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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2005
or
o
  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 900, 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 þ     No o
 
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 o     No þ
 
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 þ     No o
 
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.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ
 
         
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
  $ 5,903,355,355  
Number of shares of Common Stock outstanding as of February 15, 2006
    128,642,016  
 
Documents Incorporated by Reference:
 
(1) Proxy Statement for Annual Meeting of Shareholders to be held during May 2006 — Referenced in Part III of this report.
 


Table of Contents

 
TABLE OF CONTENTS
 
         
        Page
 
  2
  3
  Business   4
    General   4
    Available Information   4
    Evergreen Merger   4
    Mission and Strategies   4
    Business Activities   5
    Operations by Geographic Area   8
    Marketing of Production   8
    Competition, Markets and Regulations   8
  Risk Factors   10
  Unresolved Staff Comments   14
  Properties   14
    Proved Reserves   15
    Description of Properties   17
    Selected Oil and Gas Information   23
  Legal Proceedings   31
  Submission of Matters to a Vote of Security Holders   31
  Market for Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities   32
    Securities Authorized for Issuance under Equity Compensation Plans   32
    Purchases of Equity Securities by the Issuer and Affiliated Purchasers   33
  Selected Financial Data   34
  Management’s Discussion and Analysis of Financial Condition and Results of Operations   36
    Strategic Initiatives   36
    Financial and Operating Performance   36
    Current Events   37
    Acquisitions   37
    Divestitures   38
    2006 Outlook and Activities   38
    Results of Operations   39
    Capital Commitments, Capital Resources and Liquidity   48
    Critical Accounting Estimates   52
    New Accounting Pronouncements   55
  Quantitative and Qualitative Disclosures About Market Risk   56
    Quantitative Disclosures   56
    Qualitative Disclosures   60
  Financial Statements and Supplementary Data   64
    Index to Consolidated Financial Statements   64
    Report of Independent Registered Public Accounting Firm   65


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        Page
 
    Consolidated Financial Statements   66
    Notes to Consolidated Financial Statements   71
    Unaudited Supplementary Information   116
Item 9.   Changes in and Disagreements With Accountants on Accounting and Financial Disclosure   124
Item 9A.   Controls and Procedures   124
Item 9B.   Other Information   126
PART III
Item 10.   Directors and Executive Officers of the Registrant   126
Item 11.   Executive Compensation   126
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   126
Item 13.   Certain Relationships and Related Transactions   126
Item 14.   Principal Accounting Fees and Services   126
PART IV
Item 15.   Exhibits, Financial Statement Schedules   127
Signatures   133
Exhibit Index    
 Amended and Restated Bylaws of the Company
 Form of Restricted Stock Unit Agreement for Non-Employee Directors
 Indemnification Agreement
 Change in Control Agreement
 Subsidiaries
 Consent of Ernst & Young LLP
 Cosent of Netherland, Sewell & Associates, Inc.
 Certification of the Chief Executive Officer Pursuant to Section 302
 Certification of the Chief Financial Officer Pursuant to Section 302
 Certification of the Chief Executive Officer Pursuant to Section 906
 Certification of the Chief Financial Officer Pursuant to Section 906
 
Cautionary Statement Concerning Forward-Looking Statements
 
Parts I and II of this annual report on Form 10-K (the “Report”) contain forward-looking statements that involve risks and uncertainties. When used in this document, the words “believes,” “plans,” “expects,” “anticipates,” “intends,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate,” or the negative of such terms and similar expressions as they relate to Pioneer Natural Resources Company (“Pioneer” or the “Company”) or its management are intended to identify forward-looking statements. The forward-looking statements are based on our current expectations, assumptions, estimates and projections about the Company and the industry in which we operate. 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. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See “Item 1. Business — Competition, Markets and Regulations”, “Item 1A. Risk Factors” 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. The Company undertakes no duty to publicly update these statements except as required by law.


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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.
  •  “field fuel” means gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point.
  •  “GAAP” means accounting principles that are generally accepted in the United States of America.
  •  “LIBOR” means London Interbank Offered Rate, which is a market rate of interest.
  •  “MBbl” means one thousand Bbls.
  •  “MBOE” means one thousand BOEs.
  •  “Mcf” means one thousand cubic feet and is a measure of natural gas volume.
  •  “MMBbl” means one million Bbls.
  •  “MMBOE” means one million BOEs.
  •  “MMBtu” means one million Btus.
  •  “MMcf” means one million cubic feet.
  •  “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.
  •  “proved reserves” mean the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (C) crude oil, natural gas and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
  •  “SEC” means the United States Securities and Exchange Commission.
  •  “Standardized Measure” means the after-tax present value of estimated future net revenues of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs in effect at the specified date and a 10 percent discount rate.
  •  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.


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PART I
 
ITEM 1.   BUSINESS
 
General
 
Pioneer is a Delaware corporation whose common stock is listed and traded on the NYSE. The Company is a large independent oil and gas exploration and production company with operations in the United States, Argentina, Canada, Equatorial Guinea, Nigeria, South Africa and Tunisia.
 
The Company’s executive offices are located at 5205 N. O’Connor Blvd., Suite 900, Irving, Texas 75039. The Company’s telephone number is (972) 444-9001. The Company maintains other offices in Anchorage, Alaska; Denver, Colorado; Midland, Texas; Buenos Aires, Argentina; Calgary, Canada; London, England; Lagos, Nigeria; Capetown, South Africa and Tunis, Tunisia. At December 31, 2005, the Company had 1,694 employees, 912 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 450 Fifth Street, N.W., 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 on or 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.
 
In 2005, the Company submitted the annual certification of its Chief Executive Officer regarding the Company’s compliance with the NYSE’s corporate governance listing standards, pursuant to Section 303A.12(a) of the NYSE Listed Company Manual.
 
Evergreen Merger
 
On September 28, 2004, Pioneer completed a merger with Evergreen Resources, Inc. (“Evergreen”). Pioneer acquired the common stock of Evergreen for a total purchase price of approximately $1.8 billion, which was comprised of cash and Pioneer common stock. Evergreen was a publicly-traded independent oil and gas company primarily engaged in the production, development, exploration and acquisition of North American unconventional natural gas. Evergreen’s operations were principally focused on developing and expanding its coal bed methane (“CBM”) field located in the Raton Basin in southern Colorado. Evergreen also had operations in the Piceance Basin in western Colorado, the Uinta Basin in eastern Utah and the Western Canada Sedimentary Basin. See Note C of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information regarding the Evergreen merger.
 
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 and capital allocation discipline. These strategies are anchored by the Company’s long-lived Spraberry oil field and Hugoton, Raton and West Panhandle gas fields’ reserves and production which have an estimated remaining productive life in excess of 40 years. Underlying these fields are approximately 78 percent of the Company’s proved oil and gas reserves as of December 31, 2005.


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Recent strategic initiatives.  During September 2005, the Company announced that its board of directors (the “Board”) approved significant strategic initiatives intended to enhance shareholder value and investment returns. Together with other important initiatives, the Board approved:
 
  •  A $1 billion share repurchase program, $650 million of which was immediately initiated and substantially completed during 2005 and $350 million of which is subject to the completion of the planned deepwater Gulf of Mexico and Argentina divestitures discussed below.
 
  •  A plan to divest the Company’s assets in the Tierra del Fuego area in southern Argentina. The plan was later broadened to include entertaining offers for a complete sale of all of the Company’s Argentine assets. During January 2006, Pioneer entered into an agreement to sell its assets in Argentina for $675 million.
 
  •  A plan to divest the Company’s assets in the deepwater Gulf of Mexico. Bids to purchase the properties were received in January 2006 and the Company is currently engaged in negotiations for the sale of these assets. No assurance can be given that a sale can be completed on terms acceptable to the Company.
 
The implementation of the Board’s strategic initiatives is allowing Pioneer to (i) allocate and focus its investment capital more heavily towards predictable oil and gas basins in North America that have delivered relatively strong and consistent growth and (ii) lower its risk profile by expanding North American unconventional resource investments while reducing higher-risk exploration expenditures.
 
The divestiture of the Company’s Argentine oil and gas assets will allow the Company to leverage the current commodity price environment to monetize and exit operations in an area that has become characterized by lower operating margins, government-controlled pricing and modest production growth opportunities. The divestiture of the Company’s deepwater Gulf of Mexico assets, if successful, will also allow the Company to monetize and exit operations in an area that is characterized by escalating drilling and operating costs and relatively high exploration risk and production volatility.
 
During 2006, the Company plans to: (i) selectively explore for and develop proved reserve discoveries in areas that it believes will offer superior reserve growth and profitability potential; (ii) evaluate opportunities to acquire oil and gas properties that will complement the Company’s exploration and development drilling activities; (iii) invest in the personnel and technology necessary to maximize the Company’s exploration and development successes; and (iv) enhance liquidity, allowing the Company to take advantage of future exploration, development and acquisition opportunities. The Company is committed to continuing to enhance shareholder investment returns through adherence to these strategies.
 
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, NGL and gas reserves. In so doing, the Company sells homogenous oil, NGL and gas units which, except for geographic and relatively minor qualitative differentials, 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 experienced management and staff that will lead the Company to prudent capital investment decisions, technological innovation and price and cost management.
 
Petroleum industry.  The petroleum industry has generally been characterized by rising oil, NGL and gas commodity prices during 2005 and recent years. During 2005, the Company has also been affected by increasing costs, particularly higher drilling and well servicing rig rates and drilling supplies. During recent years, world oil prices have increased in response to increases in demand in Asian economies, hurricane activity in the Gulf of Mexico and supply disruptions and threatened disruptions in the Middle East and Venezuela. North American gas prices have improved as overall demand fundamentals have strengthened while supply uncertainties still remain. Significant factors that will impact 2006 commodity prices include developments in the issues currently impacting Iraq and Iran and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals. To mitigate the impact of commodity price volatility on the Company’s net asset value, Pioneer utilizes commodity hedge contracts. See


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“Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the impact to oil and gas revenues during 2005, 2004 and 2003 from the Company’s hedging activities and the Company’s open hedge positions at December 31, 2005.
 
The Company.  The Company’s asset base is anchored by the Spraberry oil field located in West Texas, the Hugoton gas field located in Southwest Kansas, the Raton gas field located in southern Colorado and the West Panhandle gas field located in the Texas Panhandle. Complementing these areas, the Company has exploration and development opportunities and/or oil and gas production activities in the Gulf of Mexico, the onshore Gulf Coast area and in Alaska, and internationally in Argentina, Canada, Equatorial Guinea, Nigeria, South Africa and Tunisia. Combined, these assets create a portfolio of resources and opportunities that are well balanced among oil, NGLs and gas, and that are also well balanced between long-lived, dependable production and exploration and development opportunities. Additionally, the Company has a team of dedicated employees that represent the professional disciplines and sciences that will allow Pioneer to maximize the long-term profitability and net asset value inherent in its physical assets.
 
The Company provides administrative, financial and management support to United States and foreign subsidiaries that explore for, develop and produce oil, NGL and gas reserves. Production operations are principally located domestically in Texas, Kansas, Colorado, Louisiana, Utah and the Gulf of Mexico, and internationally in Argentina, Canada, South Africa and Tunisia.
 
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. During the year ended December 31, 2005, the Company’s average daily production, on a BOE basis, decreased as a result of (i) production curtailments in the Gulf of Mexico resulting from 2004 and 2005 hurricane damages, (ii) production curtailment in the United States Mid-Continent area during mid-May through mid-July due to the fire at the Company’s Fain gas plant and (iii) full production of recoverable reserves from the Harrier field in the deepwater Gulf of Mexico during the third quarter of 2005. Partially offsetting these decreases in production volumes were (i) a full year of gas production from the properties acquired in the Evergreen merger, (ii) increased production from the Company’s Devils Tower oil field in the deepwater Gulf of Mexico despite hurricane disruptions, (iii) increased production from the Company’s Raptor and Tomahawk gas fields in the deepwater Gulf of Mexico and (iv) increased production from the Company’s Argentine and Canadian subsidiaries, primarily in response to increased development drilling. Production, price and cost information with respect to the Company’s properties for 2005, 2004 and 2003 is set forth under “Item 2. Properties — Selected Oil and Gas Information — Production, Price and Cost Data”.
 
The aforementioned divestitures of the Argentine and deepwater Gulf of Mexico assets, if successfully completed, will significantly reduce the Company’s 2006 production volumes.
 
Drilling activities.  The Company seeks to increase its oil and gas reserves, production and cash flow through exploratory and development drilling and by conducting other production enhancement activities, such as well recompletions. During the three years ended December 31, 2005, the Company drilled 1,626 gross (1,484 net) wells, 91 percent of which were successfully completed as productive wells, at a total drilling cost (net to the Company’s interest) of $2.1 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, 2005 include proved undeveloped reserves and proved developed reserves that are behind pipe of 196 MMBOE of oil and NGLs and 1,233 Bcf of gas. Development of these proved reserves will require future capital expenditures. The timing of the development of these reserves will be dependent upon the commodity price environment, the Company’s expected operating cash flows and the Company’s financial condition. The Company believes that its current portfolio of proved reserves and unproved prospects provides attractive development and exploration opportunities for at least the next three to five years.


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Exploratory activities.  The Company has devoted significant efforts and resources to hiring and developing a highly skilled exploration staff as well as acquiring a portfolio of exploration opportunities. During September 2005, the Company announced that the Board approved strategic initiatives to implement a plan to exit exploration in the deepwater Gulf of Mexico and the Tierra del Fuego area in Argentina and to focus its exploration efforts in onshore North America, Alaska and Africa. Associated therewith, and pending approval of a 2006 capital spending budget, the Company plans to reduce its 2006 exploration budget to less than 20 percent of the total 2006 capital budget. The Company anticipates that its 2006 exploration efforts will be concentrated domestically in the onshore Gulf Coast area, the Rocky Mountain area and Alaska, and internationally in Africa and Canada. Exploratory drilling involves 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 — Drilling activities” below.
 
Acquisition activities.  The Company regularly seeks to acquire properties that complement its operations, provide exploration and development opportunities and potentially provide superior returns on investment. In addition, the Company pursues strategic acquisitions that will allow the Company to expand into new geographical areas that feature producing properties and provide exploration/exploitation opportunities. During 2005, 2004 and 2003, the Company invested $269.7 million, $2.6 billion (including $2.5 billion associated with the Evergreen merger) and $151.0 million, respectively, of acquisition capital to purchase proved oil and gas properties, including additional interests in its existing assets, and to acquire new prospects for future exploitation and exploration activities. See Note C of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a description of the Company’s acquisitions during 2005, 2004 and 2003.
 
The Company periodically evaluates and pursues acquisition opportunities (including opportunities to acquire particular oil and gas properties or related assets; entities owning oil and gas properties or related 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 analysis, oil and gas reserve analysis, due diligence, the submission of an indication of interest, preliminary negotiations, negotiation of a letter of intent or negotiation of a definitive agreement. The success of any acquisition will depend on a number of factors. See “Item 1A. Risk Factors-Acquisitions”.
 
Asset divestitures.  The Company regularly reviews its asset base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. While the Company generally does not dispose of assets solely for the purpose of reducing debt, such dispositions can have the result of furthering the Company’s objective of increasing financial flexibility through reduced debt levels.
 
During September 2005, the Company announced that the Board had approved a series of strategic initiatives, including a plan to divest the Company’s nonoperated Tierra del Fuego interests in southern Argentina and the Company’s deepwater Gulf of Mexico portfolio. During the Argentine sale process, the Company had indications from several potential buyers that they could enhance their value for a transaction in Argentina if it included all of the Company’s properties. Consequently, the Company expressed its willingness to entertain offers for a complete exit from Argentina. During January 2006, the Company announced signing an agreement with Apache Corporation to sell all of its assets in Argentina for $675 million, subject to normal closing adjustments. The sale to Apache Corporation is expected to close during the latter part of the first quarter or in early April of 2006.
 
The deepwater Gulf of Mexico bid process has been completed and the Company is currently engaged in negotiations for the sale of the properties. No assurance can be given that a sale can be completed on terms acceptable to the Company.
 
During 2005, the Company’s material divestitures consisted of (i) the sale of three volumetric production payments (“VPPs”) in the Spraberry and Hugoton fields for net proceeds of approximately $892.6 million, (ii) the sale of all of its interests in the Martin Creek, Conroy Black and Lookout Butte oil and gas properties in Canada for net proceeds of $197.2 million, which resulted in a gain of $138.3 million that is included in the Company’s discontinued operations; (iii) the sale of all of its interests in certain oil and gas properties on the shelf of the Gulf of Mexico for net proceeds of $59.1 million, which resulted in a gain of $27.7 million that is included in the Company’s discontinued operations; and (iv) the sale of all of its shares in a subsidiary that owns the interest in the Olowi block in Gabon for net proceeds of $47.9 million, which resulted in a gain of $47.5 million that is included in


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the Company’s 2005 income from continuing operations. The net cash proceeds were primarily used to fund additions to oil and gas properties or to reduce the Company’s outstanding indebtedness. See Notes N and T 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 VPPs entered into by the Company during 2005.
 
The Company anticipates that it will continue to sell nonstrategic properties or other assets from time to time to increase capital resources available for other activities, to achieve operating and administrative efficiencies and to improve profitability.
 
Operations by Geographic Area
 
The Company operates in one industry segment, that being oil and gas exploration and production. See Note R of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for geographic operating segment information, including results of operations and segment assets.
 
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 the index or spot price for gas or the posted price for oil, price regulations, distance from the well to the pipeline, well pressure, estimated reserves, commodity quality and prevailing supply conditions. In Argentina, the Company receives significantly lower prices for its production as a result of the Argentine government’s imposed price limitations. See “Qualitative Disclosures” in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion of Argentine foreign currency, operations and price risk.
 
Significant purchasers.  During 2005, the Company’s primary purchasers of oil, NGLs and gas were Williams Power Company, Inc. (nine percent), Occidental Energy Marketing, Inc. (nine percent), ConocoPhillips (seven percent), Plains Marketing LP (seven percent) and Tenaska Marketing (six percent). The Company is of the opinion that the loss of any one purchaser would not have an adverse effect on its ability to sell its oil, NGL and gas production.
 
Hedging activities.  The Company utilizes commodity swap and collar contracts in order to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a description of the Company’s hedging activities, “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information concerning the impact on oil and gas revenues during 2005, 2004 and 2003 from the Company’s commodity hedging activities and the Company’s open commodity hedge positions at December 31, 2005.
 
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 to acquire 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 purchase such properties and the financial resources necessary to acquire and develop the properties. Higher recent commodity prices have increased the cost of properties available for acquisition. Many of the Company’s competitors are substantially larger and have financial and other resources greater than those of the Company.


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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.
 
Governmental 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 that will ensure that material information relating to the Company and its consolidated subsidiaries is made known to the Company’s management and that the financial statements and other financial 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.
 
Oil and gas exploration and production operations are also subject to various types of regulation by local, state, federal and foreign agencies. Additionally, the Company’s operations are subject to state conservation laws and regulations, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of wells. States and foreign governments also generally impose a production or severance tax with respect to the production and sale of oil and gas within their respective jurisdictions. The regulatory burden on the oil and gas industry increases the Company’s cost of doing business and, consequently, affects its profitability.
 
Additional proposals and proceedings that might affect the oil and gas industry are considered from time to time by the United States Congress, the Federal Energy Regulatory Commission, state regulatory bodies, the courts and foreign governments. The Company cannot predict when or if any such proposals might become effective or their effect, if any, on the Company’s operations.
 
Environmental and health controls.  The Company’s operations are subject to numerous U.S. federal, state and local, as well as foreign, laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental and health protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the type, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas and impose substantial liabilities for pollution resulting from oil and gas operations. The Company’s inability to obtain these permits in a timely manner or at all could cause delays or otherwise negatively impact the Company’s ability to implement its business plans. Failure to comply with these environmental laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that limit or prevent operations. Although the Company believes that compliance with U.S. and foreign environmental laws and regulations will not have a material adverse effect on its future results of operations or financial condition, risks of substantial costs and liabilities are inherent in oil and gas operations, and there can be no assurance that significant costs and liabilities will not be incurred or that curtailment in production or processing might not arise as a result of such compliance. Moreover, it is possible that other developments, such as stricter environmental laws and regulations or claims for damages to property or persons resulting from the Company’s operations, could result in substantial costs and liabilities.
 
In the U.S., the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and 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 generates wastes in the U.S., including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The U.S. Environmental Protection Agency, and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by the Company’s oil and gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly operating and disposal requirements.
 
The Company currently owns or leases, and has in the past owned or leased, properties in the U.S. that for many years have been used for the exploration and production of oil and gas reserves. Although the Company has used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where such hydrocarbons or wastes have been taken for recycling or disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under the Company’s control. These properties and the hydrocarbons or wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company could be required to remove or remediate previously disposed wastes or property contamination or to perform remedial plugging operations to prevent future contamination.
 
Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to prepare and implement spill prevention control plans, countermeasure plans and facility response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) amends certain provisions of the federal Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act (“CWA”), and other statutes as they pertain to the prevention of and response to oil spills into navigable waters of the U.S. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. The CWA provides penalties for any discharges of petroleum products in reportable quantities and imposes substantial liability for the costs of removing a spill. OPA requires responsible parties to establish and maintain evidence of financial responsibility to cover removal costs and damages resulting from an oil spill. OPA calls for a financial responsibility of $35 million to cover pollution cleanup for offshore facilities. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of releases of petroleum or its derivatives into surface waters or into the ground. The Company does not believe that the OPA, CWA or related state laws are any more burdensome to it than they are to other similarly situated oil and gas companies.
 
Many states in which the Company operates regulate naturally occurring radioactive materials (“NORM”) and NORM wastes that are generated in connection with oil and gas exploration and production activities. NORM wastes typically consist of very low-level radioactive substances that become concentrated in pipes and production equipment. Certain state regulations require the testing of pipes and production equipment for the presence of NORM, the licensing of NORM-contaminated facilities and the careful handling and disposal of NORM wastes. The Company believes the regulation of NORM has minimal effect on its operations because the Company generates only small quantities of NORM on an annual basis.
 
The Company’s field operations in the U.S. involve the use of gas-fired compressors, which are subject to the federal Clean Air Act and analogous state laws governing the control and permitting of air emissions. The Company believes that it is in substantial compliance with applicable permitting and control technology requirements of such laws and regulations; however, in the future, additional facilities could become subject to additional permitting, monitoring and pollution control requirements as compressor facilities are expanded.
 
The Company’s operations outside of the U.S. are potentially subject to similar foreign governmental controls relating to protection of the environment. The Company believes that compliance with existing requirements of these foreign governmental bodies has not had a material adverse effect on the Company’s operations.
 
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


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described in “Item 1. Business — Competition, Markets and Regulations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk”. If any of these risks actually occur, they could materially harm the Company’s business, financial condition or results of operations and impair Pioneer’s ability to implement business plans or complete development projects as scheduled. In that case, the market price of the Company’s common stock could decline.
 
Commodity prices.  The Company’s revenues, profitability, cash flow and future rate of growth are highly dependent on oil and gas prices, which are affected by numerous factors beyond the Company’s control. Historically, oil and gas prices have been very volatile. A significant downward trend in commodity prices would have a material adverse effect on the Company’s revenues, profitability and cash flow and could, under certain circumstances, result in a reduction in the carrying value of the Company’s oil and gas properties and goodwill and the recognition of deferred tax asset valuation allowances or an increase to the Company’s deferred tax asset valuation allowances, depending on the Company’s tax attributes in each country in which it has activities. Pioneer makes price assumptions that are used for planning purposes, and a significant portion of the Company’s operating expenses, including rent, salaries and noncancellable capital commitments, is largely fixed in nature. Accordingly, if commodity prices are below expectations, Pioneer’s financial results are likely to be adversely and disproportionately affected because these expenses are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.
 
Drilling activities.  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 as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions and shortages or delays in the delivery of equipment. 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 or exploratory, involves these risks, exploratory 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 2006 even though less than 20 percent of the Company’s 2006 capital budget is devoted to higher-risk exploratory projects. Increased levels of drilling activity in the oil and gas industry in recent periods have led to reduced availability, extended delivery times and increased costs of some drilling equipment, materials and supplies. The Company expects that these trends will continue in the foreseeable future and, if so, will impact the Company’s profitability, cash flow and ability to complete development projects as scheduled.
 
Unproved properties.  At December 31, 2005, the Company carried unproved property costs of $313.9 million. GAAP requires periodic evaluation of these costs on a project-by-project basis in comparison to their estimated fair value. These evaluations will be 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.
 
Acquisitions.  Acquisitions of producing oil and gas properties have been a key element of the Company’s growth. The Company’s growth following the full development of its existing property base could be impeded if it is unable to acquire additional oil and gas reserves on a profitable basis. The success of any acquisition will depend on a number of factors, including the ability to estimate accurately the costs to develop the reserves, the recoverable volumes of reserves, rates of future production and future net revenues attainable from the reserves and the assessment of possible environmental liabilities. 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.


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Divestitures.  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, including the availability of purchasers willing to purchase the nonstrategic assets at prices acceptable to the Company.
 
Operation of gas processing plants.  As of December 31, 2005, the Company owned interests in 12 gas processing plants and three treating facilities. The Company operates eight of the plants and all three treating facilities. There are significant risks associated with the operation of gas processing plants. For example, in May 2005, the Company’s Fain gas plant was shut in for two months due to a mechanical failure that resulted in a fire. Gas and NGLs are volatile and explosive and may include carcinogens. Damage to or misoperation 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.
 
Operating hazards and uninsured losses.  The Company’s operations are subject to all the risks normally incident to the oil and gas exploration and production business, including blowouts, cratering, explosions, adverse weather effects and pollution and other environmental damage, any of which 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. Increased hurricane activity over the past two years has resulted in production curtailments and physical damage to the Company’s Gulf of Mexico operations. Although the Company currently maintains insurance coverage that it considers reasonable and that is similar to that maintained by comparable companies in the oil and gas industry, it is not fully insured against certain of these risks, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance.
 
Environmental.  The oil and gas business is subject to environmental hazards, such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose the Company to substantial liability due to pollution and other environmental damage. A variety of United States federal, state and local, as well as foreign laws and regulations govern the environmental aspects of the oil and gas business. Noncompliance with these laws and regulations may subject the Company to administrative, civil, or criminal penalties, remedial cleanups, and natural resource damages or other liabilities and compliance may increase the cost of the Company’s operations. Such laws and regulations may also affect the costs of acquisitions. See “Item 1. Business — Competition, Markets and Regulations — Environmental and health controls” above for additional discussion related to environmental risks.
 
The Company does not believe that its environmental risks are materially different from those of comparable companies in the oil and gas industry. Nevertheless, no assurance can be given that 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.
 
Debt restrictions and availability.  The Company is a borrower under fixed rate senior notes and a variable rate credit facility. The terms of the Company’s borrowings under the senior 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 F 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, 2005 and the terms associated therewith.
 
The Company’s ability to obtain additional financing is also impacted by the Company’s debt credit ratings and competition for available debt financing. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of the Company’s debt credit ratings.
 
Competition.  The oil and gas industry is highly competitive. The Company competes with other companies, producers and operators for acquisitions and in the exploration, development, production and marketing of oil and


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gas. Some of these competitors have substantially greater financial and other resources than the Company. See “Item 1. Business — Competition, Markets and Regulations” above for additional discussion regarding competition.
 
Government regulation.  The Company’s business is regulated by a variety of federal, state, local and foreign laws and regulations. There can be no assurance that present or future regulations will not adversely affect the Company’s business and operations. See “Item 1. Business — Competition, Markets and Regulations” above for additional discussion regarding government regulation.
 
International operations.  At December 31, 2005, approximately 14 percent of the Company’s proved reserves of oil, NGLs and gas were located outside the United States (ten percent in Argentina, two percent in Canada and two percent in Africa). The success and profitability of international operations may be adversely affected by risks associated with international activities, including economic and labor conditions, political instability, tax laws (including host-country import-export, excise and income taxes and United States taxes on foreign subsidiaries) and changes in the value of the U.S. dollar versus the local currencies in which oil and gas producing activities may be denominated. To the extent that the Company is involved in international activities, changes in exchange rates may adversely affect the Company’s future results of operations and financial condition. See “Critical Accounting Estimates” included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Qualitative Disclosures” in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information specific to Argentina’s economic and political situation and other risks associated with the Company’s international operations. The aforementioned planned sale of Argentine assets, if completed, will significantly reduce the Company’s international operations.
 
Estimates of reserves and future net revenues.  Numerous uncertainties exist in estimating quantities of proved reserves and future net revenues therefrom. The estimates of proved reserves and related future net revenues 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 oil and gas prices and
 
  •  assumptions concerning future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs.
 
Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves:
 
  •  the quantities of oil and gas that are ultimately recovered,
 
  •  the production and operating costs incurred,
 
  •  the amount and timing of future development expenditures and
 
  •  future oil and gas sales prices.
 
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. The Company’s actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.


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As required by the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices 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,
 
  •  increases or decreases in the supply or demand of oil and gas and
 
  •  changes in governmental regulations or taxation.
 
The Company reports all proved reserves held under production sharing arrangements and concessions utilizing the “economic interest” method, which excludes the host country’s share of proved reserves. Estimated quantities of production sharing arrangements reported under the “economic interest” method are subject to fluctuations in the price of oil and gas 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. It requires the use of oil and gas prices, as well as operating and development costs, prevailing as of the date of computation. 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 revenues may be materially different from the net revenues that are ultimately received. 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.
 
Stock repurchases.  During 2005, the Company repurchased 20 million shares of its common stock, and announced its intention to repurchase up to an additional $350 million of its common stock, subject to completion of the planned divestiture of its deepwater Gulf of Mexico and Argentine assets. The Board sets limits on the price per share at which Pioneer’s common stock can be repurchased, and the Company will not be permitted to repurchase its stock during certain periods because of scheduled and unscheduled trading blackouts. Additionally, business conditions and availability of capital may dictate that repurchases be suspended or cancelled. As a result, there can be no assurance that additional repurchases will be commenced and, if so, that they will be completed.
 
Commodity hedges.  To the extent that the Company engages in hedging activities to reduce commodity price risk, Pioneer may be prevented from realizing the benefits of price increases above the levels of the hedges. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk”.
 
ITEM 1B.   UNRESOLVED STAFF COMMENTS
 
None.
 
ITEM 2.   PROPERTIES
 
The information included in this Report about the Company’s oil, NGL and gas reserves as of December 31, 2005, 2004 and 2003, which are located in the United States, Argentina, Canada, South Africa and Tunisia, were based on evaluations prepared by the Company’s engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”) with respect to the Company’s major properties and prepared by the Company’s engineers with respect to all other properties. The reserve audits performed by NSAI in aggregate represented 82 percent, 88 percent and 87 percent of the Company’s 2005, 2004 and 2003 proved reserves, respectively; and, 76 percent, 84 percent and 89 percent of the Company’s 2005, 2004 and 2003 associated present value of proved reserves discounted at ten percent, respectively.
 
NSAI follows the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers (“SPE”). A reserve audit as defined


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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 generally accepted petroleum engineering and evaluation principles.
 
  •  The estimation of proved 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 and has been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles.
 
  •  The methods and procedures used by a company, and the reserve information furnished by a company, must be reviewed in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare its own estimates of reserve information for the audited properties.
 
To further clarify, in conjunction with the audits of the Company’s proved reserves and associated present value discounted at ten percent, the Company provided to NSAI its external and internal engineering and geoscience technical data and analyses. Based on NSAI’s review of that data, they had the option of honoring the Company’s interpretation, or making their own interpretation. No data was withheld from them. NSAI accepted without independent verification the accuracy and completeness of the historical information and data furnished by the Company with respect to ownership interest; oil and gas production; well test data; oil, NGL and gas prices; operating and development costs; and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their evaluation something came to their attention which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data.
 
In the course of their evaluations, NSAI prepared, for all of the audited properties, their own estimates of the Company’s proved reserves and present value of such reserves discounted at ten percent. NSAI’s estimates of those proved reserves and present value of such reserves discounted at ten percent did not differ from the Company’s estimates by more than ten percent in the aggregate. However, when compared on a 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 present value of such reserves discounted at ten percent are reasonable and that their audit objectives have been met, NSAI will issue a completed 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 is NSAI’s opinion, as set forth in its audit letters, that Pioneer’s estimates of the Company’s proved oil and gas reserves and associated future net revenues are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles.
 
The Company did not provide estimates of total proved oil and gas reserves during 2005, 2004 or 2003 to any federal authority or agency, other than the SEC. The Company’s reserve estimates do not include any probable or possible reserves.
 
Proved Reserves
 
The Company’s proved reserves totaled 986.7 MMBOE, 1.0 billion BOE and 789.1 MMBOE at December 31, 2005, 2004 and 2003, respectively, representing $7.3 billion, $6.6 billion and $4.6 billion, respectively, of Standardized Measure. The Company’s proved reserves include field fuel which is gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point. The following table shows


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the changes in the Company’s proved reserve volumes by geographic area during the year ended December 31, 2005 (in MBOE):
 
                                                 
          Discoveries and
                         
    Production     Extensions     Acquisitions     Divestitures     Revisions     Total  
 
United States
    (49,210 )     17,494       79,663       (37,964 )     (29,049 )     (19,066 )
Argentina
    (11,874 )     7,602                   (20,881 )     (25,153 )
Canada
    (2,922 )     9,840       49       (9,947 )     3,082       102  
Africa
    (3,674 )     12,109                   184       8,619  
                                                 
Total
    (67,680 )     47,045       79,712       (47,911 )     (46,664 )     (35,498 )
                                                 
 
Production.  Production volumes include (a) 2,409 MBOE of field fuel and (b) 1,188 MBOE of production associated with certain divested assets being presented as discontinued operations.
 
Discoveries and extensions.  Discoveries and extensions are primarily the result of (a) drilling activity in the Raton Basin in the United States, Horseshoe Canyon and Chinchaga fields in Canada and the Neuquen Basin in Argentina and (b) the approval to begin development of the gas reserves, previously discovered, off the south coast of South Africa.
 
Acquisitions.  Acquisition volumes are primarily attributable to the (a) July 2005 announced completion of the acquisition of 70 MBOE of proved reserves in the Spraberry field and Gulf Coast area and (b) other smaller acquisitions.
 
Divestitures.  The divestitures are primarily attributable to (a) the sale of approximately 28 MMBOE of proved reserves in the Spraberry and Hugoton fields through three VPPs, (b) the sale of approximately 10 MMBOE of proved reserves in properties on the shelf of the Gulf of Mexico and East Texas and (c) the sale of approximately 10 MMBOE of proved reserves in the Martin Creek and Conroy Black areas of northeast British Columbia and the Lookout Butte area of southern Alberta.
 
Revisions.  The overall downward revisions are primarily attributable to (a) the recent drilling results in the deep gas reserves in the Neuquen Basin of Argentina which indicated that the gas reservoirs are more complex and compartmentalized than expected, and (b) additional production decline history on producing wells and unexpected drilling results in certain areas of the field in the Raton Basin in the United States where a number of wells drilled on the northern rim of the field during the second half of 2005 encountered less CBM reservoir than expected due to nonproductive volcanic intrusions into the coal interval. The downward revisions were offset by increased commodity prices that extended the economic life on various properties.
 
On a BOE basis, 62 percent of the Company’s total proved reserves at December 31, 2005 were proved developed reserves. Based on reserve information as of December 31, 2005, and using the Company’s production information for the year then ended, the reserve-to-production ratio associated with the Company’s proved reserves was 15 years on a BOE basis. The following table provides information regarding the Company’s proved reserves and average daily sales volumes by geographic area as of and for the year ended December 31, 2005:
 
                                                         
          2005 Average Daily
 
    Proved Reserves as of December 31, 2005(a)     Sales Volumes(b)  
    Oil
                      Oil
             
    & NGLs
    Gas
          Standardized
    & NGLs
    Gas
       
    (MBbls)     (MMcf)     MBOE     Measure     (Bbls)     (Mcf)     BOE  
                      (In thousands)                    
 
United States
    385,771       2,750,856       844,247     $ 6,078,764       43,345       497,068       126,191  
Argentina
    34,024       404,323       101,411       807,897 (c)     9,693       137,032       32,531  
Canada
    2,423       130,514       24,175       254,067       713       36,427       6,784  
Africa
    6,824       60,395       16,890       156,169       10,065             10,065  
                                                         
Total
    429,042       3,346,088       986,723     $ 7,296,897       63,816       670,527       175,571  
                                                         
 
 
(a) The gas reserves contain 306 MMcf of gas that will be produced and utilized as field fuel.


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(b) The 2005 average daily sales volumes are from continuing operations and (i) do not include the field fuel produced, which averaged 6,599 BOEPD and (ii) were calculated using a 365-day year and without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the year.
 
(c) Assuming the Argentine export tax on oil remains in place after the expiration date of the law in February 2007 the standardized measure of discounted future cash flows for Argentina would be approximately $633 million at December 31, 2005.
 
The following table represents the estimated timing and cash flows of developing the Company’s proved undeveloped reserves as of December 31, 2005:
 
                                         
    Estimated
                         
    Future
    Future
    Future
    Future
       
    Production
    Cash
    Production
    Development
    Future Net
 
Year Ended December 31,
  (MBOE)     Inflows     Costs     Costs     Cash Flows  
    ($ in thousands)  
 
2006
    5,694     $ 204,592     $ 26,656     $ 666,238     $ (488,302 )
2007
    15,552       603,300       78,878       502,221       22,201  
2008
    19,470       740,419       101,040       375,092       264,287  
2009
    21,306       825,809       119,378       208,685       497,746  
2010
    21,652       862,436       130,472       212,670       519,294  
Thereafter
    287,562       13,008,489       3,408,631       729,274       8,870,584  
                                         
      371,236     $ 16,245,045     $ 3,865,055     $ 2,694,180     $ 9,685,810  
                                         
 
Description of Properties
 
As of December 31, 2005, the Company has production, development and/or exploration operations in the United States, Argentina, Canada, Equatorial Guinea, Nigeria, South Africa and Tunisia.
 
United States
 
Approximately 78 percent of the Company’s proved reserves at December 31, 2005 is located in the Spraberry field in the Permian Basin area, the Hugoton and West Panhandle fields of the Mid-Continent area and the Raton field in the Rocky Mountain area. These fields generate substantial operating cash flow and the Spraberry and Raton fields have a large portfolio of low risk drilling opportunities. The cash flows generated from these fields provide funding for the Company’s other development and exploration activities both domestically and internationally. The Company has preliminarily budgeted approximately $900 million to $1.0 billion for exploration and development drilling expenditures for 2006.
 
The following tables summarize the Company’s development and exploration/extension drilling activities during 2005:
 
                                         
    Development Drilling  
    Beginning Wells
    Wells
    Successful
    Unsuccessful
    Ending Wells
 
    in Progress     Spud     Wells     Wells     In Progress  
 
Spraberry field
    13       181       170       1       23  
Hugoton field
    1       18       18       1        
West Panhandle field
    11       42       50       3        
Raton field
          262       262              
Other
    7       38       37       2       6  
                                         
Total United States
    32       541       537       7       29  
                                         
 


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    Exploration/Extension Drilling  
    Beginning Wells
    Wells
    Successful
    Unsuccessful
    Ending Wells
 
    in Progress     Spud     Wells     Wells     In Progress  
 
Raton field
          27       26             1  
Other
    9       18       14       7       6  
                                         
Total United States
    9       45       40       7       7  
                                         
 
The following table summarizes by geographic area the Company’s costs incurred, excluding asset retirement obligations, during 2005 and the total wells preliminarily planned to be drilled during 2006:
 
                                                 
    Property
                      2006
 
    Acquisition Costs     Exploration
    Development
          Wells
 
    Proved     Unproved     Costs     Costs     Total     Planned  
    (In thousands)  
 
United States:
                                               
Permian Basin
  $ 145,244     $ 2,520     $ 1,236     $ 130,308     $ 279,308       365  
Mid-Continent
    163             34       40,808       41,005       28  
Rocky Mountain
          20,050       13,207       132,876       166,133       379  
Gulf of Mexico
          12,374       150,305       94,552       257,231       4 (a)
Onshore Gulf Coast
    22,407       26,390       8,871       44,412       102,080       35  
Alaska
          (773 )     44,070       5,427       48,724       3  
                                                 
Total United States
  $ 167,814     $ 60,561     $ 217,723     $ 448,383     $ 894,481       814  
                                                 
 
 
(a) Includes two sidetrack wells proposed by the operator in the Aconcagua field and two delineation wells planned on the Clipper discovery.
 
  Permian Basin
 
Spraberry field.  The Spraberry field was discovered in 1949 and encompasses eight counties in West Texas. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casinghead gas with an average energy content of 1,400 Btu. The oil and gas are produced primarily from three formations, the upper and lower Spraberry and the Dean, at depths ranging from 6,700 feet to 9,200 feet. Recently, the Company has begun completing selected wells in the Wolfcamp formation at depths ranging from 9,300 feet to 10,300 feet with successful results. The Company believes the area offers excellent opportunities to enhance oil and gas production because of the numerous undeveloped drilling locations, many of which are reflected in the Company’s proved undeveloped reserves, and the ability to contain operating expenses through economies of scale.
 
  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 gas in the Hugoton field has an average energy content of 1,025 Btu. The Company’s Hugoton properties are located on approximately 257,000 gross acres (237,000 net acres), covering approximately 400 square miles. The Company has working interests in approximately 1,200 wells in the Hugoton field, about 1,000 of which it operates, and partial royalty interests in approximately 500 wells. The Company owns substantially all of the gathering and processing facilities, primarily the Satanta plant, that service its production from the Hugoton field. Such ownership allows the Company to control the production, gathering, processing and sale of its gas and NGL production.
 
The Company’s Hugoton operated wells are capable of producing approximately 74 MMcf of wet gas per day (i.e., gas production at the wellhead before processing or field fuel use and before reduction for royalties), although actual production in the Hugoton field is limited by allowables set by state regulators. The Company estimates that it

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and other major producers in the Hugoton field produced near allowable capacity during the year ended December 31, 2005.
 
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 in the West Panhandle field has an average energy content of 1,300 Btu and is produced from approximately 600 wells on more than 250,000 gross acres covering over 375 square miles. The Company controls 100 percent of the wells, production equipment, gathering system and gas processing plant for the field.
 
Rocky Mountains
 
Raton field.  The Raton Basin properties are located in the southeast portion of Colorado. Exploration for CBM in the Raton Basin began in the late 1970s and continued through the late 1980s, with several companies drilling and testing more than 100 wells during this period. The absence of a pipeline to transport gas from the Raton Basin prevented full scale development until January 1995, when Colorado Interstate Gas Company completed the construction of the Picketwire lateral pipeline system. The Company’s gas in the Raton Basin has an average energy content of 1,000 Btu. Since the completion of the Picketwire lateral, production has continued to grow, resulting in expansion of the system’s capacity by its operator, the most recent expansion of which was in October 2005. The Company owns approximately 385,000 gross acres in the center of the Raton Basin with current production from coal seams of the Vermejo and Raton formations.
 
Piceance/Uinta Basins.  The Piceance Basin is located in the central portion of western Colorado, and the Uinta Basin is located in the central portion of eastern Utah. The Company owns approximately 115,000 acres covering producing and prospective regions of the Piceance and Uinta Basins. Currently, production is established from various tight sandstone, coal and shale formations.
 
Sand Wash Basin.  The Sand Wash Basin is the site of a potential CBM project located north of the Company’s Piceance Basin properties. The Company holds a 50 percent operated interest in 114,000 gross acres in the Lay Creek field. In 2006, the Company plans to (i) refrac the wells drilled by the previous owner in two existing pilots, specifically targeting coal seams to reduce water handling and (ii) drill an additional two or three pilot programs to evaluate the potential of the project.
 
Gulf of Mexico
 
Gulf of Mexico area.  In the Gulf of Mexico, the Company has focused on reserve and production growth by drilling its portfolio of shelf and deepwater development projects, high-impact, higher-risk shelf and deepwater exploration prospects and exploitation opportunities inherent in the properties the Company currently has producing on the shelf.
 
During September 2005, the Company announced its plans to pursue the divestment of its deepwater Gulf of Mexico assets to reduce the exploration risk and production volatility that have been associated with these assets. The deepwater Gulf of Mexico bid process has been completed and the Company is currently in negotiations for the sale of these assets. No assurance can be given that a sale can be completed on terms acceptable to the Company. However, if successfully completed, such a divestiture would remove the deepwater Gulf of Mexico from the Company’s portfolio of oil and gas activities.
 
During 2005, the Company had five significant projects in the deepwater Gulf of Mexico, which are discussed below:
 
  •  Canyon Express — The Canyon Express project is a joint development of three deepwater Gulf of Mexico gas discoveries, including the Company’s Total E&P USA-operated Aconcagua field and Marathon-operated Camden Hills fields, where the Company holds 37.5 percent and 33.3 percent working interests, respectively. The Company participated in the discovery of the Aconcagua gas field in 1999 and later added Camden Hills to its portfolio to enhance its ownership in the project. The Canyon Express project was approved for development in June 2000 and reached first production in September 2002. The existing Aconcagua and Camden Hills wells are expected to reach the end of their productive lives in early


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  2006; therefore, the Company now anticipates that the system will be shut in once the recoverable reserves are fully produced until a rig becomes available to drill sidetrack wells in the Aconcagua field. The Company has been advised by the operator of the Canyon Express system that sidetrack operations are planned for the Aconcagua field in late 2006.
 
  •  Falcon Corridor — The Falcon Corridor project started with the Company’s Falcon field discovery during 2001, followed by the 2003 Harrier, Raptor and Tomahawk discoveries. The Company owns a 100 percent working interest in the Falcon Corridor discoveries and surrounding areas. First production from Falcon occurred in March 2003, followed by production from Harrier, Raptor and Tomahawk in 2004. During 2005, the Harrier, Raptor and Tomahawk fields were fully depleted.
 
  •  Devils Tower Area — The Dominion-operated Devils Tower development project was sanctioned in 2001 as a spar development project with the owners leasing a spar from a third party for the life of the field. The spar has slots for eight dry tree wells and up to four subsea tie-back risers and is capable of handling 60 MBbls of oil per day and 60 MMcf of gas per day. Devils Tower production operations were initiated in 2004 prior to being shut in due to Hurricane Ivan. Production was resumed in November 2004. In addition to the Devils Tower wells, three subsea tie-back wells in the Goldfinger and Triton satellite discoveries in the Devils Tower area were jointly tied back to the Devils Tower spar in November of 2005. The Company holds a 25 percent working interest in each of these projects.
 
  •  Thunder Hawk — The Murphy Exploration and Production Company-operated Thunder Hawk discovery in 2004 encountered in excess of 300 feet of net oil pay in two high-quality reservoir zones in Mississippi Canyon Block 734. The third appraisal well was spudded during the fourth quarter of 2005 and plans to complete the drilling of the previously spudded second well, which was temporarily suspended due to weather. These wells are expected to be completed during the first half of 2006. The Company owns a 12.5 percent working interest in this discovery.
 
  •  Clipper — During the fourth quarter of 2005, the Company announced a discovery on its Clipper prospect in the Green Canyon Block 299. The Company plans additional drilling during 2006 to further delineate the field. The Company operates the block with a 55 percent working interest.
 
  Onshore Gulf Coast
 
South Texas.  The Company has focused its drilling efforts in this area on the Pawnee field in the Edwards Reef trend in South Texas. The Edwards Reef trend is a tight gas limestone reservoir characterized by narrow bands of dry gas fields extending over 250 miles. In addition to the Pawnee field, the Company has operations in the SW Kenedy and Washburn fields of the Edwards Reef trend and a growing acreage position with over 160,000 acres acquired during the past year. Production depths in the trend range from 9,500 feet to 14,000 feet, from which over 1 trillion cubic feet of gas has been produced by the oil and gas industry. The Company drilled its first successful exploration well in the recently acquired acreage in the Edwards Reef trend in late 2005 and is currently producing approximately 1.3 MMcf of gas per day from the discovery. Pioneer’s current plans include drilling at least 20 wells in the Edwards Reef trend during 2006, leveraging the Company’s horizontal drilling expertise.
 
Northern Louisiana and Mississippi.  The Company has acquired significant acreage in Northern Louisiana and Mississippi. During 2006, the Company is planning exploratory tests in the Hosston/Cotton Valley trend in Northern Louisiana and a Norphlet prospect in Mississippi.
 
  Alaska
 
North Slope area.  During 2002, the Company acquired a 70 percent working interest and operatorship in ten state leases on Alaska’s North Slope. Associated therewith, the Company drilled three exploratory wells during 2003 to test a possible extension of the productive sands in the Kuparuk River field in the shallow waters offshore. Although all three of the wells found the sands filled with oil, they were too thin to be considered commercial on a stand-alone basis. However, the wells also encountered thick sections of oil-bearing Jurassic-aged sands, and the first well flowed at a rate of approximately 1,300 Bbls per day (“BPD”). In January 2004, the Company farmed-into a large acreage block to the southwest of the Company’s discovery. In the fourth quarter of 2004, Pioneer completed


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an extensive technical and economic evaluation of the resource potential within this area. As a result of this evaluation, the Company performed front-end engineering and permitting activities during 2005 to further define the scope of the project. In February 2006, the Company announced that it has approved and is commencing the development of the Oooguruk field in the project area. Following the construction of a gravel drilling and production site in 2006, installation of a subsea flowline and facilities are planned for 2007 to carry produced liquids to existing onshore processing facilities at the Kuparuk River Unit. Between 2007 and 2009, Pioneer plans to drill approximately 40 horizontal wells in the Oooguruk field. Total gross capital invested, including projected drilling and facility costs, is expected to range from $450 million to $525 million. First production from these wells is expected to begin in 2008.
 
During the first quarter of 2006, Pioneer anticipates drilling two exploration wells as operator, one with a 50 percent working interest in the Storms area, and a second, under a farm-in agreement with ConocoPhillips, with a 90 percent working interest on the Cronus prospect. Under another farm-in agreement with ConocoPhillips, Pioneer plans to participate with a 32.5 percent working interest in a third exploration well to be drilled on ConocoPhillips’ Antigua prospect.
 
Cosmopolitan.  During 2005, Pioneer announced that it entered into an agreement on the Cosmopolitan Unit in the Cook Inlet. Under this agreement, Pioneer earned a ten percent working interest in the unit from ConocoPhillips through a disproportionate spending arrangement for a 3-D seismic program undertaken during the fourth quarter of 2005. Pursuant to this agreement, Pioneer has the option to acquire an additional 40 percent interest in the Cosmopolitan Unit any time prior to June 1, 2006. Upon evaluation of the results of the aforementioned 3-D seismic program, Pioneer will determine whether or not to exercise this option.
 
International
 
The Company’s international operations are located in the Neuquen and Austral Basins areas of Argentina, the Chinchaga and Horseshoe Canyon areas of Canada, the Sable oil field offshore South Africa and in southern Tunisia. Additionally, the Company has other development and exploration activities in the shallow waters offshore South Africa and oil development and exploration activities in Equatorial Guinea, Nigeria and Tunisia. As of December 31, 2005, approximately ten percent, two percent and two percent of the Company’s proved reserves were located in Argentina, Canada and Africa, respectively.
 
The following tables summarize the Company’s development and exploration/extension drilling activities outside the United States during 2005:
 
                                         
    Development Drilling  
    Beginning Wells
    Wells
    Successful
    Unsuccessful
    Ending Wells
 
    in Progress     Spud     Wells     Wells     In Progress  
 
Argentina
    6       65       65       4       2  
Canada
    3       27       27             3  
                                         
Total International
    9       92       92       4       5  
                                         
 
                                         
    Exploration/Extension Drilling  
    Beginning Wells
    Wells
    Successful
    Unsuccessful
    Ending Wells
 
    in Progress     Spud     Wells     Wells     In Progress  
 
Argentina
    8       29       19       14       4  
Canada
    21       182       87       7       109  
Nigeria
          1             1        
South Africa
    2             1             1  
Tunisia
    2       4       2       2       2  
                                         
Total International
    33       216       109       24       116  
                                         


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The following table summarizes by geographic area the Company’s international costs incurred, excluding asset retirement obligations, during 2005 and the total wells preliminarily planned to be drilled during 2006:
 
                                                 
    Property
                      2006
 
    Acquisition Costs     Exploration
    Development
          Wells
 
    Proved     Unproved     Costs     Costs     Total     Planned  
    (In thousands)  
 
Argentina
  $     $ 512     $ 36,878     $ 85,786     $ 123,176        
Canada
    2,593       7,344       43,437       77,962       131,336       298  
Africa:
                                               
Equatorial Guinea
                3,395             3,395       1  
Nigeria
          30,663       34,134             64,797       1  
South Africa
          260       755       13,638       14,653       4  
Tunisia
                18,395       2,847       21,242       9  
Other
                6,926       292       7,218        
                                                 
Total International
  $ 2,593     $ 38,779     $ 143,920     $ 180,525     $ 365,817       313  
                                                 
 
Argentina.  The Company’s operated production in Argentina is concentrated in the Neuquen Basin, which is located about 925 miles southwest of Buenos Aires and to the east of the Andes Mountains. Oil and gas are produced primarily from the Al Norte de la Dorsal, the Al Sur de la Dorsal, the Dadin, the Loma Negra, the Dos Hermanas, the Anticlinal Campamento and the Estación Fernández Oro blocks, in each of which the Company has a 100 percent working interest. Most of the gas produced from these blocks is processed in the Company’s Loma Negra gas processing plant. The Company operates the Meseta Sirven block located in the southern part of the San Jorge basin in Santa Cruz Province, approximately 1,200 miles south of Buenos Aires. The production from this block, in which the Company has a 100 percent working interest, is primarily oil. The Company also operates and has a 50 percent working interest in the Lago Fuego field, which is located in Tierra del Fuego, an island in the extreme southern portion of Argentina, approximately 1,500 miles south of Buenos Aires.
 
Most of the Company’s nonoperated production in Argentina is located in Tierra del Fuego, the most southern province in Argentina, where oil, gas and NGLs are produced from six separate fields in which the Company has a 35 percent working interest. The Company also has a 14.4 percent working interest in the Confluencia field which is located in the Neuquen Basin.
 
During September 2005, the Company announced that it would pursue the sale of its nonoperated position in Tierra del Fuego. During the Tierra del Fuego sales process, several prospective buyers indicated that they could enhance their value for a transaction in Argentina if it included all of Pioneer’s properties. The Company decided that if a buyer presented an attractive offer for all of the Argentine assets, that it would consider exiting Argentina. On January 17, 2006, the Company announced signing an agreement with Apache Corporation to sell all of the Company’s interests in Argentina for $675 million (subject to normal closing adjustments). The transaction is expected to close during the latter part of the first quarter or in early April of 2006.
 
Canada.  The Company’s Canadian producing properties are located primarily in Alberta and British Columbia, Canada. In May 2005, the Company sold its ownership interests in the Martin Creek and Conroy Black areas of northeast British Columbia and the Lookout Butte area of southern Alberta for net proceeds of $197.2 million. The Company continues to exploit lower risk opportunities identified in the Chinchaga field core area of northeast British Columbia. The Company also initiated significant drilling, pipeline and facility activities in south-central Alberta targeting Horseshoe Canyon CBM potential on the existing land base in the greater Drumheller area.
 
Production from the Chinchaga area of northeast British Columbia is relatively dry gas from formation depths averaging 3,400 feet. The greater Drumheller area in south-central Alberta produces CBM gas, CBM condensate and minor oil from Cretaceous to Devonian formations at depths ranging from 400 to 6,500 feet. The Company has CBM gas production currently from the Horseshoe Canyon coal and further exploitation drilling will occur throughout the area in 2006.


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Equatorial Guinea.  The Company owns a 50 percent working interest in Block H offshore Equatorial Guinea. The Company has identified several prospects on the block that are being evaluated for future drilling, one of which is expected to be drilled during 2006 or 2007.
 
Nigeria.  A partially-owned subsidiary of the Company joined Oranto Petroleum and Orandi Petroleum in an existing production sharing contract on Block 320 in deepwater Nigeria gaining exploration rights from the Nigerian National Petroleum Corporation. The subsidiary, which holds a 51 percent interest in Block 320, is owned 59 percent by the Company and 41 percent by an unaffiliated third party. The Company acquired 3-D seismic data in 2005, is currently processing the seismic and plans to drill the first well in Block 320 during 2007.
 
The Company owns a 26 percent working interest in Devon-operated Block 256 offshore Nigeria. The Company participated in an unsuccessful exploratory well on this block during 2005 and is participating in a second exploration well that spudded during January 2006. The timing of a third exploration well planned for the block has not been determined.
 
The Company had previously announced it was awarded, through a consortium, rights to acreage in Blocks 2 and 3 of the Joint Development Zone in offshore Nigeria, São Tomé and Príncipe subject to negotiating acceptable joint operating and production sharing agreements. On February 7, 2006, the Company announced that it was withdrawing from participation in both blocks.
 
South Africa.  The Company has agreements to explore for oil and gas offshore South Africa covering over five million acres along the southern coast in water depths generally less than 650 feet. The Sable oil field began producing in August 2003 and the majority of the gas from the field has been reinjected. The Company has a 40 percent working interest in the Sable field.
 
In December 2005, the Company announced the final approvals with its partner in the South Coast Gas project. Pioneer has a 45 percent working interest in the project. The project will include subsea tie-back of gas from the Sable field and six additional gas accumulations to the existing production facilities on the F-A platform for transportation via existing pipelines to a gas-to-liquids (“GTL”) plant. The Company has signed a contract for the sale of its share of gas and condensate to the GTL plant. Production is expected to begin during the second half of 2007 and increase to an average of approximately 100 MMcf per day of gas and 3,000 BPD of condensate over the initial phase of the project through 2012. Development drilling related to the project is expected to commence in the first quarter of 2006.
 
Tunisia.  The Company’s Tunisian permits can be separated into three categories: (i) three permits covering 2.9 million acres which the Company operates with an average 55 percent working interest, (ii) the Anadarko-operated Anaguid and Jenein Nord permits covering over 1.5 million acres in which the Company has a 45 percent working interest and (iii) the ENI-operated Adam Concession and Borj El Khadra permit covering approximately 212,000 acres and 970,000 acres, respectively, in which the Company has a 20 percent and 40 percent working interest, respectively. Production from the Adam Concession began in May 2003. All permits are onshore southern Tunisia.
 
In 2005, the Company conducted an extended production test of one of the two existing Anaguid Block exploration wells and drilled an offset appraisal well to the other exploration well. The results of the extended production test were unfavorable. However, the appraisal well offsetting the second discovery encountered gas and condensate in a similar horizon to the initial well. The Company is currently reviewing data from the appraisal well to determine whether development of the area is economical.
 
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, 2005, 2004 and 2003. 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 following tables set forth production, price and cost data with respect to the Company’s properties for 2005, 2004 and 2003. These amounts represent the Company’s historical results from


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continuing operations without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the respective years. The production amounts will not agree to the reserve volume tables in the “Unaudited Supplementary Information” section included in “Item 8. Financial Statements and Supplementary Data” due to field fuel volumes and production from discontinued operations being included in the reserve volume tables.
 
The Company’s lower average prices received for its Argentine commodities, as compared to the prices received in other countries, are due to price limitations imposed by the Argentine government in an effort to keep fuel and energy prices for Argentine consumers at pre-devaluation levels. These limitations have kept the prices received for oil and gas sales in Argentina well below world market levels. Beginning in 2004, the government mandated certain scheduled gas price increases through mid-2005. Those specific increases occurred as scheduled, but no specific predictions can be made about the future of oil or gas prices in Argentina. See “Qualitative Disclosures” in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion of Argentine foreign currency, operations and price risk.


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PRODUCTION, PRICE AND COST DATA
 
                                         
    Year Ended December 31, 2005  
    United
                         
    States     Argentina     Canada     Africa     Total  
 
Production information:
                                       
Annual sales volumes:
                                       
Oil (MBbls)
    9,469       2,872       77       3,674       16,092  
NGLs (MBbls)
    6,351       666       184             7,201  
Gas (MMcf)
    181,429       50,017       13,296             244,742  
Total (MBOE)
    46,059       11,874       2,476       3,674       64,083  
Average daily sales volumes:
                                       
Oil (Bbls)
    25,943       7,869       210       10,065       44,087  
NGLs (Bbls)
    17,402       1,824       503             19,729  
Gas (Mcf)
    497,068       137,032       36,427             670,527  
Total (BOE)
    126,191       32,531       6,784       10,065       175,571  
Average prices, including hedge results:
                                       
Oil (per Bbl)
  $ 31.09     $ 36.88     $ 52.12     $ 53.00     $ 37.22  
NGLs (per Bbl)
  $ 31.72     $ 33.17     $ 45.79     $     $ 32.22  
Gas (per Mcf)
  $ 6.83     $ .88     $ 7.67     $     $ 5.66  
Revenue (per BOE)
  $ 37.66     $ 14.50     $ 46.18     $ 53.00     $ 34.57  
Average prices, excluding hedge results:
                                       
Oil (per Bbl)
  $ 54.05     $ 36.88     $ 52.12     $ 53.00     $ 50.74  
NGLs (per Bbl)
  $ 31.72     $ 33.17     $ 45.79     $     $ 32.22  
Gas (per Mcf)
  $ 7.94     $ .88     $ 7.67     $     $ 6.49  
Revenue (per BOE)
  $ 46.78     $ 14.50     $ 46.18     $ 53.00     $ 41.14  
Average costs (per BOE):
                                       
Production costs:
                                       
Lease operating
  $ 4.87     $ 2.97     $ 12.94     $ 8.82     $ 5.07  
Taxes:
                                       
Ad valorem
    .88                         .63  
Production
    1.30       .23                   .97  
Workover
    .36       .06       1.89             .34  
                                         
Total
  $ 7.41     $ 3.26     $ 14.83     $ 8.82     $ 7.01  
                                         
Depletion expense
  $ 8.71     $ 7.13     $ 12.71     $ 7.96     $ 8.53  
                                         
 


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PRODUCTION, PRICE AND COST DATA — (Continued)

                                         
    Year Ended December 31, 2004  
    United
                         
    States     Argentina     Canada     Africa     Total  
 
Production information:
                                       
Annual sales volumes:
                                       
Oil (MBbls)
    9,041       3,123       26       4,274       16,464  
NGLs (MBbls)
    7,203       566       155             7,924  
Gas (MMcf)
    188,964       44,525       9,372             242,861  
Total (MBOE)
    47,738       11,110       1,743       4,274       64,865  
Average daily sales volumes:
                                       
Oil (Bbls)
    24,700       8,534       72       11,676       44,982  
NGLs (Bbls)
    19,678       1,546       425             21,649  
Gas (Mcf)
    516,294       121,654       25,606             663,554  
Total (BOE)
    130,428       30,356       4,764       11,676       177,224  
Average prices, including hedge results:
                                       
Oil (per Bbl)
  $ 29.69     $ 28.06     $ 48.37     $ 38.12     $ 31.60  
NGLs (per Bbl)
  $ 25.05     $ 29.91     $ 32.03     $     $ 25.54  
Gas (per Mcf)
  $ 5.14     $ .66     $ 4.72     $     $ 4.30  
Revenue (per BOE)
  $ 29.75     $ 12.07     $ 28.93     $ 38.12     $ 27.25  
Average prices, excluding hedge results:
                                       
Oil (per Bbl)
  $ 39.54     $ 29.82     $ 48.37     $ 38.71     $ 37.49  
NGLs (per Bbl)
  $ 25.05     $ 29.91     $ 32.03     $     $ 25.54  
Gas (per Mcf)
  $ 5.71     $ .66     $ 5.37     $     $ 4.78  
Revenue (per BOE)
  $ 33.89     $ 12.56     $ 32.48     $ 38.71     $ 30.51  
Average costs (per BOE):
                                       
Production costs:
                                       
Lease operating
  $ 3.27     $ 2.75     $ 9.92     $ 7.37     $ 3.63  
Taxes:
                                       
Ad valorem
    .58                         .43  
Production
    .78       .23                   .61  
Workover
    .24       .01       .87             .21  
                                         
Total
  $ 4.87     $ 2.99     $ 10.79     $ 7.37     $ 4.88  
                                         
Depletion expense
  $ 8.62     $ 5.56     $ 12.93     $ 11.19     $ 8.38  
                                         
 

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PRODUCTION, PRICE AND COST DATA — (Continued)

                                         
    Year Ended December 31, 2003  
    United
                         
    States     Argentina     Canada     Africa     Total  
 
Production information:
                                       
Annual sales volumes:
                                       
Oil (MBbls)
    8,215       3,171       13       723       12,122  
NGLs (MBbls)
    7,411       481       173             8,065  
Gas (MMcf)
    152,560       34,357       9,774             196,691  
Total (MBOE)
    41,054       9,378       1,815       723       52,970  
Average daily sales volumes:
                                       
Oil (Bbls)
    22,509       8,687       35       1,981       33,212  
NGLs (Bbls)
    20,306       1,318       473             22,097  
Gas (Mcf)
    417,972       94,128       26,779             538,879  
Total (BOE)
    112,477       25,693       4,971       1,981       145,122  
Average prices, including hedge results:
                                       
Oil (per Bbl)
  $ 25.09     $ 25.62     $ 28.00     $ 29.52     $ 25.50  
NGLs (per Bbl)
  $ 19.03     $ 22.85     $ 24.30     $     $ 19.38  
Gas (per Mcf)
  $ 4.45     $ .56     $ 4.65     $     $ 3.78  
Revenue (per BOE)
  $ 24.99     $ 11.87     $ 27.56     $ 29.52     $ 22.82  
Average prices, excluding hedge results:
                                       
Oil (per Bbl)
  $ 29.52     $ 26.31     $ 28.00     $ 30.07     $ 28.71  
NGLs (per Bbl)
  $ 19.03     $ 22.85     $ 24.30     $     $ 19.38  
Gas (per Mcf)
  $ 4.91     $ .56     $ 4.79     $     $ 4.15  
Revenue (per BOE)
  $ 27.59     $ 12.10     $ 28.31     $ 30.07     $ 24.91  
Average costs (per BOE):
                                       
Production costs:
                                       
Lease operating
  $ 3.01     $ 2.57     $ 8.83     $ 3.87     $ 3.14  
Taxes:
                                       
Ad valorem
    .52                         .41  
Production
    .75       .20             .12       .62  
Workover
    .16       .01       .38             .14  
                                         
Total
  $ 4.44     $ 2.78     $ 9.21     $ 3.99     $ 4.31  
                                         
Depletion expense
  $ 7.06     $ 4.96     $ 11.42     $ 10.69     $ 6.89  
                                         

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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, 2005, 2004 and 2003:
 
PRODUCTIVE WELLS(a)
 
                                                 
    Gross Productive Wells     Net Productive Wells  
    Oil     Gas     Total     Oil     Gas     Total  
 
As of December 31, 2005:
                                               
United States
    4,300       3,955       8,255       3,531       3,669       7,200  
Argentina
    821       261       1,082       684       202       886  
Canada
    65       675       740       30       511       541  
Africa
    12             12       4             4  
                                                 
Total
    5,198       4,891       10,089       4,249       4,382       8,631  
                                                 
As of December 31, 2004:
                                               
United States
    3,999       3,990       7,989       3,288       3,563       6,851  
Argentina
    744       226       970       607       168       775  
Canada
    38       489       527       25       358       383  
Africa
    9             9       3             3  
                                                 
Total
    4,790       4,705       9,495       3,923       4,089       8,012  
                                                 
As of December 31, 2003:
                                               
United States
    3,691       2,012       5,703       2,978       1,907       4,885  
Argentina
    669       194       863       539       141       680  
Canada
    4       268       272       4       210       214  
Africa
    7             7       2             2  
                                                 
Total
    4,371       2,474       6,845       3,523       2,258       5,781  
                                                 
 
 
(a) Productive wells consist of producing wells and wells capable of production, including shut-in wells. 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, 2005, the Company owned interests in 214 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, 2005:
 
LEASEHOLD ACREAGE
 
                                         
    Developed Acreage     Undeveloped Acreage     Royalty
 
    Gross Acres     Net Acres     Gross Acres     Net Acres     Acreage  
 
United States:
                                       
Onshore
    1,362,840       1,186,135       2,294,074       927,528       289,517  
Offshore
    131,852       61,718       773,919       595,332       10,500  
                                         
      1,494,692       1,247,853       3,067,993       1,522,860       300,017  
Argentina
    736,000       342,000       953,000       870,000        
Canada
    245,000       177,000       475,000       348,000       24,000  
Africa
    337,020       106,571       9,873,962       5,230,077        
                                         
Total
    2,812,712       1,873,424       14,369,955       7,970,937       324,017  
                                         


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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, 2005:
 
                 
    Acres Expiring(a)  
    Gross     Net  
 
2006(b)
    3,043,642       1,627,381  
2007
    6,494,885       3,708,934  
2008
    432,316       311,651  
2009
    604,350       199,776  
2010
    125,242       91,798  
Thereafter
    3,669,520       2,031,397  
                 
Total
    14,369,955       7,970,937  
                 
 
 
(a) Acres expiring are based on contractual lease maturities.
 
(b) Acres subject to expiration during 2006 include 2.6 million gross acres (1.3 million net acres) in Tunisia, 97,952 gross acres (48,976 net acres) in Equatorial Guinea and 309,069 gross acres (207,200 net acres) in North America. The Company may extend these leases prior to their expiration based upon 2006 planned activities or for other business reasons. In certain of these leases, the extension is only subject to the Company’s election to extend and the fulfillment of certain capital expenditure 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.


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Drilling activities.  The following table sets forth the number of gross and net productive and dry hole wells in which the Company had an interest that were drilled during 2005, 2004 and 2003. 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,  
    2005     2004     2003     2005     2004     2003  
 
United States:
                                               
Productive wells:
                                               
Development
    537       268       244       504.6       243.1       210.5  
Exploratory
    40       8       4       36.8       5.3       4.0  
Dry holes:
                                               
Development
    7       3       6       6.8       3.0       6.0  
Exploratory
    7       6       6       5.3       3.0       3.6  
                                                 
      591       285       260       553.5       254.4       224.1  
                                                 
Argentina:
                                               
Productive wells:
                                               
Development
    65       43       29       64.4       41.7       29.0  
Exploratory
    19       21       21       17.8       21.0       21.0  
Dry holes:
                                               
Development
    4       1       2       4.0       1.0       2.0  
Exploratory
    14       10       9       14.0       9.5       9.0  
                                                 
      102       75       61       100.2       73.2       61.0  
                                                 
Canada:
                                               
Productive wells:
                                               
Development
    27       3       7       26.3       3.0       7.0  
Exploratory
    87       27       16       71.5       24.5       14.9  
Dry holes:
                                               
Development
                7                   6.5  
Exploratory
    7       24       26       6.5       23.3       21.1  
                                                 
      121       54       56       104.3       50.8       49.5  
                                                 
Africa:
                                               
Productive wells:
                                               
Development
          2       1             .6       .3  
Exploratory
    3       2       1       1.2       1.4       .4  
Dry holes:
                                               
Development
                                   
Exploratory
    3       5       4       1.2       4.4       3.5  
                                                 
      6       9       6       2.4       6.4       4.2  
                                                 
Total
    820       423       383       760.4       384.8       338.8  
                                                 
Success ratio(a)
    95 %     88 %     84 %     95 %     89 %     85 %
 
 
(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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The following table sets forth information about the Company’s wells upon which drilling was in progress as of December 31, 2005:
 
                 
    Gross Wells     Net Wells  
 
United States:
               
Development
    29       24.8  
Exploratory
    7       4.1  
                 
      36       28.9  
                 
Argentina:
               
Development
    2       2.0  
Exploratory
    4       4.0  
                 
      6       6.0  
                 
Canada:
               
Development
    3       2.3  
Exploratory
    109       98.0  
                 
      112       100.3  
                 
Africa:
               
Development
           
Exploratory
    3       1.4  
                 
      3       1.4  
                 
Total
    157       136.6  
                 
 
ITEM 3.   LEGAL PROCEEDINGS
 
The Company is party to the legal proceedings that are described under “Legal actions” in Note I 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.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
The Company did not submit any matters to a vote of security holders during the fourth quarter of 2005.


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PART II
 
ITEM 5.   MARKET FOR REGISTRANT’S COMMON STOCK, 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 $.22 per share and $.20 per share during each of the years ended December 31, 2005 and 2004, respectively. On February 15, 2006, the Board declared a cash dividend on common stock of $.12 per share payable on April 12, 2006 to stockholders of record on March 29, 2006.
 
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, 2005 and 2004:
 
                         
                Dividends
 
                Declared
 
    High     Low     Per Share  
 
Year ended December 31, 2005:
                       
Fourth quarter
  $ 55.98     $ 45.39     $  
Third quarter
  $ 56.35     $ 39.66     $ .12  
Second quarter
  $ 45.24     $ 36.67     $  
First quarter
  $ 44.82     $ 32.91     $ .10  
Year ended December 31, 2004:
                       
Fourth quarter
  $ 36.85     $ 30.80     $  
Third quarter
  $ 37.50     $ 31.03     $ .10  
Second quarter
  $ 35.18     $ 29.27     $  
First quarter
  $ 34.68     $ 29.60     $ .10  
 
On February 14, 2006, the last reported sales price of the Company’s common stock, as reported in the NYSE composite transactions, was $43.51 per share.
 
As of February 14, 2006, the Company’s common stock was held by approximately 26,000 registered holders of record.
 
Securities Authorized for Issuance under Equity Compensation Plans
 
The following table summarizes information about the Company’s equity compensation plans as of December 31, 2005:
 
                         
                (b)
 
                Number of Securities
 
    (a)
          Remaining Available
 
    Number of
          for Future Issuance
 
    Securities to be
          Under Equity
 
    Issued Upon
    Weighted Average
    Compensation Plans
 
    Exercise of
    Exercise Price of
    (Excluding Securities
 
    Outstanding Options     Outstanding Options     Reflected in First Column)  
 
Equity compensation plans approved by security holders(c):
                       
Pioneer Natural Resources Company:
                       
Long-Term Incentive Plan
    1,922,215     $ 20.66       8,467,964  
Employee Stock Purchase Plan
        $       513,406  
Predecessor plans
    763,183     $ 19.45        
                         
      2,685,398               8,981,370  
                         
 
 
(a) There are no outstanding warrants or equity rights awarded under the Company’s equity compensation plans. The securities do not include restricted stock awarded under the Company’s Long-Term Incentive Plan.


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(b) The Company’s Long-Term Incentive Plan provides for the issuance of a maximum number of shares of common stock equal to ten percent of the total number of shares of common stock equivalents outstanding less the total number of shares of common stock subject to outstanding awards under any stock-based plan for the directors, officers or employees of the Company. The number of remaining securities available for future issuance under the Company’s Employee Stock Purchase Plan (the “ESPP”) is based on the original authorized issuance of 750,000 shares less 236,594 cumulative shares issued through December 31, 2005. See Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a description of each of the Company’s equity compensation plans.
 
(c) All equity compensation plans have been approved by security holders.
 
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, 2005:
 
                                 
                Total Number of Shares
    Approximate Dollar
 
                (or Units) Purchased
    Amount of Shares
 
    Total Number of
    Average Price
    as Part of Publicly
    that May Yet Be
 
    Shares (or Units)
    Paid per Share
    Announced Plans
    Purchased under
 
Period
  Purchased(a)     (or Unit)     or Programs     Plans or Programs(b)  
 
October 2005
    4,885,424     $ 51.18       4,884,900          
November 2005
    1,359     $ 52.02                
December 2005
    4,498     $ 51.33                
                                 
Total
    4,891,281     $ 51.18       4,884,900     $ 9,294,950  
                                 
 
 
(a) Amounts include shares withheld to fund tax withholding on employees’ stock awards for which restrictions have lapsed.
 
(b) Excludes $350 million of planned share repurchases which are subject to the successful completion of the planned deepwater Gulf of Mexico and Argentina divestitures.
 
During September 2005, the Company announced that the Board had approved a new share repurchase program authorizing the purchase of up to $650 million of the Company’s common stock, $640.7 million of which was completed through open market transactions by the end of 2005. The Board approved another $350 million upon the completion of the planned deepwater Gulf of Mexico and Argentina divestitures.


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ITEM 6.   SELECTED FINANCIAL DATA
 
The following selected consolidated financial data as of and for each of the five years ended December 31, 2005 for the Company 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,(a)  
    2005     2004     2003     2002     2001  
    (In millions, except per share data)  
 
Statements of Operations Data:
                                       
Revenues and other income:
                                       
Oil and gas
  $ 2,215.7     $ 1,767.4     $ 1,208.6     $ 646.6     $ 780.6  
Interest and other(b)
    97.1       14.1       12.3       11.2       21.8  
Gain on disposition of assets, net
    60.5             1.2       4.4       7.7  
                                         
      2,373.3       1,781.5       1,222.1       662.2       810.1  
                                         
Costs and expenses:
                                       
Oil and gas production
    449.3       316.1       228.2       168.6       173.8  
Depletion, depreciation and amortization
    568.0       556.3       374.3       202.8       209.5  
Impairment of long-lived assets(c)
    .6       39.7                    
Exploration and abandonments
    266.8       180.7       131.2       86.6       122.6  
General and administrative
    124.6       80.3       60.3       48.2       36.8  
Accretion of discount on asset retirement obligations
    7.9       8.2       5.0              
Interest
    127.8       103.4       91.4       95.8       131.9  
Other(d)
    112.8       33.7       21.3       39.6       43.4  
                                         
      1,657.8       1,318.4       911.7       641.6       718.0  
                                         
Income from continuing operations before income taxes and cumulative effect of change in accounting principle
    715.5       463.1       310.4       20.6       92.1  
Income tax benefit (provision)(e)
    (291.7 )     (164.1 )     67.4       (5.1 )     (4.0 )
                                         
Income from continuing operations before cumulative effect of change in accounting principle
    423.8       299.0       377.8       15.5       88.1  
Income from discontinued operations, net of tax(f)
    110.8       13.9       17.4       11.2       11.9  
                                         
Income before cumulative effect of change in accounting principle
    534.6       312.9       395.2       26.7       100.0  
Cumulative effect of change in accounting principle, net of tax(c)
                15.4              
                                         
Net income
  $ 534.6     $ 312.9     $ 410.6     $ 26.7     $ 100.0  
                                         
Income from continuing operations before cumulative effect of change in accounting principle per share:
                                       
Basic
  $ 3.09     $ 2.39     $ 3.22     $ .14     $ .89  
                                         
Diluted
  $ 3.02     $ 2.35     $ 3.19     $ .14     $ .88  
                                         
Net income per share:
                                       
Basic
  $ 3.90     $ 2.50     $ 3.50     $ .24     $ 1.01  
                                         
Diluted
  $ 3.80     $ 2.46     $ 3.46     $ .23     $ 1.00  
                                         
Weighted average shares outstanding:
                                       
Basic
    137.1       125.2       117.2       112.5       98.5  
                                         
Diluted
    141.4       127.5       118.5       114.3       99.7  
                                         
Dividends declared per share
  $ .22     $ .20     $     $     $  
                                         
Balance Sheet Data (as of December 31):
                                       
Total assets
  $ 7,329.2     $ 6,733.5     $ 3,951.6     $ 3,455.1     $ 3,271.1  
Long-term obligations and minority interests
  $ 4,078.8     $ 3,357.2     $ 1,762.0     $ 1,805.6     $ 1,757.5  
Total stockholders’ equity
  $ 2,217.1     $ 2,831.8     $ 1,759.8     $ 1,374.9     $ 1,285.4  


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(a) Certain amounts for periods prior to January 1, 2005 have been reclassified (i) in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) to reflect the results of operations of certain oil and gas properties disposed of during 2005 as discontinued operations, rather than as a component of continuing operations. See Notes B and V of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional discussion and (ii) to conform with the current year presentation.
 
(b) Interest and other income in 2005 and 2004 include $73.6 million and $7.6 million, respectively, of income associated with various business interruption insurance claims. See Note U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”.
 
(c) During 2005 and 2004, the Company recorded $.6 million and $39.7 million of impairment charges for its Gabonese Olowi field as development of the discovery was canceled due to significant increases in projected field development costs. See Note S of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”.
 
(d) Other expense for 2005, 2003, 2002 and 2001 includes losses on the early extinguishment of debt of $26.0 million, $1.5 million, $22.3 million and $3.8 million, respectively. Other expense for 2005, 2004, 2003 and 2002 includes $54.8 million, $4.3 million, $2.8 million and $1.7 million, respectively, of derivative ineffectiveness charges. Other expense for 2001 includes noncash mark-to-market charges for changes in the fair values of non-hedge financial instruments of $11.5 million. See Note O of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”.
 
(e) Income tax benefit for 2003 includes a $197.7 million adjustment to reduce United States deferred tax asset valuation allowances. See Note P of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”.
 
(f) Cumulative effect of change in accounting principle for 2003 relates to the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”) on January 1, 2003. See Notes B and L of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”.


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ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Strategic Initiatives
 
During September 2005, the Company announced that the Board approved the following strategic initiatives to enhance shareholder value and investment returns:
 
  •  Approval of a $1 billion share repurchase program, $650 million of which was immediately initiated and substantially completed during 2005. The remaining $350 million is subject to the completion of the planned deepwater Gulf of Mexico and Argentine divestments discussed below.
  •  A plan to divest the Company’s assets in the Tierra del Fuego area in southern Argentina. The plan was later broadened to include entertaining offers for a complete sale of all of the Company’s Argentine assets. During January 2006, Pioneer entered into an agreement to sell its assets in Argentina for $675 million.
  •  A plan to divest the Company’s assets in the deepwater Gulf of Mexico. Bids to purchase the properties were received in January 2006 and the Company is currently engaged in negotiations for the sale of these assets. No assurance can be given that a sale can be completed on terms acceptable to the Company.
 
The implementation of the Board’s strategic initiatives is allowing Pioneer to (i) allocate and focus its investment capital more heavily towards predictable oil and gas basins in North America that have delivered relatively strong and consistent growth and (ii) lower its risk profile by expanding North American unconventional resource investments while reducing exploration expenditures.
 
The divestiture of the Company’s Argentine oil and gas assets will allow the Company to leverage the current commodity price environment to monetize and exit operations in an area that has become characterized by lower operating margins, government-controlled pricing and modest production growth opportunities. The divestiture of the Company’s deepwater Gulf of Mexico assets, if successful, will also allow the Company to monetize and exit operations in an area that is characterized by escalating drilling and operating costs and relatively high exploration risk and production volatility.
 
Financial and Operating Performance
 
Pioneer’s financial and operating performance for the year ended December 31, 2005 included the following highlights:
 
  •  Average daily sales volumes on a BOE basis decreased one percent in 2005 as compared to 2004.
  •  Oil and gas revenues increased 25 percent in 2005 as compared to 2004 primarily as a result of increases in worldwide oil and Argentine and North American gas prices.
  •  Interest and other income increased by $83.0 million in 2005 as compared to 2004, primarily due to $73.6 million of business interruption insurance claims related to (a) the Hurricane Ivan disruptions and (b) the Fain gas plant fire.
  •  Other expense increased by $79.1 million in 2005 as compared to 2004, primarily due to increases of $50.5 million and $26.0 million in losses associated with commodity hedge ineffectiveness and debt extinguishments, respectively.
  •  Income from continuing operations before income taxes and cumulative effect of change in accounting principle increased by 54 percent to $715.5 million in 2005 from $463.1 million in 2004.
  •  Net income increased to $534.6 million ($3.80 per diluted share) for 2005, as compared to $312.9 million ($2.46 per diluted share) for 2004.
  •  The Company recognized income from discontinued operations of $110.8 million ($.78 per diluted share) during 2005 attributable to the sale of certain Gulf of Mexico shelf and Canadian properties.
  •  Outstanding debt decreased by $327.5 million, or 14 percent, as of December 31, 2005 as compared to debt outstanding as of December 31, 2004.
  •  Net cash provided by operating activities increased by 23 percent to a record $1.3 billion in 2005 as compared to $1.1 billion in 2004.
  •  The Company declared $.22 per share of common dividends during 2005.
  •  The Company repurchased 20 million shares of the Company’s common stock for $949.3 million during 2005.


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  •  The Company sold three VPPs for net proceeds of $892.6 million.
  •  Total proved reserves of 986.7 MMBOE at December 31, 2005.
 
Current Events
 
Argentina divestiture.  During September 2005, the Company announced that it would pursue the sale of its nonoperated assets in Tierra del Fuego. During the Tierra del Fuego sales process, several prospective buyers indicated that they could enhance their value for a transaction in Argentina if it included all of Pioneer’s assets. The Company decided that if a buyer presented an attractive offer for all of the Argentine assets, that it would consider exiting Argentina. On January 17, 2006, the Company announced signing an agreement with Apache Corporation to sell all of the Company’s interests in Argentina for $675 million (subject to normal closing adjustments). The transaction is expected to close during the latter part of the first quarter or in early April of 2006. The results of operations from these assets will be reflected as discontinued operations in the Company’s future financial statements if the sale is closed.
 
Oooguruk development.  In February 2006, the Company announced that it has approved and is commencing the development of the Oooguruk field in shallow waters off the North Slope of Alaska. The Company has a 70 percent working interest in the field. Following the construction of a gravel drilling and production site during the 2006, a subsea flowline and facilities will be installed during 2007 to carry produced liquids to existing onshore processing facilities at the Kuparuk River Unit. Between 2007 and 2009, Pioneer plans to drill approximately 40 horizontal wells in the Oooguruk field. Total gross capital invested, including projected drilling and facility costs, is expected to range from $450 million to $525 million. First production from these wells is expected to begin in 2008.
 
South Coast Gas project.  In December 2005, the Company announced the final approvals with its partner in the South Coast Gas project. Pioneer has a 45 percent working interest in the project. The project will include subsea tie-back of gas from the Sable field and six additional gas accumulations to the existing production facilities on the F-A platform for transportation via existing pipelines to a GTL plant. The Company has signed a contract for the sale of its share of gas and condensate to the GTL plant. Production is expected to begin during the second half of 2007 and increase to an average of approximately 100 MMcf per day of gas and 3,000 Bbls per day of condensate over the initial phase of the project through 2012. Development drilling related to the project is expected to commence in the first quarter of 2006.
 
Deepwater Gulf of Mexico divestiture.  During September 2005, the Company announced its plans to pursue the divestment of its deepwater Gulf of Mexico assets to reduce the exploration risk and production volatility that have been associated with these properties. The deepwater Gulf of Mexico bid process has been completed and the Company is currently engaged in negotiations for the sale of these assets. No assurance can be given that a sale can be completed on terms acceptable to the Company. The results of operations from these assets will be reflected as discontinued operations in the Company’s future financial statements if the divestiture is completed.
 
Acquisitions
 
Evergreen merger.  On September 28, 2004, Pioneer completed a merger with Evergreen. Pioneer acquired the common stock of Evergreen for a total purchase price of approximately $1.8 billion, which was comprised of cash and Pioneer common stock. At the merger date, Evergreen’s proved reserves were approximately 262 MMBOE. Evergreen was primarily engaged in the production, development, exploration and acquisition of North American unconventional gas and was one of the leading developers of CBM reserves in the United States. Evergreen’s operations were principally focused on developing and expanding its CBM gas field located in the Raton Basin in southern Colorado. Evergreen also had operations in the Piceance Basin in western Colorado, the Uinta Basin in eastern Utah and the Western Canada Sedimentary Basin.
 
Permian Basin and Onshore Gulf Coast areas.  In July 2005, the Company completed the purchase of approximately 70 MMBOE of substantially undeveloped proved oil reserves in the United States core areas of the Permian Basin and South Texas for $176.9 million. The assets acquired provide an estimated 800 undrilled well locations.


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Divestitures
 
Volumetric production payments.  During January 2005, the Company sold two percent of its total proved reserves, or 20.5 MMBOE of proved reserves in the Hugoton and Spraberry fields, by means of two VPPs for net proceeds of $592.3 million, including the assignment of the Company’s obligations under certain derivative hedge agreements.
 
During April 2005, the Company sold less than one percent of its total proved reserves, or 7.3 MMBOE of proved reserves in the Spraberry field, by means of a VPP for net proceeds of $300.3 million, including the value attributable to certain derivative hedge agreements assigned to the buyer of the April VPP.
 
The Company’s VPPs represent limited-term overriding royalty interests in oil and gas reserves which: (i) entitle the purchaser to receive production volumes over a period of time from specific lease interests; (ii) are free and clear of all associated future production costs and capital expenditures; (iii) are nonrecourse to the Company (i.e., the purchaser’s only recourse is to the assets acquired); (iv) transfers title of the assets to the purchaser and (v) allows the Company to retain the assets after the VPPs volumetric quantities have been delivered.
 
Canada and Gulf of Mexico.  During May 2005, the Company sold all of its interests in the Martin Creek and Conroy Black areas of northeast British Columbia and the Lookout Butte area of southern Alberta for net proceeds of $197.2 million, resulting in a gain of $138.3 million. During August 2005, the Company sold all of its interests in certain oil and gas properties on the shelf of the Gulf of Mexico for net proceeds of $59.1 million, resulting in a gain of $27.7 million. The historic results of operations of these properties have been removed from the Company’s reported income from continuing operations and are included, together with the gains from the divestitures, in income from discontinuing operations, net of taxes.
 
Gabon divestiture.  In October 2005, the Company closed the sale of the shares in a Gabonese subsidiary that owns the interest in the Olowi block for $47.9 million of net proceeds. A gain was recognized during the fourth quarter of 2005 of $47.5 million with no associated income tax effect either in Gabon or the United States. In addition, Pioneer retains the potential, under certain circumstances, to receive additional payments for production from deeper reservoirs discovered on the block.
 
2006 Outlook and Activities
 
Commodity prices.  World oil prices increased during the year ended December 31, 2005 in response to continued demand growth in Asian economies, hurricane disruptions in the Gulf of Mexico, political unrest and supply disruptions in Middle East and Venezuela and other supply and demand factors. North American gas prices also increased during 2005 in response to continued strong demand fundamentals while supply uncertainties still remain. The Company’s outlook for 2006 commodity prices continues to be cautiously optimistic. Significant factors that will impact 2006 commodity prices include developments in Iraq, Iran and other Middle East countries, the extent to which members of the OPEC and other oil exporting nations are able to manage oil supply through export quotas and variations in key North American gas supply and demand indicators. Pioneer will continue to strategically hedge oil and gas price risk to mitigate the impact of price volatility on its oil, NGL and gas revenues.
 
See Note J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s commodity hedge positions at December 31, 2005. Also see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for disclosures about the Company’s commodity related derivative financial instruments.
 
Preliminary 2006 capital budget.  In certain of its prior Annual Reports on Form 10-K, the Company has provided detailed information on its next year capital allocation and first quarter guidance with respect to production costs and expenses. As a result of the uncertainty surrounding the Company’s proposed divestitures of its Argentine and deepwater Gulf of Mexico assets, the Company is presently unable to provide similar information for 2006.
 
The Company has prepared a preliminary capital budget that does not include capital for its Argentine assets but does include limited capital for the Company’s deepwater Gulf of Mexico assets. The preliminary budget is approximately $1.3 billion and includes plans to drill 1,000 to 1,100 wells. The Company’s preliminary 2006 capital


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budget is heavily focused on development and extension drilling, including funding for the recently sanctioned Oooguruk and South Coast gas projects. Less than 20 percent of the preliminary 2006 capital budget is for exploration activities. The Company’s final allocation of capital during 2006 is subject to the approval of the Board and is dependent on the outcome of the planned divestitures. Accordingly, the final budget may differ materially from the preliminary budget.
 
Results of Operations
 
Oil and gas revenues.  Revenues from oil and gas operations totaled $2.2 billion, $1.8 billion and $1.2 billion during 2005, 2004 and 2003, respectively. The revenue increase during 2005, as compared to 2004, was due to an 18 percent increase in oil prices, a 26 percent increase in NGL prices and a 32 percent increase in gas prices, including the effects of commodity price hedges, partially offset by a one percent decrease in average daily BOE sales volumes. The revenue increase from 2003 to 2004 was due to a 22 percent increase in average daily BOE sales volumes, a 24 percent increase in oil prices, a 32 percent increase in NGL prices and a 14 percent increase in gas prices, including the effects of commodity price hedges.
 
The following table provides average daily sales volumes from continuing operations, by geographic area and in total, for 2005, 2004 and 2003:
 
                         
    Year Ended December 31,  
    2005     2004     2003  
 
Oil (Bbls):
                       
United States
    25,943       24,700       22,509  
Argentina
    7,869       8,534       8,687  
Canada
    210       72       35  
Africa
    10,065       11,676       1,981  
                         
Worldwide
    44,087       44,982       33,212  
                         
NGLs (Bbls):
                       
United States
    17,402       19,678       20,306  
Argentina
    1,824       1,546       1,318  
Canada
    503       425       473  
                         
Worldwide
    19,729       21,649       22,097  
                         
Gas (Mcf):
                       
United States
    497,068       516,294       417,972  
Argentina
    137,032       121,654       94,128  
Canada
    36,427       25,606       26,779  
                         
Worldwide
    670,527       663,554       538,879  
                         
Total (BOE):
                       
United States
    126,191       130,428       112,476  
Argentina
    32,531       30,356       25,694  
Canada
    6,784       4,764       4,971  
Africa
    10,065       11,676       1,981  
                         
Worldwide
    175,571       177,224       145,122  
                         
 
Per BOE average daily production for 2005, as compared to 2004, increased by seven percent in Argentina and by 42 percent in Canada, while average daily sales volumes decreased by three percent in the United States and by 14 percent in Africa.


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Average daily sales volumes from continuing operations in the United States was slightly lower in 2005 as compared to 2004 principally due to declining production in the Gulf of Mexico, asset divestitures and downtime at the Fain gas plant offset by a full year of production from the properties acquired in the Evergreen merger.
 
Argentine average daily sales volumes increased as a result of successful development drilling and increased market demand during Argentina’s summer season. The Company has increased its level of capital expenditures in Argentina as the stability of the Argentine peso and the general economic outlook for Argentina has improved and gas prices have increased.
 
Canadian average daily sales volumes from continuing operations increased due to new production from Canadian properties acquired in the Evergreen merger and production from new wells drilled during 2005.
 
Production is down in South Africa due to normal production declines and timing of oil shipments, partially offset by continued growth in Tunisia production.
 
Per BOE average daily production for 2004, as compared to 2003, increased by 16 percent in the United States, increased by 18 percent in Argentina, decreased by four percent in Canada and the Company realized first production from South Africa and Tunisia during 2003. The increased production was principally attributable to (i) a full year of production from the Falcon area, (ii) new production being initiated from the Harrier, Raptor and Tomahawk fields in the Falcon area and at Devils Tower, (iii) fourth quarter production added from the Evergreen merger and (iv) oil sales having first been realized from the Company’s Tunisian and South African oil projects during August and October of 2003, respectively. Argentine oil and gas sales volumes increased during 2004 primarily due to incremental production volumes that resulted from the Company’s expanded drilling program and higher oil and gas demand during the summer season.
 
The following table provides average daily sales volumes from discontinued operations during 2005, 2004 and 2003:
 
                         
    Year Ended December 31,  
    2005     2004     2003  
 
Oil (Bbls):
                       
United States
    1,279       1,937       2,016  
Canada
    28       65       76  
                         
Worldwide
    1,307       2,002       2,092  
                         
NGLs (Bbls):
                       
United States
    65       60       32  
Canada
    112       492       433  
                         
Worldwide
    177       552       465  
                         
Gas (Mcf):
                       
United States
    4,136       5,545       5,041  
Canada
    6,489       16,261       14,890  
                         
Worldwide
    10,625       21,806       19,931  
                         
Total (BOE):
                       
United States
    2,033       2,921       2,888  
Canada
    1,221       3,267       2,991  
                         
Worldwide
    3,254       6,188       5,879  
                         


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The following table provides average reported prices from continuing operations, including the results of hedging activities, and average realized prices from continuing operations, excluding the results of hedging activities, by geographic area and in total, for 2005, 2004 and 2003:
 
                         
    Year Ended December 31,  
    2005     2004     2003  
 
Average reported prices:
                       
Oil (per Bbl):
                       
United States
  $ 31.09     $ 29.69     $ 25.09  
Argentina
  $ 36.88     $ 28.06     $ 25.62  
Canada
  $ 52.12     $ 48.37     $ 28.00  
Africa
  $ 53.00     $ 38.12     $ 29.52  
Worldwide
  $ 37.22     $ 31.60     $ 25.50  
NGL (per Bbl):
                       
United States
  $ 31.72     $ 25.05     $ 19.03  
Argentina
  $ 33.17     $ 29.91     $ 22.85  
Canada
  $ 45.79     $ 32.03     $ 24.30  
Worldwide
  $ 32.22     $ 25.54     $ 19.38  
Gas (per Mcf):
                       
United States
  $ 6.83     $ 5.14     $ 4.45  
Argentina
  $ .88     $ .66     $ .56  
Canada
  $ 7.67     $ 4.72     $ 4.65  
Worldwide
  $ 5.66     $ 4.30     $ 3.78  
Average realized prices:
                       
Oil (per Bbl):
                       
United States
  $ 54.05     $ 39.54     $ 29.52  
Argentina
  $ 36.88     $ 29.82     $ 26.31  
Canada
  $ 52.12     $ 48.37     $ 28.00  
Africa
  $ 53.00     $ 38.71     $ 30.07  
Worldwide
  $ 50.74     $ 37.49     $ 28.71  
NGL (per Bbl):
                       
United States
  $ 31.72     $ 25.05     $ 19.03  
Argentina
  $ 33.17     $ 29.91     $ 22.85  
Canada
  $ 45.79     $ 32.03     $ 24.30  
Worldwide
  $ 32.22     $ 25.54     $ 19.38  
Gas (per Mcf):
                       
United States
  $ 7.94     $ 5.71     $ 4.91  
Argentina
  $ .88     $ .66     $ .56  
Canada
  $ 7.67     $ 5.37     $ 4.79  
Worldwide
  $ 6.49     $ 4.78     $ 4.15  
 
Hedging activities.  The oil and gas prices that the Company reports are based on the market price received for the commodities adjusted by the results of the Company’s cash flow hedging activities. The Company utilizes commodity swap and collar contracts in order to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. During 2005, 2004 and 2003, the Company’s commodity price hedges decreased oil and gas revenues from continuing operations by $420.4 million, $211.9 million and $110.7 million, respectively. The effective portions of changes in the fair values of the


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Company’s commodity price hedges are deferred as increases or decreases to stockholders’ equity until the underlying hedged transaction occurs. Consequently, changes in the effective portions of commodity price hedges add volatility to the Company’s reported stockholders’ equity until the hedge derivative matures or is terminated. See Note J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information concerning the impact to oil and gas revenues during 2005, 2004 and 2003 from the Company’s hedging activities, the Company’s open hedge positions at December 31, 2005 and descriptions of the Company’s hedge commodity derivatives. Also see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional disclosures about the Company’s commodity related derivative financial instruments.
 
Subsequent to December 31, 2005, the Company reduced its oil and gas hedge positions by terminating the following swap and collar contracts: (i) 2,000 BPD of March through December 2006 oil swap contracts with a fixed price of $26.29 per Bbl; 1,000 BPD of calendar 2007 oil swap contracts with a fixed price of $31.00 per Bbl; 2,000 BPD of calendar 2008 oil swap contracts with a fixed price of $30.00 per Bbl; 2,000 BPD of March through December 2006 oil collar contracts having a floor price of $50.00 per Bbl and a ceiling price of $96.25 per Bbl; 2,500 BPD of calendar 2007 oil collar contracts having a floor price of $50.00 and a ceiling price of $91.18 per Bbl and (ii) 65,000 MMBtu per day of April through December 2006 gas collar contracts with a weighted average floor price per MMBtu of $6.74 and a weighted average ceiling price per MMBtu of $14.01. The aggregate value of the terminated oil and gas hedge contracts was a liability of $59.4 million on the dates of termination.
 
Argentina commodity prices.  During 2002, the Argentine government implemented a 20 percent tax on oil exports. In 2003, the Company exported approximately five percent of its Argentine oil production. Associated therewith, the Company incurred oil export taxes of $1.2 million for 2003. During 2004 and 2005, the Company did not export any of its Argentine oil production. The export tax has also had the effect of decreasing internal Argentine oil revenues (not only export revenues) by the taxes levied. The U.S. dollar equivalent value for domestic Argentine oil sales (now paid in pesos) has generally moved toward parity with the U.S. dollar-denominated export values, net of the export tax. The adverse impact of this tax has been partially offset by the net cost savings resulting from the devaluation of the peso on peso-denominated costs.
 
In January 2003, at the Argentine government’s request, oil producers and refiners agreed to cap amounts payable for certain domestic sales at $28.50 per Bbl, which remained in effect through April 2004. The producers and refiners further agreed that the difference between the actual price and the capped price would be payable once actual prices fall below the $28.50 cap. Subsequently the terms were modified such that while the $28.50 per Bbl payable cap was in place, the refiners would have no obligation to pay producers for sales values that exceeded $36.00 per Bbl. Initially, the refiners and producers also agreed to discount U.S. dollar-denominated oil prices at 90 percent prior to converting to pesos at the current exchange rate for the purpose of invoicing and settling oil sales to Argentine refiners. In May 2004, refiners and producers changed the discount percentage from 90 percent for all price levels to 86 percent if West Texas Intermediate (“WTI”) was equal to or less than $36 per Bbl and 80 percent if WTI exceeded $36 per Bbl. All the oil prices are adjusted for normal quality differentials prior to applying the discount.
 
In 2004, it appeared probable that the price of world oil would remain above the $28.50 cap for the foreseeable future. Given the uncertainty surrounding the timing of when Argentine producers could expect to collect balances outstanding from refiners, the Company ceased recognizing revenue and began recording any excess between the actual sales price pursuant to its oil sales contracts with Argentine refiners that were subject to the price stabilization agreement and the $28.50 price cap as deferred revenue in the balance sheet. The decision by Argentine oil producers and refiners to not renew the price stability agreement beyond April 30, 2004 does not terminate the obligation of refiners to reimburse producers for balances that accumulated from January 2003 through April 2004, if and when the price of WTI falls below $28.50.
 
In May 2004, the Argentine government increased the export tax from 20 percent to 25 percent. This tax is applied on the sales value after the tax, thus, the net effect of the 20 percent and 25 percent rates is 16.7 percent and 20 percent, respectively. In August 2004, the Argentine government further increased the export tax rates for oil exports. The export tax now escalates from the current 25 percent (20 percent effective rate) to a maximum rate of 45 percent (31 percent effective rate) of the realized value for exported Bbls as WTI prices per Bbl increase from


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less than $32.00 to $45.00 and above. The export tax is not deducted in the calculation of royalty payments and expires in February 2007. Given the number of governmental changes during 2005 affecting the realized price the Company receives for its oil sales, no specific predictions can be made about the future of oil prices in Argentina. However, in the short term, the Company expects Argentine oil realizations to be less than oil realizations in the United States.
 
As a result of the economic emergency law enacted by the Argentine government in January 2002, the Company’s gas prices, expressed in U.S. dollars, have also fallen in proportion to the devaluation of the Argentine peso since the end of 2001 due to the pesofication of contracts and freezing of gas prices at the wellhead required by that law. As a baseline, the Company’s 2001 realized Argentine gas price was $1.31 per Mcf as compared to $.88, $.66 and $.56 in 2005, 2004 and 2003, respectively.
 
The unfavorable gas price has acted to discourage gas development activities and increased gas demand. Without development of gas reserves in Argentina, supplies of gas in the country have declined, while demand for gas has been increasing due to the resurgence of the Argentine economy and the higher cost of alternative fuels. Briefly during 2004, gas exports to Chile were curtailed at the direction of the Argentine government. Argentina has also entered into an agreement to import gas from Bolivia at prices starting at approximately $2.00 per Mcf (at the border), including transportation costs. In May 2004, pursuant to a decree, the Argentine government approved measures to permit producers to renegotiate gas sales contracts, excluding those that could affect small residential customers, in accordance with scheduled price increases specified in the decree. The wellhead prices in the decree increased from a 2004 range of $.61 to $.78 per Mcf to a range of $.87 to $1.04 per Mcf after July 1, 2005, depending on the region where the gas is produced. No further gas price increases beyond July 2005 have occurred. Other than an expectation that gas prices will be permitted to increase gradually over time, as has already been demonstrated by the governing authorities, no specific predictions can be made about the future of gas prices in Argentina. However, the Company expects Argentine gas realizations to be less than gas realizations in the United States.
 
See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion of commodity prices in Argentina.
 
Interest and other income.  The Company recorded interest and other income totaling $97.1 million, $14.1 million and $12.3 during 2005, 2004 and 2003, respectively. The increase in interest and other income during 2005, as compared to 2004, is primarily attributable to the recognition of $73.6 million in business interruption insurance claims, of which $59.4 million relates to Hurricane Ivan and $14.2 million to the Fain plant fire. See Note M of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding interest and other income.
 
Gain on disposition of assets.  The Company recorded gains on disposition of assets of $60.5 million, $39,000 and $1.3 million during 2005, 2004 and 2003, respectively.
 
In 2005, the gain is primarily related to (a) the sale of the stock of a subsidiary that owned the interest in the Olowi block in Gabon, which resulted in a $47.5 million gain and (b) a $14 million insurance settlement on the Company’s East Cameron facility that was destroyed by Hurricane Rita, resulting in a $9.7 million gain.
 
During 2005 the Company also recognized gains on the sale of certain assets in Canada and the shelf of the Gulf of Mexico of approximately $166.1 million. However, pursuant to SFAS 144 the gain and the results of operations from these assets have been reclassified to discontinued operations.
 
The net cash proceeds from asset divestitures during 2005, 2004 and 2003 were used, together with net cash flows provided by operating activities, to fund additions to oil and gas properties and to reduce outstanding indebtedness. See Notes N and V of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding asset divestitures.
 
Oil and gas production costs.  The Company recorded production costs of $449.3 million, $316.1 million and $228.2 million during 2005, 2004 and 2003, 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 production taxes and ad valorem taxes are directly related to commodity price changes. Total production costs per BOE increased during 2005 by 44 percent as compared to 2004 primarily due to (i) an increase


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in production and ad valorem taxes as a result of higher commodity prices, (ii) higher Canadian gas transportation fees, (iii) the retention of operating costs related to VPP volumes sold (approximately $.19 per BOE, during 2005), (iv) new production added from the Evergreen merger which are relatively higher per BOE operating cost properties, (v) decreased production from the lower per BOE production cost deepwater Gulf of Mexico assets and (v) increases in equipment and service costs associated with rising commodity prices.
 
Total production costs per BOE increased during 2004 by 13 percent as compared to 2003. The increase in total production costs per BOE during 2004 as compared to 2003 was primarily attributable to increases in production volumes and a greater proportion of those volumes coming from the Sable oil field in South Africa, the Devils Tower oil and gas field in the deepwater Gulf of Mexico and, to a lesser extent, the new production added with the Evergreen merger which are higher operating cost properties.
 
The following tables provide the components of the Company’s total production costs per BOE from continuing operations and total production costs per BOE from continuing operations by geographic area for 2005, 2004 and 2003:
 
                         
    Year Ended December 31,  
    2005     2004     2003  
 
Lease operating expenses
  $ 5.07     $ 3.63     $ 3.14  
Taxes:
                       
Ad valorem
    .63       .43       .41  
Production
    .97       .61       .62  
Workover costs
    .34       .21       .14  
                         
Total production costs
  $  7.01     $  4.88     $ 4.31  
                         
 
                         
    Year Ended December 31,  
    2005     2004     2003  
 
United States
  $ 7.41     $ 4.87     $ 4.44  
Argentina
  $ 3.26     $ 2.99     $ 2.78  
Canada
  $ 14.83     $ 10.79     $ 9.21  
Africa
  $ 8.82     $ 7.37     $ 3.99  
Worldwide
  $ 7.01     $ 4.88     $ 4.31  
 
Depletion, depreciation and amortization expense.  The Company’s total depletion, depreciation and amortization (“DD&A”) expense was $8.86, $8.56 and $7.07 per BOE for 2005, 2004 and 2003, respectively. Depletion expense, the largest component of DD&A expense, was $8.53, $8.38 and $6.89 per BOE during 2005, 2004 and 2003, respectively. During 2005, the increase in per BOE depletion expense was primarily due to relatively higher per BOE cost basis Rocky Mountain area production acquired in the Evergreen merger and a higher depletion rate for the Hugoton and Spraberry fields as a result of the VPP volumes sold, partially offset by lower production from higher cost-basis Gulf of Mexico production. Additionally, the Company’s depletion expense per BOE (i) increased in Argentina due to downward reserve revisions associated with negative well performance and drilling results in its deep gas play in the Neuquen basin, (ii) increased in Tunisia due to the Company’s proved reserves being reduced as a result of the Company’s interest in the Adam block being reduced to 20 percent from 28 percent in accordance with the terms of the concession and (iii) decreased in South Africa as a result of upward reserve revisions attributable to better well performance.
 
During 2004, the increase in per BOE depletion expense was due to a greater proportion of the Company’s production being derived from higher cost-basis deepwater Gulf of Mexico and South African developments and downward revisions to proved reserves in Canada in 2003.


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The following table provides depletion expense per BOE from continuing operations by geographic area for 2005, 2004 and 2003:
 
                         
    Year Ended December 31,  
    2005     2004     2003  
 
United States
  $ 8.71     $ 8.62     $ 7.06  
Argentina
  $ 7.13     $ 5.56     $ 4.96  
Canada
  $ 12.71     $ 12.93     $ 11.42  
Africa
  $ 7.96     $ 11.19     $ 10.69  
Worldwide
  $ 8.53     $ 8.38     $ 6.89  
 
Impairment of oil and gas properties.  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 2005 and 2004, the Company recognized a noncash impairment charge of $.6 million and $39.7 million, respectively, to reduce the carrying value of its Gabonese Olowi field assets as development of the discovery was canceled. See “Critical Accounting Estimates” below and Notes B and S of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information pertaining to the Company’s accounting policies regarding assessments of impairment and the Gabonese Olowi field impairment, respectively.
 
Exploration, abandonments, geological and geophysical costs.  The following table provides the Company’s geological and geophysical costs, exploratory dry hole expense, lease abandonments and other exploration expense from continuing operations by geographic area for 2005, 2004 and 2003:
 
                                         
                      Africa
       
    United
                and
       
    States     Argentina     Canada     Other     Total  
    (In thousands)  
 
Year ended December 31, 2005:
                                       
Geological and geophysical
  $ 66,048     $ 6,603     $ 4,452     $ 34,353     $ 111,456  
Exploratory dry holes
    61,209       9,257       3,468       18,981       92,915  
Leasehold abandonments and other
    48,770       8,667       1,625       3,318       62,380  
                                         
    $ 176,027     $ 24,527     $ 9,545     $ 56,652     $ 266,751  
                                         
Year ended December 31, 2004:
                                       
Geological and geophysical
  $ 51,731     $ 11,718     $ 4,047     $ 14,833     $ 82,329  
Exploratory dry holes
    39,328       7,213       11,131       24,460       82,132  
Leasehold abandonments and other
    7,925       4,475       3,883       6       16,289  
                                         
    $ 98,984     $ 23,406     $ 19,061     $ 39,299     $ 180,750  
                                         
Year ended December 31, 2003:
                                       
Geological and geophysical
  $ 40,783     $ 7,689     $ 4,426     $ 3,903     $ 56,801  
Exploratory dry holes
    27,015       2,672       9,868       20,250       59,805  
Leasehold abandonments and other
    4,941       7,715       1,822       108       14,586  
                                         
    $ 72,739     $ 18,076     $ 16,116     $ 24,261     $ 131,192  
                                         
 
Significant components of the Company’s dry hole expense during 2005 included $21.2 related to certain suspended Alaskan well costs, $16.7 million associated with an unsuccessful well in the Falcon Corridor, $9.5 million associated with an unsuccessful Nigerian well, $3.5 million attributable to an unsuccessful well on the Company’s El Hamra permit in Tunisia, $5.1 million attributable to an unsuccessful suspended well in the Company’s Anaguid permit in Tunisia and various other exploratory wells. The United States leasehold abandonments and other costs during the year ended December 31, 2005 include a $39.8 million increase in East Cameron abandonment obligations that resulted from hurricane damage. During 2005, the Company


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completed and evaluated 180 exploration/extension wells, 149 of which were successfully completed as discoveries.
 
Significant components of the Company’s dry hole expense during 2004 included $27.7 million and $10.5 million on the Company’s deepwater Gulf of Mexico Juno and Myrtle Beach prospects, respectively, $19.0 million on the Company’s Gabonese Olowi prospect and $5.8 million on the Company’s Bravo prospect offshore Equatorial Guinea. During 2004, the Company completed and evaluated 103 exploration/extension wells, 58 of which were successfully completed as discoveries.
 
General and administrative expense.  General and administrative expense totaled $124.6 million ($1.94 per BOE), $80.3 million ($1.24 per BOE) and $60.3 million ($1.14 per BOE) during 2005, 2004 and 2003, respectively. The increase in general and administrative expense during 2005, as compared to 2004, was primarily due to increases in administrative staff, including staff increases associated with the Evergreen merger, and performance-related compensation costs including the amortization of restricted stock awarded to officers, directors and employees during 2005.
 
The increase in general and administrative expense during 2004, as compared to 2003, was primarily due to increases in administrative staff, including staff increases associated with the Evergreen merger, and performance-related compensation costs including the amortization of restricted stock awarded to officers, directors and employees during 2004.
 
Interest expense.  Interest expense was $127.8 million, $103.4 million and $91.4 million during 2005, 2004 and 2003, respectively. The weighted average interest rate on the Company’s indebtedness for the year ended December 31, 2005 was 6.5 percent, as compared to 5.4 percent and 5.3 percent for the years ended December 31, 2004 and 2003, respectively, including the effects of interest rate derivatives. The increase in interest expense for 2005 as compared to 2004 was primarily due to increased average borrowings under the Company’s lines of credit, primarily as a result of the cash portion of the consideration paid in the Evergreen merger and $949.3 million of stock repurchases completed during 2005, a $17.3 million decrease in the amortization of interest rate hedge gains, the assumption of $300 million of notes in connection with the Evergreen merger and higher interest rates in 2005.
 
The increase in interest expense for 2004 as compared to 2003 was primarily due to a $7.9 million decrease in interest rate hedge gains, a $3.4 million decrease in capitalized interest as the Company completed its major development projects in the Gulf of Mexico and South Africa, increased borrowings under the Company’s lines of credit, primarily as a result of the Evergreen merger, and the assumption of $300 million of notes in connection with the Evergreen merger.
 
See Note F of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information about the Company’s long-term debt and interest expense.
 
Other expenses.  Other expenses were $112.8 million during 2005, as compared to $33.7 million during 2004 and $21.3 million during 2003. The increase in other expenses during 2005, as compared to 2004, is primarily attributable to a $26.5 million loss on the redemption and tender of portions of the Company’s senior notes, a $50.5 million increase in hedge ineffectiveness and a $3.1 million increase in amortization of noncompete agreements associated with the Evergreen merger. The increase in other expense for 2004 as compared to 2003 was primarily due to an increase in contingency accrual adjustments of $11.8 million. See Note O of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a detailed description of the components included in other expenses.
 
Income tax benefits (provisions).  The Company recognized income tax provisions on continuing operations of $291.7 million and $164.2 million during 2005 and 2004, respectively, and income tax benefits on continuing operations of $67.4 million during 2003. The 2003 deferred United States federal, state and local tax benefits include a $197.7 million benefit from the reversal of the Company’s valuation allowances against United States deferred tax assets.


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The Company’s effective tax rate of 40.8 percent for the year ended December 31, 2005 differs from the combined United States federal and state statutory rate of approximately 36.5 percent primarily due to:
 
  •  The second quarter reversal of the $26.9 million tax benefit recorded in 2004 as a result of the cancellation of the development of the Olowi block and the Company’s decision to exit Gabon. The Company reversed the tax benefit as a result of signing an agreement in June 2005 to sell its shares in the subsidiary that owns the interest in the Olowi block which made it more likely than not that the Company would not realize the originally recorded tax benefit,
 
  •  The Company recognized a gain of approximately $47.5 million in the fourth quarter of 2005 relating to the sale of shares in a subsidiary that owns the interest in the Olowi Block located in Gabon. There is no associated income tax effect either in Gabon or the United States associated with the gain, which partially offsets the effects of the previous item,
 
  •  Recording $6.8 million of taxes associated with the repatriation of foreign earnings pursuant to the American Jobs Creation Act of 2004 (“AJCA”),
 
  •  Expenses for unsuccessful well costs in foreign locations where the Company receives no expected income tax benefits,
 
  •  Foreign tax rate differentials and
 
  •  Foreign statutes that differ from those in the United States.
 
See “Critical Accounting Estimates” below and Note P of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s tax position.
 
Discontinued operations.  The Company recognized income from discontinued operations of $110.8 million during 2005, as compared to $13.9 million during 2004 and $17.4 million during 2003. During 2005, the Company sold its interests in (a) the Martin Creek, Conroy Black and Lookout Butte areas in Canada for net proceeds of $197.2 million, resulting in a gain of $138.3 million and (b) certain assets on the shelf of the Gulf of Mexico for net proceeds of $59.1 million, resulting in a gain of $27.7 million. In 2005, the Company recognized an income tax provision of $73.1 million associated with these divestitures. Pursuant to SFAS 144, the gain and the results of operations from these assets have been reclassified to discontinued operations. See Note V of Notes to Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data” for additional data on discontinued operations.
 
The Company’s high effective tax rate associated with discontinued operations during 2005 (39.7 percent) was primarily due to:
 
  •  A United States deferred tax provision of $17.1 million being triggered by the gain recorded on the Canadian divestiture. The Canadian gain caused the recharacterization of Argentine dividend income from prior years that was previously offset by historical Canadian losses,
 
  •  Cash taxes of $2.5 million associated with the repatriation of foreign earnings under the provisions of the AJCA and
 
  •  A decrease in the Canadian valuation allowance of $13.4 million, which partially offset the above two items. The Canadian divestiture utilized a substantial portion of the Company’s Canadian tax pools. Consequently, the Company reassessed the likelihood that the remaining Canadian tax attributes will be utilized and determined it is now more likely than not that it will be able to utilize more of its tax pools than previously expected.
 
For years prior to the Canadian divestiture, the Company’s discontinued operations reflect no Canadian tax provisions due to the Company having maintained a valuation allowance related to its Canadian deferred tax assets. During those prior years, management’s expectation was that it was likely that the Company would not realize its Canadian deferred tax assets. Therefore, in accordance with GAAP, portions of the Canadian valuation allowance were released only to the extent that Canadian income was recorded, thereby offsetting any tax provisions.


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The Company’s effective tax rate for United States discontinued operations during 2005, 2004 and 2003 was approximately 36.5 percent.
 
Cumulative effect of change in accounting principle.  The Company adopted the provisions of SFAS 143 on January 1, 2003 and recognized a $15.4 million benefit from the cumulative effect of change in accounting principle, net of $1.3 million of deferred income taxes.
 
Capital Commitments, Capital Resources and Liquidity
 
Capital commitments.  The Company’s primary needs for cash are for exploration, development and acquisition of oil and gas properties, repayment of contractual obligations and working capital obligations. Funding for exploration, development and acquisition of oil and gas properties and repayment of contractual obligations may be provided by any combination of internally-generated cash flow, proceeds from the disposition of nonstrategic assets or alternative financing sources as discussed in “Capital resources” below. Generally, funding for the Company’s working capital obligations is provided by internally-generated cash flows.
 
Payments for acquisitions, net of cash acquired.  In 2004, the Company paid $880.4 million of cash, net of $12.1 million of cash acquired, to complete the Evergreen merger. As noted above, the Company also assumed $300 million principal amount of Evergreen notes and other current and noncurrent obligations associated with the Evergreen merger. As is further discussed in “Financing activities” below, and in Notes C and F of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”, the Company financed the cash costs utilizing credit facilities in place at the time of the merger.
 
Oil and gas properties.  The Company’s cash expenditures for additions to oil and gas properties during 2005, 2004 and 2003 totaled $1.1 billion, $562.9 million and $662.6 million, respectively. The Company’s 2005, 2004 and 2003 expenditures for additions to oil and gas properties were internally funded by $1.3 billion, $1.1 billion and $738.1 million, respectively, of net cash provided by operating activities.
 
The Company strives to maintain its indebtedness at reasonable levels in order to provide sufficient financial flexibility to take advantage of future opportunities. The Company’s preliminary capital budget for 2006 is expected to be approximately $1.3 billion. The Company believes that proceeds from asset divestitures and net cash provided by operating activities during 2006, based on the current price environment, will be sufficient to fund the 2006 capital expenditures budget.
 
Off-balance sheet arrangements.  From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of December 31, 2005, the material off-balance sheet arrangements and transactions that the Company has entered into include (i) undrawn letters of credit, (ii) operating lease agreements, (iii) drilling commitments, (iv) VPP obligations (to physically deliver volumes and pay related lease operating expenses in the future) and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable such as derivative contracts that are sensitive to future changes in commodity prices and gas transportation commitments. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. See “Contractual obligations” below for more information regarding the Company’s off-balance sheet arrangements.
 
Contractual obligations.  The Company’s contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, other liabilities, transportation commitments and VPP obligations.


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The following table summarizes by period the payments due by the Company for contractual obligations estimated as of December 31, 2005:
 
                                 
    Payments Due by Year  
          2007 and
    2009 and
       
    2006     2008     2010     Thereafter  
    (In thousands)  
 
Long-term debt(a)
  $     $ 382,075     $ 900,000     $ 882,985  
Operating leases(b)
    57,931       70,686       29,546       5,642  
Drilling commitments(c)
    172,354       118,497       5,977        
Derivative obligations(d)
    318,852       430,495              
Other liabilities(e)
    114,942       63,796       19,415       64,503  
Transportation commitments(f)
    67,222       136,876       134,614       234,986  
VPP obligations(g)
    190,327       339,370       238,121       87,020  
                                 
    $ 921,628     $ 1,541,795     $ 1,327,673     $ 1,275,136  
                                 
 
 
(a) See Note F of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”. The amounts included in the table above represent principal maturities only.
 
(b) See Note I of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”.
 
(c) Drilling commitments represent future minimum expenditure commitments under contracts that the Company was a party to on December 31, 2005 for drilling rig services and well commitments. During February 2006, the Company entered into a drilling contract under which the Company is obligated to expend $27.4 million during 2007.
 
(d) Derivative obligations represent net liabilities for oil and gas commodity derivatives that were valued as of December 31, 2005. These liabilities include $.9 million of current liabilities that are fixed in amount and are not subject to continuing market risk. The ultimate settlement amounts of the remaining portions of the Company’s derivative obligations are unknown because they are subject to continuing market risk. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s derivative obligations.
 
(e) The Company’s other liabilities represent current and noncurrent other liabilities that are comprised of benefit obligations, litigation and environmental contingencies, asset retirement obligations and other obligations for which neither the ultimate settlement amounts nor their timings can be precisely determined in advance. See Notes H, I and L of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s post retirement benefit obligations, litigation contingencies and asset retirement obligations, respectively.
 
(f) Transportation commitments represent estimated transportation fees on gas throughput commitments. See Note I of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s transportation commitments.
 
(g) These amounts represent the amortization of the deferred revenue associated with the VPPs. The Company’s ongoing obligation is to deliver the specified volumes sold under the VPPs free and clear of all associated production costs and capital expenditures. See Note T of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”.
 
Environmental contingency.  A subsidiary of the Company has been notified by a letter from the Texas Commission on Environmental Quality (“TCEQ”) dated August 24, 2005 that the TCEQ considers the subsidiary to be a potentially responsible party with respect to the Dorchester Refining Company State Superfund Site located in Mount Pleasant, Texas. The subsidiary, which was acquired by the Company in 1991, owned a refinery located at the Mount Pleasant site from 1977 until 1984. According to the TCEQ, this refinery was responsible for releases of hazardous substances into the environment. The Company does not know the nature and extent of the alleged


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contamination, the potential costs of remediation, or the portion, if any, of such costs that may be allocable to the Company’s subsidiary. However, based on the limited information currently available and assessed regarding this matter, the Company has no reason to believe that it may have a material adverse effect on its future financial condition, results of operations or liquidity. See Note I of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding this matter as well as other environmental and legal contingencies involving the Company.
 
Capital resources.  The Company’s primary capital resources are net cash provided by operating activities, proceeds from financing activities and proceeds from sales of nonstrategic assets. The Company expects that these resources will be sufficient to fund its capital commitments during 2006 and for the foreseeable future.
 
Asset divestitures.  During May 2005, the Company sold all of its interests in the Martin Creek, Conroy Black and Lookout Butte oil and gas properties in Canada for net proceeds of $197.2 million, resulting in a gain of $138.3 million. During August 2005, the Company sold all of its interests in certain oil and gas properties on the shelf of the Gulf of Mexico for net proceeds of $59.1 million, resulting in a gain of $27.7 million. During October 2005, the Company sold all of its shares in a subsidiary that owns the interest in the Olowi block in Gabon for net proceeds of $47.9 million, resulting in a gain of $47.5 million. The net cash proceeds from these divestitures were used to reduce outstanding indebtedness.
 
During January 2005, the Company sold two percent of its total proved reserves, or 20.5 MMBOE of proved reserves, by means of two VPPs for net proceeds of $592.3 million, including the assignment of the Company’s obligations under certain derivative hedge agreements. Proceeds from the VPPs were initially used to reduce outstanding indebtedness.
 
During April 2005, the Company sold less than one percent of its total proved reserves, or 7.3 MMBOE of proved reserves, by means of another VPP for net proceeds of $300.3 million, including the assignment of the Company’s obligations under certain derivative hedge agreements. Proceeds from the VPP were initially used to reduce outstanding indebtedness.
 
See Note T of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s VPPs.
 
Operating activities.  Net cash provided by operating activities during 2005, 2004 and 2003 was $1.3 billion, $1.1 billion and $738.1 million, respectively. The increase in net cash provided by operating activities in 2005, as compared to that of 2004, was primarily due to higher commodity prices. The increase in net cash provided by operating activities in 2004, as compared to that of 2003, was primarily due to increased production volumes and higher commodity prices.
 
Investing activities.  Net cash provided by investing activities during 2005 was $84.7 million, as compared to net cash used in investing activities during 2004 and 2003 of $1.5 billion and $636.7 million, respectively. The decrease in net cash used in investing activities during 2005, as compared to 2004, was primarily due to (i) $1.2 billion in proceeds from asset divestitures in 2005 which included $892.6 million of net proceeds received from VPPs sold during 2005, (ii) $880.4 million of cash consideration paid in 2004 in connection with the Evergreen merger and (iii) offset by an increase of $560.4 million in additions to oil and gas properties. The increase in net cash used in investing activities during 2004 as compared to 2003 was primarily due to $880.4 million of cash consideration paid in the third quarter of 2004 in connection with the Evergreen merger. See “Results of Operations” above and Note N of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding asset divestitures.
 
Financing activities.  Net cash used in financing activities was $1.4 billion and $91.7 million during 2005 and 2003, respectively. Net cash provided by financing activities during 2004 was $414.3 million. During 2005, financing activities were comprised of $353.6 million of net principal repayments on long-term debt, $78.3 million of payments of other noncurrent liabilities, primarily comprised of cash settlements of acquired hedge obligations, $30.3 million of dividends paid and $949.3 million of treasury stock purchases, partially offset by $41.6 million of proceeds from the exercise of long-term incentive plan stock options and employee stock purchases. During 2004, financing activities were comprised of $553.4 million of net principal borrowings on long-term debt, $54.3 million of payments of other noncurrent liabilities, primarily comprised of settlements of fair value and acquired hedge


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obligations and other financial obligations, $26.6 million of dividends paid and $92.3 million of treasury stock purchases, partially offset by $35.1 million of proceeds from the exercise of long-term incentive plan stock options and employee stock purchases. During 2003, financing activities were comprised of $105.5 million of net principal payments on long-term debt, $14.1 million of payments of other noncurrent liabilities, $2.8 million of payments for deferred loan fees and $2.3 million of treasury stock purchases, partially offset by $33.0 million of proceeds from the exercise of long-term incentive plan stock options and employee stock purchases.
 
During April 2005, $131.0 million of the Company’s 87/8% senior notes due 2005 matured and were repaid. During 2005, the Company also redeemed the remaining $64.0 million and $16.2 million, respectively, of aggregate principal amount of its 95/8% senior notes due 2010 and its 7.50% senior notes due 2012. During September 2005, the Company accepted tenders to purchase $188.4 million in principal amount of the 5.875% senior notes due 2012 for $199.9 million. The Company utilized unused borrowing capacity under its line of credit to fund these financing activities.
 
During September 2005, the Company announced that the Board had approved a new share repurchase program authorizing the purchase of up to $1 billion of the Company’s common stock, $650 million of which was immediately initiated. As of December 31, 2005, the Company had expended $640.7 million of the $1 billion repurchase program through (i) open market purchases and (ii) a repurchase plan adopted by the Company conforming to the requirements of Rule 10b5-1 of the Exchange Act. The remaining $350 million is subject to the completion of the planned deepwater Gulf of Mexico and Argentine divestments. During 2005 and 2004, the Company expended a total of $949.3 million to acquire 20.0 million shares of treasury stock and $92.3 million to acquire 2.8 million shares of treasury stock, respectively.
 
During September 2005, the Company entered into an amended credit facility that provides for initial aggregate loan commitments of $1.5 billion and a five-year term (the “Amended Credit Agreement”). In connection with the funding of the Amended Credit Agreement on September 30, 2005, all amounts outstanding under a 364-day credit facility, which was established to fund the Evergreen purchase in September 2004, were retired and the 364-day credit facility terminated.
 
As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined by the Board.
 
Liquidity.  The Company’s principal source of short-term liquidity is the Amended Credit Agreement. There were $900 million of outstanding borrowings under the Amended Credit Agreement as of December 31, 2005. Including $80.3 million of undrawn and outstanding letters of credit under the Amended Credit Agreement, the Company had $519.7 million of unused borrowing capacity as of December 31, 2005.
 
The announced plans to divest the Company’s Argentine assets and deepwater Gulf of Mexico assets, if successful, will have a positive impact on Pioneer’s future liquidity. Proceeds from one or both of these planned divestitures may be used to (i) pay down existing borrowings on the Amended Credit Agreement, (ii) complete the $1 billion share repurchase, (iii) reduce existing obligations, (iv) fund capital commitments or (v) fund working capital needs. Also, the Company may decide to maintain a certain level of any proceeds in cash and investments for future liquidity purposes. There can be no assurances that the Company will successfully conclude the announced plans to divest the Argentine assets or deepwater Gulf of Mexico assets.
 
Debt ratings.  The Company receives debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investor Services, Inc. (“Moody’s”), which are subject to regular reviews. During the fourth quarter of 2005, S&P cut the Company’s corporate credit rating to BB+ with a stable outlook from BBB-. During January 2006, Moody’s cut the Company’s corporate credit rating to Ba1 with a negative outlook from Baa3. S&P and Moody’s consider many factors in determining the Company’s ratings including: production growth opportunities, liquidity, debt levels and asset and reserve mix. As a result of the downgrades, the interest rate and fees the Company pays on the Amended Credit Agreement have increased and additional debt covenant requirements under the Amended Credit Agreement were triggered. Subsequent to December 31, 2005, as a result of the Company’s downgrades by the rating agencies, the Company has issued or may be required to issue additional


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letters of credits of approximately $73 million pursuant to agreements that contain provisions with rating triggers. The individual downgrades are not expected to materially affect the Company’s financial position or liquidity, but could negatively impact the Company’s ability to obtain additional financing or the interest rate and fees associated with such additional financing.
 
Book capitalization and current ratio.  The Company’s book capitalization at December 31, 2005 was $4.3 billion, consisting of debt of $2.1 billion and stockholders’ equity of $2.2 billion. Consequently, the Company’s debt to book capitalization increased to 48 percent at December 31, 2005 from 46 percent at December 31, 2004. The Company’s ratio of current assets to current liabilities was .60 to 1.00 at December 31, 2005 as compared to .72 to 1.00 at December 31, 2004. The decline in the Company’s ratio of current assets to current liabilities was primarily due to its current derivative liabilities as a result of higher commodity prices and current deferred revenue as a result of the VPPs.
 
Critical Accounting Estimates
 
The Company prepares its consolidated financial statements for inclusion in this Report in accordance with GAAP. See Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a comprehensive discussion of the Company’s significant accounting policies. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. Following is a discussion of the Company’s most critical accounting estimates, judgments and uncertainties that are inherent in the Company’s application of GAAP.
 
Accounting for oil and gas producing activities.  The accounting for and disclosure of oil and gas producing activities requires the Company’s management to choose between GAAP alternatives and to make judgments about estimates of future uncertainties.
 
Asset retirement obligations.  The Company has significant obligations to remove tangible equipment and facilities and to restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
 
On January 1, 2003, the Company adopted the provisions of SFAS 143. SFAS 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets. SFAS 143, together with the related FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an Interpretation of FASB Statement No. 143” (“FIN 47”), requires the Company to record a separate liability for the discounted present value of the Company’s asset retirement obligations, with an offsetting increase to the related oil and gas properties on the balance sheet.
 
Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance. See Notes B and L of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s asset retirement obligations.
 
Successful efforts method of accounting.  The Company utilizes the successful efforts method of accounting for oil and gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that, during periods of active exploration, net assets and net income are more conservatively measured under the successful efforts method of accounting for oil and gas producing activities than under the full cost method. The critical difference between the successful efforts method of accounting and the full cost method is as follows: under the successful efforts method, exploratory dry holes and geological and geophysical exploration


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costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of depletion expense. During 2005, 2004 and 2003, the Company recognized exploration, abandonment, geological and geophysical expense from continuing operations of $266.8 million, $180.8 million and $131.2 million, respectively, under the successful efforts method.
 
Proved reserve estimates.  Estimates of the Company’s proved reserves included in this Report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:
 
  •  the quality and quantity of available data,
 
  •  the interpretation of that data,
 
  •  the accuracy of various mandated economic assumptions and
 
  •  the judgment of the persons preparing the estimate.
 
The Company’s proved reserve information included in this Report as of December 31, 2005, 2004 and 2003 was prepared by the Company’s engineers and audited by independent petroleum engineers with respect to the Company’s major properties. Estimates prepared by third parties may be higher or lower than those included herein.
 
Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.
 
It should not be assumed that the Standardized Measure included in this Report as of December 31, 2005 is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the Standardized Measure on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. See “Item 1A. Risk Factors” for additional information regarding estimates of reserves and future net revenues.
 
The Company’s estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which the Company records depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of the Company’s assessment of its oil and gas producing properties and goodwill for impairment.
 
Impairment of proved oil and gas properties.  The Company reviews its long-lived proved properties to be held and used whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon its outlook of future commodity prices and net cash flows that may be generated by the properties and if a significant downward revision has occurred to the estimated proved reserves. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated.
 
Impairment of unproved oil and gas properties.  Management periodically assesses unproved oil and gas properties for impairment, on a project-by-project basis. Management’s assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects impacts the amount and timing of impairment provisions, if any.
 
Suspended wells.  The Company suspends the costs of exploratory wells that discover hydrocarbons pending a final determination of the commercial potential of the oil and gas discovery. The ultimate disposition of these well costs is dependent on the results of future drilling activity and development decisions. If the Company decides not to pursue additional appraisal activities or development of these fields, the costs of these wells will be charged to exploration and abandonment expense.


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The Company generally does not carry the costs of drilling an exploratory well as an asset in its Consolidated Balance Sheets for more than one year following the completion of drilling unless the exploratory well finds oil and gas reserves in an area requiring a major capital expenditure and both of the following conditions are met:
 
(i) The well has found a sufficient quantity of reserves to justify its completion as a producing well.
 
(ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
 
Due to the capital intensive nature and the geographical location of certain Alaskan, deepwater Gulf of Mexico and foreign projects, it may take the Company longer than one year to evaluate the future potential of the exploration well and economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves or is noncommercial and is impaired. See Note D of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s suspended exploratory well costs.
 
Assessments of functional currencies.  Management determines the functional currencies of the Company’s subsidiaries based on an assessment of the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. The U.S. dollar is the functional currency of all of the Company’s international operations except Canada. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position.
 
Argentine economic and currency measures.  The accounting for and remeasurement of the Company’s Argentine balance sheets as of December 31, 2005 and 2004 reflect management’s assumptions regarding some uncertainties unique to Argentina’s current economic situation. The Argentine economic and political situation continues to evolve and the Argentine government may enact future regulations or policies that, when finalized and adopted, may materially impact, among other items, (i) the realized prices the Company receives for the commodities it produces and sells; (ii) the timing of repatriations of excess cash flow to the Company’s corporate headquarters in the United States; (iii) the Company’s asset valuations; and (iv) peso-denominated monetary assets and liabilities. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a description of the assumptions utilized in the preparation of these financial statements.
 
Deferred tax asset valuation allowances.  The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that its deferred tax assets will be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and reassesses the likelihood that the Company’s net operating loss carryforwards and other deferred tax attributes in each jurisdiction will be utilized prior to their expiration. There can be no assurances that facts and circumstances will not materially change and require the Company to establish deferred tax asset valuation allowances in certain jurisdictions in a future period. As of December 31, 2005, the Company does not believe there is sufficient positive evidence to reverse its valuation allowances related to certain foreign tax jurisdictions.
 
Goodwill impairment.  The Company reviews its goodwill for impairment at least annually. This requires the Company to estimate the fair value of the assets and liabilities of the reporting units that have goodwill. There is considerable judgment involved in estimating fair values, particularly proved reserve estimates as described above. See Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.
 
Litigation and environmental contingencies.  The Company makes judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount of damages. Similarly, environmental remediation liabilities are


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subject to change because of changes in laws, regulations, additional information obtained relating to the extent and nature of site contamination and improvements in technology. Under GAAP, a liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimated. See Note I of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s commitments and contingencies.
 
New Accounting Pronouncements
 
The following discussions provide information about new accounting pronouncements that have been issued by the Financial Accounting Standards Board (“FASB”):
 
SFAS 123(R).  In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”), which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). SFAS 123(R) supersedes Accounting Principles Bulletin Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) and amends SFAS No. 95, “Statement of Cash Flows”. Generally, the approach in SFAS 123(R) is similar to the approach described in SFAS 123. However, SFAS 123(R) will require all share-based payments to employees, including grants of employee stock options, to be recognized as stock-based compensation expense in the Company’s Consolidated Statements of Operations based on their fair values. Pro forma disclosure is no longer an alternative.
 
SFAS 123(R) must be adopted no later than January 1, 2006 and permits public companies to adopt its requirements using one of two methods:
 
  •  A “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS 123(R) for all share-based payments granted after the adoption date and based on the requirements of SFAS 123 for all awards granted to employees prior to the effective date of SFAS 123(R) that remain unvested on the adoption date.
 
  •  A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures.
 
The Company adopted the provisions of SFAS 123(R) on January 1, 2006 using the modified prospective method.
 
As permitted by SFAS 123, the Company accounted for share-based payments to employees prior to January 1, 2006 using the intrinsic value method prescribed by APB 25 and related interpretations. As such, the Company generally did not recognize compensation expense associated with employee stock option grants. The Company has not issued stock options to employees since 2003. Consequently, the adoption of SFAS 123(R)’s fair value method will not have a significant impact on the Company’s future result of operations or financial position. Had the Company adopted SFAS 123(R) in prior periods, the impact would have approximated the impact of SFAS 123 as described in the pro forma disclosures in Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”. The adoption of SFAS 123(R) will have no effect on future results of operations related to the Company’s unvested outstanding restricted stock awards. The Company estimates that the adoption of SFAS 123(R), based on estimated outstanding unvested stock options, will result in compensation charges of approximately $1.0 million during 2006.
 
The Company’s ESPP that allows eligible employees to annually purchase the Company’s common stock at a discount. The provisions of SFAS 123(R) will cause the ESPP to be a compensatory plan. However, the change in accounting for the ESPP is not expected to have a material impact on the Company’s financial position, future results of operations or liquidity. Historically, the ESPP compensatory amounts have been nominal. See Note H of Notes to Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the ESPP.
 
SFAS 123(R) also requires that tax benefits in excess of recognized compensation expenses be reported as a financing cash flow, rather than an operating cash flow as required under prior literature. This requirement may


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serve to reduce the Company’s future cash flows from operating activities and increase future cash flows from financing activities, to the extent of associated tax benefits that may be realized in the future.
 
FIN 47.  In March 2005, the FASB issued FIN 47. FIN 47 clarifies that conditional asset retirement obligations meet the definition of liabilities and should be recognized when incurred if their fair values can be reasonably estimated. The Company adopted the provisions of FIN 47 effective on December 31, 2005. The adoption of FIN 47 had no impact on the Company’s financial position or results of operations.
 
FSP FAS 19-1.  In April 2005, the FASB issued Staff Position No. FAS 19-1, “Accounting for Suspended Well Costs (“FSP FAS 19-1”). FSP FAS 19-1 amended SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”), to allow continued capitalization of exploratory well costs beyond one year from the completion of drilling under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP FAS 19-1 also amended SFAS 19 to require enhanced disclosures of suspended exploratory well costs in the notes to the consolidated financial statements. The Company adopted the new requirements during the second quarter of 2005. See Note D of Notes to Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s exploratory well costs. The adoption of FSP FAS 19-1 did not impact the Company’s consolidated financial position or results of operations.
 
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
The following quantitative and qualitative information is provided about financial instruments to which the Company was a party as of December 31, 2005 and 2004, and from which the Company may incur future gains or losses from changes in market interest rates, foreign exchange rates or commodity prices. Although certain derivative contracts to which the Company has been a party to did not qualify as hedges, the Company does not enter into derivative or other financial instruments for trading purposes.
 
The fair value of the Company’s derivative contracts are determined based on counterparties’ estimates and valuation models. The Company did not change its valuation method during 2005. During 2005, the Company was a party to commodity, interest rate and foreign exchange rate swap contracts and commodity collar contracts. See Note J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s derivative contracts, including deferred gains and losses on terminated derivative contracts. The following table reconciles the changes that occurred in the fair values of the Company’s open derivative contracts during 2005:
 
                                 
    Derivative Contract Liabilities  
                Foreign
       
          Interest
    Exchange
       
    Commodity     Rate     Rate     Total  
    (In thousands)  
 
Fair value of contracts outstanding as of December 31, 2004
  $ (406,546 )   $     $     $ (406,546 )
Changes in contract fair values(a)
    (872,808 )     (4,614 )     (43 )     (877,465 )
Contract maturities
    497,474             43       497,517  
Contract terminations
    33,403       4,614             38,017  
                                 
Fair value of contracts outstanding as of December 31, 2005
  $ (748,477 )   $     $     $ (748,477 )
                                 
 
 
(a) At inception, new derivative contracts entered into by the Company have no intrinsic value.
 
Quantitative Disclosures
 
Foreign exchange rate sensitivity.  From time-to-time, the Company’s Canadian subsidiary enters into short-term forward currency agreements to purchase Canadian dollars with U.S. dollar gas sales proceeds. The Company does not designate these derivatives as hedges due to their short-term nature. There were no outstanding forward currency agreements at December 31, 2005.


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Interest rate sensitivity.  The following tables provide information about other financial instruments to which the Company was a party as of December 31, 2005 and 2004 and that were sensitive to changes in interest rates. For debt obligations, the tables present maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions and the debt’s estimated fair value. For fixed rate debt, the weighted average interest rate represents the contractual fixed rates that the Company was obligated to periodically pay on the debt as of December 31, 2005 and 2004. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on February 15, 2006. As of December 31, 2005, the Company was not a party to material derivatives that would subject it to interest rate sensitivity.
 
Interest Rate Sensitivity
Debt Obligations as of December 31, 2005
 
                                                                 
                                              Liability
 
                                              Fair Value at
 
    Year Ending December 31,           December 31,
 
    2006     2007     2008     2009     2010     Thereafter     Total     2005  
    (In thousands, except interest rates)  
 
Total Debt:
                                                               
Fixed rate principal maturities(a)
  $     $ 32,075     $ 350,000     $     $     $ 882,985     $ 1,265,060     $ (1,369,404 )
Weighted average interest rate (%)
    6.31       6.29       6.16       6.16       6.16       6.16                  
Variable rate maturities
  $     $     $     $     $ 900,000     $     $ 900,000     $ (900,000 )
Average interest rate (%)
    5.88       6.00       6.02       6.10       6.16                        
 
 
(a) Represents maturities of principal amounts excluding (i) debt issuance discounts and premiums and (ii) deferred fair value hedge gains and losses.
 
Interest Rate Sensitivity
Debt Obligations as of December 31, 2004
 
                                                                 
                                              Liability
 
                                              Fair Value at
 
    Year Ending December 31,           December 31,
 
    2005     2006     2007     2008     2009     Thereafter     Total     2004  
    (In thousands, except interest rates)  
 
Total Debt:
                                                               
Fixed rate principal maturities(a)
  $ 130,950     $     $ 32,075     $ 350,000     $     $ 1,151,579     $ 1,664,604     $ (1,846,110 )
Weighted average interest rate (%)
    6.46       6.40       6.39       7.04       7.04       7.04                  
Variable rate maturities
  $     $ 800,000     $     $ 28,000     $     $     $ 828,000     $ (828,000 )
Average interest rate (%)
    3.89       4.77       5.13       5.49                              
 
 
(a) Represents maturities of principal amounts excluding (i) debt issuance discounts and premiums and (ii) deferred fair value hedge gains and losses.
 
Commodity price sensitivity.  The following tables provide information about the Company’s oil and gas derivative financial instruments that were sensitive to changes in oil and gas prices as of December 31, 2005 and 2004. As of December 31, 2005 and 2004, all of the Company’s oil and gas derivative financial instruments qualified as hedges.
 
Commodity hedge instruments.  The Company hedges commodity price risk with derivative contracts, such as swap and collar contracts. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum (“floor”) and maximum (“ceiling”) prices for the Company on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price.


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See Notes B, E and J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a description of the accounting procedures followed by the Company relative to hedge derivative financial instruments and for specific information regarding the terms of the Company’s derivative financial instruments that are sensitive to changes in oil or gas prices.
 
Oil Price Sensitivity
Derivative Financial Instruments as of December 31, 2005
 
                                 
                      Liability
 
                      Fair Value at
 
    Year Ending December 31,     December 31,
 
    2006     2007     2008     2005  
                      (In thousands)  
 
Oil Hedge Derivatives: