UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

 

Commission File Number: 1-13245

 

Pioneer Natural Resources Company

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code:

(972) 444-9001

 

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

 

 

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):

 

 

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

 

 

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

 

 

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.

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

(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.

 

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.

 

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.

 

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.

 

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.

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:

 

 

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.

 

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

“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.

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

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.

 

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.

 

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.  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.

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.

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.

 

The nature of the business activities conducted by the Company subjects it to certain hazards and risks. The following is a summary of some of the material risks relating to the Company’s business activities. Other risks are

described in “Item 1. Business — Competition, Markets and Regulations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk”. 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.

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

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:

 

 

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

 

 

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.

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 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”.

 

None.

 

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

by the SPE is not the same as a financial audit. The SPE’s definition of a reserve audit includes the following concepts:

 

 

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.

 

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

the changes in the Company’s proved reserve volumes by geographic area during the year ended December 31, 2005 (in MBOE):

 

 

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:

 

 

 

 

The following table represents the estimated timing and cash flows of developing the Company’s proved undeveloped reserves as of December 31, 2005:

 

 

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:

 

 

 

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:

 

 

 

 

  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

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:

 

 

 

  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

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:

 

 

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:

 

 

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.

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.

 

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

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.

PRODUCTION, PRICE AND COST DATA

 

 

PRODUCTION, PRICE AND COST DATA — (Continued)

 

PRODUCTION, PRICE AND COST DATA — (Continued)

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)