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, 2010

or

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

For the transition period from              to             

Commission File Number: 1-13245

Pioneer Natural Resources Company

(Exact name of registrant as specified in its charter)

Delaware	75-2702753
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
5205 N. O’Connor Blvd., Suite 200, Irving, Texas	75039
(Address of principal executive offices)	(Zip Code)

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

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

Title of each class	Name of each exchange on which registered
Common Stock	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. ¨

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  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	$	6,789,095,296
Number of shares of Common Stock outstanding as of February 23, 2011		116,452,149

DOCUMENTS INCORPORATED BY REFERENCE:

(1) Proxy Statement for the 2011 Annual Meeting of Shareholders to be held during May 2011 — 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
	Operations by Geographic Area		8
	Marketing of Production		9
	Competition, Markets and Regulations		9
Item 1A.	Risk Factors		15
Item 1B.	Unresolved Staff Comments		25
Item 2.	Properties		26
	Reserve Rule Changes		26
	Reserve Estimation Procedures and Audits		26
	Proved Reserves		28
	Description of Properties		30
	Selected Oil and Gas Information		36
Item 3.	Legal Proceedings		42
Item 4.	Removed and Reserved		42
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		43
	Purchases of Equity Securities by the Issuer and Affiliated Purchasers		43
Item 6.	Selected Financial Data		44
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		45
	Financial and Operating Performance		45
	First Quarter 2011 Outlook		46
	2011 Capital Budget		46
	Acquisitions		47
	Divestitures		47
	Results of Operations		47
	Capital Commitments, Capital Resources and Liquidity		56
	Critical Accounting Estimates		60
	New Accounting Pronouncements		63
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		64
	Quantitative Disclosures		64
	Qualitative Disclosures		67
Item 8.	Financial Statements and Supplementary Data		69
	Index to Consolidated Financial Statements		69
	Report of Independent Registered Public Accounting Firm		70
	Consolidated Financial Statements		71
	Notes to Consolidated Financial Statements		78
	Unaudited Supplementary Information		121
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		130
Item 9A.	Controls and Procedures		130
	Management’s Report on Internal Control Over Financial Reporting		130
	Report of Independent Registered Public Accounting Firm		131
Item 9B.	Other Information		132

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TABLE OF CONTENTS

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	132
Item 11.	Executive Compensation	132
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	132
	Securities Authorized for Issuance Under Equity Compensation Plans	132
Item 13.	Certain Relationships and Related Transactions, and Director Independence	133
Item 14.	Principal Accounting Fees and Services	133
PART IV
Item 15.	Exhibits, Financial Statement Schedules	133
Signatures		141
Exhibit Index		142

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Definitions of Certain Terms and Conventions Used Herein

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

• “Bbl” means a standard barrel containing 42 United States gallons.

• “Bcf” means one billion cubic feet.

• “BOE” means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.

• “BOEPD” means BOE per day.

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

• “CBM” means coal bed methane.

• “Dated Brent” means a cargo of North Sea Brent blended crude oil that has been assigned a date when it will be loaded onto a tanker.

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

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

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

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

• “LNG” means liquefied natural gas.

• “MBbl” means one thousand Bbls.

• “MBOE” means one thousand BOEs.

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

• “MMBbl” means one million Bbls.

• “MMBOE” means one million BOEs.

• “MMBtu” means one million Btus.

• “MMcf” means one million cubic feet.

• “MMcfpd” means one million cubic feet per day.

• “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.

• “NGL” means natural gas liquid.

• “NYMEX” means the New York Mercantile Exchange.

• “NYSE” means the New York Stock Exchange.

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

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

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

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

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“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.

• “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.

• “U.S.” means United States.

• “VPP” means volumetric production payment.

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

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

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

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Report”) contains forward-looking statements that involve risks and uncertainties. When used in this document, the words “believes,” “plans,” “expects,” “anticipates,” “intends,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate,” or the negative of such terms and similar expressions as they relate to Pioneer Natural Resources Company and its subsidiaries (“Pioneer” or the “Company”) are intended to identify forward-looking statements. The forward-looking statements are based on the Company’s current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company’s control. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different from the anticipated results described in the forward-looking statements. See “Item 1. Business — Competition, Markets and Regulations,” “Item 1A. Risk Factors,” “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.

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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 current 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; London, England and Capetown, South Africa. At December 31, 2010, the Company had 2,248 employees, 1,399 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 long-lived Spraberry oil field; the liquid-rich Eagle Ford, 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 90 percent of the Company’s proved oil and gas reserves as of December  31, 2010.

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. For several years preceding 2008, the petroleum industry was generally characterized by volatile, but upward trending, oil, NGL and gas commodity prices. During the first half of 2008, North American gas prices increased as a result of reduced inventory levels, a perceived shortage of North American gas supply and anticipation that the United States would become a larger importer of LNG, which was then selling in the world market at a substantial premium to United States gas prices. However, by mid-year 2008, it became apparent that capital investments in gas drilling and discoveries of significant gas reserves in United States shale plays would cause domestic gas supply to exceed existing United States gas demand. Beginning in the second half of 2008 and continuing throughout most of 2009, the United States and other industrialized countries experienced a significant economic slowdown, which

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led to a substantial decline in worldwide energy demand. Declining energy demand due to the economic slowdown, together with the increased supply of United States gas, resulted in sharp declines in oil, NGL and North American gas prices during the second half of 2008 and first half of 2009.

During the second half of 2009 and throughout 2010, economic stimulus initiatives implemented in the United States and worldwide served to stabilize economies and increase industry and consumer confidence. While oil and NGL prices have steadily improved since the beginning of the second quarter of 2009, gas prices have remained volatile throughout 2009 and 2010 as a result of increased gas supply and growing storage levels in the United States, which has offset the growth in demand. The outlook for continuation of the worldwide economic recovery in 2011 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 2011.

Significant factors that will impact 2011 commodity prices include: the ongoing impact of economic stimulus initiatives in the United States and worldwide in response to the worldwide economic decline; political and economic developments in North Africa and the Middle East; demand of 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 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 derivative contracts on 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 Note J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the impact to oil, NGL and gas revenues during 2010, 2009 and 2008 from the Company’s derivative price risk management activities and the Company’s open derivative positions at December 31, 2010.

The Company. The Company’s asset base is anchored by the Spraberry oil field located in West Texas, the Raton gas field located in southern Colorado, the Hugoton gas field located in southwest Kansas and the West Panhandle gas field located in the Texas Panhandle. Complementing these areas, the Company has exploration and development opportunities and/or oil and gas production activities in the Eagle Ford Shale and Edwards Trend areas of South Texas, the Barnett Shale area of North Texas and Alaska, and internationally in South Africa. 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 foreign subsidiaries that explore for, develop and produce proved reserves. Production operations are principally located domestically in Texas, Kansas, Colorado and Alaska, and internationally in South Africa.

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, 2010, the Company’s production of 41.9 MMBOE was consistent with production during 2009. Production, price and cost information with respect to the Company’s properties for 2010, 2009 and 2008 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, 2010, the Company drilled 1,033 gross (952 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 $1.9 billion.

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PIONEER NATURAL RESOURCES COMPANY

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, 2010 include proved undeveloped reserves and proved developed reserves that are behind pipe of 219 MMBbls of oil, 79 MMBbls of NGLs and 991 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.

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 feature producing properties and provide exploration/exploitation opportunities. During 2010, 2009 and 2008, the Company invested $181.6 million, $88.9 million and $137.6 million, respectively, of acquisition capital to purchase proved oil and gas properties, including additional interests in its existing assets, and to acquire new prospects 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. 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 February 2011, the Company sold 100 percent of its share holdings in its Tunisian subsidiaries for cash proceeds of $866 million, before normal closing adjustments. As a result of having committed to a plan to sell the Tunisian subsidiaries during 2010, the Company has classified its Tunisian assets and liabilities as assets and liabilities held for sale and the historic results of operations of its Tunisian assets as discontinued operations in its accompanying consolidated financial statements.

The Company anticipates that it will continue to sell nonstrategic properties or other assets from time to time to increase capital resources available for other activities, to achieve operating and administrative efficiencies and to improve profitability. 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 Tunisia, during 2010, 2009 and 2008.

Operations by Geographic Area

The Company operates in the oil and gas exploration and production industry and has operations in two geographic areas. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note Q of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for geographic operating segment information, including results of operations and segment assets.

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PIONEER NATURAL RESOURCES COMPANY

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 2010, the Company’s significant purchasers of oil, NGLs and gas were Plains Marketing LP (12 percent) and Enterprise Products Partners L.P. (10 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. 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 2010, 2009 and 2008, as well as the Company’s open commodity derivative positions at December 31, 2010.

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 commons stock. Compliance with some of these rules and regulations is costly, and regulations are subject to change or reinterpretation.

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:

• require the acquisition of various permits before drilling commences;

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PIONEER NATURAL RESOURCES COMPANY

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

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

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

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

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the 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 existing laws, rules and regulations to which the Company’s business operations are 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.

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

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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 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, Congress has considered legislation that would repeal an exemption in the SDWA for the underground injection of hydraulic fracturing fluids near drinking water sources. Sponsors of the legislation have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the legislation could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The legislation also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The Subcommittee on Energy and Environment of the U.S. House of Representatives is examining the practice of hydraulic fracturing in the United States and is gathering information on its potential effects on human health and the environment. The EPA also has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health. In addition, various state and local governments have implemented or are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, requirements for disclosure of chemical constituents, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds.

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 holding, but there continue to be litigation and uncertainty regarding permitting of

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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 federal 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.

In January 2010, the Texas Commission on Environmental Quality (the “TCEQ”) concluded an analysis of air emissions of third-party operators in the Barnett Shale area in response to reported concerns about high concentrations of benzene in the air near certain drilling sites and gas processing facilities. The TCEQ’s investigation revealed elevated levels of benzene and other emissions at certain locations. The agency has continued to monitor emissions and pledged to investigate all complaints about oil and gas activities in the Barnett Shale area within 12 hours of receipt. Partially in response to its investigation, the TCEQ recently adopted new air emissions limitations and permitting requirements for oil and gas facilities in the state, which will first become applicable to facilities located in the Barnett Shale area on April 1, 2011. The TCEQ expects to expand the application of the requirements to facilities in other areas of the state in early 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. In addition, environmental groups have advocated for increased regulation in the Barnett Shale area, and at least one state representative has advocated a moratorium on the issuance of drilling permits for new gas wells in the 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.

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 human health and welfare 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

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GHGs under existing provisions of the CAA. The EPA recently adopted two sets of rules, which became effective January 2, 2011, 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, beginning in 2011 of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, for emissions occurring after January 1, 2010, as well as certain oil and gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

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 to below 1990 levels by 2012. 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, 2010. Additionally, the Company is not aware of any environmental issues or claims that will require material capital expenditures during 2011. 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.

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PIONEER NATURAL RESOURCES COMPANY

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 drilling of wells, the posting of bonds in connection with various types of activities and filing reports concerning operations. Most states, and some counties and municipalities, in which the Company operates also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the method and ability to fracture stimulate wells;

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

• the plugging and abandoning of wells; and

• notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas the Company can produce from the Company’s wells or limit the number of wells or the locations at which the Company can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGL and gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from the Company’s wells, negatively affect the economics of production from these wells, or to 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. 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”). The FERC’s regulations for interstate gas transmission in some circumstances may also affect the intrastate transportation of gas. As a result of initiatives like FERC Order No. 636 (“Order 636”), issued in April 1992, the interstate gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all gas supplies. In many instances, the results of Order 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of gas in favor of providing only storage and transportation services.

In August 2005, the United States Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as the Company, 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 the FERC, in contravention of rules prescribed by the FERC. The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the 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 the FERC authority to impose civil penalties for violations of the NGA up to $1.0 million per day per violation. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply 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).

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PIONEER NATURAL RESOURCES COMPANY

In December 2007, the 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 the FERC. Order 704 is intended to increase the transparency of the wholesale gas markets and to assist the FERC in monitoring those markets and in detecting market manipulation.

Although gas prices are currently unregulated, the United States Congress historically has been active in the area of gas regulation. The Company cannot predict whether new legislation to regulate gas or gas prices 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. Sales of condensate and gas liquids are not currently regulated and are made at market prices.

Gas gathering. 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.

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 projects as scheduled. In that case, the market price of the Company’s common stock could decline.

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

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

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

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

• weather conditions;

• overall domestic and global political and economic conditions;

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

• the effect of LNG deliveries to the United States;

• technological advances affecting energy consumption and energy supply;

• domestic and foreign governmental regulations and taxation;

• the effect of energy conservation efforts;

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

• the price and availability of alternative fuels.

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PIONEER NATURAL RESOURCES COMPANY

In the past, commodity prices have been extremely volatile, and the Company expects this volatility to continue. For example, oil prices reached record levels in July 2008 of $145.29 per Bbl before declining to $33.87 per Bbl in December 2008, while gas prices reached $13.58 per Mcf before declining to $5.29 per Mcf over the same period. During 2009, oil prices increased from a low of $33.98 per Bbl in February to a high of $81.37 per Bbl in October, while gas prices declined from $6.07 per Mcf in January to $2.51 per Mcf in September. 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 mark-to-market 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:

• production is less than the contracted derivative volumes,

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

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

On the other hand, failure to protect against declines in commodity prices exposes the Company to reduced revenue and liquidity when prices decline, as occurred in late 2008 for all commodities and during 2009 and 2010 for gas.

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.

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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 became costlier, as a result of a variety of factors, including:

• unexpected drilling conditions;

• unexpected pressure or irregularities in formations;

• equipment failures or accidents;

• fracture stimulation accidents or failures;

• adverse weather conditions;

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

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

The Company’s future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse effect on the Company’s future results of operations and financial condition. While all drilling, whether developmental, extension or exploratory, involves these risks, exploratory and extension drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Company expects that it will continue to experience exploration and abandonment expense in 2011.

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’s having to make substantial downward adjustments to the Company’s 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 will be required to reduce the carrying value of the proved properties to their estimated fair value. For example, during 2009 and 2008, the Company recognized impairment charges of $21.1 million and $89.8 million, respectively, due to the impairment of the Company’s net assets in the Uinta/Piceance area, 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, 2010, the Company carried unproved property costs of $191.1 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 been an important element of 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:

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PIONEER NATURAL RESOURCES COMPANY

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

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

• the validity of assumptions about costs, including synergies;

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

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

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

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

The Company 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, 2010, the Company carried goodwill of $298.2 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) future reserve adjustments both positive and negative, (b) results of drilling activities, (c) changes in management’s outlook on commodity prices and costs and expenses, (d) changes in the Company’s market capitalization, (e) changes in the Company’s weighted average cost of capital and (f) changes in income taxes. If the fair value of the reporting unit’s net assets is not sufficient to fully support the goodwill balance in the future, the Company will reduce the carrying value 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, 2010, the Company owned interests in four gas processing plants and 11 treating facilities. The Company operates two of the gas processing plants and all 11 of the treating facilities. There are significant risks associated with the operation of gas processing plants. Gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of a gas processing plant or facility could result in an explosion or the discharge of toxic gases, which could result in significant damage claims in addition to interrupting a revenue source.

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PIONEER NATURAL RESOURCES COMPANY

The Company’s operations involve many operational risks, some of which could result in 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 are subject to all the risks normally incident to the oil and gas development and production business, including:

• blowouts, cratering, explosions and fires;

• adverse weather effects;

• environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

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

• facility or equipment malfunctions, failures or accidents;

• title problems;

• pipe or cement failures or casing collapses;

• compliance with environmental and other governmental requirements;

• lost or damaged oilfield workover and service tools;

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

• natural disasters.

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

The Company is not fully insured against certain of the risks described above, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance. Additionally, the Company relies to a large extent on facilities owned and operated by third-parties, and damage to or destruction of those third-party facilities could affect the ability of the Company to produce, transport and sell its hydrocarbons. For example, in 2008, damage caused by Hurricanes Gustav and Ike to a third-party facility that fractionates NGLs from a portion of the Company’s production resulted in a portion of the Company’s production being shut in or curtailed from early September to mid-November 2008 while repairs and maintenance to the facility were being completed.

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, transmission, 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, transmit 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 transmission, storage or processing facilities to the Company, especially in areas of planned expansion where such facilities do not currently exist.

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PIONEER NATURAL RESOURCES COMPANY

The nature of the Company’s assets exposes it to significant costs and liabilities with respect to environmental and operational safety matters.

The oil and gas business 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, 2010 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.

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

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

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

• marketing oil, NGL and gas production; and

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

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

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

The Company’s business is regulated by a variety of federal, state, 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.

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PIONEER NATURAL RESOURCES COMPANY

The Company’s international operations may be adversely affected by economic, political and other factors.

At December 31, 2010, three percent of the Company’s proved reserves were located outside the United States. The success and profitability of international operations may be adversely affected by risks associated with international activities, including:

• economic and labor conditions;

• war, terrorist acts and civil disturbances;

• political instability;

• loss of revenue, property and equipment as a result of actions taken by foreign countries where the Company has operations, such as expropriation or nationalization of assets and renegotiation, modification or nullification of existing contracts;

• changes in taxation policies (including host-country import-export, excise and income taxes and United States taxes on foreign subsidiaries);

• laws and policies of the United States and foreign jurisdictions affecting foreign investment, trade and business conduct; and

• changes in the value of the U.S. dollar versus the local currencies in which oil and gas producing activities may be denominated.

In some cases, the market for the Company’s production in foreign countries is limited to some extent. For example, all of the Company’s gas and condensate production from the South Coast Gas project in South Africa is currently committed by contract to a single, government-affiliated gas-to-liquids facility. If this facility ceased to purchase the gas because of an unforeseen event, it might be difficult to find an alternative market for the production, and if such a market were secured, the price received by the Company might be less than that provided under its current gas sales contract. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding other risks associated with the Company’s international 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 there from. The estimates of proved reserves and related future net cash flows set forth in this Report are based on various assumptions, which may ultimately prove to be inaccurate.

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

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

• the quality and quantity of available data;

• the interpretation of that data;

• the assumed effects of regulations by governmental agencies;

• assumptions concerning future commodity prices; and

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

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

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

• the production costs incurred to recover the reserves;

• the amount and timing of future development expenditures; and

• future commodity prices.

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PIONEER NATURAL RESOURCES COMPANY

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

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

• the amount and timing of actual production;

• levels of future capital spending;

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

• changes in governmental regulations or taxation.

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.

The Company may be unable to complete its plans to repurchase its common stock.

The Board of Directors (the “Board”) approves share repurchase programs and sets limits on the price per share at which the Company’s common stock can be repurchased. From time to time, the Company may not be permitted to repurchase its stock during certain periods because of scheduled and unscheduled trading blackouts. Additionally, business conditions and availability of capital may dictate that repurchases be suspended or canceled. As a result, there can be no assurance that additional repurchase programs will be commenced and, if so, that they will be completed.

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 Energy Partners L.P., 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 the partnership. 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.

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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 2009 and 2010, the economic outlook for 2011 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.

The Company may not be able to obtain funding, obtain funding on acceptable terms or obtain funding under its current credit facility in the event of a deterioration of the credit and capital markets, which could hinder or prevent the Company from meeting its future capital needs.

During 2009 and 2010, access to the debt and equity capital markets improved. However, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets was higher than historical levels as many lenders and institutional investors increased interest rates, enacted tighter lending standards and limited the amount of funding available to borrowers.

If these events were to recur, the Company could be unable to obtain adequate funding under its current credit facility because (i) the Company’s lending counterparties may be unwilling or unable to meet their funding obligations or (ii) the amount the Company may borrow under its current credit facility could be reduced as a result of lower oil, NGL or gas prices, declines in reserves, stricter lending requirements or regulations, or for other reasons. For example, the Company’s credit facility requires that the Company maintain a specified ratio of the net present value of the Company’s oil and gas properties to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. Due to these factors, the Company cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, the Company may be unable to implement its business plans or otherwise take advantage of business opportunities or respond to competitive pressures any of which could have a material adverse effect on the Company’s production, revenues and results of operations.

Declining general economic, business or industry conditions could have a material adverse affect 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 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 during the second half of 2008 and most of 2009. While the worldwide economic outlook has improved, concerns about global economic growth could have a significant adverse effect on global financial markets and commodity prices. If the economic climate in the United States or abroad were to deteriorate, demand for petroleum products could diminish, which could depress the prices at which the Company could sell its oil, NGLs and gas and ultimately decrease the Company’s net revenue and profitability.

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

The Fiscal Year 2012 Budget proposed by the President recommends elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress which would implement many of these proposals. These 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

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PIONEER NATURAL RESOURCES COMPANY

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 U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect the value of an investment in the Company’s common stock.

The recent 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 human health and welfare 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 federal 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 recently adopted two sets of rules, which became effective January 2, 2011, 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, beginning in 2011 of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, for emissions occurring after January 1, 2010, as well as certain oil and gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

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. 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 new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Act, the CFTC has proposed 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 hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. 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 derivative 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

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PIONEER NATURAL RESOURCES COMPANY

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 new 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 diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, various state and local governments have implemented or are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, requirements for disclosure of chemical constituents, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for the Company to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, the Company’s fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and gas that the Company is ultimately able to produce from its reserves.

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. The Company has also adopted a shareholder rights plan. 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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PIONEER NATURAL RESOURCES COMPANY

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 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, 2010, 2009 and 2008, 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 100 percent of the Company’s share holdings in its Tunisian subsidiaries during February 2011, which owned 100 percent of 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 (“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. Asset Teams’ reserve estimates are reviewed by the asset team reservoir engineers before being submitted to the Director of the WWR and are summarized in reserve reconciliations that quantify reserve changes represented 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

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PIONEER NATURAL RESOURCES COMPANY

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 reserve audits performed by NSAI in the aggregate represented 90 percent, 93 percent and 87 percent of the Company’s 2010, 2009 and 2008 proved reserves, respectively; and, 79 percent, 86 percent and 80 percent of the Company’s 2010, 2009 and 2008 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 (“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 accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the SPE.

• 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.

To further clarify, 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 reserve differences. Such data was incorporated, as appropriate, by both parties into the 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 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 generally accepted petroleum engineering standards promulgated by the SPE.

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PIONEER NATURAL RESOURCES COMPANY

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 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 board of directors of the SPE. The WWR Director’s qualifications include 33 years of experience as a petroleum engineer, with 26 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-002699. 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 31 years of practical experience in petroleum engineering, including 30 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. The Company uses reliable technologies to establish additions to reserve estimates, including seismic data and interpretation, wireline formation tests, geophysical logs and core data. Reserve additions associated with reliable technologies were less than two percent of the Company’s total proved reserves during the year ended December 31, 2010.

Proved Reserves

The Company’s proved reserves totaled 1,011 MMBOE, 898.6 MMBOE and 959.6 MMBOE at December 31, 2010, 2009 and 2008, respectively, representing $5.4 billion, $3.3 billion and $3.2 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. The following table shows the changes in the Company’s proved reserve volumes by geographic area during the year ended December 31, 2010 (in MBOE):

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PIONEER NATURAL RESOURCES COMPANY

	Production			Extensions and Discoveries		Improved Recovery		Purchases  of Minerals-in- Place		Sales of Minerals-in- Place			Revisions of Previous Estimates
United States		(40,777	)		73,005		9,716		3,060		(5,108	)		63,540
South Africa		(2,035	)		—		—		—		—			406
Tunisia		(1,954	)		10,707		—		—		(560	)		2,145
Total		(44,766	)		83,712		9,716		3,060		(5,668	)		66,091

Production. Production volumes include 2,882 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 area and Tunisia.

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 and Eagle Ford Shale play.

Sales of minerals-in-place. Sales of minerals-in-place are primarily related to the sale of 45 percent of the Company’s interest in certain proved properties in the Eagle Ford Shale. The sale was done in connection with entering into a joint venture with an unaffiliated third party to develop the Company’s Eagle Ford Shale acreage position. See Note M 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 59 MMBOE of positive price revisions and 7 MMBOE of positive technical revisions. The Company’s proved reserves at December 31, 2010 were determined using the average of the first-day-of-the-month commodity prices during the 12-month period ending December 31, 2010 of $79.28 per barrel of oil and $4.37 per Mcf of gas, compared to $61.14 per barrel of oil and $3.87 per Mcf of gas as of December 31, 2009.

Tabular proved reserves disclosures. On a BOE basis, 57 percent of the Company’s total proved reserves at December 31, 2010 were proved developed reserves. Based on reserve information as of December 31, 2010, and using the Company’s production information for the year then ended, the reserve-to-production ratio associated with the Company’s proved reserves was in excess of 20 years on a BOE basis. The following table provides information regarding the Company’s proved reserves and average daily sales volumes by geographic area as of and for the year ended December 31, 2010:

	Summary of Oil and Gas Reserves as of December 31, 2010 Based on Average Fiscal Year Prices
	Oil (MBbls)		NGLs (MBbls)		Gas (MMcf) (a)			MBOE		Standardized Measure
	(in thousands)
Developed:
United States		160,421		108,785		1,736,765			558,667	$	3,676,662
South Africa		274		—		15,671			2,886		47,579
Tunisia		12,121		—		23,175			15,984		341,638
		172,816		108,785		1,775,611			577,537		4,065,879
Undeveloped:
United States		200,295		75,433		898,937			425,550		1,169,951
Tunisia		7,698		—		(26	)		7,694		176,179
		207,993		75,433		898,911			433,244		1,346,130
Total Proved		380,809		184,218		2,674,522			1,010,781	$	5,412,009

(a) The gas reserves contain 303,748 MMcf of gas that will be produced and utilized as field fuel.

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PIONEER NATURAL RESOURCES COMPANY

Proved undeveloped reserves. As of December 31, 2010, the Company had 4,727 proved undeveloped well locations (all of which are expected to be developed during the five year period ending December 31, 2015), as compared to 4,582 and 4,977 at December 31, 2009 and 2008, respectively. During 2010, the Company’s development drilling costs incurred increased by 168 percent, as compared to 2009, and the Company converted 19,158 MBOE of proved undeveloped reserves to proved developed reserves. The increase in development drilling costs during 2010 reflects the Company’s expansion of oil- and liquids-focused drilling expenditures during 2010. The Company significantly reduced its development drilling expenditures during 2009 in support of cost reduction initiatives implemented during the second half of 2008 and 2009 in response to significant declines in energy demand and commodity prices (see “Item 1. Business” for a discussion of the worldwide economic slowdown during 2008 and the associated decline in energy demand). The Company’s proved undeveloped well locations that have remained undeveloped for five years or more decreased by 12 percent to 1,467 as of December 31, 2010, as compared to 1,675 well locations at December 31, 2009. Of these undeveloped well locations, 85 percent are in the Spraberry field in the Permian Basin of West Texas. The significant concentration of well locations that have remained undeveloped for five years or more in the Spraberry field is reflective of the Company’s large inventory of drilling locations in the field and the aforementioned curtailment of development drilling activity during 2008 and 2009 in support of cost reduction initiatives. 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 2011 and future years.

Based on current price outlooks, the Company expects that future operating cash flows, together with a portion of the 2011 net proceeds from the sale of its Tunisian subsidiaries, will provide adequate funding for future development costs. The following table represents the estimated timing and cash flows of developing the Company’s proved undeveloped reserves as of December 31, 2010 (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
2011		3,512	$	221,273	$	28,679	$	683,742	$	(491,148	)
2012		10,877		665,138		95,451		1,167,125		(597,438	)
2013		18,558		1,040,615		160,818		1,272,636		(392,839	)
2014		27,062		1,426,423		243,151		1,394,024		(210,752	)
2015		30,467		1,597,836		288,419		1,164,644		144,773
Thereafter		342,769		16,957,215		5,298,483		339,099		11,319,633
		433,245	$	21,908,500	$	6,115,001	$	6,021,270	$	9,772,229

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

Description of Properties

United States

Approximately 86 percent of the Company’s proved reserves at December 31, 2010 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, and the Spraberry and Raton fields have a large portfolio of low-risk drilling opportunities. The cash flows generated from these fields provide funding for the Company’s other development and exploration activities both domestically and internationally.

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PIONEER NATURAL RESOURCES COMPANY

The following tables summarize the Company’s United States development and exploration/extension drilling activities during 2010:

			Development Drilling
			Beginning Wells In Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Ending Wells In Progress
Permian Basin				10		431		418		2		21
Mid-Continent				—		11		10		1		—
Raton Basin				—		1		1		—		—
South Texas				—		1		—		—		1
Alaska				1		4		4		—		1
Total United States				11		448		433		3		23
	Exploration/Extension Drilling
	Beginning Wells In Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Sold Wells		Ending Wells In Progress
Permian Basin		—		6		3		—		—		3
South Texas		1		3		2				—		2
Eagle Ford Shale		2		39		19		—		—		22
Barnett Shale		2		17		8		—		—		11
Alaska		2		—		1		1		—		—
Other		1		3		1		2		1		—
Total United States		8		68		34		3		1		38

The following table summarizes the Company’s United States average daily oil, NGL, gas and total production by asset area during 2010:

	Oil (Bbls)		NGLs (Bbls)		Gas (Mcf)		Total (BOE)
Permian Basin		17,395		10,767		43,356		35,389
Mid-Continent		3,939		7,738		54,621		20,780
Raton Basin		—		—		170,716		28,453
Barnett Shale		94		971		9,060		2,575
South Texas		53		—		50,448		8,461
Eagle Ford Shale		381		250		5,937		1,620
Alaska		6,336		—		—		6,336
Other		13		10		1,118		209
Total United States		28,211		19,736		335,256		103,823

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PIONEER NATURAL RESOURCES COMPANY

The following table summarizes the Company’s United States costs incurred by geographic area during 2010:

	Property Acquisition Costs					Exploration Costs		Development Costs			Asset Retirement Obligations			Total
	Proved			Unproved
	(in thousands)
Permian Basin	$	4,393		$	5,522	$	24,104	$	542,977		$	24,447		$	601,443
Mid-Continent		5			1,837		860		10,811			(1,421	)		12,092
Raton Basin		(363	)		777		6,273		9,984			(14,532	)		2,139
South Texas		134			2,622		35,090		10,741			(1,975	)		46,612
Eagle Ford Shale		2,481			112,353		97,485		1,307			1,316			214,942
Barnett Shale		(89	)		51,745		52,029		2,026			(166	)		105,545
Alaska		—			—		16,144		96,463	(a)		8,985			121,592
Other		—			150		7,380		(351	)		1,885			9,064
Total United States	$	6,561		$	175,006	$	239,365	$	673,958		$	18,539		$	1,113,429

(a) Includes $15.2 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 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 has also begun evaluating the Strawn formation below the Wolfcamp in certain areas of the field that have better Strawn porosity with successful results and, during 2011, plans to drill 10 to 15 wells to test the Atoka formation, which lies directly below the Strawn formation.

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 2008, the Company initiated a program to test 20-acre infill drilling performance. The Company drilled and completed eleven 20-acre wells in 2008, nine 20-acre wells in 2009, and eighteen 20-acre wells in 2010 with encouraging results to date.

During 2010, the Company also funded an approximately 7,000 acre Spraberry field waterflood project in the upper Spraberry interval of an existing Spraberry unit. Drilling, conversion and facility work was completed during the first half of 2010 and water injection commenced during the second half of 2010. Early results from the project are encouraging, as the production decline from 110 producing wells in the surveillance area has shown signs of flattening.

During 2010, the Company also commenced drilling on two horizontal wells, both of which were in progress at December 31, 2010, to test horizontal drilling in the Wolfcamp. Both wells will be 4,000-foot laterals with 15-stage fracture stimulation completions. The first well is being drilled in the middle Wolfcamp carbonate section. The second well is targeting the lower Wolfcamp shale section. The horizontal test wells are expected to be completed during the first quarter of 2011.

The 20-acre well spacing, waterflood initiatives and horizontal drilling described above are being implemented to increase the Spraberry field recovery percentage in those areas of the field that are expected to be conducive for these undertakings. However, the ultimate incremental recovery rates associated with these initiatives cannot be precisely predicted at this time.

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PIONEER NATURAL RESOURCES COMPANY

During 2010, the Company drilled 423 wells in the Spraberry field and its total acreage position now approximates 822,000 gross acres (713,000 net acres). Pioneer has expanded its drilling program in 2011 to 30 rigs and plans to increase its rig count to 35 rigs in mid-2011 and to 40 or more rigs in 2012.

To support the Company’s Spraberry drilling efforts and to control costs, the Company has expanded its integrated services by acquiring 12 Company-operated drilling rigs and three fracture stimulation fleets that have recently commenced operations in the field. Two additional fracture stimulation fleets are being built, with one scheduled for delivery in the second quarter of 2011 and the second in the fourth quarter of 2011. Additionally, the Company has sand supply in place to satisfy its forecasted fracture stimulation requirements through 2015 and tubular and pumping unit requirements have been contracted through 2012. The Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks and fishing tools, to support its growing operations.

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 285,000 gross acres (247,000 net acres), covering approximately 400 square miles. The Company has working interests in approximately 1,225 wells in the Hugoton field, approximately 1,000 of which it operates, and partial working interest in approximately 225 wells.

The Company operates substantially all of the gathering and processing facilities, including the Satanta plant, which processes the production from the Hugoton field. During 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 is expected to increase the Satanta plant’s processing volumes and 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 685 wells on more than 250,000 gross acres (240,000 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 256,000 gross acres (219,000 net acres) in the center of the Raton Basin and produces CBM gas from the coal seams in the Vermejo and Raton formations. 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.

In the Raton field, the Company has typically sold its gas at a Mid-Continent index price, which has generally provided for higher realized gas prices as compared to the Rockies-based indexes. During December 2009, the Company entered into a ten-year firm transportation contract that commences upon completion of a new 675-mile pipeline spanning from Opal, Wyoming to Malin, Oregon. Upon completion of the pipeline’s construction, which is currently anticipated in the second quarter of 2011, the Company will have 75,000 Mcf per day of firm transportation under this agreement.

During 2010, the Company entered into an additional firm transportation contract commitment that provides gas transportation from the Raton field to Opal, Wyoming in order to support the Company’s future Opal, Wyoming to Malin, Oregon commitments as well as other forecasted sales upstream of Opal, Wyoming. This firm transportation contract provides for up to 100,000 Mcf per day of gas transportation during the contract’s primary term, which began in December 2010 and ends in March 2021.

The Company also has firm transportation commitments for 215,000 Mcf per day of gas (which decline over an 11 year term) from the Raton field eastward to Mid-Continent sales points. The Company’s aggregate firm

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PIONEER NATURAL RESOURCES COMPANY

transportation commitments from the Raton field northwest towards Malin, Oregon, and east towards Mid-Continent sales points, exceed the Company’s current gas sales volumes controlled from the Raton field. While these excess firm transportation commitments provide capacity for future production growth from planned drilling, it also represents excess transportation costs to be managed until controlled sales volumes and firm transportation commitments reach equilibrium. The Company is exploring opportunities to defer near-term commitments until later periods or to purchase third party gas volumes to meet current transportation commitments. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual obligations” and Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information about the Company’s transportation commitments.

South Texas and Eagle Ford Shale

The Company’s drilling activities in the South Texas area during 2010 continue to be primarily focused on delineation and development of Pioneer’s substantial acreage position in the Eagle Ford Shale play. The Company is currently running seven drilling rigs in the Eagle Ford Shale play and plans to increase the Eagle Ford Shale rig count to 12 rigs in mid-2011, 14 rigs during 2012 and 16 rigs in 2013.

To improve the execution of the Company’s Eagle Ford Shale drilling program and reduce drilling costs, the Company has purchased two fracture stimulation fleets. One is expected to be in operation during the second quarter of 2011 and the other during the fourth quarter of 2011. The Company has also entered into a two-year contract for a dedicated third-party fracture stimulation fleet, which is expected to begin operations during the latter part of the first quarter of 2011. The Company is also pursuing opportunities to contract for other third-party fracture stimulation equipment.

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 provide 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. 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 mid-2013. The Company and its joint venture partners have drilled 41 Eagle Ford Shale wells, of which 21 wells have been completed and are producing, three wells are completed and awaiting connections to sales lines and 17 wells remain in progress awaiting limited third-party fracture stimulation fleet availability. 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 certain of the gathering, treating and transportation infrastructure in the Eagle Ford Shale area. As EFS Midstream constructs these midstream assets, the Company will be responsible for funding 50.1 percent of EFS Midstream’s cash requirements. Construction of the midstream assets is underway, with the majority of the construction expected to be completed by 2013. Three of the 14 planned facilities (“CGPs”) were completed as of December 31, 2010. EFS Midstream plans to build five additional CGPs during 2011, with the first two expected to be completed during March. As construction of CGPs is completed, EFS Midstream will provide gathering, treating and transportation services for the Company during a 20-year contractual period.

During the fourth quarter of 2010, the Company entered into contractual agreements with third parties to gather, transport, process and fractionate certain portions of the future oil, gas and NGLs produced and recovered from the Company’s Eagle Ford Shale properties. 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 after the counterparty builds the pipeline.

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PIONEER NATURAL RESOURCES COMPANY

The Company entered into two five-year gas transportation agreements, under which it is committed to provide approximately 20,600 Mcf per day of gas throughput from Eagle Ford Shale wells beginning in mid-2011. Transportation commitments under these agreements increase to approximately 88,600 Mcf per day in 2015 before terminating in mid-2016. All but 28,300 Mcf per day of the firm transportation commitments under these agreements is subject to a counterparty’s obligation to build infrastructure facilities.

The Company also entered into a ten-year contractual agreement with a third party for the transportation and processing of Eagle Ford Shale gas production and the fractionation of recovered NGLs. The firm transportation commitments under this agreement are for approximately 18,000 Mcf per day in 2011, increasing to approximately 170,000 Mcf per day in 2020; processing commitments under the agreement are for approximately 15,000 Mcf per day in 2011, increasing to approximately 139,000 Mcf per day in 2020; and, fractionation commitments under the agreement are for approximately 1,500 Bbls per day of NGLs in 2011, increasing to approximately 15,000 Bbls per day in 2020.

Barnett Shale

During 2010, 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 80,000 gross acres in the liquid-rich area of the field, representing over 600 potential drilling locations. During the fourth quarter of 2010, the Company commenced a two-rig drilling program in the play.

The Company’s total lease holdings in the Barnett Shale play now approximate 124,000 gross acres (97,000 net acres).

Alaska

The Company owns a 70 percent working interest and is the operator of the Oooguruk development project. The Company has drilled ten production wells and six injection wells of the estimated 17 production and 16 injection wells planned to fully develop this project. In addition, the Company drilled a horizontal exploration well in the Torok formation during 2010. Based on the performance to date, the Company plans to drill and fracture stimulate two additional Torok wells in 2011 to further evaluate the productivity of the formation and possibility of a future development project.

International

During 2010, the Company’s international operations were located offshore South Africa and in Tunisia. 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 Tunisia subsidiaries during February 2011.

The following table summarizes the Company’s Tunisia exploration/extension and development drilling activities during 2010:

	Beginning Wells In Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Ending Wells In Progress
Exploration/extension drilling		5		3		5		—		3
Development drilling		—		4		3		—		1
Total		5		7		8		—		4

The following table summarizes the Company’s international average daily oil, NGL, gas and total production during 2010:

	Oil (Bbls)		NGLs (Bbls)		Gas (Mcf)		Total (BOE)
South Africa		616		—		29,760		5,576
Tunisia		4,880		—		2,849		5,355
Total International		5,496		—		32,609		10,931

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PIONEER NATURAL RESOURCES COMPANY

The following table summarizes the Company’s international costs incurred by geographic area during 2010:

	Property Acquisition Costs				Exploration Costs		Development Costs			Asset Retirement Obligations		Total
	Proved		Unproved
	(in thousands)
South Africa	$	—	$	—	$	512	$	(53	)	$	1,835	$	2,294
Tunisia		—		—		30,630		39,053			820		70,503
Other		—		—		329		—			—		329
Total International	$	—	$	—	$	31,471	$	39,000		$	2,655	$	73,126

South Africa

The Company has production and exploration agreements covering over 3.6 million acres offshore the southern coast of South Africa in water depths generally less than 650 feet. The Company’s initial discovery, Sable oil field, began producing in August 2003 and over its five-year life recovered approximately 23.6 million gross barrels of oil. During the life of the Sable oil field, the majority of the gas produced in conjunction with the oil production was injected back into the reservoir. The Company had a 40 percent working interest in the oil production from the Sable field.

In 2005, the Company sanctioned the non-operated South Coast Gas development project, which included a subsea tie-back of gas from the Sable field and five additional gas accumulations to an existing production facility on the F-A platform for transportation via existing pipelines to a gas-to-liquids plant. Pioneer has a 45 percent working interest in the project. As part of sanctioning of the South Coast Gas project, the Company signed a six-year contract for the sale of its gas and condensate production from the project. The contract contains an obligation for the purchaser to take or pay for a total of 91.4 Bcf and associated condensate if the anticipated deliverability estimates are achieved. The price for both gas and condensate is indexed to Dated Brent oil prices. First production from the South Coast Gas project was achieved in the third quarter of 2007.

A significant portion of the gas reserves associated with the South Coast Gas project is in the Sable field. In the third quarter of 2008, Sable oil production was shut in and operations to convert Sable’s gas injection well to a producing well commenced. Gas sales from the Sable gas well were initiated in mid-October 2008 and the other South Coast Gas wells resumed production in late-October. The Sable gas well is the most productive well in the South Coast Gas project.

Tunisia

The Company held interests in four separate onshore permits located in the southern portion of Tunisia. During February 2011, the Company completed the sale of 100 percent of its share holdings in its Tunisian subsidiaries for cash proceeds of $866 million, before normal closing adjustments. The Company’s Tunisian permits covered a gross area of approximately 12,740 square kilometers containing three production concessions targeting the Acacus formation with additional future upside exploration potential from this and other formations. 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 divestiture of the Company’s Tunisian subsidiaries.

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, 2010, 2009 and 2008. 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. Oil and gas are commodities. The price that the Company receives for the oil and gas produced is largely a function of market supply and demand. Demand for oil and gas in the United States has increased dramatically during this decade. However, the economic slowdown reduced this demand during the second half of 2008 and through 2009. 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.

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PIONEER NATURAL RESOURCES COMPANY

The following tables set forth production, price and cost data with respect to the Company’s properties for 2010, 2009 and 2008. These amounts represent the Company’s historical results from continuing 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 and production associated with completed divestitures (reflected as discontinued operations) being included in the reserve volume tables.

PRODUCTION, PRICE AND COST DATA

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

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

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PIONEER NATURAL RESOURCES COMPANY

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.

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PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA - (Continued)

	Year Ended December 31, 2008
	United States							South Africa		Tunisia		Total
	Spraberry Field			Raton Field		Total
Production information:
Annual sales volumes:
Oil (MBbls)		5,713			—		7,720		880		2,261		10,861
NGLs (MBbls)		2,981			—		6,971		—		—		6,971
Gas (MMcf)		14,069			72,386		134,248		3,745		866		138,859
Total (MBOE)		11,038			12,064		37,065		1,504		2,406		40,975
Average daily sales volumes:
Oil (Bbls)		15,612			—		21,091		2,405		6,178		29,674
NGLs (Bbls)		8,141			—		19,048		—		—		19,048
Gas (Mcf)		38,440			197,775		366,796		10,232		2,367		379,395
Total (BOE)		30,161			32,963		101,271		4,110		6,573		111,954
Average prices, including hedge results and amortization of deferred VPP revenue (a):
Oil (per Bbl)	$	117.10		$	—	$	65.74	$	110.21	$	90.64	$	74.53
NGL (per Bbl)	$	46.49		$	—	$	51.31	$	—	$	—	$	51.31
Gas (per Mcf)	$	6.33		$	7.16	$	7.66	$	5.83	$	12.04	$	7.64
Revenue (per BOE)	$	81.24		$	42.95	$	51.08	$	79.00	$	89.53	$	54.36
Average prices, excluding hedge results and amortization of deferred VPP revenue (a):
Oil (per Bbl)	$	98.88		$	—	$	95.82	$	110.21	$	90.64	$	95.91
NGL (per Bbl)	$	46.49		$	—	$	51.56	$	—	$	—	$	51.56
Gas (per Mcf)	$	6.33		$	7.16	$	7.39	$	5.83	$	12.04	$	7.37
Revenue (per BOE)	$	71.81		$	42.95	$	56.41	$	79.00	$	89.53	$	59.18
Average costs (per BOE):
Production costs:
Lease operating	$	12.57		$	5.16	$	7.66	$	25.98	$	6.26	$	8.26
Third-party transportation charges		—			2.56		1.06		—		1.93		1.07
Net natural gas plant/gathering		(2.73	)		2.90		0.16		—		—		0.15
Workover		2.61			0.09		0.93		—		—		0.84
Total	$	12.45		$	10.71	$	9.81	$	25.98	$	8.19	$	10.32
Production and ad valorem taxes:
Ad valorem	$	2.31		$	0.81	$	1.58	$	—	$	—	$	1.43
Production		5.05			1.11		2.86		—		—		2.58
Total	$	7.36		$	1.92	$	4.44	$	—	$	—	$	4.01
Depletion expense	$	7.61		$	12.90	$	11.30	$	18.37	$	5.96	$	11.25

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

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PIONEER NATURAL RESOURCES COMPANY

Productive wells. The following table sets forth the number of productive oil and gas wells attributable to the Company’s properties as of December 31, 2010, 2009 and 2008:

PRODUCTIVE WELLS (a)

	Gross Productive Wells						Net Productive Wells
	Oil		Gas		Total		Oil		Gas		Total
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
As of December 31, 2008:
United States		5,374		4,988		10,362		4,561		4,685		9,246
South Africa		—		6		6		—		3		3
Tunisia		28		—		28		8		—		8
Total		5,402		4,994		10,396		4,569		4,688		9,257

(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, 2010, the Company owned interests in one gross well 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, 2010:

LEASEHOLD ACREAGE

	Developed Acreage				Undeveloped Acreage				Royalty Acreage
	Gross Acres		Net Acres		Gross Acres		Net Acres
United States:
Onshore		1,501,102		1,287,560		796,549		622,091		297,599
Offshore		—		—		—		—		5,000
		1,501,102		1,287,560		796,549		622,091		302,599
South Africa		119,579		53,281		3,508,421		1,578,789		—
Tunisia		297,424		83,009		2,645,012		1,930,582		—
Total		1,918,105		1,423,850		6,949,982		4,131,462		302,599

40

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, 2010:

	Acres Expiring (a)
	Gross		Net
2011 (b)		1,967,292		1,498,990
2012		1,000,166		673,954
2013		230,115		187,613
2014		77,121		65,997
2015		38,697		22,390
Thereafter		3,636,591		1,682,518
Total		6,949,982		4,131,462

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

(b) All acres subject to expiration during 2011 are in North America. The Company may extend the leases prior to their expiration based upon 2011 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 2010, 2009 and 2008 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,
	2010			2009			2008			2010			2009			2008
United States:
Productive wells:
Development		433			60			526			378			58			504
Exploratory		34			13			56			22			7			46
Dry holes:
Development		3			—			7			3			—			7
Exploratory		3			2			17			1			2			9
		473			75			606			404			67			566
Tunisia:
Productive wells:
Development		3			1			—			2			—			—
Exploratory		5			—			6			2			—			3
Dry holes:
Development		—			—			—			—			—			—
Exploratory		—			2			2			—			1			1
		8			3			8			4			1			4
Total		481			78			614			408			68			570
Success ratio (a)		99	%		95	%		96	%		99	%		96	%		97	%

(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.

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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, 2010:

	Gross Wells		Net Wells
United States:
Development		23		22
Exploratory		38		25
Total		61		47
Tunisia:
Development		1		1
Exploratory		3		2
		4		3
Total		65		50

ITEM 3. LEGAL PROCEEDINGS

The Company is party to the legal proceedings that are 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. REMOVED AND RESERVED

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PIONEER NATURAL RESOURCES COMPANY

PART II

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

The Company’s common stock is listed and traded on the NYSE under the symbol “PXD.” The Board declared dividends to the holders of the Company’s common stock totaling $.08 per share during the first and third quarters of each of the years ended December 31, 2010 and 2009, respectively.

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, 2010 and 2009:

	High		Low		Dividends Declared Per Share
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
Year ended December 31, 2009
Fourth quarter	$	50.00	$	33.49	$	—
Third quarter	$	36.74	$	21.78	$	0.04
Second quarter	$	30.56	$	15.67	$	—
First quarter	$	20.44	$	11.88	$	0.04

On February 23, 2011, the last reported sales price of the Company’s common stock, as reported in the NYSE composite transactions, was $100.67 per share.

As of February 23, 2011, the Company’s common stock was held by approximately 16,500 holders of record.

On February 17, 2011, the Board declared a cash dividend of $.04 per share on the Company’s outstanding common stock. The dividend is payable April 14, 2011 to stockholders of record at the close of business on March 31, 2011.

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, 2010:

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 2010		334	$	65.12		—
November 2010		1,481	$	80.12		—
December 2010		1,524	$	80.11		—
Total		3,339	$	78.61		—	$	355,789,018

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

During 2007, the Board approved a share repurchase program authorizing the purchase of up to $750 million of the Company’s common stock, of which $355.8 million remains available. During 2010, the Company did not repurchase any common stock pursuant to the 2007 program.

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PIONEER NATURAL RESOURCES COMPANY

ITEM 6. SELECTED FINANCIAL DATA

The following selected consolidated financial data of the Company as of and for each of the five years ended December 31, 2010 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,
	2010		2009			2008		2007		2006
	(in millions, except per share data)
Statements of Operations Data:
Oil and gas revenues (a)	$	1,803.3	$	1,459.7		$	2,012.2	$	1,589.0	$	1,334.1
Total revenues (b)	$	2,471.6	$	1,347.7		$	2,046.0	$	1,615.1	$	1,342.7
Total costs and expenses	$	1,683.1	$	1,595.1		$	1,745.2	$	1,344.3	$	1,117.5
Income (loss) from continuing operations	$	516.2	$	(159.2	)	$	186.9	$	202.7	$	123.9
Income (loss) from discontinued operations, net of tax (c)	$	129.8	$	116.9		$	44.8	$	169.7	$	613.6
Net income (loss) attributable to common stockholders	$	605.2	$	(52.1	)	$	210.0	$	372.7	$	739.7
Income (loss) from continuing operations per share:
Basic	$	4.04	$	(1.48	)	$	1.38	$	1.64	$	0.92
Diluted	$	3.99	$	(1.48	)	$	1.38	$	1.63	$	0.90
Net income (loss) attributable to common stockholders per share:
Basic	$	5.14	$	(0.46	)	$	1.76	$	3.05	$	5.85
Diluted	$	5.08	$	(0.46	)	$	1.76	$	3.04	$	5.75
Dividends declared per share	$	0.08	$	0.08		$	0.30	$	0.27	$	0.25
Balance Sheet Data (as of December 31):
Total assets	$	9,679.1	$	8,867.3		$	9,161.8	$	8,617.0	$	7,355.4
Long-term obligations	$	4,683.9	$	4,653.0		$	4,787.2	$	4,568.1	$	3,469.4
Total stockholders’ equity	$	4,226.0	$	3,643.0		$	3,679.6	$	3,054.7	$	2,999.0

(a) The Company’s oil and gas revenues for 2010, as compared to those of 2009, increased by $343.6 million (or 24 percent) due to increases in worldwide commodity prices and United States oil and NGL sales volumes, partially offset by decreases in United States and South Africa 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 $448.4 million of net derivative gains in its total revenues of 2010, including $364.4 million of noncash MTM gains as compared to $195.6 million of net derivative losses during 2009, including $191.6 million of noncash MTM losses. 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, as compared to $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 project.

(c) During February 2011, the Company sold 100 percent of its share holdings in its Tunisian subsidiaries, pursuant to a plan committed to during 2010. In accordance with GAAP, the Company has classified the Tunisia results of operations as discontinued operations, rather than a component of continuing operations. During 2010, the Company received $35.3 million of interest on excess royalties paid on oil and gas production from its deepwater Gulf of Mexico properties during the period from January 1, 2003 through December 31, 2005. 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 and deepwater properties were sold effective July 1, 2009 and January 1, 2006, respectively. 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.

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PIONEER NATURAL RESOURCES COMPANY

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

Financial and Operating Performance

Pioneer’s financial and operating performance for 2010 included the following highlights:

• Earnings attributable to common stockholders was $605.2 million ($5.08 per diluted share), as compared to a net loss attributable to common stockholders of $52.1 million ($0.46 per diluted share) in 2009. The increase in earnings attributable to common stockholders is primarily due to:

• A $343.6 million pretax increase in oil and gas revenues as a result of commodity price increases;

• A $644.0 million pretax increase in net derivative gains, primarily due to decreases in future commodity prices, principally gas prices, relative to the contract prices in the Company’s derivative position portfolio at December 31, 2010;

• A $156.2 million increase in net hurricane activity gains during 2010, primarily attributable to East Cameron 322 reclamation and abandonment insurance recoveries; and

• A $54.8 million pretax decrease in depreciation, depletion and amortization (“DD&A”) expense, primarily due to increases in proved reserves from the Company’s 2010 capital program and positive price revisions as a result of higher average commodity prices during 2010 as compared to 2009; partially offset by:

• A $33.8 million increase in general and administrative expenses due to increases in performance-related compensation expenses and staffing increases to support the Company’s increased activity level; and

• A $13.8 million increase in production and ad valorem taxes due to the increase in commodity prices.

• Daily sales volumes from continuing operations increased on a BOE basis by one percent to 109,399 BOEPD during 2010, as compared to 108,071 BOEPD during 2009.

• Average reported oil, NGL and gas prices from continuing operations increased during 2010 to $90.29 per Bbl, $38.14 per Bbl and $4.34 per Mcf, respectively, as compared to respective prices of $75.45 per Bbl, $29.76 per Bbl and $3.97 per Mcf during 2009.

• Average oil and gas production costs and total ad valorem and production taxes per BOE from continuing operations increased during 2010 to $9.17 and $2.81, respectively, as compared to respective per BOE costs of $8.90 and $2.49 during 2009, primarily as a result of inflation of well servicing costs, increased workover expenditures and higher commodity prices.

• Net cash provided by operating activities increased by $742.0 million, or 137 percent, to $1.3 billion for 2010, as compared to $543.1 million in 2009, primarily due to the increase in commodity prices, an increase in cash derivative gains and working capital changes.

• Long-term debt was reduced by $159.3 million and cash balances increased by $83.8 million during 2010.

• 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. 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. 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 mid-2013.

• In conjunction with the Eagle Ford Shale joint venture transaction, the Company also sold a 49.9 percent member interest in its subsidiary EFS Midstream LLC (“EFS Midstream”) to the purchaser for $46.4 million of cash proceeds and deferred a $46.2 million associated net gain. After the sale, the Company no longer has voting control of EFS Midstream. The Company no longer consolidates the financial statements of EFS Midstream and is accounting for its investment in the venture under the equity method.

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PIONEER NATURAL RESOURCES COMPANY

• During December 2010, the Company committed to a plan to sell its Tunisian assets and liabilities and during February 2011 sold 100 percent of the Company’s share holdings in its Tunisian subsidiaries for $866 million, before normal closing adjustments. Accordingly, the Company has classified its Tunisian assets and liabilities as discontinued operations held for sale as of December 31, 2010, and has classified its historic Tunisian revenues and expenses as income from discontinued operations in the accompanying consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

First Quarter 2011 Outlook

The Company’s first quarter of 2011 outlook below does not reflect the effects of recent weather-related downtime and associated repairs in several of Pioneer’s operating areas.

The Company expects that first quarter 2011 production will average 114 to 118 BOEPD, reflecting increased 2011 drilling activity and the expiration at December 31, 2010 of one of the Company’s VPP obligations.

First quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $11.75 to $13.75 per BOE, based on current NYMEX strip prices for oil, NGLs and gas. DD&A expense is expected to average $13.50 to $15.00 per BOE.

Total exploration and abandonment expense for the quarter is expected to be $25 million to $35 million. General and administrative expense is expected to be $45 million to $49 million. Interest expense is expected to be $44 million to $47 million, and other expense is expected to be $20 million to $25 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.

The Company’s first quarter effective income tax rate from continuing operations is expected to range from 35 percent to 45 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 $5 million to $10 million, principally related to South African income taxes.

2011 Capital Budget

Pioneer’s capital program for 2011 totals $1.8 billion, consisting of $1.6 billion for drilling operations and $0.2 billion for vertical integration and facilities. The 2011 budget excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical general and administrative expense.

The 2011 drilling capital of $1.6 billion continues to be focused on oil- and liquids-rich drilling, with 75 percent of the capital allocated to the Spraberry field and Eagle Ford Shale plays. Following is a breakdown of the forecasted spending by asset area:

• Spraberry field – $1.1 billion;

• Eagle Ford Shale – $110 million (reflecting 25 percent of anticipated 2011 drilling costs, with the remaining 75 percent to be funded by a contractual drilling carry benefit);

• Barnett Shale Combo play – $170 million;

• Alaska – $115 million; and

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

Funds for the expansion of Pioneer’s integrated well service operations in the Spraberry field, the establishment of similar services in the Eagle Ford Shale and Barnett Shale Combo plays, and the build-out of facilities to support vertical integration (such as yards, buildings and shops) are budgeted at $200 million in 2011.

The 2011 capital budget is expected to be funded from forecasted operating cash flow and by redeploying a portion of the proceeds from the sale of the Company’s Tunisian subsidiaries (see Divestitures, below).

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PIONEER NATURAL RESOURCES COMPANY

Acquisitions

During 2010, 2009 and 2008, the Company spent approximately $181.6 million, $88.9 million and $137.6 million, respectively, to acquire proved and unproved properties. The 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. The 2008 acquisitions primarily added proved reserves and increased the Company’s acreage positions in the Spraberry field, South Texas Edwards Trend and Barnett Shale play.

Divestitures

Tunisian Subsidiaries. As referred to in Financial and Operating Performance above, the Company committed to a plan to sell its Tunisian subsidiaries during December 2010 and in February 2011 sold 100 percent of its share holdings in its Tunisian subsidiaries for cash proceeds of $866 million, before normal closing adjustments (see Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” and “Divestitures,” below).

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. 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 mid-2013.

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 of certain asset retirement obligations, resulting in a pretax gain of $17.3 million.

Mississippi and Gulf of Mexico Shelf. In 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 of these assets and the related gain on disposition are reported as discontinued operations.

Results of Operations

Oil and gas revenues. Oil and gas revenues totaled $1.8 billion, $1.5 billion and $2.0 billion during 2010, 2009 and 2008, respectively.

The increase in 2010 oil and gas revenues relative to 2009 was due to commodity price increases and the increase in production. In the United States, the Company’s 2010 average reported oil, NGL and gas prices increased 20 percent, 28 percent and nine percent, respectively, as compared to 2009, and average daily sales volumes, on a BOE basis, during 2010 were one percent higher than 2009. In South Africa, the Company’s 2010 average reported oil and gas prices increased 18 percent and 20 percent, respectively, as compared to 2009, and average daily sales volumes, on a BOE basis, increased 20 percent during 2010, as compared to 2009.

The decrease in 2009 oil and gas revenues relative to 2008 was due to commodity price declines during 2009 and a reduction in production from fewer new wells drilled due to cost reduction initiatives implemented during 2008 and 2009. In the United States, the Company’s 2009 average reported NGL and gas prices declined 42 percent and 49 percent, respectively, as compared to 2008. These 2009 declines were partially offset by a 15 percent increase in the 2009 average reported oil price and a two percent increase in 2009 average daily sales volumes, on a BOE basis, as compared to 2008. In South Africa, the Company’s average reported oil and gas prices in 2009 decreased 40 percent and 11 percent, respectively, partially offset by a 13 percent increase in average daily sales volumes, on a BOE basis, as compared to 2008.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides average daily sales volumes from continuing operations by geographic area and in total for 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
Oil (Bbls):
United States		28,211		24,968		21,091
South Africa		616		375		2,405
Worldwide		28,827		25,343		23,496
NGLs (Bbls):
United States		19,736		19,680		19,048
Gas (Mcf):
United States		335,256		352,749		366,796
South Africa		29,760		25,538		10,232
Worldwide		365,016		378,287		377,028
Total (BOE):
United States		103,823		103,440		101,271
South Africa		5,576		4,631		4,110
Worldwide		109,399		108,071		105,381

During the year ended December 31, 2010, oil and gas volumes delivered under the Company’s VPP agreements decreased by 43 percent, as compared to 2009. During the year ended December 31, 2009, oil and gas volumes delivered under the Company’s VPP agreements decreased by seven percent, as compared to 2008. The Company completed its obligations to deliver gas volumes at the end of 2009 and completed oil delivery obligations under one of the VPP agreements at the end of 2010. As a result, oil volumes delivered under the VPP agreements will decline by 45 percent during 2011 as compared to 2010. The Company’s oil delivery obligations under its only remaining VPP agreement will be completed at the end of 2012.

The following table provides average daily sales volumes from discontinued operations by geographic area and in total during 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
Oil (Bbls):
United States		—		554		953
Tunisia		4,880		6,531		6,178
Worldwide		4,880		7,085		7,131
NGLs (Bbls):
United States		—		29		35
Gas (Mcf):
United States		—		1,899		3,428
Tunisia		2,849		1,668		2,367
Worldwide		2,849		3,567		5,795
Total (BOE):
United States		—		900		1,559
Tunisia		5,355		6,809		6,573
Worldwide		5,355		7,709		8,132

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PIONEER NATURAL RESOURCES COMPANY

The following table provides average reported prices from continuing operations, including recorded commodity hedge gains and losses and the amortization of VPP deferred revenue, and average realized prices from continuing operations, excluding recorded commodity hedge gains and losses and the amortization of VPP deferred revenue, by geographic area and in total for 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
Average reported prices:
Oil (per Bbl):
United States	$	90.56	$	75.60	$	65.74
South Africa	$	78.07	$	65.94	$	110.21
Worldwide	$	90.29	$	75.45	$	70.29
NGL (per Bbl):
United States	$	38.14	$	29.76	$	51.31
Gas (per Mcf):
United States	$	4.18	$	3.88	$	7.66
South Africa	$	6.20	$	5.17	$	5.83
Worldwide	$	4.34	$	3.97	$	7.61
Total (per BOE):
United States	$	45.34	$	37.15	$	51.08
South Africa	$	41.74	$	33.85	$	79.00
Worldwide	$	45.16	$	37.00	$	52.17
Average realized prices:
Oil (per Bbl):
United States	$	74.21	$	55.04	$	95.82
South Africa	$	78.07	$	65.94	$	110.21
Worldwide	$	74.30	$	55.20	$	95.84
NGL (per Bbl):
United States	$	37.12	$	28.45	$	51.56
Gas (per Mcf):
United States	$	4.15	$	3.32	$	7.39
South Africa	$	6.20	$	5.17	$	5.83
Worldwide	$	4.31	$	3.45	$	7.37
Total (per BOE):
United States	$	40.61	$	30.02	$	56.41
South Africa	$	41.74	$	33.85	$	79.00
Worldwide	$	40.67	$	30.19	$	57.07

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 and sells, (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 accumulated other comprehensive income – deferred hedge gains, net of tax (“AOCI – Hedging”), in the stockholders’ equity section of the Company’s 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.

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PIONEER NATURAL RESOURCES COMPANY

The following table summarizes the transfers of deferred hedge gains and losses associated with oil, NGL and gas cash flow hedges from AOCI – Hedging to oil, NGL and gas revenues for the years ending December 31, 2010, 2009 and 2008 (in thousands):

	Year Ended December 31,
	2010		2009		2008
Increase (decrease) to oil revenue from AOCI—Hedging transfers	$	78,052	$	88,873	$	(336,249	)
Increase (decrease) to NGL revenue from AOCI—Hedging transfers		7,297		9,402		(1,781	)
Increase (decrease) to gas revenue from AOCI—Hedging transfers		3,691		22,791		(17,533	)
Total	$	89,040	$	121,066	$	(355,563	)

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 gains and losses on discontinued commodity hedges that will be recognized as increases or decreases to future oil and gas revenues.

Deferred revenue. During 2010, the Company’s amortization of deferred VPP revenue increased annual oil revenues by $90.2 million and, during 2009 and 2008, increased oil and gas revenues by $147.9 million and $158.1 million, respectively. The Company’s amortization of deferred VPP revenue will increase 2011 annual oil revenues by $45.0 million. 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 VPP agreements.

Interest and other income. The Company’s interest and other income from continuing operations totaled $61.9 million, $101.7 million and $56.5 million during 2010, 2009 and 2008, respectively. The $39.8 million decrease during 2010, as compared to 2009, is primarily attributable to (i) a $47.3 million decrease in Alaskan Petroleum Production Tax (“PPT”) credit recoveries and (ii) increases of $2.2 million, $1.7 million, $1.2 million, and $1.8 million in interest income, insurance recoveries, retirement obligation revaluation and carbon dioxide revenues, respectively. The $45.2 million increase during 2009, as compared to 2008, is primarily attributable to (i) a $76.4 million increase in PPT credit dispositions, partially offset by (ii) a $20.5 million 2008 gain on early extinguishment of debt and (iii) a $6.6 million decrease in foreign exchange gains.

At December 31, 2010, the Company had $27.5 million of available PPT-related carryforwards that were reimbursed in cash during February 2011. The Company anticipates recognizing future benefits from the PPT-related carryforwards from (i) reductions in PPT liabilities or (ii) reimbursement directly from the State of Alaska.

Derivative gains (losses), net. The following table summarizes the Company’s net derivative gains (losses) for the years ending December 31, 2010, 2009 and 2008 (in thousands):

	December 31, 2010			December 31, 2009			December 31, 2008
Unrealized mark-to-market changes in fair value:
Oil derivative gains (losses)	$	41,094		$	(150,799	)	$	(18,566	)
NGL derivative gains (losses)		10,690			(20,206	)		7
Gas derivative gains (losses)		277,585			(6,612	)		8,405
Interest rate derivative gains (losses)		35,040			(13,928	)		—
Total unrealized mark-to-market derivative gains (losses), net (a)		364,409			(191,545	)		(10,154	)
Cash settled changes in fair value:
Oil derivative losses		(27,305	)		(60,604	)		(1,479	)
NGL derivative losses		(7,180	)		(8,340	)		—
Gas derivative gains		119,417			66,428			1,485
Interest rate derivative losses		(907	)		(1,496	)		—
Total cash derivative gains (losses), net		84,025			(4,012	)		6
Total derivative gains (losses), net	$	448,434		$	(195,557	)	$	(10,148	)

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

Gain (loss) on disposition of assets. The Company recorded net gains on the disposition of assets of $19.1 million during 2010 and net losses of $774 thousand and $381 thousand in 2009 and 2008, respectively.

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.

The Company used the net cash proceeds from asset divestitures during 2010, 2009 and 2008, together with net cash flows provided by operating activities, to fund additions to oil and gas properties, stock repurchase programs and to reduce outstanding indebtedness. See Notes M and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s asset divestitures and discontinued operations.

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PIONEER NATURAL RESOURCES COMPANY

Hurricane activity, net. The Company recorded net hurricane activity gains of $138.9 during 2010 and recorded net hurricane activity expenses of $17.3 million and $12.2 million during 2009 and 2008, respectively.

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 are substantially complete. The Company estimates that it will expend approximately $2.5 million during 2011 to complete the operations to reclaim and abandon the East Cameron 322 facility.

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. Since 2005, the Company has recovered from its insurance providers (i) $199.8 million attributable to reclamation and abandonment costs incurred, (ii) $18.0 million related to business interruption and property damage losses and (iii) $3.0 million of reimbursed interest costs. 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 totaled $366.1 million, $351.4 million and $402.9 million during 2010, 2009 and 2008, 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 2010, total production costs per BOE increased by three percent as compared to 2009. The increase in United States production costs per BOE is primarily due to inflation in well servicing costs and increases in workover expenditures incurred to mitigate production declines, partially offset by the expiration of one of the Company’s VPP delivery commitments. South Africa production costs per BOE decreased during 2010 due to continuing efficiencies being realized in South Coast Gas project operations, $1.4 million of production cost refunds received for operator overbills and the effects of higher sales volumes on the fixed components of South Africa production costs.

Total production costs per BOE decreased during 2009 by 15 percent as compared to 2008. During 2008, the Company’s oil and gas production costs increased throughout the first nine months of the year, primarily due to inflation of well servicing expense, electricity expense and water hauling costs. As a result of the Company’s cost reduction initiatives that were started in late 2008 and continued in 2009, Pioneer realized significant production cost reductions in 2009, as compared to 2008. The decrease in South Africa production costs was directly attributable to the shut in of the Sable oil field, which had a high fixed-cost component of production costs as compared to the South Coast Gas project, which has significantly lower production costs.

The following tables provide the components of the Company’s total production costs per BOE and total production costs per BOE by geographic area for 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
Lease operating expenses	$	7.39	$	7.21	$	8.38
Third-party transportation charges		0.83		0.91		1.02
Net natural gas plant/gathering charges		0.08		0.26		0.16
Workover costs		0.87		0.52		0.90
Total production costs	$	9.17	$	8.90	$	10.46

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PIONEER NATURAL RESOURCES COMPANY

	Year Ended December 31,
	2010		2009		2008
United States	$	9.61	$	9.16	$	9.81
South Africa	$	0.68	$	3.26	$	25.98
Worldwide	$	9.17	$	8.90	$	10.46

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $112.1 million during 2010, as compared to $98.4 million and $164.4 million for 2009 and 2008, 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 2010, the Company’s production taxes per BOE increased by 32 percent, reflecting the year-to-year increase in commodity prices, while ad valorem taxes decreased one percent. During 2009, the Company’s production taxes per BOE declined 62 percent, reflecting the year-to-year decline in commodity prices, while ad valorem taxes decreased slightly.

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 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
Ad valorem taxes	$	1.42	$	1.44	$	1.52
Production taxes		1.39		1.05		2.74
Total ad valorem and production taxes	$	2.81	$	2.49	$	4.26

Depletion, depreciation and amortization expense. The Company’s total DD&A expense was $14.38, $15.95 and $12.31 per BOE for 2010, 2009 and 2008, respectively. Depletion expense, the largest component of DD&A expense, was $13.63, $15.23 and $11.58 per BOE during 2010, 2009 and 2008, respectively.

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 Forms 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. During 2009, the Company’s cost reduction initiatives and a declining trend in drilling costs mitigated the 2009 increase in per BOE depletion expense.

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 December 31, 2009.

During 2009, the increase in per BOE depletion expense was primarily due to (i) losing end-of-life reserves that became uneconomic as a result of commodity price declines since December 31, 2008, (ii) a generally increasing trend through 2008 in the Company’s oil and gas properties’ cost bases per BOE of proved and proved developed reserves as a result of cost inflation in drilling rig rates and drilling supplies and (iii) the relatively higher depletion rate per BOE associated with production from the Oooguruk development, which began first production in June 2008, and the South African South Coast Gas project, which became fully operational in October 2008.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides depletion expense per BOE from continuing operations by geographic area for 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
United States	$	12.40	$	14.20	$	11.30
South Africa	$	36.50	$	38.33	$	18.37
Worldwide	$	13.63	$	15.23	$	11.58

Impairment of oil and gas properties and other 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 year ended December 31, 2010, the Company assessed its oil and gas properties for impairment and found no impairment of their carrying values to exist. 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. During the year ended December 31, 2008, the Company recognized impairment charges of $104.3 million, including $14.5 million attributable to discontinued operations, to reduce the carrying value of its net assets in the Uinta/Piceance and Mississippi areas. Declines in gas prices and downward adjustments to the economically recoverable resource potential of these properties led to the impairment charges.

The Company assesses goodwill for impairment at least annually. The Company’s assessments of goodwill for impairment during 2010 and 2009 confirmed that the Company’s carrying value of goodwill was not impaired.

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 tables provide the Company’s geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense by geographic area for 2010, 2009 and 2008 (in thousands):

	United States		South Africa		Other		Total
Year ended December 31, 2010
Geological and geophysical	$	58,016	$	512	$	—	$	58,528
Exploratory dry holes		91,922		—		—		91,922
Leasehold abandonments and other		39,659		—		—		39,659
	$	189,597	$	512	$	—	$	190,109
Year ended December 31, 2009
Geological and geophysical	$	40,919	$	623	$	—	$	41,542
Exploratory dry holes		6,873		—		—		6,873
Leasehold abandonments and other		31,303		—		—		31,303
	$	79,095	$	623	$	—	$	79,718
Year ended December 31, 2008
Geological and geophysical	$	72,146	$	143	$	1,585	$	73,874
Exploratory dry holes		73,741		—		487		74,228
Leasehold abandonments and other		43,841		—		—		43,841
	$	189,728	$	143	$	2,072	$	191,943

During 2010, the Company’s exploration and abandonment expense was primarily attributable to $58.0 million of United States geological and geophysical personnel costs, $96.7 million of dry hole and leasehold abandonment charges resulting from the Company’s decision not to pursue development of the Cosmopolitan Unit in the Cook Inlet of Alaska and other United States dry hole provisions and unproved property abandonments. The 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 42 exploration/extension wells, 39 of which were successfully completed as discoveries.

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During 2009, the Company’s exploration and abandonment expense was primarily attributable to United States geological and geophysical personnel costs, South Texas, Lay Creek and Raton Basin areas dry hole expense 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 17 exploration/extension wells, 13 of which were successfully completed as discoveries.

During 2008, the Company’s exploration and abandonment expense was primarily attributable to seismic activity in the Company’s Utah and South Texas areas, dry hole expense and unproved property abandonments. The significant components of the Company’s exploratory dry hole provisions and unproved property abandonments expense included (i) $47.1 million of costs associated with the unsuccessful Lay Creek CBM pilot project, (ii) $12.2 million of costs associated with the unsuccessful Delaware Basin exploration project, (iii) $11.3 million of costs associated with the unsuccessful Sligo exploration well in South Texas and (iv) $41.1 million of U.S. unproved property abandonments. During 2008, the Company completed and evaluated 81 exploration/extension wells, 62 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense totaled $165.3 million, $131.5 million and $132.6 million during 2010, 2009 and 2008, respectively. 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.

The decrease in general and administrative expense during 2009, as compared to 2008, was primarily due to the Company’s cost reduction initiatives, partially offset by an increases in compensation and occupancy expenses and a decline in general and administrative cost recoveries.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations from continuing operations was $10.4 million, $10.6 million and $7.7 million during 2010, 2009 and 2008, respectively. Accretion of discount on asset retirement obligations decreased slightly during 2010 as compared to 2009 due to incremental accretion associated with higher commodity prices having the effect of extending the economic life of the Company’s wells. The increase in accretion of discount on asset retirement obligations during 2009 was primarily due to the accretion associated with higher asset retirement obligations that resulted from declining commodity prices having the effect of reducing the economic life of the Company’s wells, thus accelerating their forecasted abandonment date, plus the accretion attributable to new wells placed on production. 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 $183.1 million, $173.4 million and $166.8 million during 2010, 2009 and 2008, respectively. The weighted average interest rate on the Company’s indebtedness for the year ended December 31, 2010 was 6.4 percent, as compared to 5.2 percent and 5.5 percent for the years ended December 31, 2009 and 2008, respectively, including the effects of interest rate derivatives.

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 a (ii) $10.6 million decrease in cash interest expense on lines of credit and a (iii) $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.

The $6.6 million increase in interest expense during the year ended December 31, 2009, as compared to 2008, was primarily due to (i) a $9.2 million decrease in capitalized interest related to the Oooguruk project as development wells were placed on production, partially offset by (ii) a $4.8 million decrease in cash interest expense on long-term borrowings.

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.

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Other expenses. Other expenses were $81.7 million during 2010, as compared to $100.1 million during 2009 and $114.5 million during 2008. The $18.4 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 $2.9 million increase in severance and ad valorem tax audit adjustments.

The $14.4 million decrease in other expense during 2009, as compared to 2008, is primarily attributable to (i) a $25.8 million decrease in bad debt expense, partially offset by (ii) a $9.1 million increase in idle well servicing operations.

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 an income tax provision attributable to earnings from continuing operations of $272.3 million during 2010, an income tax benefit of $88.2 million during 2009 and an income tax provision of $113.9 million during 2008. The Company’s effective tax rates for 2010, 2009 and 2008 were 36 percent, 35 percent and 40 percent, respectively, as compared to the combined United States federal and state statutory rates of approximately 37 percent. The effective tax rates differ from the combined United States federal and state statutory rates primarily due to:

• foreign tax rates and

• a $4.8 million U.S. tax benefit during 2009 and a $15.8 million U.S. tax provision during 2008 related to the Company no longer having identifiable plans to reinvest South Africa earnings in South Africa.

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 tax position.

Income (loss) from discontinued operations, net of tax. During December 2010, the Company committed to a plan to sell its Tunisian subsidiaries and in February 2011 sold 100 percent of the Company’s share holdings in its Tunisian subsidiaries for $866 million, before normal closing adjustments. Accordingly, the Company has classified its Tunisian assets and liabilities as discontinued operations held for sale as of December 31, 2010, and has classified its historic Tunisian revenues and expenses as income from discontinued operations in the accompanying consolidated financial statements. 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 of $129.8 million during 2010 as compared to income from discontinued operations of $116.9 million during 2009 and $44.8 million during 2008. The $12.9 million increase in income from discontinued operations during 2010, as compared to 2009 is attributable to 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 and (iii) a 2010 deferred tax benefit adjustment related to Tunisia of $56.5 million, partially offset by (iv) the after tax impact of the 2009 recognition of $119.3 million of pretax gain from the aforementioned excess royalty recovery.

The $72.1 million increase in income from discontinued operations during 2009, as compared to 2008, is attributable to (i) the aforementioned $119.3 million excess royalty gain, (ii) a $5.6 million increase in discontinued operations tax provisions and (iii) a $17.5 million pretax gain from the divestiture of the Company’s Mississippi assets and substantially all of the Company’s Gulf of Mexico shelf properties during 2009, partially offset by (iv) a $68.2 million decrease in Tunisian pretax income. 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) loss attributable to noncontrolling interest. Net income attributable to noncontrolling interests was $40.8 million, $9.8 million and $21.6 million for the years ended December 31, 2010, 2009 and 2008,

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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 $31.0 million increase in net income attributable to noncontrolling interest in 2010, as compared to 2009, is primarily due to an increase in Pioneer Southwest’s noncash mark-to-market derivative gains.

The $11.8 million decrease in net income attributable to noncontrolling interest in 2009, compared to 2008, is primarily due to an increase in Pioneer Southwest mark-to-market derivative losses during 2009. 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 assets, payment of contractual obligations, including funding of EFS Midstream, dividends/distributions and working capital obligations. Funding for these cash needs, as well as funding for any stock or debt repurchases that the Company may undertake, may be provided by any combination of internally-generated cash flow, proceeds from the disposition of nonstrategic assets or external financing sources as discussed in “Capital resources” below. The Company expects that it will be able to fund its needs for cash (excluding acquisitions) with internally-generated cash flows and with its liquidity under its credit facility. Although the Company expects that internal operating cash flows 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.

The Company intends to limit its capital expenditures to a level that allows the Company to deliver net cash flow from operating activities in excess of capital requirements in order to enhance and preserve financial flexibility. However, during 2011, the Company expects to redeploy a portion of the proceeds from the sale of its Tunisian subsidiaries to accelerate drilling in the Eagle Ford Shale, Spraberry and Barnett Shale Combo areas. During 2010, the Company’s capital expenditures totaled $855.6 million (excluding effects of asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream investments), as compared to $312.9 million in 2009, representing a 173 percent increase.

During 2011, the Company plans to continue its oil- and liquids-rich-gas-focused drilling activities. The Company’s 2011 capital budget totals $1.8 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream capital contributions), consisting of $1.6 billion for drilling operations and $200 million for vertical integration and facilities. Based on current NYMEX commodity prices, the Company expects its cash flow from operating activities plus a portion of the proceeds from the sale of its Tunisian subsidiaries to be sufficient to fund its planned capital expenditures and contractual obligations.

Investing activities. Net cash used in investing activities during 2010 was $954.9 million, as compared to net cash used in investing activities of $411.0 million and $1.2 billion during 2009 and 2008, respectively. 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 ETAP associated with the participation in the Cherouq concession and $77.4 million of net proceeds from the sale of other assets. The decrease in net cash used in investing activities during 2009, as compared to 2008, was primarily due to cost reduction initiatives, which resulted in a $966.0 million decrease in additions to oil and gas properties and a $15.7 million decrease in additions to other assets and other property and equipment, partially offset by a $241.3 million decrease in proceeds from disposition of 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.

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During December 2010, the Company committed to a plan to sell its Tunisian subsidiaries and in February 2011 sold 100 percent of the Company’s share holdings in its Tunisian subsidiaries for $866 million, before normal closing adjustments.

Dividends/distributions. During each of 2010 and 2009, the Board declared semiannual dividends of $0.04 per common share. Associated therewith, the Company paid $9.5 million and $9.4 million of aggregate dividends during 2010 and 2009, respectively. 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 2010 and 2009, the board of directors of the general partner of Pioneer Southwest (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 $25.2 million and $19.0 million during 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, 2010, 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 in the future), (v) open purchase commitments, (vi) EFS Midstream capital funding commitments and (vii) 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, 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”).

The following table summarizes by period the payments due by the Company for contractual obligations estimated as of December 31, 2010:

	Payments Due by Year
	2011		2012 and 2013		2014 and 2015		Thereafter
	(in thousands)
Long-term debt (a)	$	—	$	610,200	$	—	$	2,089,985
Operating leases (b)		16,719		31,586		26,604		52,387
Drilling commitments (c)		287,207		312,073		19,018		—
Derivative obligations (d)		80,998		55,060		1,514		—
Open purchase commitments (e)		403,921		96,563		—		—
Other liabilities (f)		36,210		54,586		17,390		160,258
Firm gathering, processing and transportation commitments (g)		83,448		248,128		252,056		669,421
VPP obligations (h)		44,951		42,069		—		—
	$	953,454	$	1,450,265	$	316,582	$	2,972,051

(a) Long-term debt includes $480.0 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 Company’s 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 2011. If any holders elect to convert, the Company expects that the cash portion of the conversion payment will be available from cash on hand or borrowings under the Credit Facility 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.

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(b) See Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

(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, 2010.

(d) Derivative obligations represent net liabilities for oil and gas commodity derivatives that were valued as of December 31, 2010. 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 and other property, plant and equipment ordered, but not received, as of December 31, 2010.

(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) These amounts represent the amortization of the deferred revenue associated with the VPPs. The Company’s ongoing obligation is to deliver the specified volumes sold under the VPPs 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 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 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.

Operating activities. Net cash provided by operating activities during 2010, 2009 and 2008 was $1.3 billion, $543.1 million and $1.0 billion, respectively. 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. The decrease in net cash provided by operating activities in 2009, as compared to that of 2008, was primarily due to decreased oil, NGL and gas prices from continuing operations, partially offset by an increase in commodity sales volumes and decreased production costs.

Asset divestitures. During 2010, the Company (i) committed to the sale of 100 percent of the Company’s share holdings in its Tunisian subsidiaries, which were sold during February 2011, (ii) 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, (iii) sold certain proved and unproved properties in the Uinta/Piceance area for net proceeds of $11.8 million and (iv) 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 2010 divestitures.

During June and August 2009, the Company sold its Mississippi assets and shelf properties in the Gulf of Mexico, respectively, for a net gain of $17.8 million. Also during August 2009, Pioneer USA sold certain of its

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properties in the Spraberry Field in West Texas to Pioneer Southwest for proceeds of $168.3 million including normal closing adjustments. The transaction value also included the assignment of 2009 through 2013 commodity price derivative positions to Pioneer Southwest. Pioneer Southwest is a partially-owned and consolidated subsidiary of the Company. Consequently, the sale of the properties from Pioneer USA to Pioneer Southwest represented a transfer among entities under common control and did not reduce the Company’s oil and gas properties’ carrying values. Proceeds from the sale were used to reduce Pioneer’s credit facility indebtedness. Pioneer Southwest funded the acquisition with cash on hand and borrowings on its credit facility.

During 2008, the Company terminated derivative assets prior to their contractual maturity dates. The accompanying consolidated statement of cash flows for the year ended December 31, 2008 includes $155.0 million of proceeds from disposition of assets attributable to these derivative terminations.

Financing activities. Net cash used in financing activities for 2010 was $246.4 million, as compared to net cash used in financing activities of $153.0 million and net cash provided by financing activities of $153.7 million for 2009 and 2008, respectively. 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 $61.0 million of net proceeds from a secondary unit offering by Pioneer Southwest, partially offset by $63.3 million of payments associated with dividends, distributions to noncontrolling interests, financing fees and stock repurchases. During 2008, significant components of financing activities included $225.8 million of net borrowings of long-term debt and $166.0 million of proceeds from the initial public offering by Pioneer Southwest, partially offset by $181.7 million used to purchase 4.7 million shares of treasury stock.

The following provides a description of the Company’s significant financing activities during 2010, 2009 and 2008:

• During 2010, the Company reduced borrowings under its $1.5 billion credit facility due April 2012 by $191.0 million.

• 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 proceeds, net of $11.4 million of offering discounts and costs, of $438.6 million. The Company used the net proceeds to reduce outstanding borrowings under its credit facility.

• During November 2009, Pioneer Southwest, a subsidiary of the Company, completed a public offering of 3,105,000 common units, which represented a six percent increase in limited partner interests in Pioneer Southwest, for net proceeds of $61.0 million. Pioneer Southwest used the net proceeds to repay amounts outstanding under its revolving credit facility.

• During December 2008, the Company repurchased $20.0 million principal amount of its outstanding 2.875% Senior Convertible Notes, $71.5 million principal amount of its outstanding 5.875% senior notes due 2016, $14.9 million principal amount of its outstanding 6.65% senior notes due 2017 and $500 thousand principal amount of its outstanding 6.875% senior notes due 2018. Associated therewith, the Company recognized a gain of $20.5 million, which is included in interest and other income in the accompanying consolidated statements of operations for the year ended December 31, 2008.

• On May 6, 2008, Pioneer Southwest completed its initial public offering of 9,487,500 common units, representing a 31.6 percent limited partner interest in 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 Company received $166.0 million of net proceeds from Pioneer Southwest in consideration for (i) an ownership interest in a subsidiary of Pioneer that owned the oil and gas properties prior to the initial public offering and (ii) an incremental ownership interest in certain of the same properties as a result of the exercise of the over-allotment option. The net proceeds from the initial public offering were used to reduce the Company’s outstanding indebtedness. The Company consolidates Pioneer Southwest into its financial statements and reflects the public ownership as a noncontrolling interest in Pioneer Southwest’s net assets.

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• In conjunction with the completion of the initial public offering, Pioneer Southwest completed a $300 million unsecured revolving credit facility with a syndicate of banks, which matures in May 2013 (the “Pioneer Southwest Credit Facility”). The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions.

• During January 2008, the Company issued 2.875% Senior Convertible Notes and received proceeds, net of approximately $11.3 million of underwriter discounts and offering costs, of $488.7 million. The Company used the net proceeds from the offering to reduce outstanding borrowings under its credit facility.

The Company has begun preliminary plans towards replacement of its $1.5 billion corporate credit facility that matures in April 2012, with a new corporate credit facility. The Company anticipates that it will successfully negotiate a new credit facility with terms that provide for borrowing capacity, borrowing alternatives, interest rates, fees and financial covenants similar to those of its existing facility. Current plans are to finalize a new corporate credit facility during the first quarter of 2011.

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 source of short-term liquidity is cash on hand and unused borrowing capacity under its credit facility. There were $49.0 million of outstanding borrowings under the credit facility as of December 31, 2010. Including $65.1 million of undrawn and outstanding letters of credit under the credit facility, the Company had $1.4 billion of unused borrowing capacity as of December 31, 2010. If 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. 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 will be adequate to fund capital expenditures and dividend payments, and that available borrowing capacity under the Company’s 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.

Book capitalization and current ratio. The Company’s net book capitalization at December 31, 2010 was $6.7 billion, consisting of $111.2 million of cash and cash equivalents, debt of $2.6 billion and stockholders’ equity of $4.2 billion. The Company’s debt to book capitalization decreased to 37 percent at December 31, 2010 from 43 percent at December 31, 2009, primarily due to a decrease in indebtedness. The Company’s ratio of current assets to current liabilities was 1.56 to 1.00 at December 31, 2010, as compared to 1.08 to 1.00 at December 31, 2009.

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

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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 or seabeds at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. 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, inflation factors, 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, during periods of active exploration, 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. 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 2010, 2009 and 2008, the Company recognized exploration, abandonment, geological and geophysical expense from continuing operations of $190.1 million, 79.7 million and $191.9 million, respectively. During 2010, 2009 and 2008, the Company recognized exploration, abandonment, geological and geophysical expense from discontinued operations of $15.4 million, $18.6 million and $43.6 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, 2010, 2009 and 2008 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.

It should not be assumed that the Standardized Measure included in this Report as of December 31, 2010 is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the 2010 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.

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PIONEER NATURAL RESOURCES COMPANY

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 market 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, 2010, the Company carried unproved property costs of $191.1 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 the exploration well 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 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.

Assessments of functional currencies. Management determines the functional currencies of the Company’s subsidiaries based on an assessment of the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. The U.S. dollar is the functional currency of all of the Company’s current international operations. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position.

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. As of December 31, 2010, the Company does not believe there is sufficient positive evidence to reverse its valuation allowances related to certain foreign tax jurisdictions.

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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, 2010, 2009 and 2008. See Notes B and R 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 I 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 and (c) the Monte Carlo simulation method for the fair value of performance unit awards.

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 notes receivable and 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.”

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PIONEER NATURAL RESOURCES COMPANY

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following quantitative and qualitative information is provided about financial instruments to which the Company was a party as of December 31, 2010, 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. During 2010, the Company changed its valuation inputs for NGL derivative contracts and used component price inputs presently available from independent active market quoted sources. As of December 31, 2009, the Company’s NGL component price inputs were obtained from independent brokers active in buying and selling NGL derivative contracts. As of December 31, 2010, 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 2010:

	Derivative Contract Net Assets (Liabilities) (a)
	Commodities			Interest Rate			Total
	(in thousands)
Fair value of contracts outstanding as of December 31, 2009	$	(121,562	)	$	(17,841	)	$	(139,403	)
Changes in contract fair values (b)		414,302			34,132			448,434
Contract maturities		(125,173	)		1,261			(123,912	)
Fair value of contracts outstanding as of December 31, 2010	$	167,567		$	17,552		$	185,119

(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, 2010 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, 2010. 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 22, 2011.

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PIONEER NATURAL RESOURCES COMPANY

INTEREST RATE SENSITIVITY

DEBT OBLIGATIONS AND DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2010

	Year Ending December 31,																				Asset (Liability) Fair Value at December 31,
	2011			2012			2013			2014			2015			Thereafter			Total		2010
Total Debt:
Fixed rate principal maturities (a)	$	—		$	—		$	480,000		$	—		$	—		$	2,089,985		$	2,569,985	$	(2,954,690	)
Weighted average interest rate		6.05	%		6.05	%		6.74	%		6.78	%		6.78	%		7.13	%
Variable rate principal maturities:
Pioneer credit facility	$	—		$	49,000		$	—		$	—		$	—		$	—		$	49,000	$	(58,382	)
Weighted average interest rate		2.48	%		3.48	%
Pioneer Southwest credit facility	$	—		$	—		$	81,200		$	—		$	—		$	—		$	81,200	$	(77,241	)
Weighted average interest rate		1.35	%		2.36	%		3.52	%
Interest Rate Swaps:
Notional debt amount (b)	$	23,625																			$	(887	)
Fixed rate payable (%)		3.00	%
Variable rate receivable (%)		0.48	%
Notional debt amount (b)	$	470,000		$	470,000		$	470,000		$	470,000		$	470,000		$	100,625				$	18,439
Fixed rate receivable (%)		2.92	%		2.92	%		2.92	%		2.92	%		2.92	%		3.12	%
Variable rate payable (%)		0.48	%		1.48	%		2.64	%		3.42	%		3.73	%		3.68	%

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

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

Commodity derivative instruments and price sensitivity. The following tables provide information about the Company’s oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of December 31, 2010. Although mitigated by the Company’s derivative activities, declines in commodity prices will reduce Pioneer’s revenues and internally-generated cash flows.

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.

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 or gas prices.

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OIL PRICE SENSITIVITY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2010

	Year Ending December 31,								Asset (Liability) Fair Value at December 31,
	2011		2012		2013		2014		2010
									(in thousands)
Oil Derivatives:
Average daily notional Bbl volumes (a):
Swap contracts		750		3,000		3,000		—	$	(31,182	)
Weighted average fixed price per Bbl	$	77.25	$	79.32	$	81.02	$	—
Collar contracts		2,000		—		—		—	$	16,875
Weighted average ceiling price per Bbl	$	170.00	$	—	$	—	$	—
Weighted average floor price per Bbl	$	115.00	$	—	$	—	$	—
Collar contracts with short puts		32,000		37,000		21,250		4,000	$	(86,076	)
Weighted average ceiling price per Bbl	$	99.33	$	118.34	$	117.38	$	120.50
Weighted average floor price per Bbl	$	73.75	$	80.41	$	80.18	$	85.00
Weighted average short put price per Bbl	$	59.31	$	65.00	$	65.18	$	70.00
Average forward NYMEX oil prices (b)	$	98.18	$	100.07	$	99.58	$	99.40

(a) Subsequent to December 31, 2010, the Company entered into additional collar contracts with short puts for 8,000 Bbls per day of the Company’s 2014 production with a ceiling price of $131.99 per Bbl, a floor price of $89.38 per Bbl and a short put price of $74.38 per Bbl.

(b) The average forward NYMEX oil prices are based on February 22, 2011 market quotes.

NGL PRICE SENSITIVITY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2010

	Year Ending December 31,								Liability Fair Value at December 31,
	2011		2012		2013		2014		2010
									(in thousands)
NGL Derivatives:
Average daily notional Bbl volumes:
Swap contracts		1,150		750		—		—		$	(6,519	)
Weighted average fixed price per Bbl	$	51.41	$	35.03	$	—	$	—
Collar contracts		2,650		—		—		—		$	(3,037	)
Weighted average ceiling price per Bbl	$	64.23	$	—	$	—	$	—
Weighted average floor price per Bbl	$	53.29	$	—	$	—	$	—
Average forward NGL prices (a)	$	65.91	$	47.96	$	—	$	—

(a) Forward component NGL prices are not available as formal market quotes. These forward prices represent estimates as of February 22, 2011 provided by third parties who actively trade in the derivatives weighted equivalent to the NGL component volumes covered by the derivative contracts. Accordingly, these prices are subject to estimates and assumptions.

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PIONEER NATURAL RESOURCES COMPANY

GAS PRICE SENSITIVITY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2010

	Year Ending December 31,												Asset (Liability) Fair Value at December 31,
	2011			2012			2013			2014			2010
													(in thousands)
Gas Derivatives:
Average daily notional MMBtu volumes:
Swap contracts		117,500			105,000			67,500			50,000		$	122,495
Weighted average fixed price per MMbtu	$	6.13		$	5.82		$	6.11		$	6.05
Collar contracts		—			65,000			100,000			40,000		$	16,931
Weighted average ceiling price per MMbtu	$	—		$	6.60		$	6.50		$	6.73
Weighted average floor price per MMbtu	$	—		$	5.00		$	5.00		$	5.00
Collar contracts with short puts		200,000			190,000			45,000			50,000		$	160,593
Weighted average ceiling price per MMbtu	$	8.55		$	7.96		$	7.49		$	8.08
Weighted average floor price per MMbtu	$	6.32		$	6.12		$	6.00		$	6.00
Weighted average short put price per MMbtu	$	4.88		$	4.55		$	4.50		$	4.50
Average forward NYMEX gas prices (a)	$	4.13		$	4.73		$	5.12		$	5.44
Basis swap contracts		148,500			116,000			32,500			10,000		$	(22,513	)
Weighted average fixed price per MMbtu	$	(0.54	)	$	(0.37	)	$	(0.34	)	$	(0.16	)
Average forward basis differential prices (b)	$	(0.24	)	$	(0.24	)	$	(0.20	)	$	(0.13	)

(a) The average forward NYMEX gas prices are based on February 22, 2011 market quotes.

(b) The average forward basis differential prices are based on February 17, 2011 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 interest rates, foreign exchange rates and commodity prices. These risks did not change materially from December 31, 2009 to December 31, 2010.

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, and are expected to continue to represent, a portion of the Company’s total assets. Pioneer currently has international continuing operations in South Africa, which represented five percent of the Company’s 2010 oil and gas revenues from continuing operations. During December 2010 the Company committed to a plan to sell its Tunisian assets and during February 2011, the Company sold 100 percent of the Company’s share holdings in its Tunisian subsidiaries. The Company has reflected all Tunisian assets and liabilities as of December 31, 2010 and 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 V of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information about the sale of the Company’s Tunisian subsidiaries).

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As a result of such foreign operations, the Company’s financial results and international operations could be affected by factors 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. Pioneer evaluates on a country-by-country basis whether obtaining political risk coverage is necessary and may add such insurance in the future if the Company believes it is prudent to do so.

Africa. With the completion of the sale of the Company’s Tunisian subsidiaries in February 2011, the Company’s only remaining producing assets in Africa will be in South 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’s South African operations would not have a material impact on the Company’s results of operations given that such operations are closely tied to oil prices, which are denominated in U.S. dollars.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

	Page
Consolidated Financial Statements of Pioneer Natural Resources Company:
Report of Independent Registered Public Accounting Firm		70
Consolidated Balance Sheets as of December 31, 2010 and 2009		71
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008		73
Consolidated Statements of Stockholders’ Equity for the Years Ended December  31, 2010, 2009 and 2008		74
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008		76
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December  31, 2010, 2009 and 2008		77
Notes to Consolidated Financial Statements		78
Unaudited Supplementary Information		121

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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, 2010 and 2009, 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, 2010. 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Pioneer Natural Resources Company at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, 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 reserve 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, 2010, 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 25, 2011 expressed an unqualified opinion thereon.

Ernst & Young LLP

Dallas, Texas

February 25, 2011

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	111,160		$	27,368
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1,155 and $1,310 as of December 31, 2010 and 2009, respectively		237,511			330,711
Due from affiliates		7,792			1,037
Income taxes receivable		30,901			25,022
Inventories		173,615			139,177
Prepaid expenses		11,441			9,011
Deferred income taxes		156,650			26,857
Discontinued operations held for sale		281,741			—
Other current assets:
Derivatives		171,679			48,713
Other, net of allowance for doubtful accounts of nil and $5,689 as of December 31, 2010 and 2009, respectively		14,693			8,222
Total current assets		1,197,183			616,118
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties		10,739,114			10,276,244
Unproved properties		191,112			236,660
Accumulated depletion, depreciation and amortization		(3,366,440	)		(2,946,048	)
Total property, plant and equipment		7,563,786			7,566,856
Deferred income taxes		—			387
Goodwill		298,182			309,259
Other property and equipment, net		283,542			154,830
Other assets:
Investment in unconsolidated affiliate		72,045			—
Derivatives		151,011			43,631
Other, net of allowance for doubtful accounts of $2,519 and $7,300 as of December 31, 2010 and 2009, respectively		113,353			176,184
	$	9,679,102		$	8,867,265

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

71

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (Continued)

(in thousands, except share data)

	December 31,
	2010			2009
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	354,890		$	221,359
Due to affiliates		64,260			32,224
Interest payable		59,008			47,009
Income taxes payable		19,168			17,411
Deferred income taxes		1,144			128
Discontinued operations held for sale		108,592			—
Other current liabilities:
Derivatives		80,997			116,015
Deferred revenue		44,951			90,215
Other		36,210			46,830
Total current liabilities		769,220			571,191
Long-term debt		2,601,670			2,761,011
Derivatives		56,574			133,645
Deferred income taxes		1,751,310			1,470,899
Deferred revenue		42,069			87,021
Other liabilities		232,234			200,467
Stockholders’ equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 126,212,256 and 125,203,502 shares issued at December 31, 2010 and 2009, respectively		1,262			1,252
Additional paid-in capital		3,022,768			2,981,450
Treasury stock, at cost: 10,903,743 and 10,828,171 shares at December 31, 2010 and 2009, respectively		(421,235	)		(415,211	)
Retained earnings		1,510,427			917,688
Accumulated other comprehensive income - deferred hedge gains, net of tax		7,361			51,009
Total stockholders’ equity attributable to common stockholders		4,120,583			3,536,188
Noncontrolling interest in consolidating subsidiaries		105,442			106,843
Total stockholders’ equity		4,226,025			3,643,031
Commitments and contingencies
	$	9,679,102		$	8,867,265

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

72

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year Ended December 31,
	2010			2009			2008
Revenues and other income:
Oil and gas	$	1,803,257		$	1,459,654		$	2,012,196
Interest and other		61,907			101,669			56,463
Derivative gains (losses), net		448,434			(195,557	)		(10,148	)
Gain (loss) on disposition of assets, net		19,074			(774	)		(381	)
Hurricane activity, net		138,918			(17,313	)		(12,150	)
		2,471,590			1,347,679			2,045,980
Costs and expenses:
Oil and gas production		366,146			351,392			402,875
Production and ad valorem taxes		112,141			98,371			164,417
Depletion, depreciation and amortization		574,170			628,987			474,608
Impairment of oil and gas properties		—			21,091			89,753
Exploration and abandonments		190,109			79,718			191,943
General and administrative		165,301			131,524			132,637
Accretion of discount on asset retirement obligations		10,433			10,599			7,717
Interest		183,084			173,353			166,770
Other		81,723			100,073			114,463
		1,683,107			1,595,108			1,745,183
Income (loss) from continuing operations before income taxes		788,483			(247,429	)		300,797
Income tax benefit (provision)		(272,317	)		88,246			(113,916	)
Income (loss) from continuing operations		516,166			(159,183	)		186,881
Income from discontinued operations, net of tax		129,829			116,916			44,774
Net income (loss)		645,995			(42,267	)		231,655
Net income attributable to noncontrolling interests		(40,787	)		(9,839	)		(21,635	)
Net income (loss) attributable to common stockholders	$	605,208		$	(52,106	)	$	210,020
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	4.04		$	(1.48	)	$	1.38
Income from discontinued operations attributable to common stockholders		1.10			1.02			0.38
Net income (loss) attributable to common stockholders	$	5.14		$	(0.46	)	$	1.76
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	3.99		$	(1.48	)	$	1.38
Income from discontinued operations attributable to common stockholders		1.09			1.02			0.38
Net income (loss) attributable to common stockholders	$	5.08		$	(0.46	)	$	1.76
Weighted average shares outstanding:
Basic		115,062			114,176			117,462
Diluted		116,330			114,176			117,947
Amounts attributable to common stockholders:
Income (loss) from continuing operations, net of tax	$	475,379		$	(169,022	)	$	165,246
Discontinued operations, net of tax		129,829			116,916			44,774
Net income (loss)	$	605,208		$	(52,106	)	$	210,020

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

73

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, 2007		117,727		$	1,234	$	2,693,257		$	(245,601	)	$	822,089		$	(228,257	)	$	11,942		$	3,054,664
Dividends declared ($0.30 per share)		—			—		—			—			(35,952	)		—			—			(35,952	)
Exercise of long-term incentive plan stock options and employee stock purchases		355			—		—			15,439			(7,371	)		—			—			8,068
Purchase of treasury stock		(4,714	)		—		—			(181,497	)		—			—			(240	)		(181,737	)
Tax benefits related to stock-based compensation		—			—		367			—			—			—			—			367
Compensation costs:
Vested compensation awards, net		1,178			12		(12	)		—			—			—			—			—
Compensation costs included in net income		—			—		33,970			—			—			—			107			34,077
Issuance of 2.875% senior convertible notes		—			—		49,527			—			—			—			—			49,527
Issuance of Pioneer Southwest common units		—			—		132,626			—			—			—			33,171			165,797
Cash distributions to noncontrolling interests		—			—		—			—			—			—			(8,635	)		(8,635	)
Net income		—			—		—			—			210,020			—			21,635			231,655
Other comprehensive income (loss):
Deferred hedging activity, net of tax:
Hedge fair value changes, net		—			—		—			—			—			89,152			49,361			138,513
Net hedge (gains) losses included in continuing operations		—			—		—			—			—			227,893			(4,624	)		223,269
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

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

74

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (continued)

(in thousands, except dividends per share)

	Shares Outstanding			Stockholders’ Equity Attributable to Common Stockholders														Noncontrolling Interests			Total Stockholders’ Equity
				Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income
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
Treasury stock purchases		(278	)		—		—			(13,835	)		—			—			(204	)		(14,039	)
Tax benefits 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.

75

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2010			2009			2008
Cash flows from operating activities:
Net income (loss)	$	645,995		$	(42,267	)	$	231,655
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		574,170			628,987			474,608
Impairment of oil and gas properties		—			21,091			89,753
Exploration expenses, including dry holes		132,772			37,375			115,497
Hurricane activity, net		4,508			19,850			9,000
Deferred income taxes		248,146			(75,813	)		131,215
(Gain) loss on disposition of assets, net		(19,074	)		774			381
Gain on extinguishment of debt		—			—			(20,515	)
Accretion of discount on asset retirement obligations		10,433			10,599			7,717
Discontinued operations		10,494			(30,601	)		87,594
Interest expense		30,472			27,996			28,491
Derivative related activity		(419,809	)		75,633			45,166
Amortization of stock-based compensation		39,854			37,638			34,077
Amortization of deferred revenue		(90,216	)		(147,905	)		(158,139	)
Other noncash items		26,581			35,994			61,751
Change in operating assets and liabilities
Accounts receivable, net		36,653			16,293			45,446
Income taxes receivable		(5,878	)		36,030			(20,528	)
Inventories		(26,281	)		(46,708	)		(82,403	)
Prepaid expenses		(3,874	)		(3,387	)		(3,405	)
Other current assets		(14,270	)		87,642			(11,745	)
Accounts payable		128,927			(65,862	)		65,644
Interest payable		11,999			3,762			1,227
Income taxes payable		4,007			13,793			(9,225	)
Other current liabilities		(40,586	)		(97,855	)		(89,399	)
Net cash provided by operating activities		1,285,023			543,059			1,033,863
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold		313,780			51,600			292,920
Investment in unconsolidated subsidiary		(72,864	)		—			—
Additions to oil and gas properties		(1,011,442	)		(437,240	)		(1,403,272	)
Additions to other assets and other property and equipment, net		(184,330	)		(25,345	)		(41,058	)
Net cash used in investing activities		(954,856	)		(410,985	)		(1,151,410	)
Cash flows from financing activities:
Borrowings under long-term debt		292,342			1,015,842			1,032,998
Principal payments on long-term debt		(475,252	)		(1,175,703	)		(807,239	)
Contributions from noncontrolling interests		1,151			150			—
Distributions to noncontrolling interests		(26,837	)		(20,012	)		(8,635	)
Proceeds from issuance of partnership common units, net of issuance costs		—			60,983			165,978
Borrowings (payments) of other liabilities		(21,329	)		486			(7,793	)
Exercise of long-term incentive plan stock options and employee stock purchases		7,375			8,506			8,068
Purchase of treasury stock		(14,039	)		(21,921	)		(181,737	)
Excess tax benefits from share-based payment arrangements		(153	)		1			367
Payment of financing fees		(145	)		(12,005	)		(12,377	)
Dividends paid		(9,488	)		(9,370	)		(35,917	)
Net cash provided by (used in) financing activities		(246,375	)		(153,043	)		153,713
Net increase (decrease) in cash and cash equivalents		83,792			(20,969	)		36,166
Cash and cash equivalents, beginning of period		27,368			48,337			12,171
Cash and cash equivalents, end of period	$	111,160		$	27,368		$	48,337

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

76

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

	Year Ended December 31,
	2010			2009			2008
Net income (loss)	$	645,995		$	(42,267	)	$	231,655
Other comprehensive income (loss):
Hedge activity:
Hedge fair value changes, net		—			12,974			218,202
Net hedge (gains) losses included in continuing operations		(84,877	)		(114,231	)		356,731
Income tax provision (benefit)		23,648			50,059			(213,151	)
Other comprehensive income (loss)		(61,229	)		(51,198	)		361,782
Comprehensive income (loss)		584,766			(93,465	)		593,437
Comprehensive (income) loss attributable to noncontrolling interest		(23,206	)		9,424			(66,372	)
Comprehensive income (loss) attributable to common stockholders	$	561,560		$	(84,041	)	$	527,065

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

77

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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 and South Africa.

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.

Discontinued operations. During December 2010, the Company committed to a plan to divest 100 percent of the capital stock of its Tunisian subsidiaries, which own all of the Company’s oil and gas properties in Tunisia. The Company completed the sale of its Tunisian subsidiaries during February 2011 (see Note U for more information about the sale of the Tunisian subsidiaries). Accordingly, the Company has classified the assets and liabilities of its Tunisia operations as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2010, and the historic results of operations of its Tunisia operations as income from discontinued operations, net of tax in the accompanying consolidated statements of operations.

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.

During 2009, the Company recorded a $119.3 million trade receivable from the Bureau of Ocean Energy Management, Regulation, and Enforcement (the “BOEMRE”) for the recovery of excess royalties paid by the Company on qualifying deepwater leases in the Gulf of Mexico. The BOEMRE paid the Company the $119.3 million receivable and associated interest of $35.3 million during 2010. The properties that were the source of these royalty and interest recoveries were sold by the Company during 2006. Accordingly, the Company has recorded these receipts as income from discontinued operations, net of tax in the accompanying consolidated statements of operations. See Note U for additional information regarding the Company’s discontinued 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. Cash and cash equivalents include cash on hand and depository accounts held by banks.

Accounts and notes receivable. As of December 31, 2010 and 2009, the Company had accounts receivable – trade, net of allowances for bad debts, of $237.5 million and $330.7 million, respectively, and notes receivable, net of allowances for bad debts, of nil and $4.7 million as of December 31, 2010 and 2009, respectively. The Company’s accounts receivable – trade are primarily comprised of oil and gas sales receivable, joint operations receivables and other receivables for which the Company does not require collateral security. The Company’s notes receivable are primarily comprised of notes collateralized by drilling rigs and long-lived assets.

As of December 31, 2010 and 2009, the Company’s allowances for doubtful accounts totaled $3.7 million and $14.3 million, respectively. In accordance with GAAP, the Company establishes allowances for bad debts equal to the estimable portions of accounts and notes receivables for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint

78

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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,
	2010			2009
	(in thousands)
Beginning allowance for doubtful accounts balance	$	14,299		$	32,365
Amount charged (credited) to costs and expenses, net		(442	)		4,356
Other net decreases (a)		(10,183	)		(22,422	)
Ending allowance for doubtful accounts balance	$	3,674		$	14,299

(a) Includes $19.6 million of SemGroup bad debt allowance written off upon sale of claims receivable during 2009. See Note N additional information.

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, 2010 or 2009.

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, 2010 or 2009.

Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 61.9 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.

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, 2010, Sendero owned 12 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 $105.4 million and $106.8 million as of December 31, 2010 and 2009, respectively. The Company recorded net income attributable to the noncontrolling interests of $40.8 million, $9.8 million and $21.6 million for the years ended December 31, 2010, 2009 and 2008 (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

79

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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 as of December 31, 2010.

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

Inventories. Inventories were comprised of $197.0 million and $205.6 million of materials and supplies and $3.9 million and $3.2 million of commodities as of December 31, 2010 and 2009, respectively. The Company’s materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, 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, 2010 and 2009, the Company’s materials and supplies inventory was net of $3.6 million and $5.2 million, respectively, of valuation reserve allowances. As of December 31, 2010 and 2009, the Company estimated that $24.1 million and $69.6 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, 2010 and 2009. As of December 31, 2010, the Company’s inventory in Tunisia totaled $13.6 million and is classified as discontinued operations held for sale in the accompanying consolidated balance sheets.

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.

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 well 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

80

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found proved reserves 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 11 treating facilities. The Company operates two of the gas processing plants and all eleven 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, 2010, 2009 and 2008 were $34.0 million, $26.5 million and $39.4 million, respectively. Third party expenses attributable to the processing plants and treating facilities for the same respective periods were $14.3 million, $13.7 million and $14.4 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 this circumstance, 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, forecasts of future commodity prices, production timing, drilling and production costs and discount rates. 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. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of 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 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 $29.6 million since the date of the business combination. The Company reduced the carrying value of goodwill by $10.6 million and $1.3 million, respectively, during 2010 and 2009 as a charge to the gain from the sale of a portion of its United States reporting unit. The remaining $17.7 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 2010, 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.

81

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

Other property and equipment, net. Other property and equipment is recorded at cost and primarily consists of owned land and buildings, drilling rigs, well servicing rigs, fracture stimulation equipment, other well servicing equipment, transportation equipment, furniture and fixtures and leasehold improvements. At December 31, 2010 and 2009, other property and equipment was net of accumulated depreciation of $235.3 million and $203.6 million, respectively.

Other items of equipment are generally depreciated by individual components 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 properties’ 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. The Company recognizes all derivative instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through earnings. Under the provisions of GAAP, the Company may designate a derivative instrument as hedging the exposure to changes in the fair value of an asset or a liability or an identified portion thereof that is attributable to a particular risk (a “fair value hedge”) or as hedging the exposure to variability in the expected future cash flows that are attributable to a particular risk (a “cash flow hedge”). Both at the inception of a hedge and on an ongoing basis, a fair value hedge must be expected to be highly effective in achieving offsetting changes in fair value attributable to the hedged risk during the periods that a hedge is designated. Similarly, a cash flow hedge must be expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. The expectation of hedge effectiveness must be supported by matching the essential terms of the hedged asset, liability or forecasted transaction to the derivative hedge contract or by effectiveness assessments using statistical measurements.

Changes in the fair values of derivative instruments that are fair value hedges are offset against changes in the fair values of the hedged assets, liabilities, or firm commitments through earnings. Effective changes in the fair values of derivative instruments that are cash flow hedges are recognized in accumulated other comprehensive income-deferred hedge gains, net of tax (“AOCI-Hedging”) in the stockholders’ equity section of the Company’s consolidated balance sheets until such time as the hedged items are recognized in earnings. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in earnings.

Prior to December 2008, the Company had elected to designate the majority of its commodity derivative instruments as cash flow hedges. During December 2008, the Company began entering into commodity derivative contracts that were not designated as hedges. Changes in the fair values of non-hedge derivative instruments are recognized as gains or losses in the earnings of the periods in which they occur. 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 AOCI – Hedging and have been and will continue to be 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, and in the future will recognize, 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 derivative assets or net derivative liabilities, whichever the case may be, by commodity and

82

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

master netting 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 credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates are based on an independent market-quoted credit default swap rate curve for the Company’s or the counterparties’ debt plus the United States Treasury Bill yield curve as of the valuation date.

As of December 31, 2010 and 2009, the Company was not a party to any fair value hedges. See Note I for a description of the specific types of cash flow derivative transactions in which the Company participates.

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.

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.

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, 2010 or 2009. The following table presents the Company’s oil entitlement liabilities and gas entitlement assets and liabilities with their associated volumes as of December 31, 2010 and 2009:

	December 31,
	2010				2009
	Amount		Volume		Amount		Volume
	(dollars in millions)
Oil entitlement liabilities (volumes in MBbls)	$	1.2		13	$	1.6		22
Gas entitlement assets (volumes in MMcf)	$	7.6		3,015	$	7.6		2,967
Gas entitlement liabilities (volumes in MMcf)	$	1.6		439	$	3.3		781

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 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 awards settled wholly or partially in the Company’s common stock or restricted stock 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 wholly or partially 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.

83

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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.

During January 2010, the FASB issued ASU No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820).” ASU No. 2010-06 amends ASC Topic 820 to (i) require separate disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers, (ii) require separate disclosure of purchases, sales, issuances and settlements in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), (iii) clarify the level of disaggregation for fair value measurements of assets and liabilities and (iv) clarify disclosures about inputs and valuation techniques used to measure fair values for both recurring and nonrecurring fair value measurements. ASU No. 2010-06 became effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the rollforward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years. The Company adopted the provisions of ASU No. 2010-06 on January 1, 2010. The adoption of the provisions of ASU No. 2010-06 did not impact the Company’s financial position, results of operations or liquidity. See Note D for the Company’s disclosures about fair value measurements.

During February 2010, the FASB issued ASU No. 2010-09, “Subsequent Events (Topic 855).” ASU No. 2010-09 amends ASC Topic 855 to include the definition of “SEC filer” and alleviate the obligation of SEC filers to disclose the date through which subsequent events have been evaluated. ASU No. 2010-09 became effective during February 2010. See Note V for the Company’s disclosures of subsequent events.

During December 2010, the FASB issued ASU No. 2010-28, “Intangibles-Goodwill and Other (Topic 350).” 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 is effective for fiscal years beginning after December 15, 2010. The adoption of ASU No. 2010-28 is not expected to have an impact on the goodwill impairment test performed by the Company.

NOTE C.    Exploratory Well Costs

The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves or is impaired. 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, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Beginning capitalized exploratory well costs	$	127,574		$	124,014		$	130,630
Additions to exploratory well costs pending the determination of proved reserves		238,905			80,222			403,692
Reclassification due to determination of proved reserves		(160,879	)		(58,792	)		(321,436	)
Disposition of assets sold		(17,601	)		—			—
Exploratory well costs charged to exploration expense (a)		(91,806	)		(17,870	)		(88,872	)
Ending capitalized exploratory well costs	$	96,193		$	127,574		$	124,014

(a) Includes an exploratory well credit from discontinued operations of $117 thousand in 2010, and exploratory well costs from discontinued operations of $9.9 million and $14.6 million in 2009 and 2008, respectively.

84

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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, 2010, 2009 and 2008 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,
	2010		2009		2008
	(in thousands, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	70,635	$	21,634	$	54,423
More than one year		25,558		105,940		69,591
	$	96,193	$	127,574	$	124,014
Number of projects with exploratory well costs that have been suspended for a period greater than one year		3		8		4

The following table provides an aging of capitalized costs of exploration projects that have been suspended for more than one year as of December 31, 2010:

	Total		2010		2009		2008		2007			2006
	(in thousands)
Tunisia	$	25,558	$	209	$	274	$	21,145	$	(15	)		$	3,945

During December 2010, the Company committed to a plan to divest 100 percent of the capital stock of its Tunisian subsidiaries, which own all of the Company’s oil and gas operations in Tunisia. The Company completed the sale of its Tunisian subsidiaries during February 2011. See Notes B and U for additional information about the Company’s discontinued operations. The following describes the exploration projects in Tunisia that have been suspended for more than one year.

Tunisia – Cherouq. As of December 31, 2010, the Company had $17.8 million of suspended well costs recorded for the Hayatt #1 well in the Company’s Cherouq production concession area, which is operated by the Company. The Hayatt #1 well began drilling in April 2008 to test several targeted formations. Mechanical failures were encountered during the testing of the well that did not allow completion of the formation assessments. As of December 31, 2010, the Company had project personnel at appropriate levels committed to and actively participating in analyzing seismic and other data to determine the optimal plan forward for completing the well.

Tunisia – Borj El Khadra. As of December 31, 2010, the Company had $7.8 million of suspended well costs attributable to the Nahkil #1 and Abir #1 wells in the Borj El Khadra exploration permit area, which is operated by a third-party. The Nahkil #1 well encountered oil-bearing sands and the Abir #1 well encountered gas-bearing sands. As of December 31, 2010, the third-party operator and the Company had project personnel at appropriate levels committed to and actively participating in infrastructure planning and assessment of the area. During 2010, a $13.8 million 3-D seismic program was initiated.

85

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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.

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2010 and 2009 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, 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
Pioneer credit facility		—		58,382		—		58,382
Pioneer Southwest credit facility		—		77,241		—		77,241
5.875% senior notes due 2016		475,194		—		—		475,194
6.65% senior notes due 2017		516,632		—		—		516,632
6.875% senior notes due 2018		480,969		—		—		480,969
7.50% senior notes due 2020		494,145		—		—		494,145
7.20% senior notes due 2028		259,350		—		—		259,350
2.875% convertible senior notes due 2038 (a)		728,400		—		—		728,400
Total liabilities	$	2,954,690	$	263,638	$	9,556	$	3,227,884

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

86

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

	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, 2009
	(in thousands)
Assets:
Trading securities	$	251	$	84	$	—	$	335
Commodity derivatives		—		82,678		1,402		84,080
Interest rate derivatives		—		8,264		—		8,264
Deferred compensation plan assets		27,890		—		—		27,890
Notes receivable		—		—		4,727		4,727
Total assets	$	28,141	$	91,026	$	6,129	$	125,296
Liabilities:
Commodity derivatives	$	—	$	209,249	$	14,306	$	223,555
Interest rate derivatives		—		26,105		—		26,105
Pioneer credit facility		—		259,461		—		259,461
Pioneer Southwest credit facility		—		68,495		—		68,495
5.875% senior notes due 2012		6,154		—		—		6,154
5.875% senior notes due 2016		437,170		—		—		437,170
6.65% senior notes due 2017		472,546		—		—		472,546
6.875% senior notes due 2018		438,402		—		—		438,402
7.50% senior notes due 2020		449,566		—		—		449,566
7.20% senior notes due 2028		230,868		—		—		230,868
2.875% convertible senior notes due 2038 (a)		508,320		—		—		508,320
Total liabilities	$	2,543,026	$	563,310	$	14,306	$	3,120,642

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

The following tables present the changes in the fair values of the Company’s net commodity derivative assets (liabilities) and notes receivable classified as Level 3 in the fair value hierarchy for the year ended December 31, 2010:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Year Ended December 31, 2010
	NGL Swap Contracts			Notes Receivable			Total
	(in thousands)
Beginning asset (liability) balance	$	(12,904	)	$	4,727		$	(8,177	)
Total gains and losses:
Net unrealized losses included in earnings (a)		10,690			—			10,690
Net realized gains transferred to earnings (a)		(7,180	)		—			(7,180	)
Notes receivable valuation allowance recoveries included in earnings (b)		—			187			187
Settlement receipts (c)		(162	)		(4,914	)		(5,076	)
Ending liability balance	$	(9,556	)	$	—		$	(9,556	)

(a) The hedge-effective portions of realized gains and losses on commodity derivatives in AOCI— Hedging are included in oil and gas revenues, while non-hedge derivative gains and losses or ineffective portions of realized and unrealized hedge derivatives gains and losses are included in net derivative gains (losses) in the accompanying consolidated statements of operations.

(b) The valuation allowance recoveries associated with the Company’s notes receivable are included in other expense in the accompanying consolidated statements of operations.

(c) During 2010, the Company settled the notes receivable by taking possession of a drilling rig that was the collateral for the notes receivable.

87

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

The following table presents the carrying amounts and fair values of the Company’s financial instruments as of December 31, 2010 and 2009:

	December 31, 2010				December 31, 2009
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Assets:
Commodity price derivatives	$	304,434	$	304,434	$	84,080	$	84,080
Interest rate derivatives	$	18,256	$	18,256	$	8,264	$	8,264
Trading securities	$	467	$	467	$	335	$	335
Deferred compensation plan assets	$	36,162	$	36,162	$	27,890	$	27,890
Notes receivable	$	—	$	—	$	4,727	$	4,727
Liabilities:
Commodity price derivatives	$	136,867	$	136,867	$	223,555	$	223,555
Interest rate derivatives	$	704	$	704	$	26,105	$	26,105
Pioneer credit facility	$	49,000	$	58,382	$	240,000	$	259,461
Pioneer Southwest credit facility	$	81,200	$	77,241	$	67,000	$	68,495
5.875 % senior notes due 2012	$	—	$	—	$	6,168	$	6,154
5.875 % senior notes due 2016	$	396,880	$	475,194	$	389,109	$	437,170
6.65 % senior notes due 2017	$	484,045	$	516,632	$	483,914	$	472,546
6.875 % senior notes due 2018	$	449,192	$	480,969	$	449,161	$	438,402
7.50 % senior notes due 2020	$	446,433	$	494,145	$	446,172	$	449,566
7.20 % senior notes due 2028	$	249,925	$	259,350	$	249,924	$	230,868
2.875% convertible senior notes due 2038 (a)	$	444,994	$	728,400	$	429,563	$	508,320

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

Trading securities and deferred compensation plan assets. The Company’s trading securities represent securities that are both actively traded and not actively traded on major exchanges. The Company’s deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges plus unallocated contributions as of the measurement date. As of December 31, 2010, 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, 2010 and 2009 represent (i) swap contracts for $189 million and $289 million notional amount of debt, respectively, 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 and $400 million notional amount of debt, respectively, whereby the Company pays a variable LIBOR-based rate and the counterparty pays a fixed rate of interest. The net derivative asset and liability values attributable to the Company’s interest rate derivative contracts as of December 31, 2010 and 2009 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 derivative assets and liabilities represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts (which are also known as three-way collar contracts). The Company’s oil and gas swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority and NGL derivative contract asset and liability measurements represent Level 3 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 and (for certain oil derivatives that the Company was a party to as of December 31, 2009) Dated Brent oil prices. The asset and liability values attributable to the Company’s oil derivatives were determined based on (i) the contracted notional

88

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) independent active market-quoted Dated Brent price quotes, (iv) the applicable estimated 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 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.

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 and (iii) 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. As of December 31, 2009, the Company’s NGL component price inputs were obtained from independent brokers active in buying and selling NGL derivative contracts.

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.

Credit facility. The fair value of the Company’s credit facility and Pioneer Southwest’s credit facility is 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, 2010, 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.

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.

89

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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, 2010 and 2009:

	December 31,
	2010			2009
	(in thousands)
Outstanding debt principal balances:
Pioneer credit facility	$	49,000		$	240,000
Pioneer Southwest credit facility		81,200			67,000
5.875% senior notes due 2012		—			6,110
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		480,000			480,000
		2,700,185			2,883,095
Issuance discounts and premiums, net		(96,515	)		(119,819	)
Net deferred fair value hedge losses		(2,000	)		(2,265	)
Total long-term debt	$	2,601,670		$	2,761,011

Credit Facility. During April 2007, the Company entered into an Amended and Restated 5-Year Revolving Credit Agreement (the “Credit Facility”) with a syndicate of financial institutions that matures in April 2012, unless extended in accordance with the terms of the Credit Facility. The Credit Facility provides for aggregate loan commitments of $1.5 billion. As of December 31, 2010, the Company had $49.0 million of 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 $1.4 billion of unused borrowing capacity under the Credit Facility.

Effective April 29, 2009, the Company and the lenders amended the Credit Facility to provide the Company additional financial flexibility. The Credit Facility contained certain financial covenants, one of which required 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 until the Company achieves an investment grade rating by certain independent rating agencies. The amendment changed the ratio maintenance requirement to 1.5 to 1.0 through the period ending March 31, 2011, after which time the ratio reverts to 1.75 to 1.0, and further provides that the Company may include in the calculation of the present value of its oil and gas properties 75 percent of the market value of its ownership of limited partner units of Pioneer Southwest. The covenant requiring the Company to maintain a ratio of total debt to total capitalization of no more than 0.60 to 1.0 was not changed. 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 and, therefore, 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. The lenders may declare any outstanding obligations under the Credit Facility immediately due and payable upon the occurrence, and during the continuance of, an event of default. As of December 31, 2010, the Company was in compliance with all of its debt covenants.

The amendment also adjusted certain borrowing rates and commitment fees, and changed certain provisions relating to the consequences if a lender under the Credit Facility defaults in its obligations under the agreement. After taking into account the amendment, 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 JPMorgan Chase Bank 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 (“ABR Margin”), which is currently one 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 two 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,

90

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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 0.375 percent).

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, 2010, there were $81.2 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 assets to total debt of at least 1.75 to 1.0. As of December 31, 2010, Pioneer Southwest was in compliance with all of its debt covenants.

As of December 31, 2010, the borrowing capacity under the Pioneer Southwest Credit Facility was approximately $219 million. However, because of the net present value covenant, Pioneer Southwest’s borrowing capacity under the 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, further declines in commodity prices could reduce Pioneer Southwest’s borrowing capacity under the Pioneer Southwest Credit Facility. In addition, the Pioneer Southwest Credit Facility contains various covenants that limit, among other things, Pioneer Southwest’s ability to grant liens, incur additional indebtedness, engage in a merger, enter into transactions with affiliates, pay distributions or repurchase equity and sell its assets. If any default or event of default (as defined in the Pioneer Southwest Credit Facility) were to occur, the Pioneer Southwest Credit Facility would prohibit Pioneer Southwest from making distributions to unitholders. Such events of default include, among 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 2010, the commitment fee was 0.175 percent.

Senior notes. During November 2009, the Company issued $450 million of 7.50% Senior Notes due 2020 and received proceeds, net of approximately $11.4 million of offering discounts and costs, of approximately $438.6 million. The Company used the net proceeds to reduce outstanding borrowings under the Credit Facility.

Senior notes redemption. On March 15, 2010, the Company redeemed for cash all of its outstanding 5.875% senior notes due 2012 for $6.3 million, which represented the outstanding principal plus accrued and unpaid interest.

Convertible senior notes. During January 2008, the Company issued $500 million of 2.875% Convertible Senior Notes, of which $480 million remains outstanding at December 31, 2010. Effective January 1, 2009, the Company adopted the new provisions of FASB Accounting Standards Codification (“ASC”) Topic 470, the provisions of which were applied on a retrospective basis. The adoption of the new provisions of ASC Topic 470 effective January 1, 2009 decreased the carrying value of the 2.875% Convertible Senior Notes by $63.5 million, increased stockholders’ equity by $39.5 million and increased deferred tax liabilities by $24.0 million.

The Company’s 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 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

91

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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 “Maturity Date”). 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.

As of December 31, 2010, the 2.875% Convertible Senior Notes were not convertible at the option of the holders. However, if the 2.875% Convertible Senior Notes had been convertible as of December 31, 2010, the note holders would have received $480 million of cash and approximately 1.6 million shares of the Company’s common stock, which was valued at $142.3 million at December 31, 2010.

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, 2010 and 2009, the 2.875% Convertible Senior Notes had an unamortized discount of $35.0 million and $50.4 million, respectively, and a net carrying value of $445.0 million and $429.6 million, respectively. The unamortized discount is being amortized ratably through January 2013. For the years ended December 31, 2010, 2009 and 2008, the Company recorded $31.1 million, $29.9 million and 28.8 million, respectively, of interest expense relating to the 2.875% Convertible Senior Notes, which had an effective interest rate of 6.75 percent.

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.

Principal maturities. Principal maturities of long-term debt at December 31, 2010, are as follows (in thousands):

2011	$	—
2012	$	49,000
2013	$	561,200
2014	$	—
2015	$	—
Thereafter	$	2,089,985

92

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

The principal maturities during 2013 in the preceding table represent the Company’s 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 expenses. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
		2010			2009			2008
		(in thousands)
Cash payments for interest	$	155,854		$	151,246		$	155,987
Accretion/amortization of discounts or premiums on loans		23,304			21,388			20,523
Accretion of discount on derivative obligations		521			874			3,151
Accretion of discount on postretirement benefit obligations		433			657			631
Amortization of net deferred hedge losses (see Note I)		517			465			483
Amortization of capitalized loan fees		5,698			4,612			3,703
Net changes in accruals		11,999			3,762			1,227
Interest incurred		198,326			183,004			185,705
Less capitalized interest		(15,242	)		(9,651	)		(18,935	)
Total interest expense	$	183,084		$	173,353		$	166,770

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, 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
	(in thousands)
Receipt of lease operating and supervision charges in accordance with standard industry operating agreements	$	2,184	$	2,224	$	2,064
Reimbursement of general and administrative expenses	$	344	$	265	$	415

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 2010, the Company received $1.1 million of fixed payments and $1.9 million of variable payments from EFS Midstream. The Company also received $1.1 million of proceeds from the sale of an amine plant to EFS Midstream during 2010.

93

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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 $404 thousand of gathering and treating fees during 2010. 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 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 $1.9 million, $1.7 million and $1.6 million for the years ended December 31, 2010, 2009 and 2008, 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, 2010, 2009 and 2008, the Company recognized compensation expense of $13.4 million, $11.8 million and $11.4 million, respectively, as a result of Matching Contributions.

Pioneer Long-Term Incentive Plan

In May 2006, the Company’s stockholders approved a Long-Term Incentive Plan (the “LTIP”), which provides for the granting of incentive awards in the form of 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, 2010:

Approved and authorized awards	9,100,000
Awards issued after May 3, 2006	(5,754,473	)
Awards available for future grant	3,345,527

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 LTIP awards, the Series B unit awards issued by Sendero and the Pioneer Southwest Long-Term Incentive Plan (“Pioneer Southwest LTIP”) awards and for payments associated with the Company’s Employee Stock Purchase Plan (“ESPP”).

94

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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, 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
	(in thousands)
Restricted stock-equity awards (a)	$	31,712	$	31,929	$	29,907
Restricted stock-liability awards		4,900		—		—
Stock options (b)		1,522		629		(17	)
Performance unit awards		4,635		4,868		3,658
Pioneer Southwest LTIP		475		217		107
Sendero Series B units		1,020		—		—
ESPP		1,034		907		422
Total	$	45,298	$	38,550	$	34,077
Income tax benefit	$	14,019	$	11,675	$	9,779

(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 if the employee is not offered a position with the Company or if the employee decides to sever employment with the Company. 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 2010, 2009 and 2008 amounted to $4.8 million, $6.6 million and $6.3 million, respectively.

As of December 31, 2010, there was $55.0 million of unrecognized share-based compensation expense related to awards of unvested restricted stock, restricted stock units, performance units, stock options and phantom units issued under the Pioneer Southwest LTIP and Series B unit awards issued by Sendero. As of December 31, 2010, unrecognized compensation expense related to unvested share-based compensation plan awards is being recognized on a straight-line basis over the remaining vesting periods of the awards, which is a remaining weighted average period of less than three years.

Restricted stock awards. During 2010, the Company issued 741,131 restricted shares or units of the Company’s common stock as compensation to directors, officers and employees of the Company (including 229,555 shares or units representing Liability Awards). The Company’s issued shares, as reflected in the consolidated balance sheets as of December 31, 2010 do not include 825,796 of issued but unvested shares awarded under stock-based compensation plans that have voting rights.

The following table reflects the outstanding restricted stock awards as of December 31, 2010:

	Equity Awards					Liability Awards
	Number of Shares			Weighted Average  Grant- Date Fair Value		Number of Shares
Outstanding at beginning of year		2,984,981		$	25.69		—
Shares granted		511,576		$	48.32		229,555
Shares forfeited		(82,258	)	$	29.22		(13,604	)
Shares vested		(854,520	)	$	29.43		(817	)
Outstanding at end of year		2,559,779		$	28.85		215,134

The weighted average grant-date fair value of restricted stock Equity Awards awarded during 2010, 2009 and 2008 was $48.32, $15.47 and $46.98, respectively. The fair value of shares for which restrictions lapsed during 2010, 2009 and 2008 was $42.9 million, $11.7 million and $54.5 million, respectively, based on the market price on the vesting date.

95

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

As of December 31, 2010, accounts payable – due to affiliates in the accompanying consolidated balance sheet includes $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 in 2009 or 2008. The fair value of shares for which restrictions lapsed during 2010 was $54 thousand, based on the market price on the vesting date.

For the 2009-2010 director year, the Company’s non-employee directors were offered a choice to receive their annual fee retainers as (i) 100 percent in restricted stock units, (ii) 100 percent in cash or (iii) a combination of 50 percent cash and 50 percent restricted stock units. All non-employee directors also received an annual equity grant of restricted stock units. For the 2010-2011 director year, all of the Company’s non-employee directors received 100 percent of their annual fee retainers in restricted stock units.

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 7 year average dividend yield. The Company used the following weighted-average assumptions to estimate the fair value of stock options granted during 2010 and 2009 (no options were issued during 2008):

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

A summary of the Company’s stock option awards activity for the year ended December 31, 2010 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		596,033		$	18.62
Options awarded		116,120		$	47.10
Options expired and forfeited		(1,799	)	$	24.76
Options exercised		(202,815	)	$	23.65
Outstanding and expected to vest at end of year		507,539		$	23.11		3.75	$	32,337
Exercisable at end of year		30,398		$	20.36		0.50	$	2,020

The weighted average grant-date fair value of options awarded during 2010 and 2009 was $23.79 and $6.27, respectively, using the Black-Sholes option-pricing model. The intrinsic value of options exercised during 2010, 2009 and 2008 was $6.9 million, $3.1 million and $11.5 million, respectively, based on the difference between the market price at the exercise date and the option exercise price.

Performance unit awards. During 2010, the Company awarded performance units to certain of the Company’s officers under the LTIP. The number of shares of common stock to be issued is determined by comparing the Company’s total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The performance unit awards vest over a 34-month service period. The grant-date fair

96

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

values per unit of the 2010, 2009, and 2008 performance unit awards are $63.52, $15.29 and $37.01, 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 2010, 2009 and 2008:

	2010	2009	2008
Risk-free interest rate	1.36%	1.33%	2.13%
Range of volatilities	50.4% - 83.0%	47.1% - 73.0%	26.1% - 43.4%

The following table summarizes the performance unit activity for the year ended December 31, 2010:

	Number of Units (a)			Weighted Average Grant-Date Fair Value
Beginning performance unit awards		347,031		$	25.17
Units granted		74,482		$	63.52
Units vested (b)		(157,784	)	$	37.01
Ending performance unit awards		263,729		$	28.91

(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, 2010, the service period lapsed on these performance unit awards. They earned two shares for each vested award representing 315,568 aggregate shares of common stock issued in 2011.

The fair value of shares for which restrictions lapsed during 2010 and 2009 was $27.4 million and $4.8 million, respectively, based on the market price on the vesting date. No shares vested during 2008.

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 incentive awards in the form of 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, 2010:

Approved and authorized awards	3,000,000
Awards issued after May 6, 2008	(69,401	)
Awards available for future grant	2,930,599

During 2010, the General Partner awarded 8,744 restricted common units to directors of the General Partner under the Pioneer Southwest LTIP, which vest 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. During 2008, the General Partner awarded 12,630 restricted common units to directors of the General Partner under the Pioneer Southwest LTIP.

97

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

	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		17,121		$	18.45		—	$	—
Units granted		8,744		$	22.87		35,118	$	22.74
Lapse of restrictions		(13,653	)	$	18.24		—	$	—
Outstanding at end of year		12,212		$	21.84		35,118	$	22.74

The weighted average grant-date fair value of restricted common units awarded during 2010, 2009 and 2008 was $22.87, $18.26 and $19.00, respectively. The fair value of common units for which restrictions lapsed during 2010 and 2009 was $324 thousand and $145 thousand, respectively, based on the market price at the vesting date.

During 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 a total of 35,118 common units of Pioneer Southwest after a three-year vesting period. No phantom units were issued prior to 2010.

Subsidiary Issuances of Unit-Based Compensation

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

Employee Stock Purchase Plan

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

Postretirement Benefit Obligations

At December 31, 2010 and 2009, the Company had $7.4 million and $9.1 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, 2010 or 2009. Other than the Company’s retirement plan, the participants of these plans are not current employees of the Company.

At December 31, 2010, 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 $2.8 million of unfunded accumulated postretirement benefit obligations. For the years ended December 31, 2010, 2009 and 2008, the undiscounted accumulated post retirement benefit obligations were discounted at four percent, five percent and six percent to value the benefit obligations. Certain of the aforementioned plans provide for medical cost subsidies for plan participants. Annual medical cost escalation trends of nine percent were forecasted for 2011, declining annually to eight percent in 2015 and five percent in 2025 and thereafter, were employed to estimate the accumulated postretirement benefit obligations associated with the medical cost subsidies.

98

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

The following table reconciles changes in the Company’s unfunded accumulated postretirement benefit obligations during the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Beginning accumulated postretirement benefit obligations	$	9,075		$	9,612		$	10,494
Net benefit payments		(1,491	)		(1,430	)		(1,526	)
Service costs		321			228			190
Net actuarial losses (gains)		(930	)		8			(177	)
Accretion of interest		433			657			631
Ending accumulated postretirement benefit obligations	$	7,408		$	9,075		$	9,612

Estimated benefit payments and service/interest costs associated with the plans for the year ending December 31, 2011 are $889 thousand and $558 thousand, respectively.

Future postretirement benefits the Company expects to pay at December 31, 2010 are as follows (in thousands):

2011	$	889
2012	$	943
2013	$	1,000
2014	$	1,058
2015	$	1,053
Thereafter	$	2,465

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 $44.2 million.

Indemnifications. The Company has indemnified 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 actions 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.

Colorado Notice of Violation. On May 13, 2008, the Company was served with a Notice of Violation/Cease and Desist Order by the State of Colorado Department of Public Health and Environmental Water Quality Control Division. The Notice alleges violations of stormwater discharge permits in the Company’s Raton Basin and former Lay Creek operations; deficiencies in the Company’s stormwater management plans, failure to implement and maintain best management practices to protect stormwater runoff and failure to conduct inspections of the stormwater management system. On November 12, 2010, the Company entered into an administrative settlement of the enforcement action under the Colorado Water Quality Control Act pursuant to which it will pay cash fines of approximately $27,000 and fund two local environmental projects in the amount of approximately $139,000.

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

99

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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, 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. The Company does not believe that these obligations, which primarily pertain to matters of litigation, environmental contingencies, royalty obligations and income taxes, are probable of having a material impact on its liquidity, financial position or future results of operations.

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 the Company’s Tunisian subsidiaries.

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 contracted.

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, 2010, 2009 and 2008 were $29.5 million, $30.5 million and $49.6 million, respectively. Future minimum lease commitments under noncancellable operating leases at December 31, 2010 are as follows (in thousands):

2011	$	16,719
2012	$	16,015
2013	$	15,571
2014	$	14,002
2015	$	12,602
Thereafter	$	52,387

Gathering, Processing and Transportation agreements. The Company is party to contractual commitments with midstream service companies and pipeline carriers for the future gathering, processing and transportation of oil, NGL and gas production from certain of the Company’s properties located in the Raton Basin and Eagle Ford Shale area.

The Raton Basin transportation commitments averaged approximately 238 million cubic feet (“MMcf”) of gross gas volumes per day during 2010, including fuel commitments, and will average approximately 361 MMcf per day of gross gas volume during 2011, increasing to approximately 400 MMcf per day during 2012 and declining thereafter to approximately 194 MMcf per day during 2022.

In December 2009, the Company entered into a ten-year firm transportation contract that commences upon completion of a new 675-mile pipeline spanning from Opal, Wyoming to Malin, Oregon. Upon the pipeline’s completion (currently expected during the second or third quarter of 2011) and in accordance with the transportation contract, the Company is committed to transport 75,000 Mcf per day of gas for a minimum transportation fee of $0.95 per Mcf plus fuel, depending on the receipt point and other conditions. The Company has issued and outstanding a $39.0 million letter of credit in accordance with the terms of this agreement. In 2010, the Company entered additional agreements to allow Raton field production to reach the receipt point at Opal, Wyoming. The Company is committed to transport 75,000 to 100,000 Mcf per day of gas plus fuel volumes for an aggregate transportation fee of up to $0.76 per Mcf on transportation intervals from the Raton field to Opal, Wyoming.

100

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

The Raton Basin volumetric transportation commitments exceed the Company’s forecasted controlled gas production in the Raton field for certain future periods. The Company may purchase third party gas volumes to satisfy certain volumetric commitments or pay demand fees for commitment shortfalls, should they occur.

During 2010, the Company entered into contractual agreements with third parties to gather, transport, process and fractionate certain portions of the future oil, gas and NGLs produced and recovered from the Company’s Eagle Ford Shale properties. 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 after the counterparty builds the pipeline.

The Company entered into two five-year gas transportation agreements, under which it is committed to provide approximately 20,600 Mcf per day of gas throughput from Eagle Ford Shale wells beginning in mid-2011. Transportation commitments under these agreements increase to approximately 88,600 Mcf per day in 2015 before terminating in mid-2016. All but 28,300 Mcf per day of the commitments under these agreements is subject to a counterparty’s obligation to build infrastructure facilities.

The Company also entered into a ten-year contractual agreement with at third party for the transportation and processing of Eagle Ford Shale gas production and the fractionation of recovered NGLs. The firm transportation commitments under this agreement are for approximately 18,000 Mcf per day in 2011, increasing to approximately 170,000 Mcf per day in 2020; processing commitments under the agreement are for approximately 15,000 Mcf per day in 2011, increasing to approximately 139,000 Mcf per day in 2020’; and, fractionation commitments under the agreement are for approximately 1,500 Bbls per day of NGLs in 2011, increasing to approximately 15,000 Bbls per day in 2020.

The Company entered into the HGH Agreement with EFS Midstream to gather, treat and transport certain Eagle Ford Shale oil and gas production. The HGH Agreement has sequential start dates linked to commencement of Eagle Ford Shale production spanning the next 24 months and has 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. See Notes B and F for additional information about EFS Midstream and the HGH Agreement.

Future minimum gathering, processing and transportation fees under the Company’s oil, NGL and gas gathering, processing and transportation commitments at December 31, 2010 are as follows (in thousands):

2011	$	83,448
2012	$	130,488
2013	$	117,640
2014	$	121,155
2015	$	130,901
Thereafter	$	669,421

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.

101

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

Oil prices. All material physical sales contracts governing the Company’s oil production are tied directly or indirectly to NYMEX WTI or Dated Brent oil prices. The following table sets forth the volumes in Bbls outstanding as of December 31, 2010 under the Company’s oil derivative contracts and the weighted average oil prices per Bbl for those contracts:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily oil production derivatives (a):
2011 – Swap contracts
Volume (Bbl)		750		750		750		750		750
Price per Bbl	$	77.25	$	77.25	$	77.25	$	77.25	$	77.25
2011 – Collar contracts
Volume (Bbl)		2,000		2,000		2,000		2,000		2,000
Price per Bbl:
Ceiling	$	170.00	$	170.00	$	170.00	$	170.00	$	170.00
Floor	$	115.00	$	115.00	$	115.00	$	115.00	$	115.00
2011 – Collar Contracts with short puts
Volume (Bbl)		32,000		32,000		32,000		32,000		32,000
Price per Bbl:
Ceiling	$	99.33	$	99.33	$	99.33	$	99.33	$	99.33
Floor	$	73.75	$	73.75	$	73.75	$	73.75	$	73.75
Short put	$	59.31	$	59.31	$	59.31	$	59.31	$	59.31
2012 – Swap contracts
Volume (Bbl)		3,000		3,000		3,000		3,000		3,000
Price per Bbl	$	79.32	$	79.32	$	79.32	$	79.32	$	79.32
2012 – Collar contracts with short puts
Volume (Bbl)		37,000		37,000		37,000		37,000		37,000
Price per Bbl:
Ceiling	$	118.34	$	118.34	$	118.34	$	118.34	$	118.34
Floor	$	80.41	$	80.41	$	80.41	$	80.41	$	80.41
Short put	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00
2013 – Swap contracts
Volume (Bbl)		3,000		3,000		3,000		3,000		3,000
Price per Bbl	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02
2013 – Collar contracts with short puts
Volume (Bbl)		21,250		21,250		21,250		21,250		21,250
Price per Bbl:
Ceiling	$	117.38	$	117.38	$	117.38	$	117.38	$	117.38
Floor	$	80.18	$	80.18	$	80.18	$	80.18	$	80.18
Short put	$	65.18	$	65.18	$	65.18	$	65.18	$	65.18
2014 – Collar contracts with short puts
Volume (Bbl)		4,000		4,000		4,000		4,000		4,000
Price per Bbl:
Ceiling	$	120.50	$	120.50	$	120.50	$	120.50	$	120.50
Floor	$	85.00	$	85.00	$	85.00	$	85.00	$	85.00
Short put	$	70.00	$	70.00	$	70.00	$	70.00	$	70.00

(a) Subsequent to December 31, 2010, the Company entered into additional collar contracts with short puts for 8,000 Bbls per day of the Company’s 2014 production with a ceiling price of $131.99 per Bbl, a floor price of $89.38 per Bbl and a short put price of $74.38 per Bbl.

102

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

Natural gas liquids prices. All material physical sales contracts governing the Company’s NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities’ NGL product component prices. The following table sets forth the volumes in Bbls outstanding as of December 31, 2010 under the Company’s NGL derivative contracts and the weighted average NGL prices per Bbl for those contracts:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily NGL production derivatives:
2011 – Swap contracts
Volume (Bbl)		1,150		1,150		1,150		1,150		1,150
Price per Bbl	$	51.26	$	51.38	$	51.50	$	51.50	$	51.41
2011 – Collar contracts
Volume (Bbl)		2,650		2,650		2,650		2,650		2,650
Price per Bbl:
Ceiling	$	64.23	$	64.23	$	64.23	$	64.23	$	64.23
Floor	$	53.29	$	53.29	$	53.29	$	53.29	$	53.29
2012 – Swap contracts
Volume (Bbl)		750		750		750		750		750
Price per Bbl	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03

Gas prices. All material physical sales contracts governing the Company’s gas production are tied directly or indirectly to regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and reduce basis risk between NYMEX Henry Hub prices and actual index prices upon which the gas is sold. The following table sets forth the volumes in MMBtus outstanding as of December 31, 2010 under the Company’s gas derivative contracts and the weighted average gas prices per MMBtu for those contracts:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Outstanding Average
Average daily gas production derivatives:
2011 – Swap contracts
Volume (MMBtu)		117,500			117,500			117,500			117,500			117,500
Price per MMBtu	$	6.13		$	6.13		$	6.13		$	6.13		$	6.13
2011 – Collar contracts with short puts
Volume (MMBtu)		200,000			200,000			200,000			200,000			200,000
Price per MMBtu:
Ceiling	$	8.55		$	8.55		$	8.55		$	8.55		$	8.55
Floor	$	6.32		$	6.32		$	6.32		$	6.32		$	6.32
Short put	$	4.88		$	4.88		$	4.88		$	4.88		$	4.88
2011 – Basis swap contracts
Volume (MMBtu)		153,500			153,500			143,500			143,500			148,500
Price per MMBtu	$	(0.53	)	$	(0.53	)	$	(0.56	)	$	(0.56	)	$	(0.54	)
2012 – Swap contracts
Volume (MMBtu)		105,000			105,000			105,000			105,000			105,000
Price per MMBtu	$	5.82		$	5.82		$	5.82		$	5.82		$	5.82
2012 – Collar contracts
Volume (MMBtu)		65,000			65,000			65,000			65,000			65,000
Price per MMBtu:
Ceiling	$	6.60		$	6.60		$	6.60		$	6.60		$	6.60
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2012 – Collar contracts with short puts
Volume (MMBtu)		190,000			190,000			190,000			190,000			190,000
Price per MMBtu:
Ceiling	$	7.96		$	7.96		$	7.96		$	7.96		$	7.96
Floor	$	6.12		$	6.12		$	6.12		$	6.12		$	6.12
Short put	$	4.55		$	4.55		$	4.55		$	4.55		$	4.55

103

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

2012 – Basis swap contracts
Volume (MMBtu)		116,000			116,000			116,000			116,000			116,000
Price per MMBtu	$	(0.37	)	$	(0.37	)	$	(0.37	)	$	(0.37	)	$	(0.37	)
2013 – Swap contracts
Volume (MMBtu)		67,500			67,500			67,500			67,500			67,500
Price per MMBtu	$	6.11		$	6.11		$	6.11		$	6.11		$	6.11
2013 – Collar contracts
Volume (MMBtu)		100,000			100,000			100,000			100,000			100,000
Price per MMBtu:
Ceiling	$	6.50		$	6.50		$	6.50		$	6.50		$	6.50
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2013 – Collar contracts with short puts
Volume (MMBtu)		45,000			45,000			45,000			45,000			45,000
Price per MMBtu:
Ceiling	$	7.49		$	7.49		$	7.49		$	7.49		$	7.49
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50
2013 – Basis swap contracts
Volume (MMBtu)		32,500			32,500			32,500			32,500			32,500
Price per MMBtu	$	(0.34	)	$	(0.34	)	$	(0.34	)	$	(0.34	)	$	(0.34	)
2014 – Swap contracts
Volume (MMBtu)		50,000			50,000			50,000			50,000			50,000
Price per MMBtu	$	6.05		$	6.05		$	6.05		$	6.05		$	6.05
2014 – Collar contracts
Volume (MMBtu)		40,000			40,000			40,000			40,000			40,000
Price per MMBtu:
Ceiling	$	6.73		$	6.73		$	6.73		$	6.73		$	6.73
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2014 – Collar contracts with short puts
Volume (MMBtu)		50,000			50,000			50,000			50,000			50,000
Price per MMBtu:
Ceiling	$	8.08		$	8.08		$	8.08		$	8.08		$	8.08
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50
2014 – Basis swap contracts
Volume (MMBtu)		10,000			10,000			10,000			10,000			10,000
Price per MMBtu	$	(0.16	)	$	(0.16	)	$	(0.16	)	$	(0.16	)	$	(0.16	)

Interest rates. The following table sets forth as of December 31, 2010 the notional amount of the Company’s debt subject to outstanding variable-for-fixed and fixed-for-variable interest rate swap contracts, the weighted average fixed annual interest rate and the termination dates for those contracts:

Type	Notional Amount		Weighted Average  Fixed Interest Rate		Termination Date
	(in thousands)
Variable-for-fixed	$	189,000		3.0 percent		February 2011
Fixed-for-variable	$	400,000		2.87 percent		July 2016
Fixed-for-variable	$	70,000		3.23 percent		March 2017

Tabular disclosure of derivative fair value. All of the Company’s derivatives are accounted for as non-hedge derivatives as of December 31, 2010 and 2009, except for $17.9 million of net obligations on terminated hedges as of December 31, 2009. The following tables provide disclosure of the Company’s derivative instruments:

104

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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)						(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
Total derivatives			$	347,802			$	162,683
Fair Value of Derivative Instruments as of December 31, 2009
	Asset Derivatives (a)				Liability Derivatives (a)
Type	Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
	(in thousands)						(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives		Derivatives - current	$	66,442		Derivatives - current	$	120,112
Interest rate derivatives		Derivatives - current		9,450		Derivatives - current		5,169
Commodity price derivatives		Derivatives - noncurrent		48,341		Derivatives - noncurrent		116,233
Interest rate derivatives		Derivatives - noncurrent		2,192		Derivatives - noncurrent		24,314
Total derivatives not designated as hedging instruments				126,425				265,828
Derivatives designated as hedging instruments
Commodity price derivatives (b)		Derivatives - current		—		Derivatives - current		17,913
Total derivatives designated as hedging instruments				—				17,913
Total derivatives			$	126,425			$	283,741

(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.

(b) Represent derivative obligations under terminated hedge arrangements.

		Amount of Gain/(Loss) Recognized in AOCI on Effective Portion
		Year Ended December 31,
Derivatives in Cash Flow Hedging Relationships		2010			2009			2008
		(in thousands)
Interest rate derivatives		$	—		$	(433	)	$	(10,405	)
Commodity price derivatives			—			13,407			228,607
Total		$	—		$	12,974		$	218,202
Derivatives in Cash Flow Hedging Relationships	Location of Gain/(Loss)	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
	Reclassified from AOCI	Year Ended December 31,
	into Earnings	2010			2009			2008
		(in thousands)
Interest rate derivatives	Interest expense	$	(1,698	)	$	(6,835	)	$	(1,168	)
Interest rate derivatives	Derivative gains (losses), net		(2,465	)		—			—
Commodity price derivatives	Oil and gas revenue		89,040			121,066			(355,563	)
Total		$	84,877		$	114,231		$	(356,731	)

105

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

	Location of Loss	Amount of Loss Recognized in Earnings on Ineffective Portion
	Recognized in Earnings on	Year Ended December 31,
Derivatives in Cash Flow Hedging Relationships	Ineffective Portion	2010		2009			2008
		(in thousands)
Commodity price derivatives	Derivative gains (losses), net	$	—	$	—		$	(499	)
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	Amount of Gain (Loss) Recognized in Earnings on Derivatives
	Recognized in Earnings on	Year Ended December 31,
	Derivatives	2010		2009			2008
		(in thousands)
Interest rate derivatives	Derivative gains (losses), net	$	36,597	$	(15,423	)	$	—
Commodity price derivatives	Derivative gains (losses), net		414,302		(180,134	)		(9,649	)
Total		$	450,899	$	(195,557	)	$	(9,649	)

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, 2010 and 2009, and are being transferred to oil and gas revenue (for deferred commodity hedge gains and 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 MTM 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, 2010 and 2009, AOCI - Hedging represented net deferred gains of $7.4 million and $51.0 million, respectively. The AOCI - Hedging balance as of December 31, 2010 was comprised of $29.8 million of net deferred gains on the effective portions of discontinued commodity hedges, $2.0 million of net deferred losses on the effective portions of discontinued interest rate hedges and $6.7 million of associated net deferred tax provisions, reduced by $13.7 million of AOCI – Hedging net deferred gains attributable to and classified as noncontrolling interests in consolidated subsidiaries.

During the 12 months ending December 31, 2011, the Company expects to reclassify $32.9 million of AOCI – Hedging net deferred gains to oil revenues (including $13.9 million related to noncontrolling interests) and $282 thousand of AOCI – Hedging net deferred losses to interest expense. The Company also expects to reclassify $11.7 million of net deferred income tax provisions associated with hedge derivatives during the 12 months ending December 31, 2011 from AOCI – Hedging to income tax expense. During 2012, the Company expects to reclassify deferred losses on discontinued commodity hedges of $3.2 million to oil revenues. The $2.0 million of net deferred hedge losses on the effective portion of interest rate hedges will be transferred from AOCI – Hedging to interest expense ratably through April 2018.

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.

106

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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, 2010. 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,
	2010			2009			2008
Plains Marketing LP		12	%		10	%		13	%
Enterprise Products Partners L.P.		10	%		6	%		10	%

Derivative counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures. The following table provides the Company’s derivative assets and liabilities by counterparty as of December 31, 2010:

	Assets		Liabilities
	(in thousands)
JP Morgan Chase	$	72,038	$	6,199
Citibank, N.A.		61,986		4,774
BNP Paribas		43,844		4,167
Barclays Capital		39,568		8,995
Calyon Corporate and Investment Bank		34,961		3,202
Morgan Stanley		26,316		—
Deutsche Bank		13,826		14,244
Societe Generale		9,941		43,751
Toronto Dominion		6,956		1,069
Credit Suisse		5,095		4,112
Wells Fargo Bank, N.A.		3,764		34,063
J. Aron & Company		2,396		1,837
BMO Financial Group		1,999		10,689
UBS		—		469
Total	$	322,690	$	137,571

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, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Beginning asset retirement obligations	$	166,434		$	172,433		$	208,184
Liabilities assumed in acquisitions		6			—			2,237
New wells placed on production		5,218			625			8,459
Changes in estimates (a)		24,075			40,153			15,178
Liabilities reclassified to discontinued operations held for sale		(5,779	)		—			—
Disposition of wells		(30,693	)		(13,334	)		—
Liabilities settled		(17,838	)		(45,010	)		(70,325	)
Accretion of discount on continuing operations		10,433			10,599			7,717
Accretion of discount on discontinued operations		435			968			983
Ending asset retirement obligations	$	152,291		$	166,434		$	172,433

(a) The change in the 2010 estimate is primarily due to increases in abandonment cost estimates based 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 commodity prices used to calculate proved reserves at December 31, 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 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 Basin, Hugoton and West Panhandle gas fields and (ii) a $19.9 million increase in East Cameron facilities reclamation and abandonment estimates. The change in the 2008 estimate is primarily due to lower year-end prices for oil, NGL and gas being used to calculate proved reserves at December 31, 2008, which had the effect of shortening the economic life of many wells and increasing the present value of future retirement obligations.

107

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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, 2010 and December 31, 2009, the current portions of the Company’s asset retirement obligations were $19.9 million and $13.9 million, respectively.

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, 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
	(in thousands)
Alaskan Petroleum Production Tax credits and refunds (a)	$	47,652	$	94,989	$	18,636
Interest income		4,192		1,943		3,256
Other income		2,972		2,500		1,440
Insurance claim recovery		1,665		—		—
Retirement obligation revaluation		1,230		—		—
Deferred compensation plan income		1,228		1,034		2,007
Carbon dioxide revenue		1,818		—		—
Credit card rebates		975		864		1,178
Foreign currency remeasurement and exchange gains (b)		175		339		6,936
Gain on early extinguishment of debt		—		—		20,515
Legal settlements		—		—		2,495
Total interest and other income	$	61,907	$	101,669	$	56,463

(a) The Company earns Alaskan Petroleum Production Tax (“PPT”) credits on qualifying capital expenditures. The Company recognizes income from PPT credits when they are realized through cash refunds from the State of Alaska. During 2010, the Company recorded interest and other income of $7.7 million attributable to PPT overpayment refunds.

(b) The Company’s operations in South Africa periodically recognize monetary assets and liabilities in currencies other than its functional currency. Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses.

NOTE M.    Asset Divestitures

During the years ended December 31, 2010, 2009 and 2008, the Company completed asset divestitures for net proceeds of $313.8 million, $51.6 million and $292.9 million, respectively. Associated therewith, the Company recorded gains on disposition of assets in continuing operations of $19.1 million, during the year ended December 31, 2010, and losses on disposition of assets in continuing operations of $774 thousand and $381 thousand during the years ended December 31, 2009 and 2008, respectively. The Company recorded gains from the disposition of discontinued operations of $17.5 million during 2009 and losses from the disposition of discontinued operations of $392 thousand during 2008. The following describes the significant divestitures:

108

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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. 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 of certain asset retirement obligations, resulting in a pretax gain of $17.3 million.

Other Assets. During 2010, the Company also sold unproved leaseholds, inventory and other property and equipment and recorded a pretax net loss of $4.2 million.

Mississippi and Gulf of Mexico Shelf. During June and August 2009, the Company sold its oil and gas properties in Mississippi and substantially all of its shelf properties in the Gulf of Mexico, respectively. In accordance with GAAP, the Company classified the results of operations of the Mississippi and shelf properties in the Gulf of Mexico as discontinued in its accompanying consolidated statements of operations for 2009.

Tunisian Cherouq Concession. During 2007, Enterprise Tunisiene d’Activities Petrolieres (“ETAP”) exercised its right to participate with the Company as a 50 percent owner in the Company-operated Cherouq Concession. Associated therewith, ETAP became obligated to compensate the Company for $74.5 million of past Cherouq Concession costs, subject to ETAP’s audit. During 2010 and 2009, ETAP paid the Company $23.7 million and $27.2 million, respectively, of the Cherouq Concession past costs. This cash receipt is classified as proceeds from disposition of assets in the accompanying consolidated statement of cash flows for the years ended December 31, 2010 and 2009.

Derivative asset divestitures. During 2008, the Company terminated derivative assets prior to their contractual maturity dates. The accompanying consolidated statement of cash flows for the year ended December 31, 2008 includes $155.0 million of proceeds from disposition of assets attributable to these derivative terminations. See Note I for additional information regarding the Company’s derivative activities.

NOTE N.    Other Expense

The following table provides the components of the Company’s other expense during the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009		2008
	(in thousands)
Excess and terminated rig related costs (a)	$	37,516		$	54,223	$	54,539
Well servicing operations (b)		13,065			12,437		3,289
Inventory impairment (c)		10,729			2,275		—
Other		6,061			5,130		1,715
Contingency and environmental accrual adjustments		5,581			7,796		12,449
Severance and ad valorem tax audit adjustments		2,931			—		5,730
Foreign currency remeasurement and exchange losses (d)		2,283			4,970		27
Cancelled wells		1,591			2,047		3,213
Transportation commitment charge (e)		1,589			6,839		—
Equity interest in losses of unconsolidated affiliate		819			—		—
Bad debt expense (f)		(442	)		4,356		30,119
Rig impairment		—			—		3,382
Total other expense	$	81,723		$	100,073	$	114,463

(a) Represents above market drilling rig costs, idle rig costs and costs incurred to terminate contractual drilling rig commitments prior to their contractual maturities.

(b) Represents idle well servicing costs.

(c) Represents impairment charges to reduce the carrying value of excess lease and well equipment and supplies inventories to their estimated net realizable values.

109

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

(d) The Company’s operations in Africa periodically recognize monetary assets and liabilities in currencies other than their functional currencies. Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses.

(e) Primarily represents firm transportation contract deficiency payment obligations.

(f) The change in 2008 includes a $19.6 million bad debt allowance attributable to $29.6 million of SemGroup, L.P. receivables. The Company recovered the remaining $10.0 million of SemGroup, L.P. receivables carrying value during 2009.

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 $36.6 million (net of tax refunds) during 2010, received tax refunds (net of tax payments) during 2009 of $42.6 million and made current and estimated tax payments (net of tax refunds) of $70.3 million during 2008. These payments and net refunds include tax payments related to Tunisian operations of $17.8 million during 2010, $10.6 million during 2009 and $69.8 million during 2008. 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. As of December 31, 2010 and 2009, the Company’s valuation allowances were $33.1 million and $44.2 million, respectively. These allowances include $26.5 million for 2010 (classified as discontinued operations held for sale) and $40.5 million for 2009 related to Tunisian operations.

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, 2010, 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 2005. The Internal Revenue Service is concluding an examination of the 2007 and 2008 tax years. As of December 31, 2010, 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	2006
Various U.S. states	2005
Tunisia	2005
South Africa	2005

110

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

The Company’s income tax (provision) benefit and amounts separately allocated were attributable to the following items for the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Income from continuing operations	$	(272,317	)	$	88,246		$	(113,916	)
Income from discontinued operations		2,960			(90,578	)		(84,985	)
Changes in goodwill – tax benefits related to stock-based compensation		453			124			307
Changes in stockholders’ equity:
Net deferred hedge gains (losses)		23,648			50,059			(213,151	)
Tax benefits related to stock-based compensation		(153	)		1			367

The Company’s income tax (provision) benefit attributable to income from continuing operations consisted of the following for the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Current:
U.S. federal	$	—		$	21,714		$	19,954
U.S. state		(9,863	)		(10,010	)		(665	)
Foreign		(14,308	)		729			(1,990	)
		(24,171	)		12,433			17,299
Deferred:
U.S. federal		(263,554	)		64,046			(118,909	)
U.S. state		3,300			8,072			(423	)
Foreign		12,108			3,695			(11,883	)
		(248,146	)		75,813			(131,215	)
Income tax (provision) benefit	$	(272,317	)	$	88,246		$	(113,916	)

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, 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009			2008
	(in thousands)
U.S. federal	$	741,817	$	(234,175	)	$	227,442
Foreign		5,879		(23,093	)		51,720
	$	747,696	$	(257,268	)	$	279,162

111

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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, 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
	(in percentages)
U.S. federal statutory tax rate		35.0		35.0		35.0
State income taxes (net of federal benefit)		0.5		(0.4)		0.4
U.S. tax on foreign income inclusions and distributions		0.1		1.8		5.3
Other		0.7		(1.9)		(0.6)
Consolidated effective tax rate		36.3		34.5		40.1

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows as of December 31, 2010 and 2009:

	December 31,
	2010			2009
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	—		$	136,676
Foreign tax credit carryforward		174,054			—
Asset retirement obligations		50,886			55,553
Net deferred hedge losses		—			50,870
Other		78,014			45,520
Total deferred tax assets		302,954			288,619
Valuation allowances		(6,632	)		(44,210	)
Net deferred tax assets		296,322			244,409
Deferred tax liabilities:
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes		(1,695,336	)		(1,525,359	)
State taxes and other		(144,558	)		(162,833	)
Net deferred hedge gains		(52,232	)		—
Total deferred tax liabilities		(1,892,126	)		(1,688,192	)
Net deferred tax liability	$	(1,595,804	)	$	(1,443,783	)

During 2010, the Company utilized all available NOLs in the United States and South Africa. At December 31, 2010, the Company has $174.1 million of foreign tax credit carryforwards, which are available to offset future U.S. regular taxable income, if any. These carryforwards expire in 2015; however, as a result of the sale of the Company’s Tunisian subsidiaries during February 2011, the Company expects to realize substantially 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 is net of $12.2 million of unrealized excess tax benefits from stock based compensation.

112

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

The Company’s income tax (provision) benefit attributable to income from discontinued operations consisted of the following for the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Current:
U.S. federal	$	—		$	—		$	—
U.S. state		(538	)		(1,300	)		—
Foreign		(10,641	)		(20,037	)		(66,290	)
		(11,179	)		(21,337	)		(66,290	)
Deferred:
U.S. federal		44,070			(48,581	)		2,489
U.S. state		3			—			—
Foreign		(29,934	)		(20,660	)		(21,184	)
		14,139			(69,241	)		(18,695	)
Income tax (provision) benefit	$	2,960		$	(90,578	)	$	(84,985	)

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, 2010, 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. 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, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Net income (loss) attributable to common stockholders	$	605,208		$	(52,106	)	$	210,020
Participating basic distributed earnings (a)		(13,896	)		(196	)		(2,745	)
Basic net income (loss) attributable to common stockholders		591,312			(52,302	)		207,275
Diluted adjustments to share- and unit-based earnings (a)		180			—			9
Diluted net income (loss) attributable to common stockholders	$	591,492		$	(52,302	)	$	207,284

(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

113

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually obligated to do so.

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010		2009		2008
	(in thousands)
Weighted average common shares outstanding (a):
Basic		115,062		114,176		117,462
Dilutive common stock options (b)		212		—		247
Contingently issuable—performance shares (b)		646		—		90
Convertible notes dilution (c)		410		—		148
Diluted		116,330		114,176		117,947

(a) In 2007, the Company’s Board of Directors (“Board”) approved a $750 million share repurchase program of which $355.8 million remained available for purchase as of December 31, 2010. The Company did not purchase any common stock pursuant to the program during 2010. During 2009, the Company purchased $16.2 million of common stock pursuant to the program.

(b) Diluted earnings per share were calculated using the two-class method for the years ended December 31, 2010, 2009 and 2008. 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.

(c) 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, 2010 and 2008, 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 operations in only one industry segment, that being the oil and gas exploration and production industry; however, the Company is organizationally structured along geographic operating segments or regions. The Company has reportable continuing operations in the United States and South Africa.

The following tables provide the Company’s geographic operating segment data as of and for the years ended December 31, 2010, 2009 and 2008. Geographic operating segment income tax benefits (provisions) have been determined based on statutory rates existing in the various tax jurisdictions where the Company has oil and gas producing activities. The “Headquarters” table column includes income and expenses that are not routinely included in the earnings measures internally reported to management on a geographic operating segment basis.

114

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Year Ended December 31, 2010:
Revenues and other income:
Oil and gas	$	1,718,296		$	84,961		$	—		$	1,803,257
Interest and other		—			—			61,907			61,907
Derivative gains, net		—			—			448,434			448,434
Gain (loss) on disposition of assets, net		25,289			—			(6,215	)		19,074
Hurricane activity, net		138,918						—			138,918
		1,882,503			84,961			504,126			2,471,590
Costs and expenses:
Oil and gas production		364,763			1,383			—			366,146
Production and ad valorem taxes		112,141			—			—			112,141
Depletion, depreciation and amortization		470,077			74,288			29,805			574,170
Exploration and abandonments		189,597			512			—			190,109
General and administrative		—			—			165,301			165,301
Accretion of discount on asset retirement obligations		7,945			2,488			—			10,433
Interest		—			—			183,084			183,084
Other		37,516			—			44,207			81,723
		1,182,039			78,671			422,397			1,683,107
Income from continuing operations before income taxes		700,464			6,290			81,729			788,483
Income tax provision		(259,172	)		(1,824	)		(11,321	)		(272,317	)
Income from continuing operations	$	441,292		$	4,466		$	70,408		$	516,166
Year Ended December 31, 2009:
Revenues and other income:
Oil and gas	$	1,402,437		$	57,217		$	—		$	1,459,654
Interest and other		—			—			101,669			101,669
Derivative losses, net		—			—			(195,557	)		(195,557	)
Gain (loss) on disposition of assets, net		82			—			(856	)		(774	)
Hurricane activity, net		(17,313	)		—			—			(17,313	)
		1,385,206			57,217			(94,744	)		1,347,679
Costs and expenses:
Oil and gas production		345,885			5,507			—			351,392
Production and ad valorem taxes		98,371			—			—			98,371
Depletion, depreciation and amortization		536,075			64,802			28,110			628,987
Impairment of oil and gas properties		21,091			—			—			21,091
Exploration and abandonments		79,095			623			—			79,718
General and administrative		—			—			131,524			131,524
Accretion of discount on asset retirement obligations		8,050			2,549			—			10,599
Interest		—			—			173,353			173,353
Other		54,223			—			45,850			100,073
		1,142,790			73,481			378,837			1,595,108
Income (loss) from continuing operations before income taxes		242,416			(16,264	)		(473,581	)		(247,429	)
Income tax benefit (provision)		(89,694	)		4,717			173,223			88,246
Income (loss) from continuing operations	$	152,722		$	(11,547	)	$	(300,358	)	$	(159,183	)

115

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

	United States			South Africa			Other Foreign			Headquarters			Consolidated Total
	(in thousands)
Year Ended December 31, 2008
Revenues and other income:
Oil and gas	$	1,893,360		$	118,836		$	—		$	—		$	2,012,196
Interest and other		—			—			—			56,463			56,463
Derivative losses, net		—			—			—			(10,148	)		(10,148	)
Gain (loss) on disposition of assets, net		513			—			—			(894	)		(381	)
Hurricane activity, net		(12,150	)		—			—			—			(12,150	)
		1,881,723			118,836			—			45,421			2,045,980
Costs and expenses:
Oil and gas production		363,796			39,079			—			—			402,875
Production and ad valorem taxes		164,417			—			—			—			164,417
Depletion, depreciation and amortization		418,847			27,629			—			28,132			474,608
Impairment of oil and gas properties		89,753			—			—			—			89,753
Exploration and abandonments		189,728			143			2,072			—			191,943
General and administrative		—			—			—			132,637			132,637
Accretion of discount on asset retirement obligations		5,509			2,208			—			—			7,717
Interest		—			—			—			166,770			166,770
Other		54,539			—			—			59,924			114,463
		1,286,589			69,059			2,072			387,463			1,745,183
Income (loss) from continuing operations before income taxes		595,134			49,777			(2,072	)		(342,042	)		300,797
Income tax benefit (provision)		(220,200	)		(14,435	)		—			120,719			(113,916	)
Income (loss) from continuing operations	$	374,934		$	35,342		$	(2,072	)	$	(221,323	)	$	186,881
	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Segment Assets:
United States	$	8,987,141		$	8,333,414		$	8,524,622
South Africa		134,901			179,000			241,619
Tunisia (a)		325,942			266,342			299,168
Headquarters		231,118			88,509			96,376
Total consolidated assets	$	9,679,102		$	8,867,265		$	9,161,785

(a) Tunisia assets are classified as discontinued operations held for sale within current assets in the accompanying consolidated balance sheet as of December 31, 2010 (see Notes B and U for additional information about the Company’s discontinued operations).

NOTE R.    Impairment

The Company reviews its assets for impairment, including intangible assets, oil and gas properties and other long-lived assets, whenever events or circumstances indicate that their carrying values may not be recoverable. During the years ended December 31, 2009 and 2008, the Company recognized charges for the impairment of oil and gas properties in continuing operations of $21.1 million and $89.8 million, respectively, and $14.5 million of impairment in discontinued operations during the year ended December 31, 2008.

United States impairment. During the first quarter of 2009 and the second half of 2008, declines in commodity prices provided indications that the carrying values of the Company’s oil and gas properties in the Uinta/Piceance area and Mississippi 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 and the third quarter of 2008 of $21.1 million and $89.8 million, respectively, to reduce the carrying value of the Uinta/Piceance area oil and gas properties, and $14.5 million during the fourth quarter of 2008 to reduce the carrying value of its Mississippi assets. During 2009, the Company sold its Mississippi assets and during the first half of 2010, the Company sold substantially all of its oil and gas properties in the Uinta/Piceance area. The results of operations and impairment charge attributable to the Mississippi assets are

116

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

included in discontinued operations, referred to in more detail in Note U. 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.

During the fourth quarter of 2010, declines in future gas prices indicated that the Company’s $2.4 billion carrying value of Raton Basin oil and gas properties may have been at risk for impairment. The Company tested the Raton Basin assets for impairment as of December 31, 2010 and determined that the future undiscounted cash flows attributable to the Raton Basin proved reserves exceeded the carrying value of the assets. Accordingly, the assets were not impaired. The Company will continue to assess its Raton Basin assets for impairment when impairment indicators are determined to exist.

The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves and risk-adjusted probable reserves, (ii) management’s commodity price outlook, including assumptions as to inflation of costs and expenses, (iii) the estimated discount rate that would be used by purchasers to assess the fair value of the assets and (iv) future income tax expense attributable to the net cash flows.

Goodwill assessments. The Company’s goodwill is attributable to a business combination that was completed in 2004 and is entirely attributable to United States reporting unit. The Company assesses its goodwill for impairment annually, during the third quarter using a July 1 assessment date, and whenever facts or circumstances indicate that the carrying value of its goodwill may be impaired. The Company’s assessments of goodwill during the third quarters of 2010 and 2009 indicated that it was not impaired.

The Company’s assessments of goodwill for impairment include estimates of the fair value of its United States reporting unit and comparisons of those fair value estimates with the United States reporting unit’s carrying value. The Company’s estimates of the fair value of its United States reporting unit entail estimating the fair values of the reporting unit’s assets and liabilities. The primary component of those assets and liabilities is comprised of the reporting unit’s oil and gas properties, whose estimated values were based on the estimated discounted future net cash flows expected to be recovered from the properties. The Company’s primary assumptions in preparing the estimated discounted future net cash flows expected to be recovered from the properties are based on (i) proved reserves and risk-adjusted probable reserves, (ii) management’s price outlook, including assumptions as to inflation of costs and expenses, (iii) the estimated discount rate that would be used by purchasers to assess the fair value of the assets and liabilities attributable to the United States reporting unit and (iv) future income tax expense attributable to the net cash flows.

The Company will assess its goodwill for impairment when facts and circumstances indicate that it may be impaired, but no less often than annually, and such assessments may be affected by (i) additional reserve adjustments, both positive and negative, (ii) results of drilling activities, (iii) changes in management’s outlook on commodity prices and costs and expenses, (iv) changes in the Company’s market capitalization, (v) changes in the Company’s weighted average cost of capital and (vi) changes in income taxes related to the Company’s United States reporting unit.

NOTE S.    Volumetric Production Payments

The Company’s VPPs represent limited-term overriding royalty interests in oil and gas reserves that: (i) entitle the purchaser to receive production volumes over a period of time from specific lease interests, (ii) are free and clear of all associated future production costs and capital expenditures associated with the reserves, (iii) are nonrecourse to the Company (i.e., the purchaser’s only recourse is to the reserves acquired), (iv) transfer title of the reserves to the purchaser and (v) allow 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 VPPs, (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to oil revenues over the term of each 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.

117

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

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

Deferred revenue at December 31, 2009	$	177,236
Less: 2010 amortization		(90,216	)
Deferred revenue at December 31, 2010	$	87,020

The remaining deferred revenue amounts will be recognized in oil revenues in the consolidated statements of operations as noted below, assuming the related VPP production volumes are delivered as scheduled (in thousands):

2011	$	44,951
2012		42,069
	$	87,020

NOTE T.    Insurance Claims

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 are substantially complete. The Company estimates that it will expend approximately $2.5 million during 2011 to complete the operations to reclaim and abandon the East Cameron 322 facility.

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. Since 2005, the Company has recovered from its insurance providers (i) $199.8 million attributable to reclamation and abandonment costs incurred, (ii) $18.0 million related to business interruption and property damage losses and (iii) $3.0 million of reimbursed interest costs.

NOTE U.    Discontinued Operations

During December 2010, the Company committed to a plan to sell its Tunisia subsidiaries and in February 2011 completed a sale to an unaffiliated third party of 100 percent of the Company’s share holdings in Pioneer Natural Resources Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as “Pioneer Tunisia”) for cash proceeds of $866 million, before 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 have been classified as discontinued operations herein.

The Company sold substantially all of its Mississippi assets and shelf properties in the Gulf of Mexico during June and August 2009, respectively. The Company has reflected the results of operations of these divestitures as discontinued operations, rather than as a component of continuing operations.

During the fourth quarter of 2009, the Company recorded a $119.3 million receivable from the BOEMRE for the recovery of excess royalties paid by the Company on qualifying deepwater leases in the Gulf of Mexico. During 2010, 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 during 2006. Accordingly, the income recorded during 2010 has been classified as a component of income from discontinued operations, net of tax in the accompanying consolidated statements of operations.

118

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

The following table represents the components of the Company’s discontinued operations for the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Revenues and other income:
Oil and gas	$	151,382		$	164,062		$	265,134
Interest and other (a)		44,961			119,982			3,355
Gain (loss) on disposition of assets, net (b)		36			17,491			(392	)
		196,379			301,535			268,097
Costs and expenses:
Oil and gas production		13,371			34,114			27,746
Production and ad valorem taxes		—			(27	)		204
Depletion, depreciation and amortization (b)		24,181			26,435			37,237
Impairment of oil and gas properties (c)		—			—			14,516
Exploration and abandonments (b)		15,396			18,617			43,588
General and administrative		4,728			8,987			10,011
Accretion of discount on asset retirement obligations (b)		435			968			982
Interest		—			8			46
Other		11,399			4,938			4,008
		69,510			94,040			138,338
Income from discontinued operations before income taxes		126,869			207,495			129,759
Income tax benefit (provision):
Current		(11,179	)		(21,338	)		(66,290	)
Deferred		14,139			(69,241	)		(18,695	)
Income from discontinued operations	$	129,829		$	116,916		$	44,774

(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 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 and (v) $3.8 million of Argentine value added tax contingency charge reversals recorded during 2010 on Argentine discontinued operations sold during 2006.

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

(c) During 2008, the Company recognized $14.5 million of impairment to reduce the carrying value of its Mississippi assets that were sold during 2009. See Note R for additional information regarding impairment of oil and gas properties and other assets.

119

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

As of December 31, 2010, the carrying values of the Company’s Tunisia operations were included in discontinued operations held for sale in the accompanying consolidated balance sheet and are comprised of the following (in thousands):

Composition of assets included in discontinued operations held for sale:
Current assets	$	43,500
Property, plant and equipment		184,357
Deferred tax assets		14,731
Other assets, net		39,153
Total assets	$	281,741
Composition of liabilities included in discontinued operations held for sale:
Current liabilities	$	30,148
Deferred tax liabilities		72,663
Other liabilities		5,781
Total liabilities	$	108,592

NOTE V. Subsequent Events

On February 17, 2011, the Board declared a cash dividend of $.04 per common share. The dividend is payable April 14, 2011 to stockholders of record at the close of business on March 31, 2011.

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

120

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2010, 2009 and 2008

Capitalized Costs

	December 31,
	2010 (a)			2009
	(in thousands)
Oil and gas properties:
Proved	$	11,003,805		$	10,276,244
Unproved		191,112			236,660
Capitalized costs for oil and gas properties		11,194,917			10,512,904
Less accumulated depletion, depreciation and amortization		(3,447,740	)		(2,946,048	)
Net capitalized costs for oil and gas properties	$	7,747,177		$	7,566,856

(a) Includes $264.7 million of proved property and $81.3 million of accumulated depletion, depreciation and amortization related to 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, 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
Year Ended December 31, 2008:
United States	$	87,482	$	50,126	$	322,086	$	860,754		$	1,320,448
South Africa		—		—		145		7,062			7,207
Tunisia		—		—		104,343		28,902			133,245
Total	$	87,482	$	50,126	$	426,574	$	896,718		$	1,460,900

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

	Year Ended December 31,
	2010		2009		2008
	(in thousands)
Proved property acquisition costs	$	6	$	—	$	2,237
Exploration costs		6,820		1,068		749
Development costs		14,369		19,859		22,515
Total	$	21,195	$	20,927	$	25,501

Information about the Company’s results of operations for oil and gas producing activities by geographic operating segment is presented in Note Q of the accompanying notes to consolidated financial statements.

121

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2010, 2009 and 2008

Reserve Quantity Information

The estimates of the Company’s proved reserves as of December 31, 2010, 2009, and 2008, 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 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 2009, the SEC issued 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 the 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:

• 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 the 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 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, 2010, 2009 and 2008 utilized respective oil prices of $77.16, $59.49 and $43.00 per Bbl (reflecting adjustments for oil quality), respective NGL prices of $37.82, $28.41 and $20.07 per Bbl, and respective gas prices of $4.07, $3.19 and $4.63 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, 2010, 2009 and 2008, 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 thousands of barrels of oil equivalent (“MBOE”).

122

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2010, 2009 and 2008

	Year Ended December 31,
	2010												2009												2008
	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		315,593			156,834			2,450,131			880,781			294,357			154,535			2,917,029			935,063			291,381			159,710			2,903,055			934,933
Revisions of previous estimates		12,897			19,291			188,109			63,540			21,910			8,263			(335,006	)		(25,660	)		(8,577	)		(6,077	)		(92,794	)		(30,120	)
Purchases of minerals-in-place		1,944			555			3,364			3,060			—			—			—			—			2,425			2,045			58,758			14,263
Extensions and discoveries		31,428			15,669			155,448			73,005			10,413			1,229			18,865			14,785			17,196			5,841			202,284			56,751
Improved recovery		9,716			—			—			9,716			—			—			—			—			—			—			—			—
Production (b)		(10,297	)		(7,203	)		(139,658	)		(40,777	)		(9,315	)		(7,193	)		(147,473	)		(41,088	)		(8,068	)		(6,984	)		(154,274	)		(40,764	)
Sales of minerals-in-place		(565	)		(928	)		(21,692	)		(5,108	)		(1,772	)		—			(3,284	)		(2,319	)		—			—			—			—
Balance, December 31 (c)		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
SOUTH AFRICA
Balance, January 1		217			—			25,790			4,516			471			—			38,624			6,909			757			—			40,565			7,520
Revisions of previous estimates		282			—			743			406			(117	)		—			(3,513	)		(703	)		594			—			1,804			894
Production (b)		(225	)		—			(10,862	)		(2,035	)		(137	)		—			(9,321	)		(1,690	)		(880	)		—			(3,745	)		(1,505	)
Balance, December 31		274			—			15,671			2,887			217			—			25,790			4,516			471			—			38,624			6,909
TUNISIA
Balance, January 1		9,526			—			22,880			13,339			13,587			—			24,104			17,604			17,850			—			20,794			21,314
Revisions of previous estimates		1,927			—			1,309			2,145			(1,678	)		—			(615	)		(1,780	)		(3,376	)		—			4,176			(2,679	)
Extensions and discoveries		10,707			—			—			10,707			—			—			—			—			2,026			—			—			2,026
Production (b)		(1,781	)		—			(1,040	)		(1,954	)		(2,383	)		—			(609	)		(2,485	)		(2,261	)		—			(866	)		(2,405	)
Sales of minerals-in-place		(560	)		—			—			(560	)		—			—			—			—			(652	)		—			—			(652	)
Balance, December 31		19,819			—			23,149			23,677			9,526			—			22,880			13,339			13,587			—			24,104			17,604
TOTAL
Balance, January 1		325,336			156,834			2,498,801			898,636			308,415			154,535			2,979,757			959,576			309,988			159,710			2,964,414			963,767
Revisions of previous estimates		15,106			19,291			190,161			66,091			20,115			8,263			(339,134	)		(28,143	)		(11,359	)		(6,077	)		(86,814	)		(31,905	)
Purchases of minerals-in-place		1,944			555			3,364			3,060			—			—			—			—			2,425			2,045			58,758			14,263
Extensions and discoveries		42,135			15,669			155,448			83,712			10,413			1,229			18,865			14,785			19,222			5,841			202,284			58,777
Improved recovery		9,716			—			—			9,716			—			—			—			—			—			—			—			—
Production (b)		(12,303	)		(7,203	)		(151,560	)		(44,766	)		(11,835	)		(7,193	)		(157,403	)		(45,263	)		(11,209	)		(6,984	)		(158,885	)		(44,674	)
Sales of minerals-in-place		(1,125	)		(928	)		(21,692	)		(5,668	)		(1,772	)		—			(3,284	)		(2,319	)		(652	)		—			—			(652	)
Balance, December 31		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

(a) The proved gas reserves as of December 31, 2010, 2009 and 2008 include 303,748 MMcf, 310,463 MMcf, and 360,340 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 2010, 2009 and 2008 includes approximately 17,289 MMcf, 18,027 MMcf and 18,771 MMcf of field fuel, respectively. Also, for 2010, 2009 and 2008, production includes 1,954 MBOE, 328 MBOE and 571 MBOE of production associated with discontinued operations. See Note U for additional information.

(c) As of December 31, 2010 , 2009 and 2008, the portions of the Company’s United States proved reserves attributable to noncontrolling interests in Pioneer Southwest were as follows:

123

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2010, 2009 and 2008

	Year Ended December 31,
	2010								2009								2008
	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:
Noncontrolling interest in total proved reserves		11,852		4,753		18,843		19,745		10,539		3,741		15,448		16,854		4,311		1,680		6,966		7,152

The following table provides the Company’s proved developed and proved undeveloped reserves as of January 1 and December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010									2009								2008
	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		135,568		93,015		1,671,052			507,092		119,964		91,456		1,907,719		529,373		136,571		101,501		1,976,080		567,419
South Africa		217		—		25,790			4,516		471		—		38,624		6,909		757		—		40,565		7,520
Tunisia		8,478		—		22,880			12,291		13,587		—		24,104		17,604		17,850		—		20,794		21,314
Balance, January 1		144,263		93,015		1,719,722			523,899		134,022		91,456		1,970,447		553,886		155,178		101,501		2,037,439		596,253
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, December 31		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
Proved Undeveloped Reserves (a):
United States		180,025		63,819		779,079			373,689		174,393		63,079		1,009,310		405,690		154,810		58,209		926,975		367,514
Tunisia		1,048		—		—			1,048		—		—		—		—		—		—		—		—
Balance, January 1		181,073		63,819		779,079			374,737		174,393		63,079		1,009,310		405,690		154,810		58,209		926,975		367,514
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, December 31		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

124

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2010, 2009 and 2008

(a) As of December 31, 2010, the Company has 4,727 proved undeveloped well locations (all of which are expected to be developed during the five year period ending December 31, 2015), as compared to 4,582 and 4,977 at December 31, 2009 and 2008, respectively. During 2010, the Company’s development drilling costs incurred increased by 168 percent, as compared to 2009, and the Company converted 19,158 MBOE of proved undeveloped reserves to proved developed reserves. The increase in development drilling costs during 2010 is reflective of the Company’s expansion of oil- and liquids-focused drilling expenditures during 2010. The Company significantly reduced its development drilling expenditures during 2009 in support of cost reduction initiatives implemented during the second half of 2008 and 2009 in response to significant declines in energy demand and commodity prices. The Company’s proved undeveloped well locations that have remained undeveloped for five years or more decreased by 12 percent to 1,467 as of December 31, 2010, as compared to 1,675 well locations at December 31, 2009. Of these undeveloped well locations, 85 percent are in the Spraberry field in the Permian Basin of West Texas. The significant concentration of well locations that have remained undeveloped for five years or more in the Spraberry field is reflective of the Company’s large inventory of drilling locations in the field and the aforementioned curtailment of development drilling activity during 2008 and 2009 in support of cost reduction initiatives. 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 2011 and future years.

125

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2010, 2009 and 2008

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, 2010, held constant over each derivative contract’s term, the net present value of the Company’s derivative contracts, less associated estimated income taxes and discounted at ten percent, was an asset of $490.4 million at December 31, 2010.

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.

126

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2010, 2009 and 2008

The following tables provide the standardized measure of discounted future cash flows by geographic area and in total as of December 31, 2010, 2009 and 2008, as well as a roll forward in total for each respective year:

	December 31,
	2010			2009			2008
	(in thousands)
UNITED STATES
Oil and gas producing activities:
Future cash inflows	$	44,100,276		$	29,884,670		$	27,779,303
Future production costs		(17,313,651	)		(12,527,319	)		(11,605,862	)
Future development costs		(6,663,322	)		(4,623,978	)		(4,840,604	)
Future income tax expense		(6,453,833	)		(3,468,973	)		(2,831,642	)
		13,669,470			9,264,400			8,501,195
10% annual discount factor		(8,822,857	)		(6,193,552	)		(5,530,053	)
Standardized measure of discounted future cash flows (a)	$	4,846,613		$	3,070,848		$	2,971,142
SOUTH AFRICA
Oil and gas producing activities:
Future cash inflows	$	123,215		$	147,022		$	140,031
Future production costs		(7,805	)		(11,130	)		(18,594	)
Future development costs		(42,281	)		(41,445	)		(46,516	)
Future income tax expense		(27,052	)		(21,830	)		(9,431	)
		46,077			72,617			65,490
10% annual discount factor		1,502			(712	)		(629	)
Standardized measure of discounted future cash flows	$	47,579		$	71,905		$	64,861
TUNISIA
Oil and gas producing activities:
Future cash inflows	$	1,771,661		$	750,078		$	574,417
Future production costs		(218,785	)		(193,420	)		(214,566	)
Future development costs		(64,184	)		(75,083	)		(58,335	)
Future income tax expense		(754,238	)		(213,847	)		(102,187	)
		734,454			267,728			199,329
10% annual discount factor		(216,637	)		(79,927	)		(47,945	)
Standardized measure of discounted future cash flows	$	517,817		$	187,801		$	151,384
TOTAL
Oil and gas producing activities:
Future cash inflows	$	45,995,152		$	30,781,770		$	28,493,751
Future production costs		(17,540,241	)		(12,731,869	)		(11,839,022	)
Future development costs(b)		(6,769,787	)		(4,740,506	)		(4,945,455	)
Future income tax expense		(7,235,123	)		(3,704,650	)		(2,943,260	)
		14,450,001			9,604,745			8,766,014
10% annual discount factor		(9,037,992	)		(6,274,191	)		(5,578,627	)
Standardized measure of discounted future cash flows	$	5,412,009		$	3,330,554		$	3,187,387

(a) Includes $214.2 million and $99.6 million, respectively, attributable to a 38 percent noncontrolling interest in Pioneer Southwest for 2010 and 2009 and $38.5 million attributable to a 32 percent minority interest in Pioneer Southwest in 2008.

(b) Includes $823.5 million, $453.5 million and $443.0 million of undiscounted future asset retirement expenditures estimated as of December 31, 2010, 2009 and 2008, respectively, using current estimates of future abandonment costs. See Note K for corresponding information regarding the Company’s discounted asset retirement obligations.

127

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2010, 2009 and 2008

Changes in Standardized Measure of Discounted Future Net Cash Flows

	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Oil and gas sales, net of production costs	$	(1,373,943	)	$	(1,018,798	)	$	(2,037,654	)
Net changes in prices and production costs		2,098,422			1,006,250			(9,019,111	)
Extensions, discoveries and improved recovery		1,017,597			82,431			867,528
Development costs incurred during the period		380,754			183,936			632,359
Sales of minerals-in-place		(42,043	)		(22,006	)		(64,384	)
Purchases of minerals-in-place		20,957			—			243,412
Revisions of estimated future development costs		(952,508	)		(151,029	)		(915,265	)
Revisions of previous quantity estimates		626,693			(229,369	)		(175,159	)
Accretion of discount		437,523			385,681			1,336,401
Changes in production rates, timing and other		1,415,999			281,326			(375,321	)
Change in present value of future net revenues		3,629,451			518,422			(9,507,194	)
Net change in present value of future income taxes		(1,547,996	)		(375,255	)		3,677,697
		2,081,455			143,167			(5,829,497	)
Balance, beginning of year		3,330,554			3,187,387			9,016,884
Balance, end of year	$	5,412,009		$	3,330,554		$	3,187,387

128

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2010, 2009 and 2008

Selected Quarterly Financial Results

The following table provides selected quarterly financial results for the years ended December 31, 2010 and 2009:

	Quarter
	First			Second			Third			Fourth
	(In thousands, except per share data)
Year ended December 31, 2010:
Oil and gas revenues:
As reported	$	507,796		$	462,142		$	471,372		$	471,759
Less discontinued operations		(35,751	)		(40,100	)		(33,961	)		—
Adjusted	$	472,045		$	422,042		$	437,411		$	471,759
Total revenues:
As reported	$	817,428		$	662,394		$	616,652		$	486,659
Less discontinued operations		(37,546	)		(43,411	)		(30,586	)		—
Adjusted	$	779,882		$	618,983		$	586,066		$	486,659
Total costs and expenses:
As reported	$	396,348		$	405,168		$	426,499		$	501,738
Less discontinued operations		(17,268	)		(16,243	)		(13,136	)		—
Adjusted	$	379,080		$	388,925		$	413,363		$	501,738
Net income	$	260,606		$	188,689		$	114,574		$	82,126
Net income attributable to common stockholders	$	245,254		$	167,576		$	112,036		$	80,342
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
Year ended December 31, 2009:
Oil and gas revenues:
As reported	$	373,837		$	370,692		$	409,969		$	461,472
Less discontinued operations		(34,246	)		(38,502	)		(39,097	)		(44,471	)
Adjusted	$	339,591		$	332,190		$	370,872		$	417,001
Total revenues:
As reported	$	483,870		$	273,044		$	393,035		$	354,683
Less discontinued operations		(34,869	)		(38,312	)		(39,220	)		(44,552	)
Adjusted	$	449,001		$	234,732		$	353,815		$	310,131
Total costs and expenses:
As reported	$	495,946		$	405,017		$	408,515		$	377,102
Less discontinued operations		(32,031	)		(24,063	)		(19,019	)		(16,359	)
Adjusted	$	463,915		$	380,954		$	389,496		$	360,743
Net income (loss)	$	(10,813	)	$	(87,518	)	$	1,833		$	54,230
Net income (loss) attributable to common stockholders	$	(14,606	)	$	(86,995	)	$	(7,165	)	$	56,660
Net income (loss) attributable to common stockholders per share:
Basic	$	(0.13	)	$	(0.76	)	$	(0.06	)	$	0.48
Diluted	$	(0.13	)	$	(0.76	)	$	(0.06	)	$	0.48

129

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, 2010 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, 2010, 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, 2010, 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, 2010. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

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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, 2010, 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, 2010, 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, 2010 and 2009 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, 2010, and our report dated February 25, 2010 expressed an unqualified opinion thereon.

Ernst & Young LLP

Dallas, Texas

February 25, 2011

131

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 2011 and is incorporated herein by reference.

Item 11. Executive Compensation

The information required in response to this Item will be set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held during May 2011 and is incorporated herein by reference.

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

Securities Authorized for Issuance under Equity Compensation Plans

The following table summarizes information about the Company’s equity compensation plans as of December 31, 2010:

	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)		—		—		3,345,527
Long-Term Incentive Plan		17,625	$	25.19		—
Employee Stock Purchase Plan		—		—		171,307
Predecessor plans		12,773		13.71		—
Equity compensation plans not approved by security holders		—		—		—
Total:		30,398	$	20.36		3,516,834

(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 Long-Term Incentive Plan, which provides for the issuance of up to 9.1 million awards, as was supplementally approved by the shareholders of the Company during May 2009. Awards under the 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 578,693 cumulative shares issued through December 31, 2010. 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 reflect the deduction of the maximum number of shares that could be issued pursuant to grants of performance units outstanding at December 31, 2010.

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 2011 and is incorporated herein by reference.

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

The information required in response to this Item will be set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held during May 2011 and is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

The information required in response to this Item will be set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held during May 2011 and is incorporated herein by reference.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) Listing of Financial Statements

Financial Statements

The following consolidated financial statements of the Company are included in “Item 8. Financial Statements and Supplementary Data”:

• Report of Independent Registered Public Accounting Firm

• Consolidated Balance Sheets as of December 31, 2010 and 2009

• Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008

• Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008

• Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008

• Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2010, 2009 and 2008

• 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.

133

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 * (a)	—	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.
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, dated November 17, 2006, File No. 1-13245).
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	—	Rights Agreement dated July 24, 2001, between the Company and Continental Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form 8-A, File No. 1-13245, filed with the SEC on July 24, 2001).
4.3	—	Amendment No. 1 to Rights Agreement, dated as of May 22, 2006, between the Company and Continental Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.2 to Amendment No. 1 the Company’s Registration Statement on Form 8-A/A, File No. 1-13245, filed with the SEC on May 23, 2006).
4.4	—	Certificate of Designation of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit A to Exhibit 4.1 to the Company’s Registration Statement on Form 8-A, File No. 1-13245, filed with the SEC on July 24, 2001).
4.5	—	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).
4.6	—	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).
4.7	—	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).
4.8	—	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).
4.9	—	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).
4.10	—	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).
4.11	—	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).
4.12	—	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).

134

4.13	—	Indenture dated as of March 10, 2004, among Evergreen and Wachovia Bank, National Association, as trustee, relating to Evergreen’s 5.875% Senior Subordinated Notes due 2012 (incorporated by reference to Exhibit 4.1 to Evergreen’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File No. 1-13171).
4.14	—	First Supplemental Indenture dated as of September 28, 2004, among Pioneer Evergreen Properties, LLC (as successor to Evergreen) and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on October 1, 2004).
4.15	—	Second Supplemental Indenture dated as of September 30, 2004, among Pioneer Debt Sub, LLC and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004).
4.16	—	Third Supplemental Indenture dated as of September 30, 2004, among the Company and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.15 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004).
4.17	—	Fourth Supplemental Indenture dated as of November 1, 2004, among the Company, Pioneer USA, as guarantor, and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004).
4.18	—	Fifth Supplemental Indenture dated as of September 16, 2005 among the Company, Pioneer USA, as Guarantor, and Wachovia Bank, National Association, as Trustee, with respect to the indenture identified above as Exhibit 4.13 (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 September 21, 2005).
4.19	—	Indenture dated January 22, 2008 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).
4.20	—	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).
4.21	—	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).

135

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).
10.18	—	Amended and Restated 5-Year Revolving Credit Agreement dated as of April 11, 2007 among the Company, as Borrower, JPMorgan Chase Bank, N.A. as Administrative Agent and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 1-13245).
10.19	—	First Amendment to Amended and Restated Credit Agreement dated as of November 20, 2007 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (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 January 14, 2008).
10.20	—	Second Amendment to Amended and Restated Credit Agreement dated as of January 1, 2009 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-13245).
10.21	—	Third Amendment to Amended and Restated Credit Agreement dated as of April 29, 2009 among the Company, as Borrower, JPMorgan Chase Bank, N.A., 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 May 5, 2009).
10.22	—	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).
10.23	—	Production Payment Purchase and Sale Agreement dated as of April 19, 2005 among the Company, as the Seller, and Wolfcamp Oil and Gas Trust, as the Buyer (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 April 21, 2005).
10.24 H	—	2000 Stock Incentive Plan of Evergreen (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-8, File No. 333-119355, filed with the SEC on September 29, 2004).

136

10.25 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).
10.26 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).
10.27 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).
10.28 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).
10.29 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).
10.30 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).
10.31 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).
10.32 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).
10.33 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).
10.34 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).
10.35 H	—	Fourth Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).
10.36 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).
10.37 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).
10.38 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).

137

10.39 H	—	Form of Performance Unit Award Agreement, dated February 12, 2008, 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 Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 19, 2008).
10.40	—	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, File No. 001-34032, of Pioneer Southwest Energy Partners L.P. filed with the SEC on May 9, 2008).
10.41	—	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, File No. 001-34032, of Pioneer Southwest Energy Partners L.P. filed with the SEC on May 9, 2008).
10.42	—	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).
10.43	—	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).
10.44	—	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).
10.45	—	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).
10.46	—	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).
10.47 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).
10.48 H	—	Change in Control Agreement, dated May 19, 2008, between the Company and Frank W. Hall (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-13245).
10.49 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).
10.50 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).

138

10.51 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).
10.52 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).
10.53 H	—	Form of First Amendment to Performance Unit Award Agreements, dated November 20, 2008 (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.54 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).
10.55 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).
10.56 H (a)	—	Amendment No. 2 to the Company’s Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2011.
10.57	—	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).
10.58 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).
10.59 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).
10.60 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).
10.61 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).
10.62 H	—	Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company’s 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13245).
10.63 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).
10.64 H (a)	—	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.

139

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 (b)	—	XBRL Instance Document.
101. SCH (b)	—	XBRL Taxonomy Extension Schema.
101. CAL (b)	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101. DEF (b)	—	XBRL Taxonomy Extension Definition Linkbase Document.
101. LAB (b)	—	XBRL Taxonomy Extension Label Linkbase Document.
101. PRE (b)	—	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.

140

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 25, 2011
	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 25, 2011
/s/ Richard P. Dealy Richard P. Dealy	Executive Vice President and Chief Financial Officer (principal financial officer)	February 25, 2011
/s/ Frank W. Hall Frank W. Hall	Vice President and Chief Accounting Officer (principal accounting officer)	February 25, 2011
/s/ Thomas D. Arthur Thomas D. Arthur	Director	February 25, 2011
/s/ Edison C. Buchanan Edison C. Buchanan	Director	February 25, 2011
/s/ Andrew F. Cates Andrew F. Cates	Director	February 25, 2011
/s/ R. Hartwell Gardner R. Hartwell Gardner	Director	February 25, 2011
/s/ Andrew D. Lundquist Andrew D. Lundquist	Director	February 25, 2011
/s/ Charles E. Ramsey, Jr. Charles E. Ramsey, Jr.	Director	February 25, 2011
/s/ Scott J. Reiman Scott J. Reiman	Director	February 25, 2011
/s/ Frank A. Risch Frank A. Risch	Director	February 25, 2011
/s/ Jim A. Watson Jim A. Watson	Director	February 25, 2011

141

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*(a)	—	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.
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, dated November 17, 2006, File No. 1-13245).
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	—	Rights Agreement dated July 24, 2001, between the Company and Continental Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form 8-A, File No. 1-13245, filed with the SEC on July 24, 2001).
4.3	—	Amendment No. 1 to Rights Agreement, dated as of May 22, 2006, between the Company and Continental Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.2 to Amendment No. 1 the Company’s Registration Statement on Form 8-A/A, File No. 1-13245, filed with the SEC on May 23, 2006).
4.4	—	Certificate of Designation of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit A to Exhibit 4.1 to the Company’s Registration Statement on Form 8-A, File No. 1-13245, filed with the SEC on July 24, 2001).
4.5	—	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).
4.6	—	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).
4.7	—	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).
4.8	—	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).
4.9	—	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).
4.10	—	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).
4.11	—	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).
4.12	—	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).

142

4.13	—	Indenture dated as of March 10, 2004, among Evergreen and Wachovia Bank, National Association, as trustee, relating to Evergreen’s 5.875% Senior Subordinated Notes due 2012 (incorporated by reference to Exhibit 4.1 to Evergreen’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File No. 1-13171).
4.14	—	First Supplemental Indenture dated as of September 28, 2004, among Pioneer Evergreen Properties, LLC (as successor to Evergreen) and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on October 1, 2004).
4.15	—	Second Supplemental Indenture dated as of September 30, 2004, among Pioneer Debt Sub, LLC and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004).
4.16	—	Third Supplemental Indenture dated as of September 30, 2004, among the Company and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.15 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004).
4.17	—	Fourth Supplemental Indenture dated as of November 1, 2004, among the Company, Pioneer USA, as guarantor, and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004).
4.18	—	Fifth Supplemental Indenture dated as of September 16, 2005 among the Company, Pioneer USA, as Guarantor, and Wachovia Bank, National Association, as Trustee, with respect to the indenture identified above as Exhibit 4.13 (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 September 21, 2005).
4.19	—	Indenture dated January 22, 2008 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).
4.20	—	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).
4.21	—	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).

143

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).
10.18	—	Amended and Restated 5-Year Revolving Credit Agreement dated as of April 11, 2007 among the Company, as Borrower, JPMorgan Chase Bank, N.A. as Administrative Agent and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 1-13245).
10.19	—	First Amendment to Amended and Restated Credit Agreement dated as of November 20, 2007 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (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 January 14, 2008).
10.20	—	Second Amendment to Amended and Restated Credit Agreement dated as of January 1, 2009 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-13245).
10.21	—	Third Amendment to Amended and Restated Credit Agreement dated as of April 29, 2009 among the Company, as Borrower, JPMorgan Chase Bank, N.A., 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 May 5, 2009).
10.22	—	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).
10.23	—	Production Payment Purchase and Sale Agreement dated as of April 19, 2005 among the Company, as the Seller, and Wolfcamp Oil and Gas Trust, as the Buyer (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 April 21, 2005).
10.24 H	—	2000 Stock Incentive Plan of Evergreen (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-8, File No. 333-119355, filed with the SEC on September 29, 2004).

144

10.25 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).
10.26 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).
10.27 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).
10.28 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).
10.29 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).
10.30 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).
10.31 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).
10.32 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).
10.33 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).
10.34 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).
10.35 H	—	Fourth Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).
10.36 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).
10.37 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).
10.38 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).

145

10.39 H	—	Form of Performance Unit Award Agreement, dated February 12, 2008, 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 Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 19, 2008).
10.40	—	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, File No. 001-34032, of Pioneer Southwest Energy Partners L.P. filed with the SEC on May 9, 2008).
10.41	—	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, File No. 001-34032, of Pioneer Southwest Energy Partners L.P. filed with the SEC on May 9, 2008).
10.42	—	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).
10.43	—	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).
10.44	—	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).
10.45	—	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).
10.46	—	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).
10.47 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).
10.48 H	—	Change in Control Agreement, dated May 19, 2008, between the Company and Frank W. Hall (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-13245).
10.49 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).
10.50 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).
10.51 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).

146

10.52 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).
10.53 H	—	Form of First Amendment to Performance Unit Award Agreements, dated November 20, 2008 (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.54 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).
10.55 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).
10.56 H (a)	—	Amendment No. 2 to the Company’s Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2011.
10.57	—	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).
10.58 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).
10.59 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).
10.60 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).
10.61 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).
10.62 H	—	Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company’s 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13245).
10.63 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).
10.64 H (a)	—	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.
21.1 (a)	—	Subsidiaries of the registrant.

147

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 (b)	—	XBRL Instance Document.
101. SCH (b)	—	XBRL Taxonomy Extension Schema.
101. CAL (b)	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101. DEF (b)	—	XBRL Taxonomy Extension Definition Linkbase Document.
101. LAB (b)	—	XBRL Taxonomy Extension Label Linkbase Document.
101. PRE (b)	—	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.

148

EX-2.2

Exhibit 2.2

DATED 6 JANUARY 2011

(1) Pioneer Natural Resources USA, Inc.

(2) OMV (Tunesien) Production GmbH

AGREEMENT FOR THE SALE AND PURCHASE

OF THE ENTIRE ISSUED SHARE CAPITAL OF

PIONEER NATURAL RESOURCES ANAGUID LTD.

AND

PIONEER NATURAL RESOURCES TUNISIA LTD.

CityPoint

33rd Floor

1 Ropemaker Street

London EC2Y 9UE

Tel: 44.20.7065.6000

Fax: 44.20.7065.6001

CONTENTS

CLAUSE		PAGE
1.	DEFINITIONS		3
2.	SALE OF SHARES AND CONSIDERATION		12
3.	CONDITIONS AND CONDUCT TO CLOSING		13
4.	DEPOSIT		17
5.	PRICE ADJUSTMENT		18
6.	2010 ACCOUNTS		19
7.	CLOSING		21
8.	WARRANTIES AND INDEMNIFICATION		22
9.	TAX		26
10.	PROTECTIVE COVENANTS		26
11.	INSURANCE		27
12.	EMPLOYMENT		28
13.	LEFT BLANK INTENTIONALLY		29
14.	BUYER WARRANTIES		29
15.	ANNOUNCEMENTS AND CONFIDENTIALITY		29
16.	NOTICES		30
17.	GENERAL		31
18.	WHOLE AGREEMENT		33
19.	CONSTRUCTION		33
20.	GOVERNING LAW AND JURISDICTION		35
SCHEDULE 1 INFORMATION ABOUT THE COMPANIES			36
SCHEDULE 2 BUSINESS TO BE TRANSACTED AT CLOSING			37
SCHEDULE 3 PART I SELLER WARRANTIES			39
PART II BUYER WARRANTIES			52
SCHEDULE 4 RELEVANT CLAIMS			54
SCHEDULE 5 INTERIM PERIOD			63
SCHEDULE 6 WORKING CAPITAL CALCULATION AND ADJUSTED BID AMOUNT			67
SCHEDULE 7 TAX COVENANT			70
SCHEDULE 8 INTENTIONALLY BLANK			74
SCHEDULE 9 ACCOUNTS			75
SCHEDULE 10 INTENTIONALLY BLANK			76
SCHEDULE 11 CONTENT OF THE DATA ROOM			77
SCHEDULE 12 FIRST DISCLOSURE LETTER			78
SCHEDULE 13 SERVICES AGREEMENT - KEY TERMS			82

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SCHEDULE 14 LIST OF SELLER’S / SELLER’S GROUP IP RIGHTS	85
SCHEDULE 15 LIST OF INSURANCE POLICIES TO BE MAINTAINED OR TAKEN	93
SCHEDULE 16 INTENTIONALLY BLANK	95
SCHEDULE 17 INTENTIONALLY BLANK	96
SCHEDULE 18 PRICE ALLOCATION	97
SCHEDULE 19 INTENTIONALLY BLANK	98
SCHEDULE 20 OUTSTANDING MINIMUM WORK COMMITMENTS	99
SCHEDULE 21 GUARANTEES	101

ii

THIS AGREEMENT is made on 6 January 2011

BETWEEN

(1) Pioneer Natural Resources USA, Inc., a company incorporated under the laws of Delaware, under registration number 4541779 and having its registered office at c/o The Corporation Trust Company, Corporation Trust Center, 1209 Orange Street, Wilmington, Delaware 19801, United States of America (the “Seller”);

(2) OMV (Tunesien) Production GmbH, a company incorporated under the laws of Austria under registration number 250795 t and having its registered office at Trabrennstrasse 6-8, 1020 Vienna, Austria (the “Buyer”);

RECITALS:

(A) Pioneer Natural Resources Anaguid Ltd. (“Pioneer Anaguid”) and Pioneer Natural Resources Tunisia Ltd. (“Pioneer Tunisia” and together with Pioneer Anaguid shall be hereinafter referred to as the “Companies” or each as a “Company”) are each an exempted company incorporated under the laws of the Cayman Islands. Further particulars of the Companies are set out in Schedule 1.

(B) The Seller is the owner of the entire issued share capital of each Company, which it agrees to sell to the Buyer and which the Buyer agrees to buy from the Seller on the terms and subject to the conditions set forth in this Agreement.

NOW IT IS AGREED as follows:

1. DEFINITIONS

In this Agreement, the following terms shall have the following meaning, unless the context requires otherwise:

“2010 Accounts” means the fully audited balance sheet, profit and loss account and statement of cash flows, including related notes, of each Company, on a stand alone basis, as at and for the period from 1 January 2010 until the Effective Date, which are to be prepared in accordance with paragraph 3.1(b) of Part I of Schedule 3;

“Accounts” means the unaudited balance sheet of each Company as at 30 September 2010, which is attached hereto as Schedule 9;

“Accounts Date” means 30 September 2010;

“Actual Knowledge of Buyer” means the actual knowledge (and with no duty of enquiry) of Andreas Scheed (General Manager, Buyer), Arno Dettlinger (Vice President, NW Europe, North Africa & Latin America Region, E&P International), Bernd Apelt (Commercial Manager, Buyer), Ali Muhammad (Finance Manager, Buyer), Stefan Waldner (Senior Vice President, Corporate Development & M&A), Andreas Aigner (Head of Department M&A Legal, Corporate Development & M&A), Peter Krois (Head of Exploration, North Africa & Offshore), Jan Steckhan (Advisor Petrophysics, Buyer), Christian Astl (Exploration Advisor, North Africa & Offshore), Tony Reilly (Senior Facility Engineer, Production & Projects), Andrea Iro (Head of HR Business, OMV E&P), Kazim Ali (Senior Expert Project Related HSE) and Julian Roberts (Senior Expert Planning, Assessment, Monitoring; Sustainability & HSSE);

3

“Actual Knowledge of Seller” means the actual knowledge (and with no duty of enquiry) of Ed Hance, David McManus, Ed Caamano, Tom Hagen, Tom Grau, Dave Simpson, Mark Berg, Chris Cheatwood, Richard Dealy, Timothy Dove and Ralph Watkins;

“Adjusted Bid Amount” means the Base Value, plus Working Capital based on the 2010 Accounts and calculated according to Schedule 6, as finally agreed by the Buyer and the Seller or finalised by the Expert according to Clause 6.8;

“Agreement” means this agreement together with the Schedules;

“Anaguid Exploration Permit” means:

(a) Convention for Research and Exploitation of Mineral Substances by and among Coho International Limited, ETAP and the State of Tunisia dated 8 April 1992; and

(b) Joint Venture Agreement and Annexes by and between Coho International Limited and ETAP dated 8 April 1992;

“Anaguid-Durra Application” means the application dated April 8, 2010, the CCH approval dated July 7, 2010 and the amended application dated October 25, 2010;

“Anaguid Interest” means:

(a) a thirty percent (30%) participating interest conferring all legal and beneficial rights in the Anaguid Exploration Permit and the Anaguid-Durra Application; and

(b) a sixty percent (60%) interest under the Anaguid JOA;

“Anaguid JOA” means the joint operating agreement by and among Coho Anaguid, Inc., Bligh Tunisia Inc. and Anadarko Tunisia Anaguid Company with an effective date of 1 July 1997, as amended on 2 July 2001, 10 September 2002 and 12 June 2007;

“Base Value” means US$800,000,000 (eight hundred million US Dollars) provided that where the preferential right under the Anaguid JOA is exercised and Closing hereunder involves only the acquisition by the Buyer of the entire issued share capital of Pioneer Tunisia, the Base Value shall be US$695,700,000 (six hundred and ninety five million seven hundred thousand US Dollars);

“BEK Exploration Permit” means:

(a) Convention for Research and Exploitation of Mineral Substances by and among Elf Acquitaine Tunisie, ETAP and the State of Tunisia dated 22 September 1990, as amended on 26 December 1997 and 12 March 2010; and

4

(b) Joint Venture Agreement and Annexes by and among Elf Acquitaine Tunisie, ETAP and the State of Tunisia dated 22 September 1990, as amended on 15 August 1991, 13 May 1996 (as modified on 12 December 1997 and 10 February 2004) and 1 January 2005;

“BEK-Adam Concession” means the application dated 8 April 2003, the CCH approval dated 2 May 2003 (with minor amendment dated May 21, 2003), the official gazettal dated July 1, 2003, and the adoption on 10 April 2004 of the benefits allowed by Article 2 of Decree Law No. 99-93 dated 17 August 1999;

“BEK Interest” means:

(a) a twenty percent (20%) participating interest conferring all legal and beneficial rights in the BEK Exploration Permit and the BEK-Adam Concession; and

(b) a forty percent (40%) interest under the BEK JOA;

“BEK JOA” means the joint operating agreement by and among Phillips Petroleum Company Tunisia, Lasmo Tunisia B.V. and Unions Texas Maghreb, Inc. and dated 1 September 1997, as amended 17 September 2001, 17 June 2002 and 18 June 2002;

“Best Knowledge of Seller” means the actual knowledge of Ed Hance, David McManus, Ed Caamano, Tom Hagen, Tom Grau, Dave Simpson, Mark Berg, Chris Cheatwood, Richard Dealy, Timothy Dove and Ralph Watkins and the knowledge those persons would be deemed to have had after making reasonable enquiry;

“Bid Amount” means US$865,692,063 (eight hundred and sixty five million six hundred and ninety two thousand and sixty three US Dollars) comprised of the Base Value plus the Working Capital reflected in the Accounts;

“Business Day” means a day other than a Saturday or Sunday on which banks are generally open for business in New York, United States of America, Vienna, Austria and Tunis, Tunisia (except that any references to Business Day with respect to any provision in this Agreement relating to the timing of Closing or to an obligation to pay any amounts owed hereunder shall not include Tunis, Tunisia);

“Buyer” means OMV (Tunesien) Production GmbH, a company incorporated under the laws of Austria under registration number 250795 t and having its registered office at Trabrennstrasse 6-8, 1020 Vienna, Austria;

“Buyer’s Group” means the Buyer and any other company which is or becomes a subsidiary or holding company of the Buyer or a subsidiary of such holding company;

“Cash in Lieu Agreement” means an agreement for bonus payment in lieu of a stock award between an employee of Pioneer Tunisia and Pioneer Tunisia that is entered into prior to the Closing;

“CCH” means the Comité Consultatif des Hydrocarbures (Consultative Committee of Hydrocarbons) of the Ministry in charge of Energy of Tunisia or any successor Tunisian Governmental Entity;

“Claims Notice” has the meaning given to it in paragraph 4.1 of Schedule 4;

5

“Closing” has the meaning given to it in Clause 7.1;

“Closing Date” means the date on which Closing occurs;

“Company” and “Companies” has the meaning given to it in Recital (A);

“Company Returns” has the meaning given to it in paragraph 5 of Schedule 7;

“Concessions” means the:

(a) Anaguid-Durra Application;

(b) BEK-Adam Concession; and

(c) JN-Cherouq Concession;

“Conditions” means the conditions contained in Clause 3.1;

“Confidentiality Agreement” means the confidentiality agreement between OMV Aktiengesellschaft and Pioneer Tunisia and Pioneer Anaguid dated 15 November 2010;

“Contributions” means all equity contributions made in the ordinary course of business to Pioneer Anaguid or to Pioneer Tunisia, by the members of the Seller’s Group during the period from (and inclusive of) the Effective Date to (and inclusive of) the Closing Date provided, however, that the Seller shall not be entitled to make capital contributions (i) in excess of US$5,000,000 to Pioneer Anaguid or (ii) any capital contribution to Pioneer Tunisia, without, in either case, the consent of the Buyer (which consent shall not be unreasonably withheld, conditioned or delayed) provided further, however, that the contributions made by any member of the Seller’s Group to Pioneer Tunisia pursuant to Clause 12 shall not constitute Contributions for the purposes of this definition;

“Data Room” means the documents and information listed in Schedule 11;

“de minimis claims” has the meaning given to it in paragraph 1.1(a) of Schedule 4;

“Deposit” means the sum equal to 10% of the Bid Amount;

“Deposit Advance” means the sum equal to 5% of the Bid Amount which shall be payable by the Buyer to the Seller by way of deposit at the time of signature of this Agreement and for the purposes of this definition, Bid Amount shall be calculated without regard to any exercise of the preferential right set forth in the Anaguid JOA;

“Disputed Item” has the meaning given to it in Clause 6.2;

“Dividend” means any distribution of distributable reserves by Pioneer Tunisia to the Seller on or after the Effective Date and before Closing (but shall not, for the avoidance of doubt, include any payments permitted under Schedule 5);

“Effective Date” means 00:00 local time in Tunisia on 1 January 2011;

6

“El Hamra Exploration Permit” means:

(a) Convention for Research and Exploitation of Mineral Substances by and among Eurogas International, Inc., Pioneer Tunisia, ETAP and the State of Tunisia dated 5 April 2002, as amended 13 February 2006; and

(b) Joint Venture Agreement and Annexes by and among Eurogas International Inc., Pioneer Natural Resources Tunisia Ltd and ETAP dated 5 April 2002;

“El Hamra Interest” means a fifty percent (50%) participating interest conferring all legal and beneficial rights in the El Hamra Exploration Permit;

“Employee List” has the meaning given to it in paragraph 5(a) of Part I of Schedule 3;

“Encumbrance” means any mortgage, charge (fixed or floating), pledge, lien, option, right to acquire, right of first offer, right of pre-emption, assignment by way of security or trust arrangement for the purpose of providing security or other security interest of any kind (including any retention arrangement), over-riding royalty or other restriction or limitation of a similar nature or any agreement to create any of the foregoing;

“ETAP” means the Entreprise Tunisienne d’Activités Pétrolières;

“ETAP Receivables” means costs or expenses incurred or paid by the Companies, the Companies’ predecessors in interest or any other current or former party to the Key Agreements in connection with any of the Interests prior to the Effective Date which are attributed to, or are collectable in connection with, any amounts receivable due from ETAP;

“Expert” has the meaning given to it in Clause 6.6;

“Exploration Permits” means:

(a) the Anaguid Exploration Permit;

(b) the BEK Exploration Permit;

(c) the El Hamra Exploration Permit; and

(d) the JN Exploration Permit;

“First Disclosure Letter” means the letter which is attached in Schedule 12;

“Governmental Entity” means any public international, multinational or transnational organisation or any national, state, municipal or local governmental, legislative, administrative or other person, authority, ministry, department, agency, instrumentality, office, organisation or stock exchange having jurisdiction over the Seller, the Buyer or the Companies or their respective properties or assets;

“Guarantees” means the guarantees which are listed in Schedule 21;

7

“holding company” shall have the meaning given to that term by the Companies Act 2006 of England;

“Hydrocarbon Code” means, with respect to any Interest, whichever of (a) Decree Law No. 85-9 dated 14 September 1985 or (b) Decree Law No. 99-93 dated 17 August 1999 is applicable thereto;

“Interest” means any of, and “Interests” means all of:

(a) the Anaguid Interest;

(b) the BEK Interest;

(c) the El Hamra Interest; and

(d) the JN Interest;

“Interim Period” means the period from the date of this Agreement to the Closing Date (both dates inclusive);

“JN Exploration Permit” means:

(a) Convention for Research and Exploitation of Mineral Substances by and among AGIP Tunisia B.V., ETAP and the State of Tunisia dated 16 April 1996, as amended 15 February 2007 and 22 February 2010; and

(b) Joint Venture Agreement and Annexes by and among AGIP Tunisia B.V. and ETAP dated 16 April 1996, as amended 20 June 2000;

“JN-Cherouq Concession” means the application dated 10 November 2007, the CCH approval dated 17 December 2007 and the official gazettal dated 25 April 2008;

“JN Interest” means a fifty percent (50%) participating interest conferring all legal and beneficial rights in the JN Exploration Permit and the JN-Cherouq Concession;

“JOA” means any of, and “JOAs” means all of:

(a) the Anaguid JOA; and

(b) the BEK JOA;

“Key Agreement” means any of, and “Key Agreements” means all of:

(a) the Exploration Permits;

(b) the Concessions; and

(c) the JOAs;

“Law(s)” means any law, statute, regulation, rule, ordinance, decree, principle of civil, administrative or common law, governmental or administrative instruction and any treaty.

8

“Long Stop Date” means:

(a) 28 February 2011; or

(b) such other date as may be mutually agreed in writing by the Parties;

“Losses” means losses, costs, damages, liabilities, interests, charges, expenses, fines, penalties and environmental clean up costs but Losses shall not include any internal costs of a Party;

“Material Adverse Event” means one or more events which individually or in the aggregate has an adverse effect on the Interests or on the business, operations, financial condition or assets of the Companies and which results, or is reasonably likely to result, in Losses to the Companies exceeding the Materiality Threshold; provided, however, that for the purposes of this definition, no event arising or resulting from any of the following, either alone or in combination, shall constitute or be taken into account in determining whether there has been or may be, a Material Adverse Event: (i) general changes, developments or conditions in any national, regional or world economy or in the industries in which the Companies operate or in commodity prices, (ii) financial or other market or political conditions (including any changes or instabilities in political conditions), (iii) the announcement of this Agreement and the transactions contemplated hereby, including any termination of, reduction in or similar negative impact on relationships, contractual or otherwise, with any customers, suppliers, distributors, partners or employees of the Companies due to the announcement and performance of this Agreement or the identity of the Parties, (iv) natural disasters, acts of war or terrorism, (v) the fact that the Companies failed to meet any projections, forecasts, or revenue or earnings predictions for any period, (vi) the performance of and compliance with this Agreement and the transactions contemplated hereby and any action taken or omitted to be taken by the Companies at the request or with the prior written consent of the Buyer, (vii) changes after the date hereof in any Laws or regulations or applicable accounting regulations or principles or the interpretations thereof or (viii) any adverse consequences to reserves or resource potential resulting from drilling activities (excluding, for the avoidance of doubt, any blow-out or similar adverse physical event). For the avoidance of doubt, the fact that events are excluded from the definition of Material Adverse Event is not a limitation on the Warranties or Seller’s covenants;

“Material Agreement” means:

(a) each Key Agreement;

(b) the ENI Oil Marketing Agreement dated 12 September 2003 by and among Pioneer Tunisia and ENI S.p.A. Refining and Marketing Division, as amended on 21 February 2007;

(c) the Gaz du Sud Agreement dated 8 March 2007 by and among ETAP, ENI Tunisia B.V., ENI Tunisia BEK B.V., Pioneer Tunisia and Talisman Resources (Tunisia) Limited on one hand, and la Société Tunisienne de l’Electricté et du Gaz on the other hand;

9

(d) the Adam Gas Sales Contract dated 22 February 2010 by and among ETAP, ENI Tunisia B.V., ENI Tunisia BEK B.V., Pioneer Tunisia and Talisman Resources (Tunisia) Limited on one hand, and la Société Tunisienne de l’Electricté et du Gaz on the other hand; and

(e) the Trapsa Agreement dated 1 January 2007 by and among La Compagnie des Transports par Pipe-Line au Sahara and Pioneer Tunisia;

“Materiality Threshold” means 15% of the Bid Amount;

“Notice” has the meaning given to it in Clause 16.1;

“Objection Notice” has the meaning given to it in Clause 6.4;

“Order” means any permit or licence or any judgment, injunction, order, rulings, decree or other restriction of any Governmental Entity, court or tribunal;

“Party” means any of the Seller, the Buyer and “Parties” shall mean all of them;

“Person” means any natural person, company, corporation, partnership, limited partnership, limited liability company, trust, unincorporated organization, joint venture, Governmental Entity, or other entity;

“Pioneer Anaguid” has the meaning given to it in Recital (A);

“Pioneer Services Agreement” means the transitional services agreement to be entered into between Seller and Buyer upon Closing, consistent with the principles set forth in Schedule 13;

“Pioneer Tunisia” has the meaning given to it in Recital (A);

“President” has the meaning given to it in Clause 6.6;

“Relevant Claim” means a claim by the Buyer arising in connection with a breach by the Seller of any Warranty or under or pursuant to any covenant, indemnity or other term of any Transaction Document;

“Relief” means, unless the context otherwise requires, any allowance, credit, deduction, exemption or set-off in respect of any Tax or relevant to the computation of any income, profits or gains for the purposes of any Tax, or any saving or repayment of Tax (including any interest in respect of Tax);

“Royalty” means any royalty payment to be paid to ETAP or any Tunisian Governmental Entity pursuant to the Hydrocarbons Code and/or the Concessions and relating to the Interests;

“Royalty Liability” has the meaning given to it in paragraph 1.1(b) of Schedule 7;

“Schedule” means any of the schedules attached hereto;

“Second Disclosure Letter” means the letter from the Seller to the Buyer to be delivered prior to Closing in accordance with Clause 7.6;

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“Seller” means Pioneer Natural Resources USA, Inc., a company incorporated under the laws of Delaware, under registration number 4541779 and having its registered office at c/o The Corporation Trust Company, Corporation Trust Center, 1209 Orange Street, Wilmington, Delaware 19801, United States of America;

“Seller’s Group” means the Seller and all its subsidiaries, all its holding companies and all the other subsidiaries of each of its holding companies (other than the Companies);

“Shares” means:

(a) 1,000 ordinary shares with a par value of US$1 each in the capital of Pioneer Anaguid, comprising the entire issued share capital of Pioneer Anaguid; and

(b) 1,000 ordinary shares with a par value of US$1 each in the capital of Pioneer Tunisia, comprising the entire issued share capital of Pioneer Tunisia;

“subsidiary” shall have the meaning given to that term by the Companies Act 2006 of England;

“Tax” means all forms of taxation including income, withholding, corporation, capital gains, inheritance, value added, employment, property, sales, goods, wealth, customs and other import or export duties, excise duties, stamp duties, transfer taxes, social security or other similar contributions and all charges, duties, imposts and levies of a similar nature, and any interest, penalty, surcharge or fine relating to such taxation;

“Tax and Royalty Audit Adjustments” has the meaning given to it in paragraph 6(a) of Schedule 7;

“Tax Authority” means any authority competent to impose, administer or collect any Tax;

“Tax Liability” means an obligation or liability of either Company to make or suffer an actual payment of Tax;

“Tax Warranties” shall have the meaning given to it in Clause 9.1;

“Third Party Claim” has the meaning given to it in paragraph 4.1 of Schedule 4;

“Transaction” means the sale and purchase of the Shares pursuant to this Agreement provided that where the preferential right under the Anaguid JOA is exercised and Closing hereunder involves only the acquisition by the Buyer of the entire issued share capital of Pioneer Tunisia, the Transaction shall mean the sale and purchase of the Shares in Pioneer Tunisia only;

“Transaction Documents” means this Agreement and the other documents entered into by the Parties in connection with the Transaction including the First Disclosure Letter, the Second Disclosure Letter, the Pioneer Services Agreement and the transfers of the Shares;

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“Transfer Tax” means stamp or similar taxes, fees and levies imposed by a competent authority in Tunisia with respect to the transactions contemplated by this Agreement;

“Undisclosed Known Breaches” has the meaning given to it in Clause 3.3;

“US$” or “US dollars” means US dollars, the lawful currency of the United States of America;

“Violation Claim” means any proceeding, claim, dispute, demand or assertion by a third party or Governmental Entity under the Material Agreements or Tunisian Law arising as a result of the execution or performance of this Agreement including the consummation of the transactions contemplated hereby (including any proceeding, claim, dispute, demand or assertion concerning any right of pre-emption or right of first offer, consent or approval required under the Material Agreements or Tunisian Law);

“Warranties” means the warranties of the Seller contained in Part I of Schedule 3 and “Warranty” shall be construed accordingly; and

“Working Capital” has the meaning ascribed to it in Schedule 6.

2. SALE OF SHARES AND CONSIDERATION

2.1 The Seller shall sell and the Buyer shall buy the Shares with legal effect from Closing.

2.2 The Shares shall be sold to the Buyer hereunder together with all rights attaching to them.

2.3 The consideration to be paid by the Buyer to the Seller for the purchase of the Shares shall be the Adjusted Bid Amount. At Closing, the following amount shall be paid by the Buyer to the Seller in US dollars in immediately available funds for same day value by wire transfer to the bank account of the Seller specified in a written notice delivered by the Seller to the Buyer prior to Closing:

(a) the Bid Amount or, where the 2010 Accounts have been finalized prior to the Closing in accordance with Clauses 5 and 6 and Schedule 6, the Adjusted Bid Amount; plus

(b) the amount of Contributions, in the event any Contributions are made, which amount shall be notified by the Seller to the Buyer no less than five (5) Business Days prior to Closing; minus

(c) the amount of the Deposit Advance; minus

(d) the amount of the Dividends, if any, declared and paid in accordance with Clause 5.4.

2.4 Where the 2010 Accounts have not been finalized prior to the Closing, as a separate and independent obligation in connection with the transactions contemplated herein, the Buyer shall also pay to the Seller the price adjustment, if any, in accordance with Clause 5. Upon payment of the amounts referred in Clause 2.3, all loans and inter-company payables owed by either Company to a member of the Seller’s Group shall be deemed finally settled and paid in full.

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2.5 Contemporaneously with the execution and delivery of this Agreement by the Parties:

(a) the Deposit Advance shall be paid by the Buyer to the Seller in accordance with Clause 4.1;

(b) the Seller shall provide the Buyer with a certified copy of the resolutions, dated as of or prior to the date of this Agreement, of the board of directors of the Seller which authorises the execution of, and consummation of all transactions contemplated under, each Transaction Document to which the Seller is or is to be a party; and

(c) the Buyer shall provide the Seller with a statement in English issued by the compliance officer of the Buyer’s ultimate parent company on or prior to the date of this Agreement confirming that the supervisory board of the Buyer’s ultimate parent company has authorised the execution of, and consummation of all transactions contemplated under, each Transaction Document to which the Buyer is or is to be a party.

2.6 Contributions paid or otherwise in respect of any currency other than US dollars shall, for the purposes of this Agreement, be converted into US dollars in accordance with the Seller’s normal accounting procedure applied on a consistent basis.

2.7 In the event a party to the Anaguid JOA timely exercises its pre-emption rights thereunder pursuant to the Anaguid JOA, then Closing hereunder shall involve only the acquisition of the entire issued share capital of Pioneer Tunisia by the Buyer and:

(a) the amount payable by the Buyer to the Seller contemporaneously with completion of the acquisition of the entire issued share capital of Pioneer Tunisia shall be equal to:

(i) the amount calculated and to be paid at Closing pursuant to Clause 2.3; minus

(ii) the amount allocated pursuant to paragraph 1 of Schedule 18; minus

(iii) the amount of Contributions to Pioneer Anaguid; and

(b) any and all obligations, liabilities and Warranties of the Seller and any and all obligations, liabilities and warranties of the Buyer relating to Pioneer Anaguid and the Anaguid Interest shall be null and void and all provisions relating to Closing (including Schedule 2) shall be deemed amended to refer to the transfer of Shares in Pioneer Tunisia only.

3. CONDITIONS AND CONDUCT TO CLOSING

3.1 Closing is conditional upon the following conditions being fulfilled (or waived as provided in Clauses 3.2, 3.4 and/or 3.5, as applicable) on or before the Long Stop Date:

(a) (i) each of the Warranties shall be true and correct in all respects as of the Closing as though made on and as of the Closing (except those Warranties that are made as of a specific date which need only be true as of such specific date); and

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(ii) the Seller shall have performed in all respects all obligations required to be performed by it under this Agreement at or prior to Closing,

provided that the Conditions in this Clause 3.1(a) shall nonetheless be deemed fulfilled for all purposes of this Clause 3.1(a) with respect to any failure of any such Warranty to be so true and correct in all respects and/or the failure of the Seller to have so performed in all respects any of such obligations where all such failures would not, individually or in the aggregate, be reasonably likely to result in Losses to the Buyer or the Companies in excess of the Materiality Threshold (or the equivalent thereof in any other currency);

(b) each of the warranties of the Buyer referred to in Clause 14 (except those warranties that are made as of a specific date which need only be true as of such date) shall be true and correct in all material respects as of the Closing as though made on and as of the Closing;

(c) the Buyer shall have performed in all material respects all obligations required to be performed by it under this Agreement at or prior to Closing;

(d) no Governmental Entity shall have issued an order which remains in effect as of the Closing (which is capable of being enforced) which prohibits the consummation of the transactions contemplated herein;

(e) the absence of occurrence of any Material Adverse Event; and

(f) no applicable Governmental Entity having jurisdiction over either Party shall have notified either Party in writing that merger control clearance is required, which requirement remains in effect as of the Closing, to consummate the transactions contemplated herein.

3.2 Notwithstanding anything to the contrary in this Agreement, if prior to Closing the Buyer becomes aware that there are one or more breaches of Warranties and/or any of the Seller’s covenants under this Agreement that would result in the failure of any of the Conditions in Clause 3.1(a) being satisfied, then the Buyer shall elect either to:

(a) terminate this Agreement prior to Closing by serving a written notice on the Seller prior to Closing of the Buyer’s election to terminate this Agreement in which case the Deposit Advance paid to the Seller pursuant to Clause 4.1 shall be returned to the Buyer pursuant to Clause 3.8; or

(b) waive (subject to Clause 3.3) all such breaches for all purposes of this Agreement (and the Buyer’s failure to notify the Seller prior to Closing pursuant to Clause 3.2(a) shall (subject to Clause 3.3) constitute an irrevocable election by the Buyer to waive all such breaches for all purposes) and proceed to Closing and, without in any way limiting the generality of the foregoing, the Buyer shall have no right or entitlement to seek damages or any other remedy in respect of any such breaches pursuant to this Agreement or otherwise,

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provided that the Buyer’s right to elect to terminate this Agreement pursuant to Clause 3.2(a) shall be subject to the Buyer having not intentionally or wilfully breached this Agreement in a manner that results in one of the Conditions not being satisfied and where the Buyer is then in such breach under this Agreement, the Buyer shall have no right to make an election pursuant to said Clause 3.2(a); provided further that where the aggregate Losses arising from the breaches in question do not cause any of the Conditions in Clause 3.1(a) not to be satisfied, then the Buyer shall proceed to Closing and, subject to Schedule 4, shall be entitled after Closing to bring claims for all such breaches.

3.3 Should the Closing occur pursuant to Clause 3.2(b) above and notwithstanding the waiver contained in Clause 3.2(b), the Buyer’s waiver provided under said Clause shall not apply and the Buyer shall (subject to the other terms and provisions of this Agreement, including, except as otherwise specified below, of Schedule 4) be entitled to make a Relevant Claim:

(a) (i) in respect of a breach prior to Closing of any of the Warranties or obligations set out in Clause 3.1(a), if, to the Actual Knowledge of Seller as of the execution and delivery of this Agreement, such Warranties or obligations were breached (such breaches referred to herein as “Undisclosed Known Breaches”) and provided that, if such Undisclosed Known Breaches had not occurred, the Materiality Threshold referenced in the proviso of Clause 3.1(a) would nevertheless have been exceeded by Losses relating to other breaches. In this case, the Buyer shall only be entitled to recover the Losses relating to the Undisclosed Known Breaches (the other breaches being waived in accordance with Clause 3.2(b)), and the threshold provided for under paragraph 1.1(b) of Schedule 4 shall not be applicable to Relevant Claims relating to such Losses for the Undisclosed Known Breaches;

(ii) in respect of all breaches of the Warranties or obligations set out in Clause 3.1(a) prior to Closing, if the Materiality Threshold referenced in the proviso of Clause 3.1(a) would not have been exceeded but for the existence of Undisclosed Known Breaches. In this case, the threshold provided for under paragraph 1.1(b) of Schedule 4 shall not be applicable to the Relevant Claims relating to the portion of the Losses for the Undisclosed Known Breaches.

For the avoidance of doubt, if the Materiality Threshold referenced in the proviso of Clause 3.1(a) is not exceeded by breaches of the Warranties or obligations set out in Clause 3.1(a) (including any Undisclosed Known Breaches), the threshold provided for under paragraph 1.1(b) of Schedule 4 shall be applicable to all Relevant Claims including Relevant Claims relating to the Losses for any Undisclosed Known Breaches.

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3.4 If any of the Conditions set forth in Clauses 3.1(a), (d), (e) or (f) have not been fulfilled, or otherwise waived in writing by the Buyer, in its sole discretion, on or before the Long Stop Date then this Agreement shall terminate immediately.

3.5 If any of the Conditions set forth in Clauses 3.1(b) or (c) have not been fulfilled (in so far as such non-fulfilment results in the failure by the Buyer to pay any of the amounts set forth in Clause 2) or otherwise waived in writing by the Seller, in its sole discretion, on or before the Long Stop Date then this Agreement shall terminate immediately.

3.6 Where this Agreement is terminated prior to Closing pursuant to any applicable provision of this Agreement, each Party shall be released from its obligations under this Agreement (other than Clauses 3.7, 3.8, 3.9, 4.1, 10.2, 15, 16, 17, 18, 19 and 20) without any further action of the Parties and no Party shall have any claim or liability to the other Party, other than in respect of any breach of Clauses 3.7, 3.8, 3.9, 4.1, 10.2, 15, 16, 17, 18, 19 and 20.

3.7 Notwithstanding any other provision of this Agreement, where any of the Conditions set out in Clause 3.1(b) and/or 3.1(c) (in so far as such non-fulfilment results in the failure by the Buyer to pay any of the amounts set forth in Clause 2) have not been satisfied and not waived by the Seller, at its sole discretion, prior to the Closing, the sole and exclusive remedy of the Seller shall be to retain the Deposit Advance paid to the Seller pursuant to Clause 4.1 and to be paid an additional amount from the Buyer equal to the Deposit Advance payment, which additional payment shall be made by the Buyer no later than five (5) Business Days following the date of termination of this Agreement provided that nothing in this Clause 3.7 shall constitute a limitation on the Seller’s right to recover damages or claim any other remedy for a breach by the Buyer of Clause 4.1, 10.2, 10.3 and/or 15.

3.8 Notwithstanding any other provision of this Agreement, where any of the Conditions set out in Clause 3.1(a) are not satisfied and not waived by the Buyer at its sole discretion prior to the Closing, the sole and exclusive remedy of the Buyer shall be a right to recover from the Seller the Deposit Advance paid to the Seller pursuant to Clause 4.1 and any reasonable and documented out-of-pocket expenses incurred by the Buyer in relation to this Agreement provided that where the Seller has intentionally and wilfully breached its obligation to deliver the Shares at the Closing, the Buyer shall also be entitled to an additional amount from the Seller equal to the Deposit Advance which shall be made by the Seller no later than five (5) Business Days following the date of termination of this Agreement provided further that nothing in this Clause 3.8 shall constitute a limitation on the Buyer’s right to recover damages or claim any other remedy for a breach by the Seller of Clause 15.

3.9 Notwithstanding any other provision of this Agreement, where this Agreement is terminated solely because of the failure to satisfy any of the Conditions set out in Clauses 3.1(d), (e) and/or (f), the sole and exclusive remedy of the Buyer shall be a right to recover from the Seller the Deposit Advance paid to the Seller pursuant to Clause 4.1 (which shall be paid by the Seller to the Buyer within five (5) Business Days following the date of termination of this Agreement) provided that nothing in this Clause 3.9 shall constitute a limitation on the Buyer’s right to recover damages or claim any other remedy for a breach by the Seller of Clause 15 and provided further that where this Agreement is terminated solely as a result of any aforesaid failure, the

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Seller shall be entitled to retain the Deposit Advance and recover an additional amount from Buyer equal to the Deposit Advance (which additional amount shall be paid within five (5) Business Days after the date of termination)where the Buyer is in material breach of any of its covenants under this Agreement.

3.10 The Parties shall use their best endeavours to ensure that the Conditions are fulfilled as soon as reasonably practicable and, in any event, no later than at the Long Stop Date, which shall include an obligation by Buyer and the Seller (to the extent reasonably applicable to the Seller) to use its best efforts to prevent the failure of the Conditions in Clauses 3.1(d) and 3.1(f) and to seek to have overturned or revoked any order or merger clearance notification or requirement which would result in a failure of the Conditions set out in Clauses 3.1(d) and/or 3.1(f). Compliance by a Party with its obligations set forth in this Clause 3.10, shall not deprive the other Party from claiming any remedies available to such Party pursuant to Clauses 3.7, 3.8 or 3.9, as applicable.

3.11 Prior to Closing, the Parties shall agree on a date, time and venue for meetings with any Governmental Entity of Tunisia and shall consult with each other and obtain each other’s consent (not to be unreasonably withheld, conditioned or delayed) and approval prior to commencing any correspondence or discussions with the Government of Tunisia in connection with the transactions contemplated by this Agreement. To the extent that either Party or any of their affiliates receives any correspondence (in whatever form) from the Government of Tunisia relating to the transactions contemplated by this Agreement, such receiving Party shall send a copy of such correspondence, if it is in written form, or otherwise communicate such correspondence (with a written summary to follow), if it is in oral form, to the other Party as soon as reasonably practicable after receipt of such correspondence.

3.12 If this Agreement is terminated prior to the Closing for any reason, then the amounts referred to in Clauses 3.7, 3.8, 3.9 and 4.1 are reasonable and necessary and represent a genuine pre-estimate of the Loss that the Seller or the Buyer, as the case may be, would suffer as a result of termination and such amounts are payable as liquidated damages and not as penalties.

3.13 Between the date of this Agreement and Closing, the Parties shall reasonably cooperate with each other and use commercially reasonable efforts to effect a smooth transition of the ownership and operation of the Companies and the Seller shall use reasonable efforts to ensure that all material documentation of the Companies in Seller’s possession is transferred to the Buyer within sixty (60) days after Closing provided that the Seller shall be entitled to keep copies of such material documentation for the purposes of its records provided further that no material documentation shall be removed from the office in Tunis of Pioneer Tunisia prior to Closing.

4. DEPOSIT

4.1 Upon the date of this Agreement or the next day, the Buyer shall pay to the Seller the Deposit Advance in immediately available funds in US dollars by wire transfer to the bank account of the Seller specified in writing by the Seller for value. If the Deposit Advance is not received in accordance with Clause 4.1, the Seller:

(a) shall have an action in debt for the amount of the Deposit Advance; and

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(b) may unilaterally terminate this Agreement by notice in writing to the Buyer in the event that:

(i) evidence reasonably satisfactory to the Seller from the paying bank that the Buyer has delivered irrevocable wire transfer instructions to the paying bank to initiate the transfer of the wire to the Seller (to the account nominated by the Seller) for the Deposit Advance is not received by the Seller from the Buyer within three (3) Business Days of the date of this Agreement; or

(ii) the Seller does not receive the Deposit Advance within eleven (11) Business Days of the date of this Agreement,

upon which termination the Seller shall have a further action against the Buyer for an additional amount equal to the Deposit Advance (the Parties hereby agree and acknowledge that in the event of such termination the Seller shall be entitled to an amount equal to no less than the Deposit).

4.2 Except as provided in Clauses 3.2(a), 3.8 and 3.9, the Deposit Advance paid to the Seller pursuant to Clause 4.1 shall not be refundable and shall be retained by the Seller and (if Closing occurs) applied in part satisfaction of the obligation of the Buyer to pay the Bid Amount as provided in Clause 2.3.

5. PRICE ADJUSTMENT

5.1 The Bid Amount has been calculated by the Buyer as the Base Value, plus the Working Capital on the basis of the Accounts and according to Schedule 6.

5.2 In the event the 2010 Accounts show a different Working Capital than that resulting from the Accounts, the Bid Amount will be adjusted upwards or downwards, on a US dollar for US dollar basis, in accordance with the procedure set out in Schedule 6; provided that no such adjustment shall be made to the Bid Amount with respect to differences in Working Capital resulting from changes in the amount of the ETAP Receivable attributable to the JN Interest from the Accounts to the 2010 Accounts, it being agreed that for purposes of the calculation of Working Capital in the 2010 Accounts, the amount of the ETAP Receivable attributable to the JN Interest shall be US$16,059,416.

5.3 In the event that the 2010 Accounts are finalized after the Closing Date in accordance with Clause 6 below, then any payment due by the Buyer to the Seller or by the Seller to the Buyer shall be paid within five (5) Business Days after such finalization.

5.4 The Seller shall be, prior to Closing, entitled to distribute as a Dividend up to thirty seven million US dollars (US$37,000,000), provided that Pioneer Tunisia holds sufficient cash amount to carry out such distribution and that no loan or other credit facility will be required in order to implement such distribution. Should a distribution be made on or following the Effective Date and prior to the Closing Date, the Seller shall inform the Buyer at least five (5) Business Days prior to the anticipated Closing Date of the amount of the Dividend. Such amount will be deducted from the amount to be paid by the Buyer at Closing in accordance with Clause 2.3(d).

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6. 2010 ACCOUNTS

6.1 Preparation of the 2010 Accounts

(a) As soon as reasonably practicable after the Effective Date and in any event within sixty (60) Business Days following the Effective Date, the Seller shall ensure that the Companies prepare the 2010 Accounts on the basis of the principles set out in paragraph 3.1(b) of Part I of Schedule 3, together with the calculation of the Working Capital.

(b) The Working Capital calculation (together with the 2010 Accounts and together with an unqualified statement from the Seller’s auditors with respect to the 2010 Accounts) shall be sent as soon as reasonably practicable to the Buyer (with a copy to the Buyer’s auditors where the Buyer has notified the Seller in writing of the identity and address of the Buyer’s auditors).

(c) In the event the Closing occurs prior to the sixty (60) Business Day period referred to in Clause 6.1(a) above, the Buyer shall procure that the Companies provide to the Seller all reasonable assistance to perform its obligations hereunder, including reasonable access to all working papers, accounts and documents and access to and reasonable cooperation from relevant personnel.

(d) In the event that the Seller fails to submit the 2010 Accounts and the Working Capital calculation to the Buyer within sixty (60) Business Days following the Effective Date, the Buyer shall prepare the 2010 Accounts and the Working Capital calculation, and the remaining provisions of this Clause 6 shall be construed in such a manner whereby it is deemed that the Buyer submits the 2010 Accounts and the Working Capital calculation and the Seller is entitled to review and confirm such calculations.

(e) The Buyer’s auditors shall be entitled to review all the documents referred to in this Clause 6.1 and to discuss with the Seller and the Seller’s auditors any matters arising therefrom. The Seller shall, in particular, ensure that the Buyer’s auditors are granted reasonable access to all working papers and other relevant documents of the Seller’s auditors and receive reasonable cooperation from the latter’s relevant personnel.

(f) The costs and expenses arising in connection with an audit of the 2010 Accounts required pursuant to this Clause 6 shall be borne by the Companies.

6.2 Within twenty (20) Business Days from the date of receipt of the 2010 Accounts and the Working Capital calculation, the Buyer shall review such documents and confirm in writing to the Seller, whether or not it approves the 2010 Accounts and the Working Capital calculation, explaining in writing any disputed item concerning the 2010 Accounts and the Working Capital calculation (“Disputed Item”). If after such time limit, the Buyer has not confirmed in writing to the Seller whether or not it approves such 2010 Accounts and Working Capital calculation, they shall be deemed to have been approved by the Buyer and shall become final and binding on the Parties.

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6.3 If the Buyer confirms its agreement with the 2010 Accounts and the Working Capital calculation (either as presented to it initially or as modified in such a manner that it has approved them), the 2010 Accounts and the Working Capital calculation shall become final and binding on the Parties.

6.4 Disputed Items shall be notified by the relevant Party in writing (such notification being an “Objection Notice”). Any Objection Notice shall set out in reasonable detail the Party’s reasons for such non-acceptance and specify the adjustments which, in such Party’s opinion, should be made to the 2010 Accounts and the Working Capital calculation in order to comply with the provisions of this Agreement and accompanied by such Party’s calculation and its best estimate of each of the items that are in dispute.

6.5 If the relevant Party serves an Objection Notice in accordance with Clause 6.4, then the Buyer and the Seller shall attempt, in good faith, to reach agreement upon the adjustments required to be made to the 2010 Accounts and the Working Capital calculation pursuant to the 2010 Accounts within a period of fifteen (15) Business Days after receipt by the relevant Party of the Objection Notice during which period the Party receiving the Objection Notice and its representatives, advisors and auditors shall be permitted to review the working papers of the other Party and its representatives, advisors and auditors (to the extent permitted under applicable Laws) relating to the Objection Notice and the basis therefor.

6.6 If the Buyer and the Seller fail to reach agreement as specified in this Clause 6 within the 15-Business Day period provided herein, the Disputed Items may be referred by either the Buyer or the Seller for determination by an independent chartered accountant (the “Expert”) who is jointly nominated by the Buyer and the Seller or, in the absence of agreement between the Buyer and the Seller on the Expert within five (5) Business Days of a Party notifying the other that it proposes to refer the dispute to an Expert, by the President of the Institute of Chartered Accountants in England and Wales (the “President”) provided that where the President is unwilling or unable to serve as an Expert, the President shall nominate a replacement person to serve as the Expert. The Expert to be nominated shall have no conflict of interest in respect of any of the Parties, the Buyer’s Group or the Seller’s Group. The Buyer and the Seller shall instruct the Expert to render its decision and notify it to the Parties within sixty (60) Business Days of its appointment.

6.7 The Expert shall be afforded such access to books, records, accounts and documents in the possession of the Parties as the Expert may reasonably request, and the Expert shall act as an expert and not as an arbitrator. The Parties shall make available (and cause the Companies to make available and shall use their best endeavours to cause their respective auditors to make available) all such information, and provide such access, to the Expert as may be required for the performance of his/its assignment.

6.8 The Expert shall review the 2010 Accounts and the Working Capital calculation as well as all necessary supporting documentation so as to settle all Disputed Items thereby finalising the Adjusted Bid Amount. The Expert’s determination shall, in the absence of fraud or manifest error, be final and binding on the Parties. Any challenge

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to the determination of the Expert on those grounds shall be brought via the dispute resolution mechanism specified in Clause 20 below, and until such time as a resolution to such challenge is achieved, the Parties will act in accordance with the determination of the Expert. The fees, costs and expenses of the Expert shall be paid entirely by the Party whose assertions regarding the Adjusted Bid Amount differ by the greatest amount from the determination by the Expert with respect to the Adjusted Bid Amount. If the Expert determines that any amount is owed by the Seller to the Buyer or the Buyer to the Seller, as a result of the resolution of the dispute concerning the Disputed Items, the amount owed shall be paid by the Seller to the Buyer or the Buyer to the Seller, as applicable, within seven (7) days after the Seller’s and the Buyer’s receipt of notice of the Expert’s determination and for the avoidance of doubt the Expert shall not make any adjustments to the Base Value.

6.9 All of the calculations to be made pursuant to this Clause 6 shall be made on a consistent basis and in accordance with generally accepted accounting principles in the United States in force at the Effective Date unless otherwise stated in this Agreement and such principles shall be consistently applied for the purposes of any and all disputes between the Parties.

6.10 For the avoidance of doubt, any approval by the Buyer of the 2010 Accounts in accordance with this Clause 6 shall be without prejudice to any Relevant Claim(s) made pursuant to Clause 8.

7. CLOSING

7.1 The closing of the sale and purchase of the Shares under this Agreement (the “Closing”) shall take place at 10:00 a.m. at the London office of Vinson & Elkins L.L.P. on the fifth (5^th) Business Day following:

(a) the earliest of the date the:

(i) pre-emption period set forth in the Anaguid JOA expires without the counter-party to the Anaguid JOA exercising its pre-emption right under the Anaguid JOA;

(ii) counter-party to the Anaguid JOA waives its pre-emption right; or

(iii) counter-party to the Anaguid JOA exercises its pre-emption right; and

(b) fulfilment (or waiver pursuant to Clause 3.2(b), 3.4 and/or 3.5, as applicable) of all the Conditions in Clause 3.1 (other than those Conditions that by their nature can only be satisfied at the Closing but subject to the fulfilment or waiver pursuant to Clause 3.2(b), 3.4 and/or 3.5, as applicable, of such conditions at Closing).

7.2 At Closing each Party shall do all those things respectively required of such Party in Schedule 2.

7.3 The Buyer shall not be obliged to complete this Agreement unless the Seller complies with all of its obligations in Schedule 2. The Seller shall not be obliged to complete this Agreement unless the Buyer complies with all of its obligations in Schedule 2.

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7.4 Should the Closing not occur by the Long Stop Date as a result of the Seller not complying with its obligations contained in Schedule 2, the provisions of Clause 3.8 shall apply mutatis mutandis.

7.5 Should the Closing not occur by the Long Stop Date as a result of the Buyer not complying with its obligations contained in Schedule 2, the provisions of Clause 3.7 shall apply mutatis mutandis.

7.6 The Seller shall be entitled to address to the Buyer, at least four (4) Business Days prior to the Closing, a Second Disclosure Letter which shall disclose exceptions to the Warranties which to the Actual Knowledge of Seller did not exist prior to the First Disclosure Letter. Should the exceptions contained in the Second Disclosure Letter result in the Conditions set forth in Clause 3.1(a) being unable to be satisfied and, subject to the Buyer having not intentionally or wilfully breached this Agreement as provided in the first proviso in Clause 3.2, the Buyer shall be entitled to not complete this Agreement (as provided in Clause 3.2(a)), in which case the provisions of Clause 3.2 and/or 3.8 shall apply mutatis mutandis.

7.7 From and after Closing, the Buyer shall cause the Companies to take such actions as may be reasonably necessary to satisfy any obligations (if any) arising under the Key Agreements or Tunisian Law as a result of the transactions contemplated by this Agreement.

8. WARRANTIES AND INDEMNIFICATION

8.1 The Seller warrants to the Buyer that each of the Warranties is true and accurate as at the date of this Agreement and as at the Closing (except that Warranties that are made as of a specific date need to be so true and accurate only as of such date), subject to any exceptions or disclosures (taken as a whole) disclosed or deemed to be disclosed, fully, fairly and accurately by the Seller in the First Disclosure Letter, the Second Disclosure Letter or the Data Room, to enable an experienced energy company acting reasonably to understand that the Warranty in question is in fact qualified by such exception or disclosure; provided, however, that:

(a) except as provided in Clause 8.1(b), no disclosure contained in the Second Disclosure Letter shall be a limitation on the Buyer’s remedies under this Agreement after Closing with respect to:

(i) any Warranty that is not true and correct as referred to in Clause 3.1(a)(i) provided that the aggregate Losses resulting from the disclosures contained in the Second Disclosure Letter remain equal to or below the Materiality Threshold ; or

(ii) any Warranty that is not true and correct at Closing to the extent that such breach of Warranty occurred prior to the Effective Date; and

(b) disclosures contained in the Second Disclosure Letter shall be a limitation on the Buyer’s remedies under this Agreement after Closing with respect to any Warranty that is not true and correct at Closing to the extent that such breach of Warranty occurred after the Effective Date.

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8.2 The Buyer acknowledges and agrees that notwithstanding anything to the contrary:

(a) the Warranties are the only assurances given by the Seller and the Seller makes no other warranties or assurances in connection with the Transaction or otherwise (and, in particular, the assurances set forth in paragraph 13 of Part I of Schedule 3 are the sole and exclusive warranties given in connection with any environmental matters or issues);

(b) it shall have no right or entitlement to bring a breach of Warranty claim in connection with paragraph 13 of Part I of Schedule 3 unless:

(i) the breach relates to a period:

(A) prior to the Effective Date; and

(B) as to any Company, during which such Company held a participating interest in, and acted as operator of, the Interest where the breach occurred;

(ii) the breach was caused by either Company carrying out operations pursuant to the Key Agreements in its capacity as operator; and

(iii) the breach either:

(A) violated any applicable Laws of Tunisia in force prior to the Effective Date; or

(B) resulted in liability prior to the Effective Date to a third party;

(c) (i)         none of the Warranties will be considered breached, untrue or inaccurate as a result of a Violation Claim;

(i) the assertion or enforcement of a Violation Claim or the exercise of any pre-emption rights or right of first offer under any Key Agreement or Tunisian Law will not be considered a Material Adverse Event; and

(ii) the Seller shall not be under any obligation to indemnify or otherwise compensate or reimburse the Buyer for any Losses arising in connection with a Violation Claim including arising in connection with any settlement or final determination with respect to any Violation Claim;

(d) it has entered into each Transaction Document as a result of its own due diligence, investigations, enquiries, advice and knowledge. The Buyer acknowledges that it has knowledge and experience in the oil and gas industry generally, and is capable of evaluating the merits associated with entering into and performing its obligations under each Transaction Document;

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(e) save as expressly provided for herein, the Warranties do not include any assurance (and the Seller does not give any such assurance) as to:

(i) the accuracy of any forecasts, estimates, projections, management presentations, statements of intent or statements of opinion howsoever provided to the Buyer or any of its directors, employees, officers, agents, advisers or other Persons on, prior to or after the date of this Agreement including as are included in the Data Room, First Disclosure Letter, the Second Disclosure Letter or any other documents provided to or for the benefit of the Buyer or its advisers in the course of the Buyer’s investigation of the Companies and the Interests;

(ii) the value of the Interests or the Shares;

(iii) the amounts, quality or deliverability of reserves of crude oil, natural gas or other hydrocarbons attributable to the Interests;

(iv) any geological, geographical, engineering, economic or other interpretations, forecasts or evaluations or any estimates or projections of reserves or resources;

(v) any forecast of expenditures, budgets or financial projections;

(vi) any geological formation, drilling prospect or hydrocarbon reserve;

(vii) the past, present or future exercise of any regulatory, administrative or ministerial discretion under any applicable Law;

(viii) the past, present or future performance, action, operation, ownership or profitability of the oil and gas industry in Tunisia;

(ix) the existence of any present or future business opportunities of either Company of any type whatsoever, including in respect of the oil and gas industry in Tunisia;

(x) the state, condition, performance, quality, operability or fitness for a particular purpose of the Interests and/or any of the property or assets relating to the Interests (which are acknowledged by the Buyer to be on an “as-is” basis) including any platforms, pipelines, plant, machinery, wells, facilities and all other installations and structures; or

(xi) the accuracy of the English or other translation of any agreement or document referred to in the First Disclosure Letter or the Second Disclosure Letter or as included in the Data Room.

(f) Seller shall have no liability under this Agreement attributable to costs or expenses incurred or paid by the Companies, the Companies’ predecessors in interest or any other current or former party to the Key Agreements in connection with the Key Agreements prior to the Effective Date to the extent that such costs or expenses relate to the following (“past costs or expenses”):

(i) the recoverability or collectability of past costs or expenses reflected as ETAP Receivables in the Accounts or, when finalized, the 2010 Accounts; or

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(ii) issues relating to the deductibility of any past costs or expenses in connection with the computation of the Companies’ Taxes; or

(iii) the amount of past costs or expenses properly included in the calculation of any Royalty or other amount calculated pursuant to the applicable R-Factor or ratio (R) (as defined in the Hydrocarbon Code).

8.3 After Closing, the Seller shall, subject to Schedule 4 and the other provisions of this Clause 8, undertake to indemnify the Buyer and any payments to Buyer shall be deemed to be a reduction in the Adjusted Bid Amount or, if the Buyer in its absolute discretion so wishes and directs the Seller in writing, by paying the amounts due under this Clause 8.3 to the Companies directly for the amount of:

(i) all Losses suffered or incurred by the Buyer or any of the Companies, as a result of any Relevant Claims arising from any breach of any of the Warranties;

(ii) subject to any and all of the limitations in Clauses 8.2(e) and 8.2(f) and Schedule 7, any Loss attributable to a Tax Liability or Royalty Liability for a period prior to the Effective Date, (x) if such Loss has not been provided for in the 2010 Accounts of such Company or (y) if and to the extent such Loss represents an increase over the amount so provided in the 2010 Accounts for such Tax or Royalty; and

(iii) all reasonable costs and expenses of any proceedings and any legal advice incurred in connection with any Loss referred to in Clauses 8.3(i) and 8.3(ii).

8.4 The liability of the Seller in connection with a Relevant Claim shall be subject to the limitations contained in, and to the provisions of, Schedule 4.

8.5 After the Closing, Relevant Claims shall be notified in writing by the Buyer to the Seller within the time limits set out in Schedule 4. As soon as reasonably practicable after the Buyer becomes aware that there is a breach of Warranty, the Buyer shall without undue delay notify the Seller in writing. To the extent that the Losses relating to any such breach are increased as a result of a failure by the Buyer to notify the Seller timely of such a breach in accordance with this Clause 8.5, the Buyer shall be deemed to have irrevocably waived its rights and entitlement to claim such increase in Losses. To the extent reasonably practicable, the notification of the Relevant Claim shall contain reasonable information as to the details of such matter or circumstance then known to the Buyer including the Buyer’s best estimate of the amount of the Relevant Claim. To the extent reasonably practicable, the Buyer shall thereafter provide a written update to the Seller of such matters or circumstances whenever any material new information, facts or details become known by the Buyer in connection with such matter or circumstance.

8.6 Should the Buyer become aware at any time before or after Closing that there has been a breach of any of the Warranties or any other term of this Agreement, the Buyer shall not be entitled to (and the Buyer hereby waives the right to) rescind or terminate this Agreement after Closing.

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8.7 Each of the Parties acknowledges and agrees that after the Closing, notwithstanding any other provision of any Transaction Document to the contrary, the sole and exclusive remedy of the Buyer with respect to any Relevant Claim shall be a claim for damages under Clause 8.3 and Schedule 4 of this Agreement provided that any such Relevant Claim shall be subject to the limitations set forth herein.

9. TAX

9.1 The Seller’s obligation to hold the Buyer harmless in accordance with Clause 8.3, the provisions of Schedule 7 and the provisions of paragraph 8 of Part I of Schedule 3 (the “Tax Warranties”), shall represent the Seller’s only obligation with respect to Tax matters.

9.2 The Parties agree and acknowledge that no Transfer Tax should be chargeable by any Tax Authority in Tunisia in connection with the transactions contemplated by the Transaction Documents; provided, however, that where any Transfer Tax is payable in Tunisia or Austria in connection with the transactions contemplated by the Transaction Documents, then such Transfer Tax shall be borne solely by the Buyer.

10. PROTECTIVE COVENANTS

10.1 The Buyer covenants in favour of the Seller that:

(a) no later than thirty (30) days following the Closing Date the Buyer will, and will cause each Company to, change its name and register such change of name with the registrar of companies in the Cayman Islands, and as soon as reasonably practicable but no later than forty five (45) days following the Closing Date the Buyer will, and will cause each Company to, cease using the word “Pioneer” or “PNR” or any variation or derivative thereof (including any logo, trademark or design containing such name or word or derivative or otherwise associated with the Seller or any member of the Seller’s Group and which are listed in Schedule 14) or any other name which could be confused or associated with any such name in connection with the Interests or any assets of either Company or in any way using the word “Pioneer” or “PNR” or any variation or derivative thereof in connection with the business of any member of the Buyer’s Group provided that the Buyer will be entitled to a period of no more than ninety (90) days following the Closing Date to remove any signage or logos or marks referring to any of the above;

(b) the Buyer will comply with all registration and filing requirements imposed by a Governmental Entity in connection with the matters contemplated by this Clause 10.1;

(c) for a period of 5 years after the Closing or, if longer, for the applicable statute of limitations with respect to records and data relating to Tax, the Buyer shall, and shall cause each Company to, preserve and retain the records and data and all other corporate, accounting, legal, auditing and other books and records relating to the either Company (including any documents relating to any governmental or non-governmental actions, suits, proceedings or investigations); and

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(d) from and after the Closing, the Buyer shall, upon reasonable notice from the Seller, make available and provide the Seller with reasonable access (at the Seller’s sole cost and risk) to the facilities and properties of each Company and to all information, files, documents and records (written and computer) relating to the Interests and each Company for any and all periods prior to the Closing, and permit the Seller to take extracts therefrom and to make copies thereof so long as such access will not unreasonably interfere with the normal operation of the Companies, and shall (and shall cause each Company to) cooperate reasonably with the Seller in connection with the foregoing including by making tax, accounting and financial personnel and other appropriate employee and officers of either Company available to the Seller.

10.2 Except as permitted pursuant to this Agreement or otherwise agreed to in writing by the Parties, for a period of twelve (12) months from the date of this Agreement no member of the Buyer’s Group shall solicit for hire:

(i) any employee, officer, or representative of any member of the Seller’s Group (including any employee of any member of the Seller’s Group that is seconded to either Company or works on projects relating to either Company or the Interests); or

(ii) unless the Closing occurs (but subject to Clause 10.2(i)), any employee, officer, or representative of either Company.

10.3 The Buyer covenants in favour of the Seller (on behalf of itself and on trust for each member of the Seller’s Group) and the Seller covenants in favour of the Buyer (on behalf of itself and on trust for each member of the Buyer’s Group) that it will not make or offer, with respect to the matters which are the subject of this Agreement or in relation to the Interests, any payment, gift, promise or other advantage, whether directly or through any other Person, to or for the use or benefit of any public official or any political party or political party official or candidate for office, where such payment, gift, promise or advantage would violate (i) the applicable Laws of Tunisia; (ii) the Laws of the country of incorporation or principal place of business of the Companies; (iii) the U.S. Foreign Corrupt Practices Act 1977 or (iv) the principles described in the Convention on Combating Bribery of Foreign Public Officials in International Business Transactions, signed in Paris on December 17, 1997.

10.4 The Buyer hereby agrees that from and after Closing it shall indemnify the Seller against any Losses suffered by any member of the Seller’s Group in connection with each Guarantee.

11. INSURANCE

11.1 The Buyer acknowledges and agrees that upon Closing all insurance coverage in relation to the Companies pursuant to policies maintained (or to be maintained) by or on behalf of the Seller or any other member of the Seller’s Group shall, in relation to the Companies, cease.

11.2 Notwithstanding the above, all insurance policies taken by any of the Companies (excluding any fronting insurance policies required, in accordance with the applicable Laws of Tunisia, to be maintained by either Company) shall not be terminated nor

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varied by the Seller and shall be maintained by the Seller prior to Closing in accordance with their current terms (except insofar as the Seller is named as co-insured or beneficiary, in which case, the Buyer shall be named co-insured or beneficiary as from the Closing Date). The insurance polices to which this obligation relates are listed in Schedule 15.

11.3 Where:

(a) Closing occurs; and

(b) the Seller has insurance which covers any Losses (or any portion thereof) suffered by the Companies up to the Closing Date (provided that the Seller shall not be required to pursue any such insurance claim beyond a determination in the first instance whether by way of an expert, an arbitral award, court judgment or otherwise),

the Seller shall, (i) upon receipt of the insurance proceeds relating thereto, pay the Buyer such insurance proceeds (less any applicable taxes and costs of recovery) and (ii) if the first instance determination is not satisfactory to the Buyer assign, to the extent such rights are assignable, to the Buyer (at its sole discretion) any and all rights of the Seller to pursue the claim against the relevant insurer. Nothing in this Clause 11.3 shall obligate the Seller to maintain any such insurance after Closing or require that the Seller pursue a claim under insurance that is maintained beyond a determination in the first instance, whether by way of an expert, an arbitral award, court judgment or otherwise.

12. EMPLOYMENT

12.1 The Parties agree that:

(a) the transactions contemplated by this Agreement will not operate so as to terminate the contracts of employment of employees of Pioneer Tunisia listed in the Employee List and such contracts shall continue on and after the Closing. Except for those employees who commenced employment with either Company after the date of this Agreement and as permitted under Schedule 5, at Closing the Seller shall cause any employment contract with any of the Companies relating to an employee which is not listed in the Employee List to be terminated, at the Seller’s cost;

(b) the Seller shall cause each of the Companies, at or prior to the Closing, to exercise its right to settle and pay all amounts due as of Closing to employees of Pioneer Tunisia arising under each Cash in Lieu Agreement and the Seller shall, no later than thirty (30) days after Closing, contribute to each of the Companies an aggregate amount equal to all such amounts so due under each Cash in Lieu Agreement and the Buyer covenants to procure that Pioneer Tunisia pays such funds to each applicable employee entitled to an amount pursuant to a Cash in Lieu Agreement;

(c) no later than three (3) months after the date of this Agreement, the Seller shall submit to the Buyer a written schedule of bonuses due to be paid to each employee of Pioneer Tunisia. Where the aggregate of such bonuses exceeds

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the amount accrued and set forth for such bonuses in the 2010 Accounts, the Seller shall pay the Buyer the amount of such excess and the Buyer covenants to procure that Pioneer Tunisia pays such funds to each applicable employee set forth in the schedule; and

(d) where the period of continuous employment of an employee of Pioneer Tunisia is terminated by Pioneer Tunisia without cause within twelve (12) months after the Closing, the Buyer shall be liable to pay or shall cause Pioneer Tunisia to pay the employee so terminated an amount equal to the sum of one (1) month’s base salary for each year of continuous employment with Pioneer Tunisia (measured on the date of termination of employment) plus two (2) months base salary, such aggregate sum subject to a minimum of six (6) months base salary.

13. LEFT BLANK INTENTIONALLY

14. BUYER WARRANTIES

The Buyer warrants to the Seller that each of the statements set forth in Part II of Schedule 3 is true and accurate in all material respects as at the date of this Agreement and as at the Closing Date (except where any such statement is made as of a specific date in which case such statement need only be true as of such specific date).

15. ANNOUNCEMENTS AND CONFIDENTIALITY

15.1 After the date hereof, neither the Seller nor the Buyer shall make (or permit any other member of the Seller’s Group or the Buyer’s Group (as the case may be) to make) any announcement concerning the sale and purchase of the Shares or any ancillary matter (including the terms of any Transaction Document or the existence or content of any proceedings relating to this Agreement) without the prior approval in writing of the other. Without prejudice to the Confidentiality Agreement, each Party shall keep confidential the existence and the content of this Agreement, as well as any information given or document exchanged in the context of the negotiation, the drafting, the execution or the performance of this Agreement and shall not communicate any such information or documents to any Person (except any other member of the Seller’s Group or the Buyer’s Group or the advisors of any Party) without the prior written approval of the other Party.

15.2 The Buyer covenants, and shall procure that each member of the Buyer’s Group covenants, in favour of the Seller, prior to Closing, to adhere to and comply with the terms and conditions of the Confidentiality Agreement.

15.3 Nothing in this Clause nor the Confidentiality Agreement prevents any announcement being made or any information being disclosed:

(a) with the prior written approval of the other Party, which in the case of any announcement shall not be unreasonably withheld or delayed;

(b) to the extent required to be disclosed in relation to the resolution of any claims or disputes arising under this Agreement (including any pleadings made or any other actions required in the commencement or prosecution or defense of any such claim or dispute);

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(c) to the extent required to be disclosed to any governmental or regulatory authority; or

(d) to the extent necessary to be disclosed under applicable Laws or the rules of any applicable stock exchange or by any order, decree, regulation or rule of any governmental or competent regulatory body, provided that a Party so required to disclose any such information shall promptly notify the other Party, where practicable and lawful to do so, before disclosure occurs and co-operate with the other Party regarding the timing and content of such disclosure.

16. NOTICES

16.1 Notices or other communications (a “Notice”) given in connection with this Agreement shall be:

(a) in writing;

(b) delivered by hand or sent by registered post with a return receipt request or express courier (such as Federal Express, UPS, DHL or similar reliable delivery service) to the address in Clause 16.3 of the Party to which the Notice is being given or to such other address as such Party shall communicate in accordance with Clause 16.4; or

(c) sent by email, with an electronic delivery receipt, or facsimile, to the address or number in Clause 16.3 of the Party to which it is being sent or to such other number as such Party shall communicate to the Party giving the Notice, confirmed by registered post with a return receipt request or express courier (such as Federal Express, UPS, DHL or similar reliable delivery service) in accordance with sub-clause (b) above.

16.2 Every Notice given in accordance with this Clause shall be deemed to have been received as follows:

Means of Dispatch	Deemed Received
Delivery by hand:	the date when receipt has been confirmed by the addressee
Registered post or express courier (Federal Express, UPS, DHL or similar reliable delivery service):	the date of delivery receipt issued by the post office or the express courier company
Facsimile:	the date of the sender's transmission report (subject to Sub-Clause 16.1 (c) above)
Email:	when sent (subject to Sub-Clause 16.1 (c) above)

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PROVIDED THAT if the receipt is not within working hours (being 9 am to 5 pm (local time wherever received) on a Business Day) Notice shall be deemed to be given or made at the start of working hours on the next Business Day.

16.3 The relevant addressee, address, facsimile number and email address of each Party for the purposes of this Agreement, subject to Clause 16.4 are:

Name of Party	Address	Facsimile No.	Email address
Pioneer Natural Resources USA, Inc.	5205 N. O’Connor Blvd., Suite 200, Irving, TX 75039 Attention: General Counsel	+00 (1) 972-969- 3577	Mark.Berg@pxd.com
with a copy to:	5205 N. O’Connor Blvd., Suite 200, Irving, TX 75039 Attention: Corporate Secretary	+00 (1) 972-969- 3552	Mark.Kleinman@pxd.com
OMV (Tunesien) Production GmbH	c/o OMV Aktiengesellschaft, Trabrennstrasse 6-8, 1020 Vienna, Austria Attention: Senior Vice President, Corporate Development & M&A	+43 (1) 40 440621437	stefan.waldner@omv.com andreas.aigner@omv.com

16.4 A Party shall notify the other Party of a change to its name, relevant address, facsimile number or email address for the purposes of Clause 16.3. Such notification shall only be effective on:

(a) the date specified in the notification as the date on which the change is to take place; or

(b) if no date is specified or the date specified is less than five (5) Business Days after the date on which notice is received, the date falling five (5) Business Days after notice of any such change has been received.

17. GENERAL

17.1 If:

(a) any monetary sum expressed in a currency other than US$ is to be taken into account for the purposes of calculating the monetary amount of any Relevant Claim; and/or

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(b) it is necessary to determine whether any monetary amount set out in paragraph 1 of Schedule 4 or any other provision of this Agreement has been reached or exceeded;

then the value of that Relevant Claim or amount, as applicable, shall be translated into US$ at the closing mid-point US$ spot rate applicable to that amount of that currency at close of business in London on the last business day in London before dispatch by the Buyer of written notification from the Buyer in accordance with Clause 16, of the existence of the applicable Losses or Relevant Claim as shown in the Financial Times (London edition) published on the next following day or, if the Financial Times (London edition) is not published on that day, the closing middle point spot rate quoted by the Wall Street Journal (US) published on that next following day for US$ applicable to amounts of US$1,000,000 or more.

17.2 This Agreement shall not be varied or cancelled, unless such variation or cancellation is in writing and signed by a duly authorised signatory of each of the Buyer and the Seller.

17.3 The observance of any term of this Agreement may be waived (either generally or in a particular instance and either retroactively or prospectively) by the Party entitled to enforce such term, but such waiver shall be effective only if it is in writing and signed by the Party entitled to enforce such term and against which such waiver is to be asserted. Unless otherwise expressly provided in this Agreement, no delay or omission on the part of any Party in exercising any right or privilege under this Agreement shall operate as a waiver thereof, nor shall any waiver on the part of any Party of any right or privilege under this Agreement operate as a waiver of any other right or privilege under this Agreement nor shall any single or partial exercise of any right or privilege preclude any other or further exercise thereof or the exercise of any other right or privilege under this Agreement.

17.4 Without prejudice to any other obligations in this Agreement, each Party shall use all commercially reasonable endeavours to provide such further documents or instruments required by any other Party which are reasonably necessary to carry out the provisions of this Agreement, whether before or after the Closing.

17.5 Unless otherwise provided for in this Agreement, each Party shall pay its own costs in connection with the negotiation, preparation, execution and performance of this Agreement (including all banker’s and broker’s fees).

17.6 This Agreement is personal to the Parties and shall not be assignable in whole or in part by any Party. Notwithstanding the preceding sentence, the Buyer shall be entitled to assign after Closing any of its rights and obligations hereunder to any other company belonging to the Buyer’s Group with the written consent of the Seller (not to be unreasonably withheld) provided that no such consent shall be required after Closing for assignments of this Agreement by the Buyer to a wholly-owned subsidiary of the Buyer.

17.7 Except as otherwise set forth in this Agreement, the rights, powers and remedies provided for in this Agreement are cumulative and not exclusive of any rights, powers and remedies provided by Law.

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17.8 This Agreement may be executed in any number of counterparts, each of which is an original and all of which when taken together shall constitute one and the same agreement.

17.9 Except as otherwise provided in this Agreement, no Party will, in any circumstance whatsoever, be liable under this Agreement or any other Transaction Document to any other Party for any punitive, special, incidental, exemplary, indirect or consequential damages or losses or lost profits of any kind or nature suffered, sustained, paid, incurred or claimed by any other Party.

17.10 Time shall be of the essence in respect of any dates, times and periods specified in this Agreement.

17.11 Except as provided in Clause 10.3, a Person who is not a party to this Agreement has no right under the Contracts (Rights of Third Parties) Act 1999 to enforce this Agreement.

18. WHOLE AGREEMENT

18.1 This Agreement and the other documents to be executed at Closing contain the whole agreement between the Parties relating to the Transaction and supersede all previous agreements, whether oral or in writing, between the Parties relating to the Transaction; provided however, the Confidentiality Agreement shall survive the execution and delivery of this Agreement until Closing occurs notwithstanding anything to the contrary in the Confidentiality Agreement.

18.2 Each Party acknowledges that, in agreeing to enter into this Agreement and the other documents to be executed at Closing, it has not relied on any assurance made by or on behalf of any third party before the entering into of this Agreement. Each Party waives all rights and remedies which, but for this sub-Clause, might otherwise be available to it in respect of any such assurance.

19. CONSTRUCTION

19.1 The Parties have participated jointly in the negotiation and drafting of this Agreement and the other Transaction Documents. In the event an ambiguity or question of intent or interpretation arises, this Agreement and each other Transaction Document shall be construed as if drafted jointly by the Parties, and no presumption or burden of proof shall arise favouring or disfavouring any Party by virtue of the authorship of any provisions of this Agreement or any other Transaction Document.

19.2 Reference to any matter in the First Disclosure Letter or the Second Disclosure Letter shall not be deemed to be an acknowledgement by the Seller, or to otherwise imply, that the matter meets or exceeds any applicable threshold of materiality or any other relevant threshold. To the extent a matter is disclosed against a particular Warranty in the First Disclosure Letter or the Second Disclosure Letter such matter shall be deemed to be disclosed against all other Warranties to the extent it is reasonably apparent on its face that it relates to such other Warranties.

19.3 In this Agreement, unless the context requires otherwise:

(a) use of the singular includes the plural and vice versa;

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(b) a reference to one gender includes a reference to each other gender;

(c) a document in the “agreed form” is a reference to a document in a form approved and for the purposes of identification initialed by, or on behalf of, each Party;

(d) a reference to “including” or “includes” does not limit the scope of the meaning of the words preceding it;

(e) all references to days, months or years shall be deemed references to calendar days, months or years;

(f) the words “hereof”, “herein”, and “hereunder” and words of similar import referring to this Agreement refer to this Agreement as a whole and not to any particular provision of this Agreement;

(g) any reference to a Person’s “Group” is, unless otherwise stated, a reference to that Person, its subsidiary undertakings, its parent undertakings and any other subsidiary undertakings of its parent undertakings;

(h) the headings are inserted for convenience of reference only and shall not in any way form part of, or affect the construction or interpretation of, this Agreement;

(i) the provisions of the Schedules to this Agreement form an integral part of this Agreement and have as full effect as if they were incorporated in the body of this Agreement and the expressions “this Agreement” and “the Agreement” shall be deemed to include the Schedules to this Agreement;

(j) a reference to a Person (including a Party) includes a reference to a firm, a body corporate, an unincorporated organisation, government agency, an independent authority or to a Person's executors or administrators and includes a reference to that Person’s legal personal representatives, successors and permitted assigns;

(k) a reference to a document is a reference to that document as from time to time amended, novated, supplemented or varied (in each case, other than in breach of the provisions of this Agreement);

(l) a reference to a document, copies of which have been made available or otherwise provided, to any member of the Buyer’s Group or any of their advisers, in both English and French, is a reference to such document in the language which takes precedence in accordance with such document;

(m) any reference to any statute or statutory provision shall include:

(i) any statute or statutory provision which:

(A) amends, extends, consolidates, re-enacts or replaces any statute or statutory provision; or

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(B) has been amended, extended, consolidated, re-enacted or replaced (whether before or after the date of this Agreement) by any statute or statutory provision; and

(ii) any orders, regulations, instruments or other subordinate legislation made under the relevant statute;

(n) a reference to any Clause, sub-Clause, paragraph, or Schedule shall be a reference to the Clause, sub-Clause, paragraph, or Schedule of this Agreement unless the context otherwise requires;

(o) reference to a company shall be construed so as to include any company, corporation or body corporate, whenever and however established or incorporated; and

(p) if a period of time is specified and dates from a given day or the day of an act or event, it shall be calculated exclusive of that day (unless otherwise herein expressly provided to the contrary).

20. GOVERNING LAW AND JURISDICTION

20.1 This Agreement is governed by, and shall be construed in accordance with the laws of England and Wales.

20.2 All disputes or differences of any kind between the Parties in connection with, arising out of or related to this Agreement or the breach, termination or invalidity of this Agreement shall be finally decided by binding arbitration.

20.3 The arbitration referred to in Sub-Clause 20.2 above shall be conducted under the Rules of Arbitration of the International Chamber of Commerce by three arbitrators appointed in accordance with the said Rules. No provisions of said Rules will apply insofar as it renders any individual ineligible for appointment as arbitrator on the grounds of nationality.

20.4 The arbitration proceedings shall be conducted and the award rendered in the English language, and the arbitrators shall be fluent in the English language.

20.5 The seat of arbitration shall be London, England.

20.6 The Parties agree to exclude the application of Sections 45 and 69 of the English Arbitration Act 1996, and no Party shall have the right to apply to a court for a determination of a question of law arising in the proceedings or to appeal to a court on a question of law arising out of an award.

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SCHEDULE 1

INFORMATION ABOUT THE COMPANIES

Pioneer Natural Resources Anaguid Ltd.

Date of Incorporation:	2 May 2001
The Directors:	Mark Berg Chris Cheatwood Richard Dealy Timothy Dove
The Secretary:	Mark Kleinman
Authorised Share Capital:	50,000 ordinary shares with a par value of US$1 each
Issued Share Capital:	1,000 ordinary shares with a par value of US$1 each

Pioneer Natural Resources Tunisia Ltd.

Date of Incorporation:	2 May 2001
The Directors:	Mark Berg Chris Cheatwood Richard Dealy Timothy Dove
The Secretary:	Mark Kleinman
Authorised Share Capital:	50,000 ordinary shares with a par value of US$1 each
Issued Share Capital:	1,000 ordinary shares with a par value of US$1 each

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SCHEDULE 2

BUSINESS TO BE TRANSACTED AT CLOSING

At Closing:

1. the Seller shall deliver to the Buyer:

(a) duly executed and completed Shares transfer forms to the Buyer together with share certificates for the Shares (numbered 001 to 003 for each Company);

(b) a written resignation of each of the directors and the officers of the Companies effective as of the Closing in a form reasonably acceptable to the Buyer and the Seller from their respective offices in the Company;

(c) a duly executed mutual release between each of the directors and the officers of the Companies on the one hand and the respective Company on the other hand effective as of the Closing in a form reasonably acceptable to the Buyer and the Seller;

(d) signed board resolutions of each Company, effective as of the Closing Date, approving the transfer of Shares, accepting the resignation of the existing directors and the secretary, removing the existing officers and appointing the new directors whose identity will be notified by the Buyer to the Seller at least 10 days prior to Closing;

(e) a signed copy of the Pioneer Services Agreement, to be entered into between the Seller and the Buyer, consistent with the principles set forth in Schedule 13;

(f) a copy of the updated register of members of each Company showing the Buyer as the sole shareholder of respectively Pioneer Anaguid and Pioneer Tunisia;

(g) a duly executed deed of termination, release and waiver between the Seller and the Companies in a form reasonably acceptable to the Buyer and the Seller;

(h) a duly executed officer’s certificate, annexed to which shall be the form of pre-emption notification served on each counterparty to the Anaguid JOA, a related receipt of delivery and all material written correspondence from each counterparty to the Anaguid JOA relating to the pre-emption notification, which certificate shall certify that such pre-emption notification has been duly sent to the counterparties and that the aforesaid related receipt of delivery and all material written correspondence from each counterparty to the Anaguid JOA relating to such pre-emption notification are annexed to the certificate; and

2. the Buyer shall:

(a) pay the amounts due pursuant to Clause 2.3;

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(b) provide to the Seller a countersigned copy of:

(i) the Pioneer Services Agreement, to be entered into between the Seller and the Buyer, consistent with the principles set forth in Schedule 13;

(ii) the deed of termination, release and waiver between the Seller and the Companies in a form reasonably acceptable to the Buyer and the Seller.

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SCHEDULE 3

PART I

SELLER WARRANTIES

1. CAPACITY AND AUTHORITY

1.1 Incorporation and existence

(a) Each Company is duly incorporated and validly existing and in good standing under the laws of the Cayman Islands and (without limiting the Warranty in paragraph 10 of this Schedule 4) has all the requisite corporate power and authority, and to the Best Knowledge of Seller as of the date hereof all necessary approvals, licenses, permits and authorisations, to own its properties and to carry on its business(es) as now conducted.

(b) No resolution has been adopted providing for the amendment of the memorandum of association, articles of association and certificate of incorporation of either of the Companies or for the dissolution or winding-up of any of the Companies.

(c) All corporate decisions have been taken in accordance with the Laws of the Cayman Islands or the United States of America and internal rules applicable to the Companies.

1.2 Power and authority

The Seller has the legal right and full power and corporate authority to execute and deliver, and to exercise its rights and perform its obligations under, this Agreement and each other Transaction Document to which it is party.

1.3 Binding agreement

This Agreement constitutes a valid and binding agreement of the Seller.

2. SHARES AND CORPORATE MATTERS

2.1 The Shares

(a) The Seller is the sole legal and beneficial owner of the Shares.

(b) The Shares comprise the whole of the allotted and issued share capital of the Companies and are transferred with full ownership of title.

(c) The Shares are validly issued and fully paid up or credited as fully paid up.

(d) Subject to the Key Agreements, there is no Encumbrance, nor is there any agreement or obligation by the Seller or the Companies to create or give any Encumbrance, on, over or affecting the Shares or any issued or unissued shares of the Companies.

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(e) Save as provided in this Agreement (and, in respect of paragraph (i) below, the Key Agreements):

(i) there is no agreement, arrangement or obligation in force which is binding on the Companies or on the Seller which calls for the present or future allotment, issue or transfer of, or the grant to any Person of the right (whether conditional or otherwise) to call for the allotment, issue or transfer of, any share or loan capital of the Companies; and

(ii) no share or loan capital has been created, allotted, issued, acquired, repaid or redeemed, or agreed to be created, allotted, issued, acquired, repaid or redeemed, by the Company since the Effective Date.

(f) The share registers of the Companies have been properly maintained in compliance with applicable Laws of the Caymans Islands and contain an accurate record of the shareholders of such entities.

(g) Other rights: except as provided in the Key Agreements,

(i) There are no shares or other securities or equity interests of any of the Companies, other than the Shares, issuable upon conversion, exchange or redemption of any security or pursuant to any other agreement or undertaking, nor are there any rights, options or warrants outstanding or other agreements to issue or acquire securities of any of the Companies, nor is any of the Companies obligated to purchase, redeem or otherwise acquire any of its outstanding shares or other securities.

(ii) Neither the Seller nor any other Person is entitled to any preferential or similar rights to subscribe for shares or other securities in the Companies.

(iii) There are no voting trusts, proxies or other arrangements or understandings with respect to the voting of the shares or equity interests of the Companies.

2.2 Registers, minute books and statutory books

All registers, minute books and other statutory books required by Law to be kept by the Companies have been kept properly in accordance with applicable Law.

2.3 Returns

All returns, particulars, resolutions and other documents required to be delivered by the Companies to The Registrar of Companies in the Cayman Islands have been properly and correctly prepared and submitted in a timely manner.

2.4 Powers of attorney and authorities

There is no power of attorney given by either Company currently in force and, subject to the Key Agreements, there is no outstanding authority by which any Person may enter into any agreement, arrangement or obligation to do anything on behalf of either

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Company (other than any authority of its officers and directors to enter into agreements or obligations in the ordinary and usual course of their duties), except (i) such power of attorney or authority as will be terminated on or prior to Closing or (ii) such power of attorney that has been granted to the local manager of either Company.

2.5 Effect of Transfer of Shares

The sale of the Shares to the Buyer and, more generally, the execution and performance of this Agreement by the Seller shall not give rise to the following events:

(a) any violation of any Law of the Cayman Islands or the United States of America or Order of any Governmental Entity of the Cayman Islands or the United States of America;

(b) any breach of the memorandum of association, articles of association or any other constitutional document of the Companies;

(c) any calls for early repayment of any loans or financing granted to any of the Companies;

(d) except as provided in Clause 12 of this Agreement, any obligation to pay a bonus or indemnity to any of the employees or managers of any of the Companies;

(e) any entitlement for any Person to be released from its obligations under the terms of any guarantee or other similar document issued as a security or in support of any undertakings on the part of any of the Companies;

(f) any registration or constitution of a pledge or lien on the Interests, assets or securities of any of the Companies; and

(g) save as specifically provided in this Agreement, any obligation to obtain any consent or approval of, or give any notice to or make any registration with, any Governmental Entity of the Cayman Islands or the United States of America which has not been obtained or made at the date hereof (both on an unconditional basis and on a basis that cannot be revoked).

3. ACCOUNTS AND 2010 ACCOUNTS

3.1 General

(a) The Accounts (as prepared by the Companies) were prepared on a consistent basis in accordance with generally accepted accounting principles in the United States, except with respect to those parts of generally accepted accounting principles in the United States that require explanatory notes, and represent a true and fair view of the financial position of the relevant Company as of September 30, 2010.

(b) To the extent prepared by the Seller, the 2010 Accounts (as will be prepared by the Companies) will be prepared in accordance with generally accepted accounting principles in the United States and represent a true and fair view of the financial position, results of operations and statement of cash flows of the relevant Company as of and for the year ended December 31, 2010.

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3.2 Books and financial records

To the Best Knowledge of Seller, all the accounting books and records of the Companies are in its possession or under its control and as of the date of this Agreement are accurate and have been properly kept and completed in accordance with applicable legal requirements.

4. CHANGES SINCE THE LAST ACCOUNTS DATE

4.1 Ordinary course of business

Since the Accounts Date:

(a) the business and activities of the Companies have been carried on in the ordinary and usual course up to the date of this Agreement; and

(b) no resolution of either Company in general meeting has been passed up to the Closing Date (other than any resolution constituting ordinary business conducted at an annual general meeting).

4.2 Guarantees / Securities

(a) On the Closing Date there will be no outstanding guarantee, indemnity or suretyship or similar undertaking given by the Companies for the benefit of any member of the Seller’s Group.

(b) Save as set forth in the Key Agreements, (i) the Companies have granted no security or guarantee to the Seller or to any third party, (ii) there is no Encumbrance created by the Companies (or, to the Best Knowledge of Seller, created by any other Person) on, over or affecting the whole or any part of the business or assets of the Companies, (iii) there is no commitment by the Companies and to the Best Knowledge of the Seller, there is no fact giving or which could give rise to any such security or Encumbrance in favour of any Person, and (iv) to the Best Knowledge of the Seller, no claim, whether through legal proceedings or otherwise, has been made by any Person claiming to be entitled to any such right.

(c) Except as provided for in the Material Agreements, the Companies are not parties to and have no obligation (present or future) in respect of any third party guarantee, indemnity, letter of credit or loan.

4.3 Loans

(a) There will be, as of the Closing:

(i) no outstanding loans made by either Company to any member of the Seller’s Group; and

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(ii) no outstanding loans made to either Company by any member of the Seller’s Group.

(b) The Companies are not a party to any third party loan, banking and other credit facilities.

4.4 Contracts with Connected Persons

There will be at the Closing Date (following execution of the deed of termination, release and waiver referred to in Schedule 2) no contracts or arrangements between either Company, on the one hand, and any member of the Seller’s Group, on the other hand, other than the deed of termination, release and waiver referred to in Schedule 2, the Pioneer Services Agreement.

5. EMPLOYEES

(a) Seller has delivered to Buyer a true and complete list, as of the date of this Agreement, of all the Companies’ employees together with their job title, date of beginning of employment with the relevant Company and last annual salary (the “Employee List”) and each such employee’s employer is Pioneer Tunisia. Save as regards any new employees hired in accordance with Schedule 5 after the date of this Agreement or any dismissal, resignation or other termination of employment in accordance with Schedule 5, this list shall be true, complete and accurate at the Closing Date.

(b) As of the date hereof, no director, officer or employee of the Companies is under notice of redundancy or dismissal for any reason whatsoever and no amount due to any current or former director, officer or employee for any reason whatsoever is in arrears or unpaid other than salaries due for the current month.

(c) To the Actual Knowledge of Seller, no amount is due as of the date hereof in any respect whatsoever to former employees of the Companies following a redundancy, dismissal for personal reasons, resignation, or termination by mutual agreement.

(d) There is not, to the Best Knowledge of the Seller, outstanding any dispute between any of the Companies, on the one hand, and any of their respective employees, directors (or former employees or directors), or trade unions or similar organisation on the other hand. To the Actual Knowledge of Seller as of the date hereof, no such disputes or actions are threatened.

6. INSOLVENCY

6.1 No order

No order has been made or bona fide petition presented or resolution passed for the winding up or dissolution of the Companies or for the appointment of a liquidator or examiner to the Companies or any resolutions or officers analogous to them in any jurisdiction.

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6.2 No receiver/manager

No receiver (including any administrative receiver or other Person with a similar task) and/or insolvency or similar manager has been appointed by any Person over the whole or any part of the business or assets of the Companies.

6.3 Payment of debts

The Companies have not stopped paying or suspended payment of their debts as they fall due.

6.4 Composition or Schemes

No composition in satisfaction of the debts of either of the Companies, or scheme of arrangement of its affairs, or compromise or arrangement between it and its creditors or members or any class of its creditors or members, has been sanctioned or approved.

7. LITIGATION AND COMPLIANCE WITH LAW

7.1 Litigation

The Companies are not a party to any litigation, arbitration, legal proceedings or prosecution (or to the Best Knowledge of Seller), administrative or Tax investigation and at the date of this Agreement no such litigation, arbitration, proceedings or prosecution, investigation, or claim relating thereto is, to the Best Knowledge of the Seller, pending or, to the Actual Knowledge of Seller, threatened by or against the Companies. To the Best Knowledge of the Seller at the date of this Agreement there is no fact or circumstance which, to the Actual Knowledge of Seller, could reasonably be expected to give rise to such litigation, arbitration, proceedings or prosecution, investigation, or claim. For the avoidance of doubt, this paragraph 7.1 does not apply to Tax audits (which are the subject of paragraph 8.4).

7.2 Compliance with law

(a) As at the date of this Agreement the Companies are in compliance with all applicable Laws in the jurisdictions in which they have conducted business (including all applicable Tunisian environmental Laws).

(b) As at the date of this Agreement no written notice has been received by the Companies of any actual or alleged violation by the Companies of any applicable Law.

7.3 Constitution

The Companies have at all times carried on their business and affairs in accordance with their memorandum of association and articles of association or other relevant organisational and governance document for the time being.

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8. TAX

8.1 Tax liabilities

All Tax for which the Companies have been liable and which have fallen due for payment have been duly paid in a timely fashion. To the Best Knowledge of the Seller, none of the Companies is in dispute with any Tax Authority.

8.2 Tax returns

All notices, computations and returns which ought to have been given or made have been properly and duly made and submitted in timely fashion by the Companies to the relevant Tax Authority. All records which the Companies are required to keep for Tax purposes are complete and, to the Best Knowledge of Seller, accurate and have been duly and properly kept and are available for inspection at the premises of the respective Company.

8.3 Penalties and interest

The Companies do not have as of the date hereof any outstanding liability in respect of any interest, penalty, surcharge or fine relating to Tax.

8.4 Investigations

As of the date of this Agreement and to the Best Knowledge of Seller, the Companies are not subject to any non routine investigation or audit by any Tax Authority nor has any of the Companies been subject to such non routine investigation or audit within the last four years.

8.5 Tax Residence

(a) The Companies are not treated for any Tax purpose as resident of, or as having a branch, agency or permanent establishment in, a country other than (i) the country of their incorporation or (ii) Tunisia.

(b) The Companies (i) are and have always been exempted companies under Cayman Islands Law, (ii) do not hold and have never held real property or other assets in the Cayman Islands and (iii) do not and did never carry on business in the Cayman Islands.

8.6 Tax withholdings

The Companies have complied with all statutory provisions relating to Taxes which require the deduction of Taxes from any payment made by them, and have properly accounted to the appropriate Taxation Authority for any such Tax, which ought to have been accounted for.

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9. AGREEMENTS

(a) Complete copies of each:

(i) Material Agreement to which either Company is a signatory as of the date hereof; and

(ii) agreement which is material to the Companies’ business and to which either Company is a signatory or (to the Best Knowledge of the Seller) is otherwise bound as of the date hereof,

(iii) are contained in the Data Room.

(b) To the Best Knowledge of Seller, the Material Agreements (with the exception of the Key Agreements) are valid and subsisting.

(c) The Key Agreements are valid and subsisting.

(d) (i) To the Best Knowledge of the Seller, the Companies are not in breach of a Material Agreement and no fact or circumstance exists which is likely to give rise to such a breach.

(ii) To the Best Knowledge of the Seller and as at the date hereof, no other contracting party is in breach of a Material Agreement and no fact or circumstance exists which is likely to give rise to such a breach.

(iii) To the Best Knowledge of the Seller, all bonuses, Royalties, rentals and other payments due by the Companies under or for the purposes of any Key Agreement have been paid.

10. INTERESTS

(a) Subject to the provisions of the Key Agreements and the applicable Laws of Tunisia the Interests are free from any royalty, over-riding royalty or other Encumbrance created by the Companies or, to the Best Knowledge of the Seller, created by any other Person.

(b) Subject to the Key Agreements and the rights of any Governmental Entity of Tunisia pursuant to the applicable Laws of Tunisia, Pioneer Anaguid validly holds:

(i) a thirty percent (30%) undivided interest in:

(A) the Anaguid-Durra Application; and

(B) the Anaguid Exploration Permit; and

(ii) a Participating Interest (as defined in the Anaguid JOA) of sixty percent (60%) under the Anaguid JOA

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free from any Encumbrances or interests of third parties created by the Companies and to the Best Knowledge of Seller, free from any Encumbrances and interests of third parties created by any other Person.

(c) Subject to the Key Agreements and the rights of any Governmental Entity of Tunisia pursuant to the applicable Laws of Tunisia, Pioneer Tunisia validly holds:

(i) a twenty percent (20%) undivided interest in:

(A) the BEK-Adam Concession; and

(B) the BEK Exploration Permit;

(ii) a Participating Interest (as defined in the BEK JOA) of forty percent (40%) under the BEK JOA

(iii) a fifty percent (50%) undivided interest in:

(A) the JN-Cherouq Concession; and

(B) the JN Exploration Permit; and

(iv) a fifty (50%) undivided interest in the El Hamra Exploration Permit

free from any Encumbrances or interests of third parties created by the Companies and to the Best Knowledge of Seller, free from any Encumbrances and interests of third parties created by any other Person.

(d) (i) As of the date hereof, neither the Companies nor the Seller has received notice from any Tunisian Governmental Entity that the Interests were not validly and properly granted.

(ii) To the Best Knowledge of the Seller as of the date hereof, no fact or circumstance exists which would be expected to cause any such notice to be given.

(iii) To the Best Knowledge of the Seller, each of the Exploration Permits were properly, timely and validly renewed and/or extended.

(e) Minimum work commitments and Over-riding royalty interests:

(i) Except as set out in Schedule 20, as of the date hereof, all minimum work commitments (including seismic acquisition, explorations works, well drilling, etc.) (i) contained in the Key Agreements as well as (ii) in relation to the Transferred Well Obligation (as this expression is defined under the Joint Acquisition Agreement entered into by Pioneer Anaguid, Anadarko Tunisia Anaguid Company and Nuevo Anaguid Ltd on 1^st June 2002), have been fully, properly and timely performed.

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(ii) Except for the over-riding royalty interests referred to in the First Disclosure Letter, there is no other over-riding interest obligation or similar payment obligation burdening the Interests and created by the Companies or any member of the Seller Group (or to the Best Knowledge of the Seller created by any other Person) due to a previous owner of the Interests.

(iii) As of the date hereof and to the Best Knowledge of Seller, the Seller expects that the Anaguid-Durra concession will be granted in furtherance to the Anaguid-Durra Application which was filed in accordance with the applicable provisions of Tunisian Law.

(f) No written demand has been received by a guarantor from a beneficiary under a Guarantee in relation to the obligations guaranteed thereunder.

11. LICENCES

Without in any way limiting paragraph 10 of this Part I Schedule 3, to the Best Knowledge of the Seller as of the date hereof (a) the Companies have all permits, licences and authorities required by statute for the carrying on of their businesses or have obtained a waiver thereof from the relevant Governmental Entity and such permits, licences, authorities or waivers are in full force and effect and validly granted and (b) the Companies are not in breach of the terms of any such permit, licence , authority and waiver.

12. BROKERS

Neither the Seller nor the Companies has paid or is obligated to pay any fee or commission to any broker, finder or intermediary in connection with the transactions contemplated by this Agreement for which the Buyer may have any liability or the Companies may have any liability following Closing.

13. ENVIRONMENTAL MATTERS

(a) The Companies’ activities are not the source of any pollution or any damage to human health or the environment of any nature whatsoever.

(b) None of the land, premises or installations used or owned by the Companies is contaminated by any pollution.

(c) Except in relation to oil, gas, condensates, LPG or other products customary in the oil industry:

(i) no dangerous or toxic wastes or substances are or have been stored or treated by the Companies in violation of Law as of the date hereof on land belonging to or which has belonged to any of the Companies or which has been leased or used by them. None of the Companies has as of the date hereof transported or ordered the transportation of any dangerous or toxic wastes or substances in violation of Law; and

(ii) none of the Companies, has, as of the date hereof, violated any Law in the disposition of wastes from any product or packaging whatsoever

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outside of sites adapted for their storage, treatment, evacuation or destruction which are regulated by competent Government Entity for purposes of such operations.

(d) To the Best Knowledge of the Seller as of the date hereof, there are no judgments, orders, or injunctions of any nature whatsoever on the free use or disposal of the Companies’ movable or immovable assets arising from their environmental situation, and there are no facts or circumstances which may provide a basis for any such prohibition, injunction, restriction or limitation.

(e) All wells in which the Companies own an interest, and in respect of which either of the Companies carried out plugging and abandonment operations in its capacity as operator under the applicable JOA, have been plugged and abandoned in compliance with Tunisian Law and good international oilfield practice.

14. ABSENCE OF CERTAIN DEVELOPMENTS

Since the Effective Date until the date hereof, each of the Companies has conducted its business solely within the ordinary course of business and there has not been in relation to any of the Companies:

(a) any acquisition of assets or other capital investment for more than one million US dollars (US$1,000,000), otherwise than in the normal course of business;

(b) any declaration or payment of any dividend or any other distribution of profits or reserves;

(c) any material damage, destruction or other casualty loss (whether or not covered by insurance) affecting the business or financial position of any Company;

(d) any purchase or sale of securities or any issue of shares or other securities, rights or options to purchase or subscribe shares in any Company or which are capable of granting the right to acquire or subscribe securities which represent a share in the capital or a voting right of any Company;

(e) any third party loan incurred, granted, promised or secured by any of the Companies in excess of one million US dollars (US$1,000,000);

(f) the assumption of an obligation or liability other than obligations or liabilities incurred in the normal course of business;

(g) any termination, waiver, amendment of, or (to the Best Knowledge of the Seller) default by the Companies in relation to, any contract, undertaking or arrangement other than in the normal course of business;

(h) any change (except for salary increases or other items of employee remuneration made by virtue of applicable Laws or collective bargaining agreements) in the amounts or method of calculation of the salaries and other items of employee remuneration or the other terms of employment of any employees of the Companies nor any express commitment to do so nor any negotiation or claim in view of such changes;

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(i) any sale, lease or transfer of any tangible or intangible assets other than in the normal course of business, nor any cancellation or waiver of any receivables;

(j) any guarantee, surety or letter of comfort in respect of the obligations of third parties;

(k) any Encumbrance granted by the Companies over any tangible or intangible assets;

(l) any change in accounting methods, principles or practices unless required by a concurrent change in applicable Law;

(m) any amendment to the Companies’ memorandum of association, articles of association or other organisational documents;

(n) the entering into of any co-operation, partnership, joint venture or other similar agreements; and

(o) any undertaking to do any of the foregoing.

15. INTELLECTUAL PROPERTY RIGHTS

(a) To the Best Knowledge of the Seller, the Companies are not infringing, are not reasonably liable to infringe and have not in the past three years infringed any intellectual property or made unauthorised use of any rights in confidential business information of another person.

(b) To the Best Knowledge of the Seller as of the date hereof, none of the Companies’ intellectual property rights are being, or have been, infringed, attacked or opposed by any Person and no Person is making unauthorised use of confidential business information owned by any of the Companies.

(c) Except as set forth in Schedule 14, the Companies do not use any of the Seller's intellectual property rights in order to carry out their activities. and no license of any intellectual property rights from the Seller is necessary for the Companies to carry on their activities.

16. GENERAL

(a) Schedule 1, Schedule 9, Schedule 14 and Schedule 20 are true, accurate and complete as of the date hereof.

(b) To the Actual Knowledge of Seller as of the date hereof, Seller has not failed to disclose in the Data Room (unless otherwise disclosed in this Agreement or the First Disclosure Letter) any information that causes any other Warranty to be breached in any material respect.

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17. MERGER CONTROL

There are no merger control clearances required pursuant to the applicable Laws of the Cayman Islands or the United States of America in order to consummate the transactions contemplated by this Agreement.

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PART II

BUYER WARRANTIES

The Buyer warrants to the Seller that:

1. it is duly incorporated and validly existing and in good standing under the laws of Austria;

2. no resolution has been adopted providing for the dissolution or winding-up of the Buyer;

3. all corporate decisions relating to the Transaction have been taken in accordance with the Laws of Austria and internal rules applicable to the Buyer;

4. it has the legal right and full power and corporate authority to execute and deliver, and to exercise its rights and perform its obligations under this Agreement and each other Transaction Document to which it is party;

5. this Agreement constitutes valid and binding agreements of the Buyer;

6. the execution and delivery of, and the performance of its obligations under this Agreement will not result in:

(a) any violation of any Law of Austria or Order of any Governmental Entity of Austria;

(b) any breach of the articles of association or any other constitutional document of the Buyer;

(c) any calls for early repayment of any loans or financing granted to the Buyer; and

(d) save as specifically provided in this Agreement, any obligation to obtain any consent or approval of, or give any notice to or make any registration with, any Governmental Entity of Austria which has not been obtained or made at the date hereof (both on an unconditional basis and on a basis that cannot be revoked);

7. it has immediately available on an unconditional basis the necessary cash resources to meet its obligations under this Agreement;

8. No:

(a) order has been made or bona fide petition presented or resolution passed for the winding up or dissolution of the Buyer or for the appointment of a liquidator or examiner to the Buyer or any resolutions or officers analogous to them in any jurisdiction;

(b) receiver (including any administrative receiver or other Person with a similar task) and/or insolvency or similar manager has been appointed by any Person over the whole or any part of the business or assets of the Buyer; and

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(c) composition in satisfaction of the debts of either of the Buyer, or scheme of arrangement of its affairs, or compromise or arrangement between it and its creditors or members or any class of its creditors or members, has been sanctioned or approved;

the Buyer has not stopped paying or suspended payment of its debts as they fall due;

9. the Buyer is not party to any litigation, arbitration, legal proceedings or prosecution, administrative or Tax investigation and, at the date of this Agreement, no such litigation, arbitration, proceedings or prosecution, investigation, or claim relating thereto is pending or, to the Actual Knowledge of Buyer, threatened by or against the Buyer, any of which could adversely affect the Buyer’s ability to perform its obligations under this Agreement. At the date of this Agreement there is no fact or circumstance which, to the Actual Knowledge of Buyer, could reasonably be expected to give rise to such litigation, arbitration, proceedings or prosecution, investigation, or claim which could adversely affect the Buyer’s ability to perform its obligations under this Agreement;

10. the Buyer has not paid or become obligated to pay any fee or commission to any broker, investment banker, finder or intermediary in connection with the transactions contemplated by this Agreement for which any member of the Seller’s Group or the Companies may have any liability; and

11. there are no merger control clearances required pursuant to the applicable Laws of Austria in order to consummate the transactions contemplated by this Agreement.

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SCHEDULE 4

RELEVANT CLAIMS

The terms and provisions of this Schedule 4 apply from and after Closing (including with respect to any Relevant Claims in connection with Clause 8.3).

1. QUANTITY LIMITATIONS

1.1 The Seller shall not be liable for any Relevant Claim:

(a) where the liability of the Seller for any particular claim (or the aggregate liability of the Seller for several related claims) whether relating to Pioneer Anaguid and/or Pioneer Tunisia is less than three hundred and fifty thousand US dollars (US$350,000) (such claims being “de minimis claims”) provided that once the threshold set forth in paragraph 1.1(b) of this Schedule 4 is exceeded the Seller shall not be liable for any Relevant Claim where the liability of the Seller for any particular claim (or the aggregate liability of the Seller for several related claims) is less than five hundred thousand US dollars (US$500,000) and each such claim which does not so exceed five hundred thousand US dollars (US$500,000) shall constitute a “de minimis claim” provided further that any claim which constitutes a de minimis claim shall not count or be taken into consideration when determining whether the threshold set forth in paragraph 1.1(b) of this Schedule 4 has been exceeded; and

(b) where the aggregate liability of the Seller for all Relevant Claims that are not de minimis claims does not exceed a threshold amount equal to 2% of the Adjusted Bid Amount, provided that once the aggregate amount of all such claims (excluding all de minimis claims) exceeds such sum the Seller shall be liable for:

(i) 50% of the threshold amount referred to in this paragraph 1.1(b) of Schedule 4 and the Seller shall pay such amount to the Buyer within twenty (20) Business Days of being notified by the Buyer that the threshold amount referred to in this paragraph 1.1(b) has been exceeded and receipt by the Seller from the Buyer of reasonable documentation evidencing that the threshold has been exceeded; and

(ii) subject to the other limitations set forth in this Agreement, any excess liability over and above the threshold amount referred to in this paragraph 1.1(b) of Schedule 4.

1.2 The aggregate liability of the Seller in respect of:

(a) all Relevant Claims in respect of paragraphs 1 and 2.1, and, subject to paragraph 1.2(b) below, paragraph 9(c) and 10(a), 10(b), 10(c) and 10(d) of Part I of Schedule 3 shall not in any event exceed, in the aggregate, an amount equal to the Adjusted Bid Amount;

(b) all Relevant Claims in respect of the Warranties in paragraphs 9(c), 10(a), 10(b), 10(c) and 10(d) of Part I of Schedule 3 shall not in any event exceed, in the aggregate, an amount equal to the value allocated to the particular Interest (as set forth in Schedule 18) affected by such breaches of Warranty;

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(c) except as provided in paragraph 1.2(a) of this Schedule 4, all Relevant Claims shall not in any event exceed, in the aggregate, an amount equal to fifty percent (50%) of the Adjusted Bid Amount; and

(d) all Relevant Claims referred to in (a), (b) and (c) of this paragraph 1.2 shall not in any event exceed, in the aggregate, an amount equal to the Adjusted Bid Amount.

2. TIME LIMITS

2.1 The Seller shall not be liable in respect of any Relevant Claim unless written notice of it shall have been given to the Seller:

(a) in the case of a Relevant Claim in respect of the Tax Warranties or arising under Schedule 7, before (i) 3 months following the expiry of the applicable statutory limitation period relevant to the raising of any Tax assessments by the relevant Tax Authority or (ii) if later, 3 months following the date on which any decision from any relevant court or authority or any arbitration award in relation to the matter forming the basis of any such Relevant Claim has become final and non appealable, provided that Buyer gives notice to the Seller of the matter giving rise to such decision, sentence or settlement before three (3) months following the expiry of the applicable statutory limitation period relevant to the raising of any Tax assessments by the relevant Tax Authority; or

(b) in the case of any other Relevant Claim, before the date falling eighteen (18) months after the Closing.

2.2 A Relevant Claim notified in accordance with paragraph 2.1 above and not satisfied, settled or withdrawn shall be unenforceable against the Seller on the expiry of the period of 6 months starting on the day of notification of the Relevant Claim, unless proceedings in respect of the Relevant Claim have been issued and served on the Seller within that period, in which case the rights of the Party seeking indemnification or recovery with respect to such Relevant Claim shall survive until such time as such Relevant Claim is finally resolved.

3. EXCLUSIONS

3.1 The Seller shall not be liable for any Relevant Claim:

(a) if the subject matter thereof or matter giving rise thereto has been disclosed in accordance with Clause 8.1:

(i) in the First Disclosure Letter;

(ii) except as set forth in Clause 3.2(b), in the Second Disclosure Letter; or

(iii) in the Data Room;

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(b) if the Buyer or any member of the Buyer’s Group recovers from some other Person (including insurers and third parties) any sum in respect of any matter or event which has given rise or could give rise to a Relevant Claim, any sum so recovered will reduce the amount of the Relevant Claim. In the event of the recovery being delayed until after satisfaction by the Seller of its relevant indemnification or other liability hereunder, an amount equal to the sum so recovered by the Buyer or any member of the Buyer’s Group, shall be paid to the Seller, but only up to the amount paid by the Seller in respect of such Claim.

3.2 The Seller shall not be liable in respect of any Relevant Claim if and to the extent that:

(a) it is attributable to some act, omission, transaction or arrangement carried out by the Seller after the Effective Date on behalf of the Buyer or a member of the Buyer’s Group, in accordance with Schedule 5, or after the date of Closing, by the Buyer or by a member of the Buyer’s Group or by either Company or any of their respective successors in title;

(b) such claim is attributable to or increased by any admission of liability made after the date hereof by the Buyer’s successors in title or by a member of the Buyer’s Group or by Persons acting on their behalf;

(c) the claim arises or is increased as a result of:

(i) an increase in rates of Tax, or new Tax, relating to periods after the Effective Date;

(ii) any administrative or judicial decision, or practice or any uncertainties, inconsistencies or changing interpretations of Law or regulations or administrative process on or after the Effective Date or any change in the practice of any Tax Authority or the practices or policies of any recognised accounting body on or after the Effective Date;

(iii) any failure of federal, regional or local legislative, executive and/or judicial authorities to fully implement and give effect to the Key Agreements or other contract or permit after the Effective Date;

(iv) the passing of any primary or subordinate legislation or Law, or making of any other government regulation, not in force at the Effective Date or the withdrawal or alteration after the Effective Date of any published extra statutory concession made by any fiscal authority and currently in operation;

(v) the failure or omission on the part of the Buyer and/or either Company after Closing (except where such failure or omission is attributable to the Seller) to file all necessary Tax returns and computations required to be filed by it or to submit such returns and computations within the appropriate time limits and on a proper basis; or

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(vi) either Company waiving or surrendering after the date of Closing any Relief from Tax available to it;

(d) the matter giving rise to the Relevant Claim was taken into account in the Accounts or the 2010 Accounts or was included in a provision appropriate under generally accepted accounting principles in the United States in force at the Effective Date;

(e) the claim would not have arisen but for anything expressly provided to be done or omitted to be done pursuant to this Agreement or which is otherwise done or omitted to be done at the written request or with the written consent of the Buyer prior to Closing;

(f) the claim would not have arisen but for (or if the same claim is increased by reason of) a breach by the Buyer of any of its obligations under this Agreement;

(g) it involves the winding up, cessation of trade, change in the trade or business of either Company after Closing or any re-organisation or change in ownership of any member of the Buyer’s Group after Closing;

(h) it involves a failure to utilise any payments received by the Buyer to discharge liabilities to which the claim giving rise to the payment relates;

(i) such claim would (but for this paragraph 3.2(i) of Schedule 4) involve a breach of any operational activities or duties under paragraph 1(a) or 1(b) of Schedule 5 but neither Company shall have any liability under the applicable JOA (or, where the affected Interest is not subject to a JOA, then under a hypothetical joint operating agreement similar to the Anaguid JOA) as a result of a breach of such operational activities or duties;

(j) to the extent that the claim arises in connection with a claim made by a third party between the date of this Agreement and the Closing Date (both dates inclusive) where (i) such claim relates to an occurrence or event which occurred prior to the Effective Date or otherwise relates to an occurrence or event which had its origin prior to the Effective Date and (ii) to the extent that the Buyer took or omitted to take (or instructed the Seller to take or omit to take) any action since the date hereof which resulted in an increase in the liability of the Seller in connection with such occurrence or event. In this case, the Seller shall not be liable for the amount of the increased liability only; or

(k) the claim arises or is increased as a result of the Buyer taking or omitting to take any action since the execution and delivery of this Agreement that results in an increase to the liability of the Seller in connection with such Loss in which case the Seller shall not be liable for the amount of the increased liability only.

3.3 For the avoidance of doubt, any approval of the annual accounts for any fiscal year expiring on or prior to the Effective Date by the Companies shall have no effect on any potential indemnification liability of the Seller.

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3.4 No claim may be made by the Buyer under a Warranty to the extent that, to the Actual Knowledge of Buyer prior to signing this Agreement and from a source other than the Data Room, such Warranty was breached.

3.5 If any Relevant Claim under this Agreement relates to a liability that is contingent only (a “Contingent Liability”), the Seller shall not be under any obligation to make any payment to the Buyer in connection therewith unless the contingent liability is notified by the Buyer to the Seller in accordance with Clause 8.5 and ceases to be contingent and becomes an actual liability within a period of twenty four (24) months after the Closing. For the avoidance of doubt, if a Contingent Liability does not become an actual liability within such twenty four (24) month time period, such Contingent Liability shall not be the basis for a Relevant Claim and the Seller shall have no liability with respect to such Contingent Liability or any claim relating thereto under this Agreement. For the purposes of this provision, a Contingent Liability means any breach of Warranty which does not result in a Loss for the Buyer, the Companies or a third party at the time the Relevant Claim is made, it being understood that a liability shall not be deemed to be contingent solely because the quantum of Losses which may arise in relation to such Relevant Claim are unascertainable.

4. THIRD PARTY CLAIMS

4.1 If the Buyer receives written notice of the commencement or assertion of any proceeding, claim or investigation by a third party which could give rise to a Relevant Claim and if such claim is as a result of or in connection with a claim against either Company by, or a liability of either Company to, a third party (a “Third Party Claim”), the Buyer shall give written notice thereof (a “Claims Notice”) to the Seller as soon as practicable. The Claims Notice shall describe the Third Party Claim in sufficient detail to enable to Seller to determine the effect of such proceeding, claim or investigation or otherwise attach a copy of the notice received from the Third Party, and shall indicate the amount (reasonably estimated, if necessary) of the Losses that have been or may be suffered.

4.2 The Buyer shall assume control of and appoint lead counsel for the defence of such Third Party Claim. However, if it appears that, after taking into consideration the financial limitations on liability set forth in paragraphs 1.1(b) and 1.2 of this Schedule 4 the Seller bears the greatest financial exposure in the event that the Third Party Claim is successful, the Seller shall be entitled to serve written notice on the Buyer (setting forth the reasons why the Seller believes that it has the greater financial exposure) within fifteen (15) Business Days of Seller’s receipt of the Claims Notice informing the Buyer that the Seller elects to assume control of such Third Party Claim. Pending any receipt of written notice from the Seller after the issuance of a Claims Notice, the Buyer shall assume control of such Third Party Claim provided, however, in the event that during the course of such Third Party Claim the threshold set forth in paragraph 1.1(b) of Schedule 4 would be reasonably likely to be exceeded, the Buyer shall notify the Seller and the Seller shall have the right to take over and assume control of the Third Party Claim.

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4.3 If the Seller assumes the control of the defence of the Third Party Claim in accordance with the provisions of this paragraph 4 of Schedule 4, the Buyer shall:

(a) provide to the Seller and its advisers (to the extent allowed under the applicable Laws) reasonable access to relevant documents and records within the Buyer’s and/or the Companies’ power or control for the purpose of enabling the Seller to investigate the matter;

(b) procure that each Company shall use its reasonable endeavours to procure that the professional advisers (both past and present) of either Company makes available to the Seller and its professional advisers their working papers in respect of each Company’s accounts for any relevant accounting period in connection with any Relevant Claim, to the extent allowed under applicable Laws;

(c) procure that both Companies shall take any action and institute any proceedings, and give reasonable information and assistance, as the Seller may reasonably request to dispute, resist, appeal, compromise, defend, remedy, settle or mitigate the matter or enforce against a Person the rights of the Buyer or the Companies in relation to the matter; and

(d) be entitled to participate, at its own cost and expense, in the defence of such Third Party Claim and to employ separate counsel of its choice for such purpose. The fees, costs and expenses of any such separate counsel to the Buyer pursuant to this paragraph 4 of Schedule 4, shall be paid by the Buyer.

4.4 If the Buyer shall control the defence of the Third Party Claim in accordance with the provisions of this paragraph 4 of Schedule 4, the Seller shall nevertheless be entitled to participate, at its own cost and expense, in the defence of such Third Party Claim and to employ separate counsel of its choice for such purpose. The fees, costs and expenses of any such separate counsel to Seller pursuant to this paragraph 4 of Schedule 4, shall be paid and borne by the Seller. In addition, if the Buyer shall control the defence of the Third Party Claim in accordance with the provisions of this paragraph 4 of Schedule 4, the Buyer shall keep the Seller reasonably informed of any actual or proposed developments (including any meetings) and shall provide the Seller with copies of all correspondence and documentation relating to such Third Party Claim, matter or action, and such other information, assistance and access to records and personnel as the Seller reasonably requires and shall furthermore consult with the Seller before taking any significant decision or action affecting the defence or settlement of the Third Party Claim, the filing of pleadings and motions, the submission of any material correspondence and the selection of venue or forum.

4.5 Neither the Seller nor the Buyer shall settle a Third Party Claim in excess of three hundred and fifty thousand US dollars (US$350,000) (or the equivalent thereof in any other currency) without reasonable prior notice to and consultation with, and the written consent (not to be unreasonably withheld, delayed or conditioned) of, the other. Without prejudice to the generality of the foregoing, the Seller shall obtain the prior written consent of the Buyer (which shall not be unreasonably withheld, conditioned or delayed) before entering into any settlement, compromise, admission or acknowledgement of the validity of such Third Party Claim if the settlement does not unconditionally release the Buyer and its affiliates from all liabilities and

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obligations with respect to such Third Party Claim, if the settlement requires any payment by the Buyer or any member of the Buyer’s Group or if the settlement imposes injunctive or other equitable relief against the Buyer or any member of the Buyer’s Group or acknowledges culpable conduct by the Buyer or any member of the Buyer’s Group and the Buyer shall obtain the prior written consent of the Seller (which shall not be unreasonably withheld, conditioned or delayed) before entering into any settlement, compromise, admission or acknowledgement of the validity of such Third Party Claim if the settlement does not unconditionally release the Seller and its affiliates from all liabilities and obligations with respect to such Third Party Claim, if the settlement requires any payment by the Seller or any member of the Seller’s Group pursuant to any Transaction Document or otherwise, or if the settlement imposes injunctive or equitable relief against the Seller or any member of the Seller’s Group or acknowledges culpable conduct by the Seller or any member of the Seller’s Group. For the avoidance of doubt and notwithstanding any provision to the contrary contained herein, any settlement agreement entered into by the Buyer pursuant to this paragraph 4 of Schedule 4 shall in no event relieve the Seller from its obligation to indemnify the Buyer in accordance with this Agreement.

4.6 Each of the Seller and the Buyer shall cooperate, and cause their respective affiliates (and in any event the Buyer shall cause the Companies) to cooperate, in the defence or prosecution of any Third Party Claim and the assumption of control of the defence of any Third Party Claim as provided in this paragraph 4 of Schedule 4 and shall furnish or cause to be furnished such records, information and testimony (subject to any applicable confidentiality agreement), and attend such conferences, discovery proceedings, hearings, trials or appeals as may be reasonably requested in connection therewith.

5. RECOVERY FROM THIRD PARTIES

5.1 If Buyer delivers notice of a Relevant Claim and the Buyer or either Company (or any affiliate of any of them) either receives, or is entitled or may be entitled either immediately or at some future date to recover or obtain, from any Person (other than the Buyer, a Company or any such affiliate) a payment in connection with the liability that gave rise to such Relevant Claim, then:

(a) the Buyer shall notify the Seller of that fact as soon as possible and if so required by the Seller shall take (or shall procure that the relevant Company or other Person concerned shall take) such action as the Seller may reasonably request to enforce such recovery or to obtain such payment (keeping the Seller reasonably informed of the progress of any action taken and providing it with copies of all relevant correspondence and documentation) provided that the Buyer shall not be required to pursue any appeal of any determination by an arbitral panel or court except that where such determination is not satisfactory to the Seller, the Buyer shall assign, to the extent such rights are assignable, to the Seller (at the Seller’s sole discretion) any and all rights of the Buyer to pursue or appeal the claim against the relevant arbitral panel or court; and

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(b) if the Buyer, a Company or other Person concerned receives or obtains such a payment, the Buyer shall promptly pay to the Seller:

(i) where the amount received is less than the liability paid by the Seller under the Relevant Claim, the entire amount received; or

(ii) where the amount received exceeds the liability paid by the Seller under the Relevant Claim, the liability paid by the Seller under the Relevant Claim.

6. NO DOUBLE RECOVERY

The Buyer shall not be entitled to recover any amount pursuant to any Transaction Document in respect of any claim to the extent that the Buyer and/or either Company has already recovered any amount in respect of such claim.

7. MITIGATION

7.1 Nothing in any Transaction Document shall or shall be deemed to relieve the Buyer of any common law duty to mitigate any Loss or damage incurred by it or either Company or the Seller of any common law duty to mitigate any Loss or damage incurred by it.

7.2 Without prejudice to the generality of the foregoing, the Buyer shall, and shall procure that each Company shall, before seeking to recover any amount from the Seller, at the request of the Seller, first use all reasonable endeavours to recover any Loss or damage which it may suffer in consequence of any matter giving rise to a Relevant Claim (or capable of doing so) from any third party or third parties (including any insurer with whom the Buyer and/or either Company has insurance) from whom the Buyer and/or either of the Companies is or may be entitled to recover all or part of such Loss or damage; provided, however, that the Seller shall be liable for all reasonable costs incurred by the Buyer and/or the Companies in connection with any action taken pursuant to this paragraph 7.2.

7.3 Without prejudice to the generality of the foregoing, the Seller shall before seeking to recover any amount from the Buyer, at the request of the Buyer, first use all reasonable endeavours to recover any Loss or damage which it may suffer in consequence of any matter giving rise to a claim (or capable of doing so) from any third party or third parties (including any insurer with whom the Seller has insurance) from whom the Seller is or may be entitled to recover all or part of such Loss or damage; provided, however, that the Buyer shall be liable for all reasonable costs incurred by the Seller in connection with any action taken pursuant to this paragraph 7.3.

8. ASSIGNMENT OF RECOVERY RIGHTS

In the event of any Relevant Claim by the Buyer succeeding and any payment being made by the Seller pursuant thereto, the Buyer will, and/or (as the case may be) will procure that each Company will assign or procure the assignment to or to the order of the Seller, of all rights of reimbursement, actions and indemnities against third parties in respect of the subject matter of such claim (to the extent possible under the applicable Laws).

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9. NO LIMITATION FOR FRAUD

Notwithstanding any other provision of this Agreement, no limitation of any kind whatsoever referred to in paragraphs 1 or 2 of this Schedule 4 shall apply in respect of any Relevant Claim made against the Seller if:

(a) such claim arises from a fraud committed by the Seller; provided, however, no claim of fraud may be made (or considered) in determining whether or not fraud exists or the amount of any damages arising from fraud unless the Relevant Claim in question constitutes a material breach of a Warranty or covenant by the Seller; and

(b) the Buyer has proved beyond a reasonable doubt that such fraud was committed by the Seller.

10. GROSS-UP

Where the Seller is liable to pay an amount to the Buyer in connection with any Relevant Claim, the Seller shall ensure that such amount is grossed-up or paid free of any U.S. tax withholdings or any bank transfer charges and other similar fees, expenses and charges levied on the Seller in connection with the payment of such amounts.

11. ASSESSMENT

Until the later of:

(a) expiry of the time limits set forth in paragraph 2.1(a) of Schedule 4; and

(b) settlement and final and binding determination of all Relevant Claims,

the Parties shall, at the Seller’s election, meet no later than once every three (3) months to assess and discuss the status of any actual, pending or threatened claims or proceedings for which the Seller could be liable and the Buyer’s view of the aggregate amount of claims that are then subject to paragraph 1.1(b) of this Schedule 4 in order to enable the Seller to assess whether or not it should take over the conduct of any claims provided that such meetings shall not constitute a formal or an implicit waiver of any of the Buyer’s rights to recover Losses under this Agreement nor shall any information given or opinion expressed by the Buyer or relied upon by the Seller, relieve the Seller from its obligations hereunder or otherwise reduce its indemnification liability if any.

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SCHEDULE 5

INTERIM PERIOD

1. Until Closing the Seller shall procure that except with the written consent of the Buyer (not to be unreasonably conditioned, withheld or delayed), the Companies shall:

(a) conduct activities relating to the Interests in the ordinary course of business and consistent with good international oilfield practice;

(b) comply with all applicable Laws and each Material Agreement;

(c) not dispose of, or create any Encumbrance in respect of, the Interests or the Shares;

(d) not do or knowingly omit to do anything which would reasonably be expected to result in the termination, revocation, suspension, modification, amendment or non-renewal of any Material Agreement (except any such modification or amendment that is immaterial);

(e) not create, issue, purchase or redeem any class of share capital; and

(f) not:

(i) create, incur or assume any long term debt other than (x) any such debt that is repaid in full by the Seller prior to Closing or any other such debt that is permitted pursuant to paragraph 6 of this Schedule 5 or (y) as a result of any inter company funding provided by the Seller Group in the ordinary course of business;

(ii) provide any guarantee of any debt other than any guarantee terminated prior to Closing;

(iii) amend their respective memorandum of association and articles of association;

(iv) undertake any merger, spin-off, contribution or other form of reorganisation;

(v) propose, declare or pay any dividend or otherwise distribute any profit or dividend, except up to thirty seven million US dollars (US$37,000,000) in Dividends (in aggregate) provided that Pioneer Tunisia holds sufficient cash amount to carry out such distribution and that no loan or other credit facility will be required in order to implement such distribution;

(vi) save for increases which are consistent with past practice and in the ordinary course of business or mandatory under applicable labour Law, increase or undertake to increase the compensation payable or other benefits due (including salaries, profit-sharing, pension or retirement rights or other similar benefits) to any employee, director or officer (whether or not having employee status) of the Companies

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that is payable by the Companies nor shall the Companies hire any employee unless it is undertaken in the ordinary course of business or dismiss any corporate officers or executive employees save in the case of serious misconduct (faute grave/lourde) and after consulting the Buyer;

(vii) enter into any contracts which are subject to unduly onerous terms, or which are outside the normal course of business of the Companies concerned, or which are not at arms’ length, nor terminate any material business relationship (other than expiry in accordance with its terms);

(viii) undertake any material non routine expenditure, save (i) where such expenditure is essential to preserve the value of an asset of the relevant Company or (ii) where provided in the Companies’ work programmes or approved budgets (to the extent copies of such work programmes and approved budgets are in the Data Room), nor transfer any of its assets except in the usual and prudent course of business;

(ix) grant any security interests with respect to the obligations of a third party;

(x) surrender nor voluntarily relinquish any of the surface area covered by the Exploration Permits or by the Concessions, nor commit to any additional work which has not been disclosed in the Data Room; and

(xi) undertake to do any of the foregoing.

2. Until Closing the Seller shall:

(a) advise the Buyer regarding the exercise of the Companies’ material rights under any Material Agreements after the date hereof, where such exercise has materially departed from the ordinary course of business;

(b) advise reasonably in advance (to the extent practicable) the Buyer regarding any significant operation that is to be discussed in any operating committee, in particular in any committee set up under the Key Agreements, and shall consult with the Buyer with a view of agreeing upon the decision to be taken and the vote to be made. Failing such agreement, the Seller undertakes to vote on significant operations according to the Buyer’s instructions provided that such vote would neither entail additional expenses nor liabilities for the Seller or the Companies or obligate the Companies or the Seller to future expenditures or liabilities, and that instructions given by the Buyer are not manifestly contrary to a sound conduct of petroleum operations, provided that Buyer shall not have the right to veto any action proposed by Seller if such action is reasonable (provided that at the request of Buyer, Seller shall use reasonable efforts to defer the taking of the action unless Seller or the Companies would be materially prejudiced by the deferral);

(c) provide the Buyer with copies of written proceedings of the relevant operating committee meetings and technical committee meetings after the date hereof as

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and when prepared in the ordinary course of business consistent with the Companies’ past practices and of any written communication with ETAP or any Tunisian Government Entity regarding the Transaction and the Material Agreements;

(d) notify forthwith to the Buyer in writing if any Material Adverse Event has, to the Actual Knowledge of Seller, occurred or materialized after the date hereof with a reasonable description (based on facts then known by Seller) of such Material Adverse Event; and

(e) promptly inform the Buyer of any material action or decision made by any of the Companies in its capacity as operator under the JN Exploration Permit, the El Hamra Exploration Permit and/or the Anaguid Exploration Permit or otherwise in relation to any of the Interests.

3. Neither the Seller nor the Companies will make or offer, with respect to the matters which are the subject of this Agreement or in relation to the Interests, any payment, gift, promise or other advantage, whether directly or through any other Person, to or for the use or benefit of any public official or any political party or political party official or candidate for office, where such payment, gift, promise or advantage would violate (i) the applicable Laws of Tunisia; (ii) the Laws of the country of incorporation or principal place of business of the Companies; (iii) the U.S. Foreign Corrupt Practices Act of 1977 or (iv) the principles described in the Convention on Combating Bribery of Foreign Public Officials in International Business Transactions, signed in Paris on December 17, 1997.

4. Access to the Companies

(a) Between the date hereof and the Closing Date, the Buyer and its representatives (including its auditors and legal advisors) shall, upon giving a reasonable notice, have access (at the Buyer’s sole cost and risk) to the employees, advisers, accountants, properties, assets, books and records of the Companies during normal business hours, in order to ensure a smooth transition and transfer of ownership and to protect the Interests or any of its rights arising out of this Agreement.

(b) For the avoidance of doubt, it is hereby specified that any inspections or visits by the Buyer and/or persons designated by the Buyer shall have no effect on any potential indemnification liability.

5. Relationship with the Seller’s Group

(a) Following the Closing, the Seller waives, on behalf of itself and the Seller’s Group, its rights to repayment of any amount due prior to the Closing Date by a Company to the Seller.

(b) At the latest by the Closing Date, the Seller shall terminate or ensure termination of, without any indemnity or other obligation for the Companies (include any notice periods), all contracts and other arrangements between (i) the Seller and any and all of the Seller’s Group, on the one hand, and (ii) any and all of the Companies, on the other hand.

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(c) At the latest by the Closing Date, the Seller shall have obtained the release from all guarantees and other security interests granted by any of the Companies to the benefit of the Seller or any of the Seller’s Group.

6. Notwithstanding the limitations on Seller as provided above, the Seller or the Companies, as applicable, shall be entitled to carry out any action listed below:

(a) required under a contract to which either Company is bound;

(b) required to satisfy a work obligation required by any Governmental Entity in Tunisia;

(c) required by applicable Law or required to maintain any Interest;

(d) required pursuant to an emergency procedure or for the preservation and/or safety of lives or property or the environment;

(e) otherwise consented to by the Buyer in writing (and where the Seller requires the Buyer’s consent and the Buyer fails to notify Seller in writing (within five (5) Business Days after the receipt by the Buyer of a reasonable request from the Seller for consent) that Buyer does not so consent and the basis for not granting its consent, then Buyer shall be deemed to have consented);

(f) constituting a transfer of amounts and the settlement of any inter-company payables and/or inter-company receivables (i) between the Companies and/or (ii) between any member of the Seller’s Group and either or both of the Companies, in each case after the Effective Date; or

(g) as otherwise agreed to by the Buyer and the Seller in writing,

provided, however, that where the action to be performed is material then the Seller shall notify the Buyer in advance of performing such action except where such a notification is impractical under the circumstances in which case the Seller shall notify the Buyer of the action performed as soon as reasonably practicable after performing such action. For the avoidance of doubt, any prior notification by the Seller to the Buyer of any action to be carried out pursuant to this paragraph 6, shall not deprive the Buyer of its right to claim Material Adverse Event.

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SCHEDULE 6

WORKING CAPITAL CALCULATION

and

ADJUSTED BID AMOUNT

1. Working Capital calculation

The Working Capital is calculated based on the Accounts and the 2010 Accounts, respectively, of the Companies. It is understood that for the purpose of this Working Capital calculation the Accounts and 2010 Accounts are consolidated and any intercompany profit is eliminated. Working Capital shall be defined as follows:

Cash and Cash Equivalents

Plus 55% (in words “fifty-five percent”) of the portion of the ETAP Receivables attributable to the Anaguid Interest / Pioneer Anaguid included in Other Non-Current Assets

Plus 70% (in words “seventy percent”) of the portion of the ETAP Receivables attributable to the BEK Interest / Pioneer Tunisia included in Accounts Receivable - Trade Other and Other Non-Current Assets

Plus 55% (in words “fifty-five percent”) of the portion of the ETAP Receivables attributable to the JN Interest / Pioneer Tunisia included in Other Current Assets and Other Non-Current Assets (for purposes of the 2010 Accounts, determined in accordance with Clause 5.2)

Plus deposits included in Other Non-Current Assets

Plus Accounts Receivable Oil & Gas

Plus Accounts Receivable Trade Other, excluding ETAP Receivables

Plus Inventories

Plus Prepaids

Less Accounts Payable Affiliates

Less Accounts Payable Trade

Less Other Current Liabilities (including other provisions if any)

Less            Current Income Taxes (including current tax provisions if any)

= Working Capital

For the avoidance of doubt Working Capital excludes Deferred Income Taxes and accrued abandonment obligations.

The above mentioned terms shall have the meaning ascribed to them in the Accounts and 2010 Accounts.

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For the avoidance of doubt, the amount of the ETAP Receivables to which the Buyer may apply the discount noted above, shall be the amount noted or set aside for the ETAP Receivables in the Accounts and 2010 Accounts and the Buyer shall not be entitled to apply any further discount to the amount attributable to ETAP Receivables (including whether arising as a result of an audit by ETAP or any other Governmental Entity of Tunisia).

2. Adjustment of the Bid Amount

2.1 Calculation:

Adjusted Bid Amount = Bid Amount + ( 2010WC – WCn)

Where:

(i) 2010 WC means the Working Capital as appearing in the 2010 Accounts; and

(ii) WCn means the Working Capital as appearing in the Accounts.

2.2 Payment:

If Adjusted Bid Amount – Bid Amount > 0: the Buyer shall pay to the Seller, within the five (5) Business Day period provided for in Clause 5, an amount equal to:

Adjusted Bid Amount - Bid Amount

If Bid Amount – Adjusted Bid Amount > 0: the Seller shall pay to the Buyer, within the five (5) Business Day period provided for in Clause 5, an amount equal to:

Bid Amount – Adjusted Bid Amount.

If Adjusted Bid Amount – Bid Amount = 0: the Bid Amount shall not be adjusted.

3. Pre-emption

Where the preferential right under the Anaguid JOA is exercised and the Closing under this Agreement involves only the acquisition of the entire issued share capital of Pioneer Tunisia by the Buyer, Working Capital calculations shall be determined without any reference to any Working Capital of Pioneer Anaguid and shall be determined on the basis of the Working Capital attributable to Pioneer Tunisia only.

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Working Capital

As at the Accounts Date (US$)

		Pioneer Tunisia		Pioneer Anaguid
	Cash and Cash Equivalents		47,174,927		2,182,900
Plus:	Accounts Receivable - Oil & Gas		19,150,454		—
	Accounts Receivable Trade Other, excluding ETAP Receivables		6,125,671		—
	Inventories		15,440,017		10,325
	Prepaids		1,440,380		—
	Deposits included in Other Non-Current Assets		442,629		—
	ETAP Receivables (55%) attributable to the Anaguid Interest / Pioneer Anaguid included in Other Non-Current Assets		—		7,015,139
	ETAP Receivables (70%) attributable to the BEK Interest / Pioneer Tunisia included in Accounts Receivable – Trade Other and Other Non-Current Assets		3,576,917		—
	ETAP Receivables (55%) attributable to the JN Interest / Pioneer Tunisia included in Other Current Assets and Other Non-Current Assets		16,059,416		—
Less:	Accounts Payable – Trade		22,088,017		4,361,288
	Accounts Payable – Affiliates		3,883,130		10,436,711
	Other Current Liabilities (including other provisions if any)		10,060,472		—
	Current Income Taxes		2,097,094		—
	Total		71,281,698		(5,589,635	)
	Combined		65,692,063

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SCHEDULE 7

TAX COVENANT

1. COVENANT TO PAY

1.1 The Seller hereby covenants to the Buyer to indemnify the Buyer against:

(a) Any Tax Liability which arises in respect of or in consequence of (i) any income, profits or gains earned, accrued or received before the Effective Date; or (ii) any production, act or transaction which occurred before the Effective Date; and

(b) any liability which arises in respect of or in consequence of any underpayment or non-payment of Royalty in respect of any production, act or transaction which occurred before the Effective Date (“Royalty Liability”);

together with all documented costs and expenses reasonably and properly incurred by the Buyer in connection with a successful claim by the Buyer under this Schedule.

1.2 After demand (which demand shall be made no earlier than two months prior to the first date on which the Tax Liability or Royalty Liability becomes recoverable by the relevant Tax Authority), the Seller shall pay to the Buyer any amount payable under paragraph 1.1 on or before the date which is the earlier of the date:

(a) twenty (20) Business Days after demand is made therefor by the Buyer; or

(b) two (2) Business Days before the first date on which the Tax or Royalty becomes recoverable by the relevant Tax Authority.

2. EXCLUSIONS

2.1 By way of addition to the limitations and exclusions set forth in Clause 8.2(e) and 8.2(f) and Schedule 4, paragraph 1.1 shall not apply to the extent that:

(a) provision or reserve in respect of the Tax Liability or Royalty Liability, as applicable, has been made in the 2010 Accounts; or

(b) the Tax Liability or Royalty Liability, as applicable, was paid or discharged before the Effective Date; or

(c) the Tax Liability or Royalty Liability, as applicable, arises as a result of any change in rates of Tax or Royalty made after the Effective Date or of any change in Law (or a change in interpretation on the basis of case law), regulation, directive or requirement, or the practice of any Tax Authority, occurring after the Effective Date and exclusively relating to Taxes or Royalties that relate to periods after the Effective Date; or

(d) the Tax Liability or Royalty Liability, as applicable, would not have arisen but for a transaction, action or omission carried out or effected by any of the Buyer, a Company, or any affiliate of any of them, at any time after the Effective Date, except that this exclusion shall not apply where any such transaction, action or omission is carried out or effected by the Company concerned pursuant to a legally binding commitment created on or before the Effective Date; or

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(e) any Relief from Tax or Royalty previously unutilised is available, or is for no consideration made available by the Seller, to either Company to set-off or otherwise mitigate the Tax Liability or Royalty Liability, as applicable, the subject of such claim or to which the liability relates; or

(f) the Tax Liability arises in connection with a deductible reserve, under Article 113.3 of the Hydrocarbon Code applicable to such Company’s Interests, from the taxable profits of either Company relating to any under-utilisation of any such deductible reserve; or

(g) the matter giving rise to the Relevant Claim results in a benefit accruing to any member of the Buyer’s Group (including any right to reduce any present or future liability to Tax, Royalty or otherwise) in which case, the Relevant Claim shall only be reduced by the amount of such benefit; or

(h) it relates to income, profits, gains, production, acts or transactions of either Company arising after the Effective Date; or

(i) the provisions of paragraph 6 are applicable to the relevant Tax or Royalty (in which case the provisions of paragraph 6 of this Schedule 7 apply only and not paragraph 1.1 of this Schedule 7).

2.2 The provisions of paragraph 2.1 shall also operate to limit or reduce the liability of the Seller in respect of claims under the Warranties set forth in paragraph 8 of Part I of Schedule 3 and any other Warranty insofar as it relates to Tax or Royalty.

3. NOTIFICATION OF CLAIMS AND CONDUCT OF DISPUTES

The provisions of paragraph 4 of Schedule 4 shall apply to this Schedule 7.

4. RECOVERY FROM THIRD PARTIES/TAX SAVINGS

The provisions of paragraph 5 of Schedule 4 shall apply to this Schedule 7.

5. TAX RETURNS

With respect to any Tax returns, notices or elections required to be filed by or with respect to either Company (the “Company Returns”):

(a) the Seller shall cause the Companies to prepare all such Company Returns that are required to be filed prior to the Closing Date provided that the Seller shall cooperate and consult with the Buyer in the preparation of Company Returns which relate to any Tax year of which the whole or part falls after the Effective Date and provide the Buyer with no less than five (5) Business Days notice before submitting any such Company Returns to the applicable Tax Authorities during which five (5) Business Day period the Seller shall take into account the Buyer’s reasonable requests relating to such Company Returns;

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(b) the Buyer shall prepare all Company Returns that are required to be filed on or after the Closing Date and shall pay or cause the Companies to pay all Taxes shown to be due on such Tax Returns provided that the Buyer shall cooperate and consult with the Seller in the preparation of Company Returns which relate to any Tax year of which the whole or part falls prior to the Effective Date and provide the Seller with no less than thirty (30) days notice before submitting any such Company Returns to the applicable Tax Authorities during which thirty (30) day period the Buyer shall take into account the Seller’s reasonable requests relating to, such Company Returns.

6. TUNISIAN TAX AND ROYALTY AUDIT

(a) On December 29, 2010, Pioneer Tunisia received a Notification of Tax Audit Results from the Tunisia Ministry of Finance for the years 2006, 2007, 2008 and (in the case of amounts other than income taxes) 2009. The audit covered the following taxes and resulted in proposed adjustments to income taxes, quarterly provisional advances, royalty, VAT, withholding taxes, promotional fund for social housing salaries, training taxes on salaries and taxes to local communities (the “Tax and Royalty Audit Adjustments”).

(b) Seller will cause appropriate provisions to be recorded in the 2010 Accounts in respect of the Tax and Royalty Audit Adjustments in accordance with US GAAP.

(c) If the ultimate liability in respect of the Tax and Royalty Audit Adjustments exceeds the provision therefor in the 2010 Accounts, Seller will pay to Buyer the amount by which such ultimate Liability exceeds the provision therefor in the 2010 Accounts (with application of the de minimis amount in paragraph 1.1(a) of Schedule 4 (of $350,000) but without application of the threshold in paragraph 1.1(b) of Schedule 4).

(d) If the ultimate liability in respect of the Tax and Royalty Audit Adjustments is less than the provision therefor in the 2010 Accounts, Buyer will pay to Seller the amount by which the provision therefor in the 2010 Accounts exceeds such ultimate liability (with application of the de minimis amount in paragraph 1.1(a) of Schedule 4 (of $350,000) but without application of the threshold in paragraph 1.1(b) of Schedule 4).

(e) The provisions of this paragraph 6 shall represent the Parties’ sole rights and obligations with respect to the Tax and Royalty Audit Adjustments but nothing in this paragraph 6(e) is a limitation on Schedule 4 except as expressly provided in this paragraph 6.

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IN WITNESS WHEREOF the Parties have executed this Agreement on the date first written above.

SIGNED IN IRVING, TEXAS BY Richard P. Dealy for and on behalf of	/s/ Richard P. Dealy
Pioneer Natural Resources USA, Inc.
	Richard P. Dealy
SIGNED BY
for and on behalf of OMV (Tunesien) Production GmbH	/s/ Andreas Aigner
(under a power of attorney dated 30 December 2010)	Andreas Aigner

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EX-10.56H

Exhibit 10.56H

AMENDMENT NO. 2

TO THE

PIONEER NATURAL RESOURCES COMPANY

EXECUTIVE DEFERRED COMPENSATION PLAN

(Amended and Restated Effective January 1, 2009)

Pursuant to the provisions of Section 11.4 thereof, the Pioneer Natural Resources Company Executive Deferred Compensation Plan (Amended and Restated Effective January 1, 2009) is hereby amended to restate Section 2.1(o) in its entirety as follows:

“Eligible Employee” means any individual employed by a Company who is (i) an officer of the Company or (ii) a member of a select group of management or highly compensated employees (A) designated by the Plan Administrator from time to time as being eligible to participate in the Plan and (B) whose annual rate of Basic Compensation is $185,000 or above and whose designated grade level is at least grade 23 in the Company’s general salary grade structure or an equivalent grade in the specialized grade structure, as determined by the Plan Administrator; provided, however, that the Basic Compensation and grade level requirements provided in clause (ii)(B) of this subsection shall not apply to Members in the Plan as of December 31, 2008. An Eligible Employee shall remain an Eligible Employee notwithstanding any reduction in his or her annual rate of Basic Compensation below the applicable minimum under clause (ii)(B) of this subsection; provided, however, that the Plan Administrator in its discretion may withdraw an individual’s designation as an Eligible Employee under clause (ii) at any time and for any reason effective with respect to any subsequent Plan Year.

IN WITNESS WHEREOF, this Amendment has been executed on this 13th day of December, 2010, to be effective January 1, 2011.

PIONEER NATURAL RESOURCES COMPANY
By	/s/ Larry N. Paulsen
	Larry N. Paulsen
	Vice President, Administration and Risk Management

EX-10.64H

Exhibit 10.64H

RESTRICTED STOCK UNIT AWARD AGREEMENT

PIONEER NATURAL RESOURCES COMPANY

2006 LONG TERM INCENTIVE PLAN

To: Scott Sheffield

Pioneer Natural Resources Company, a Delaware corporation (the “Company”), is pleased to grant you an award (the “Award”) to receive              Restricted Stock Units (the “Restricted Stock Units”) whereby each Restricted Stock Unit represents the right to receive one share of common stock, par value $0.01, of the Company (the “Stock”), plus an additional amount pursuant to Section 2, subject to certain restrictions and on the terms and conditions contained in this Restricted Stock Unit Award Agreement (the “Agreement”) and the Pioneer Natural Resources Company 2006 Long Term Incentive Plan (the “Plan”). A copy of the Plan is available upon request. Except as provided below, to the extent that any provision of this Agreement conflicts with the expressly applicable terms of the Plan, you acknowledge and agree that those terms of the Plan shall control and, if necessary, the applicable provisions of this Agreement shall be deemed amended so as to carry out the purpose and intent of the Plan. Terms that have their initial letters capitalized, but that are not otherwise defined in this Agreement, shall have the meanings given to them in the Plan in effect as of the date of this Agreement.

This Agreement sets forth the terms of the agreement between you and the Company with respect to the Restricted Stock Units. By accepting this Agreement, you agree to be bound by all of the terms hereof.

1. No Shareholder Rights. The Restricted Stock Units granted pursuant to this Agreement do not and shall not entitle you to any rights of a stockholder of the Company prior to the date shares of Stock are issued to you in settlement of the Award. Your rights with respect to Restricted Stock Units shall remain forfeitable at all times prior to the date on which rights become vested and the restrictions with respect to the Restricted Stock Units lapse in accordance with Section 4, 6 or 7.

2. Dividend Equivalents. In the event that the Company declares and pays a dividend in respect of its outstanding shares of Stock and, on the record date for such dividend, you hold Restricted Stock Units granted pursuant to this Agreement that have not been settled, the Company shall pay to you an amount in cash equal to the cash dividends you would have received if you were the Beneficial Owner, as of such record date, of the number of shares of Stock related to the portion of your Restricted Stock Units that have not been settled as of such record date, such payment to be made on or promptly following the date that the Company pays such dividend (however, in no event shall the dividend equivalent payment be made later than 30 days following the date on which the Company pays such dividend).

3. Conversion of Restricted Stock Units; Issuance of Stock; Payment of Stock. No shares of Stock shall be issued to you prior to the date on which the Restricted Stock Units vest and the restrictions with respect to the Restricted Stock Units lapse, in accordance with Section 4, 6 or 7. Neither this Section 3 nor any action taken pursuant to or in accordance with this Section 3 shall be construed to create a trust of any kind. After any Restricted Stock Units vest pursuant to Section 4, 6 or 7 the Company shall, on or promptly following the applicable dates set forth in Section 5, cause to be issued Stock in book entry form registered in your name in payment of such vested Restricted Stock Units upon receipt by the Company of any required tax withholding with respect to such shares. The value of any fractional Restricted Stock Units shall be paid in cash at the time Stock is issued to you in connection with the Restricted Stock Units. The value of the fractional Restricted Stock Units shall equal the percentage of a Restricted Stock Unit represented by a fractional Restricted Stock Unit multiplied by the Fair Market Value of the Stock. The value of such shares of Stock shall not bear any interest owing to the passage of time.

4. Expiration of Restrictions and Risk of Forfeiture. Subject to the terms and conditions of this Agreement, the forfeiture restrictions on the Restricted Stock Units granted pursuant to this Agreement will expire in full on the third anniversary of the date of this Agreement (the “Vesting Date”); provided, however, that such restrictions will expire on the Vesting Date only if you have been an employee of the Company or of a Subsidiary continuously from the date of this Agreement through the Vesting Date; provided, further, however, that if you cease to be an employee of the Company or of a Subsidiary for any reason after the Vesting Date, all Restricted Stock Units granted pursuant to this Agreement will survive the termination of employment.

5. Payment Date. The payment date of the Stock related to your Restricted Stock Units will be the date on which the restrictions on such Restricted Stock Units expire as provided in Section 4, 6 or 7 of this Agreement; provided that, notwithstanding the provisions of Section 7(d) or Section 27, in the event that restrictions on your Restricted Stock Units expire due to the termination of your employment relationship with the Company and each of its Subsidiaries by which you are employed as a result of your Normal Retirement, then the payment date of the Stock related to such Restricted Stock Units will be the date on which the restrictions on such Restricted Stock Units would have expired as provided in Section 4 had you remained an employee of the Company or of a Subsidiary continuously from the date of this Agreement through the Vesting Date; provided, further, that, payment of your Restricted Stock Units may be made prior to the payment events specified in this Section 5 or in Section 27 to the limited extent necessary to pay employment or other taxes imposed on the Award.

6. Change in Control of the Company. Notwithstanding Section 4 of this Agreement, but subject to Section 27 of this Agreement, upon the occurrence of a Change in Control, all of the Restricted Stock Units granted pursuant to this Agreement shall become immediately and unconditionally vested and the shares of Stock related to such Restricted Stock Units shall be paid to you immediately.

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7. Termination of Employment.

(a) Termination By Employee Without Good Reason. If your employment relationship with the Company or any of its Subsidiaries is terminated voluntarily by you prior to the Vesting Date and such termination is not a Termination for Good Reason (as such term is defined in the Severance Agreement between you and the Company or one of its Subsidiaries), then all Restricted Stock Units granted pursuant to this Agreement shall become null and void as of the date of such termination.

(b) Termination By The Company for Cause. If your employment relationship with the Company or any of its Subsidiaries is terminated by the Company prior to the Vesting Date and such termination is a Termination for Cause (as such term is defined in the Severance Agreement between you and the Company or one of its Subsidiaries), then all Restricted Stock Units granted pursuant to this Agreement shall become null and void as of the date of termination.

(c) Termination By The Company Not For Cause Or By Employee For Good Reason. Subject to Section 27 of this Agreement, if your employment relationship with the Company and each of its Subsidiaries by which you are employed is terminated prior to the Vesting Date (x) by the Company and such Subsidiaries and such termination is not a Termination for Cause or (y) by you and such termination is a Termination for Good Reason, then all of the Restricted Stock Units granted pursuant to this Agreement shall become immediately and unconditionally vested and unrestricted and the shares of Stock related to such Restricted Stock Units shall be paid to you immediately.

(d) Other Termination Events. Subject to Section 27 of this Agreement, if your employment relationship with the Company and each of its Subsidiaries by which you are employed is terminated prior to the Vesting Date as a result of any of the following events:

(i) your death;

(ii) your Disability; or

(iii) your Normal Retirement,

then the restrictions on a number of the Restricted Stock Units shall automatically lapse such that the number of Restricted Stock Units for which the restrictions have lapsed as of the termination date will be equal to the product of (i) the total number of Restricted Stock Units granted to you pursuant to this Agreement, times (ii) a fraction, the numerator of which is the number of full months (counting the month in which your termination of employment occurs as a full month), beginning with the first full month following the date of this Agreement, during which you were employed by the Company and/or any Subsidiary and the denominator of which is 36. The portion, if any, of your Restricted Stock Units for which the restrictions have not lapsed as of the termination date of your employment relationship shall become null and void as of the termination date; provided, however, that the portion, if any, of this Award for which forfeiture restrictions have lapsed as of the date of termination shall survive.

For purposes of this Section 7(d), “Disability” shall have the meaning ascribed to it in the Severance Agreement between you and the Company or one of its Subsidiaries; and “Normal

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Retirement” shall mean the termination of your employment relationship with the Company and each of its Subsidiaries by which you are employed due to your retirement on or after the date that you attain age 60.

8. Adjustment Provisions. In the event there is any change in the Stock by reason of any reorganization, recapitalization, stock split, stock dividend, combination of shares or otherwise, the number of shares associated with the Award of Restricted Stock Units subject to this Agreement shall be adjusted in the manner consistent with the adjustment provisions provided in Section 9(b) and 9(c)(ii) of the Plan.

9. Furnish Information. You agree to furnish to the Company all information requested by the Company to enable it to comply with any reporting or other requirements imposed upon the Company by or under any applicable statute or regulation.

10. Remedies. The parties to this Agreement shall be entitled to recover from each other reasonable attorneys’ fees incurred in connection with the enforcement of the terms and provisions of this Agreement whether by an action to enforce specific performance or for damages for its breach or otherwise.

11. Information Confidential. As partial consideration for the granting of the Award hereunder, you hereby agree with the Company that you will keep confidential all information and knowledge, except that which has been disclosed in any public filings required by law, that you have relating to the terms and conditions of this Agreement; provided, however, that such information may be disclosed as required by law and may be given in confidence to your spouse, tax and financial advisors, or to a financial institution to the extent that such information is necessary to secure a loan. In the event any breach of this promise comes to the attention of the Company, it shall take into consideration that breach in determining whether to recommend the grant of any future similar award to you, as a factor militating against the advisability of granting any such future award to you.

12. Payment of Taxes. The Company may from time to time require you to pay to the Company (or the Company’s Subsidiary if you are an employee of a Subsidiary of the Company) the amount that the Company deems necessary to satisfy the Company’s or its Subsidiary’s current or future obligation to withhold federal, state or local income or other taxes or social security or other obligations that you incur as a result of the Award, including without limitation with respect to any payment pursuant to Section 2 of this Agreement. With respect to any required tax withholding, unless another arrangement is permitted by the Company in its discretion, the Company shall withhold from the shares of Stock to be issued to you the number of shares necessary to satisfy the Company’s obligation to withhold taxes, that determination to be based on the shares’ Fair Market Value at the time as of which such determination is made. In the event the Company subsequently determines that the aggregate Fair Market Value of any shares of Stock withheld as payment of any tax withholding obligation is insufficient to discharge that tax withholding obligation, then you shall pay to the Company, immediately upon the Company’s request, the amount of that deficiency.

13. Right of the Company and Subsidiaries to Terminate Employment. Nothing contained in this Agreement shall confer upon you the right to continue in the employ of the Company or any Subsidiary of the Company, or interfere in any way with the rights of the Company or any Subsidiary of the Company to terminate your employment at any time.

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14. No Liability for Good Faith Determinations. Neither the Company nor the members of the Board and the Committee shall be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Restricted Stock Units granted hereunder.

15. No Guarantee of Interests. The Board and the Company do not guarantee the Stock of the Company from loss or depreciation.

16. Company Records. Records of the Company or its Subsidiaries regarding your period of employment, termination of employment and the reason therefor, leaves of absence, re-employment, and other matters shall be conclusive for all purposes hereunder, unless determined by the Company to be incorrect.

17. Severability. If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein.

18. Notices. Whenever any notice is required or permitted hereunder, such notice must be in writing and personally delivered or sent by mail. Any such notice required or permitted to be delivered hereunder shall be deemed to be delivered on the date on which it is personally delivered, or, whether actually received or not, on the third Business Day after it is deposited in the United States mail, certified or registered, postage prepaid, addressed to the person who is to receive it at the address which such person has theretofore specified by written notice delivered in accordance herewith. The Company or you may change, at any time and from time to time, by written notice to the other, the address which it or he had previously specified for receiving notices.

The Company and you agree that any notices shall be given to the Company or to you at the following addresses:

Company:	Pioneer Natural Resources Company Attn: Corporate Secretary 5205 N. O’Connor Boulevard, Suite 200 Irving, Texas 75039-3746
Holder:	At your current address as shown in the Company’s records.

19. Waiver of Notice. Any person entitled to notice hereunder may waive such notice in writing.

20. Successors. This Agreement shall be binding upon you, your legal representatives, heirs, legatees and distributees, and upon the Company, its successors and assigns.

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21. Headings. The titles and headings of Sections are included for convenience of reference only and are not to be considered in construction of the provisions hereof.

22. Governing Law. All questions arising with respect to the provisions of this Agreement shall be determined by application of the laws of the State of Delaware except to the extent Delaware law is preempted by federal law. The obligation of the Company to sell and deliver Stock hereunder is subject to applicable laws and to the approval of any governmental authority required in connection with the authorization, issuance, sale, or delivery of such Stock.

23. Execution of Receipts and Releases. Any payment of cash or any issuance or transfer of shares of Stock or other property to you, or to your legal representative, heir, legatee or distributee, in accordance with the provisions hereof, shall, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. The Company may require you or your legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a release and receipt therefor in such form as it shall determine.

24. Amendment. This Agreement may be amended at any time unilaterally by the Company, provided that such amendment is consistent with all applicable laws and does not reduce any rights or benefits you have accrued pursuant to this Agreement. This Agreement may also be amended at any time unilaterally by the Company to the extent the Company believes in good faith that such amendment is necessary or advisable to bring this Agreement in compliance with any applicable laws, including Section 409A of the Code.

25. The Plan. This Agreement is subject to all the terms, conditions, limitations and restrictions contained in the Plan; provided, however, that notwithstanding anything to the contrary herein, any provision of this Agreement that is inconsistent with the provisions of Section 9(c), (e), and (f) of the Plan shall control over such provisions of the Plan.

26. Agreement Respecting Securities Act of 1933. You represent and agree that you will not sell the Stock that may be issued to you pursuant to your Restricted Stock Units except pursuant to an effective registration statement under the Securities Act of 1933 or pursuant to an exemption from registration under the Securities Act of 1933 (including Rule 144 of the Securities Act).

27. Special Provisions Addressing Section 409A of the Code.

(a) Change in Control. Notwithstanding the provisions of Section 6 that may be to the contrary, if a Change in Control occurs at a time when you have reached the age of 60 or later, no shares of Stock related to the Restricted Stock Units shall be paid to you as a result of that Change in Control unless the event constituting such Change in Control also constitutes a “change in the ownership or effective control” or “in the ownership of a substantial portion of the assets” of the Company within the meaning of Section 409A of the Code and the regulations and other authoritative guidance promulgated thereunder (collectively, the “Nonqualified Deferred Compensation Rules”); except that, to the extent permitted under the Nonqualified Deferred Compensation Rules, payment may be made in respect of this Award, upon the occurrence of a Change in Control, as determined by the Committee in its discretion, to the extent necessary to pay employment or other taxes imposed on the Award. To the extent shares of Stock related to

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the Restricted Stock Units are not paid to you upon a Change in Control as a result of the limitations described in the preceding sentence, the payment date of the Stock related to your Restricted Stock Units shall be the earlier to occur of:

(i) the time or times specified in Section 4 of this Agreement;

(ii) your separation from service with the Company (determined in accordance with the Company’s written and generally applicable policies regarding what constitutes a “separation from service” for purposes of Section 409A of the Code); provided that, if at the time of the Change in Control you are a “specified employee” within the meaning of Section 409A of the Code, as determined in accordance with the procedures specified or established by the Company in accordance with the Nonqualified Deferred Compensation Rules (a “Specified Employee”), this date shall be the earlier of (A) the date of your death, or (B) the date that is six months and one day following the date of your separation from service with the Company; or

(iii) a Change in Control that constitutes a “change in the ownership or effective control” or “in the ownership of a substantial portion of the assets” of the Company within the meaning of the Nonqualified Deferred Compensation Rules.

(b) Termination of Employment. Notwithstanding the provisions of Section 7(c) or 7(d) that may be to the contrary, if you have reached the age of 60 or later at the time of the event giving rise to the termination of your employment relationship with the Company and each of its Subsidiaries, any payment that becomes due to you pursuant to Section 7(c) or 7(d) of this Agreement (other than as a result of your Normal Retirement, which shall be governed by Section 5) shall only be paid to you on the earlier to occur of:

(i) the time or times specified in Section 4 of this Agreement; or

(ii) the date of your separation from service with the Company; provided that, if at the time of the Change in Control you are a Specified Employee, this date shall be the earlier of (A) the date of your death, or (B) the date that is six months and one day following the date of your separation from service with the Company;

provided that, to the extent permitted under the Nonqualified Deferred Compensation Rules, payment shall be made in respect of this Award, upon your termination of employment, as determined by the Committee in its discretion, to the extent necessary to pay employment or other taxes imposed on the Award.

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28. Electronic Delivery and Acknowledgement. No signature by you is required to accept the award represented by this Agreement. By your acceptance of this award, you are acknowledging that you have received and read, understood and accepted all the terms, conditions and restrictions of this Agreement and the Plan. The Company may, in its sole discretion, deliver any documents related to this award and this Agreement, or other awards that have been or may be awarded under the Plan, by electronic means, including prospectuses, proxy materials, annual reports and other related documents, and the Company may, in its sole discretion, engage a third party to effect the delivery of these documents on its behalf and provide other administrative services related to this award and the Plan. By your acceptance of the award represented by this Agreement, you consent to receive such documents by electronic delivery and to the engagement of any such third party.

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EX-21.1

Exhibit 21.1

SUBSIDIARIES OF THE COMPANY

as of December 31, 2010

Subsidiaries		State or Jurisdiction of Organization
Pioneer Natural Resources USA, Inc.		Delaware
DMLP CO.		Delaware
Long Canyon Gas Company, LLC	(75.4%)	Colorado
Lorencito Gas Gathering, LLC	(85%)	Colorado
Mesa Environmental Ventures Co.		Delaware
Petroleum South Cape (Pty) Ltd.		South Africa
Pioneer JDZ Limited		Nigeria
Pioneer Natural Gas Company		Texas
Pioneer Natural Resources Alaska, Inc.		Delaware
Pioneer Natural Resources Algeria Limited		Cayman Islands
Pioneer Natural Resources Anaguid Ltd.		Cayman Islands
Pioneer Natural Resources Foundation		Texas
Pioneer Natural Resources GP LLC		Delaware
Pioneer Natural Resources Midstream Holding LLC		Delaware
Pioneer Natural Resources Morocco Limited		Cayman Islands
Pioneer Natural Resources South Africa (Pty) Limited		South Africa
Pioneer Natural Resources (Tierra Del Fuego) S.R.L.		Argentina
Pioneer Natural Resources Tunisia Ltd.		Cayman Islands
Pioneer Natural Resources UK Limited		England
Pioneer Natural Resources West Africa Limited		Cayman Islands
Pioneer Natural Resources Equatorial Guinea Limited		Cayman Islands
Pioneer Nigeria Deepwater Limited		Nigeria
Pioneer Resources Africa Limited		Cayman Islands
Pioneer Natural Resources Nigeria Ltd.		Cayman Islands
Pioneer NR Nigeria (256) Limited		Nigeria
Pioneer Resources Gabon Limited		Bahamas
Pioneer Southwest Energy Partners L.P.	(61.9%)	Delaware
Pioneer Southwest Energy Partners USA LLC		Delaware
PSE Finance Corporation		Delaware
Pioneer Uravan, Inc.		Texas
Sendero Holding Company, LLC		Delaware
Sendero Drilling Company, LLC	(98.34699%)	Delaware
Westpan Limited NGL LLC		Texas
Westpan Limited Resources LLC		Texas
Pioneer International Resources Company		Delaware
LF Holding Company LDC		Cayman Islands
Parker & Parsley Argentina, Inc.		Delaware
TDF Holding Company LDC		Cayman Islands
Pioneer Shelf Properties Incorporated		Delaware
Partnerships in which Pioneer Natural Resources USA, Inc. is the managing general partner:
Parker & Parsley 87-A Conv., Ltd.		Texas
Parker & Parsley Private Investment 88 L.P.		Delaware
Parker & Parsley Private Investment 89, L.P.		Delaware
Parker & Parsley 90 Spraberry Private Development, L.P.		Delaware
Midkiff Development Drilling Program, Ltd.		Texas

Notes:

1. Indented names are subsidiaries of subsidiaries.

2. Inclusion in the list is not a representation that the subsidiary is a significant subsidiary.

3. Except as noted, the voting shares of all subsidiaries are 100% owned by Pioneer Natural Resources Company or its subsidiaries.

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-3 No. 333-148655) of Pioneer Natural Resources Company and Pioneer Natural Resources USA, Inc. and in the related Prospectus,

(2) Registration Statement (Form S-8 No. 333-136488) pertaining to the Pioneer Natural Resources Company Executive Deferred Compensation Plan,

(3) Registration Statement (Form S-8 No. 333-136489) pertaining to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan,

(4) Registration Statement (Form S-8 No. 333-136490) pertaining to the Pioneer Natural Resources Company Long-Term Incentive Plan,

(5) Registration Statement (Form S-8 No. 333-119355) pertaining to the 2000 Stock Incentive Plan of Evergreen Resources, Inc., the Carbon Energy Corporation 1999 Stock Option Plan, and the Evergreen Resources, Inc. Initial Stock Option Plan,

(6) Registration Statement (Form S-8 No. 333-88438) pertaining to the Pioneer Natural Resources Company Long-Term Incentive Plan,

(7) Registration Statement (Form S-8 No. 333-39153) pertaining to the Pioneer Natural Resources Company Deferred Compensation Retirement Plan,

(8) Registration Statement (Form S-8 No. 333-39249) pertaining to the Pioneer Natural Resources USA, Inc. Profit Sharing 401(k) Plan,

(9) Registration Statement (Form S-8 No. 333-35087) pertaining to the Pioneer Natural Resources Company Long-Term Incentive Plan,

(10) Registration Statement (Form S-8 No. 333-35165) pertaining to the Pioneer Natural Resources Company Employee Stock Purchase Plan, and

(11) Registration Statement (Form S-8 No. 333-161283) pertaining to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan;

of our reports dated February 25, 2011, with respect to the consolidated financial statements of Pioneer Natural Resources Company and the effectiveness of internal control over financial reporting of Pioneer Natural Resources Company included in this Annual Report (Form 10-K) of Pioneer Natural Resources Company for the year ended December 31, 2010.

/s/ Ernst & Young LLP

Dallas, Texas

February 25, 2011

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references to our firm, in the context in which they appear, and to the references to and the incorporation by reference of our audit letter dated January 31, 2011, included in the Annual Report on Form 10-K of Pioneer Natural Resources Company (the “Company”) for the fiscal year ended December 31, 2010, as well as in the notes to the financial statements included therein. We also hereby consent to the incorporation by reference of the references to our firm, in the context in which they appear, and to our audit letter dated January 31, 2011, into the Company’s previously filed Registration Statements on Form S-8 (No. 333-35087, No. 333-35165, No. 333-39153, No. 333-39249, No. 333-88438, No. 333-119355, No. 333-136488, No. 333-136489, No. 333-136490 and No. 333-161283) and on Form S-3 (No. 333-148655) in accordance with the requirements of the Securities Act of 1933, as amended.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ G. Lance Binder
	G. Lance Binder, P.E.
	Executive Vice President

Dallas, Texas

February 24, 2011

EX-31.1

Exhibit 31.1

CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Scott D. Sheffield, certify that:

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

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

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

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

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

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

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

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

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

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

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

February 25, 2011
	/s/ Scott D. Sheffield
	Scott D. Sheffield, Chairman and
	Chief Executive Officer

EX-31.2

Exhibit 31.2

CHIEF FINANCIAL OFFICER CERTIFICATION

I, Richard P. Dealy, certify that:

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

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

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

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

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

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

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

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

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

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

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

February 25, 2011
	/s/ Richard P. Dealy
	Richard P. Dealy, Executive Vice President
	and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF PIONEER NATURAL RESOURCES COMPANY

PURSUANT TO 18 U.S.C. § 1350

I, Scott D. Sheffield, Chairman and Chief Executive Officer of Pioneer Natural Resources Company (the “Company”), hereby certify that the accompanying Annual Report on Form 10-K for the year ended December 31, 2010 and filed with the Securities and Exchange Commission pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

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

	/s/ Scott D. Sheffield
Name:	Scott D. Sheffield, Chairman and
	Chief Executive Officer
Date:	February 25, 2011

EX-32.2

Exhibit 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF PIONEER NATURAL RESOURCES COMPANY

PURSUANT TO 18 U.S.C. § 1350

I, Richard P. Dealy, Executive Vice President and Chief Financial Officer of Pioneer Natural Resources Company (the “Company”), hereby certify that the accompanying Annual Report on Form 10-K for the year ended December 31, 2010 and filed with the Securities and Exchange Commission pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

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

	/s/ Richard P. Dealy
Name:	Richard P. Dealy, Executive Vice
	President and Chief Financial Officer
Date:	February 25, 2011

EX-99.1

Exhibit 99.1

January 31, 2011

Mr. Kerry D. Scott

Pioneer Natural Resources Company

5205 North O’Connor Boulevard, Suite 200

Irving, Texas 75039-3746

Dear Mr. Scott:

In accordance with your request, we have audited the estimates prepared by Pioneer Natural Resources Company (Pioneer), as of December 31, 2010, of the proved reserves and future revenue to the Pioneer interest in certain oil and gas properties located in the United States, Tunisia, and offshore South Africa. It is our understanding that the proved reserves estimates shown herein constitute all of the proved reserves owned by Pioneer. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and guidelines of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit on January 31, 2011. This report has been prepared for Pioneer’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth Pioneer’s estimates of the net reserves and future net revenue, as of December 31, 2010, for the audited properties:

	Net Reserves						Future Net Revenue (M$)
Category	Oil (MBBL)		NGL (MBBL)		Gas (MMCF)		Total		Present Worth at 10%
Proved Developed Producing		161,983		105,383		1,683,975		11,086,092		5,583,657
Proved Developed Non-Producing		10,833		3,403		91,635		826,803		404,025
Proved Undeveloped		207,993		75,433		898,910		9,772,228		2,017,002
Total Proved		380,809		184,218		2,674,521		21,685,123		8,004,685

Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on a field-by-field basis, some of the estimates of Pioneer are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. (NSAI). However, in our opinion the estimates of Pioneer’s proved reserves and future revenue shown herein are, in the aggregate, reasonable and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by Pioneer in preparing the December 31, 2010, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Pioneer.

The estimates shown herein are for proved reserves. Pioneer’s estimates do not include probable or possible reserves that may exist for these properties, nor do they include any value for undeveloped acreage beyond those

tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Prices used by Pioneer are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2010. For oil and NGL volumes, the average of Platts Oil Daily West Texas Intermediate (Cushing) spot price of $79.282 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average Platts Gas Daily Henry Hub spot price of $4.373 per MMBTU is adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $77.16 per barrel of oil, $37.82 per barrel of NGL, and $4.07 per MCF of gas.

Lease and well operating costs used by Pioneer are based on historical operating expense records. For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Lease and well operating costs for the operated properties include direct lease- and field-level costs and Pioneer’s estimate of the portion of its headquarters general and administrative overhead (G&A) expenses necessary to operate the properties. Pioneer’s estimate of G&A expenses is included at the field area level for all areas except for Raton Basin, which is included at the lease level. Lease and well operating costs are held constant throughout the lives of the properties. Pioneer’s estimates of capital costs are included as required for workovers, new development wells, production equipment, abandonment, and salvage. The future capital costs are held constant to the date of expenditure.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of Pioneer and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of Pioneer to recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of major properties making up approximately 90 percent of Pioneer’s total proved reserves and accounting for approximately 79 percent of the present worth for those reserves. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Pioneer with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of Pioneer’s overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by Pioneer, are on file in our office. The technical persons responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-002699
	/s/ C.H. (Scott) Rees III
By:
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer
	/s/ G. Lance Binder
By:
	G. Lance Binder, P.E., 61794
	Executive Vice President
Date Signed: January 31, 2011

GLB:JLW

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