December 31, 2011 and 2010 were determined based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy priority.

Commodity derivatives. The Company’s commodity derivatives represent oil, NGL, gas and diesel swap contracts, collar contracts and collar contracts with short puts (which are also known as three-way collar contracts). The Company’s oil, NGL, gas and diesel swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority.

Oil derivatives. The Company’s oil derivatives are swap, collar and three-way collar contracts for notional barrels (“Bbls”) of oil at fixed (in the case of swap contracts) or interval (in the case of collar and three-way collar contracts) New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The asset and liability values attributable to the Company’s oil derivatives were determined based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company’s collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling oil options and were corroborated by market-quoted volatility factors.

As of December 31, 2011, the Company is also party to “roll adjustment” swap derivatives to mitigate the timing risk associated with the sales price of oil in the Permian Basin. The asset value attributable to the Company’s roll adjustment swaps as of December 31, 2011, of $181 thousand, was determined based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the applicable estimated credit-adjusted risk-free rate yield curve.

NGL derivatives. The Company’s NGL derivatives include swap and collar contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs, Conway-posted-price NGLs or NGL component prices per Bbl. The asset and liability values attributable to the Company’s NGL derivatives were determined based on (i) the contracted notional volumes, (ii) independent active market-quoted NGL component prices, (iii) independent active NYMEX futures price quotes for WTI oil and (iv) the applicable credit-adjusted risk-free rate yield curve. The implied rates of volatility inherent in the Company’s collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling NGL options and were corroborated by market-quoted volatility factors.

Gas derivatives. The Company’s gas derivatives are swap, collar and three-way collar contracts for notional volumes of gas (expressed in millions of British thermal units “MMBtus”) contracted at various posted price indexes, including NYMEX Henry Hub (“HH”) swap contracts coupled with basis swap contracts that convert the HH price index point to other price indexes. The asset and liability values attributable to the Company’s gas derivative contracts were determined based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices, (iv) the applicable credit-adjusted risk-free rate yield curve and (v) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company’s collar contracts and three-way collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling gas options and were corroborated by market-quoted volatility factors.

Diesel derivatives. The Company’s diesel derivatives are swap contracts for notional Bbls posted as Gulf Coast Ultra Low Sulfur (Pipeline) diesel by a posting service. The asset and liability values attributable to the Company’s diesel derivatives were determined based on (i) the contracted notional volumes, (ii) independent active market-quoted diesel prices and (iii) the applicable credit-adjusted risk-free rate yield curve.

Liability Awards. The fair values of the Company’s Liability Awards are updated each balance sheet date based on the closing stock price on the balance sheet date.

Credit facility. The fair values of the Company’s credit facility and Pioneer Southwest’s credit facility are based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

Senior notes. The Company’s senior notes represent debt securities that are 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.

Concentrations of credit risk. As of December 31, 2011, 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 B for information regarding the Company’s accounts receivable – trade and Note J for information regarding the Company’s major customers.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

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 I for additional information regarding the Company’s derivative activities and Note J for information regarding derivative assets and liabilities by counterparty.

NOTE E. Long-term Debt

Long-term debt, including the effects of net deferred fair value hedge losses and issuance discounts and premiums, consisted of the following components at December 31, 2011 and 2010:


	December 31,
	2011			2010
	(in thousands)
Outstanding debt principal balances:
Pioneer credit facility	$	—		$	49,000
Pioneer Southwest credit facility		32,000			81,200
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
7.20% senior notes due 2028		250,000			250,000
2.875% convertible senior notes due 2038		479,930			480,000

		2,601,915			2,700,185
Issuance discounts and premiums, net		(71,301	)		(96,515	)
Net deferred fair value hedge losses		(1,709	)		(2,000	)

Total long-term debt	$	2,528,905		$	2,601,670

Credit Facility. During March 2011, the Company entered into a Second Amended and Restated 5-Year Revolving Credit Agreement (the “Credit Facility”) with a syndicate of financial institutions that matures in March 2016, unless extended in accordance with the terms of the Credit Facility. The Credit Facility replaces the Company’s Amended and Restated 5-Year Revolving Credit Agreement entered into in April 2007 (the “Expired Credit Facility”) and provides for aggregate loan commitments of $1.25 billion. As of December 31, 2011, the Company had no outstanding borrowings under the Credit Facility and $65.1 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $1.2 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 0.75 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 1.75 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 0.325 percent).

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

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. In November 2011, the Company achieved an investment grade rating with one of the credit rating agencies. As such, in accordance with the financial covenants of the Credit Facility, the requirement of the Company to maintain a ratio of the net present value of the Company’s oil and gas properties to total debt of at least 1.75 to 1.0 has been permanently deleted. As of December 31, 2011, the Company was in compliance with all of its debt covenants.

In accordance with GAAP, the Company accounted for the entry into the Credit Facility as an extinguishment of the Expired Credit Facility. Associated therewith, the Company recorded a $2.4 million loss on extinguishment of debt to write off the unamortized issuance costs of the Expired Credit Facility, which is included in other expense in the accompanying consolidated statement of operations for the year ended December 31, 2011 (see Note N).

In May 2008, Pioneer Southwest entered into a $300 million unsecured revolving credit facility with a syndicate of financial institutions, which matures in May 2013 (the “Pioneer Southwest Credit Facility”). As of December 31, 2011, there were $32.0 million of outstanding borrowings under the Pioneer Southwest Credit Facility. 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 0.875 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 or (ii) the Bank of America prime rate (the “Base Rate”) plus a margin (currently zero 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 maximum leverage ratio of not more than 3.5 to 1.00, (ii) an interest coverage ratio (representing a ratio of 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 hedge and derivative related activity; and noncash equity-based compensation to interest expense) of not less than 2.5 to 1.0 and (iii) the maintenance of a ratio of the net present value of Pioneer Southwest’s projected future cash flows from its oil and gas properties to total debt of at least 1.75 to 1.0. As of December 31, 2011, Pioneer Southwest was in compliance with all of its debt covenants.

As of December 31, 2011, the borrowing capacity under the Pioneer Southwest Credit Facility was $268.0 million. However, because of the net present value covenant, Pioneer Southwest’s borrowing capacity under the Pioneer Southwest Credit Facility may be limited in the future. The variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) are subject to adjustment by the lenders. As a result, if commodity prices decline in the future, it 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 other things, nonpayment of principal or interest, violations of covenants, bankruptcy and material judgments and liabilities.

Pioneer Southwest pays a commitment fee on the undrawn amounts under the Pioneer Southwest Credit Facility. The commitment fee is variable based on the Partnership’s consolidated leverage ratio. For 2011, the commitment fee was 0.175 percent.

Convertible senior notes. During January 2008, the Company issued $500 million of 2.875% Convertible Senior Notes due 2038 (the “2.875% Convertible Notes”), of which $479.9 million remains outstanding at December 31, 2011.

The 2.875% Convertible Senior Notes 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. The initial base conversion price is approximately $72.60 per share (subject to adjustment in certain circumstances), which is

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

equivalent to an initial base conversion rate of 13.7741 common shares per $1,000 principal amount of convertible notes. In general, upon conversion of a note, the holder of such note will receive cash equal to the principal amount of the note and the Company’s common stock for the 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 2.875% Convertible Senior Notes mature on January 15, 2038. The Company may redeem the 2.875% 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 2.875% Convertible Senior Notes may require the Company to purchase their 2.875% 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. 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);

•

During five-day periods following defined circumstances when the trading price of the 2.875% 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 price during March 2011 caused the 2.875% Convertible Senior Notes to become convertible at the option of the holders during the three months ended June 30, 2011. Associated therewith, certain holders of the 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for conversion during the three months ended June 30, 2011. During 2011, the Company paid the tendering holders a total of $71 thousand of cash and issued to the tendering holders 340 shares of the Company’s common stock in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

As of December 31, 2011, the Company’s stock price performance did not qualify the 2.875% Convertible Senior Notes for conversion at the option of the holders. However, if all of the 2.875% Convertible Senior Notes had been convertible on December 31, 2011, the note holders would have received $479.9 million of cash and approximately 1.9 million shares of the Company’s common stock, which had a market value of $173.3 million as of December 31, 2011.

Interest on the principal amount of the 2.875% 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 day price of a 2.875% Convertible Senior Note for the five consecutive trading days immediately preceding the first day of the applicable six-month interest period equals or exceeds $1,200, interest on the principal amount of the 2.875% Convertible Senior Notes will be 2.375% solely for the relevant interest period.

As of December 31, 2011 and 2010, the 2.875% Convertible Senior Notes had an unamortized discount of $18.5 million and $35.0 million, respectively, and a net carrying value of $461.5 million and $445.0 million, respectively. The unamortized discount is being amortized ratably through January 2013. For the years ended December 31, 2011, 2010 and 2009, the Company recorded $32.3 million, $31.1 million and $29.9 million, respectively, of interest expense relating to the 2.875% Convertible Senior Notes, which had an effective interest rate of 6.75 percent. As of December 31, 2011 and 2010, $49.5 million is recorded in Additional Paid-in Capital as the equity component of the 2.875% 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 senior convertible notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company’s senior notes and senior convertible notes is payable semiannually.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

Principal maturities. Principal maturities of long-term debt at December 31, 2011, are as follows (in thousands):


2012	$	—
2013	$	511,930
2014	$	—
2015	$	—
2016	$	455,385
Thereafter	$	1,634,600

The principal maturities during 2013 in the preceding table represent the 2.875% Convertible Senior Notes, which are subject to repurchase at the option of the holders in 2013, and the Pioneer Southwest Credit Facility.

Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Cash payments for interest	$	165,307		$	155,854		$	151,246
Accretion/amortization of discounts or premiums on loans		25,210			23,304			21,388
Accretion of discount on derivative obligations		—			521			874
Accretion of discount on postretirement benefit obligations		315			433			657
Amortization of net deferred hedge losses (see Note I)		573			517			465
Amortization of capitalized loan fees		5,385			5,698			4,612
Net changes in accruals		(1,768	)		11,999			3,762

Interest incurred		195,022			198,326			183,004
Less capitalized interest		(13,362	)		(15,242	)		(9,651	)

Total interest expense	$	181,660		$	183,084		$	173,353

NOTE F. 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, 2011, 2010 and 2009:


	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Receipt of lease operating and supervision charges in accordance with standard industry operating agreements	$	2,104	$	2,184	$	2,224
Reimbursement of general and administrative expenses	$	313	$	344	$	265

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

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 2011 and 2010, the Company received $2.2 million and $1.1 million of fixed payments and $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 $21.3 million and $404 thousand of gathering and treating fees. Such amounts were expensed as oil and gas production costs in the accompanying consolidated statements of operations during 2011 and 2010, respectively. See Note H for additional information about commitments under the HGH Agreement.

NOTE G. 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 $2.2 million, $1.9 million and $1.7 million for the years ended December 31, 2011, 2010 and 2009, 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, 2011, 2010 and 2009, the Company recognized compensation expense of $18.3 million, $13.4 million and $11.8 million, respectively, as a result of Matching Contributions.

Compensation costs. In accordance with GAAP, the Company records 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”).

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

The following table reflects compensation expense recorded for each type of incentive award and the associated income tax benefit for the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Restricted stock-equity awards (a)	$	32,861	$	31,712	$	31,929
Restricted stock-liability awards		10,882		4,900		—
Stock options (b)		2,936		1,522		629
Performance unit awards		4,500		4,635		4,868
Pioneer Southwest LTIP		761		475		217
Sendero Series B units		1,020		1,020		—
ESPP		125		1,034		907

Total	$	53,085	$	45,298	$	38,550

Income tax benefit	$	22,084	$	14,019	$	11,675

(a)

For the year ended December 31, 2010, 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 statement of operations for the year ended December 31, 2010.

(b)	Cash proceeds received from stock option exercises during 2011, 2010 and 2009 amounted to $619 thousand, $4.8 million and $6.6 million, respectively.

As of December 31, 2011, there was $69.5 million of unrecognized share-based compensation expense related to unvested share and unit based compensation plans, including $19.7 million attributable to Liability Awards. The 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, 2011:


Approved and authorized awards	9,100,000
Awards issued after May 3, 2006	(5,705,600	)

Awards available for future grant	3,394,400

Restricted stock awards. During 2011, the Company awarded 645,471 restricted shares or units of the Company’s common stock as compensation to directors, officers and employees of the Company (including 202,411 shares or units representing Liability Awards). The Company’s issued shares, as reflected in the consolidated balance sheets as of December 31, 2011 do not include 533,125 of issued, but unvested shares awarded under stock-based compensation plans that have voting rights.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

The following table reflects the restricted stock award activity for the year ended December 31, 2011:


	Equity Awards					Liability Awards
	Number of Shares			Weighted Average Grant- Date Fair Value		Number of Shares
Outstanding at beginning of year		2,559,779		$	28.85		215,134
Shares granted		443,060		$	97.52		202,411
Shares forfeited		(63,105	)	$	54.51		(23,953	)
Shares vested		(1,082,122	)	$	36.41		(70,667	)

Outstanding at end of year		1,857,612		$	39.95		322,925

The weighted average grant-date fair value of restricted stock Equity Awards awarded during 2011, 2010 and 2009 was $97.52, $48.32 and $15.47, respectively. The fair value of shares for which restrictions lapsed during 2011, 2010 and 2009 was $98.6 million, $42.9 million and $11.7 million, respectively, based on the market price on the vesting date.

As of December 31, 2011 and 2010, accounts payable – due to affiliates in the accompanying consolidated balance sheet includes $9.2 million and $4.9 million of liabilities attributable to the Liability Awards, representing the fair value of employee services rendered in consideration for the awards as of that date. There were no Liability Awards issued or outstanding as of December 31, 2009. The fair value of shares for which restrictions lapsed during 2011 was $6.7 million, based on the market price on the vesting date.

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-Sholes option-pricing model. Option awards have a 10 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 U.S. 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 2011, 2010 and 2009:


	2011			2010			2009
Expected option life - years		7			7			7
Volatility		47.6	%		46.8	%		43.0	%
Risk-free interest rate		2.9	%		3.4	%		3.3	%
Dividend yield		0.4	%		0.4	%		1.9	%

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

A summary of the Company’s stock option awards activity for the year ended December 31, 2011 is presented below:


	Number of Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
						(in years)		(in thousands)
Nonstatutory stock options:
Outstanding at beginning of year		507,539		$	23.11
Options awarded		86,903		$	98.69
Options expired and forfeited		—		$	—
Options exercised		(30,398	)	$	20.36

Outstanding and expected to vest at end of year		564,044		$	34.90		8.10	$	30,786

Exercisable at end of year		26,905		$	22.64		7.63	$	1,798

The weighted average grant-date fair value of options awarded during 2011, 2010 and 2009 was $49.61, $23.79 and $6.27, respectively, using the Black-Sholes option-pricing model. The intrinsic value of options exercised during 2011, 2010 and 2009 was $1.5 million, $6.9 million and $3.1 million, respectively, based on the difference between the market price at the exercise date and the option exercise price.

Performance unit awards. During 2011, 2010 and 2009, 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 2011, 2010 and 2009 performance unit awards are $134.68, $63.52 and $15.29, respectively, which amounts were determined using the Monte Carlo simulation method and are being recognized as 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 U.S. 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 2011, 2010 and 2009:


	2011	2010	2009
Risk-free interest rate	1.32%	1.36%	1.33%
Range of volatilities	50.2% - 84.1%	50.4% - 83.0%	47.1% - 73.0%

The following table summarizes the performance unit activity for the year ended December 31, 2011:


	Number of Units (a)			Weighted Average Grant-Date Fair Value
Beginning performance unit awards		263,729		$	28.91
Units granted		43,495		$	134.68
Units vested (b)		(193,096	)	$	16.25

Ending performance unit awards		114,128		$	90.64

(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, 2011, the service period lapsed on 178,289 of these performance unit awards. The lapsed units earned 2.5 shares for each vested award representing 445,724 aggregate shares of common stock issued in 2012. On May 31, 2011, 14,807 units lapsed as part of the Tunisian divesture and earned 2.5 shares for each vested award, representing 37,018 of aggregate shares of common stock.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

The fair value of shares for which restrictions lapsed during 2011, 2010 and 2009 was $44.7 million, $27.4 million and $4.8 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 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 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, 2011:


Approved and authorized awards	3,000,000
Awards issued after May 6, 2008	(106,252	)

Awards available for future grant	2,893,748

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 vest 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. During 2009, the General Partner awarded 12,909 restricted common units to directors of the General Partner under the Pioneer Southwest LTIP, of which 2,038 units vest ratably over three years and 10,871 units vested in May 2010.


	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		12,212		$	21.84		35,118	$	22.74
Units granted		6,812		$	29.35		30,039	$	32.16
Lapse of restrictions		(11,532	)	$	21.97		—	$	—

Outstanding at end of year		7,492		$	28.47		65,157	$	27.08

The weighted average grant-date fair value of restricted common units awarded during 2011, 2010 and 2009 was $29.35, $22.87 and $18.26, respectively. The fair value of common units for which restrictions lapsed on the restricted common units during 2011, 2010 and 2009 was $342 thousand, $324 thousand and $145 thousand, respectively, based on the market price at the vesting date.

During 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 2011 and 2010 was $32.16 and 22.74, respectively. No phantom common units were awarded in 2009. 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

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, 2011:


Approved and authorized shares	750,000
Shares issued	(625,003	)

Shares available for future issuance	124,997

Postretirement Benefit Obligations

At December 31, 2011 and 2010, the Company had $7.5 million and $7.4 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 plans of which four relate to predecessor entities that the Company acquired in prior years. These plans had no assets as of December 31, 2011 or 2010. Other than the Company’s retirement plan, the participants of these plans are not current employees of the Company.

At December 31, 2011, the accumulated postretirement benefit obligations related to these plans were determined by independent actuaries for four plans representing $4.6 million of unfunded accumulated postretirement benefit obligations and by the Company for one plan representing $2.9 million of unfunded accumulated postretirement benefit obligations. For the years ended December 31, 2011, 2010 and 2009, the undiscounted accumulated post retirement benefit obligations were discounted at four percent, four percent and five percent to value the benefit obligations. Certain of the aforementioned plans provide for medical cost subsidies for plan participants. Annual medical cost escalation trends were employed to estimate the accumulated postretirement benefit obligations associated with the medical cost subsidies. The Company forecasted a cost escalation trend of eight percent for 2012, declining annually to seven percent in 2016 and five percent in 2025 and thereafter.

The following table reconciles changes in the Company’s unfunded accumulated postretirement benefit obligations during the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Beginning accumulated postretirement benefit obligations	$	7,408		$	9,075		$	9,612
Net benefit payments		(1,323	)		(1,491	)		(1,430	)
Service costs		243			321			228
Net actuarial losses (gains)		813			(930	)		8
Accretion of interest		315			433			657

Ending accumulated postretirement benefit obligations	$	7,456		$	7,408		$	9,075

Estimated benefit payments and service/interest costs associated with the plans for the year ending December 31, 2012 are $854 thousand and $596 thousand, respectively.

100

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

Future postretirement benefits the Company expects to pay at December 31, 2011 are as follows (in thousands):


2012	$	854
2013	$	902
2014	$	953
2015	$	1,006
2016	$	995
Thereafter	$	2,746

NOTE H. 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 $42.6 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. In addition to the legal action described below, the Company is party to other 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 will continue to evaluate its litigation on a quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to reflect its assessment of the then current status of litigation.

Investigation by the Alaska Oil and Gas Conservation Commission (the “AOGCC”). During the second quarter of 2010, the AOGCC commenced an investigation into allegations by a former Pioneer employee regarding the Company’s Oooguruk facility on the North Slope of Alaska. Among the allegations are claims that the Company did not have authorization to inject certain non-hazardous substances into its enhanced oil recovery well, that the Company mishandled disposal of waste products and that the Company’s operating practices are harmful to the project’s oil reservoirs. Upon initially becoming aware of the allegations, the Company informed the AOGCC and other relevant federal, state and local agencies and commenced its own investigation, which confirmed injections of non-hazardous fluids into the Oooguruk enhanced oil recovery well without prior authorizations to do so. The results of the Company’s investigation were reported to the agencies. In December 2010, the AOGCC investigator submitted a report outlining its findings, which (i) found that the Company’s operating practices have not harmed the project’s oil reservoirs and (ii) raised certain regulatory compliance issues, all of which the Company previously reported or has since taken actions to remedy. Although the Company does not know at this time what action the AOGCC will take in response to the report, based on the facts as known to date, the Company believes that compliance with any order or other action of the AOGCC will not materially and negatively affect the Company’s liquidity, financial position or future results of operations.

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 in 2007 of its Canadian assets and the February 2011 sale of Pioneer Tunisia. 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.

101

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

Lease agreements. The Company leases equipment and office facilities under noncancellable operating leases. Lease payments associated with these operating leases for the years ended December 31, 2011, 2010 and 2009 were $26.9 million, $29.5 million and $30.5 million, respectively. These payments include $513 thousand, $7.2 million and $10.7 million for the years ended December 31, 2011, 2010 and 2009 respectively, of lease payments associated with discontinued operations and included in income from discontinued operations, net of tax, in the accompanying consolidates statement of operations. Future minimum lease commitments under noncancellable operating leases at December 31, 2011 are as follows (in thousands):


2012	$	26,843
2013	$	24,997
2014	$	14,732
2015	$	13,156
2016	$	11,775
Thereafter	$	41,459

Gathering, processing and transportation agreements. The Company is party to contractual commitments with midstream service companies and pipeline carriers for the future gathering, processing, transportation and purchase of oil, NGL and gas production from certain of the Company’s asset areas described below:

Permian Basin. The Company has entered into an agreement to sell NGL production that includes a commitment to deliver minimum NGL volumes for transportation and fractionation. Under the terms of the agreement, committed NGL volumes equal 13,900 Bbls per day in 2012, increasing to 16,000 Bbls in 2015 and continuing at this rate until 2021.

The Company has entered into an NGL purchase and sale agreement pursuant to which the Company has committed to sell NGL production at or near the field processing plant in the Spraberry field and repurchase it at the inlet of the fractionation facilities of the counterparty in Mt. Belvieu, Texas. The Company’s commitment commences in 2012 for 2,000 Bbls of NGL per day, increasing annually to 15,000 Bbls per day by 2019 and continuing at this rate until 2027. The Company’s commitment prior to December 31, 2013, is subject to the completion of certain construction activities by the counterparty to the agreement. The Company also has NGL fractionation commitments with the same counterparty that average 2,000 Bbls of NGL per day commencing in 2014, increasing to 10,000 Bbls per day by 2018 and continuing at this rate until 2023.

Raton. The Company has firm transportation commitments for 214,000 Mcf per day of gas through 2020, then declining annually to 133,000 Mcf per day in 2026, from the Raton field eastward to Mid-Continent sales points and north to Cheyenne, Wyoming. Of these committed volumes, 75,000 Mcf per day is committed onward to Opal, Wyoming.

Eagle Ford Shale. During 2010, the Company entered into agreements with third parties to gather, transport, process and fractionate certain portions of the Company’s future Eagle Ford Shale oil, gas and NGL production. During 2010, the Company entered into a ten-year oil gathering agreement, under which the counterparty is obligated to build a 111-mile oil pipeline that will transport approximately 7,100 Bbls of oil per day in 2012, increasing to approximately 17,400 Bbls per day in 2017, and declining thereafter until the contract term ends in 2022. The Company has firm transportation commitments under this contract upon completion of the pipeline, which is expected during the third quarter of 2012.

During 2010, the Company entered into two five-year gas transportation agreements. Transportation commitments under these agreements in 2012 are approximately 37,000 Mcf per day, increasing to approximately 83,500 Mcf per day in 2015 declining thereafter to 9,700 Mcf per day until terminating in mid-2016.

During 2010, the Company also entered into a ten-year contractual agreement with a third party for the transportation and processing of gas production and the fractionation of recovered NGLs. The firm transportation and processing commitments under this agreement are for approximately 41,800 Mcf per day in 2012 and increasing to approximately 139,100 Mcf per day in 2020. Fractionation commitments under the agreement are for approximately 4,500 Bbls per day of NGLs in 2012 and increasing to approximately 14,900 Bbls per day in 2020.

102

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

During 2010, the Company entered into an agreement with its unconsolidated subsidiary EFS Midstream to gather, treat and transport certain Eagle Ford Shale oil and gas production. The agreement has sequential start dates linked to commencement of Eagle Ford Shale production, with a primary term of 20 years and continuing year-to-year thereafter. EFS Midstream is obligated to construct various gathering and field facilities to handle the Eagle Ford Shale area production, and the Company has dedicated the areas’ reserves to the contract. The Company has minimum annual revenue commitments payable to EFS Midstream of $46.2 million in 2012 and increasing to $128.0 million in 2016 under the aforementioned agreement. See Notes B and F for additional information about EFS Midstream.

Barnett Shale Combo. During 2011, the Company entered into a gas gathering and processing agreement with a third party commencing in 2013 for 50,000 Mcf of gas per day, increasing to 95,000 Mcf per day in 2016 then decreasing to 70,000 Mcf per day in 2019. The agreement terms provide for annual adjustments based on the prior year’s deliveries under the contract. The contract commitment is also subject to commencement of construction of a related plant upon notice given by the Company of its intent to deliver volumes to the plant.

Other. The Company also has a 10-year firm transportation commitment for 75,000 Mcf per day from Opal, Wyoming to Malin, Oregon, which became effective when construction of a 675-mile new pipeline was completed and placed in service during August 2011. The Company does not ship any of its production under this transportation commitment. From time to time, the Company is able to mitigate its exposure to the firm transportation commitments under this agreement by purchasing gas in Cheyenne or Opal, Wyoming and transporting and selling the gas in Malin, Oregon when the spread between the index prices at these two locations is wider than the Company’s variable cost to transport the gas. The firm transportation charges, net of any income from the Company’s mitigation efforts, are recorded in other expense in the accompanying statements of operations. See Note N for additional information on unused transportation commitments.

Future minimum gathering, processing, transportation and fractionation fees under the Company’s oil, NGL and gas gathering, processing and transportation commitments at December 31, 2011 are as follows (in thousands):


2012	$	151,640
2013	$	217,617
2014	$	262,888
2015	$	311,529
2016	$	329,379
Thereafter	$	1,069,159

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 I. 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, (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 and forward currency exchange rate agreements to reduce the effect of exchange rate volatility.

Oil production derivative activities. All material physical sales contracts governing the Company’s oil production are tied directly or indirectly to NYMEX WTI oil prices.

103

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

The following table sets forth the volumes in Bbls outstanding as of December 31, 2011 under the Company’s oil derivative contracts and the weighted average oil prices per Bbl for those contracts:


	2012		2013		2014
Swap contracts:
Volume (Bbl)		3,000		3,000		—
Average price per Bbl	$	79.32	$	81.02	$	—

Collar contracts:
Volume (Bbl)		2,000		—		—
Average price per Bbl:
Ceiling	$	127.00	$	—	$	—
Floor	$	90.00	$	—	$	—

Collar contracts with short puts: (a)
Volume (Bbl)		41,610		34,000		10,000
Average price per Bbl:
Ceiling	$	118.24	$	119.38	$	127.46
Floor	$	82.36	$	84.35	$	87.50
Short put	$	66.52	$	66.56	$	72.50

(a)

During the period from January 1, 2012 to February 24, 2012, the Company entered into additional collar contracts with short puts for (i) 8,500 Bbls per day of the Company’s July through September 2012 production with a ceiling price of $120.47 per Bbl, a floor price of $95.00 per Bbl and a short put price of $80.00 per Bbl, (ii) 11,500 Bbls per day of the Company’s October through December 2012 production with a ceiling price of $121.10 per Bbl, a floor price of $95.00 per Bbl and a short put price of $80.00 per Bbl, (iii) 32,250 Bbls per day of the Company’s 2013 production with a ceiling price of $121.62 per Bbl, a floor price of $93.45 per Bbl and a short put price of $76.90 per Bbl and (iv) 13,000 Bbls per day of the Company’s 2014 production with a ceiling price of $118.78 per Bbl, a floor price of $90.00 per Bbl and a short put price of $70.00 per Bbl.

Permian Basin roll adjustment swap derivatives. The Company uses “roll adjustment” swap derivatives to mitigate the timing risk associated with the sales price of oil in the Permian Basin. In the Permian Basin, the Company generally sells its oil at a sales price based on the calendar month average NYMEX price of oil during that month, plus an adjustment calculated as the weighted average spread between the NYMEX price for that delivery month and (i) the next month and (ii) the following month during the period when the delivery month is prompt. The Company has roll adjustment swap derivatives for 3,000 Bbls per day of March 2012 through May 2012 oil sales and 3,000 Bbls per day of oil sales for the year 2013. Under the terms of the roll adjustment swap derivatives, the Company pays the periodic variable roll adjustments and receives a fixed price of $0.28 per Bbl for March 2012 through May 2012 and $0.43 per Bbl for the year 2013. The Permian Basin roll adjustment swap derivatives are not included in the table presented above. During the period from January 1, 2012 to February 24, 2012, the Company entered into additional roll adjustment swap derivatives for 3,000 Bbls per day of 2013 oil sales, under which the Company pays the periodic variable roll adjustments and receives a fixed price of $0.43 per Bbl.

Natural gas liquids production derivative activities. All material physical sales contracts governing the Company’s NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities’ NGL product component prices. As of December 31, 2011 the Company had NGL swap derivatives for 750 Bbls per day of 2012 NGL sales at an average price of $35.03 per Bbl and NGL collar contracts with short put derivatives for 3,000 Bbls per day of 2012 sales with a ceiling price of $79.99 per Bbl, a floor price of $67.70 per Bbl and short put price of $55.76 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.

104

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

The following table sets forth the volumes in MMBtus outstanding as of December 31, 2011 under the Company’s gas derivative contracts and the weighted average gas prices per MMBtu for those contracts:


	2012			2013			2014			2015
Swap contracts: (a)
Volume (MMBtu)		105,000			67,500			50,000			—
Price per MMBtu	$	5.82		$	6.11		$	6.05		$	—

Collar contracts:
Volume (MMBtu)		65,000			150,000			140,000			50,000
Price per MMBtu:
Ceiling	$	6.60		$	6.25		$	6.44		$	7.92
Floor	$	5.00		$	5.00		$	5.00		$	5.00

Collar contracts with short puts: (a)
Volume (MMBtu)		170,000			45,000			60,000			30,000
Price per MMBtu:
Ceiling	$	7.92		$	7.49		$	7.80		$	7.11
Floor	$	6.07		$	6.00		$	5.83		$	5.00
Short put	$	4.50		$	4.50		$	4.42		$	4.00

Basis swap contracts:
Volume (MMBtu)		136,000			142,500			115,000			—
Price per MMBtu	$	(0.34	)	$	(0.22	)	$	(0.23	)	$	—

(a)

During the period from January 1, 2012 to February 24, 2012, the Company (i) entered into offsetting swap contracts for 20,000 MMBtus per day of the Company’s March 2012 production with a fixed price of $2.41, (ii) converted 95,000 MMBtus per day of the Company’s February through December 2012 collar contracts with short puts to swap contracts with a fixed price of $4.47 per MMBtu , (iii) converted 75,000 MMBtus per day of the Company’s March through December 2012 collar contracts with short puts to swap contracts with a fixed price of $4.41 per MMBtu and (iii) converted 45,000 MMBtus per day of the Company’s 2013 collar contracts with short puts to swap contracts with a fixed price of $4.88 per MMbtu.

Diesel prices. As of December 31, 2011, the Company had diesel derivative swap contracts for 500 Bbls per day for 2012 at an average per Bbl fixed price of $119.49. The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs, fracture stimulation fleet equipment and well servicing equipment. The Company purchases diesel derivative swap contracts to mitigate fuel price risk.

Subsequent to December 31, 2011, the Company terminated all diesel derivative swap contracts and received cash proceeds of $1.8 million associated with the termination.

Interest rates. As of December 31, 2011, the Company is a party to interest rate derivative contracts that lock in, through July 2012, a fixed forward 10-year annual interest rate of 3.06 percent on $200 million notional amount of debt.

105

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

Tabular disclosure of derivative fair value. All of the Company’s derivatives are accounted for as non-hedge derivatives as of December 31, 2011 and 2010. The following tables provide disclosure of the Company’s derivative instruments:

$000,000,000,00

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)

Derivatives not designated as hedging instruments

Commodity price derivatives

Derivatives - current

248,809

Derivatives - current

68,735

Interest rate derivatives

Derivatives - current

—

Derivatives - current

15,654

Commodity price derivatives

Derivatives - noncurrent

257,368

Derivatives - noncurrent

47,689

Interest rate derivatives

Derivatives - noncurrent

—

Derivatives - noncurrent

—

506,177

132,078

Fair Value of Derivative Instruments as of December 31, 2010

Asset Derivatives (a)

Liability Derivatives (a)

Type

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

(in thousands)

Derivatives not designated as hedging instruments

Commodity price derivatives

Derivatives - current

167,406

Derivatives - current

87,741

Interest rate derivatives

Derivatives - current

11,903

Derivatives - current

886

Commodity price derivatives

Derivatives - noncurrent

152,731

Derivatives - noncurrent

64,829

Interest rate derivatives

Derivatives - noncurrent

15,762

Derivatives - noncurrent

9,227

Total derivatives not designated as hedging instruments

347,802

162,683

(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.


	Amount of Gain/(Loss) Recognized in AOCI on Effective Portion
	Year Ended December 31,
Derivatives in Cash Flow Hedging Relationships	2011		2010		2009
	(in thousands)
Interest rate derivatives	$	—	$	—	$	(433	)
Commodity price derivatives		—		—		13,407

Total	$	—	$	—	$	12,974


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,
		2011			2010			2009
		(in thousands)
Interest rate derivatives	Interest expense	$	(282	)	$	(1,698	)	$	(6,835	)
Interest rate derivatives	Derivative gains (losses), net		—			(2,465	)		—
Commodity price derivatives	Oil and gas revenue		32,918			89,040			121,066

Total		$	32,636		$	84,877		$	114,231

106

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009


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,
		2011		2010		2009
		(in thousands)
Interest rate derivatives	Derivative gains (losses), net	$	3,098	$	36,597	$	(15,423	)
Commodity price derivatives	Derivative gains (losses), net		389,654		414,302		(180,134	)

Total		$	392,752	$	450,899	$	(195,557	)

AOCI - Hedging. The effective portions of deferred cash flow hedge gains and losses, net of associated taxes are reflected in AOCI-Hedging as of December 31, 2011 and 2010, and are being transferred to oil revenue (for deferred commodity hedge losses) and to interest expense (for deferred interest rate hedge gains and losses) in the same periods in which the hedged transactions are recorded in earnings. In accordance with the change to the mark-to-market method of accounting on February 1, 2009, the Company recognizes changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which the changes occur.

As of December 31, 2011, AOCI - Hedging represented net deferred losses of $3.1 million compared to net deferred gains of $7.4 million as of December 31, 2010. The AOCI - Hedging balance as of December 31, 2011 was comprised of $3.1 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 the 12 months ending December 31, 2012, the Company expects to reclassify $3.1 million of AOCI – Hedging net deferred losses to oil revenues and $317 thousand of AOCI – Hedging net deferred losses to interest expense. The Company also expects to reclassify $1.3 million of net deferred income tax benefits associated with hedge derivatives during the 12 months ending December 31, 2012 from AOCI – Hedging to income tax benefit.

NOTE J. Major Customers and Derivative Counterparties

Sales to 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 Company is of the opinion that the loss of any one purchaser would not have an adverse effect on the ability of the Company to sell its oil and gas production.

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 years in the three years ended December 31, 2011. 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,
	2011			2010			2009
Plains Marketing LP		16	%		12	%		10	%
Occidental Energy Marketing Inc		14	%		8	%		7	%
Enterprise Products Partners L.P.		12	%		10	%		6	%

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.

107

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

The following table provides the Company’s derivative assets and liabilities by counterparty as of December 31, 2011:


	Assets		Liabilities
	(in thousands)
Citibank, N.A.	$	138,267	$	6,850
JP Morgan Chase		117,335		13,070
BNP Paribas		41,879		6,391
Barclays Capital		35,413		4,278
Societe Generale		32,376		2,241
Credit Agricole		28,545		5,487
Toronto Dominion		20,856		1,369
Credit Suisse		16,076		4,779
J. Aron & Company		15,985		3,139
BMO Financial Group		13,146		12,365
Wells Fargo Bank, N.A.		12,539		46,216
Morgan Stanley		4,923		774
Den Norske Bank		4,582		—
Merrill Lynch		153		1,017

Total	$	482,075	$	107,976

NOTE K. 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, 2011, 2010 and 2009:


	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Beginning asset retirement obligations	$	152,291		$	166,434		$	172,433
Liabilities assumed in acquisitions		6			6			—
New wells placed on production		9,233			5,218			625
Changes in estimates (a)		7,490			24,075			40,153
Liabilities reclassified to discontinued operations held for sale		(29,892	)		(5,779	)		—
Disposition of wells		(448	)		(30,693	)		(13,334	)
Liabilities settled		(12,880	)		(17,838	)		(45,010	)
Accretion of discount on continuing operations		8,256			7,945			8,050
Accretion of discount on discontinued operations		2,686			2,923			3,517

Ending asset retirement obligations	$	136,742		$	152,291		$	166,434

(a)

The change in the 2011 and 2010 estimates are primarily due to increases in abandonment cost estimates based in part on recent actual costs incurred and a decline in credit-adjusted risk-free discount rates used to value increases in asset retirement obligations. These increases were partially offset by higher oil and NGL prices used to calculate proved reserves at December 31, 2011 and 2010, 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. The change in the 2009 estimate is primarily due to (i) lower gas prices used to calculate proved reserves at December 31, 2009, which had the effect of shortening the economic life of wells and increasing the present value of future retirement obligations primarily in the Raton, Hugoton and West Panhandle gas fields and (ii) a $19.9 million increase in East Cameron facilities reclamation and abandonment estimates.

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of December 31, 2011 and 2010, the current portions of the Company’s asset retirement obligations were $14.2 million and $19.9 million, respectively.

108

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

NOTE L. Interest and Other Income

The following table provides the components of the Company’s interest and other income during the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011		2010			2009
	(in thousands)
Third-party income from vertical integration services (a)	$	45,115	$	169		$	—
Alaskan Petroleum Production Tax credits and refunds (b)		38,939		47,652			94,989
Equity interest in income (loss) of EFS Midstream		7,868		(819	)		—
Eagle Ford Shale land fees		3,747		—			—
Other income		3,937		4,565			3,631
Deferred compensation plan income		1,657		1,228			1,034
Interest income		697		4,177			1,935

Total interest and other income	$	101,960	$	56,972		$	101,589

(a)	Third-party income from vertical integration services represents the third-party working interests’ share of earnings associated with Company-provided fracture stimulation, drilling and related services.

(b)	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.

NOTE M. Asset Divestitures

During the years ended December 31, 2011, 2010 and 2009, the Company completed asset divestitures for net proceeds of $819.0 million, $313.8 million and $51.6 million, respectively. The Company recorded net losses on disposition of assets in continuing operations of $3.6 million and $774 thousand during the years ended December 31, 2011 and 2009, respectively, and a net gain on disposition of assets in continuing operations of $19.1 million during the year ended December 31, 2010. The Company recorded gains from the disposition of discontinued operations of $645.2 million and $17.5 million during the years ended December 31, 2011 and 2009. The following describes the significant divestitures of continuing operations:

•

Eagle Ford Shale. 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, including normal closing adjustments, resulting in a pretax gain of $6.0 million in 2010 and a $46.2 million deferred gain that is being amortized as a reduction to production costs over a 20-year period. Under the terms of the transaction, the purchaser is also paying 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets;

•

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

The following describes the significant divestitures of discontinued operations:

•

Pioneer Tunisia. During December 2010, the Company committed to a plan to sell its Tunisia subsidiaries and in February 2011 completed the sale of Pioneer Tunisia to an unaffiliated third party for cash proceeds of $853.6

109

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

million, including normal closing adjustments. Pioneer Tunisia represents all of the Company’s Tunisian oil and gas operations. Accordingly, assets, liabilities and historic results of operations of Pioneer Tunisia, including a $645.2 million pretax gain on disposition of assets, have been classified as discontinued operations herein. (Refer to Note U for further information regarding discontinued operations);

•

Mississippi and Gulf of Mexico Shelf. During 2009, the Company sold its oil and gas asset properties in Mississippi and substantially all of its shelf properties in the Gulf of Mexico. In accordance with GAAP, the Company classified the results of operations attributable to these divestitures as discontinued operations, rather than as a component of continuing operations.

NOTE N. Other Expense

The following table provides the components of the Company’s other expense during the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Transportation commitment charge (a)	$	23,248		$	1,589		$	6,839
Above market drilling and rig termination costs (b)		20,132			37,516			54,223
Other		5,503			4,758			4,151
Contingency and environmental accrual adjustments		4,057			5,581			7,796
Inventory impairment (c)		3,126			10,729			2,275
Cancelled wells		3,009			1,591			2,047
Legal settlements		2,725			501			315
Loss on extinguishment of debt		2,366			—			—
Tax penalties and adjustments		693			3,516			263
Well servicing operations (d)		—			13,065			12,437
Bad debt expense (recovery)		(1,693	)		(442	)		4,356

Total other expense	$	63,166		$	78,404		$	94,702

(a)	Primarily represents contract deficiency payments on excess pipeline capacity.

(b)	Primarily represents rig termination fees and charges for the portion of Pioneer’s contracted drilling rig rates that are above market rates and are not charged to joint operations.

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

(d)	Represents idle well servicing costs.

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 $22.3 million and $36.6 million (net of tax refunds) during 2011 and 2010, respectively, and received tax refunds (net of tax payments) during 2009 of $42.6 million. These payments and net refunds include tax payments related to Pioneer Tunisia’s and Pioneer South Africa’s operations of $12.2 million, $17.8 million and $10.6 million during 2011, 2010 and 2009, respectively. During 2009, the Company received $61.6 million of refunds as a result of carrying back 2007 and 2008 net operating losses. In November 2009, President Obama signed into law the Worker, Homeownership, and Business Assistance Act of 2009, which expanded the carryback period from two years to five years and suspended certain loss utilization limitations. Pursuant to this new legislation, the Company filed an amended carryback claim and received an additional $19.9 million refund during 2010.

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.

110

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2011, the Company had no unrecognized tax benefits. The Company’s policy is to account for interest charges with respect to income taxes as interest expense and any penalties, with respect to income taxes, as other expense in the consolidated statements of operations. The Company files income tax returns in the U.S. federal jurisdiction, and various state and foreign jurisdictions. With few exceptions, the Company believes that it is no longer subject to examinations by tax authorities for years before 2006. The Internal Revenue Service recently closed the examination of the 2007, 2008 and 2009 tax years, and is concluding an examination of the 2010 tax year. As of December 31, 2011, 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			2010
Various U.S. states			2007
Tunisia			2006
South Africa			2006

The Company’s income tax (provision) benefit and amounts separately allocated were attributable to the following items for the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Income from continuing operations	$	(197,644	)	$	(269,627	)	$	83,195
Income from discontinued operations		(257,950	)		270			(85,527	)
Changes in goodwill – tax benefits related to stock-based compensation		40			453			124
Changes in stockholders’ equity:
Net deferred hedge gains		8,407			23,648			50,059
Tax benefits related to stock-based compensation		31,087			(153	)		1
Tax on Pioneer Southwest common units sold by the Company on December 12, 2011		(15,381	)		—			—

The Company’s income tax (provision) benefit attributable to income from continuing operations consisted of the following for the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Current:
U.S. federal	$	—		$	—		$	21,714
U.S. state		(9,065	)		(9,864	)		(10,010	)
Foreign		—			—			(551	)

		(9,065	)		(9,864	)		11,153

Deferred:
U.S. federal		(207,146	)		(263,063	)		63,970
U.S. state		18,567			3,300			8,072

		(188,579	)		(259,763	)		72,042


Income tax (provision) benefit	$	(197,644	)	$	(269,627	)	$	83,195

111

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

Income (loss) from continuing operations before income taxes less net income attributable to the noncontrolling interests consists of the following for the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011		2010		2009
	(in thousands)
U.S. federal	$	608,981	$	740,785	$	(234,860	)
Foreign		—		—		(157	)

	$	608,981	$	740,785	$	(235,017	)

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, 2011, 2010 and 2009:


	Year Ended December 31,
	2011			2010		2009
	(in percentages)
U.S. federal statutory tax rate		35.0			35.0		35.0
State income taxes (net of federal benefit)		(0.9	)		0.5		(0.4	)
Other		(1.6	)		0.9		0.8

Consolidated effective tax rate		32.5			36.4		35.4

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, 2011 and 2010:


	December 31,
	2011			2010
	(in thousands)
Deferred tax assets:
Foreign tax credit carryforward	$	—		$	174,054
Asset retirement obligations		47,860			50,886
Other		82,828			78,014

Total deferred tax assets		130,688			302,954
Valuation allowances		—			(6,632	)

Net deferred tax assets		130,688			296,322
Deferred tax liabilities:
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes		(1,692,317	)		(1,663,343	)
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes		(102,351	)		(58,866	)
State taxes and other		(191,621	)		(117,685	)
Net deferred hedge gains		(144,558	)		(52,232	)

Total deferred tax liabilities		(2,130,847	)		(1,892,126	)

Net deferred tax liability	$	(2,000,159	)	$	(1,595,804	)


Reflected in accompanying consolidated balance sheets as:
Current deferred income tax asset	$	77,005		$	156,650
Current deferred income tax liability		—			(1,144	)
Non-current deferred income tax liability		(2,077,164	)		(1,751,310	)

Total	$	(2,000,159	)	$	(1,595,804	)

During 2010, the Company utilized all available NOLs in the United States and South Africa. At December 31, 2010, the Company had $174.1 million of foreign tax credit carryforwards, which were available to offset future U.S.

112

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

regular taxable income, if any. As a result of the sale of Pioneer Tunisia during February 2011, the Company realized all of these carryforwards in 2011. Pursuant to GAAP, the Company’s $174.1 million deferred tax asset related to the foreign tax credit carryforwards at December 31, 2010 is net of $12.2 million of unrealized excess tax benefits from stock based compensation.

The Company’s income tax (provision) benefit attributable to income from discontinued operations consisted of the following for the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Current:
U.S. state	$	(4,354	)	$	(538	)	$	(1,300	)
Foreign		(39,543	)		(24,948	)		(18,757	)

		(43,897	)		(25,486	)		(20,057	)

Deferred:
U.S. federal		(227,385	)		42,155			(48,879	)
U.S. state		(1,836	)		3			—
Foreign		15,168			(16,402	)		(16,591	)

		(214,053	)		25,756			(65,470	)


Income tax (provision) benefit	$	(257,950	)	$	270		$	(85,527	)

NOTE P. Net Income (Loss) Per Share Attributable To Common Stockholders

In the calculation of basic net income (loss) 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 (loss) 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 (loss) 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, 2011, the two-class method of calculating the Company’s diluted net income (loss) per share was more dilutive than the treasury stock method.

The Company’s basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) 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 (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding.

113

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

The following table is a reconciliation of the Company’s net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and to diluted net income (loss) attributable to common stockholders for the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31, 2011
	Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) 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 (loss) attributable to common stockholders	$	471,158		$	134,050		$	605,208
Participating basic earnings (a)		(10,818	)		(3,078	)		(13,896	)

Basic 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


	Year Ended December 31, 2009
	Continuing Operations			Discontinued Operations		Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	(151,822	)	$	99,716	$	(52,106	)
Participating basic earnings (a)		(571	)		375		(196	)

Basic net income (loss) attributable to common stockholders		(152,393	)		100,091		(52,302	)
Reallocation of participating earnings (a)		—			—		—

Diluted income (loss) attributable to common stockholders	$	(152,393	)	$	100,091	$	(52,302	)

(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.

114

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

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, 2011, 2010 and 2009:


	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Weighted average common shares outstanding:
Basic		116,904		115,062		114,176
Dilutive common stock options (a)		190		212		—
Contingently issuable—performance shares (a)		424		646		—
Convertible notes dilution (b)		1,697		410		—


Diluted		119,215		116,330		114,176

(a)

Diluted earnings per share were calculated using the two-class method for the years ended December 31, 2011, 2010 and 2009. The following common stock equivalents were excluded from the diluted loss per share calculations for the year ended 2009 because they would have been anti-dilutive to the calculations: 173,915 outstanding options to purchase the Company’s common stock and 223,969 performance shares.

(b)

During January 2008, the Company issued $500 million of 2.875% Convertible Senior Notes. Weighted average common shares outstanding have been increased to reflect the dilutive effect that would have resulted if the 2.875% Convertible Senior Notes had qualified for and been converted during the years ended December 31, 2011 and 2010, respectively. The 2.875% Convertible Senior Notes were not dilutive to the per share calculations of 2009.

NOTE Q. Geographic Operating Segment Information

The Company has determined that its business is comprised of only one geographic and business segment as the Company’s vertical integration services are ancillary to production operations and are not separately managed.

NOTE R. Impairment

The Company reviews its long-lived assets for impairment, including oil and gas proved properties, whenever events or circumstances indicate that their carrying values may not be fully recoverable. During the years ended 2011 and 2009, the Company recognized $354.4 million and $21.1 million, respectively, of charges from impairment of oil and gas proved properties.

2011 impairment. During the third and fourth quarters of 2011, events and circumstances provided indications of possible impairment of certain of the Company’s dry gas assets, including oil and gas proved properties in the Company’s Edwards, Austin Chalk, Raton and Barnett Shale fields. The events and circumstances indicating possible impairment of these fields were primarily related to a reduction in Management’s Price Outlook for gas that led to a decrease in estimated future undiscounted net cash flows attributable to each fields’ proved reserves. During the fourth quarter of 2011, the estimate of undiscounted future net cash flows attributable to the Company’s Edwards and Austin Chalk fields in South Texas indicated that their carrying amounts were partially unrecoverable. Consequently, the Company recorded $354.4 million of noncash impairment charges to reduce the carrying values of these fields to their estimated fair values, represented by the estimated discounted future cash flows attributable to the assets, which were derived from Level 3 fair value inputs, including Management’s Price Outlook and the primary factors described in Note B and below.

2009 impairment. During the first quarter of 2009, declines in commodity prices provided indications that the carrying values of the Company’s oil and gas properties in the Uinta/Piceance area may have been impaired. The Company’s estimates of the undiscounted future cash flows attributed to the assets indicated that their carrying amounts were not expected to be recovered. Consequently, the Company recorded noncash charges during the first quarter of 2009 of $21.1 million to reduce the carrying value of the Uinta/Piceance area oil and gas properties. During 2010, the Company sold substantially all of its oil and gas properties in the Uinta/Piceance area. See Note M for more information on asset divestitures. The impairment charges reduced the oil and gas properties’ carrying values to their estimated fair values on those dates, represented by the estimated discounted future cash flows attributable to the assets, which were derived from Level 3 fair value inputs.

115

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

Impairment risks. The Company’s estimates of undiscounted future net cash flows attributable to the Raton and Barnett Shale fields’ oil and gas properties indicated on December 31, 2011 that their carrying amounts were expected to be recovered. However, the carrying values of these fields continue to be at risk for impairment if future estimates of undiscounted cash flows decline. As of December 31, 2011, the Company’s Raton and Barnett Shale fields have carrying values of $2.3 billion and $456.8 million, respectively.

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 the fields.

NOTE S. Deferred Revenue

The Company’s remaining volumetric production payment (“VPP”) represents a limited-term overriding royalty interest in oil reserves that: (i) entitles the purchaser to receive production volumes over a period of time from specific lease interests, (ii) is free and clear of all associated future production costs and capital expenditures associated with the reserves, (iii) is nonrecourse to the Company (i.e., the purchaser’s only recourse is to the reserves acquired), (iv) transferred title of the reserves to the purchaser and (v) allows the Company to retain the remaining reserves after the VPPs volumetric quantities have been delivered.

At the inception of the VPP agreements, the Company (i) removed the proved reserves associated with the VPP, (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to oil revenues over the term of the VPP, (iii) retained responsibility for 100 percent of the production costs and capital costs related to VPP interests and (iv) no longer recognizes production associated with the VPP volumes.

The following table provides information about the deferred revenue carrying values of the Company’s VPP (in thousands):


Deferred revenue at December 31, 2010	$	87,020
Less: 2011 amortization		(44,951	)

Deferred revenue at December 31, 2011	$	42,069

The remaining $42.1 million of deferred revenue will be recognized in oil revenues in the consolidated statements of operations in 2012, assuming the related VPP production volumes are delivered as scheduled.

NOTE T. Insurance Claims

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 million during November 2010. East Cameron 322 facility insurance recoveries and reclamation and abandonment costs are included in hurricane activity, net in the accompanying consolidated statements of operations.

NOTE U. Discontinued Operations

The following lists the divestitures that have been reflected as discontinued operations in the accompanying consolidated balance sheets and statements of operations:

•

During December 2011, the Company committed to a plan to divest Pioneer South Africa. The plan is expected to result in the sale of Pioneer South Africa during 2012;

116

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

•

During December 2010, the Company committed to a plan to sell Pioneer Tunisia and in February 2011 completed a sale to an unaffiliated third party for cash proceeds of $853.6 million, including normal closing adjustments. Associated therewith, the Company recognized a pretax gain of $645.2 million;

•

During the fourth quarter of 2009, the Company recorded a $119.3 million receivable from the Bureau of Ocean Energy Management, Regulation, and Enforcement (“BOEMRE”) for the recovery of excess royalties paid by the Company on qualifying leases in the Gulf of Mexico. During 2010, the BOEMRE paid the Company the $119.3 million receivable plus an additional $35.3 million of associated interest on the excess royalty payments. The properties that were the source of these royalty and interest recoveries were sold by the Company and classified as discontinued operations during 2006;

•

The Company sold substantially all of its Mississippi assets and shelf properties in the Gulf of Mexico during 2009.

See Note B for additional information about the presentation of the Company’s discontinued operations in the accompanying consolidated balance sheets and statements of operations.

The following table summarizes the components of the Company’s discontinued operations (principally related to the divestitures of Pioneer South Africa and Pioneer Tunisia) for the years ended December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Revenues and other income:
Oil and gas	$	100,275		$	236,343		$	221,279
Interest and other (a)		6,193			49,076			120,062
Gain on disposition of assets, net (b)		645,241			36			17,491

		751,709			285,455			358,832

Costs and expenses:
Oil and gas production		5,519			14,754			39,621
Production and ad valorem taxes		—			—			(27	)
Depletion, depreciation and amortization (b)		41,916			98,495			91,273
Exploration and abandonments (b)		4,268			15,908			19,240
General and administrative		10,286			5,697			9,647
Accretion of discount on asset retirement obligations (b)		2,686			2,923			3,517
Interest		773			—			8
Other		5,159			13,898			10,310

		70,607			151,675			173,589

Income from discontinued operations before income taxes		681,102			133,780			185,243
Income tax benefit (provision):
Current		(43,897	)		(25,486	)		(20,057	)
Deferred (b)		(214,053	)		25,756			(65,470	)

Income from discontinued operations	$	423,152		$	134,050		$	99,716

(a)

Primarily comprised of (i) $119.3 million receivable from the BOEMRE recorded in the fourth quarter of 2009 for the recovery of excess royalties paid by the Company on qualifying deepwater leases in the Gulf of Mexico, (ii) $35.3 million of associated interest on the aforementioned excess royalty payments received from BOEMRE during the second quarter of 2010, (iii) $2.8 million of legal settlements paid to the Company during the third quarter of 2010 on Gulf of Mexico discontinued operations sold during 2006, (iv) $2.1 million of Canadian sales tax refunds paid to the Company during the second quarter of 2010 attributable Canadian discontinued operations sold during 2007, (v) $3.8 million of Argentine value added tax contingency charge reversals recorded during 2010 on Argentine discontinued operations sold during 2006, (vi) $2.0 million of interest received during the first quarter of 2011 associated with the 2010 recovery of excess royalties paid by the Company on qualifying deepwater leases in the Gulf of Mexico and (vii) $2.8 million of interest income associated with Pioneer Tunisia operations recorded during the first quarter of 2011.

(b)	Represents the significant noncash components of discontinued operations.

117

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

As of December 31, 2011 and 2010, the carrying values of Pioneer South Africa and Pioneer Tunisia assets and liabilities, respectively, were included in discontinued operations held for sale in the accompanying consolidated balance sheet and are comprised of the following (in thousands):


	December 31,
	2011		2010
Composition of assets included in discontinued operations held for sale:
Current assets (excluding cash and cash equivalents)	$	10,465	$	43,500
Property, plant and equipment		53,025		184,357
Deferred tax assets		9,816		14,731
Other assets, net		43		39,153

Total assets	$	73,349	$	281,741

Composition of liabilities included in discontinued operations held for sale:
Current liabilities	$	11,689	$	30,148
Deferred tax liabilities		—		72,663
Deferred revenue		34,320		—
Other liabilities		29,892		5,781

Total liabilities	$	75,901	$	108,592

NOTE V. Subsequent Events

During January 2012, the Company sold a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale to unaffiliated third parties for proceeds of $54.8 million. Associated therewith, the Company expects to record a pretax gain of $40 million to $43 million during the three months ended March 31, 2012.

The Company has evaluated subsequent events through the date of issuance of the consolidated financial statements. Except as described above, the Company is not aware of any reportable subsequent events.

118

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2011, 2010 and 2009

Capitalized Costs


	December 31,
	2011 (a)			2010 (b)
	(in thousands)
Oil and gas properties:
Proved	$	12,373,848		$	11,003,805
Unproved		235,527			191,112

Capitalized costs for oil and gas properties		12,609,375			11,194,917
Less accumulated depletion, depreciation and amortization		(3,955,483	)		(3,447,740	)

Net capitalized costs for oil and gas properties	$	8,653,892		$	7,747,177

(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.

(b)	Includes $264.7 million of proved property and $81.3 million of accumulated depletion, depreciation and amortization related to Pioneer Tunisia, which was classified as held for sale at December 31, 2010.

Costs Incurred for Oil and Gas Producing Activities (a)


	Property Acquisition Costs				Exploration		Development			Total Costs
	Proved		Unproved		Costs		Costs			Incurred
	(in thousands)
Year Ended December 31, 2011:
United States	$	7,571	$	124,326	$	560,036	$	1,470,362		$	2,162,295
South Africa		—		—		341		(3,602	)		(3,261	)
Tunisia		—		—		6,819		7,633			14,452

Total	$	7,571	$	124,326	$	567,196	$	1,474,393		$	2,173,486

Year Ended December 31, 2010:
United States	$	6,566	$	175,007	$	246,186	$	685,670		$	1,113,429
South Africa		—		—		512		1,782			2,294
Tunisia		—		—		30,629		39,874			70,503
Other		—		—		329		—			329

Total	$	6,566	$	175,007	$	277,656	$	727,326		$	1,186,555

Year Ended December 31, 2009:
United States	$	8,770	$	80,088	$	90,737	$	255,538		$	435,133
South Africa		65		—		623		(1,448	)		(760	)
Tunisia		—		—		19,931		17,470			37,401
Other		—		—		724		—			724

Total	$	8,835	$	80,088	$	112,015	$	271,560		$	472,498

(a) The costs incurred for oil and gas producing activities includes the following amounts of asset retirement obligations:


	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Proved property acquisition costs	$	6	$	6	$	—
Exploration costs		1,222		6,820		1,068
Development costs		18,274		14,369		19,859

Total	$	19,502	$	21,195	$	20,927

119

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2011, 2010 and 2009

The Company has continuing operations in only one business and geographic segment, that being United States 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.

Reserve Quantity Information

The estimates of the Company’s proved reserves as of December 31, 2011, 2010, and 2009, which were located in the United States, South Africa and Tunisia, 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 with no provision for price and cost escalations except by contractual arrangements.

During the fourth quarter of 2009, the Company adopted the SEC’s final rule on “Modernization of Oil and Gas Reporting” (the “Reserve Ruling”) and the FASB issued an ASU to ASC Topic 932 that aligns Topic 932 estimation and disclosure requirements with the Reserve Ruling. The Reserve Ruling and Topic 932 ASU became effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. The key provisions of the Reserve Ruling and Topic 932 ASU are as follows:

•

Adding to and amending other definitions used in estimating proved oil and gas reserves, such as “reliable technology” and “reasonable certainty”;

•

Broadening the types of technology that a registrant may use to establish reserves estimates and categories; and

•

Changing disclosure requirements and providing formats for tabular reserve disclosures, including the following new disclosure provisions:

•

Disclosure of reserves from non-traditional sources as oil and gas reserves,

•

Optional disclosure of probable and possible reserves,

•

Disclosure based on a new definition of the term “geographic area” and

•

Disclosure of significant portions of reserve quantities and standardized measure of discounted future net cash flows attributable to a consolidated subsidiary in which there is a significant noncontrolling interest.

The Company reports all reserves held under production sharing arrangements and concessions utilizing the “economic interest” method, which excludes the host country’s share of proved reserves. Estimated quantities for production sharing arrangements reported under the “economic interest” method are subject to fluctuations in the commodity prices of and recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. The reserve estimates as of December 31, 2011, 2010 and 2009 utilized respective oil prices of $94.77, $77.16 and $59.49 per Bbl (reflecting adjustments for oil quality), respective NGL prices of $46.47, $37.82 and $28.41 per Bbl, and respective gas prices of $3.88, $4.07 and $3.19 per Mcf (reflecting adjustments for Btu content, gas processing and shrinkage).

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.

The following table provides a rollforward of total proved reserves by geographic area and in total for the years ended December 31, 2011, 2010 and 2009, as well as proved developed and undeveloped reserves by geographic area and in total as of the beginning and end of each respective year. Oil and NGL volumes are expressed in MBbls, gas volumes are expressed in MMcf and total volumes are expressed in barrels of oil equivalent (“MBOE”).

120

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2011, 2010 and 2009


	Year Ended December 31,
	2011												2010												2009
	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)
Total Proved Reserves:
UNITED STATES
Balance, January 1		360,716			184,218			2,635,702			984,217			315,593			156,834			2,450,131			880,781			294,357			154,535			2,917,029			935,063
Revisions of previous estimates		8,816			(5,750	)		(248,355	)		(38,328	)		12,897			19,291			188,109			63,540			21,910			8,263			(335,006	)		(25,660	)
Purchases of minerals-in-place		2,810			863			4,569			4,435			1,944			555			3,364			3,060			—			—			—			—
Extensions and discoveries		70,864			39,912			269,699			155,728			31,428			15,669			155,448			73,005			10,413			1,229			18,865			14,785
Improved recovery		1,394			—			—			1,394			9,716			—			—			9,716			—			—			—			—
Production		(14,826	)		(8,208	)		(143,243	)		(46,907	)		(10,297	)		(7,203	)		(139,658	)		(40,777	)		(9,315	)		(7,193	)		(147,473	)		(41,088	)
Sales of minerals-in-place		—			—			—			—			(565	)		(928	)		(21,692	)		(5,108	)		(1,772	)		—			(3,284	)		(2,319	)

Balance, December 31 (c)		429,774			211,035			2,518,372			1,060,539			360,716			184,218			2,635,702			984,217			315,593			156,834			2,450,131			880,781

SOUTH AFRICA
Balance, January 1		274			—			15,671			2,887			217			—			25,790			4,516			471			—			38,624			6,909
Revisions of previous estimates		122			—			1,159			315			282			—			743			406			(117	)		—			(3,513	)		(703	)
Extensions and discoveries		28						3,344			585			—			—			—			—			—			—			—			—
Production		(193)			—			(7,508)			(1,445)			(225)			—			(10,862)			(2,035)			(137)			—			(9,321)			(1,690)

Balance, December 31		231			—			12,666			2,342			274			—			15,671			2,887			217			—			25,790			4,516

TUNISIA
Balance, January 1		19,819			—			23,149			23,677			9,526			—			22,880			13,339			13,587			—			24,104			17,604
Revisions of previous estimates		—			—			—			—			1,927			—			1,309			2,145			(1,678	)		—			(615	)		(1,780	)
Extensions and discoveries		—			—			—			—			10,707			—			—			10,707			—			—			—			—
Production		(200	)		—			(181	)		(230	)		(1,781	)		—			(1,040	)		(1,954	)		(2,383	)		—			(609	)		(2,485	)
Sales of minerals-in-place		(19,619)			—			(22,968)			(23,447)			(560)			—			—			(560)			—			—			—			—

Balance, December 31		—			—			—			—			19,819			—			23,149			23,677			9,526			—			22,880			13,339

TOTAL
Balance, January 1		380,809			184,218			2,674,522			1,010,781			325,336			156,834			2,498,801			898,636			308,415			154,535			2,979,757			959,576
Revisions of previous estimates		8,938			(5,750	)		(247,196	)		(38,013	)		15,106			19,291			190,161			66,091			20,115			8,263			(339,134	)		(28,143	)
Purchases of minerals-in-place		2,810			863			4,569			4,435			1,944			555			3,364			3,060			—			—			—			—
Extensions and discoveries		70,892			39,912			273,043			156,313			42,135			15,669			155,448			83,712			10,413			1,229			18,865			14,785
Improved recovery		1,394			—			—			1,394			9,716			—			—			9,716			—			—			—			—
Production (b)		(15,219	)		(8,208	)		(150,932	)		(48,582	)		(12,303	)		(7,203	)		(151,560	)		(44,766	)		(11,835	)		(7,193	)		(157,403	)		(45,263	)
Sales of minerals-in-place		(19,619)			—			(22,968)			(23,447)			(1,125)			(928)			(21,692)			(5,668)			(1,772)			—			(3,284)			(2,319)

Balance, December 31		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

(a)

The proved gas reserves as of December 31, 2011, 2010 and 2009 include 301,123 MMcf, 303,748 MMcf, and 310,463 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 2011, 2010 and 2009 includes approximately 17,727 MMcf, 17,289 MMcf and 18,027 MMcf of field fuel, respectively. Also, for 2011, 2010 and 2009, production includes 1,675 MBOE, 3,989 MBOE and 4,175 MBOE of production associated with discontinued operations. See Note U for additional information.

(c)	As of December 31, 2011 , 2010 and 2009, the portions of the Company’s United States proved reserves attributable to noncontrolling interests in Pioneer Southwest were as follows:

121

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2011, 2010 and 2009


	Year Ended December 31,
	2011								2010								2009
	Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBOE)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBOE)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBOE)
Total Proved Reserves:
Noncontrolling interest in total proved reserves		14,747		5,699		22,012		24,114		11,852		4,753		18,843		19,745		10,539		3,741		15,448		16,854

The following table provides the Company’s proved developed and proved undeveloped reserves as of January 1 and December 31, 2011, 2010 and 2009:


	Year Ended December 31,
	2011									2010									2009
	Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)			Total (MBOE)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)			Total (MBOE)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBOE)
Proved Developed Reserves:
United States		160,421		108,785		1,736,765			558,667		135,568		93,015		1,671,052			507,092		119,964		91,456		1,907,719		529,373
South Africa		274		—		15,671			2,886		217		—		25,790			4,516		471		—		38,624		6,909
Tunisia		12,121		—		23,175			15,984		8,478		—		22,880			12,291		13,587		—		24,104		17,604

Balance, January 1		172,816		108,785		1,775,611			577,537		144,263		93,015		1,719,722			523,899		134,022		91,456		1,970,447		553,886


United States		189,975		120,405		1,840,697			617,164		160,421		108,785		1,736,765			558,667		135,568		93,015		1,671,052		507,092
South Africa		231		—		12,666			2,342		274		—		15,671			2,886		217		—		25,790		4,516
Tunisia		—		—		—			—		12,121		—		23,175			15,984		8,478		—		22,880		12,291

Balance, December 31		190,206		120,405		1,853,363			619,506		172,816		108,785		1,775,611			577,537		144,263		93,015		1,719,722		523,899

Proved Undeveloped Reserves (a):
United States		200,295		75,433		898,937			425,550		180,025		63,819		779,079			373,689		174,393		63,079		1,009,310		405,690
Tunisia		7,698		—		(26	)		7,694		1,048		—		—			1,048		—		—		—		—

Balance, January 1		207,993		75,433		898,911			433,244		181,073		63,819		779,079			374,737		174,393		63,079		1,009,310		405,690

United States		239,799		90,630		677,675			443,375		200,295		75,433		898,937			425,550		180,025		63,819		779,079		373,689
Tunisia		—		—		—			—		7,698		—		(26	)		7,694		1,048		—		—		1,048

Balance, December 31		239,799		90,630		677,675			443,375		207,993		75,433		898,911			433,244		181,073		63,819		779,079		374,737

(a)

As of December 31, 2011, the Company has 4,599 proved undeveloped well locations, as compared to 4,727 and 4,582 at December 31, 2010 and 2009, respectively. During 2011, the Company’s development drilling costs incurred increased by 103 percent, as compared to 2010, and the Company converted 62,436 MBOE of proved undeveloped reserves to proved developed reserves. The increase in development drilling costs during 2011 is reflective of the Company’s expansion of oil- and liquids-focused drilling expenditures during 2011. The Company’s proved undeveloped well locations that have remained undeveloped for five years or more decreased by 42 percent to 858 as of December 31, 2011, as compared to 1,467 well locations at December 31, 2010. All these undeveloped well locations are in the Spraberry field in the Permian Basin of West Texas. The Company expects to continue to reduce the average age of its undeveloped well locations in the Spraberry field as a result of increases in development drilling budgets in 2012 and future years.

122

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2011, 2010 and 2009

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, 2011, 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 $307.3 million at December 31, 2011.

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.

123

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2011, 2010 and 2009

The following tables provide the standardized measure of discounted future cash flows by geographic area and in total as of December 31, 2011, 2010 and 2009, as well as a roll forward in total for each respective year:


	December 31,
	2011			2010			2009
	(in thousands)

UNITED STATES
Oil and gas producing activities:
Future cash inflows	$	59,106,103		$	44,100,276		$	29,884,670
Future production costs		(21,145,304	)		(17,313,651	)		(12,527,319	)
Future development costs		(8,424,574	)		(6,663,322	)		(4,623,978	)
Future income tax expense		(9,552,172	)		(6,453,833	)		(3,468,973	)

		19,984,053			13,669,470			9,264,400
10% annual discount factor		(12,211,716	)		(8,822,857	)		(6,193,552	)

Standardized measure of discounted future cash flows (a)	$	7,772,337		$	4,846,613		$	3,070,848

SOUTH AFRICA
Oil and gas producing activities:
Future cash inflows	$	114,254		$	123,215		$	147,022
Future production costs		(8,712	)		(7,805	)		(11,130	)
Future development costs		(41,833	)		(42,281	)		(41,445	)
Future income tax expense		(29,343	)		(27,052	)		(21,830	)

		34,366			46,077			72,617
10% annual discount factor		6,320			1,502			(712	)

Standardized measure of discounted future cash flows	$	40,686		$	47,579		$	71,905

TUNISIA
Oil and gas producing activities:
Future cash inflows	$	—		$	1,771,661		$	750,078
Future production costs		—			(218,785	)		(193,420	)
Future development costs		—			(64,184	)		(75,083	)
Future income tax expense		—			(754,238	)		(213,847	)

		—			734,454			267,728
10% annual discount factor		—			(216,637	)		(79,927	)

Standardized measure of discounted future cash flows	$	—		$	517,817		$	187,801

TOTAL
Oil and gas producing activities:
Future cash inflows	$	59,220,357		$	45,995,152		$	30,781,770
Future production costs		(21,154,016	)		(17,540,241	)		(12,731,869	)
Future development costs (b)		(8,466,407	)		(6,769,787	)		(4,740,506	)
Future income tax expense		(9,581,515	)		(7,235,123	)		(3,704,650	)

		20,018,419			14,450,001			9,604,745
10% annual discount factor		(12,205,396	)		(9,037,992	)		(6,274,191	)

Standardized measure of discounted future cash flows	$	7,813,023		$	5,412,009		$	3,330,554

(a)	Includes $378.6 million attributable to a 48 percent noncontrolling interest in Pioneer Southwest for 2011 and $214.2 million and $99.6 million, respectively, attributable to a 38 percent noncontrolling interest in Pioneer Southwest for 2010 and 2009.

(b)

Includes $785.0 million, $823.5 million and $453.5 million of undiscounted future asset retirement expenditures estimated as of December 31, 2011, 2010 and 2009, respectively, using current estimates of future abandonment costs. See Note K for corresponding information regarding the Company’s discounted asset retirement obligations.

124

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2011, 2010 and 2009

Changes in Standardized Measure of Discounted Future Net Cash Flows


	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Oil and gas sales, net of production costs	$	(1,755,153	)	$	(1,373,943	)	$	(1,018,798	)
Net changes in prices and production costs		2,615,481			2,098,422			1,006,250
Extensions, discoveries and improved recovery		1,676,866			1,017,597			82,431
Development costs incurred during the period		750,268			380,754			183,936
Sales of minerals-in-place		(1,021,513	)		(42,043	)		(22,006	)
Purchases of minerals-in-place		81,036			20,957			—
Revisions of estimated future development costs		(1,280,213	)		(952,508	)		(151,029	)
Revisions of previous quantity estimates		(442,120	)		626,693			(229,369	)
Accretion of discount		800,468			437,523			385,681
Changes in production rates, timing and other		1,660,419			1,415,999			281,326

Change in present value of future net revenues		3,085,539			3,629,451			518,422
Net change in present value of future income taxes		(684,525	)		(1,547,996	)		(375,255	)

		2,401,014			2,081,455			143,167
Balance, beginning of year		5,412,009			3,330,554			3,187,387

Balance, end of year	$	7,813,023		$	5,412,009		$	3,330,554

125

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2011, 2010 and 2009

Selected Quarterly Financial Results

The following table provides selected quarterly financial results for the years ended December 31, 2011 and 2010:


	Quarter
	First			Second			Third			Fourth (a)
	(In thousands, except per share data)
Year ended December 31, 2011:
Oil and gas revenues:
As reported	$	497,130		$	583,931		$	610,509		$	664,776
Less discontinued operations		(21,402	)		(21,519	)		(19,362	)		—

Adjusted	$	475,728		$	562,412		$	591,147		$	664,776

Total revenues:
As reported	$	283,123		$	831,569		$	1,031,689		$	703,053
Less discontinued operations		(21,769	)		(21,536	)		(19,544	)		—

Adjusted	$	261,354		$	810,033		$	1,012,145		$	703,053

Total costs and expenses:
As reported (b)	$	401,112		$	419,589		$	460,073		$	893,769
Less discontinued operations		(15,773	)		(18,463	)		(10,128	)		—

Adjusted	$	385,339		$	401,126		$	449,945		$	893,769

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	)

Year ended December 31, 2010:
Oil and gas revenues:
As reported	$	507,796		$	462,142		$	471,372		$	471,759
Less discontinued operations		(61,133	)		(60,600	)		(55,261	)		(17,778	)

Adjusted	$	446,663		$	401,542		$	416,111		$	453,981

Total revenues:
As reported (c)	$	817,428		$	662,394		$	616,382		$	486,110
Less discontinued operations		(64,599	)		(66,260	)		(51,149	)		(18,611	)

Adjusted	$	752,829		$	596,134		$	565,233		$	467,499

Total costs and expenses:
As reported	$	396,348		$	405,168		$	426,231		$	501,189
Less discontinued operations		(40,884	)		(36,679	)		(35,216	)		(16,034	)

Adjusted	$	355,464		$	368,489		$	391,015		$	485,155

Net income	$	260,606		$	188,689		$	114,573		$	82,127
Net income attributable to common stockholders	$	245,254		$	167,576		$	112,035		$	80,343
Net income attributable to common stockholders per share:
Basic	$	2.09		$	1.42		$	0.95		$	0.68
Diluted	$	2.08		$	1.41		$	0.94		$	0.67

(a)	During the fourth quarters of 2011 and 2010, the Company committed to plans to sell Pioneer South Africa and Pioneer Tunisia, respectively. Accordingly, the Pioneer South Africa and Pioneer Tunisia results of operations are classified as discontinued operations in all quarters presented.

(b)

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.

(c)	During the fourth quarter of 2010, the Company’s total revenues include $122.2 million of net mark-to-market derivative losses and a $140.0 million East Cameron 322 insurance recovery gain recorded in net hurricane activity.

126

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 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, 2011 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, 2011, 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, 2011, 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, 2011. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

127

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, 2011, 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, 2011, 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, 2011 and 2010 and the related consolidated statements of operations, stockholders’ equity, cash flows and comprehensive income (loss) for each of the three years in the period ended December 31, 2011, and our report dated February 29, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas

February 29, 2012

128

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 2012 and is incorporated herein by reference.

ITEM 11.

EXECUTIVE COMPENSATION

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, 2011:


	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)		26,905	$	22.64		3,394,400
Long-Term Incentive Plan		—		—		—
Employee Stock Purchase Plan		—		—		124,997
Equity compensation plans not approved by security holders		—		—		—

Total:		26,905	$	22.64		3,519,397

(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 less 625,003 cumulative shares issued through December 31, 2011. See Note G 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 remaining securities for future issuance reflects the deduction of the maximum number of shares that could be issued pursuant to grants of performance units outstanding at December 31, 2011.

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 2012 and is incorporated herein by reference.

129

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

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, 2011 and 2010

•

Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009

•

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2011, 2010 and 2009

•

Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009

•

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2011, 2010 and 2009

•

Notes to Consolidated Financial Statements

•

Unaudited Supplementary Information

(b)

Exhibits

The exhibits to this Report 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.

130

Exhibits



Exhibit Number		Description

2.1	—	Purchase and Sale Agreement by and between Pioneer as Seller and Marubeni Offshore Production (USA) Inc. as Purchaser (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 28, 2006).

2.2^*	—	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	—	Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 17, 2006).

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 4.5 (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 4.5 (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 4.5 (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 4.5 (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 4.5 (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 Natural Resources USA, Inc. and The Bank of New York Trust Company, N.A., as Trustee, with respect to the indenture identified above as Exhibit 4.5 (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 Natural Resources USA, Inc., 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 4.5 (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).

131


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 4.19 (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).

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).

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	—	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).

10.12 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).

10.13 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).

10.14 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).

10.15 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).

10.16 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).

10.17 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).

132


10.18 H (a)	—	Amendment No. 5 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed December 12, 2011.

10.19 H (a)	—	Amendment No. 6 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed January 12, 2012.

10.20	—	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).

10.21	—	Production Payment Purchase and Sale Agreement dated as of January 26, 2005 among the Company, as the Seller, and Royalty Acquisition Company, LLC, as the Buyer (related to Spraberry oil) (incorporated by reference to Exhibit 99.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 1, 2005).

10.22 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).

10.23 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).

10.24 H	—	Amended and restated Severance Agreement dated February 17, 2010, between the Company and David McManus (incorporated by reference to Exhibit 10.30 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009).

10.25 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).

10.26 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).

10.27 H	—	Form of Change in Control Agreement dated September 10, 2005, between the Company and each of Jay P. Still and David McManus (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).

10.28 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).

10.29 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).

10.30 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).

10.31 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).

10.32 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).

133


10.33 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).

10.34 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).

10.35 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).

10.36	—	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).

10.37	—	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).

10.38	—	Credit Agreement entered into as of October 29, 2007, 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 Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference).

10.39	—	Amendment to Credit Agreement dated as of December 14, 2007, 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 10.8 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference).

10.40	—	Second Amendment to Credit Agreement dated as of February 15, 2008, 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 10.13 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference).

10.41	—	Third Amendment to Credit Agreement dated as of April 15, 2008, 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 10.15 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference).

10.42	—	Limited Waiver Regarding Credit Agreement, entered into as of March 26, 2009, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and the other lenders signatory thereto (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 March 31, 2009).

10.43 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).

10.44 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).

134


10.45 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).

10.46 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).

10.47 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).

10.48 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).

10.49 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).

10.50 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).

10.51 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).

10.52	—	Letter Agreement dated March 18, 2009 between the Company and Southeastern Asset Management, Inc. (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 19, 2009).

10.53 H	—	Form of Performance Unit Award Agreement, dated February 18, 2009, 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 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, 2009, File No. 1-13245).

10.54 H	—	Form of Nonstatutory Stock Option Agreement, dated February 18, 2009, 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 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13245).

10.55 H	—	Form of Restricted Stock Unit Award Agreement, dated February 18, 2009, between the Company and Frank W. Hall and other officers of the Company, with respect to awards made under the Company’s 2006 Long Term Incentive Plan (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13245).

10.56 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).

10.57 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).

135


10.58 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).

10.59 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).

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.

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.

99.1 (a)	—	Report of Netherland, Sewell & Associates, Inc.

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.

136

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 29, 2012

	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 Scott D. Sheffield	Chairman of the Board and Chief Executive Officer (principal executive officer)	February 29, 2012

/s/ Richard P. Dealy Richard P. Dealy	Executive Vice President and Chief Financial Officer (principal financial officer)	February 29, 2012

/s/ Frank W. Hall Frank W. Hall	Vice President and Chief Accounting Officer (principal accounting officer)	February 29, 2012

/s/ Thomas D. Arthur Thomas D. Arthur	Director	February 29, 2012

/s/ Edison C. Buchanan Edison C. Buchanan	Director	February 29, 2012

/s/ Andrew F. Cates Andrew F. Cates	Director	February 29, 2012

/s/ R. Hartwell Gardner R. Hartwell Gardner	Director	February 29, 2012

/s/ Andrew D. Lundquist Andrew D. Lundquist	Director	February 29, 2012

/s/ Charles E. Ramsey, Jr. Charles E. Ramsey, Jr.	Director	February 29, 2012

/s/ Scott J. Reiman Scott J. Reiman	Director	February 29, 2012

/s/ Frank A. Risch Frank A. Risch	Director	February 29, 2012

/s/ J. Kenneth Thompson J. Kenneth Thompson	Director	February 29, 2012

/s/ Jim A. Watson Jim A. Watson	Director	February 29, 2012

137

Exhibit Index


Exhibit Number		Description
2.1	—	Purchase and Sale Agreement by and between Pioneer as Seller and Marubeni Offshore Production (USA) Inc. as Purchaser (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 28, 2006).

2.2*	—	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	—	Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, File No. 1-13245 filed with the SEC on November 17, 2006).

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 4.5 (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 4.5 (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 4.5 (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 4.5 (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 4.5 (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 Natural Resources USA, Inc. and The Bank of New York Trust Company, N.A., as Trustee, with respect to the indenture identified above as Exhibit 4.5 (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 Natural Resources USA, Inc., 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 4.5 (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).

138


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 4.19 (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).

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).

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	—	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).

10.12 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).

10.13 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).

10.14 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).

10.15 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).

10.16 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).

10.17 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).

139


10.18 H (a)	—	Amendment No. 5 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed December 12, 2011.

10.19 H (a)	—	Amendment No. 6 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed January 12, 2012.

10.20	—	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).

10.21	—	Production Payment Purchase and Sale Agreement dated as of January 26, 2005 among the Company, as the Seller, and Royalty Acquisition Company, LLC, as the Buyer (related to Spraberry oil) (incorporated by reference to Exhibit 99.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 1, 2005).

10.22 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).

10.23 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).

10.24 H	—	Amended and restated Severance Agreement dated February 17, 2010, between the Company and David McManus (incorporated by reference to Exhibit 10.30 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009).

10.25 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).

10.26 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).

10.27 H	—	Form of Change in Control Agreement dated September 10, 2005, between the Company and each of Jay P. Still and David McManus (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).

10.28 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).

10.29 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).

10.30 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).

10.31 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).

10.32 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).

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10.33 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).

10.34 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).

10.35 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).

10.36	—	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).

10.37	—	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).

10.38	—	Credit Agreement entered into as of October 29, 2007, 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 Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference).

10.39	—	Amendment to Credit Agreement dated as of December 14, 2007, 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 10.8 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference).

10.40	—	Second Amendment to Credit Agreement dated as of February 15, 2008, 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 10.13 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference).

10.41	—	Third Amendment to Credit Agreement dated as of April 15, 2008, 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 10.15 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference).

10.42	—	Limited Waiver Regarding Credit Agreement, entered into as of March 26, 2009, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and the other lenders signatory thereto (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 March 31, 2009).

10.43 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).

10.44 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).

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10.45 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).

10.46 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).

10.47 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).

10.48 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).

10.49 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).

10.50 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).

10.51 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).

10.52	—	Letter Agreement dated March 18, 2009 between the Company and Southeastern Asset Management, Inc. (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 19, 2009).

10.53 H	—	Form of Performance Unit Award Agreement, dated February 18, 2009, 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 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, 2009, File No. 1-13245).

10.54 H	—	Form of Nonstatutory Stock Option Agreement, dated February 18, 2009, 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 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13245).

10.55 H	—	Form of Restricted Stock Unit Award Agreement, dated February 18, 2009, between the Company and Frank W. Hall and other officers of the Company, with respect to awards made under the Company’s 2006 Long Term Incentive Plan (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13245).

10.56 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).

10.57 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).

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10.58 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).

10.59 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).

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.

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.

99.1 (a)	—	Report of Netherland, Sewell & Associates, Inc.

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.

143