10-K 1 d10k.htm FORM 10-K Form 10-K
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

 

x

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

For the fiscal year ended December 31, 2010

or

 

¨

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

For the transition period from              to             

Commission File Number: 1-13245

Pioneer Natural Resources Company

(Exact name of registrant as specified in its charter)

 

Delaware   75-2702753

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

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

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

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

 

Title of each class

 

Name of each exchange on which registered

Common Stock   New York Stock Exchange

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

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

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

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

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

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

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

 

Large accelerated filer

 

x

  

Accelerated filer

 

¨

Non-accelerated filer

 

¨  (Do not check if a smaller reporting company)

  

Smaller reporting company

 

¨

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

 

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

   $ 6,789,095,296   

Number of shares of Common Stock outstanding as of February 23, 2011

     116,452,149   

DOCUMENTS INCORPORATED BY REFERENCE:

(1) Proxy Statement for the 2011 Annual Meeting of Shareholders to be held during May 2011 — Referenced in Part III of this report.


Table of Contents

TABLE OF CONTENTS

 

          Page  

Definitions of Certain Terms and Conventions Used Herein

     4  

Cautionary Statement Concerning Forward-Looking Statements

     5  
PART I   

Item 1.

  

Business

     6  
  

General

     6  
  

Available Information

     6  
  

Mission and Strategies

     6  
  

Business Activities

     6  
  

Operations by Geographic Area

     8  
  

Marketing of Production

     9  
  

Competition, Markets and Regulations

     9  

Item 1A.

  

Risk Factors

     15  

Item 1B.

  

Unresolved Staff Comments

     25  

Item 2.

  

Properties

     26  
  

Reserve Rule Changes

     26  
  

Reserve Estimation Procedures and Audits

     26  
  

Proved Reserves

     28  
  

Description of Properties

     30  
  

Selected Oil and Gas Information

     36  

Item 3.

  

Legal Proceedings

     42  

Item 4.

  

Removed and Reserved

     42   
PART II   

Item 5.

   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
  

 

43

 

     
  

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

     43  

Item 6.

  

Selected Financial Data

     44  

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     45  
  

Financial and Operating Performance

     45  
  

First Quarter 2011 Outlook

     46  
  

2011 Capital Budget

     46  
  

Acquisitions

     47  
  

Divestitures

     47  
  

Results of Operations

     47  
  

Capital Commitments, Capital Resources and Liquidity

     56  
  

Critical Accounting Estimates

     60  
  

New Accounting Pronouncements

     63  

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

     64  
  

Quantitative Disclosures

     64  
  

Qualitative Disclosures

     67  

Item 8.

  

Financial Statements and Supplementary Data

     69  
  

Index to Consolidated Financial Statements

     69  
  

Report of Independent Registered Public Accounting Firm

     70  
  

Consolidated Financial Statements

     71  
  

Notes to Consolidated Financial Statements

     78  
  

Unaudited Supplementary Information

     121  

Item 9.

  

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

     130  

Item 9A.

  

Controls and Procedures

     130  
  

Management’s Report on Internal Control Over Financial Reporting

     130  
  

Report of Independent Registered Public Accounting Firm

     131  

Item 9B.

  

Other Information

    

132

 

 

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TABLE OF CONTENTS

 

PART III  

Item 10.

  

Directors, Executive Officers and Corporate Governance

     132  

Item 11.

  

Executive Compensation

     132  

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     132  
  

Securities Authorized for Issuance Under Equity Compensation Plans

     132  

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

     133  

Item 14.

  

Principal Accounting Fees and Services

     133  
PART IV   

Item 15.

  

Exhibits, Financial Statement Schedules

     133  

Signatures

     141  

Exhibit Index

     142  

 

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Definitions of Certain Terms and Conventions Used Herein

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

 

 

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

 

 

“Bcf” means one billion cubic feet.

 

 

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

 

 

“BOEPD” means BOE per day.

 

 

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

 

 

“CBM” means coal bed methane.

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

“LNG” means liquefied natural gas.

 

 

“MBbl” means one thousand Bbls.

 

 

“MBOE” means one thousand BOEs.

 

 

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

 

 

“MMBbl” means one million Bbls.

 

 

“MMBOE” means one million BOEs.

 

 

“MMBtu” means one million Btus.

 

 

“MMcf” means one million cubic feet.

 

 

“MMcfpd” means one million cubic feet per day.

 

 

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

 

 

“NGL” means natural gas liquid.

 

 

“NYMEX” means the New York Mercantile Exchange.

 

 

“NYSE” means the New York Stock Exchange.

 

 

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

 

 

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

 

 

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

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

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

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

 

 

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

 

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

 

 

“U.S.” means United States.

 

 

“VPP” means volumetric production payment.

 

 

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

 

 

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

 

 

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

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

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

 

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PART I

 

ITEM 1. BUSINESS

General

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

The Company’s executive offices are located at 5205 N. O’Connor Blvd., Suite 200, Irving, Texas 75039. The Company’s telephone number is (972) 444-9001. The Company maintains other offices in Anchorage, Alaska; Denver, Colorado; Midland, Texas; London, England and Capetown, South Africa. At December 31, 2010, the Company had 2,248 employees, 1,399 of whom were employed in field and plant operations.

Available Information

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

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

Mission and Strategies

The Company’s mission is to enhance shareholder investment returns through strategies that maximize Pioneer’s long-term profitability and net asset value. The strategies employed to achieve this mission are predicated on maintaining financial flexibility, capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions. These strategies are anchored by the Company’s interests in long-lived Spraberry oil field; the liquid-rich Eagle Ford, Barnett Shale Combo, Hugoton and West Panhandle fields; and the Raton gas field; which together have an estimated remaining productive life in excess of 40 years. Underlying these fields are approximately 90 percent of the Company’s proved oil and gas reserves as of December  31, 2010.

Business Activities

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

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

 

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

During the second half of 2009 and throughout 2010, economic stimulus initiatives implemented in the United States and worldwide served to stabilize economies and increase industry and consumer confidence. While oil and NGL prices have steadily improved since the beginning of the second quarter of 2009, gas prices have remained volatile throughout 2009 and 2010 as a result of increased gas supply and growing storage levels in the United States, which has offset the growth in demand. The outlook for continuation of the worldwide economic recovery in 2011 is cautiously optimistic but remains uncertain; therefore, the sustainability of the recovery in worldwide demand for energy is difficult to predict. As a result, the Company believes it is likely that commodity prices, especially North American gas prices, will continue to be volatile during 2011.

Significant factors that will impact 2011 commodity prices include: the ongoing impact of economic stimulus initiatives in the United States and worldwide in response to the worldwide economic decline; political and economic developments in North Africa and the Middle East; demand of Asian and European markets; the extent to which members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations are able to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals.

Pioneer uses commodity derivative contracts to mitigate the impact of commodity price volatility on the Company’s net cash provided by operating activities and its net asset value. Although the Company has entered into derivative contracts on a large portion of its forecasted production through 2014, a sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Company could enter into derivative contracts on additional volumes in the future. As a result, the Company’s internal cash flows would be reduced for affected periods. A sustained decline in commodity prices could result in a shortfall in expected cash flows, which could negatively impact the Company’s liquidity, financial position and future results of operations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the impact to oil, NGL and gas revenues during 2010, 2009 and 2008 from the Company’s derivative price risk management activities and the Company’s open derivative positions at December 31, 2010.

The Company. The Company’s asset base is anchored by the Spraberry oil field located in West Texas, the Raton gas field located in southern Colorado, the Hugoton gas field located in southwest Kansas and the West Panhandle gas field located in the Texas Panhandle. Complementing these areas, the Company has exploration and development opportunities and/or oil and gas production activities in the Eagle Ford Shale and Edwards Trend areas of South Texas, the Barnett Shale area of North Texas and Alaska, and internationally in South Africa. Combined, these assets create a portfolio of resources and opportunities that are well balanced among oil, NGL and gas, and that are also well balanced among long-lived, dependable production and lower-risk exploration and development opportunities. Additionally, the Company has a team of dedicated employees that represent the professional disciplines and sciences that are necessary to allow Pioneer to maximize the long-term profitability and net asset value inherent in its physical assets.

The Company provides administrative, financial, legal and management support to United States and foreign subsidiaries that explore for, develop and produce proved reserves. Production operations are principally located domestically in Texas, Kansas, Colorado and Alaska, and internationally in South Africa.

Production. The Company focuses its efforts towards maximizing its average daily production of oil, NGLs and gas through development drilling, production enhancement activities and acquisitions of producing properties, while minimizing the controllable costs associated with the production activities. For the year ended December 31, 2010, the Company’s production of 41.9 MMBOE was consistent with production during 2009. Production, price and cost information with respect to the Company’s properties for 2010, 2009 and 2008 is set forth in “Item 2. Properties — Selected Oil and Gas Information — Production, Price and Cost Data.”

Development activities. The Company seeks to increase its oil and gas reserves, production and cash flow through development drilling and by conducting other production enhancement activities, such as well recompletions. During the three years ended December 31, 2010, the Company drilled 1,033 gross (952 net) development wells, 99 percent of which were successfully completed as productive wells, at a total drilling cost (net to the Company’s interest) of $1.9 billion.

 

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PIONEER NATURAL RESOURCES COMPANY

 

The Company believes that its current property base provides a substantial inventory of prospects for future reserve, production and cash flow growth. The Company’s proved reserves as of December 31, 2010 include proved undeveloped reserves and proved developed reserves that are behind pipe of 219 MMBbls of oil, 79 MMBbls of NGLs and 991 Bcf of gas. The Company believes that its current portfolio of proved reserves provides attractive development opportunities for at least the next five years. The timing of the development of these reserves will be dependent upon commodity prices, drilling and operating costs and the Company’s expected operating cash flows and financial condition.

Exploratory activities. The Company has devoted significant efforts and resources to hiring and developing a highly skilled geoscience staff as well as acquiring a portfolio of lower-risk exploration opportunities. Exploratory and extension drilling involve greater risks of dry holes or failure to find commercial quantities of hydrocarbons than development drilling or enhanced recovery activities. See “Item 1A. Risk Factors — Exploration and development drilling may not result in commercially productive reserves” below.

Acquisition activities. The Company regularly seeks to acquire properties that complement its operations, provide exploration and development opportunities and potentially provide superior returns on investment. In addition, the Company pursues strategic acquisitions that will allow the Company to expand into new geographical areas that feature producing properties and provide exploration/exploitation opportunities. During 2010, 2009 and 2008, the Company invested $181.6 million, $88.9 million and $137.6 million, respectively, of acquisition capital to purchase proved oil and gas properties, including additional interests in its existing assets, and to acquire new prospects for future exploitation and exploration activities.

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

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

During February 2011, the Company sold 100 percent of its share holdings in its Tunisian subsidiaries for cash proceeds of $866 million, before normal closing adjustments. As a result of having committed to a plan to sell the Tunisian subsidiaries during 2010, the Company has classified its Tunisian assets and liabilities as assets and liabilities held for sale and the historic results of operations of its Tunisian assets as discontinued operations in its accompanying consolidated financial statements.

The Company anticipates that it will continue to sell nonstrategic properties or other assets from time to time to increase capital resources available for other activities, to achieve operating and administrative efficiencies and to improve profitability. See Notes M and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for specific information regarding the Company’s asset divestitures and discontinued operations, including the 2011 sale of Tunisia, during 2010, 2009 and 2008.

Operations by Geographic Area

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

 

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PIONEER NATURAL RESOURCES COMPANY

 

Marketing of Production

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

Significant purchasers. During 2010, the Company’s significant purchasers of oil, NGLs and gas were Plains Marketing LP (12 percent) and Enterprise Products Partners L.P. (10 percent). The Company believes that the loss of any one purchaser would not have an adverse effect on its ability to sell its oil, NGL and gas production.

Derivative risk management activities. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts and began accounting for its derivative contracts using the mark-to-market (“MTM”) method of accounting. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a description of the Company’s derivative risk management activities, “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” and Note I of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information about the impact of commodity derivative activities on oil, NGL and gas revenues and net derivative gains and losses during 2010, 2009 and 2008, as well as the Company’s open commodity derivative positions at December 31, 2010.

Competition, Markets and Regulations

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

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

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

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

 

   

require the acquisition of various permits before drilling commences;

 

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

 

   

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

 

   

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

 

   

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

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

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

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

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

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

The Company currently owns or leases numerous properties that have been used for oil and gas exploration and production for many years. Although the Company believes it has used operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by the Company, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of the Company’s properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons were not under the Company’s control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by the Company. These

 

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properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

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

The primary federal law imposing liability for oil spills is the Oil Pollution Act (“OPA”), which sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil spill cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

Operations associated with the Company’s properties also produce wastewaters that are disposed via injection in underground wells. These injection wells are regulated by the Safe Drinking Water Act (the “SDWA”) and analogous state and local laws. The underground injection well program under the SDWA requires permits from the EPA or analogous state agency for the Company’s disposal wells, establishes minimum standards for injection well operations, and restricts the types and quantities of fluids that may be injected. Currently, the Company believes that disposal well operations on the Company’s properties comply with all applicable requirements under the SDWA. However, a change in the regulations or the inability to obtain permits for new injection wells in the future may affect the Company’s ability to dispose of produced waters and ultimately increase the cost of the Company’s operations. In addition, Congress has considered legislation that would repeal an exemption in the SDWA for the underground injection of hydraulic fracturing fluids near drinking water sources. Sponsors of the legislation have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the legislation could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The legislation also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The Subcommittee on Energy and Environment of the U.S. House of Representatives is examining the practice of hydraulic fracturing in the United States and is gathering information on its potential effects on human health and the environment. The EPA also has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health. In addition, various state and local governments have implemented or are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, requirements for disclosure of chemical constituents, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds.

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

 

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produced water withdrawn in connection with CBM activities. The Company’s CBM or other oil and gas operations and the Company’s ability to expand its operations could be adversely affected, and these changes in regulation could ultimately increase the Company’s cost of doing business.

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

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require the Company to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies for gas and oil exploration and production operations. In addition, some gas and oil production facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Gas and oil exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

In January 2010, the Texas Commission on Environmental Quality (the “TCEQ”) concluded an analysis of air emissions of third-party operators in the Barnett Shale area in response to reported concerns about high concentrations of benzene in the air near certain drilling sites and gas processing facilities. The TCEQ’s investigation revealed elevated levels of benzene and other emissions at certain locations. The agency has continued to monitor emissions and pledged to investigate all complaints about oil and gas activities in the Barnett Shale area within 12 hours of receipt. Partially in response to its investigation, the TCEQ recently adopted new air emissions limitations and permitting requirements for oil and gas facilities in the state, which will first become applicable to facilities located in the Barnett Shale area on April 1, 2011. The TCEQ expects to expand the application of the requirements to facilities in other areas of the state in early 2012. These new requirements could increase the cost and time associated with drilling wells in the Barnett Shale, or other areas of the State in the future. The agency’s investigations could lead to additional, more stringent air permitting requirements, increased regulation, and possible enforcement actions against producers, including Pioneer, in the Barnett Shale area. In addition, environmental groups have advocated for increased regulation in the Barnett Shale area, and at least one state representative has advocated a moratorium on the issuance of drilling permits for new gas wells in the area. Any adoption of laws, regulations, orders or other legally enforceable mandates governing gas drilling and operating activities in the Barnett Shale or other areas of the State that result in more stringent drilling or operating conditions or limit or prohibit the drilling of new gas wells for any extended period of time could increase the Company’s costs and/or reduce its production, which could have a material adverse effect on the Company’s results of operations and cash flows.

Health and safety. The Company’s operations are subject to the requirements of the federal Occupational Safety and Health Act (the “OSH Act”) and comparable state statutes. These laws and the related regulations strictly govern the protection of the health and safety of employees. The OSH Act hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statues require that the Company organize or disclose information about hazardous materials used or produced in the Company’s operations. The Company believes that it is in substantial compliance with these applicable requirements and with other OSH Act and comparable requirements.

Global warming and climate change. In December 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases,” or “GHGs,” present an endangerment to human health and welfare because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of

 

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GHGs under existing provisions of the CAA. The EPA recently adopted two sets of rules, which became effective January 2, 2011, that regulate greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources. The EPA has also adopted rules requiring the reporting, on an annual basis, beginning in 2011 of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, for emissions occurring after January 1, 2010, as well as certain oil and gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

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

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Company’s business, financial condition and results of operations. It should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Company’s financial condition and results of operations.

Finally, other nations have been seeking to reduce emissions of GHGs pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of GHGs to below 1990 levels by 2012. Depending on the particular jurisdiction in which the Company’s operations are located, it could be required to purchase and surrender allowances for GHG emissions resulting from the Company’s operations.

The Company believes it is in substantial compliance with all existing environmental laws and regulations applicable to the Company’s current operations and that its continued compliance with existing requirements will not have a material adverse effect on the Company’s financial condition and results of operations. For instance, the Company did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2010. Additionally, the Company is not aware of any environmental issues or claims that will require material capital expenditures during 2011. However, accidental spills or releases may occur in the course of the Company’s operations, and the Company cannot give any assurance that it will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, the Company cannot give any assurance that the passage of more stringent laws or regulations in the future will not have a negative effect on the Company’s business, financial condition and results of operations.

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

 

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

 

   

the location of wells;

 

   

the method of drilling and casing wells;

 

   

the method and ability to fracture stimulate wells;

 

   

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

 

   

the plugging and abandoning of wells; and

 

   

notice to surface owners and other third parties.

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

Regulation of transportation and sale of gas. The availability, terms and cost of transportation significantly affect sales of gas. Foreign, federal and state regulations govern the price and terms for access to gas pipeline transportation. The interstate transportation and sale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). The FERC’s regulations for interstate gas transmission in some circumstances may also affect the intrastate transportation of gas. As a result of initiatives like FERC Order No. 636 (“Order 636”), issued in April 1992, the interstate gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all gas supplies. In many instances, the results of Order 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of gas in favor of providing only storage and transportation services.

In August 2005, the United States Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as the Company, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1.0 million per day per violation. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order 704 (defined below).

 

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In December 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as the Company, that engages in wholesale sales or purchases of gas that equal or exceed 2.2 million MMBtus during a calendar year annually report such sales and purchases to the FERC. Order 704 is intended to increase the transparency of the wholesale gas markets and to assist the FERC in monitoring those markets and in detecting market manipulation.

Although gas prices are currently unregulated, the United States Congress historically has been active in the area of gas regulation. The Company cannot predict whether new legislation to regulate gas or gas prices might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on the Company’s operations. Sales of condensate and gas liquids are not currently regulated and are made at market prices.

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

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

 

ITEM 1A. RISK FACTORS

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

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

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

 

   

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

 

   

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

 

   

weather conditions;

 

   

overall domestic and global political and economic conditions;

 

   

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

 

   

the effect of LNG deliveries to the United States;

 

   

technological advances affecting energy consumption and energy supply;

 

   

domestic and foreign governmental regulations and taxation;

 

   

the effect of energy conservation efforts;

 

   

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

 

   

the price and availability of alternative fuels.

 

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In the past, commodity prices have been extremely volatile, and the Company expects this volatility to continue. For example, oil prices reached record levels in July 2008 of $145.29 per Bbl before declining to $33.87 per Bbl in December 2008, while gas prices reached $13.58 per Mcf before declining to $5.29 per Mcf over the same period. During 2009, oil prices increased from a low of $33.98 per Bbl in February to a high of $81.37 per Bbl in October, while gas prices declined from $6.07 per Mcf in January to $2.51 per Mcf in September. During 2010, oil prices fluctuated from a low of $68.01 per Bbl in May to a high of $91.51 per Bbl in December, while gas prices fluctuated from a high of $6.01 per Mcf in January to a low of $3.29 per Mcf in October. The Company makes price assumptions that are used for planning purposes, and a significant portion of the Company’s cash outlays, including rent, salaries and noncancellable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, the Company’s financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.

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

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

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

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

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

 

   

production is less than the contracted derivative volumes,

 

   

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

 

   

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

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

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

The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default on its obligations under the Company’s derivative arrangements, such a default could have a material, adverse effect on the Company’s results of operations, and could result in a larger percentage of the Company’s future production being subject to commodity price changes.

 

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

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

 

   

unexpected drilling conditions;

 

   

unexpected pressure or irregularities in formations;

 

   

equipment failures or accidents;

 

   

fracture stimulation accidents or failures;

 

   

adverse weather conditions;

 

   

restricted access to land for drilling or laying pipelines; and

 

   

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

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

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

Declines in commodity prices may result in the Company’s having to make substantial downward adjustments to the Company’s estimated proved reserves. If this occurs, or if the Company’s estimates of production or economic factors change, accounting rules may require the Company to impair, as a noncash charge to earnings, the carrying value of the Company’s oil and gas properties. The Company is required to perform impairment tests on proved oil and gas properties whenever events or changes in circumstances indicate that the carrying value of proved properties may not be recoverable. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of the Company’s oil and gas properties, the carrying value may not be recoverable and therefore an impairment charge will be required to reduce the carrying value of the proved properties to their estimated fair value. For example, during 2009 and 2008, the Company recognized impairment charges of $21.1 million and $89.8 million, respectively, due to the impairment of the Company’s net assets in the Uinta/Piceance area, primarily due to declines in gas prices and downward adjustments to the economically recoverable resource potential. The Company may incur impairment charges in the future, which could materially affect the Company’s results of operations in the period incurred.

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

At December 31, 2010, the Company carried unproved property costs of $191.1 million. GAAP requires periodic evaluation of these costs on a project-by-project basis. These evaluations are affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of the leases, contracts and permits appurtenant to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize noncash charges in the earnings of future periods.

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

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

 

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

 

   

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

 

   

the validity of assumptions about costs, including synergies;

 

   

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

 

   

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

 

   

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

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

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

The Company regularly reviews its property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect the ability of the Company to dispose of nonstrategic assets or complete announced dispositions, including the availability of purchasers willing to purchase the nonstrategic assets at prices acceptable to the Company. Sellers typically retain certain liabilities or indemnify buyers for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release the Company from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a sale, the Company may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

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

At December 31, 2010, the Company carried goodwill of $298.2 million associated with its United States reporting unit. Goodwill is tested for impairment annually during the third quarter using a July 1 assessment date, and also whenever facts or circumstances indicate that the carrying value of the Company’s goodwill may be impaired, requiring an estimate of the fair values of the reporting unit’s assets and liabilities. Those assessments may be affected by (a) future reserve adjustments both positive and negative, (b) results of drilling activities, (c) changes in management’s outlook on commodity prices and costs and expenses, (d) changes in the Company’s market capitalization, (e) changes in the Company’s weighted average cost of capital and (f) changes in income taxes. If the fair value of the reporting unit’s net assets is not sufficient to fully support the goodwill balance in the future, the Company will reduce the carrying value of goodwill for the impaired value, with a corresponding noncash charge to earnings in the period in which goodwill is determined to be impaired.

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

As of December 31, 2010, the Company owned interests in four gas processing plants and 11 treating facilities. The Company operates two of the gas processing plants and all 11 of the treating facilities. There are significant risks associated with the operation of gas processing plants. Gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of a gas processing plant or facility could result in an explosion or the discharge of toxic gases, which could result in significant damage claims in addition to interrupting a revenue source.

 

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

The Company’s operations are subject to all the risks normally incident to the oil and gas development and production business, including:

 

   

blowouts, cratering, explosions and fires;

 

   

adverse weather effects;

 

   

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

 

   

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

 

   

facility or equipment malfunctions, failures or accidents;

 

   

title problems;

 

   

pipe or cement failures or casing collapses;

 

   

compliance with environmental and other governmental requirements;

 

   

lost or damaged oilfield workover and service tools;

 

   

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

 

   

natural disasters.

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

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

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

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

The Company may not be able to obtain access to pipelines, gas gathering, transmission, storage and processing facilities to market its oil, NGL and gas production.

The marketing of oil, NGL and gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. If there were insufficient capacity available on these systems, or if these systems were unavailable to the Company, the price offered for the Company’s production could be significantly depressed, or the Company could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while it constructs its own facility. The Company also relies (and expects to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit and sell its oil, NGL and gas production. The Company’s plans to develop and sell its oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient transmission, storage or processing facilities to the Company, especially in areas of planned expansion where such facilities do not currently exist.

 

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

The oil and gas business is subject to environmental hazards such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose the Company to substantial liability due to pollution and other environmental damage. A variety of United States federal, state and local, as well as foreign laws and regulations govern the environmental aspects of the oil and gas business. Noncompliance with these laws and regulations may subject the Company to administrative, civil or criminal penalties, remedial cleanups, and natural resource damages or other liabilities, and compliance with these laws and regulations may increase the cost of the Company’s operations. Such laws and regulations may also affect the costs of acquisitions. See “Item 1. Business — Competition, Markets and Regulations — Environmental matters and regulations” above for additional discussion related to environmental risks.

No assurance can be given that existing or future environmental laws will not result in a curtailment of production or processing activities, result in a material increase in the costs of production, development, exploration or processing operations or adversely affect the Company’s future operations and financial condition. Pollution and similar environmental risks generally are not fully insurable.

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

The Company is a borrower under fixed rate senior notes, senior convertible notes and a credit facility. The terms of the Company’s borrowings under the senior notes, senior convertible notes and the credit facility specify scheduled debt repayments and require the Company to comply with certain associated covenants and restrictions. The Company’s ability to comply with the debt repayment terms, associated covenants and restrictions is dependent on, among other things, factors outside the Company’s direct control, such as commodity prices and interest rates. See Note E of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the Company’s outstanding debt as of December 31, 2010 and the terms associated therewith.

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

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

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

 

   

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

 

   

marketing oil, NGL and gas production; and

 

   

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

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

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

The Company’s business is regulated by a variety of federal, state, local and foreign laws and regulations. For instance, the TCEQ recently adopted rules establishing new air emissions limitations and permitting requirements for oil and gas activities in the Barnett Shale area, which may increase the cost and time associated with drilling wells in that area. In addition, in connection with the Company’s CBM operations in the Raton Basin in Colorado, the Colorado Supreme Court affirmed a state water court holding that water produced in connection with CBM operations should be subject to state water-use regulations, including regulations requiring permits for diversion and use of surface and subsurface water, an evaluation of potential competing permits, possible uses of the water and a possible requirement to provide augmentation water supplies for water rights owners with more senior rights. There can be no assurance that present or future regulations will not adversely affect the Company’s business and operations, including that the Company may be required to suspend drilling operations or shut in production pending compliance. See “Item 1. Business — Competition, Markets and Regulations” for additional discussion regarding government regulation.

 

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

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

 

   

economic and labor conditions;

 

   

war, terrorist acts and civil disturbances;

 

   

political instability;

 

   

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

 

   

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

 

   

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

 

   

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

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

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

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

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

 

   

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

 

   

the quality and quantity of available data;

 

   

the interpretation of that data;

 

   

the assumed effects of regulations by governmental agencies;

 

   

assumptions concerning future commodity prices; and

 

   

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

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

 

   

the quantities of oil and gas that are ultimately recovered;

 

   

the production costs incurred to recover the reserves;

 

   

the amount and timing of future development expenditures; and

 

   

future commodity prices.

 

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

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

 

   

the amount and timing of actual production;

 

   

levels of future capital spending;

 

   

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

 

   

changes in governmental regulations or taxation.

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

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

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

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

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

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

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

A subsidiary of the Company acts as the general partner of Pioneer Southwest Energy Partners L.P., a publicly-traded limited partnership formed by the Company to own, develop and acquire oil and gas assets in its area of operations. As general partner, the subsidiary may be deemed to have undertaken fiduciary obligations to the partnership. Activities determined to involve fiduciary obligations to others typically involve a higher standard of conduct than ordinary business operations and therefore may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Any such liability may be material.

 

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

While the credit markets, the availability of credit and the equity markets have improved during 2009 and 2010, the economic outlook for 2011 remains uncertain. To the extent that purchasers of the Company’s production rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to the Company if such purchasers were unable to access the credit or equity markets for an extended period of time. If for any reason the Company were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of the Company’s production were uncollectible, the Company would recognize a pre-tax charge in the earnings of that period for the probable loss.

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

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

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

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

Concerns over the worldwide economic outlook, geopolitical issues, the availability and cost of credit and the United States mortgage and real estate markets contributed to increased volatility and diminished expectations for the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment resulted in a worldwide recession during the second half of 2008 and most of 2009. While the worldwide economic outlook has improved, concerns about global economic growth could have a significant adverse effect on global financial markets and commodity prices. If the economic climate in the United States or abroad were to deteriorate, demand for petroleum products could diminish, which could depress the prices at which the Company could sell its oil, NGLs and gas and ultimately decrease the Company’s net revenue and profitability.

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

The Fiscal Year 2012 Budget proposed by the President recommends elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress which would implement many of these proposals. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and

 

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

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

During December 2009, the EPA officially published its findings that emissions of GHGs present an endangerment to human health and welfare because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal CAA. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA recently adopted two sets of rules, which became effective January 2, 2011, that regulate greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources. The EPA has also adopted rules requiring the reporting, on an annual basis, beginning in 2011 of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, for emissions occurring after January 1, 2010, as well as certain oil and gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

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

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Company’s business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Company’s financial condition and results of operations. See “Item 1. Business – Competition, Markets and Regulations.”

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to the Company is uncertain at this time. The financial reform legislation may also require the counterparties to the

 

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

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

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

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

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

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

 

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ITEM 2. PROPERTIES

Reserve Rule Changes

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

Changing disclosure requirements and providing formats for tabular reserve disclosures.

Reserve Estimation Procedures and Audits

The information included in this Report about the Company’s proved reserves as of December 31, 2010, 2009 and 2008, which were located in the United States, South Africa and Tunisia, is based on evaluations prepared by (i) the Company’s engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), with respect to the Company’s major properties, and (ii) the Company’s engineers, with respect to all other properties. The Company has no oil and gas reserves from non-traditional sources. Additionally, the Company does not provide optional disclosure of probable or possible reserves. See Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the sale of 100 percent of the Company’s share holdings in its Tunisian subsidiaries during February 2011, which owned 100 percent of the Company’s Tunisia proved reserves.

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

The management of Pioneer’s oil and gas assets is decentralized geographically by individual asset teams who are responsible for the oil and gas activities in each of the Company’s Permian Basin, Rockies, Mid-Continent, South Texas—Eagle Ford Shale, South Texas—Edwards, Barnett Shale, Alaska and Africa asset teams (the “Asset Teams”). The Company’s Asset Teams are each staffed with reservoir engineers and geoscientists who prepare reserve estimates at the end of each calendar quarter for the assets that they manage, using reservoir engineering information technology. There is shared oversight of the Asset Teams’ reservoir engineers by the Asset Teams’ managers and the Director of the WWR, each of whom is in turn subject to direct or indirect oversight by the Company’s Chief Operating Officer (“COO”) and management committee (“MC”). The Company’s MC is comprised of its Chief Executive Officer, COO, Chief Financial Officer and other Executive Vice Presidents. Asset Teams’ reserve estimates are reviewed by the asset team reservoir engineers before being submitted to the Director of the WWR and are summarized in reserve reconciliations that quantify reserve changes represented by revisions of previous estimates, purchases of minerals-in-place, improved recovery, extensions and discoveries, production and sales of minerals-in-place. All reserve estimates, material assumptions and inputs used in reserve estimates and significant changes in reserve estimates are reviewed for engineering and financial appropriateness and compliance with SEC and GAAP standards by the WWR, in consultation with the Company’s accounting and financial management personnel. Annually, the MC reviews the reserve estimates and any differences with NSAI (for the portion of the reserves audited by NSAI) on a consolidated basis before these estimates are approved. The engineers and geoscientists who participate in the reserve estimation and disclosure process periodically attend training on the Reserve Ruling by external consultants and/or through internal Pioneer programs. Additionally, the WWR has

 

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prepared and maintains written policies and guidelines for the Asset Teams to reference on reserve estimation and preparation to promote objectivity in the preparation of the Company’s reserve estimates and SEC and GAAP compliance in the reserve estimation and reporting process.

Proved reserves audits. The reserve audits performed by NSAI in the aggregate represented 90 percent, 93 percent and 87 percent of the Company’s 2010, 2009 and 2008 proved reserves, respectively; and, 79 percent, 86 percent and 80 percent of the Company’s 2010, 2009 and 2008 associated pre-tax present value of proved reserves discounted at ten percent, respectively.

NSAI follows the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers (“SPE”). A reserve audit as defined by the SPE is not the same as a financial audit. The SPE’s definition of a reserve audit includes the following concepts:

 

 

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

 

 

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

 

 

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

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

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

 

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

Qualifications of reserves preparers and auditors. The WWR is staffed by petroleum engineers with extensive industry experience and is managed by the Director of WWR, the technical person that is primarily responsible for overseeing the Company’s reserves estimates. These individuals meet the professional qualifications of reserves estimators and reserves auditors as defined by the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,” promulgated by the board of directors of the SPE. The WWR Director’s qualifications include 33 years of experience as a petroleum engineer, with 26 years focused on reserves reporting for independent oil and gas companies, including Pioneer. His educational background includes an undergraduate degree in Chemical Engineering and a Masters of Business Administration degree in Finance. He is also a Chartered Financial Analyst Charterholder (“CFA”) and a member of the Oil and Gas Reserves Committee of the SPE.

NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. The technical person primarily responsible for auditing the Company’s reserves estimates has been a practicing consulting petroleum engineer at NSAI since 1983 and has over 31 years of practical experience in petroleum engineering, including 30 years of experience in the estimation and evaluation of proved reserves. He graduated with a Bachelor of Science degree in Chemical Engineering in 1978 and meets or exceeds the education, training and experience requirements set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the board of directors of the SPE.

Technologies used in reserves estimates. The Company uses reliable technologies to establish additions to reserve estimates, including seismic data and interpretation, wireline formation tests, geophysical logs and core data. Reserve additions associated with reliable technologies were less than two percent of the Company’s total proved reserves during the year ended December 31, 2010.

Proved Reserves

The Company’s proved reserves totaled 1,011 MMBOE, 898.6 MMBOE and 959.6 MMBOE at December 31, 2010, 2009 and 2008, respectively, representing $5.4 billion, $3.3 billion and $3.2 billion, respectively, of Standardized Measure. The Company’s proved reserves include field fuel, which is gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point. The following table shows the changes in the Company’s proved reserve volumes by geographic area during the year ended December 31, 2010 (in MBOE):

 

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     Production     Extensions and
Discoveries
     Improved
Recovery
     Purchases  of
Minerals-in-
Place
     Sales of
Minerals-in-

Place
    Revisions of
Previous
Estimates
 

United States

     (40,777     73,005        9,716        3,060        (5,108     63,540  

South Africa

     (2,035     —           —           —           —          406  

Tunisia

     (1,954     10,707        —           —           (560     2,145  
                                                   

Total

     (44,766     83,712        9,716        3,060        (5,668     66,091  
                                                   

Production. Production volumes include 2,882 MBOE of field fuel.

Extensions and discoveries. Extensions and discoveries are primarily comprised of extensions in the Spraberry field and discoveries in the Eagle Ford Shale area and Tunisia.

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

Purchases of minerals-in-place. Purchases of minerals-in-place are primarily attributable to acquisitions in the Company’s Spraberry field and Eagle Ford Shale play.

Sales of minerals-in-place. Sales of minerals-in-place are primarily related to the sale of 45 percent of the Company’s interest in certain proved properties in the Eagle Ford Shale. The sale was done in connection with entering into a joint venture with an unaffiliated third party to develop the Company’s Eagle Ford Shale acreage position. See Note M of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

Revisions of previous estimates. Revisions of previous estimates are comprised of 59 MMBOE of positive price revisions and 7 MMBOE of positive technical revisions. The Company’s proved reserves at December 31, 2010 were determined using the average of the first-day-of-the-month commodity prices during the 12-month period ending December 31, 2010 of $79.28 per barrel of oil and $4.37 per Mcf of gas, compared to $61.14 per barrel of oil and $3.87 per Mcf of gas as of December 31, 2009.

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

 

     Summary of Oil and Gas Reserves as of December 31, 2010
Based on Average Fiscal Year Prices
 
     Oil
(MBbls)
     NGLs
(MBbls)
     Gas
(MMcf) (a)
    MBOE      Standardized
Measure
 
     (in thousands)  

Developed:

             

United States

     160,421        108,785        1,736,765       558,667      $ 3,676,662  

South Africa

     274        —           15,671       2,886        47,579  

Tunisia

     12,121        —           23,175       15,984        341,638  
                                           
     172,816        108,785        1,775,611       577,537        4,065,879  
                                           

Undeveloped:

             

United States

     200,295        75,433        898,937       425,550        1,169,951  

Tunisia

     7,698        —           (26     7,694        176,179  
                                           
     207,993        75,433        898,911       433,244        1,346,130  
                                           

Total Proved

     380,809        184,218        2,674,522       1,010,781      $ 5,412,009  
                                           

 

(a)

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

 

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

Based on current price outlooks, the Company expects that future operating cash flows, together with a portion of the 2011 net proceeds from the sale of its Tunisian subsidiaries, will provide adequate funding for future development costs. The following table represents the estimated timing and cash flows of developing the Company’s proved undeveloped reserves as of December 31, 2010 (dollars in thousands):

 

Year Ended December 31, (a)

   Estimated
Future
Production
(MBOE)
     Future Cash
Inflows
     Future
Production
Costs
     Future
Development
Costs
     Future Net
Cash Flows
 

2011

     3,512      $ 221,273      $ 28,679      $ 683,742      $ (491,148

2012

     10,877        665,138        95,451        1,167,125        (597,438

2013

     18,558        1,040,615        160,818        1,272,636        (392,839

2014

     27,062        1,426,423        243,151        1,394,024        (210,752

2015

     30,467        1,597,836        288,419        1,164,644        144,773  

Thereafter

     342,769        16,957,215        5,298,483        339,099        11,319,633  
                                            
     433,245      $ 21,908,500      $ 6,115,001      $ 6,021,270      $ 9,772,229  
                                            

 

(a)

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

Description of Properties

United States

Approximately 86 percent of the Company’s proved reserves at December 31, 2010 are located in the Spraberry field in the Permian Basin area, the Hugoton and West Panhandle fields in the Mid-Continent area and the Raton field in the Rocky Mountains area. These fields generate substantial operating cash flow, and the Spraberry and Raton fields have a large portfolio of low-risk drilling opportunities. The cash flows generated from these fields provide funding for the Company’s other development and exploration activities both domestically and internationally.

 

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

 

           Development Drilling  
           Beginning Wells
In Progress
     Wells
Spud
     Successful
Wells
     Unsuccessful
Wells
     Ending Wells
In Progress
 

Permian Basin

       10        431        418        2        21  

Mid-Continent

       —           11        10        1        —     

Raton Basin

       —           1        1        —           —     

South Texas

       —           1        —           —           1  

Alaska

       1        4        4        —           1  
                                              

Total United States

       11        448        433        3        23  
                                              
    Exploration/Extension Drilling  
    Beginning Wells
In Progress
     Wells
Spud
     Successful
Wells
     Unsuccessful
Wells
     Sold Wells      Ending Wells
In Progress
 

Permian Basin

    —           6        3        —           —           3  

South Texas

    1        3        2           —           2  

Eagle Ford Shale

    2        39        19        —           —           22  

Barnett Shale

    2        17        8        —           —           11  

Alaska

    2        —           1        1        —           —     

Other

    1        3        1        2        1        —     
                                                    

Total United States

    8        68        34        3        1        38  
                                                    

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

 

     Oil (Bbls)      NGLs (Bbls)      Gas (Mcf)      Total (BOE)  

Permian Basin

     17,395        10,767        43,356        35,389  

Mid-Continent

     3,939        7,738        54,621        20,780  

Raton Basin

     —           —           170,716        28,453  

Barnett Shale

     94        971        9,060        2,575  

South Texas

     53        —           50,448        8,461  

Eagle Ford Shale

     381        250        5,937        1,620  

Alaska

     6,336        —           —           6,336  

Other

     13        10        1,118        209  
                                   

Total United States

     28,211        19,736        335,256        103,823  
                                   

 

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

 

     Property
Acquisition Costs
     Exploration
Costs
     Development
Costs
    Asset
Retirement

Obligations
    Total  
     Proved     Unproved            
     (in thousands)  

Permian Basin

   $ 4,393     $ 5,522      $ 24,104      $ 542,977     $ 24,447     $ 601,443  

Mid-Continent

     5       1,837        860        10,811       (1,421     12,092  

Raton Basin

     (363     777        6,273        9,984       (14,532     2,139  

South Texas

     134       2,622        35,090        10,741       (1,975     46,612  

Eagle Ford Shale

     2,481       112,353        97,485        1,307       1,316       214,942  

Barnett Shale

     (89     51,745        52,029        2,026       (166     105,545  

Alaska

     —          —           16,144        96,463 (a)     8,985       121,592  

Other

     —          150        7,380        (351     1,885       9,064  
                                                  

Total United States

   $ 6,561     $ 175,006      $ 239,365      $ 673,958     $ 18,539     $ 1,113,429  
                                                  

 

(a)

Includes $15.2 million of capitalized interest related to the Oooguruk project.

Permian Basin

Spraberry field. The Spraberry field was discovered in 1949 and encompasses eight counties in West Texas. According to the Energy Information Administration, the Spraberry field is the second largest oil field in the United States. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casinghead gas with an average energy content of 1,400 Btu. The oil and gas are produced primarily from four formations, the upper and lower Spraberry, the Dean and the Wolfcamp, at depths ranging from 6,700 feet to 11,300 feet. In addition, the Company has also begun evaluating the Strawn formation below the Wolfcamp in certain areas of the field that have better Strawn porosity with successful results and, during 2011, plans to drill 10 to 15 wells to test the Atoka formation, which lies directly below the Strawn formation.

The Company believes the Spraberry field offers excellent opportunities to grow oil and gas production because of the numerous undeveloped drilling locations, many of which are reflected in the Company’s proved undeveloped reserves; the ability to improve incremental recovery rates through infill and deeper formation drilling, waterflood projects and horizontal drilling in certain formations; and the ability to contain operating expenses and drilling costs through economies of scale and vertical integration of field services.

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

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

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

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

 

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

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

Mid-Continent

Hugoton field. The Hugoton field in southwest Kansas is one of the largest producing gas fields in the continental United States. The gas is produced from the Chase and Council Grove formations at depths ranging from 2,700 feet to 3,000 feet. The Company’s Hugoton properties are located on approximately 285,000 gross acres (247,000 net acres), covering approximately 400 square miles. The Company has working interests in approximately 1,225 wells in the Hugoton field, approximately 1,000 of which it operates, and partial working interest in approximately 225 wells.

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

West Panhandle field. The West Panhandle properties are located in the panhandle region of Texas. These stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite, Granite Wash and fractured Granite formations at depths no greater than 3,500 feet. The Company’s gas has an average energy content of 1,365 Btu and is produced from approximately 685 wells on more than 250,000 gross acres (240,000 net acres) covering over 375 square miles. The Company controls 100 percent of the wells, production equipment, gathering system and the Fain gas processing plant for the field. As this field is operated at or below vacuum conditions, Pioneer continually works to improve compressor and gathering system efficiency.

Raton

The Raton Basin properties are located in the southeast portion of Colorado. The Company owns approximately 256,000 gross acres (219,000 net acres) in the center of the Raton Basin and produces CBM gas from the coal seams in the Vermejo and Raton formations. The Company owns the majority of the well servicing and fracture stimulation equipment that it utilizes in the Raton field, allowing it to control costs and insure availability.

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

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

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

 

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

South Texas and Eagle Ford Shale

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

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

During June 2010, the Company entered into an Eagle Ford Shale joint venture transaction. Pursuant to the transaction, the Company entered into a purchase and sale agreement to sell 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds, including normal closing adjustments. The terms of the transaction also provide that the purchaser will pay 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. The Company’s current expectations are that the purchaser’s obligation to pay 75 percent of the Company’s defined exploration, drilling and completion costs attributable to Eagle Ford Shale assets will be satisfied by mid-2013. The Company and its joint venture partners have drilled 41 Eagle Ford Shale wells, of which 21 wells have been completed and are producing, three wells are completed and awaiting connections to sales lines and 17 wells remain in progress awaiting limited third-party fracture stimulation fleet availability. The Company also sold a 49.9 percent member interest in EFS Midstream LLC (“EFS Midstream”), an entity formed by the Company to own and operate gathering facilities in the Eagle Ford Shale area, to the purchaser for $46.4 million of cash proceeds and deferred a $46.2 million associated net gain. The Company does not have voting control of EFS Midstream and does not consolidate its financial statements.

EFS Midstream is obligated to construct certain of the gathering, treating and transportation infrastructure in the Eagle Ford Shale area. As EFS Midstream constructs these midstream assets, the Company will be responsible for funding 50.1 percent of EFS Midstream’s cash requirements. Construction of the midstream assets is underway, with the majority of the construction expected to be completed by 2013. Three of the 14 planned facilities (“CGPs”) were completed as of December 31, 2010. EFS Midstream plans to build five additional CGPs during 2011, with the first two expected to be completed during March. As construction of CGPs is completed, EFS Midstream will provide gathering, treating and transportation services for the Company during a 20-year contractual period.

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

 

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

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

Barnett Shale

During 2010, the Company continued to increase its acreage position in the liquid-rich Barnett Shale Combo area in North Texas. In total, the Company has accumulated approximately 80,000 gross acres in the liquid-rich area of the field, representing over 600 potential drilling locations. During the fourth quarter of 2010, the Company commenced a two-rig drilling program in the play.

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

Alaska

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

International

During 2010, the Company’s international operations were located offshore South Africa and in Tunisia. See Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the sale of the Company’s Tunisia subsidiaries during February 2011.

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

 

     Beginning Wells
In Progress
     Wells
Spud
     Successful
Wells
     Unsuccessful
Wells
     Ending Wells
In Progress
 

Exploration/extension drilling

     5        3        5        —           3  

Development drilling

     —           4        3        —           1  
                                            

Total

     5        7        8        —           4  
                                            

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

 

     Oil (Bbls)      NGLs (Bbls)      Gas (Mcf)      Total (BOE)  

South Africa

     616        —           29,760        5,576  

Tunisia

     4,880        —           2,849        5,355  
                                   

Total International

     5,496        —           32,609        10,931  
                                   

 

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

 

     Property
Acquisition Costs
     Exploration
Costs
     Development
Costs
    Asset
Retirement
Obligations
     Total  
     Proved      Unproved             
     (in thousands)  

South Africa

   $ —         $ —         $ 512      $ (53   $ 1,835      $ 2,294  

Tunisia

     —           —           30,630        39,053       820        70,503  

Other

     —           —           329        —          —           329  
                                                    

Total International

   $ —         $ —         $ 31,471      $ 39,000     $ 2,655      $ 73,126  
                                                    

South Africa

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

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

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

Tunisia

The Company held interests in four separate onshore permits located in the southern portion of Tunisia. During February 2011, the Company completed the sale of 100 percent of its share holdings in its Tunisian subsidiaries for cash proceeds of $866 million, before normal closing adjustments. The Company’s Tunisian permits covered a gross area of approximately 12,740 square kilometers containing three production concessions targeting the Acacus formation with additional future upside exploration potential from this and other formations. See Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information about the divestiture of the Company’s Tunisian subsidiaries.

Selected Oil and Gas Information

The following tables set forth selected oil and gas information from continuing operations for the Company as of and for each of the years ended December 31, 2010, 2009 and 2008. Because of normal production declines, increased or decreased drilling activities and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

Production, price and cost data. Oil and gas are commodities. The price that the Company receives for the oil and gas produced is largely a function of market supply and demand. Demand for oil and gas in the United States has increased dramatically during this decade. However, the economic slowdown reduced this demand during the second half of 2008 and through 2009. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or gas can result in substantial price volatility. Historically, commodity prices have been volatile and the Company expects that volatility to continue in the future. A substantial or extended decline in oil or gas prices or poor drilling results could have a material adverse effect on the Company’s financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and the Company’s ability to access capital markets.

 

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The following tables set forth production, price and cost data with respect to the Company’s properties for 2010, 2009 and 2008. These amounts represent the Company’s historical results from continuing operations without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the respective years. The production amounts will not agree to the reserve volume tables in the “Unaudited Supplementary Information” section included in “Item 8. Financial Statements and Supplementary Data” due to field fuel volumes and production associated with completed divestitures (reflected as discontinued operations) being included in the reserve volume tables.

PRODUCTION, PRICE AND COST DATA

 

     Year Ended December 31, 2010  
     United States      South
Africa
     Tunisia      Total  
     Spraberry
Field
    Raton
Field
     Total                       

Production information:

                

Annual sales volumes:

                

Oil (MBbls)

     6,314       —           10,297        225        1,781        12,303  

NGLs (MBbls)

     3,725       —           7,203        —           —           7,203  

Gas (MMcf)

     14,242       62,311        122,369        10,862        1,040        134,271  

Total (MBOE)

     12,413       10,385        37,895        2,035        1,954        41,885  

Average daily sales volumes:

                

Oil (Bbls)

     17,300       —           28,211        616        4,880        33,707  

NGLs (Bbls)

     10,206       —           19,736        —           —           19,736  

Gas (Mcf)

     39,020       170,716        335,256        29,760        2,849        367,865  

Total (BOE)

     34,009       28,453        103,823        5,576        5,355        114,754  

Average prices, including hedge results and amortization of deferred VPP revenue (a):

                

Oil (per Bbl)

   $ 91.53     $ —         $ 90.56      $ 78.07      $ 78.42      $ 88.57  

NGL (per Bbl)

   $ 33.11     $ —         $ 38.14      $ —         $ —         $ 38.14  

Gas (per Mcf)

   $ 3.41     $ 4.20      $ 4.18      $ 6.20      $ 11.25      $ 4.40  

Revenue (per BOE)

   $ 60.40     $ 25.19      $ 45.34      $ 41.74      $ 77.46      $ 46.67  

Average prices, excluding hedge results and amortization of deferred VPP revenue (a):

                

Oil (per Bbl)

   $ 77.24     $ —         $ 74.21      $ 78.07      $ 78.42      $ 74.89  

NGL (per Bbl)

   $ 33.11     $ —         $ 37.12      $ —         $ —         $ 37.12  

Gas (per Mcf)

   $ 3.41     $ 4.20      $ 4.15      $ 6.20      $ 11.25      $ 4.37  

Revenue (per BOE)

   $ 53.14     $ 25.19      $ 40.61      $ 41.74      $ 77.46      $ 42.39  

Average costs (per BOE):

                

Production costs:

                

Lease operating

   $ 11.40     $ 6.11      $ 7.74      $ 0.68      $ 4.98      $ 7.28  

Third-party transportation charges

     —          2.35        0.87        —           1.50        0.86  

Net natural gas plant/gathering

     (1.66     1.93        0.08        —           —           0.08  

Workover

     1.88       0.07        0.92        —           0.36        0.85  
                                                    

Total

   $ 11.62     $ 10.46      $ 9.61      $ 0.68      $ 6.84      $ 9.07  
                                                    

Production and ad valorem taxes:

                

Ad valorem

   $ 2.30     $ 0.46      $ 1.49      $ —         $ —         $ 1.35  

Production

     3.53       0.52        1.47        —           —           1.33  
                                                    

Total

   $ 5.83     $ 0.98      $ 2.96      $ —         $ —         $ 2.68  
                                                    

Depletion expense

   $ 9.02     $ 14.39      $ 12.40      $ 36.50      $ 12.07      $ 13.56  
                                                    

 

(a)

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

 

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PRODUCTION, PRICE AND COST DATA - (Continued)

 

     Year Ended December 31, 2009  
     United States      South
Africa
     Tunisia      Total  
     Spraberry
Field
    Raton
Field
     Total                       

Production information:

                

Annual sales volumes:

                

Oil (MBbls)

     5,836       —           9,113        137        2,384        11,634  

NGLs (MBbls)

     3,454       —           7,183        —           —           7,183  

Gas (MMcf)

     15,313       67,991        128,753        9,321        609        138,683  

Total (MBOE)

     11,842       11,332        37,756        1,690        2,485        41,931  

Average daily sales volumes:

                

Oil (Bbls)

     15,989       —           24,968        375        6,531        31,874  

NGLs (Bbls)

     9,461       —           19,680        —           —           19,680  

Gas (Mcf)

     41,954       186,278        352,749        25,538        1,668        379,955  

Total (BOE)

     32,443       31,046        103,440        4,631        6,809        114,880  

Average prices, including hedge results and amortization of deferred VPP revenue (a):

                

Oil (per Bbl)

   $ 73.12     $ —         $ 75.60      $ 65.94      $ 60.98      $ 72.49  

NGL (per Bbl)

   $ 25.91     $ —         $ 29.76      $ —         $ —         $ 29.76  

Gas (per Mcf)

   $ 2.84     $ 3.26      $ 3.88      $ 5.17      $ 8.14      $ 3.99  

Revenue (per BOE)

   $ 47.27     $ 19.59      $ 37.15      $ 33.85      $ 60.49      $ 38.40  

Average prices, excluding hedge results and amortization of deferred VPP revenue (a):

                

Oil (per Bbl)

   $ 56.25     $ —         $ 55.04      $ 65.94      $ 60.98      $ 56.38  

NGL (per Bbl)

   $ 25.91     $ —         $ 28.45      $ —         $ —         $ 28.45  

Gas (per Mcf)

   $ 2.84     $ 3.26      $ 3.32      $ 5.17      $ 8.14      $ 3.47  

Revenue (per BOE)

   $ 38.96     $ 19.59      $ 30.02      $ 33.85      $ 60.49      $ 31.98  

Average costs (per BOE):

                

Production costs:

                

Lease operating

   $ 10.47     $ 5.14      $ 7.39      $ 3.26      $ 7.38      $ 7.22  

Third-party transportation charges

     —          2.39        0.95        —           1.69        0.96  

Net natural gas plant/gathering

     (1.23     1.79        0.27        —           —           0.25  

Workover

     1.30       0.10        0.55        —           2.58        0.65  
                                                    

Total

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

Production and ad valorem taxes:

                

Ad valorem

   $ 2.10     $ 0.39      $ 1.51      $ —         $ —         $ 1.36  

Production

     2.72       0.12        1.10        —           —           0.99  
                                                    

Total

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

Depletion expense

   $ 8.69     $ 18.19      $ 14.20      $ 38.33      $ 8.77      $ 14.85  
                                                    

 

(a)

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

 

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PRODUCTION, PRICE AND COST DATA - (Continued)

 

      Year Ended December 31, 2008  
      United States      South
Africa
     Tunisia      Total  
      Spraberry
Field
    Raton
Field
     Total                       

Production information:

                

Annual sales volumes:

                

Oil (MBbls)

     5,713       —           7,720        880        2,261        10,861   

NGLs (MBbls)

     2,981       —           6,971        —           —           6,971   

Gas (MMcf)

     14,069       72,386        134,248        3,745        866        138,859   

Total (MBOE)

     11,038       12,064        37,065        1,504        2,406        40,975   

Average daily sales volumes:

                

Oil (Bbls)

     15,612       —           21,091        2,405        6,178        29,674   

NGLs (Bbls)

     8,141       —           19,048        —           —           19,048   

Gas (Mcf)

     38,440       197,775        366,796        10,232        2,367        379,395   

Total (BOE)

     30,161       32,963        101,271        4,110        6,573        111,954   

Average prices, including hedge results and amortization of deferred VPP revenue (a):

                

Oil (per Bbl)

   $ 117.10     $ —         $ 65.74      $ 110.21      $ 90.64      $ 74.53   

NGL (per Bbl)

   $ 46.49     $ —         $ 51.31      $ —         $ —         $ 51.31   

Gas (per Mcf)

   $ 6.33     $ 7.16      $ 7.66      $ 5.83      $ 12.04      $ 7.64   

Revenue (per BOE)

   $ 81.24     $ 42.95      $ 51.08      $ 79.00      $ 89.53      $ 54.36   

Average prices, excluding hedge results and amortization of deferred VPP revenue (a):

                

Oil (per Bbl)

   $ 98.88     $ —         $ 95.82      $ 110.21      $ 90.64      $ 95.91   

NGL (per Bbl)

   $ 46.49     $ —         $ 51.56      $ —         $ —         $ 51.56   

Gas (per Mcf)

   $ 6.33     $ 7.16      $ 7.39      $ 5.83      $ 12.04      $ 7.37   

Revenue (per BOE)

   $ 71.81     $ 42.95      $ 56.41      $ 79.00      $ 89.53      $ 59.18   

Average costs (per BOE):

                

Production costs:

                

Lease operating

   $ 12.57     $ 5.16      $ 7.66      $ 25.98      $ 6.26      $ 8.26   

Third-party transportation charges

     —          2.56        1.06        —           1.93        1.07   

Net natural gas plant/gathering

     (2.73     2.90        0.16        —           —           0.15   

Workover

     2.61       0.09        0.93        —           —           0.84   
                                                    

Total

   $ 12.45     $ 10.71      $ 9.81      $ 25.98      $ 8.19      $ 10.32   
                                                    

Production and ad valorem taxes:

                

Ad valorem

   $ 2.31     $ 0.81      $ 1.58      $ —         $ —         $ 1.43   

Production

     5.05       1.11        2.86        —           —           2.58   
                                                    

Total

   $ 7.36     $ 1.92      $ 4.44      $ —         $ —         $ 4.01   
                                                    

Depletion expense

   $ 7.61     $ 12.90      $ 11.30      $ 18.37      $ 5.96      $ 11.25   
                                                    

 

(a)

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

 

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

PRODUCTIVE WELLS (a)

 

      Gross Productive Wells      Net Productive Wells  
   Oil      Gas      Total      Oil      Gas      Total  

As of December 31, 2010:

                 

United States

     5,533        4,836        10,369        4,769        4,347        9,116  

South Africa

     —           6        6        —           3        3  

Tunisia

     33        —           33        10        —           10  
                                                     

Total

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

As of December 31, 2009:

                 

United States

     5,332        5,021        10,353        4,566        4,604        9,170  

South Africa

     —           6        6        —           3        3  

Tunisia

     29        —           29        9        —           9  
                                                     

Total

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

As of December 31, 2008:

                 

United States

     5,374        4,988        10,362        4,561        4,685        9,246  

South Africa

     —           6        6        —           3        3  

Tunisia

     28        —           28        8        —           8  
                                                     

Total

     5,402        4,994        10,396        4,569        4,688        9,257  
                                                     

 

(a)

Productive wells consist of producing wells and wells capable of production, including shut-in wells and gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. One or more completions in the same well bore are counted as one well. If any well in which one of the multiple completions is an oil completion, then the well is classified as an oil well. As of December 31, 2010, the Company owned interests in one gross well containing multiple completions.

Leasehold acreage. The following table sets forth information about the Company’s developed, undeveloped and royalty leasehold acreage as of December 31, 2010:

LEASEHOLD ACREAGE

 

      Developed Acreage      Undeveloped Acreage      Royalty
Acreage
 
      Gross Acres      Net Acres      Gross Acres      Net Acres     

United States:

              

Onshore

     1,501,102        1,287,560        796,549        622,091        297,599  

Offshore

     —           —           —           —           5,000  
                                            
     1,501,102        1,287,560        796,549        622,091        302,599  

South Africa

     119,579        53,281        3,508,421        1,578,789        —     

Tunisia

     297,424        83,009        2,645,012        1,930,582        —     
                                            

Total

     1,918,105        1,423,850        6,949,982        4,131,462        302,599  
                                            

 

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PIONEER NATURAL RESOURCES COMPANY

 

The following table sets forth the expiration dates of the leases on the Company’s gross and net undeveloped acres as of December 31, 2010:

 

      Acres Expiring (a)  
      Gross      Net  

2011 (b)

     1,967,292        1,498,990  

2012

     1,000,166        673,954  

2013

     230,115        187,613  

2014

     77,121        65,997  

2015

     38,697        22,390  

Thereafter

     3,636,591        1,682,518  
                 

Total

     6,949,982        4,131,462  
                 

 

(a)

Acres expiring are based on contractual lease maturities.

(b)

All acres subject to expiration during 2011 are in North America. The Company may extend the leases prior to their expiration based upon 2011 planned activities or for other business reasons. In certain leases, the extension is only subject to the Company’s election to extend and the fulfillment of certain capital expenditures commitments. In other cases, the extensions are subject to the consent of third parties, and no assurance can be given that the requested extensions will be granted. See “Description of Properties” above for information regarding the Company’s drilling operations.

Drilling and other exploratory and development activities. The following table sets forth the number of gross and net wells drilled by the Company during 2010, 2009 and 2008 that were productive or dry holes. This information should not be considered indicative of future performance, nor should it be assumed that there was any correlation between the number of productive wells drilled and the oil and gas reserves generated thereby or the costs to the Company of productive wells compared to the costs of dry holes.

DRILLING ACTIVITIES

 

     Gross Wells     Net Wells  
     Year Ended December 31,     Year Ended December 31,  
     2010     2009     2008     2010     2009     2008  

United States:

            

Productive wells:

            

Development

     433       60       526       378       58       504  

Exploratory

     34       13       56       22       7       46  

Dry holes:

            

Development

     3       —          7       3       —          7  

Exploratory

     3       2       17       1       2       9  
                                                
     473       75       606       404       67       566  
                                                

Tunisia:

            

Productive wells:

            

Development

     3       1       —          2       —          —     

Exploratory

     5       —          6       2       —          3  

Dry holes:

            

Development

     —          —          —          —          —          —     

Exploratory

     —          2       2       —          1       1  
                                                
     8       3       8       4       1       4  
                                                

Total

     481       78       614       408       68       570  
                                                

Success ratio (a)

     99     95     96     99     96     97

 

(a)

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

 

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Present activities. The following table sets forth information about the Company’s wells that were in process of being drilled as of December 31, 2010:

 

     Gross Wells      Net Wells  

United States:

     

Development

     23        22  

Exploratory

     38        25  
                 

Total

     61        47  
                 

Tunisia:

     

Development

     1        1  

Exploratory

     3        2  
                 
     4        3  
                 

Total

     65        50  
                 

 

ITEM 3. LEGAL PROCEEDINGS

The Company is party to the legal proceedings that are described under “Legal actions” in Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.” The Company is also party to other proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations.

 

ITEM 4. REMOVED AND RESERVED

 

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PIONEER NATURAL RESOURCES COMPANY

 

PART II

 

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

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

The following table sets forth quarterly high and low prices of the Company’s common stock and dividends declared per share for the years ended December 31, 2010 and 2009:

 

     High      Low      Dividends
Declared
Per Share
 

Year ended December 31, 2010

        

Fourth quarter

   $ 88.00      $ 64.97      $ —     

Third quarter

   $ 67.77      $ 54.89      $ 0.04  

Second quarter

   $ 74.00      $ 54.72      $ —     

First quarter

   $ 56.88      $ 41.88      $ 0.04  

Year ended December 31, 2009

        

Fourth quarter

   $ 50.00      $ 33.49      $ —     

Third quarter

   $ 36.74      $ 21.78      $ 0.04  

Second quarter

   $ 30.56      $ 15.67      $ —     

First quarter

   $ 20.44      $ 11.88      $ 0.04  

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

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

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company’s purchases of treasury stock during the three months ended December 31, 2010:

 

Period

   Total Number of
Shares  (or Units)
Purchased (a)
     Average Price
Paid per  Share
(or Unit)
     Total Number of  Shares
(or Units) Purchased
as Part of Publicly
Announced Plans
or Programs
     Approximate Dollar
Amount of Shares
that May Yet Be
Purchased under
Plans or Programs
 

October 2010

     334      $ 65.12        —        

November 2010

     1,481      $ 80.12        —        

December 2010

     1,524      $ 80.11        —        
                                   

Total

     3,339      $ 78.61        —         $ 355,789,018  
                                   

 

(a)

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

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

 

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ITEM 6. SELECTED FINANCIAL DATA

The following selected consolidated financial data of the Company as of and for each of the five years ended December 31, 2010 should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data.”

 

     Year Ended December 31,  
     2010      2009     2008      2007      2006  
     (in millions, except per share data)  

Statements of Operations Data:

             

Oil and gas revenues (a)

   $ 1,803.3      $ 1,459.7     $ 2,012.2      $ 1,589.0      $ 1,334.1  

Total revenues (b)

   $ 2,471.6      $ 1,347.7     $ 2,046.0      $ 1,615.1      $ 1,342.7  

Total costs and expenses

   $ 1,683.1      $ 1,595.1     $ 1,745.2      $ 1,344.3      $ 1,117.5  

Income (loss) from continuing operations

   $ 516.2      $ (159.2   $ 186.9      $ 202.7      $ 123.9  

Income (loss) from discontinued operations, net of tax (c)

   $ 129.8      $ 116.9     $ 44.8      $ 169.7      $ 613.6  

Net income (loss) attributable to common stockholders

   $ 605.2      $ (52.1   $ 210.0      $ 372.7      $ 739.7  

Income (loss) from continuing operations per share:

             

Basic

   $ 4.04      $ (1.48   $ 1.38      $ 1.64      $ 0.92  
                                           

Diluted

   $ 3.99      $ (1.48   $ 1.38      $ 1.63      $ 0.90  
                                           

Net income (loss) attributable to common stockholders per share:

             

Basic

   $ 5.14      $ (0.46   $ 1.76      $ 3.05      $ 5.85  
                                           

Diluted

   $ 5.08      $ (0.46   $ 1.76      $ 3.04      $ 5.75  
                                           

Dividends declared per share

   $ 0.08      $ 0.08     $ 0.30      $ 0.27      $ 0.25  
                                           

Balance Sheet Data (as of December 31):

             

Total assets

   $ 9,679.1      $ 8,867.3     $ 9,161.8      $ 8,617.0      $ 7,355.4  

Long-term obligations

   $ 4,683.9      $ 4,653.0     $ 4,787.2      $ 4,568.1      $ 3,469.4  

Total stockholders’ equity

   $ 4,226.0      $ 3,643.0     $ 3,679.6      $ 3,054.7      $ 2,999.0  

 

(a)

The Company’s oil and gas revenues for 2010, as compared to those of 2009, increased by $343.6 million (or 24 percent) due to increases in worldwide commodity prices and United States oil and NGL sales volumes, partially offset by decreases in United States and South Africa gas sales volumes. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for discussions about oil and gas revenues and factors impacting the comparability of such revenues.

(b)

The Company recognized $448.4 million of net derivative gains in its total revenues of 2010, including $364.4 million of noncash MTM gains as compared to $195.6 million of net derivative losses during 2009, including $191.6 million of noncash MTM losses. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Notes B and I of Notes to Consolidated Financial Statements included in “Item 8 Financial Statements and Supplementary Data” for information about the Company’s derivative contracts and associated accounting methods. The Company also recognized $138.9 million of net hurricane activity gains during 2010, primarily associated with East Cameron 322 insurance recoveries, as compared to $17.3 million of net hurricane activity charges during 2009. See Note T of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information about the East Cameron 322 project.

(c)

During February 2011, the Company sold 100 percent of its share holdings in its Tunisian subsidiaries, pursuant to a plan committed to during 2010. In accordance with GAAP, the Company has classified the Tunisia results of operations as discontinued operations, rather than a component of continuing operations. During 2010, the Company received $35.3 million of interest on excess royalties paid on oil and gas production from its deepwater Gulf of Mexico properties during the period from January 1, 2003 through December 31, 2005. During 2009, the Company recorded $119.3 million of pretax income for the recovery of the excess royalties previously mentioned and a $17.5 million pretax gain, primarily from the sale of substantially all of its Gulf of Mexico shelf properties. The Company’s Gulf of Mexico shelf and deepwater properties were sold effective July 1, 2009 and January 1, 2006, respectively. The results of operations of these properties, and certain other properties sold during the periods presented are classified as discontinued operations in accordance with GAAP. See Notes B and U of Notes to Consolidated Financial Statements included in “Item 8 Financial Statements and Supplementary Data” for more information about the Company’s discontinued operations.

 

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

Financial and Operating Performance

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

 

 

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

During June 2010, the Company entered into an Eagle Ford Shale joint venture transaction. Pursuant to the transaction, the Company entered into a purchase and sale agreement to sell 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds, including normal closing adjustments. Under the terms of the transaction, the purchaser is also paying 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. The Company’s current expectations are that the purchaser’s obligation to pay 75 percent of the Company’s defined exploration, drilling and completion costs attributable to Eagle Ford Shale assets will be satisfied by mid-2013.

 

 

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

 

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PIONEER NATURAL RESOURCES COMPANY

 

 

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

First Quarter 2011 Outlook

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

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

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

Total exploration and abandonment expense for the quarter is expected to be $25 million to $35 million. General and administrative expense is expected to be $45 million to $49 million. Interest expense is expected to be $44 million to $47 million, and other expense is expected to be $20 million to $25 million. Accretion of discount on asset retirement obligations from continuing operations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries’ net income, excluding noncash derivative MTM adjustments, is expected to be $9 million to $12 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company’s first quarter effective income tax rate from continuing operations is expected to range from 35 percent to 45 percent, assuming current capital spending plans and no significant derivative MTM changes in the Company’s derivative position. Cash income taxes are expected to be $5 million to $10 million, principally related to South African income taxes.

2011 Capital Budget

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

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

 

 

Spraberry field – $1.1 billion;

 

 

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

 

 

Barnett Shale Combo play – $170 million;

 

 

Alaska – $115 million; and

 

 

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

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

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

 

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Acquisitions

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

Divestitures

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

Eagle Ford Shale. In June 2010, the Company entered into an Eagle Ford Shale joint venture. Associated therewith, the Company sold 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds, including normal closing adjustments. Under the terms of the transaction, the purchaser is also paying 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. The Company’s current expectations are that the purchaser’s obligation to pay 75 percent of the Company’s defined exploration, drilling and completion costs attributable to Eagle Ford Shale assets will be satisfied by mid-2013.

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

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

Results of Operations

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

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

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

 

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

 

     Year Ended December 31,  
     2010      2009      2008  

Oil (Bbls):

        

United States

     28,211        24,968        21,091  

South Africa

     616        375        2,405  
                          

Worldwide

     28,827        25,343        23,496  
                          

NGLs (Bbls):

        

United States

     19,736        19,680        19,048  
                          

Gas (Mcf):

        

United States

     335,256        352,749        366,796  

South Africa

     29,760        25,538        10,232  
                          

Worldwide

     365,016        378,287        377,028  
                          

Total (BOE):

        

United States

     103,823        103,440        101,271  

South Africa

     5,576        4,631        4,110  
                          

Worldwide

     109,399        108,071        105,381  
                          

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

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

 

     Year Ended December 31,  
     2010      2009      2008  

Oil (Bbls):

        

United States

     —           554        953  

Tunisia

     4,880        6,531        6,178  
                          

Worldwide

     4,880        7,085        7,131  
                          

NGLs (Bbls):

        

United States

     —           29        35  
                          

Gas (Mcf):

        

United States

     —           1,899        3,428  

Tunisia

     2,849        1,668        2,367  
                          

Worldwide

     2,849        3,567        5,795  
                          

Total (BOE):

        

United States

     —           900        1,559  

Tunisia

     5,355        6,809        6,573  
                          

Worldwide

     5,355        7,709        8,132  
                          

 

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PIONEER NATURAL RESOURCES COMPANY

 

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

 

     Year Ended December 31,  
     2010      2009      2008  

Average reported prices:

        

Oil (per Bbl):

        

United States

   $ 90.56      $ 75.60      $ 65.74  

South Africa

   $ 78.07      $ 65.94      $ 110.21  

Worldwide

   $ 90.29      $ 75.45      $ 70.29  

NGL (per Bbl):

        

United States

   $ 38.14      $ 29.76      $ 51.31  

Gas (per Mcf):

        

United States

   $ 4.18      $ 3.88      $ 7.66  

South Africa

   $ 6.20      $ 5.17      $ 5.83  

Worldwide

   $ 4.34      $ 3.97      $ 7.61  

Total (per BOE):

        

United States

   $ 45.34      $ 37.15      $ 51.08  

South Africa

   $ 41.74      $ 33.85      $ 79.00  

Worldwide

   $ 45.16      $ 37.00      $ 52.17  

Average realized prices:

        

Oil (per Bbl):

        

United States

   $ 74.21      $ 55.04      $ 95.82  

South Africa

   $ 78.07      $ 65.94      $ 110.21  

Worldwide

   $ 74.30      $ 55.20      $ 95.84  

NGL (per Bbl):

        

United States

   $ 37.12      $ 28.45      $ 51.56  

Gas (per Mcf):

        

United States

   $ 4.15      $ 3.32      $ 7.39  

South Africa

   $ 6.20      $ 5.17      $ 5.83  

Worldwide

   $ 4.31      $ 3.45      $ 7.37  

Total (per BOE):

        

United States

   $ 40.61      $ 30.02      $ 56.41  

South Africa

   $ 41.74      $ 33.85      $ 79.00  

Worldwide

   $ 40.67      $ 30.19      $ 57.07  

Derivative activities. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts in order to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts. Changes in the fair value of effective cash flow hedges prior to the Company’s discontinuance of hedge accounting were recorded as a component of accumulated other comprehensive income – deferred hedge gains, net of tax (“AOCI – Hedging”), in the stockholders’ equity section of the Company’s consolidated balance sheets, and are being transferred to earnings during the same periods in which the hedged transactions are recognized in the Company’s earnings. Since February 1, 2009, the Company has recognized all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.

 

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PIONEER NATURAL RESOURCES COMPANY

 

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

 

     Year Ended December 31,  
     2010      2009      2008  

Increase (decrease) to oil revenue from AOCI—Hedging transfers

   $ 78,052      $ 88,873      $ (336,249

Increase (decrease) to NGL revenue from AOCI—Hedging transfers

     7,297        9,402        (1,781

Increase (decrease) to gas revenue from AOCI—Hedging transfers

     3,691        22,791        (17,533
                          

Total

   $ 89,040      $ 121,066      $ (355,563
                          

See Note I of Notes to Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data” for further information concerning the Company’s commodity derivatives and scheduled amortization of net deferred gains and losses on discontinued commodity hedges that will be recognized as increases or decreases to future oil and gas revenues.

Deferred revenue. During 2010, the Company’s amortization of deferred VPP revenue increased annual oil revenues by $90.2 million and, during 2009 and 2008, increased oil and gas revenues by $147.9 million and $158.1 million, respectively. The Company’s amortization of deferred VPP revenue will increase 2011 annual oil revenues by $45.0 million. See Note S of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for specific information regarding the Company’s VPP agreements.

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

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

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

 

     December 31,
2010
    December 31,
2009
    December 31,
2008
 

Unrealized mark-to-market changes in fair value:

      

Oil derivative gains (losses)

   $ 41,094     $ (150,799   $ (18,566

NGL derivative gains (losses)

     10,690       (20,206     7  

Gas derivative gains (losses)