Edgar Filing: PIONEER NATURAL RESOURCES CO

PXD-2012.12.31-10K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



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

For the fiscal year ended December 31, 2012



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

For the transition period from to

Commission File Number: 1-13245

Pioneer Natural Resources Company

(Exact name of registrant as specified in its charter)



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

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

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

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



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

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

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

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



Large accelerated filer	ý	Accelerated filer	o

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

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



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

Number of shares of Common Stock outstanding as of February 8, 2013	123,360,341

DOCUMENTS INCORPORATED BY REFERENCE:


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

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TABLE OF CONTENTS



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

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

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Definitions of Certain Terms and Conventions Used Herein

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


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


•	"BCF" means one billion cubic feet.


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


•	"BOEPD" means BOE per day.


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


•	"CBM" means coal bed methane.


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


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


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


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


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


•	"MBBL" means one thousand BBLs.


•	"MBOE" means one thousand BOEs.


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


•	"MMBBL" means one million BBLs.


•	"MMBOE" means one million BOEs.


•	"MMBTU" means one million BTUs.


•	"MMCF" means one million cubic feet.


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


•	"NGL" means natural gas liquid.


•	"NYMEX" means the New York Mercantile Exchange.


•	"NYSE" means the New York Stock Exchange.


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


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

•

"Proved reserves" mean the quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities,

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


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


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


•	"U.S." means United States.


•	"VPP" means volumetric production payment.


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

•

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


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

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

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

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PIONEER NATURAL RESOURCES COMPANY

PART I



ITEM 1.	BUSINESS

General

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

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

Available Information

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

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

Mission and Strategies

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

Business Activities

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

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

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PIONEER NATURAL RESOURCES COMPANY

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

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

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

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

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

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

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

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

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

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PIONEER NATURAL RESOURCES COMPANY

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

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

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

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

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

In January 2013, the Company signed an agreement with Sinochem Petroleum USA LLC ("Sinochem"), a U.S. subsidiary of the Sinochem Group, an unaffiliated third party, to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for consideration of $1.7 billion. At closing, Sinochem will pay $522.0 million in cash to Pioneer, before normal closing adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of Pioneer's portion of future drilling and facilities costs attributable to the horizontal Wolfcamp Shale play. This transaction is expected to close during the second quarter of 2013, subject to governmental and third party approvals.

During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest its net assets in South Africa ("Pioneer South Africa"). During the first quarter of 2012, the Company agreed to sell Pioneer South Africa to an unaffiliated third party, effective January 1, 2012, for $60.0 million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities of the Company's South Africa subsidiaries. In August 2012, the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale, resulting in a pretax gain of $28.6 million. The Company classified (i) Pioneer South Africa's assets and liabilities as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2011 and (ii) Pioneer South Africa's results of operations as income from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

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

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

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PIONEER NATURAL RESOURCES COMPANY

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

Marketing of Production

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

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

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

Competition, Markets and Regulations

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

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

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

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PIONEER NATURAL RESOURCES COMPANY

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


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


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


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


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


•	impose specific criteria addressing worker protection; and


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


•	the location of wells;


•	the method of drilling and casing wells;


•	the method and ability to fracture stimulate wells;


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


•	the plugging and abandoning of wells; and


•	notice to surface owners and other third parties.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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



ITEM 1A.	RISK FACTORS

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

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

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


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


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

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•	gas inventory levels in the United States;


•	weather conditions;


•	overall domestic and global political and economic conditions;


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


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


•	technological advances affecting energy consumption and energy supply;


•	domestic and foreign governmental regulations and taxation;


•	the effect of energy conservation efforts;


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


•	the price and availability of alternative fuels.

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

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

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

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

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

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


•	production is less than the contracted derivative volumes;


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


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

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

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

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

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

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

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


•	unexpected drilling conditions;


•	unexpected pressure or irregularities in formations;


•	equipment failures or accidents;


•	fracture stimulation accidents or failures;


•	adverse weather conditions;


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


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

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

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

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

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

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

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

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

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

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

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


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


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


•	the validity of assumptions about costs, including synergies;


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


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


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

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

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

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

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

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

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

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

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


•	blowouts, cratering, explosions and fires;


•	adverse weather effects;


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


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


•	facility or equipment malfunctions, failures or accidents;


•	title problems;


•	pipe or cement failures or casing collapses;


•	compliance with environmental and other governmental requirements;


•	lost or damaged oilfield workover and service tools;


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


•	natural disasters.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


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


•	marketing oil, NGL and gas production; and


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

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

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

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

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

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

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

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

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


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


•	the quality and quantity of available data;


•	the interpretation of that data;


•	the assumed effects of regulations by governmental agencies;


•	assumptions concerning future commodity prices; and


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

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


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


•	the production costs incurred to recover the reserves;


•	the amount and timing of future development expenditures; and


•	future commodity prices.

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

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


•	the amount and timing of actual production;


•	levels of future capital spending;


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


•	changes in governmental regulations or taxation.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


•	unusual or unexpected geological formations or pressures;


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


•	unanticipated ground, grade or water conditions;


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


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


•	changes in laws and regulations;


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


•	restrictions on blasting operations;


•	inability to obtain necessary production equipment or replacement parts;

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•	reduction in the amount of water available for processing;


•	technical difficulties or failures;


•	labor disputes;


•	late delivery of supplies;


•	fires, explosions or other accidents; and


•	facility shutdowns in response to environmental regulatory actions.

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

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

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


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


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


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

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

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

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


•	issuance of administrative, civil and criminal penalties;


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


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


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

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

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

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

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

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

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

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

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

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

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

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

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

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



ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.



ITEM 2.	PROPERTIES

Reserve Estimation Procedures and Audits

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

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

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

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

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

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


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

•

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

•

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

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

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

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

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

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

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

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

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

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

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Proved Reserves

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



	Summary of Oil and Gas Reserves as of Fiscal Year-End Based on Average Fiscal-Year Prices
	Reserve Volumes
	Oil (MBBLs)	NGLs (MBBLs)	Gas (MMCF) (a)	Total (MBOE)	%		Standardized Measure
							(in thousands)
December 31, 2012:
Developed	230,700	134,637	1,605,209	632,872	58	%	$	5,010,779
Undeveloped	256,138	97,939	592,271	452,789	42	%	1,342,619
Total Proved	486,838	232,576	2,197,480	1,085,661	100	%	$	6,353,398

December 31, 2011:
Developed	190,206	120,405	1,853,363	619,506	58	%	$	5,494,007
Undeveloped	239,799	90,630	677,675	443,375	42	%	$	2,319,016
Total Proved	430,005	211,035	2,531,038	1,062,881	100	%	$	7,813,023

December 31, 2010:
Developed	172,816	108,785	1,775,611	577,537	57	%	$	4,065,879
Undeveloped	207,993	75,433	898,911	433,244	43	%	$	1,346,130
Total Proved	380,809	184,218	2,674,522	1,010,781	100	%	$	5,412,009

______________________


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

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

Description of Properties

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

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



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

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PIONEER NATURAL RESOURCES COMPANY



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

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



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

_____________________


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

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



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

____________________


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

Permian Basin

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

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

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PIONEER NATURAL RESOURCES COMPANY

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

During 2012, the Company drilled 691 wells in the Spraberry field and its total acreage position now approximates 827,000 gross acres (707,000 net acres). The Company currently has 24 rigs operating in the Spraberry field, of which 15 are drilling vertical wells and nine are drilling horizontal Wolfcamp Shale wells. During 2013, the Company expects to drill approximately 290 vertical wells and 120 horizontal wells, with the horizontal wells being principally in the Wolfcamp Shale horizon. Excluding the southern Wolfcamp joint interest area, the Company expects to incur $1.2 billion of drilling capital in the Spraberry field during 2013.

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

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

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

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

In January 2013, the Company signed an agreement with Sinochem, an unaffiliated third party, to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for consideration of $1.7 billion. At closing Sinochem will pay $522.0 million in cash to Pioneer, before normal closing adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of Pioneer's portion of future drilling and facilities costs attributable to the horizontal Wolfcamp Shale play. This transaction is expected to close during the second quarter of 2013, subject to governmental and third party approvals.

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

The Company continues to expand its integrated services to control drilling and operating costs and support the execution of its drilling and production activities in the Spraberry field. The Company owns 15 drilling rigs and has five Company-owned vertical fracture stimulation fleets totaling 100,000 horsepower and two Company-owned horizontal fracture stimulation fleets totaling 70,000 horsepower currently operating in the Spraberry field. To support its growing operations, the Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, in early April 2012, the Company completed the acquisition of Premier Silica, which is expected to supply the Company's growing brown sand requirements for proppant that will be used for fracture stimulating wells in the vertical Spraberry and horizontal Wolfcamp Shale plays.

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PIONEER NATURAL RESOURCES COMPANY

Mid-Continent

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

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

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

Raton Basin

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

South Texas Eagle Ford Shale and Edwards

The Company's drilling activities in the South Texas area during 2012 continued to be primarily focused on delineation and development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2012 drilling program has been focused on liquids-rich drilling, with only 10 percent of the wells designated to hold strategic dry gas acreage.

The Company completed 137 horizontal Eagle Ford Shale wells during 2012, all of which were successful, with average lateral lengths of 5,700 feet and, on average, 13-stage fracture stimulations. The Company plans to incur $575 million of drilling capital and utilize 10 drilling rigs in 2013 to drill 134 wells. The Company plans to primarily use two Pioneer-owned fracture stimulation fleets during 2013.

The Company has also been testing the use of lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. The Company is expanding the use of white sand proppant to deeper areas of the field to further define its performance limits. Early well performance has been similar to direct offset ceramic-stimulated wells. The Company is continuing to monitor the performance of these wells and expects that greater than 50 percent of its 2013 drilling program will use lower-cost white sand proppant.

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

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

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PIONEER NATURAL RESOURCES COMPANY

Barnett Shale

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

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

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

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

Alaska

The Company owns a 70 percent working interest in, and is the operator of, the Oooguruk development project. Since inception, the Company has drilled 18 production wells and ten injection wells to develop this project. During the first quarter of 2012, the Company drilled an exploration well which was drilled from an onshore location to further evaluate the productivity of the Torok formation and the feasibility of future development expansion. The Company flow tested the well during April 2012 until production could no longer be transported along the ice road being utilized. The well had a gross initial production rate of approximately 2,000 barrels of oil per day. The well will be production tested again this winter pending permanent onshore production facilities, for which an onshore development front-end engineering design (FEED) study has been initiated. In September 2012, the Company entered into a contract for a drilling rig that is currently drilling a second onshore well in the Torok formation to further appraise its resource potential.

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

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

International

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

Selected Oil and Gas Information

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

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PIONEER NATURAL RESOURCES COMPANY

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

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

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PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA



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

____________________


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

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PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA - (Continued)



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

_____________________


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

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PRODUCTION, PRICE AND COST DATA - (Continued)



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

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(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.

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

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

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

PRODUCTIVE WELLS



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

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

LEASEHOLD ACREAGE

Developed Acreage

Undeveloped Acreage

Royalty Acreage

Gross Acres

Net Acres

Gross Acres

Net Acres

Onshore

1,690,423

1,437,950