10-K 1 d270523d10k.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, 2011

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.    x

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

 

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

   $ 10,243,708,609   

Number of shares of Common Stock outstanding as of February 24, 2012

   123,260,358  

DOCUMENTS INCORPORATED BY REFERENCE:

 

(1)

Proxy Statement for the 2012 Annual Meeting of Shareholders to be held during May 2012 — Referenced in Part III of this report.


Table of Contents

TABLE OF CONTENTS

 

          Page  

Definitions of Certain Terms and Conventions Used Herein

     4  

Cautionary Statement Concerning Forward-Looking Statements

     5   
PART I   

Item 1.

  

Business

     6  
  

General

     6  
  

Available Information

     6  
  

Mission and Strategies

     6  
  

Business Activities

     6  
  

Marketing of Production

     9  
  

Competition, Markets and Regulations

     9  

Item 1A.

  

Risk Factors

     16  

Item 1B.

  

Unresolved Staff Comments

     28  

Item 2.

  

Properties

     28  
  

Reserve Rule Changes

     28  
  

Reserve Estimation Procedures and Audits

     28  
  

Proved Reserves

     30  
  

Description of Properties

     33  
  

Selected Oil and Gas Information

     37  

Item 3.

  

Legal Proceedings

     43  

Item 4.

  

Mine Safety Disclosures

     43  

PART II

  

Item 5.

   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      44  
  

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

     44  

Item 6.

  

Selected Financial Data

     45  

Item 7.

  

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

     46  
  

Financial and Operating Performance

     46  
  

First Quarter 2012 Continuing Operations Outlook

     47  
  

2012 Capital Budget

     47  
  

Acquisitions

     48  
  

Divestitures and Discontinued Operations

     48  
  

Results of Operations

     49  
  

Capital Commitments, Capital Resources and Liquidity

     56  
  

Critical Accounting Estimates

     61  
  

New Accounting Pronouncements

     63  

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

     64  
  

Quantitative Disclosures

     64  
  

Qualitative Disclosures

     68  

Item 8.

  

Financial Statements and Supplementary Data

     70  
  

Index to Consolidated Financial Statements

     70  
  

Report of Independent Registered Public Accounting Firm

     71  
  

Consolidated Financial Statements

     72  
  

Notes to Consolidated Financial Statements

     79  
  

Unaudited Supplementary Information

     119  

Item 9.

  

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

     127  

Item 9A.

  

Controls and Procedures

     127  
  

Management’s Report on Internal Control Over Financial Reporting

     127  
  

Report of Independent Registered Public Accounting Firm

     128  

Item 9B.

  

Other Information

     129  

 

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TABLE OF CONTENTS

 

PART III  

Item 10.

  

Directors, Executive Officers and Corporate Governance

     129  

Item 11.

  

Executive Compensation

     129  

Item 12.

  

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

     129  
  

Securities Authorized for Issuance Under Equity Compensation Plans

     129  

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

     130  

Item 14.

  

Principal Accounting Fees and Services

     130  
PART IV   

Item 15.

  

Exhibits, Financial Statement Schedules

     130  

Signatures

     137  

Exhibit Index

     138  

 

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Definitions of Certain Terms and Conventions Used Herein

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

 

 

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

 

 

Bcf” means one billion cubic feet.

 

 

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

 

BOEPD” means BOE per day.

 

 

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

 

 

CBM” means coal bed methane.

 

 

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

 

 

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 gas volume.

 

 

MMBbl” means one million Bbls.

 

 

MMBOE” means one million BOEs.

 

 

MMBtu” means one million Btus.

 

 

MMcf” means one million cubic feet.

 

 

Mont Belvieu–posted-price” means the daily average natural gas liquids components as priced in Oil Price Information Service (“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.

 

 

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

 

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U.S.” means United States.

 

 

VPP” means volumetric production payment.

 

 

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

 

 

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

 

 

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

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Report”) contains forward-looking statements that involve risks and uncertainties. When used in this document, the words “believes,” “plans,” “expects,” “anticipates,” “forecasts,” “intends,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate,” or the negative of such terms and similar expressions as they relate to the Company are intended to identify forward-looking statements. 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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PIONEER NATURAL RESOURCES COMPANY

PART I

 

ITEM 1. BUSINESS

General

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

The Company’s executive offices are located at 5205 N. O’Connor Blvd., Suite 200, Irving, Texas 75039. The Company’s telephone number is (972) 444-9001. The Company maintains other offices in Anchorage, Alaska; Denver, Colorado; Midland, Texas and Capetown, South Africa. At December 31, 2011, the Company had 3,304 employees, 2,282 of whom were employed in field and plant operations.

Available Information

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

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

Mission and Strategies

The Company’s mission is to enhance shareholder investment returns through strategies that maximize Pioneer’s long-term profitability and net asset value. The strategies employed to achieve this mission are predicated on maintaining financial flexibility, capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions. These strategies are anchored by the Company’s interests in the long-lived Spraberry oil field; the liquid-rich Eagle Ford Shale, Barnett Shale Combo, Hugoton and West Panhandle fields; and the Raton gas field; which together have an estimated remaining productive life in excess of 40 years. Underlying these fields are approximately 93 percent of the Company’s proved oil and gas reserves as of December  31, 2011.

Business Activities

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

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

 

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

Significant factors that will impact 2012 commodity prices include: the ongoing impact of economic stimulus initiatives in the United States and worldwide and continuing economic struggles in Eurozone nations’ economies; political and economic developments in North Africa and the Middle East; demand from Asian and European markets; the extent to which members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations are able to manage oil supply through export quotas; and overall North American NGL and gas supply and demand fundamentals.

Pioneer uses commodity derivative contracts to mitigate the impact of commodity price volatility on the Company’s net cash provided by operating activities and its net asset value. Although the Company has entered into commodity derivative contracts for a large portion of its forecasted production through 2014, a sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Company could enter into derivative contracts on additional volumes in the future. As a result, the Company’s internal cash flows would be reduced for affected periods. A sustained decline in commodity prices could result in a shortfall in expected cash flows, which could negatively impact the Company’s liquidity, financial position and future results of operations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Notes I and J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the impact to oil and gas revenues during 2011, 2010 and 2009 from the Company’s derivative price risk management activities and the Company’s open derivative positions as of December 31, 2011.

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

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

Production. The Company focuses its efforts towards maximizing its average daily production of oil, NGLs and gas through development drilling, production enhancement activities and acquisitions of producing properties, while minimizing the controllable costs associated with the production activities. For the year ended December 31, 2011, the Company’s production from continuing operations, excluding field fuel usage, of 44.0 MMBOE represented a 16 percent increase over production from continuing operations during 2010. Production, price and cost information with respect to the Company’s properties for 2011, 2010 and 2009 is set forth in “Item 2. Properties — Selected Oil and Gas Information — Production, price and cost data.”

Development activities. The Company seeks to increase its oil and gas reserves, production and cash flow through development drilling and by conducting other production enhancement activities, such as well recompletions. During the three years ended December 31, 2011, the Company drilled 1,236 gross (1,112 net) development wells, 99 percent of which were successfully completed as productive wells, at a total drilling cost (net to the Company’s interest) of $2.5 billion.

The Company believes that its current property base provides a substantial inventory of prospects for future reserve, production and cash flow growth. The Company’s proved reserves as of December 31, 2011 include proved

 

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undeveloped reserves and proved developed reserves that are behind pipe of 259.0 MMBbls of oil, 98.7 MMBbls of NGLs and 850.8 Bcf of gas. The Company believes that its current portfolio of proved reserves provides attractive development opportunities for at least the next five years. The timing of the development of these reserves will be dependent upon commodity prices, drilling and operating costs and the Company’s expected operating cash flows and financial condition.

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

Integrated services. The Company continues to expand its integrated services to control drilling costs and support the execution of its accelerating drilling program. The Company has 15 owned drilling rigs operating in the Spraberry field, and at the end of 2011, had Company-owned fracture stimulation fleets totaling 250,000 horsepower supporting drilling operations in the Spraberry, Eagle Ford Shale and Barnett Shale Combo areas. The Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools.

Acquisition activities. The Company regularly seeks to acquire properties that complement its operations, provide exploration and development opportunities and potentially provide superior returns on investment. In addition, the Company pursues strategic acquisitions that will allow the Company to expand into new geographical areas that provide future exploration/exploitation opportunities. During 2011, 2010 and 2009, the Company spent $131.9 million, $181.6 million and $88.9 million, respectively, to purchase primarily undeveloped acreage for future exploitation and exploration activities.

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

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

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

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

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

 

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improve profitability. See Notes M and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for specific information regarding the Company’s asset divestitures and discontinued operations, including the 2011 sale of Pioneer Tunisia and planned sale of Pioneer South Africa.

Marketing of Production

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

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

Derivative risk management activities. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also utilizes commodity swap contracts to reduce price volatility on the fuel that the Company’s drilling rigs and fracture stimulation fleets consume. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts and began accounting for its derivative contracts using the mark-to-market (“MTM”) method of accounting. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a description of the Company’s derivative risk management activities, “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” and Note I of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information about the impact of commodity derivative activities on oil, NGL and gas revenues and net derivative gains and losses during 2011, 2010 and 2009, as well as the Company’s open commodity derivative positions at December 31, 2011.

Competition, Markets and Regulations

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

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

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

 

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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;

 

   

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 laws, rules and regulations to which the Company’s business operations are or may be subject.

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

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

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

 

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The Company currently owns or leases numerous properties that have been used for oil and gas exploration and production for many years. Although the Company believes it has used operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by the Company, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of the Company’s properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons were not under the Company’s control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by the Company. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

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

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

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

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

 

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

In addition, certain governmental reviews are either underway or proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

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

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

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

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

 

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In July 2011, the EPA issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs. The EPA’s proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with the flaring of gas. If finalized, these rules could require a number of modifications to the Company’s operations, including the installation of new equipment. Compliance with such rules could result in significant new costs to the Company and make it more costly and time-consuming to complete oil and gas wells. Any delay or decrease in the completion of new oil and gas wells could have a material adverse effect on the Company’s liquidity, results of operations and financial condition. Moreover, in response to reported concerns about high concentrations of benzene in the air near certain drilling sites and gas processing facilities in the Barnett Shale area, the Texas Commission on Environmental Quality (the “TCEQ”) adopted new air emissions limitations and permitting requirements for oil and gas facilities in the state, which are applicable to facilities located in the Barnett Shale area. The TCEQ may expand the application of the requirements to facilities in other areas of the state in 2012. These new requirements could increase the cost and time associated with drilling wells in the Barnett Shale or other areas of the state in the future. The agency’s investigations could lead to additional, more stringent air permitting requirements, increased regulation, and possible enforcement actions against producers, including Pioneer, in the Barnett Shale area. Any adoption of laws, regulations, orders or other legally enforceable mandates governing gas drilling and operating activities in the Barnett Shale or other areas of the state that result in more stringent drilling or operating conditions or limit or prohibit the drilling of new gas wells for any extended period of time could increase the Company’s costs and/or reduce its production, which could have a material adverse effect on the Company’s results of operations and cash flows.

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

The United States Fish and Wildlife Service has proposed listing the Dunes Sagebrush Lizard as endangered under the ESA and expects to make a final determination on the listing by June 2012. Some of the Company’s operations in the Permian Basin are located in or near areas that may potentially be designated as Dunes Sagebrush Lizard habitat. If the lizard is classified as an endangered species, the Company’s operations in any area that is designated as the lizard’s habitat may be limited, delayed or, in some circumstances, prohibited, and the Company may be required to comply with expensive mitigation measures intended to protect the lizard and its habitat. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA and issue decisions with respect to the 250 candidate species over the next several years. The designation of previously unprotected species in areas where the Company operates as threatened or endangered could cause the Company to incur increased costs arising from species protection measures or could result in limitations on the Company’s exploration and production activities that could have an adverse effect on the Company’s ability to develop and produce its reserves.

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

Global warming and climate change. In December 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases,” or “GHGs,” present an endangerment to public

 

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

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

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

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

The Company believes it is in substantial compliance with all existing environmental laws and regulations applicable to the Company’s current operations and that its continued compliance with existing requirements will not have a material adverse effect on the Company’s financial condition and results of operations. For instance, the Company did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2011. Additionally, the Company is not aware of any environmental issues or claims that will require material capital expenditures during 2012. However, accidental spills or releases may occur in the course of the Company’s operations, and the Company cannot give any assurance that it will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, the Company cannot give any assurance that the passage of more stringent laws or regulations in the future will not have a negative effect on the Company’s business, financial condition and results of operations.

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

Development and production. Development and production operations are subject to various types of regulation at foreign, federal, state and local levels. These types of regulation include requiring permits for the

 

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

 

   

the location of wells;

 

   

the method of drilling and casing wells;

 

   

the method and ability to fracture stimulate wells;

 

   

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

 

   

the plugging and abandoning of wells; and

 

   

notice to surface owners and other third parties.

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

Regulation of transportation and sale of gas. The availability, terms and cost of transportation significantly affect sales of gas. Foreign, federal and state regulations govern the price and terms for access to gas pipeline transportation. Intrastate gas pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies, including the Railroad Commission of Texas (the “TRRC”). The interstate transportation and sale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Since 1985, FERC has endeavored to make gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis.

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

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

Gas gathering. Section 1(b) of the NGA exempts gas gathering facilities from FERC’s jurisdiction. The Company believes that its gathering facilities meet the traditional tests FERC has used to establish a pipeline system’s status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so the classification and

 

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regulation of some of the Company’s gathering facilities may be subject to change based on future determinations by FERC and the courts. Thus, the Company cannot guarantee that the jurisdictional status of its gas gathering facilities will remain unchanged.

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

Regulation of transportation and sale of oil and NGLs. The availability, terms and cost of transportation significantly affect sales of oil and NGLs. Foreign, federal and state regulations govern the price and terms for access to pipeline transportation of oil and NGLs. Intrastate pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies, including the TRRC. Interstate common carrier pipeline operations are subject to rate regulation by FERC under the Interstate Commerce Act (the “ICA”). The ICA requires that tariff rates for petroleum pipelines, which include both oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory.

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

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

 

ITEM 1A. RISK FACTORS

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

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

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

 

   

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

 

   

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

 

   

gas inventory levels in the United States;

 

   

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;

 

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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.

In the past, commodity prices have been extremely volatile, and the Company expects this volatility to continue. For example, during 2011, oil prices fluctuated from a high of $113.93 per Bbl in April to a low of $75.67 per Bbl in October, while gas prices fluctuated from a high of $4.85 per Mcf in June to a low of $2.99 per Mcf in December. During 2010, oil prices fluctuated from a low of $68.01 per Bbl in May to a high of $91.51 per Bbl in December, while gas prices fluctuated from a high of $6.01 per Mcf in January to a low of $3.29 per Mcf in October. The Company makes price assumptions that are used for planning purposes, and a significant portion of the Company’s cash outlays, including rent, salaries and noncancellable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, the Company’s financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.

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

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

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

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

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

 

   

production is less than the contracted derivative volumes;

 

   

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

 

   

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

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

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

The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default on its obligations under the Company’s derivative 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 become costlier, as a result of a variety of factors, including:

 

   

unexpected drilling conditions;

 

   

unexpected pressure or irregularities in formations;

 

   

equipment failures or accidents;

 

   

fracture stimulation accidents or failures;

 

   

adverse weather conditions;

 

   

restricted access to land for drilling or laying pipelines; and

 

   

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

The Company’s future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse effect on the Company’s future results of operations and financial condition. While all drilling, whether developmental, extension or exploratory, involves these risks, exploratory and extension drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Company expects that it will continue to experience exploration and abandonment expense in 2012.

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

Declines in commodity prices may result in the Company having to make substantial downward adjustments to its estimated proved reserves. If this occurs, or if the Company’s estimates of production or economic factors change, accounting rules may require the Company to impair, as a noncash charge to earnings, the carrying value of the Company’s oil and gas properties. The Company is required to perform impairment tests on proved oil and gas properties whenever events or changes in circumstances indicate that the carrying value of proved properties may not be recoverable. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of the Company’s oil and gas properties, the carrying value may not be recoverable and therefore an impairment charge would be required to reduce the carrying value of the proved properties to their estimated fair value. For example, during 2011 and 2009, the Company recognized impairment charges of $354.4 million and $21.1 million, respectively, due to the impairment of the Company’s Edwards and Austin Chalk gas fields in South Texas and the Uinta/Piceance area in Colorado, primarily due to declines in gas prices and downward adjustments to the economically recoverable resource potential. The Company may incur impairment charges in the future, which could materially affect the Company’s results of operations in the period incurred.

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

At December 31, 2011, the Company carried unproved property costs of $235.5 million. GAAP requires periodic evaluation of these costs on a project-by-project basis. These evaluations are affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of the leases, contracts and permits appurtenant to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize noncash charges in the earnings of future periods.

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

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

 

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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, 2011, the Company carried goodwill of $298.1 million associated with its United States reporting unit. Goodwill is tested for impairment annually during the third quarter using a July 1 assessment date, and also whenever facts or circumstances indicate that the carrying value of the Company’s goodwill may be impaired, requiring an estimate of the fair values of the reporting unit’s assets and liabilities. Those assessments may be affected by (a) additional reserve adjustments both positive and negative, (b) results of drilling activities, (c) management’s outlook for commodity prices and costs and expenses, (d) changes in the Company’s market capitalization, (e) changes in the Company’s weighted average cost of capital and (f) changes in income taxes related to the Company’s United States reporting unit. If the fair value of the reporting unit’s net assets is not sufficient to fully support the goodwill balance in the future, the Company will reduce the carrying value of goodwill for the impaired value, with a corresponding noncash charge to earnings in the period in which goodwill is determined to be impaired.

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

As of December 31, 2011, the Company owned interests in four gas processing plants and ten treating facilities. The Company operates two of the gas processing plants and all ten of the treating facilities. There are significant risks associated with the operation of gas processing plants. Gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of a gas processing plant or facility could result in an explosion or the discharge of toxic gases, which could result in significant damage claims in addition to interrupting a revenue source.

 

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

 

   

blowouts, cratering, explosions and fires;

 

   

adverse weather effects;

 

   

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

 

   

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.

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

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

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

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

 

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

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

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

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

The Company is a borrower under fixed rate senior notes, senior convertible notes and a credit facility. The terms of the Company’s borrowings under the senior notes, senior convertible notes and the credit facility specify scheduled debt repayments and require the Company to comply with certain associated covenants and restrictions. The Company’s ability to comply with the debt repayment terms, associated covenants and restrictions is dependent on, among other things, factors outside the Company’s direct control, such as commodity prices and interest rates. See Note E of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the Company’s outstanding debt as of December 31, 2011 and the terms associated therewith.

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

 

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

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

 

   

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

 

   

marketing oil, NGL and gas production; and

 

   

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

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

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

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

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

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

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

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

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

 

   

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.

 

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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.

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.

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

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

 

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

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

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

A change in Pioneer Southwest’s business could cause it to be treated as a corporation for federal income tax purposes. In addition, a change in current law may cause Pioneer Southwest to be treated as a corporation for such purposes. For example, members of United States Congress have from time to time considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. Moreover, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If Pioneer Southwest were subject to federal income tax as a corporation or any state was to impose a tax upon Pioneer Southwest, its cash available to pay distributions would be reduced. Therefore, treatment of Pioneer Southwest as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to Pioneer Southwest’s unitholders, including the Company, and would likely cause a substantial reduction in the value of the Company’s investment in Pioneer Southwest.

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

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

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

 

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

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

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

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

In recent years, legislation has been proposed that would, if enacted into law, make significant changes to United States tax laws, including elimination of certain key United States federal income tax incentives currently available to oil and gas companies. Such tax legislation changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in United States federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect the value of an investment in the Company’s common stock.

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

During December 2009, the EPA officially published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted two sets of rules that regulate greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources. The EPA has also adopted rules requiring the reporting, on an annual basis, of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries as well as certain oil and gas production facilities. The Company is monitoring GHG emissions from its operations in accordance with the GHG emissions reporting rule and believes that its monitoring activities are in substantial compliance with applicable reporting obligations.

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.

 

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

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

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President in July 2010 and requires the CFTC and the SEC to promulgate rules and regulations to implement the new legislation. In December 2011, the CFTC extended temporary exemptive relief from certain regulations applicable to swaps until no later than July 16, 2012. In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide derivative transactions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. The financial reform legislation may also require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivatives activities, although the application of those provisions to the Company is uncertain at this time. The financial reform legislation may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect the Company’s available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less creditworthy counterparties. If the Company reduces its use of derivatives as a result of the legislation and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. The Company’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on the Company, its financial condition and its results of operations.

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

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

 

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

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

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

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

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

The Company’s strategy is to expand drilling activity in areas in which industry activity has increased rapidly, particularly in the Spraberry field area, the Eagle Ford Shale play in South Texas and the Barnett Shale Combo play in North Texas. As a result, demand for personnel, equipment, hydraulic fracturing services, proppant for fracture stimulation operations, water and other services and resources, as well as access to transportation, processing and refining facilities in these areas has increased, as has the costs for those items. A delay or inability to secure the personnel, equipment, services, resources and facilities access necessary for the Company to complete its development activities as planned could result in a rate of oil and gas production below the rate forecasted, and significant increases in costs would impact the Company’s profitability.

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

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the ESA, the Migratory Bird Treaty Act, the CWA and CERCLA. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities, or at times private parties, may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and may seek damages and, in some cases, criminal penalties. The United States Fish and Wildlife Service has proposed listing the Dunes Sagebrush Lizard as endangered under the ESA and expects to make a final determination on the listing by June 2012. Some of the Company’s operations in the Permian Basin are located in or near areas that may potentially be designated as Dunes Sagebrush Lizard habitat. If the lizard is

 

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

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

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

 

ITEM 2. PROPERTIES

Reserve Rule Changes

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

Changing disclosure requirements and providing formats for tabular reserve disclosures.

Reserve Estimation Procedures and Audits

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

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

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

 

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

Proved reserves audits. The proved reserve audits performed by NSAI in the aggregate represented 90 percent, 90 percent and 93 percent of the Company’s 2011, 2010 and 2009 proved reserves, respectively; and, 91 percent, 79 percent and 86 percent of the Company’s 2011, 2010 and 2009 associated pre-tax present value of proved reserves discounted at ten percent, respectively.

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

 

 

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

 

 

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

 

 

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

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

In the course of its evaluations, NSAI prepared, for all of the audited properties, its own estimates of the Company’s proved reserves and the pre-tax present value of such reserves discounted at ten percent. NSAI reviewed its audit differences with the Company, and, in a number of cases, held joint meetings with the Company to review additional reserves work performed by the technical teams and any updated performance data related to the proved reserve differences. Such data was incorporated, as appropriate, by both parties into the proved reserve estimates. NSAI’s estimates, including any adjustments resulting from additional data, of those proved reserves and the pre-tax present value of such reserves discounted at ten percent did not differ from Pioneer’s estimates by more than ten percent in the aggregate. However, when compared on a lease-by-lease, field-by-field or area-by-area basis, some of the Company’s estimates were greater than those of NSAI and some were less than the estimates of NSAI. When such differences do not exceed ten percent in the aggregate and NSAI is satisfied that the proved reserves and pre-tax

 

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present value of such reserves discounted at ten percent are reasonable and that its audit objectives have been met, NSAI will issue an unqualified audit opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analyses by the Company and NSAI. At the conclusion of the audit process, it was NSAI’s opinion, as set forth in its audit letter, which is included as an exhibit to this Report, that Pioneer’s estimates of the Company’s proved oil and gas reserves and associated pre-tax present value discounted at ten percent are, in the aggregate, reasonable and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE.

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

Qualifications of reserves preparers and auditors. The WWR is staffed by petroleum engineers with extensive industry experience and is managed by the Director of the WWR, the technical person that is primarily responsible for overseeing the Company’s reserves estimates. These individuals meet the professional qualifications of reserves estimators and reserves auditors as defined by the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,” promulgated by the SPE. The WWR Director’s qualifications include 34 years of experience as a petroleum engineer, with 27 years focused on reserves reporting for independent oil and gas companies, including Pioneer. His educational background includes an undergraduate degree in Chemical Engineering and a Masters of Business Administration degree in Finance. He is also a Chartered Financial Analyst Charterholder (“CFA”) and a member of the Oil and Gas Reserves Committee of the SPE.

NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. The technical person primarily responsible for auditing the Company’s reserves estimates has been a practicing consulting petroleum engineer at NSAI since 1983 and has over 33 years of practical experience in petroleum engineering, including 32 years of experience in the estimation and evaluation of proved reserves. He graduated with a Bachelor of Science degree in Chemical Engineering in 1978 and meets or exceeds the education, training and experience requirements set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the board of directors of the SPE.

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

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

Proved Reserves

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

 

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

 

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

Place
    Revisions of
Previous
Estimates
 

United States

     (46,907     155,728        1,394        4,435        —          (38,328

South Africa

     (1,445     585        —           —           —          315  

Tunisia

     (230     —           —           —           (23,447     —     
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total

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

 

 

   

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

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

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

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

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

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

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

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

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

 

     Summary of Oil and Gas Reserves as of December 31, 2011
Based on Average Fiscal Year Prices
 
     Oil
(MBbls)
     NGLs
(MBbls)
     Gas
(MMcf) (a)
     MBOE      Standardized
Measure
 
     (in thousands)  

Developed:

              

United States

     189,975        120,405        1,840,697        617,164      $ 5,453,321  

South Africa

     231        —           12,666        2,342        40,686  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

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

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Undeveloped:

              

United States

     239,799        90,630        677,675        443,375        2,319,016  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

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

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a)

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

 

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

 

Beginning proved undeveloped reserves

     433,244  

Extensions and discoveries

     103,224  

Purchases of minerals-in-place

     4,345  

Improved recovery

     1,274  

Revisions of previous estimates

     (28,582

Transfers to proved developed

     (62,436

Sales of minerals-in-place

     (7,694
  

 

 

 

Ending proved undeveloped reserves

     443,375  
  

 

 

 

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

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

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

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

Revisions of previous estimates. Revisions of previous estimates are comprised of 34 MMBOE of negative price revisions associated with proved dry gas reserves that are no longer planned to be drilled in the next five years and 5 MMBOE of positive technical revisions, primarily in the Spraberry field.

Transfers to proved developed. Transfers to proved developed reserves represents those undeveloped proved reserves that moved to proved developed as a result of development drilling during 2011.

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

During 2011, the Company added approximately 32 MMBOE of proved undeveloped reserves for locations that are more than one location removed from developed locations in the Spraberry field. Within the Spraberry field, the Company uses both public and proprietary geologic data to establish continuity of the formation and its producing properties. This included seismic data and interpretations (2-D, 3-D and micro seismic); open hole log information (both vertical and horizontally collected) and petrophysical analysis of the log data; mud logs; gas sample analysis; drill cutting samples; measurements of total organic content; thermal maturity; sidewall cores and data measured from our internal core analysis facility. After the geologic area was shown to be continuous, statistical analysis of existing producing wells was conducted to generate area of reasonable certainty at distances from established production. As a result of this analysis, proved undeveloped reserves for drilling locations within this area of reasonable certainty were recorded during 2011.

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

 

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Based on management’s commodity price outlook, the Company expects that future operating cash flows will provide adequate funding for future development of its proved undeveloped reserves within the next five years. The following table represents the estimated timing and cash flows of developing the Company’s proved undeveloped reserves as of December 31, 2011 (dollars in thousands):

 

Year Ended December 31, (a)

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

2012

     5,193      $ 385,942      $ 55,517      $ 1,152,395      $ (821,970

2013

     15,707        1,118,140        160,479        1,488,576        (530,915

2014

     23,504        1,609,820        251,653        1,577,529        (219,362

2015

     29,475        1,997,551        336,961        1,546,016        114,574  

2016

     33,783        2,229,206        411,086        1,466,408        351,712  

Thereafter (b)

     335,713        21,710,831        6,501,238        321,791        14,887,802  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

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

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a)

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

(b)

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

Description of Properties

United States

Approximately 83 percent of the Company’s proved reserves at December 31, 2011 are located in the Spraberry field in the Permian Basin area, the Hugoton and West Panhandle fields in the Mid-Continent area and the Raton field in the Rocky Mountains area. These fields generate substantial operating cash flow, which provides funding for the Company’s development and exploration activities in the Spraberry field, Raton field, Eagle Ford Shale play, Barnett Shale Combo play and Alaska.

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

 

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

Permian Basin

     144        696        668        11        161  

Mid-Continent

     —           2        2        —           —     

Raton Basin

     —           57        52        —           5  

South Texas—Edwards and Austin Chalk

     1        1        2        —           —     

Alaska

     1        1        1        —           1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total United States

     146        757        725        11        167  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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     Exploration/Extension Drilling  
     Beginning Wells
In Progress
     Wells
Spud
     Successful
Wells
     Unsuccessful
Wells
     Ending
Wells In
Progress
 

Permian Basin

     3        24        27        —           —     

Mid-Continent

     —           5        —           —           5  

South Texas—Eagle Ford Shale

     22        111        94        —           39  

South Texas—Edwards and Austin Chalk

     2        1        2        1        —     

Barnett Shale

     11        59        44        —           26  

Alaska

     —           1        —           —           1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total United States

     38        201        167        1        71  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

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

 

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

Permian Basin

     27,514        11,027        47,600        46,475  

Mid-Continent

     3,593        7,107        51,291        19,249  

Raton Basin

     —           —           160,550        26,758  

Barnett Shale

     598        1,369        11,013        3,803  

South Texas—Eagle Ford Shale

     4,383        2,982        28,020        12,035  

South Texas—Edwards and Austin Chalk

     93        1        45,324        7,648  

Alaska

     4,432        —           —           4,432  

Other

     5        1        81        18  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total United States

     40,618        22,487        343,879        120,418  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a)

Gas production excludes gas produced and utilized as field fuel.

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

 

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

Permian Basin

   $ 7,252      $ 30,954      $ 98,318      $ 1,254,454     $ 3,902     $ 1,394,880  

Mid-Continent

     14        9,955        7,112        15,710       1,797       34,588  

Raton Basin

     210        25        7,401        58,107       (698     65,045  

South Texas—Eagle Ford Shale

     —           26,263        136,985        4,793       5,959       174,000  

South Texas—Edwards and Austin Chalk

     —           1,707        13,628        10,881       6,239       32,455  

Barnett Shale

     69        44,006        258,446        14,421       3,042       319,984  

Alaska

     20        32        32,140        90,120  (a)      3,319       125,631  

Other

     —           11,384        4,784        —          (456     15,712  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total United States

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

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

 

(a)

Includes $13.4 million of capitalized interest related to the Oooguruk project.

Permian Basin

Spraberry field. The Spraberry field was discovered in 1949 and encompasses eight counties in West Texas. According to the Energy Information Administration, the Spraberry field is the second largest oil field in the United States. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casinghead gas with an average energy content of 1,400 Btu. The

 

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oil and gas are produced primarily from four formations, the upper and lower Spraberry, the Dean and the Wolfcamp, at depths ranging from 6,700 feet to 11,300 feet. In addition, the Company is drilling deeper to the Strawn, Atoka and Mississippian intervals with positive results.

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

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

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

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

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

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

The Company continues to expand its integrated services to control drilling costs and support the execution of its accelerating drilling program. The Company has increased its owned drilling rigs to 15 and has five Company-owned fracture stimulation fleets totaling 100,000 horsepower currently operating in the Spraberry field supporting vertical drilling operations. Two additional fleets totaling 70,000 horsepower will be added by mid-year 2012 to support Pioneer’s horizontal drilling program in the Wolfcamp Shale. To support its growing operations, the Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, the Company has contracted for tubular and pumping unit requirements through 2012 and well cementing services through 2016.

Mid-Continent

Hugoton field. The Hugoton field in southwest Kansas is one of the largest producing gas fields in the continental United States. The gas is produced from the Chase and Council Grove formations at depths ranging from 2,700 feet to 3,000 feet. The Company’s Hugoton properties are located on approximately 284,000 gross acres (245,000 net acres), covering approximately 400 square miles. The Company has working interests in approximately 1,220 wells in the Hugoton field, approximately 1,000 of which it operates.

The Company operates substantially all of the gathering and processing facilities, including the Satanta plant, which processes the production from the Hugoton field. In January 2011, the Company sold a 49 percent interest in the Satanta plant to an unaffiliated third party for the third party’s commitment to dedicate gas volumes to the Satanta plant. This agreement has increased the Satanta plant’s processing volumes and is expected to increase its

 

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economic longevity. The Company is also exploring opportunities to process other gas production in the Hugoton area at the Satanta plant. By maintaining operatorship of the gathering and processing facilities, the Company is able to control the production, gathering, processing and sale of its Hugoton field gas and NGL production.

West Panhandle field. The West Panhandle properties are located in the panhandle region of Texas. These stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite, Granite Wash and fractured Granite formations at depths no greater than 3,500 feet. The Company’s gas has an average energy content of 1,365 Btu and is produced from approximately 680 wells on more than 259,000 gross acres (252,000 net acres) covering over 375 square miles. The Company controls 100 percent of the wells, production equipment, gathering system and the Fain gas processing plant for the field. As this field is operated at or below vacuum conditions, Pioneer continually works to improve compressor and gathering system efficiency.

Raton

The Raton Basin properties are located in the southeast portion of Colorado. The Company owns approximately 227,000 gross acres (201,000 net acres) in the center of the Raton Basin and produces CBM gas from the coal seams in the Vermejo and Raton formations from approximately 2,300 wells. The Company owns the majority of the well servicing and fracture stimulation equipment that it utilizes in the Raton field, allowing it to control costs and insure availability.

South Texas Eagle Ford Shale and Edwards

The Company’s drilling activities in the South Texas area during 2011 were primarily focused on delineation and development of Pioneer’s substantial acreage position in the Eagle Ford Shale play. The Company drilled 94 horizontal Eagle Ford Shale wells during 2011, with average lateral lengths of approximately 5,500 feet and 13-stage fracture stimulations. The Company plans to utilize 12 rigs in 2012 and drill approximately 125 wells. The 2012 drilling program will continue to focus on liquids-rich drilling, with only 15 percent of the wells designated to hold strategic dry gas acreage.

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

The Company has also been testing the use of lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. Early well performance has been similar to direct offset ceramic-stimulated wells. The Company plans to continue to monitor the performance of these wells and plans to use white sand in 50 percent of its 2012 drilling program.

During June 2010, the Company entered into an Eagle Ford Shale joint venture transaction. Pursuant to the transaction, the Company entered into a purchase and sale agreement to sell 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds, including normal closing adjustments. The terms of the transaction also provided that the purchaser will pay 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. As of December 31, 2011, $398.2 million of the carry obligation had been paid by the purchaser and the Company expects that the purchaser’s obligation will be satisfied by the end of 2012. The Company also sold a 49.9 percent member interest in EFS Midstream LLC (“EFS Midstream”), an entity formed by the Company to own and operate gathering facilities in the Eagle Ford Shale area, to the purchaser for $46.4 million of cash proceeds and deferred a $46.2 million associated net gain. The Company does not have voting control of EFS Midstream and does not consolidate its financial statements.

EFS Midstream is obligated to construct midstream assets in the Eagle Ford Shale area. Construction of the midstream assets is continuing, with the majority of the construction expected to be completed by 2013. Eight of the 12 planned central gathering plants (“CGPs”) were completed as of December 31, 2011. EFS Midstream plans to build three additional CGPs in 2012. As construction of CGPs is completed, EFS Midstream will provide gathering, treating and transportation services for the Company during a 20-year contractual term. The Company has invested $169.5 million of capital in EFS Midstream, $97.5 million of which was contributed during 2011. During June 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility that is being used to fund infrastructure investments that exceed its operating cash flows.

 

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Barnett Shale

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

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

Alaska

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

International

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

Selected Oil and Gas Information

The following tables set forth selected oil and gas information from continuing operations for the Company as of and for each of the years ended December 31, 2011, 2010 and 2009. Because of normal production declines, increased or decreased drilling activities and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

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

The following tables set forth production, price and cost data with respect to the Company’s properties for 2011, 2010 and 2009. These amounts represent the Company’s historical results from operations without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the respective years. The production amounts will not agree to the reserve volume tables in the “Unaudited Supplementary Information” section included in “Item 8. Financial Statements and Supplementary Data” due to field fuel volumes being included in the reserve volume tables.

 

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PRODUCTION, PRICE AND COST DATA

 

     Year Ended December 31, 2011  
     United States      South
Africa
     Tunisia     Total  
     Spraberry
Field
    Raton
Field
     Total                      

Production information:

               

Annual sales volumes:

               

Oil (MBbls)

     10,011       —           14,825        193        201       15,219  

NGLs (MBbls)

     3,844       —           8,208        —           —          8,208  

Gas (MMcf)

     15,899       58,601        125,516        7,508        181       133,205  

Total (MBOE)

     16,505       9,767        43,953        1,445        229       45,627  

Average daily sales volumes:

               

Oil (Bbls)

     27,428       —           40,618        530        547       41,695  

NGLs (Bbls)

     10,530       —           22,487        —           —          22,487  

Gas (Mcf)

     43,559       160,550        343,879        20,570        496       364,945  

Total (BOE)

     45,218       26,758        120,418        3,958        630       125,006  

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

               

Oil (per Bbl)

   $ 95.93     $ —         $ 96.60      $ 108.14      $ 99.03     $ 96.78  

NGL (per Bbl)

   $ 42.38     $ —         $ 46.27      $ —         $ —        $ 46.27  

Gas (per Mcf)

   $ 3.44     $ 3.81      $ 3.84      $ 7.62      $ 13.04     $ 4.07  

Revenue (per BOE)

   $ 71.37     $ 22.86      $ 52.19      $ 54.09      $ 96.29     $ 52.48  

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

               

Oil (per Bbl)

   $ 91.44     $ —         $ 91.35      $ 108.14      $ 99.03     $ 91.67  

NGL (per Bbl)

   $ 42.38     $ —         $ 46.27      $ —         $ —        $ 46.27  

Gas (per Mcf)

   $ 3.44     $ 3.81      $ 3.84      $ 7.62      $ 13.04     $ 4.07  

Revenue (per BOE)

   $ 68.65     $ 22.86      $ 50.42      $ 54.09      $ 96.29     $ 50.77  

Average costs (per BOE):

               

Production costs:

               

Lease operating

   $ 10.40     $ 6.49      $ 8.09      $ 2.35      $ 7.61     $ 7.90  

Third-party transportation charges

     —          3.01        1.26        —           1.91       1.22  

Net natural gas plant/gathering

     (1.45     2.15        0.15        —           —          0.14  

Workover

     1.74       —           0.82        —           (0.27 )     0.78  
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total

   $ 10.69     $ 11.65      $ 10.32      $ 2.35      $ 9.25     $ 10.04  
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Production and ad valorem taxes:

               

Ad valorem

   $ 1.73     $ 0.41      $ 1.24      $ —           —        $ 1.20  

Production

     3.87       0.31        2.11        —           —          2.04  
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total

   $ 5.60     $ 0.72      $ 3.35      $ —           —        $ 3.24  
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Depletion expense

   $ 11.41     $ 14.46      $ 12.55      $ 29.00        —        $ 13.01  
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

(a)

The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its hedging activities at a field level. As of December 31, 2011, the Company had an obligation to deliver 1.3 million Bbls of oil under the VPP obligation. See Notes H and S of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information about the Company’s gathering, processing, transportation and fractionation agreements and VPP obligation, respectively.

 

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PRODUCTION, PRICE AND COST DATA - (Continued)

 

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

Production information:

                

Annual sales volumes:

                

Oil (MBbls)

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

NGLs (MBbls)

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

Gas (MMcf)

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

Total (MBOE)

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

Average daily sales volumes:

                

Oil (Bbls)

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

NGLs (Bbls)

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

Gas (Mcf)

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

Total (BOE)

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

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

                

Oil (per Bbl)

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

NGL (per Bbl)

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

Gas (per Mcf)

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

Revenue (per BOE)

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

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

                

Oil (per Bbl)

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

NGL (per Bbl)

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

Gas (per Mcf)

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

Revenue (per BOE)

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

Average costs (per BOE):

                

Production costs:

                

Lease operating

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

Third-party transportation charges

     —          2.35        0.87        —           1.50        0.86  

Net natural gas plant/gathering

     (1.66     1.93        0.08        —              0.08  

Workover

     1.88       0.07        0.92        —           0.36        0.85  
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

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

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Production and ad valorem taxes:

                

Ad valorem

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

Production

     3.53       0.52        1.47        —           —           1.33  
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

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

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Depletion expense

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

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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

PRODUCTIVE WELLS (a)

 

000000000 000000000 000000000 000000000 000000000 000000000
     Gross Productive Wells      Net Productive Wells  
     Oil      Gas      Total      Oil      Gas      Total  

As of December 31, 2011:

                 

United States

     6,111        5,268        11,379        5,525        4,502        10,027  

South Africa

     —           6        6        —           3        3  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

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

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

As of December 31, 2010:

                 

United States

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

South Africa

     —           6        6        —           3        3  

Tunisia

     33        —           33        10        —           10  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

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

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

As of December 31, 2009:

                 

United States

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

South Africa

     —           6        6        —           3        3  

Tunisia

     29        —           29        9        —           9  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

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

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a)

Productive wells consist of producing wells and wells capable of production, including shut-in wells and gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. One or more completions in the same well bore are counted as one well. If any well in which one of the multiple completions is an oil completion, then the well is classified as an oil well. As of December 31, 2011, the Company owned interests in two gross wells containing multiple completions.

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

LEASEHOLD ACREAGE

 

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

United States:

              

Onshore

     1,603,656        1,348,040        1,459,058        964,537        302,316  

Offshore

     —           —           —           —           5,000  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     1,603,656        1,348,040        1,459,058        964,537        307,316  

South Africa

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

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

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

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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

 

     Acres Expiring (a)  
     Gross      Net  

2012 (b)

     258,119        217,103  

2013

     157,758        112,063  

2014

     85,759        57,992  

2015

     40,974        23,866  

2016

     831,714        484,074  

Thereafter

     3,593,155        1,648,228  
  

 

 

    

 

 

 

Total

     4,967,479        2,543,326  
  

 

 

    

 

 

 

 

(a)

Acres expiring are based on contractual lease maturities.

(b)

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

Drilling and other exploratory and development activities. The following table sets forth the number of gross and net wells drilled by the Company during 2011, 2010 and 2009 that were productive or dry holes. This information should not be considered indicative of future performance, nor should it be assumed that there was any correlation between the number of productive wells drilled and the oil and gas reserves generated thereby or the costs to the Company of productive wells compared to the costs of dry holes.

DRILLING ACTIVITIES

 

     Gross Wells     Net Wells  
     Year Ended December 31,     Year Ended December 31,  
     2011     2010     2009     2011     2010     2009  

United States:

            

Productive wells:

            

Development

     725       433       60       661       378       58  

Exploratory

     167       34       13       115       22       7  

Dry holes:

            

Development

     11       3       —          10       3       —     

Exploratory

     1       3       2       1       1       2  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
     904       473       75       787       404       67  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Tunisia:

            

Productive wells:

            

Development

     —          3       1       —          2       —     

Exploratory

     —          5       —          —          2       —     

Dry holes:

            

Development

     —          —          —          —          —          —     

Exploratory

     —          —          2       —          —          1  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
     —          8       3       —          4       1  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

     904       481       78       787       408       68  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Success ratio (a)

     99     99     95     99     99     96

 

(a)

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

 

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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, 2011:

 

     Gross Wells      Net Wells  

Development

     167        153  

Exploratory

     71        49  
  

 

 

    

 

 

 

Total

     238        202  
  

 

 

    

 

 

 

 

ITEM 3. LEGAL PROCEEDINGS

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

 

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

 

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PART II

 

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

The Company’s common stock is listed and traded on the NYSE under the symbol “PXD.” The Board declared dividends to the holders of the Company’s common stock of $.04 per share during each of the first and third quarters of the years ended December 31, 2011 and 2010. The Board intends to consider the payment of dividends to the holders of the Company’s common stock in the future. The declaration and payment of future dividends, however, will be at the discretion of the Board and will depend on, among other things, the Company’s earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the Board deems relevant.

The following table sets forth quarterly high and low prices of the Company’s common stock and dividends declared per share for the years ended December 31, 2011 and 2010:

 

     High      Low      Dividends
Declared
Per Share
 

Year ended December 31, 2011

        

Fourth quarter

   $ 97.10      $ 58.63      $ —     

Third quarter

   $ 99.64      $ 65.73      $ 0.04  

Second quarter

   $ 106.07      $ 82.41      $ —     

First quarter

   $ 104.29      $ 85.90      $ 0.04  

Year ended December 31, 2010

        

Fourth quarter

   $ 88.00      $ 64.97      $ —     

Third quarter

   $ 67.77      $ 54.89      $ 0.04  

Second quarter

   $ 74.00      $ 54.72      $ —     

First quarter

   $ 56.88      $ 41.88      $ 0.04  

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

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

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

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

 

Period

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

October 2011

     63      $ 71.98        —        

November 2011

     58      $ 87.46        —        

December 2011

     155      $ 89.01        —        
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     276      $ 84.80        —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a)

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

 

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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, 2011 should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data.”

 

     Year Ended December 31,  
     2011      2010      2009     2008      2007  
     (in millions, except per share data)  

Statements of Operations Data:

             

Oil and gas revenues (a)

   $ 2,294.1      $ 1,718.3      $ 1,402.4     $ 1,893.4      $ 1,507.2  

Total revenues (b)

   $ 2,786.6      $ 2,381.7      $ 1,290.4     $ 1,920.1      $ 1,533.1  

Total costs and expenses (c)

   $ 2,130.2      $ 1,600.1      $ 1,515.6     $ 1,675.3      $ 1,299.3  

Income (loss) from continuing operations

   $ 458.8      $ 511.9      $ (142.0   $ 144.8      $ 162.2  

Income from discontinued operations, net of tax (d)

   $ 423.2      $ 134.1      $ 99.7     $ 86.8      $ 210.2  

Net income (loss) attributable to common stockholders

   $ 834.5      $ 605.2      $ (52.1   $ 210.0      $ 372.7  

Income (loss) from continuing operations attributable to common stockholders per share:

             

Basic

   $ 3.45      $ 4.00      $ (1.33   $ 1.02      $ 1.30  
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Diluted

   $ 3.39      $ 3.96      $ (1.33   $ 1.02      $ 1.30  
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

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

             

Basic

   $ 7.01      $ 5.14      $ (0.46   $ 1.76      $ 3.05  
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Diluted

   $ 6.88      $ 5.08      $ (0.46   $ 1.76      $ 3.04  
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Dividends declared per share

   $ 0.08      $ 0.08      $ 0.08     $ 0.30      $ 0.27  
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Balance Sheet Data (as of December 31):

             

Total assets

   $ 11,524.2      $ 9,679.1      $ 8,867.3     $ 9,161.8      $ 8,617.0  

Long-term obligations

   $ 4,861.2      $ 4,683.9      $ 4,653.0     $ 4,787.2      $ 4,568.1  

Total stockholders’ equity

   $ 5,651.1      $ 4,226.0      $ 3,643.0     $ 3,679.6      $ 3,054.7  

 

(a)

The Company’s oil and gas revenues for 2011, as compared to those of 2010, increased by $575.8 million (or 34 percent) due to increases in average oil and NGL sales prices and United States oil, NGL, and gas sales volumes. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for discussions about oil and gas revenues and factors impacting the comparability of such revenues.

(b)

The Company recognized $392.8 million of net derivative gains in its total revenues for 2011, including $225.5 million of noncash MTM gains, as compared to $448.4 million of net derivative gains during 2010, including $364.4 million of noncash MTM gains. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Notes B and I of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information about the Company’s derivative contracts and associated accounting methods. The Company also recognized $138.9 million of net hurricane activity gains during 2010, primarily associated with East Cameron 322 insurance recoveries, and $17.3 million of net hurricane activity charges during 2009. See Note T of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information about the East Cameron 322 reclamation and abandonment project.

(c)

During 2011, the Company recorded an impairment charge of $354.4 million related to its Edwards and Austin Chalk net assets in South Texas. During 2009 and 2008, the Company recorded impairment charges of $21.1 million and $89.8 million, respectively, to its Uinta/Piceance net assets in Colorado. During 2007, the Company recorded charges of $10.2 million on Block 320 in Nigeria, $10.3 million related to Block H in Equatorial Guinea and $5.7 million related to properties in the United States for a total of $26.2 million. See Note R of Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

(d)

During December 2011, the Company committed to a plan to divest Pioneer South Africa. In accordance with GAAP, the Company has classified the Pioneer South Africa results of operations as discontinued operations in each of the years presented, rather than as a component of continuing operations. During December 2010, the Company committed to a plan to sell Pioneer Tunisia and in February 2011 completed the sale of the Company’s share holdings in Pioneer Tunisia to an unaffiliated party for net cash proceeds of $853.6 million, including normal post-closing adjustments, resulting in a pretax gain of $645.2 million. During 2010, the Company received $35.3 million of interest on excess royalties paid during the period from January 1, 2003 through December 31, 2005 on oil and gas production from its deepwater Gulf of Mexico properties, which were sold in 2006. During 2009, the Company recorded $119.3 million of pretax income for the recovery of the excess royalties previously mentioned and a $17.5 million pretax gain, primarily from the sale of substantially all of its Gulf of Mexico shelf properties. The Company’s Gulf of Mexico shelf properties were sold effective July 1, 2009. The results of operations of these properties, and certain other properties sold during the periods presented are classified as discontinued operations in accordance with GAAP. See Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information about the Company’s discontinued operations.

 

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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 2011 included the following highlights:

 

 

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

 

   

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

 

   

A $289.1 million increase in income from discontinued operations, net of associated income taxes, primarily attributable to a $645.2 million pretax gain on the sale of Pioneer Tunisia during February 2011; and

 

   

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

 

   

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

 

   

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

 

   

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

 

   

An $88.3 million increase in oil and gas production costs, primarily due to increases in lease operating expenses as a result of higher sales volumes and inflation of oilfield service costs; and

 

   

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

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

 

 

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

 

 

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

First Quarter 2012 Continuing Operations Outlook

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

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

Total exploration and abandonment expense for the quarter is expected to be $35 million to $60 million, the higher limit of which reflects the potential dry hole costs associated with two exploration wells being drilled in Alaska. General and administrative expense is expected to be $49 million to $54 million. Interest expense is expected to be $45 million to $49 million, and other expense is expected to be $20 million to $30 million. Accretion of discount on asset retirement obligations from continuing operations is expected to be $2 million to $4 million.

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

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

The Company’s first quarter effective income tax rate from continuing operations is expected to range from 35 percent to 40 percent, assuming current capital spending plans and no significant derivative MTM changes in the Company’s derivative position. Cash income taxes are expected to be $2 million to $5 million and are primarily attributable to state taxes.

2012 Capital Budget

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

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

 

 

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

 

 

Horizontal Wolfcamp Shale – $275 million;

 

 

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

 

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Barnett Shale Combo play – $215 million;

 

 

Alaska – $135 million; and

 

 

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

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

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

Acquisitions

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

Divestitures and Discontinued Operations

Pioneer South Africa. As referred to in Financial and Operating Performance above, in December 2011 the Company committed to a plan to divest Pioneer South Africa. The assets and liabilities of Pioneer South Africa are classified as discontinued operations held for sale in the Company’s accompanying consolidated balance sheet as of December 31, 2011 and the results of operations of Pioneer South Africa are reported as income from discontinued operations, net of tax in all periods presented in the Company’s accompanying consolidated statements of operations (see Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information about the Company’s discontinued operations).

Pioneer Tunisia. During December 2010, the Company committed to a plan to sell Pioneer Tunisia. The assets and liabilities of Pioneer Tunisia are classified as discontinued operations held for sale in the Company’s accompanying consolidated balance sheet as of December 31, 2010. In February 2011 the Company sold its share holdings in Pioneer Tunisia for net proceeds of $853.6 million and recorded an associated pretax gain of $645.2 million during the year ended December 31, 2011. Pioneer Tunisia’s historical results of operations, and the related gain recorded on the disposition of Pioneer Tunisia, are reported as discontinued operations, net of tax in the Company’s accompanying consolidated statements of operations.

Eagle Ford Shale. In June 2010, the Company entered into an Eagle Ford Shale joint venture. Associated therewith, the Company sold 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds, including normal closing adjustments. Under the terms of the transaction, the purchaser is also paying 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. As of December 31, 2011, the purchaser had satisfied $398.2 million of the obligation to pay 75 percent of the Company’s defined exploration, drilling and completion costs attributable to Eagle Ford Shale assets and continues to be obligated to pay $488.6 million of the Company’s future qualifying costs. The Company’s current expectations are that the purchaser’s obligation to pay 75 percent of the Company’s defined exploration, drilling and completion costs attributable to Eagle Ford Shale assets will be satisfied by the end of 2012.

Uinta/Piceance. During the first half of 2010, the Company sold certain proved and unproved oil and gas properties in the Uinta/Piceance area for net proceeds of $11.8 million and the assumption by the purchaser of certain asset retirement obligations, resulting in a pretax gain of $17.3 million. The historical results and the related gain on disposition are reported as discontinued operations, net of tax.

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

 

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Results of Operations

Oil and gas revenues. Oil and gas revenues from continuing operations totaled $2.3 billion, $1.7 billion and $1.4 billion during 2011, 2010 and 2009, respectively.

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

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

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

 

     Year Ended December 31,  
     2011      2010      2009  

Oil (Bbls)

     40,618        28,211        24,968  

NGLs (Bbls)

     22,487        19,736        19,680  

Gas (Mcf)

     343,879        335,256        352,749  

Total (BOE)

     120,418        103,823        103,440  

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

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

 

     Year Ended December 31,  
     2011      2010      2009  

Oil (Bbls):

        

United States

     —           —           554  

South Africa

     530        616        375  

Tunisia

     547        4,880        6,531  
  

 

 

    

 

 

    

 

 

 

Worldwide

     1,077        5,496        7,460  
  

 

 

    

 

 

    

 

 

 

NGLs (Bbls):

        

United States

     —           —           29  
  

 

 

    

 

 

    

 

 

 

Gas (Mcf):

        

United States

     —           —           1,899  

South Africa

     20,570        29,760        25,538  

Tunisia

     496        2,849        1,668  
  

 

 

    

 

 

    

 

 

 

Worldwide

     21,066        32,609        29,105  
  

 

 

    

 

 

    

 

 

 

Total (BOE):

        

United States

     —           —           900  

South Africa

     3,958        5,576        4,631  

Tunisia

     630        5,355        6,809  
  

 

 

    

 

 

    

 

 

 

Worldwide

     4,588        10,931        12,340  
  

 

 

    

 

 

    

 

 

 

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

 

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

The following table provides average reported prices from continuing operations (including deferred hedge gains and losses and the amortization of deferred VPP revenue) and average realized prices from continuing operations (excluding deferred hedge gains and losses and the amortization of deferred VPP revenue) for 2011, 2010 and 2009:

 

     Year Ended December 31,  
     2011      2010      2009  

Average reported prices:

        

Oil (per Bbl)

   $ 96.60      $ 90.56      $ 75.60  

NGL (per Bbl)

   $ 46.27      $ 38.14      $ 29.76  

Gas (per Mcf)

   $ 3.84      $ 4.18      $ 3.88  

Total (per BOE)

   $ 52.19      $ 45.34      $ 37.15  

Average realized prices:

        

Oil (per Bbl)

   $ 91.35      $ 74.21      $ 55.04  

NGL (per Bbl)

   $ 46.27      $ 37.12      $ 28.45  

Gas (per Mcf)

   $ 3.84      $ 4.15      $ 3.32  

Total (per BOE)

   $ 50.42      $ 40.61      $ 30.02  

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

The following table summarizes the transfers of deferred hedge gains and losses associated with oil, NGL and gas cash flow hedges from AOCI – Hedging to oil, NGL and gas revenues for the years ending December 31, 2011, 2010 and 2009 (in thousands):

 

     Year Ended December 31,  
     2011      2010      2009  

Increase to oil revenue from AOCI—Hedging transfers

   $ 32,918      $ 78,052      $ 88,873  

Increase to NGL revenue from AOCI—Hedging transfers

     —           7,297        9,402  

Increase to gas revenue from AOCI—Hedging transfers

     —           3,691        22,791  
  

 

 

    

 

 

    

 

 

 

Total

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

 

 

    

 

 

    

 

 

 

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

 

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Deferred revenue. During 2011 and 2010, the Company’s amortization of deferred VPP revenue increased annual oil revenues by $45.0 million and $90.2 million, respectively, and during 2009, increased oil and gas revenues by $147.9 million. The Company’s amortization of deferred VPP revenue will increase 2012 annual oil revenues by $42.1 million, representing the remaining deferred revenues associated with VPP that is recorded in the Company’s accompanying balance sheet as of December 31, 2011. See Note S of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for specific information regarding the Company’s deferred revenue.

Interest and other income. The Company’s interest and other income from continuing operations totaled $102.0 million, $57.0 million and $101.6 million during 2011, 2010 and 2009, respectively. The $45.0 million increase during 2011, as compared to 2010, is primarily attributable to a $45.0 million increase in third-party income associated with vertical integration services provided by the Company on operated wells and an $8.7 million increase in equity earnings from EFS Midstream, partially offset by an $8.7 million decrease in Alaskan Petroleum Production Tax (“PPT”) credit recoveries. The $44.6 million decrease in interest and other income during 2010, as compared to 2009, is primarily attributable to a $47.3 million decrease in PPT credit recoveries and a $2.2 million increase in interest income.

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

 

     Year Ended December 31,  
     2011     2010     2009  

Unrealized mark-to-market changes in fair value:

      

Oil derivative gains (losses)

   $ 68,376     $ 41,094     $ (150,799

NGL derivative gains (losses)

     10,243       10,690       (20,206

Gas derivative gains (losses)

     179,787       277,585       (6,612

Diesel derivative gains

     270       —          —     

Interest rate derivative gains (losses)

     (33,206     35,040       (13,928
  

 

 

   

 

 

   

 

 

 

Total unrealized mark-to-market derivative gains (losses), net (a)

     225,470       364,409       (191,545
  

 

 

   

 

 

   

 

 

 

Cash settled changes in fair value:

      

Oil derivative losses

     (36,664     (27,305     (60,604

NGL derivative losses

     (15,418     (7,180     (8,340

Gas derivative gains

     182,993       119,417       66,428  

Diesel derivative gains

     67       —          —     

Interest rate derivative gains (losses)

     36,304       (907     (1,496
  

 

 

   

 

 

   

 

 

 

Total cash derivative gains (losses), net

     167,282       84,025       (4,012
  

 

 

   

 

 

   

 

 

 

Total derivative gains (losses), net

   $ 392,752     $ 448,434     $ (195,557
  

 

 

   

 

 

   

 

 

 

 

(a)

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

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

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

Hurricane activity, net. The Company recorded net hurricane activity gains of $1.5 million and $138.9 million during 2011 and 2010 and recorded net hurricane activity expenses of $17.3 million during 2009.

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

 

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In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues for the cost of reclamation and abandonment of the East Cameron 322 facility. During the fourth quarter of 2010, the Company and the insurance carriers agreed to settle the insurance policy dispute, resulting in an additional payment to the Company of $140 million during November 2010. See Note T of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for specific information regarding the Company’s East Cameron platform facilities reclamation and abandonment.

Oil and gas production costs. The Company’s oil and gas production costs from continuing operations totaled $453.1 million, $364.8 million and $345.9 million during 2011, 2010 and 2009, respectively. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company’s gas, reduced by net revenues earned from gathering and processing of third party gas in Company-owned facilities.

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

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

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

 

     Year Ended December 31,  
     2011      2010      2009  

Lease operating expenses

   $ 8.09      $ 7.74      $ 7.39  

Third-party transportation charges

     1.26        0.87        0.95  

Net natural gas plant/gathering charges

     0.15        0.08        0.27  

Workover costs

     0.82        0.92        0.55  
  

 

 

    

 

 

    

 

 

 

Total production costs

   $ 10.32      $ 9.61      $ 9.16  
  

 

 

    

 

 

    

 

 

 

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

The following table provides the Company’s production and ad valorem taxes per BOE from continuing operations and total production and ad valorem taxes per BOE from continuing operations for 2011, 2010 and 2009:

 

     Year Ended December 31,  
     2011      2010      2009  

Ad valorem taxes

   $ 1.24      $ 1.49      $ 1.51  

Production taxes

     2.11        1.47        1.10  
  

 

 

    

 

 

    

 

 

 

Total ad valorem and production taxes

   $ 3.35      $ 2.96      $ 2.61  
  

 

 

    

 

 

    

 

 

 

 

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

During 2011, the one percent increase in per BOE depletion expense was primarily due to modest inflation in drilling costs in the Spraberry field in West Texas and the Barnett Shale Combo play, partially offset by the cost containment associated with employed integrated services and increasing production in the Eagle Ford Shale play where portions of the Company’s drilling costs are carried by a third party. During 2010, the decrease in per BOE depletion expense was primarily due to (i) proved reserve additions associated with the Company’s successful 2010 capital expenditures program and (ii) adding end-of-life reserves that became economic as a result of commodity price increases since 2009.

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

Impairment of oil and gas properties and other long-lived assets. The Company reviews its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable.

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

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

It is reasonably possible that the estimate of undiscounted future net cash flows attributable to these or other properties may change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of future cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves (ii) results of future drilling activities, (iii) Management’s Price Outlook and (iv) increases or decreases in production and capital costs associated with these fields.

 

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

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

Exploration and abandonments expense. The following table provides the Company’s geological and geophysical costs, exploratory dry holes expense and leasehold abandonments and other exploration expense from continuing operations for 2011, 2010 and 2009 (in thousands):

 

     Year Ended December 31,  
     2011      2010      2009  

Geological and geophysical

   $ 73,552      $ 58,016      $ 40,919  

Exploratory dry holes

     3,112        91,922        6,873  

Leasehold abandonments and other

     44,656        39,659        31,303  
  

 

 

    

 

 

    

 

 

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

 

 

    

 

 

    

 

 

 

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

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