UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2010
or
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 1-13245
Pioneer Natural Resources Company
(Exact name of registrant as specified in its charter)
| Delaware | 75-2702753 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) | |
| 5205 N. O’Connor Blvd., Suite 200, Irving, Texas | 75039 | |
| (Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code: (972) 444-9001
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class |
Name of each exchange on which registered | |
| Common Stock | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer |
x |
Accelerated filer |
¨ | |||||
| Non-accelerated filer |
¨ (Do not check if a smaller reporting company) |
Smaller reporting company |
¨ | |||||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x
| Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter |
$ | 6,789,095,296 | ||
| Number of shares of Common Stock outstanding as of February 23, 2011 |
116,452,149 | |||
DOCUMENTS INCORPORATED BY REFERENCE:
(1) Proxy Statement for the 2011 Annual Meeting of Shareholders to be held during May 2011 — Referenced in Part III of this report.
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| PART I | ||||||
| Item 1. |
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| Item 1A. |
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| Item 1B. |
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| Item 2. |
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| Item 3. |
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| Item 4. |
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| PART II | ||||||
| Item 5. |
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
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43 |
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| Purchases of Equity Securities by the Issuer and Affiliated Purchasers |
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| Item 6. |
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| Item 7. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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| Item 7A. |
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| Item 8. |
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| Item 9. |
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure |
130 | ||||
| Item 9A. |
130 | |||||
| Management’s Report on Internal Control Over Financial Reporting |
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| Item 9B. |
132 |
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TABLE OF CONTENTS
| PART III | ||||||
| Item 10. |
132 | |||||
| Item 11. |
132 | |||||
| Item 12. |
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
132 | ||||
| Securities Authorized for Issuance Under Equity Compensation Plans |
132 | |||||
| Item 13. |
Certain Relationships and Related Transactions, and Director Independence |
133 | ||||
| Item 14. |
133 | |||||
| PART IV | ||||||
| Item 15. |
133 | |||||
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| 142 | ||||||
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Definitions of Certain Terms and Conventions Used Herein
Within this Report, the following terms and conventions have specific meanings:
| • | “Bbl” means a standard barrel containing 42 United States gallons. |
| • | “Bcf” means one billion cubic feet. |
| • | “BOE” means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid. |
| • | “BOEPD” means BOE per day. |
| • | “Btu” means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. |
| • | “CBM” means coal bed methane. |
| • | “Dated Brent” means a cargo of North Sea Brent blended crude oil that has been assigned a date when it will be loaded onto a tanker. |
| • | “DD&A” means depletion, depreciation and amortization. |
| • | “field fuel” means gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point. |
| • | “GAAP” means accounting principles that are generally accepted in the United States of America. |
| • | “LIBOR” means London Interbank Offered Rate, which is a market rate of interest. |
| • | “LNG” means liquefied natural gas. |
| • | “MBbl” means one thousand Bbls. |
| • | “MBOE” means one thousand BOEs. |
| • | “Mcf” means one thousand cubic feet and is a measure of natural gas volume. |
| • | “MMBbl” means one million Bbls. |
| • | “MMBOE” means one million BOEs. |
| • | “MMBtu” means one million Btus. |
| • | “MMcf” means one million cubic feet. |
| • | “MMcfpd” means one million cubic feet per day. |
| • | “Mont Belvieu–posted-price” means the daily average natural gas liquids components as priced in Oil Price Information Service (“OPIS”) in the table “U.S. and Canada LP – Gas Weekly Averages” at Mont Belvieu, Texas. |
| • | “NGL” means natural gas liquid. |
| • | “NYMEX” means the New York Mercantile Exchange. |
| • | “NYSE” means the New York Stock Exchange. |
| • | “Pioneer” or the “Company” means Pioneer Natural Resources Company and its subsidiaries. |
| • | “Pioneer Southwest” means Pioneer Southwest Energy Partners L.P. and its subsidiaries. |
| • | “Proved reserves” mean the quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. |
(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
| • | “SEC” means the United States Securities and Exchange Commission. |
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| • | “Standardized Measure” means the after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs employed in the determination of proved reserves and a ten percent discount rate. |
| • | “U.S.” means United States. |
| • | “VPP” means volumetric production payment. |
| • | “WTI” means a light, sweet blend of oil produced from fields in Western Texas. |
| • | With respect to information on the working interest in wells, drilling locations and acreage, “net” wells, drilling locations and acres are determined by multiplying "gross" wells, drilling locations and acres by the Company's working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres. |
| • | Unless otherwise indicated, all currency amounts are expressed in U.S. dollars. |
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (this “Report”) contains forward-looking statements that involve risks and uncertainties. When used in this document, the words “believes,” “plans,” “expects,” “anticipates,” “intends,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate,” or the negative of such terms and similar expressions as they relate to Pioneer Natural Resources Company and its subsidiaries (“Pioneer” or the “Company”) are intended to identify forward-looking statements. The forward-looking statements are based on the Company’s current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company’s control. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different from the anticipated results described in the forward-looking statements. See “Item 1. Business — Competition, Markets and Regulations,” “Item 1A. Risk Factors,” “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.
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| ITEM 1. | BUSINESS |
Pioneer is a Delaware corporation whose common stock is listed and traded on the NYSE. The Company is a large independent oil and gas exploration and production company with current operations in the United States and South Africa. Pioneer is a holding company whose assets consist of direct and indirect ownership interests in, and whose business is conducted substantially through, its subsidiaries.
The Company’s executive offices are located at 5205 N. O’Connor Blvd., Suite 200, Irving, Texas 75039. The Company’s telephone number is (972) 444-9001. The Company maintains other offices in Anchorage, Alaska; Denver, Colorado; Midland, Texas; London, England and Capetown, South Africa. At December 31, 2010, the Company had 2,248 employees, 1,399 of whom were employed in field and plant operations.
Pioneer files or furnishes annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”). The public may read and copy any materials that Pioneer files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including Pioneer, that file electronically with the SEC. The public can obtain any documents that Pioneer files with the SEC at http://www.sec.gov.
The Company also makes available free of charge through its internet website (www.pxd.com) its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after it electronically files such material with, or furnishes it to, the SEC.
The Company’s mission is to enhance shareholder investment returns through strategies that maximize Pioneer’s long-term profitability and net asset value. The strategies employed to achieve this mission are predicated on maintaining financial flexibility, capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions. These strategies are anchored by the Company’s interests in long-lived Spraberry oil field; the liquid-rich Eagle Ford, Barnett Shale Combo, Hugoton and West Panhandle fields; and the Raton gas field; which together have an estimated remaining productive life in excess of 40 years. Underlying these fields are approximately 90 percent of the Company’s proved oil and gas reserves as of December 31, 2010.
The Company is an independent oil and gas exploration and production company. Pioneer’s purpose is to competitively and profitably explore for, develop and produce oil and gas reserves. In so doing, the Company sells homogenous oil, NGL and gas units that, except for geographic and relatively minor quality differences, cannot be significantly differentiated from units offered for sale by the Company’s competitors. Competitive advantage is gained in the oil and gas exploration and development industry by employing well-trained and experienced personnel who make prudent capital investment decisions based on management direction, embrace technological innovation and are focused on price and cost management.
Petroleum industry. For several years preceding 2008, the petroleum industry was generally characterized by volatile, but upward trending, oil, NGL and gas commodity prices. During the first half of 2008, North American gas prices increased as a result of reduced inventory levels, a perceived shortage of North American gas supply and anticipation that the United States would become a larger importer of LNG, which was then selling in the world market at a substantial premium to United States gas prices. However, by mid-year 2008, it became apparent that capital investments in gas drilling and discoveries of significant gas reserves in United States shale plays would cause domestic gas supply to exceed existing United States gas demand. Beginning in the second half of 2008 and continuing throughout most of 2009, the United States and other industrialized countries experienced a significant economic slowdown, which
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led to a substantial decline in worldwide energy demand. Declining energy demand due to the economic slowdown, together with the increased supply of United States gas, resulted in sharp declines in oil, NGL and North American gas prices during the second half of 2008 and first half of 2009.
During the second half of 2009 and throughout 2010, economic stimulus initiatives implemented in the United States and worldwide served to stabilize economies and increase industry and consumer confidence. While oil and NGL prices have steadily improved since the beginning of the second quarter of 2009, gas prices have remained volatile throughout 2009 and 2010 as a result of increased gas supply and growing storage levels in the United States, which has offset the growth in demand. The outlook for continuation of the worldwide economic recovery in 2011 is cautiously optimistic but remains uncertain; therefore, the sustainability of the recovery in worldwide demand for energy is difficult to predict. As a result, the Company believes it is likely that commodity prices, especially North American gas prices, will continue to be volatile during 2011.
Significant factors that will impact 2011 commodity prices include: the ongoing impact of economic stimulus initiatives in the United States and worldwide in response to the worldwide economic decline; political and economic developments in North Africa and the Middle East; demand of Asian and European markets; the extent to which members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations are able to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals.
Pioneer uses commodity derivative contracts to mitigate the impact of commodity price volatility on the Company’s net cash provided by operating activities and its net asset value. Although the Company has entered into derivative contracts on a large portion of its forecasted production through 2014, a sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Company could enter into derivative contracts on additional volumes in the future. As a result, the Company’s internal cash flows would be reduced for affected periods. A sustained decline in commodity prices could result in a shortfall in expected cash flows, which could negatively impact the Company’s liquidity, financial position and future results of operations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the impact to oil, NGL and gas revenues during 2010, 2009 and 2008 from the Company’s derivative price risk management activities and the Company’s open derivative positions at December 31, 2010.
The Company. The Company’s asset base is anchored by the Spraberry oil field located in West Texas, the Raton gas field located in southern Colorado, the Hugoton gas field located in southwest Kansas and the West Panhandle gas field located in the Texas Panhandle. Complementing these areas, the Company has exploration and development opportunities and/or oil and gas production activities in the Eagle Ford Shale and Edwards Trend areas of South Texas, the Barnett Shale area of North Texas and Alaska, and internationally in South Africa. Combined, these assets create a portfolio of resources and opportunities that are well balanced among oil, NGL and gas, and that are also well balanced among long-lived, dependable production and lower-risk exploration and development opportunities. Additionally, the Company has a team of dedicated employees that represent the professional disciplines and sciences that are necessary to allow Pioneer to maximize the long-term profitability and net asset value inherent in its physical assets.
The Company provides administrative, financial, legal and management support to United States and foreign subsidiaries that explore for, develop and produce proved reserves. Production operations are principally located domestically in Texas, Kansas, Colorado and Alaska, and internationally in South Africa.
Production. The Company focuses its efforts towards maximizing its average daily production of oil, NGLs and gas through development drilling, production enhancement activities and acquisitions of producing properties, while minimizing the controllable costs associated with the production activities. For the year ended December 31, 2010, the Company’s production of 41.9 MMBOE was consistent with production during 2009. Production, price and cost information with respect to the Company’s properties for 2010, 2009 and 2008 is set forth in “Item 2. Properties — Selected Oil and Gas Information — Production, Price and Cost Data.”
Development activities. The Company seeks to increase its oil and gas reserves, production and cash flow through development drilling and by conducting other production enhancement activities, such as well recompletions. During the three years ended December 31, 2010, the Company drilled 1,033 gross (952 net) development wells, 99 percent of which were successfully completed as productive wells, at a total drilling cost (net to the Company’s interest) of $1.9 billion.
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PIONEER NATURAL RESOURCES COMPANY
The Company believes that its current property base provides a substantial inventory of prospects for future reserve, production and cash flow growth. The Company’s proved reserves as of December 31, 2010 include proved undeveloped reserves and proved developed reserves that are behind pipe of 219 MMBbls of oil, 79 MMBbls of NGLs and 991 Bcf of gas. The Company believes that its current portfolio of proved reserves provides attractive development opportunities for at least the next five years. The timing of the development of these reserves will be dependent upon commodity prices, drilling and operating costs and the Company’s expected operating cash flows and financial condition.
Exploratory activities. The Company has devoted significant efforts and resources to hiring and developing a highly skilled geoscience staff as well as acquiring a portfolio of lower-risk exploration opportunities. Exploratory and extension drilling involve greater risks of dry holes or failure to find commercial quantities of hydrocarbons than development drilling or enhanced recovery activities. See “Item 1A. Risk Factors — Exploration and development drilling may not result in commercially productive reserves” below.
Acquisition activities. The Company regularly seeks to acquire properties that complement its operations, provide exploration and development opportunities and potentially provide superior returns on investment. In addition, the Company pursues strategic acquisitions that will allow the Company to expand into new geographical areas that feature producing properties and provide exploration/exploitation opportunities. During 2010, 2009 and 2008, the Company invested $181.6 million, $88.9 million and $137.6 million, respectively, of acquisition capital to purchase proved oil and gas properties, including additional interests in its existing assets, and to acquire new prospects for future exploitation and exploration activities.
The Company periodically evaluates and pursues acquisition opportunities (including opportunities to acquire particular oil and gas assets or entities owning oil and gas assets and opportunities to engage in mergers, consolidations or other business combinations with such entities) and at any given time may be in various stages of evaluating such opportunities. Such stages may take the form of internal financial analyses, oil and gas reserve analyses, due diligence, the submission of indications of interest, preliminary negotiations, negotiation of letters of intent or negotiation of definitive agreements. The success of any acquisition is uncertain and depends on a number of factors, some of which are outside the Company’s control. See “Item 1A. Risk Factors — The Company may be unable to make attractive acquisitions and any acquisition it completes is subject to substantial risks that could adversely affect its business.”
Asset divestitures. The Company regularly reviews its asset base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. While the Company generally does not dispose of assets solely for the purpose of reducing debt, such dispositions can have the result of furthering the Company’s objective of increasing financial flexibility through reduced debt levels.
During February 2011, the Company sold 100 percent of its share holdings in its Tunisian subsidiaries for cash proceeds of $866 million, before normal closing adjustments. As a result of having committed to a plan to sell the Tunisian subsidiaries during 2010, the Company has classified its Tunisian assets and liabilities as assets and liabilities held for sale and the historic results of operations of its Tunisian assets as discontinued operations in its accompanying consolidated financial statements.
The Company anticipates that it will continue to sell nonstrategic properties or other assets from time to time to increase capital resources available for other activities, to achieve operating and administrative efficiencies and to improve profitability. See Notes M and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for specific information regarding the Company’s asset divestitures and discontinued operations, including the 2011 sale of Tunisia, during 2010, 2009 and 2008.
The Company operates in the oil and gas exploration and production industry and has operations in two geographic areas. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note Q of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for geographic operating segment information, including results of operations and segment assets.
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PIONEER NATURAL RESOURCES COMPANY
General. Production from the Company’s properties is marketed using methods that are consistent with industry practices. Sales prices for oil, NGL and gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion of operations and price risk.
Significant purchasers. During 2010, the Company’s significant purchasers of oil, NGLs and gas were Plains Marketing LP (12 percent) and Enterprise Products Partners L.P. (10 percent). The Company believes that the loss of any one purchaser would not have an adverse effect on its ability to sell its oil, NGL and gas production.
Derivative risk management activities. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts and began accounting for its derivative contracts using the mark-to-market (“MTM”) method of accounting. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a description of the Company’s derivative risk management activities, “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” and Note I of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information about the impact of commodity derivative activities on oil, NGL and gas revenues and net derivative gains and losses during 2010, 2009 and 2008, as well as the Company’s open commodity derivative positions at December 31, 2010.
Competition, Markets and Regulations
Competition. The oil and gas industry is highly competitive. A large number of companies, including major integrated and other independent companies, and individuals engage in the exploration for and development of oil and gas properties, and there is a high degree of competition for oil and gas properties suitable for development or exploration. Acquisitions of oil and gas properties have been an important element of the Company’s growth. The Company intends to continue acquiring oil and gas properties that complement its operations, provide exploration and development opportunities and potentially provide superior returns on investment. The principal competitive factors in the acquisition of oil and gas properties include the staff and data necessary to identify, evaluate and acquire such properties and the financial resources necessary to acquire and develop the properties. Many of the Company’s competitors are substantially larger and have financial and other resources greater than those of the Company.
Markets. The Company’s ability to produce and market oil, NGLs and gas profitably depends on numerous factors beyond the Company’s control. The effect of these factors cannot be accurately predicted or anticipated. Although the Company cannot predict the occurrence of events that may affect these commodity prices or the degree to which these prices will be affected, the prices for any commodity that the Company produces will generally approximate current market prices in the geographic region of the production.
Securities regulations. Enterprises that sell securities in public markets are subject to regulatory oversight by agencies such as the SEC and the NYSE. This regulatory oversight imposes on the Company the responsibility for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting, and ensuring that the financial statements and other information included in submissions to the SEC do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made in such submissions not misleading. Failure to comply with the rules and regulations of the SEC could subject the Company to litigation from public or private plaintiffs. Failure to comply with the rules of the NYSE could result in the de-listing of the Company’s common stock, which would have an adverse effect on the market price of the Company’s commons stock. Compliance with some of these rules and regulations is costly, and regulations are subject to change or reinterpretation.
Environmental matters and regulations. The Company’s operations are subject to stringent and complex foreign, federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:
| • | require the acquisition of various permits before drilling commences; |
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PIONEER NATURAL RESOURCES COMPANY
| • | enjoin some or all of the operations of facilities deemed in non-compliance with permits; |
| • | restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, production and transportation activities; |
| • | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and |
| • | require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells. |
These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the United States Congress and state legislatures, federal and state regulatory agencies and foreign government and agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on the Company’s operating costs.
The following is a summary of some of the existing laws, rules and regulations to which the Company’s business operations are subject.
Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. It is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in the Company’s costs to manage and dispose of wastes, which could have a material adverse effect on the Company’s results of operations and financial position. Also, in the course of the Company’s operations, it generates some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.
Wastes containing naturally occurring radioactive materials (“NORM”) may also be generated in connection with the Company’s operations. Certain processes used to produce oil and gas may enhance the radioactivity of NORM, which may be present in oilfield wastes. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration (“OSHA”). These state and OSHA regulations impose certain requirements concerning worker protection; the treatment, storage and disposal of NORM waste; the management of waste piles, containers and tanks containing NORM; as well as restrictions on the uses of land with NORM contamination.
Comprehensive Environmental Response, Compensation, and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
The Company currently owns or leases numerous properties that have been used for oil and gas exploration and production for many years. Although the Company believes it has used operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by the Company, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of the Company’s properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons were not under the Company’s control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by the Company. These
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PIONEER NATURAL RESOURCES COMPANY
properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.
Water discharges and use. The Clean Water Act (the “CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
The primary federal law imposing liability for oil spills is the Oil Pollution Act (“OPA”), which sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil spill cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.
Operations associated with the Company’s properties also produce wastewaters that are disposed via injection in underground wells. These injection wells are regulated by the Safe Drinking Water Act (the “SDWA”) and analogous state and local laws. The underground injection well program under the SDWA requires permits from the EPA or analogous state agency for the Company’s disposal wells, establishes minimum standards for injection well operations, and restricts the types and quantities of fluids that may be injected. Currently, the Company believes that disposal well operations on the Company’s properties comply with all applicable requirements under the SDWA. However, a change in the regulations or the inability to obtain permits for new injection wells in the future may affect the Company’s ability to dispose of produced waters and ultimately increase the cost of the Company’s operations. In addition, Congress has considered legislation that would repeal an exemption in the SDWA for the underground injection of hydraulic fracturing fluids near drinking water sources. Sponsors of the legislation have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the legislation could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The legislation also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The Subcommittee on Energy and Environment of the U.S. House of Representatives is examining the practice of hydraulic fracturing in the United States and is gathering information on its potential effects on human health and the environment. The EPA also has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health. In addition, various state and local governments have implemented or are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, requirements for disclosure of chemical constituents, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds.
The water produced by the Company’s CBM operations also may be subject to the laws of various states and regulatory bodies regarding the ownership and use of water. For example, in connection with the Company’s CBM operations in the Raton Basin in Colorado, water is removed from coal seams to reduce pressure and allow the methane to be recovered. Historically, these operations have been regulated by the state agency responsible for regulating oil and gas activity in the state. In a 2008 case brought by the owners of ranch land involving a CBM competitor in a different CBM basin in Colorado, the Colorado Supreme Court held that water produced in connection with the CBM operations should be subject to state water-use regulations administered by a different agency that regulates other uses of water in the state, including requirements to obtain permits for diversion and use of surface and subsurface water, an evaluation of potential competing uses of the water, and a possible requirement to provide mitigation water for other water users. The Colorado legislature and state agency adopted laws and regulations in response to this holding, but there continue to be litigation and uncertainty regarding permitting of
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PIONEER NATURAL RESOURCES COMPANY
produced water withdrawn in connection with CBM activities. The Company’s CBM or other oil and gas operations and the Company’s ability to expand its operations could be adversely affected, and these changes in regulation could ultimately increase the Company’s cost of doing business.
Air emissions. The Federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions; obtain or strictly comply with air permits containing various emissions and operational limitations; or utilize specific emission control technologies to limit emissions of certain air pollutants. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Moreover, states can impose air emissions limitations that are more stringent than the federal standards imposed by the EPA. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.
Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require the Company to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies for gas and oil exploration and production operations. In addition, some gas and oil production facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Gas and oil exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.
In January 2010, the Texas Commission on Environmental Quality (the “TCEQ”) concluded an analysis of air emissions of third-party operators in the Barnett Shale area in response to reported concerns about high concentrations of benzene in the air near certain drilling sites and gas processing facilities. The TCEQ’s investigation revealed elevated levels of benzene and other emissions at certain locations. The agency has continued to monitor emissions and pledged to investigate all complaints about oil and gas activities in the Barnett Shale area within 12 hours of receipt. Partially in response to its investigation, the TCEQ recently adopted new air emissions limitations and permitting requirements for oil and gas facilities in the state, which will first become applicable to facilities located in the Barnett Shale area on April 1, 2011. The TCEQ expects to expand the application of the requirements to facilities in other areas of the state in early 2012. These new requirements could increase the cost and time associated with drilling wells in the Barnett Shale, or other areas of the State in the future. The agency’s investigations could lead to additional, more stringent air permitting requirements, increased regulation, and possible enforcement actions against producers, including Pioneer, in the Barnett Shale area. In addition, environmental groups have advocated for increased regulation in the Barnett Shale area, and at least one state representative has advocated a moratorium on the issuance of drilling permits for new gas wells in the area. Any adoption of laws, regulations, orders or other legally enforceable mandates governing gas drilling and operating activities in the Barnett Shale or other areas of the State that result in more stringent drilling or operating conditions or limit or prohibit the drilling of new gas wells for any extended period of time could increase the Company’s costs and/or reduce its production, which could have a material adverse effect on the Company’s results of operations and cash flows.
Health and safety. The Company’s operations are subject to the requirements of the federal Occupational Safety and Health Act (the “OSH Act”) and comparable state statutes. These laws and the related regulations strictly govern the protection of the health and safety of employees. The OSH Act hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statues require that the Company organize or disclose information about hazardous materials used or produced in the Company’s operations. The Company believes that it is in substantial compliance with these applicable requirements and with other OSH Act and comparable requirements.
Global warming and climate change. In December 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases,” or “GHGs,” present an endangerment to human health and welfare because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of
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GHGs under existing provisions of the CAA. The EPA recently adopted two sets of rules, which became effective January 2, 2011, that regulate greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources. The EPA has also adopted rules requiring the reporting, on an annual basis, beginning in 2011 of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, for emissions occurring after January 1, 2010, as well as certain oil and gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Company’s business, financial condition and results of operations. It should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Company’s financial condition and results of operations.
Finally, other nations have been seeking to reduce emissions of GHGs pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of GHGs to below 1990 levels by 2012. Depending on the particular jurisdiction in which the Company’s operations are located, it could be required to purchase and surrender allowances for GHG emissions resulting from the Company’s operations.
The Company believes it is in substantial compliance with all existing environmental laws and regulations applicable to the Company’s current operations and that its continued compliance with existing requirements will not have a material adverse effect on the Company’s financial condition and results of operations. For instance, the Company did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2010. Additionally, the Company is not aware of any environmental issues or claims that will require material capital expenditures during 2011. However, accidental spills or releases may occur in the course of the Company’s operations, and the Company cannot give any assurance that it will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, the Company cannot give any assurance that the passage of more stringent laws or regulations in the future will not have a negative effect on the Company’s business, financial condition and results of operations.
Other regulation of the oil and gas industry. The oil and gas industry is regulated by numerous foreign, federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous federal, state and foreign departments and agencies are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry may increase the Company’s cost of doing business by increasing the cost of production, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
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PIONEER NATURAL RESOURCES COMPANY
Development and production. Development and production operations are subject to various types of regulation at foreign, federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, the posting of bonds in connection with various types of activities and filing reports concerning operations. Most states, and some counties and municipalities, in which the Company operates also regulate one or more of the following:
| • | the location of wells; |
| • | the method of drilling and casing wells; |
| • | the method and ability to fracture stimulate wells; |
| • | the surface use and restoration of properties upon which wells are drilled; |
| • | the plugging and abandoning of wells; and |
| • | notice to surface owners and other third parties. |
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas the Company can produce from the Company’s wells or limit the number of wells or the locations at which the Company can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGL and gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from the Company’s wells, negatively affect the economics of production from these wells, or to limit the number of locations the Company can drill.
Regulation of transportation and sale of gas. The availability, terms and cost of transportation significantly affect sales of gas. Foreign, federal and state regulations govern the price and terms for access to gas pipeline transportation. The interstate transportation and sale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). The FERC’s regulations for interstate gas transmission in some circumstances may also affect the intrastate transportation of gas. As a result of initiatives like FERC Order No. 636 (“Order 636”), issued in April 1992, the interstate gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all gas supplies. In many instances, the results of Order 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of gas in favor of providing only storage and transportation services.
In August 2005, the United States Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as the Company, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1.0 million per day per violation. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order 704 (defined below).
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In December 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as the Company, that engages in wholesale sales or purchases of gas that equal or exceed 2.2 million MMBtus during a calendar year annually report such sales and purchases to the FERC. Order 704 is intended to increase the transparency of the wholesale gas markets and to assist the FERC in monitoring those markets and in detecting market manipulation.
Although gas prices are currently unregulated, the United States Congress historically has been active in the area of gas regulation. The Company cannot predict whether new legislation to regulate gas or gas prices might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on the Company’s operations. Sales of condensate and gas liquids are not currently regulated and are made at market prices.
Gas gathering. While the Company owns or operates some gas gathering facilities, the Company also depends on gathering facilities owned and operated by third parties to gather production from its properties, and therefore the Company is impacted by the rates charged by such third parties for gathering services. To the extent that changes in foreign, federal and/or state regulation affect the rates charged for gathering services, the Company also may be affected by such changes. Accordingly, the Company does not anticipate that the Company would be affected any differently than similarly situated gas producers.
Transportation of hazardous materials. The federal Department of Transportation has adopted regulations requiring that certain entities transporting designated hazardous materials develop plans to address security risks related to the transportation of hazardous materials. The Company does not believe that these requirements will have an adverse effect on the Company or its operations. The Company cannot provide any assurance that the security plans required under these regulations would protect against all security risks and prevent an attack or other incident related to the Company’s transportation of hazardous materials.
| ITEM 1A. | RISK FACTORS |
The nature of the business activities conducted by the Company subjects it to certain hazards and risks. The following is a summary of some of the material risks relating to the Company’s business activities. Other risks are described in “Item 1. Business — Competition, Markets and Regulations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” These risks are not the only risks facing the Company. The Company’s business could also be affected by additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial. If any of these risks actually occurs, it could materially harm the Company’s business, financial condition or results of operations and impair Pioneer’s ability to implement business plans or complete development projects as scheduled. In that case, the market price of the Company’s common stock could decline.
The prices of oil, NGL and gas are highly volatile. A sustained decline in these commodity prices could adversely affect the Company’s financial condition and results of operations.
The Company’s revenues, profitability, cash flow and future rate of growth are highly dependent on commodity prices. Commodity prices may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, NGL and gas, market uncertainty and a variety of additional factors that are beyond the Company’s control, such as:
| • | domestic and worldwide supply of and demand for oil, NGL and gas; |
| • | inventory levels at Cushing, Oklahoma, the benchmark for WTI oil prices; |
| • | weather conditions; |
| • | overall domestic and global political and economic conditions; |
| • | actions of OPEC and other state-controlled oil companies relating to oil price and production controls; |
| • | the effect of LNG deliveries to the United States; |
| • | technological advances affecting energy consumption and energy supply; |
| • | domestic and foreign governmental regulations and taxation; |
| • | the effect of energy conservation efforts; |
| • | the proximity, capacity, cost and availability of pipelines and other transportation facilities; and |
| • | the price and availability of alternative fuels. |
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PIONEER NATURAL RESOURCES COMPANY
In the past, commodity prices have been extremely volatile, and the Company expects this volatility to continue. For example, oil prices reached record levels in July 2008 of $145.29 per Bbl before declining to $33.87 per Bbl in December 2008, while gas prices reached $13.58 per Mcf before declining to $5.29 per Mcf over the same period. During 2009, oil prices increased from a low of $33.98 per Bbl in February to a high of $81.37 per Bbl in October, while gas prices declined from $6.07 per Mcf in January to $2.51 per Mcf in September. During 2010, oil prices fluctuated from a low of $68.01 per Bbl in May to a high of $91.51 per Bbl in December, while gas prices fluctuated from a high of $6.01 per Mcf in January to a low of $3.29 per Mcf in October. The Company makes price assumptions that are used for planning purposes, and a significant portion of the Company’s cash outlays, including rent, salaries and noncancellable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, the Company’s financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.
Significant or extended price declines could also adversely affect the amount of oil, NGL and gas that the Company can produce economically. A reduction in production could result in a shortfall in expected cash flows and require the Company to reduce capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively affect the Company’s ability to replace its production and its future rate of growth.
The Company could experience periods of higher costs if commodity prices rise. These increases could reduce the Company’s profitability, cash flow and ability to complete development activities as planned.
Historically, the Company’s capital and operating costs have risen during periods of increasing oil, NGL and gas prices. These cost increases result from a variety of factors beyond the Company’s control, such as increases in the cost of electricity, steel and other raw materials that the Company and its vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Increased levels of drilling activity in the oil and gas industry in recent periods have led to increased costs of some drilling equipment, materials and supplies. Such costs may rise faster than increases in the Company’s revenue, thereby negatively impacting the Company’s profitability, cash flow and ability to complete development activities as scheduled and on budget.
The Company’s derivative risk management activities could result in financial losses.
To achieve more predictable cash flow and to manage the Company’s exposure to fluctuations in the prices of oil, NGL and gas, the Company’s strategy is to enter into derivative arrangements covering a portion of its oil, NGL and gas production. These derivative arrangements are subject to mark-to-market accounting treatment, and the changes in fair market value of the contracts are reported in the Company’s statement of operations each quarter, which may result in significant net gains or losses. These derivative contracts may also expose the Company to risk of financial loss in certain circumstances, including when:
| • | production is less than the contracted derivative volumes, |
| • | the counterparty to the derivative contract defaults on its contract obligations, or |
| • | the derivative contracts limit the benefit the Company would otherwise receive from increases in commodity prices. |
On the other hand, failure to protect against declines in commodity prices exposes the Company to reduced revenue and liquidity when prices decline, as occurred in late 2008 for all commodities and during 2009 and 2010 for gas.
The failure by counterparties to the Company’s derivative risk management activities to perform their obligations could have a material adverse effect on the Company’s results of operations.
The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default on its obligations under the Company’s derivative arrangements, such a default could have a material, adverse effect on the Company’s results of operations, and could result in a larger percentage of the Company’s future production being subject to commodity price changes.
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Exploration and development drilling may not result in commercially productive reserves.
Drilling involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain and drilling operations may be curtailed, delayed or canceled, or became costlier, as a result of a variety of factors, including:
| • | unexpected drilling conditions; |
| • | unexpected pressure or irregularities in formations; |
| • | equipment failures or accidents; |
| • | fracture stimulation accidents or failures; |
| • | adverse weather conditions; |
| • | restricted access to land for drilling or laying pipelines; and |
| • | access to, and the cost and availability of, the equipment, services and personnel required to complete the Company’s drilling, completion and operating activities. |
The Company’s future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse effect on the Company’s future results of operations and financial condition. While all drilling, whether developmental, extension or exploratory, involves these risks, exploratory and extension drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Company expects that it will continue to experience exploration and abandonment expense in 2011.
Future price declines could result in a reduction in the carrying value of the Company’s proved oil and gas properties, which could adversely affect the Company’s results of operations.
Declines in commodity prices may result in the Company’s having to make substantial downward adjustments to the Company’s estimated proved reserves. If this occurs, or if the Company’s estimates of production or economic factors change, accounting rules may require the Company to impair, as a noncash charge to earnings, the carrying value of the Company’s oil and gas properties. The Company is required to perform impairment tests on proved oil and gas properties whenever events or changes in circumstances indicate that the carrying value of proved properties may not be recoverable. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of the Company’s oil and gas properties, the carrying value may not be recoverable and therefore an impairment charge will be required to reduce the carrying value of the proved properties to their estimated fair value. For example, during 2009 and 2008, the Company recognized impairment charges of $21.1 million and $89.8 million, respectively, due to the impairment of the Company’s net assets in the Uinta/Piceance area, primarily due to declines in gas prices and downward adjustments to the economically recoverable resource potential. The Company may incur impairment charges in the future, which could materially affect the Company’s results of operations in the period incurred.
The Company periodically evaluates its unproved oil and gas properties and could be required to recognize noncash charges in the earnings of future periods.
At December 31, 2010, the Company carried unproved property costs of $191.1 million. GAAP requires periodic evaluation of these costs on a project-by-project basis. These evaluations are affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of the leases, contracts and permits appurtenant to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize noncash charges in the earnings of future periods.
The Company may be unable to make attractive acquisitions, and any acquisition it completes is subject to substantial risks that could adversely affect its business.
Acquisitions of producing oil and gas properties have been an important element of the Company’s growth. The Company’s growth following the full development of its existing property base could be impeded if it is unable to acquire additional oil and gas reserves on a profitable basis. Acquisition opportunities in the oil and gas industry are very competitive, which can increase the cost of, or cause the Company to refrain from, completing acquisitions. The success of any acquisition will depend on a number of factors and involves potential risks, including among other things:
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PIONEER NATURAL RESOURCES COMPANY
| • | the inability to estimate accurately the costs to develop the reserves, the recoverable volumes of reserves, rates of future production and future net cash flows attainable from the reserves; |
| • | the assumption of unknown liabilities, losses or costs for which the Company is not indemnified or for which the indemnity the Company receives is inadequate; |
| • | the validity of assumptions about costs, including synergies; |
| • | the impact on the Company’s liquidity or financial leverage of using available cash or debt to finance acquisitions; |
| • | the diversion of management’s attention from other business concerns; and |
| • | an inability to hire, train or retain qualified personnel to manage and operate the Company’s growing business and assets. |
All of these factors affect whether an acquisition will ultimately generate cash flows sufficient to provide a suitable return on investment. Even though the Company performs a review of the properties it seeks to acquire that it believes is consistent with industry practices, such reviews are often limited in scope. As a result, among other risks, the Company’s initial estimates of reserves may be subject to revision following an acquisition, which may materially and adversely affect the desired benefits of the acquisition.
The Company may be unable to dispose of nonstrategic assets on attractive terms, and may be required to retain liabilities for certain matters.
The Company regularly reviews its property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect the ability of the Company to dispose of nonstrategic assets or complete announced dispositions, including the availability of purchasers willing to purchase the nonstrategic assets at prices acceptable to the Company. Sellers typically retain certain liabilities or indemnify buyers for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release the Company from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a sale, the Company may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
The Company periodically evaluates its goodwill for impairment and could be required to recognize noncash charges in the earnings of future periods.
At December 31, 2010, the Company carried goodwill of $298.2 million associated with its United States reporting unit. Goodwill is tested for impairment annually during the third quarter using a July 1 assessment date, and also whenever facts or circumstances indicate that the carrying value of the Company’s goodwill may be impaired, requiring an estimate of the fair values of the reporting unit’s assets and liabilities. Those assessments may be affected by (a) future reserve adjustments both positive and negative, (b) results of drilling activities, (c) changes in management’s outlook on commodity prices and costs and expenses, (d) changes in the Company’s market capitalization, (e) changes in the Company’s weighted average cost of capital and (f) changes in income taxes. If the fair value of the reporting unit’s net assets is not sufficient to fully support the goodwill balance in the future, the Company will reduce the carrying value of goodwill for the impaired value, with a corresponding noncash charge to earnings in the period in which goodwill is determined to be impaired.
The Company’s gas processing operations are subject to operational risks, which could result in significant damages and the loss of revenue.
As of December 31, 2010, the Company owned interests in four gas processing plants and 11 treating facilities. The Company operates two of the gas processing plants and all 11 of the treating facilities. There are significant risks associated with the operation of gas processing plants. Gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of a gas processing plant or facility could result in an explosion or the discharge of toxic gases, which could result in significant damage claims in addition to interrupting a revenue source.
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PIONEER NATURAL RESOURCES COMPANY
The Company’s operations involve many operational risks, some of which could result in substantial losses to the Company and unforeseen interruptions to the Company’s operations for which the Company may not be adequately insured.
The Company’s operations are subject to all the risks normally incident to the oil and gas development and production business, including:
| • | blowouts, cratering, explosions and fires; |
| • | adverse weather effects; |
| • | environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases; |
| • | high costs, shortages or delivery delays of equipment, labor or other services; |
| • | facility or equipment malfunctions, failures or accidents; |
| • | title problems; |
| • | pipe or cement failures or casing collapses; |
| • | compliance with environmental and other governmental requirements; |
| • | lost or damaged oilfield workover and service tools; |
| • | unusual or unexpected geological formations or pressure or irregularities in formations; and |
| • | natural disasters. |
The Company’s overall exposure to operational risks may increase as its drilling activity expands and as it seeks to directly provide drilling, fracture stimulation and other services internally. Any of these risks could result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigations and penalties and suspension of operations.
The Company is not fully insured against certain of the risks described above, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance. Additionally, the Company relies to a large extent on facilities owned and operated by third-parties, and damage to or destruction of those third-party facilities could affect the ability of the Company to produce, transport and sell its hydrocarbons. For example, in 2008, damage caused by Hurricanes Gustav and Ike to a third-party facility that fractionates NGLs from a portion of the Company’s production resulted in a portion of the Company’s production being shut in or curtailed from early September to mid-November 2008 while repairs and maintenance to the facility were being completed.
The Company’s expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.
The Company has identified drilling locations and prospects for future drilling opportunities, including development, exploratory and infill drilling and enhanced recovery activities. These drilling locations and prospects represent a significant part of the Company’s future drilling plans. The Company’s ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services and personnel and drilling results. Because of these uncertainties, the Company cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or meet the Company’s expectations for success. As such, the Company’s actual drilling and enhanced recovery activities may materially differ from the Company’s current expectations, which could have a significant adverse effect on the Company’s proved reserves, financial condition and results of operations.
The Company may not be able to obtain access to pipelines, gas gathering, transmission, storage and processing facilities to market its oil, NGL and gas production.
The marketing of oil, NGL and gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. If there were insufficient capacity available on these systems, or if these systems were unavailable to the Company, the price offered for the Company’s production could be significantly depressed, or the Company could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while it constructs its own facility. The Company also relies (and expects to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit and sell its oil, NGL and gas production. The Company’s plans to develop and sell its oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient transmission, storage or processing facilities to the Company, especially in areas of planned expansion where such facilities do not currently exist.
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PIONEER NATURAL RESOURCES COMPANY
The nature of the Company’s assets exposes it to significant costs and liabilities with respect to environmental and operational safety matters.
The oil and gas business is subject to environmental hazards such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose the Company to substantial liability due to pollution and other environmental damage. A variety of United States federal, state and local, as well as foreign laws and regulations govern the environmental aspects of the oil and gas business. Noncompliance with these laws and regulations may subject the Company to administrative, civil or criminal penalties, remedial cleanups, and natural resource damages or other liabilities, and compliance with these laws and regulations may increase the cost of the Company’s operations. Such laws and regulations may also affect the costs of acquisitions. See “Item 1. Business — Competition, Markets and Regulations — Environmental matters and regulations” above for additional discussion related to environmental risks.
No assurance can be given that existing or future environmental laws will not result in a curtailment of production or processing activities, result in a material increase in the costs of production, development, exploration or processing operations or adversely affect the Company’s future operations and financial condition. Pollution and similar environmental risks generally are not fully insurable.
The Company’s credit facility and debt instruments have substantial restrictions and financial covenants that may restrict its business and financing activities.
The Company is a borrower under fixed rate senior notes, senior convertible notes and a credit facility. The terms of the Company’s borrowings under the senior notes, senior convertible notes and the credit facility specify scheduled debt repayments and require the Company to comply with certain associated covenants and restrictions. The Company’s ability to comply with the debt repayment terms, associated covenants and restrictions is dependent on, among other things, factors outside the Company’s direct control, such as commodity prices and interest rates. See Note E of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the Company’s outstanding debt as of December 31, 2010 and the terms associated therewith.
The Company’s ability to obtain additional financing is also affected by the Company’s debt credit ratings and competition for available debt financing.
The Company faces significant competition, and many of its competitors have resources in excess of the Company’s available resources.
The oil and gas industry is highly competitive. The Company competes with a large number of companies, producers and operators in a number of areas such as:
| • | seeking to acquire oil and gas properties suitable for development or exploration; |
| • | marketing oil, NGL and gas production; and |
| • | seeking to acquire the equipment and expertise, including trained personnel, necessary to evaluate, operate and develop properties. |
Many of the Company’s competitors are larger and have substantially greater financial and other resources than the Company. See “Item 1. Business — Competition, Markets and Regulations” for additional discussion regarding competition.
The Company is subject to regulations that may cause it to incur substantial costs.
The Company’s business is regulated by a variety of federal, state, local and foreign laws and regulations. For instance, the TCEQ recently adopted rules establishing new air emissions limitations and permitting requirements for oil and gas activities in the Barnett Shale area, which may increase the cost and time associated with drilling wells in that area. In addition, in connection with the Company’s CBM operations in the Raton Basin in Colorado, the Colorado Supreme Court affirmed a state water court holding that water produced in connection with CBM operations should be subject to state water-use regulations, including regulations requiring permits for diversion and use of surface and subsurface water, an evaluation of potential competing permits, possible uses of the water and a possible requirement to provide augmentation water supplies for water rights owners with more senior rights. There can be no assurance that present or future regulations will not adversely affect the Company’s business and operations, including that the Company may be required to suspend drilling operations or shut in production pending compliance. See “Item 1. Business — Competition, Markets and Regulations” for additional discussion regarding government regulation.
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PIONEER NATURAL RESOURCES COMPANY
The Company’s international operations may be adversely affected by economic, political and other factors.
At December 31, 2010, three percent of the Company’s proved reserves were located outside the United States. The success and profitability of international operations may be adversely affected by risks associated with international activities, including:
| • | economic and labor conditions; |
| • | war, terrorist acts and civil disturbances; |
| • | political instability; |
| • | loss of revenue, property and equipment as a result of actions taken by foreign countries where the Company has operations, such as expropriation or nationalization of assets and renegotiation, modification or nullification of existing contracts; |
| • | changes in taxation policies (including host-country import-export, excise and income taxes and United States taxes on foreign subsidiaries); |
| • | laws and policies of the United States and foreign jurisdictions affecting foreign investment, trade and business conduct; and |
| • | changes in the value of the U.S. dollar versus the local currencies in which oil and gas producing activities may be denominated. |
In some cases, the market for the Company’s production in foreign countries is limited to some extent. For example, all of the Company’s gas and condensate production from the South Coast Gas project in South Africa is currently committed by contract to a single, government-affiliated gas-to-liquids facility. If this facility ceased to purchase the gas because of an unforeseen event, it might be difficult to find an alternative market for the production, and if such a market were secured, the price received by the Company might be less than that provided under its current gas sales contract. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding other risks associated with the Company’s international operations.
Estimates of proved reserves and future net cash flows are not precise. The actual quantities and net cash flows of the Company’s proved reserves may prove to be lower than estimated.
Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows there from. The estimates of proved reserves and related future net cash flows set forth in this Report are based on various assumptions, which may ultimately prove to be inaccurate.
Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:
| • | historical production from the area compared with production from other producing areas; |
| • | the quality and quantity of available data; |
| • | the interpretation of that data; |
| • | the assumed effects of regulations by governmental agencies; |
| • | assumptions concerning future commodity prices; and |
| • | assumptions concerning future operating costs, severance, ad valorem and excise taxes, development costs, transportation costs and workover and remedial costs. |
Because all proved reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:
| • | the quantities of oil and gas that are ultimately recovered; |
| • | the production costs incurred to recover the reserves; |
| • | the amount and timing of future development expenditures; and |
| • | future commodity prices. |
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PIONEER NATURAL RESOURCES COMPANY
Furthermore, different reserve engineers may make different estimates of proved reserves and cash flows based on the same available data. The Company’s actual production, revenues and expenditures with respect to proved reserves will likely be different from estimates, and the differences may be material.
As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on average prices preceding the date of the estimate and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:
| • | the amount and timing of actual production; |
| • | levels of future capital spending; |
| • | increases or decreases in the supply of or demand for oil, NGLs and gas; and |
| • | changes in governmental regulations or taxation. |
The Company reports all proved reserves held under concessions utilizing the “economic interest” method, which excludes the host country’s share of proved reserves. Estimated quantities reported under the “economic interest” method are subject to fluctuations in commodity prices and recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices.
Standardized Measure is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. In general, it requires the use of commodity prices that are based upon a 12-month unweighted average, as well as operating and development costs being incurred at the end of the reporting period. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and gas production because of seasonal price fluctuations or other varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general. Therefore, the estimates of discounted future net cash flows or Standardized Measure in this Report should not be construed as accurate estimates of the current market value of the Company’s proved reserves.
The Company’s actual production could differ materially from its forecasts.
From time to time, the Company provides forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells and the outcome of future drilling activity. Should these estimates prove inaccurate, actual production could be adversely affected. In addition, the Company’s forecasts assume that none of the risks associated with the Company’s oil and gas operations summarized in this “Item 1A. Risk Factors” occur, such as facility or equipment malfunctions, adverse weather effects, or downturns in commodity prices or significant increases in costs, which could make certain drilling activities or production uneconomical.
The Company may be unable to complete its plans to repurchase its common stock.
The Board of Directors (the “Board”) approves share repurchase programs and sets limits on the price per share at which the Company’s common stock can be repurchased. From time to time, the Company may not be permitted to repurchase its stock during certain periods because of scheduled and unscheduled trading blackouts. Additionally, business conditions and availability of capital may dictate that repurchases be suspended or canceled. As a result, there can be no assurance that additional repurchase programs will be commenced and, if so, that they will be completed.
A subsidiary of the Company acts as the general partner of a publicly-traded limited partnership. As such, the subsidiary’s operations may involve a greater risk of liability than ordinary business operations.
A subsidiary of the Company acts as the general partner of Pioneer Southwest Energy Partners L.P., a publicly-traded limited partnership formed by the Company to own, develop and acquire oil and gas assets in its area of operations. As general partner, the subsidiary may be deemed to have undertaken fiduciary obligations to the partnership. Activities determined to involve fiduciary obligations to others typically involve a higher standard of conduct than ordinary business operations and therefore may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Any such liability may be material.
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PIONEER NATURAL RESOURCES COMPANY
A failure by purchasers of the Company’s production to perform their obligations to the Company could require the Company to recognize a pre-tax charge in earnings and have a material adverse effect on the Company’s results of operation.
While the credit markets, the availability of credit and the equity markets have improved during 2009 and 2010, the economic outlook for 2011 remains uncertain. To the extent that purchasers of the Company’s production rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to the Company if such purchasers were unable to access the credit or equity markets for an extended period of time. If for any reason the Company were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of the Company’s production were uncollectible, the Company would recognize a pre-tax charge in the earnings of that period for the probable loss.
The Company may not be able to obtain funding, obtain funding on acceptable terms or obtain funding under its current credit facility in the event of a deterioration of the credit and capital markets, which could hinder or prevent the Company from meeting its future capital needs.
During 2009 and 2010, access to the debt and equity capital markets improved. However, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets was higher than historical levels as many lenders and institutional investors increased interest rates, enacted tighter lending standards and limited the amount of funding available to borrowers.
If these events were to recur, the Company could be unable to obtain adequate funding under its current credit facility because (i) the Company’s lending counterparties may be unwilling or unable to meet their funding obligations or (ii) the amount the Company may borrow under its current credit facility could be reduced as a result of lower oil, NGL or gas prices, declines in reserves, stricter lending requirements or regulations, or for other reasons. For example, the Company’s credit facility requires that the Company maintain a specified ratio of the net present value of the Company’s oil and gas properties to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. Due to these factors, the Company cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, the Company may be unable to implement its business plans or otherwise take advantage of business opportunities or respond to competitive pressures any of which could have a material adverse effect on the Company’s production, revenues and results of operations.
Declining general economic, business or industry conditions could have a material adverse affect on the Company’s results of operations.
Concerns over the worldwide economic outlook, geopolitical issues, the availability and cost of credit and the United States mortgage and real estate markets contributed to increased volatility and diminished expectations for the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment resulted in a worldwide recession during the second half of 2008 and most of 2009. While the worldwide economic outlook has improved, concerns about global economic growth could have a significant adverse effect on global financial markets and commodity prices. If the economic climate in the United States or abroad were to deteriorate, demand for petroleum products could diminish, which could depress the prices at which the Company could sell its oil, NGLs and gas and ultimately decrease the Company’s net revenue and profitability.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
The Fiscal Year 2012 Budget proposed by the President recommends elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress which would implement many of these proposals. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and
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PIONEER NATURAL RESOURCES COMPANY
geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect the value of an investment in the Company’s common stock.
The recent adoption of climate change legislation by the United States Congress or regulation by the EPA could result in increased operating costs and reduced demand for the oil, NGLs and gas the Company produces.
During December 2009, the EPA officially published its findings that emissions of GHGs present an endangerment to human health and welfare because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal CAA. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA recently adopted two sets of rules, which became effective January 2, 2011, that regulate greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources. The EPA has also adopted rules requiring the reporting, on an annual basis, beginning in 2011 of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, for emissions occurring after January 1, 2010, as well as certain oil and gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Company’s business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Company’s financial condition and results of operations. See “Item 1. Business – Competition, Markets and Regulations.”
The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.
The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to the Company is uncertain at this time. The financial reform legislation may also require the counterparties to the
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PIONEER NATURAL RESOURCES COMPANY
Company’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect the Company’s available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less creditworthy counterparties. If the Company reduces its use of derivatives as a result of the legislation and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. The Company’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on the Company, its financial condition, and its results of operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The Company routinely utilizes hydraulic fracturing techniques in many of its drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions. The EPA, however, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, various state and local governments have implemented or are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, requirements for disclosure of chemical constituents, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for the Company to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, the Company’s fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and gas that the Company is ultimately able to produce from its reserves.
Provisions of the Company’s charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for the Company’s common stock.
Provisions in the Company’s certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which the Company is not the surviving company and may otherwise prevent or slow changes in the Company’s board of directors and management. In addition, because the Company is incorporated in Delaware, it is governed by the provisions of Section 203 of the Delaware General Corporation Law. The Company has also adopted a shareholder rights plan. These provisions could discourage an acquisition of the Company or other change in control transaction and thereby negatively affect the price that investors might be willing to pay in the future for the Company’s common stock.
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
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PIONEER NATURAL RESOURCES COMPANY
| ITEM 2. | PROPERTIES |
During 2009, the SEC issued its final rule on the modernization of oil and gas reporting (the “Reserve Ruling”) and the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update No. 2010-03 (“ASU 2010-03”) “Extractive Industries – Oil and Gas,” which aligned the estimation and disclosure requirements of FASB Accounting Standards Codification Topic 932 with the Reserve Ruling. The Reserve Ruling and ASU 2010-03 became effective for Annual Reports on Form 10-K for fiscal years ending on or after December 31, 2009. The key provisions of the Reserve Ruling and ASU 2010-03 are as follows:
| • | Expanding the definition of oil- and gas-producing activities to include the extraction of saleable hydrocarbons, in the solid, liquid or gaseous state, from oil sands, coalbeds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction; |
| • | Amending the definition of proved oil and gas reserves to require the use of an average of the first-day-of-the-month commodity prices during the 12-month period ending on the balance sheet date rather than period-end commodity prices; |
| • | Adding to and amending other definitions used in estimating proved oil and gas reserves, such as “reliable technology” and “reasonable certainty”; |
| • | Broadening the types of technology that a reporter may use to establish reserves estimates and categories; and |
| • | Changing disclosure requirements and providing formats for tabular reserve disclosures. |
Reserve Estimation Procedures and Audits
The information included in this Report about the Company’s proved reserves as of December 31, 2010, 2009 and 2008, which were located in the United States, South Africa and Tunisia, is based on evaluations prepared by (i) the Company’s engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), with respect to the Company’s major properties, and (ii) the Company’s engineers, with respect to all other properties. The Company has no oil and gas reserves from non-traditional sources. Additionally, the Company does not provide optional disclosure of probable or possible reserves. See Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the sale of 100 percent of the Company’s share holdings in its Tunisian subsidiaries during February 2011, which owned 100 percent of the Company’s Tunisia proved reserves.
Reserve estimation procedures. The Company has established internal controls over reserve estimation processes and procedures to support the accurate and timely preparation and disclosure of reserve estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation reporting processes by Pioneer’s Worldwide Reserves Group (“WWR”), and annual external audits of substantial portions of the Company’s proved reserves by NSAI.
The management of Pioneer’s oil and gas assets is decentralized geographically by individual asset teams who are responsible for the oil and gas activities in each of the Company’s Permian Basin, Rockies, Mid-Continent, South Texas—Eagle Ford Shale, South Texas—Edwards, Barnett Shale, Alaska and Africa asset teams (the “Asset Teams”). The Company’s Asset Teams are each staffed with reservoir engineers and geoscientists who prepare reserve estimates at the end of each calendar quarter for the assets that they manage, using reservoir engineering information technology. There is shared oversight of the Asset Teams’ reservoir engineers by the Asset Teams’ managers and the Director of the WWR, each of whom is in turn subject to direct or indirect oversight by the Company’s Chief Operating Officer (“COO”) and management committee (“MC”). The Company’s MC is comprised of its Chief Executive Officer, COO, Chief Financial Officer and other Executive Vice Presidents. Asset Teams’ reserve estimates are reviewed by the asset team reservoir engineers before being submitted to the Director of the WWR and are summarized in reserve reconciliations that quantify reserve changes represented by revisions of previous estimates, purchases of minerals-in-place, improved recovery, extensions and discoveries, production and sales of minerals-in-place. All reserve estimates, material assumptions and inputs used in reserve estimates and significant changes in reserve estimates are reviewed for engineering and financial appropriateness and compliance with SEC and GAAP standards by the WWR, in consultation with the Company’s accounting and financial management personnel. Annually, the MC reviews the reserve estimates and any differences with NSAI (for the portion of the reserves audited by NSAI) on a consolidated basis before these estimates are approved. The engineers and geoscientists who participate in the reserve estimation and disclosure process periodically attend training on the Reserve Ruling by external consultants and/or through internal Pioneer programs. Additionally, the WWR has
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PIONEER NATURAL RESOURCES COMPANY
prepared and maintains written policies and guidelines for the Asset Teams to reference on reserve estimation and preparation to promote objectivity in the preparation of the Company’s reserve estimates and SEC and GAAP compliance in the reserve estimation and reporting process.
Proved reserves audits. The reserve audits performed by NSAI in the aggregate represented 90 percent, 93 percent and 87 percent of the Company’s 2010, 2009 and 2008 proved reserves, respectively; and, 79 percent, 86 percent and 80 percent of the Company’s 2010, 2009 and 2008 associated pre-tax present value of proved reserves discounted at ten percent, respectively.
NSAI follows the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers (“SPE”). A reserve audit as defined by the SPE is not the same as a financial audit. The SPE’s definition of a reserve audit includes the following concepts:
| • | A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable and has been presented in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the SPE. |
| • | The estimation of reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by a company in estimating its reserves so that the reserve auditors may express an opinion as to whether, in the aggregate, the reserve information furnished by a company is reasonable. |
| • | The methods and procedures used by a company, and the reserve information furnished by a company, must be reviewed in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare its own estimates of reserve information for the audited properties. |
To further clarify, in conjunction with the audit of the Company’s proved reserves and associated pre-tax present value discounted at ten percent, Pioneer provided to NSAI its external and internal engineering and geoscience technical data and analyses. Following NSAI’s review of that data, it had the option of honoring Pioneer’s interpretation, or making its own interpretation. No data was withheld from NSAI. NSAI accepted without independent verification the accuracy and completeness of the historical information and data furnished by Pioneer with respect to ownership interest, oil and gas production, well test data, commodity prices, operating and development costs, and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its evaluation something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.
In the course of its evaluations, NSAI prepared, for all of the audited properties, its own estimates of the Company’s proved reserves and the pre-tax present value of such reserves discounted at ten percent. NSAI reviewed its audit differences with the Company, and, in a number of cases, held joint meetings with the Company to review additional reserves work performed by the technical teams and any updated performance data related to the reserve differences. Such data was incorporated, as appropriate, by both parties into the reserve estimates. NSAI’s estimates, including any adjustments resulting from additional data, of those proved reserves and the pre-tax present value of such reserves discounted at ten percent did not differ from Pioneer’s estimates by more than ten percent in the aggregate. However, when compared on a lease-by-lease, field-by-field or area-by-area basis, some of the Company’s estimates were greater than those of NSAI and some were less than the estimates of NSAI. When such differences do not exceed ten percent in the aggregate and NSAI is satisfied that the proved reserves and pre-tax present value of such reserves discounted at ten percent are reasonable and that its audit objectives have been met, NSAI will issue an unqualified audit opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analyses by the Company and NSAI. At the conclusion of the audit process, it was NSAI’s opinion, as set forth in its audit letter which is included as an exhibit to this Report, that Pioneer’s estimates of the Company’s proved oil and gas reserves and associated pre-tax present value discounted at ten percent are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering standards promulgated by the SPE.
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PIONEER NATURAL RESOURCES COMPANY
See “Item 1A. Risk Factors,” “Critical Accounting Estimates” in “Item 7. Management’s Discussion and Analysis and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” for additional discussions regarding proved reserves and their related cash flows.
Qualifications of reserves preparers and auditors. The WWR is staffed by petroleum engineers with extensive industry experience and is managed by the Director of WWR, the technical person that is primarily responsible for overseeing the Company’s reserves estimates. These individuals meet the professional qualifications of reserves estimators and reserves auditors as defined by the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,” promulgated by the board of directors of the SPE. The WWR Director’s qualifications include 33 years of experience as a petroleum engineer, with 26 years focused on reserves reporting for independent oil and gas companies, including Pioneer. His educational background includes an undergraduate degree in Chemical Engineering and a Masters of Business Administration degree in Finance. He is also a Chartered Financial Analyst Charterholder (“CFA”) and a member of the Oil and Gas Reserves Committee of the SPE.
NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. The technical person primarily responsible for auditing the Company’s reserves estimates has been a practicing consulting petroleum engineer at NSAI since 1983 and has over 31 years of practical experience in petroleum engineering, including 30 years of experience in the estimation and evaluation of proved reserves. He graduated with a Bachelor of Science degree in Chemical Engineering in 1978 and meets or exceeds the education, training and experience requirements set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the board of directors of the SPE.
Technologies used in reserves estimates. The Company uses reliable technologies to establish additions to reserve estimates, including seismic data and interpretation, wireline formation tests, geophysical logs and core data. Reserve additions associated with reliable technologies were less than two percent of the Company’s total proved reserves during the year ended December 31, 2010.
The Company’s proved reserves totaled 1,011 MMBOE, 898.6 MMBOE and 959.6 MMBOE at December 31, 2010, 2009 and 2008, respectively, representing $5.4 billion, $3.3 billion and $3.2 billion, respectively, of Standardized Measure. The Company’s proved reserves include field fuel, which is gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point. The following table shows the changes in the Company’s proved reserve volumes by geographic area during the year ended December 31, 2010 (in MBOE):
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PIONEER NATURAL RESOURCES COMPANY
| Production | Extensions and Discoveries |
Improved Recovery |
Purchases
of Minerals-in- Place |
Sales
of Minerals-in- Place |
Revisions of Previous Estimates |
|||||||||||||||||||
| United States |
(40,777 | ) | 73,005 | 9,716 | 3,060 | (5,108 | ) | 63,540 | ||||||||||||||||
| South Africa |
(2,035 | ) | — | — | — | — | 406 | |||||||||||||||||
| Tunisia |
(1,954 | ) | 10,707 | — | — | (560 | ) | 2,145 | ||||||||||||||||
| Total |
(44,766 | ) | 83,712 | 9,716 | 3,060 | (5,668 | ) | 66,091 | ||||||||||||||||
Production. Production volumes include 2,882 MBOE of field fuel.
Extensions and discoveries. Extensions and discoveries are primarily comprised of extensions in the Spraberry field and discoveries in the Eagle Ford Shale area and Tunisia.
Improved recovery. Additions from improved recovery relate to recognizing secondary recovery reserves attributable to waterflooding the Nuiqsut horizon of the Alaskan Oooguruk development project.
Purchases of minerals-in-place. Purchases of minerals-in-place are primarily attributable to acquisitions in the Company’s Spraberry field and Eagle Ford Shale play.
Sales of minerals-in-place. Sales of minerals-in-place are primarily related to the sale of 45 percent of the Company’s interest in certain proved properties in the Eagle Ford Shale. The sale was done in connection with entering into a joint venture with an unaffiliated third party to develop the Company’s Eagle Ford Shale acreage position. See Note M of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”
Revisions of previous estimates. Revisions of previous estimates are comprised of 59 MMBOE of positive price revisions and 7 MMBOE of positive technical revisions. The Company’s proved reserves at December 31, 2010 were determined using the average of the first-day-of-the-month commodity prices during the 12-month period ending December 31, 2010 of $79.28 per barrel of oil and $4.37 per Mcf of gas, compared to $61.14 per barrel of oil and $3.87 per Mcf of gas as of December 31, 2009.
Tabular proved reserves disclosures. On a BOE basis, 57 percent of the Company’s total proved reserves at December 31, 2010 were proved developed reserves. Based on reserve information as of December 31, 2010, and using the Company’s production information for the year then ended, the reserve-to-production ratio associated with the Company’s proved reserves was in excess of 20 years on a BOE basis. The following table provides information regarding the Company’s proved reserves and average daily sales volumes by geographic area as of and for the year ended December 31, 2010:
| Summary of Oil and Gas Reserves as of December 31, 2010 Based on Average Fiscal Year Prices |
||||||||||||||||||||
| Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf) (a) |
MBOE | Standardized Measure |
||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Developed: |
||||||||||||||||||||
| United States |
160,421 | 108,785 | 1,736,765 | 558,667 | $ | 3,676,662 | ||||||||||||||
| South Africa |
274 | — | 15,671 | 2,886 | 47,579 | |||||||||||||||
| Tunisia |
12,121 | — | 23,175 | 15,984 | 341,638 | |||||||||||||||
| 172,816 | 108,785 | 1,775,611 | 577,537 | 4,065,879 | ||||||||||||||||
| Undeveloped: |
||||||||||||||||||||
| United States |
200,295 | 75,433 | 898,937 | 425,550 | 1,169,951 | |||||||||||||||
| Tunisia |
7,698 | — | (26 | ) | 7,694 | 176,179 | ||||||||||||||
| 207,993 | 75,433 | 898,911 | 433,244 | 1,346,130 | ||||||||||||||||
| Total Proved |
380,809 | 184,218 | 2,674,522 | 1,010,781 | $ | 5,412,009 | ||||||||||||||
| (a) | The gas reserves contain 303,748 MMcf of gas that will be produced and utilized as field fuel. |
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PIONEER NATURAL RESOURCES COMPANY
Proved undeveloped reserves. As of December 31, 2010, the Company had 4,727 proved undeveloped well locations (all of which are expected to be developed during the five year period ending December 31, 2015), as compared to 4,582 and 4,977 at December 31, 2009 and 2008, respectively. During 2010, the Company’s development drilling costs incurred increased by 168 percent, as compared to 2009, and the Company converted 19,158 MBOE of proved undeveloped reserves to proved developed reserves. The increase in development drilling costs during 2010 reflects the Company’s expansion of oil- and liquids-focused drilling expenditures during 2010. The Company significantly reduced its development drilling expenditures during 2009 in support of cost reduction initiatives implemented during the second half of 2008 and 2009 in response to significant declines in energy demand and commodity prices (see “Item 1. Business” for a discussion of the worldwide economic slowdown during 2008 and the associated decline in energy demand). The Company’s proved undeveloped well locations that have remained undeveloped for five years or more decreased by 12 percent to 1,467 as of December 31, 2010, as compared to 1,675 well locations at December 31, 2009. Of these undeveloped well locations, 85 percent are in the Spraberry field in the Permian Basin of West Texas. The significant concentration of well locations that have remained undeveloped for five years or more in the Spraberry field is reflective of the Company’s large inventory of drilling locations in the field and the aforementioned curtailment of development drilling activity during 2008 and 2009 in support of cost reduction initiatives. The Company expects to continue to reduce the average age of its undeveloped well locations in the Spraberry field as a result of increases in development drilling budgets in 2011 and future years.
Based on current price outlooks, the Company expects that future operating cash flows, together with a portion of the 2011 net proceeds from the sale of its Tunisian subsidiaries, will provide adequate funding for future development costs. The following table represents the estimated timing and cash flows of developing the Company’s proved undeveloped reserves as of December 31, 2010 (dollars in thousands):
| Year Ended December 31, (a) |
Estimated Future Production (MBOE) |
Future Cash Inflows |
Future Production Costs |
Future Development Costs |
Future Net Cash Flows |
|||||||||||||||
| 2011 |
3,512 | $ | 221,273 | $ | 28,679 | $ | 683,742 | $ | (491,148 | ) | ||||||||||
| 2012 |
10,877 | 665,138 | 95,451 | 1,167,125 | (597,438 | ) | ||||||||||||||
| 2013 |
18,558 | 1,040,615 | 160,818 | 1,272,636 | (392,839 | ) | ||||||||||||||
| 2014 |
27,062 | 1,426,423 | 243,151 | 1,394,024 | (210,752 | ) | ||||||||||||||
| 2015 |
30,467 | 1,597,836 | 288,419 | 1,164,644 | 144,773 | |||||||||||||||
| Thereafter |
342,769 | 16,957,215 | 5,298,483 | 339,099 | 11,319,633 | |||||||||||||||
| 433,245 | $ | 21,908,500 | $ | 6,115,001 | $ | 6,021,270 | $ | 9,772,229 | ||||||||||||
| (a) | Production and cash flows represent the drilling results from the respective year plus the incremental effects of proved undeveloped drilling. |
United States
Approximately 86 percent of the Company’s proved reserves at December 31, 2010 are located in the Spraberry field in the Permian Basin area, the Hugoton and West Panhandle fields in the Mid-Continent area and the Raton field in the Rocky Mountains area. These fields generate substantial operating cash flow, and the Spraberry and Raton fields have a large portfolio of low-risk drilling opportunities. The cash flows generated from these fields provide funding for the Company’s other development and exploration activities both domestically and internationally.
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PIONEER NATURAL RESOURCES COMPANY
The following tables summarize the Company’s United States development and exploration/extension drilling activities during 2010:
| Development Drilling | ||||||||||||||||||||||||
| Beginning Wells In Progress |
Wells Spud |
Successful Wells |
Unsuccessful Wells |
Ending Wells In Progress |
||||||||||||||||||||
| Permian Basin |
10 | 431 | 418 | 2 | 21 | |||||||||||||||||||
| Mid-Continent |
— | 11 | 10 | 1 | — | |||||||||||||||||||
| Raton Basin |
— | 1 | 1 | — | — | |||||||||||||||||||
| South Texas |
— | 1 | — | — | 1 | |||||||||||||||||||
| Alaska |
1 | 4 | 4 | — | 1 | |||||||||||||||||||
| Total United States |
11 | 448 | 433 | 3 | 23 | |||||||||||||||||||
| Exploration/Extension Drilling | ||||||||||||||||||||||||
| Beginning Wells In Progress |
Wells Spud |
Successful Wells |
Unsuccessful Wells |
Sold Wells | Ending Wells In Progress |
|||||||||||||||||||
| Permian Basin |
— | 6 | 3 | — | — | 3 | ||||||||||||||||||
| South Texas |
1 | 3 | 2 | — | 2 | |||||||||||||||||||
| Eagle Ford Shale |
2 | 39 | 19 | — | — | 22 | ||||||||||||||||||
| Barnett Shale |
2 | 17 | 8 | — | — | 11 | ||||||||||||||||||
| Alaska |
2 | — | 1 | 1 | — | — | ||||||||||||||||||
| Other |
1 | 3 | 1 | 2 | 1 | — | ||||||||||||||||||
| Total United States |
8 | 68 | 34 | 3 | 1 | 38 | ||||||||||||||||||
The following table summarizes the Company’s United States average daily oil, NGL, gas and total production by asset area during 2010:
| Oil (Bbls) | NGLs (Bbls) | Gas (Mcf) | Total (BOE) | |||||||||||||
| Permian Basin |
17,395 | 10,767 | 43,356 | 35,389 | ||||||||||||
| Mid-Continent |
3,939 | 7,738 | 54,621 | 20,780 | ||||||||||||
| Raton Basin |
— | — | 170,716 | 28,453 | ||||||||||||
| Barnett Shale |
94 | 971 | 9,060 | 2,575 | ||||||||||||
| South Texas |
53 | — | 50,448 | 8,461 | ||||||||||||
| Eagle Ford Shale |
381 | 250 | 5,937 | 1,620 | ||||||||||||
| Alaska |
6,336 | — | — | 6,336 | ||||||||||||
| Other |
13 | 10 | 1,118 | 209 | ||||||||||||
| Total United States |
28,211 | 19,736 | 335,256 | 103,823 | ||||||||||||
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PIONEER NATURAL RESOURCES COMPANY
The following table summarizes the Company’s United States costs incurred by geographic area during 2010:
| Property Acquisition Costs |
Exploration Costs |
Development Costs |
Asset Retirement Obligations |
Total | ||||||||||||||||||||
| Proved | Unproved | |||||||||||||||||||||||
| (in thousands) | ||||||||||||||||||||||||
| Permian Basin |
$ | 4,393 | $ | 5,522 | $ | 24,104 | $ | 542,977 | $ | 24,447 | $ | 601,443 | ||||||||||||
| Mid-Continent |
5 | 1,837 | 860 | 10,811 | (1,421 | ) | 12,092 | |||||||||||||||||
| Raton Basin |
(363 | ) | 777 | 6,273 | 9,984 | (14,532 | ) | 2,139 | ||||||||||||||||
| South Texas |
134 | 2,622 | 35,090 | 10,741 | (1,975 | ) | 46,612 | |||||||||||||||||
| Eagle Ford Shale |
2,481 | 112,353 | 97,485 | 1,307 | 1,316 | 214,942 | ||||||||||||||||||
| Barnett Shale |
(89 | ) | 51,745 | 52,029 | 2,026 | (166 | ) | 105,545 | ||||||||||||||||
| Alaska |
— | — | 16,144 | 96,463 | (a) | 8,985 | 121,592 | |||||||||||||||||
| Other |
— | 150 | 7,380 | (351 | ) | 1,885 | 9,064 | |||||||||||||||||
| Total United States |
$ | 6,561 | $ | 175,006 | $ | 239,365 | $ | 673,958 | $ | 18,539 | $ | 1,113,429 | ||||||||||||
| (a) | Includes $15.2 million of capitalized interest related to the Oooguruk project. |
Permian Basin
Spraberry field. The Spraberry field was discovered in 1949 and encompasses eight counties in West Texas. According to the Energy Information Administration, the Spraberry field is the second largest oil field in the United States. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casinghead gas with an average energy content of 1,400 Btu. The oil and gas are produced primarily from four formations, the upper and lower Spraberry, the Dean and the Wolfcamp, at depths ranging from 6,700 feet to 11,300 feet. In addition, the Company has also begun evaluating the Strawn formation below the Wolfcamp in certain areas of the field that have better Strawn porosity with successful results and, during 2011, plans to drill 10 to 15 wells to test the Atoka formation, which lies directly below the Strawn formation.
The Company believes the Spraberry field offers excellent opportunities to grow oil and gas production because of the numerous undeveloped drilling locations, many of which are reflected in the Company’s proved undeveloped reserves; the ability to improve incremental recovery rates through infill and deeper formation drilling, waterflood projects and horizontal drilling in certain formations; and the ability to contain operating expenses and drilling costs through economies of scale and vertical integration of field services.
During 2008, the Company initiated a program to test 20-acre infill drilling performance. The Company drilled and completed eleven 20-acre wells in 2008, nine 20-acre wells in 2009, and eighteen 20-acre wells in 2010 with encouraging results to date.
During 2010, the Company also funded an approximately 7,000 acre Spraberry field waterflood project in the upper Spraberry interval of an existing Spraberry unit. Drilling, conversion and facility work was completed during the first half of 2010 and water injection commenced during the second half of 2010. Early results from the project are encouraging, as the production decline from 110 producing wells in the surveillance area has shown signs of flattening.
During 2010, the Company also commenced drilling on two horizontal wells, both of which were in progress at December 31, 2010, to test horizontal drilling in the Wolfcamp. Both wells will be 4,000-foot laterals with 15-stage fracture stimulation completions. The first well is being drilled in the middle Wolfcamp carbonate section. The second well is targeting the lower Wolfcamp shale section. The horizontal test wells are expected to be completed during the first quarter of 2011.
The 20-acre well spacing, waterflood initiatives and horizontal drilling described above are being implemented to increase the Spraberry field recovery percentage in those areas of the field that are expected to be conducive for these undertakings. However, the ultimate incremental recovery rates associated with these initiatives cannot be precisely predicted at this time.
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PIONEER NATURAL RESOURCES COMPANY
During 2010, the Company drilled 423 wells in the Spraberry field and its total acreage position now approximates 822,000 gross acres (713,000 net acres). Pioneer has expanded its drilling program in 2011 to 30 rigs and plans to increase its rig count to 35 rigs in mid-2011 and to 40 or more rigs in 2012.
To support the Company’s Spraberry drilling efforts and to control costs, the Company has expanded its integrated services by acquiring 12 Company-operated drilling rigs and three fracture stimulation fleets that have recently commenced operations in the field. Two additional fracture stimulation fleets are being built, with one scheduled for delivery in the second quarter of 2011 and the second in the fourth quarter of 2011. Additionally, the Company has sand supply in place to satisfy its forecasted fracture stimulation requirements through 2015 and tubular and pumping unit requirements have been contracted through 2012. The Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks and fishing tools, to support its growing operations.
Mid-Continent
Hugoton field. The Hugoton field in southwest Kansas is one of the largest producing gas fields in the continental United States. The gas is produced from the Chase and Council Grove formations at depths ranging from 2,700 feet to 3,000 feet. The Company’s Hugoton properties are located on approximately 285,000 gross acres (247,000 net acres), covering approximately 400 square miles. The Company has working interests in approximately 1,225 wells in the Hugoton field, approximately 1,000 of which it operates, and partial working interest in approximately 225 wells.
The Company operates substantially all of the gathering and processing facilities, including the Satanta plant, which processes the production from the Hugoton field. During January 2011, the Company sold a 49 percent interest in the Satanta plant to an unaffiliated third party for the third party’s commitment to dedicate gas volumes to the Satanta plant. This agreement is expected to increase the Satanta plant’s processing volumes and economic longevity. The Company is also exploring opportunities to process other gas production in the Hugoton area at the Satanta plant. By maintaining operatorship of the gathering and processing facilities, the Company is able to control the production, gathering, processing and sale of its Hugoton field gas and NGL production.
West Panhandle field. The West Panhandle properties are located in the panhandle region of Texas. These stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite, Granite Wash and fractured Granite formations at depths no greater than 3,500 feet. The Company’s gas has an average energy content of 1,365 Btu and is produced from approximately 685 wells on more than 250,000 gross acres (240,000 net acres) covering over 375 square miles. The Company controls 100 percent of the wells, production equipment, gathering system and the Fain gas processing plant for the field. As this field is operated at or below vacuum conditions, Pioneer continually works to improve compressor and gathering system efficiency.
Raton
The Raton Basin properties are located in the southeast portion of Colorado. The Company owns approximately 256,000 gross acres (219,000 net acres) in the center of the Raton Basin and produces CBM gas from the coal seams in the Vermejo and Raton formations. The Company owns the majority of the well servicing and fracture stimulation equipment that it utilizes in the Raton field, allowing it to control costs and insure availability.
In the Raton field, the Company has typically sold its gas at a Mid-Continent index price, which has generally provided for higher realized gas prices as compared to the Rockies-based indexes. During December 2009, the Company entered into a ten-year firm transportation contract that commences upon completion of a new 675-mile pipeline spanning from Opal, Wyoming to Malin, Oregon. Upon completion of the pipeline’s construction, which is currently anticipated in the second quarter of 2011, the Company will have 75,000 Mcf per day of firm transportation under this agreement.
During 2010, the Company entered into an additional firm transportation contract commitment that provides gas transportation from the Raton field to Opal, Wyoming in order to support the Company’s future Opal, Wyoming to Malin, Oregon commitments as well as other forecasted sales upstream of Opal, Wyoming. This firm transportation contract provides for up to 100,000 Mcf per day of gas transportation during the contract’s primary term, which began in December 2010 and ends in March 2021.
The Company also has firm transportation commitments for 215,000 Mcf per day of gas (which decline over an 11 year term) from the Raton field eastward to Mid-Continent sales points. The Company’s aggregate firm
33
PIONEER NATURAL RESOURCES COMPANY
transportation commitments from the Raton field northwest towards Malin, Oregon, and east towards Mid-Continent sales points, exceed the Company’s current gas sales volumes controlled from the Raton field. While these excess firm transportation commitments provide capacity for future production growth from planned drilling, it also represents excess transportation costs to be managed until controlled sales volumes and firm transportation commitments reach equilibrium. The Company is exploring opportunities to defer near-term commitments until later periods or to purchase third party gas volumes to meet current transportation commitments. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual obligations” and Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information about the Company’s transportation commitments.
South Texas and Eagle Ford Shale
The Company’s drilling activities in the South Texas area during 2010 continue to be primarily focused on delineation and development of Pioneer’s substantial acreage position in the Eagle Ford Shale play. The Company is currently running seven drilling rigs in the Eagle Ford Shale play and plans to increase the Eagle Ford Shale rig count to 12 rigs in mid-2011, 14 rigs during 2012 and 16 rigs in 2013.
To improve the execution of the Company’s Eagle Ford Shale drilling program and reduce drilling costs, the Company has purchased two fracture stimulation fleets. One is expected to be in operation during the second quarter of 2011 and the other during the fourth quarter of 2011. The Company has also entered into a two-year contract for a dedicated third-party fracture stimulation fleet, which is expected to begin operations during the latter part of the first quarter of 2011. The Company is also pursuing opportunities to contract for other third-party fracture stimulation equipment.
During June 2010, the Company entered into an Eagle Ford Shale joint venture transaction. Pursuant to the transaction, the Company entered into a purchase and sale agreement to sell 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds, including normal closing adjustments. The terms of the transaction also provide that the purchaser will pay 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. The Company’s current expectations are that the purchaser’s obligation to pay 75 percent of the Company’s defined exploration, drilling and completion costs attributable to Eagle Ford Shale assets will be satisfied by mid-2013. The Company and its joint venture partners have drilled 41 Eagle Ford Shale wells, of which 21 wells have been completed and are producing, three wells are completed and awaiting connections to sales lines and 17 wells remain in progress awaiting limited third-party fracture stimulation fleet availability. The Company also sold a 49.9 percent member interest in EFS Midstream LLC (“EFS Midstream”), an entity formed by the Company to own and operate gathering facilities in the Eagle Ford Shale area, to the purchaser for $46.4 million of cash proceeds and deferred a $46.2 million associated net gain. The Company does not have voting control of EFS Midstream and does not consolidate its financial statements.
EFS Midstream is obligated to construct certain of the gathering, treating and transportation infrastructure in the Eagle Ford Shale area. As EFS Midstream constructs these midstream assets, the Company will be responsible for funding 50.1 percent of EFS Midstream’s cash requirements. Construction of the midstream assets is underway, with the majority of the construction expected to be completed by 2013. Three of the 14 planned facilities (“CGPs”) were completed as of December 31, 2010. EFS Midstream plans to build five additional CGPs during 2011, with the first two expected to be completed during March. As construction of CGPs is completed, EFS Midstream will provide gathering, treating and transportation services for the Company during a 20-year contractual period.
During the fourth quarter of 2010, the Company entered into contractual agreements with third parties to gather, transport, process and fractionate certain portions of the future oil, gas and NGLs produced and recovered from the Company’s Eagle Ford Shale properties. The Company entered into a ten year oil gathering agreement, under which the counterparty is obligated to build a 111-mile oil pipeline that will transport approximately 7,100 Bbls of oil per day in 2012, increasing to approximately 17,400 Bbls per day in 2017, and declining thereafter until the contract term ends in 2022. The Company has firm transportation commitments under this contract after the counterparty builds the pipeline.
34
PIONEER NATURAL RESOURCES COMPANY
The Company entered into two five-year gas transportation agreements, under which it is committed to provide approximately 20,600 Mcf per day of gas throughput from Eagle Ford Shale wells beginning in mid-2011. Transportation commitments under these agreements increase to approximately 88,600 Mcf per day in 2015 before terminating in mid-2016. All but 28,300 Mcf per day of the firm transportation commitments under these agreements is subject to a counterparty’s obligation to build infrastructure facilities.
The Company also entered into a ten-year contractual agreement with a third party for the transportation and processing of Eagle Ford Shale gas production and the fractionation of recovered NGLs. The firm transportation commitments under this agreement are for approximately 18,000 Mcf per day in 2011, increasing to approximately 170,000 Mcf per day in 2020; processing commitments under the agreement are for approximately 15,000 Mcf per day in 2011, increasing to approximately 139,000 Mcf per day in 2020; and, fractionation commitments under the agreement are for approximately 1,500 Bbls per day of NGLs in 2011, increasing to approximately 15,000 Bbls per day in 2020.
Barnett Shale
During 2010, the Company continued to increase its acreage position in the liquid-rich Barnett Shale Combo area in North Texas. In total, the Company has accumulated approximately 80,000 gross acres in the liquid-rich area of the field, representing over 600 potential drilling locations. During the fourth quarter of 2010, the Company commenced a two-rig drilling program in the play.
The Company’s total lease holdings in the Barnett Shale play now approximate 124,000 gross acres (97,000 net acres).
Alaska
The Company owns a 70 percent working interest and is the operator of the Oooguruk development project. The Company has drilled ten production wells and six injection wells of the estimated 17 production and 16 injection wells planned to fully develop this project. In addition, the Company drilled a horizontal exploration well in the Torok formation during 2010. Based on the performance to date, the Company plans to drill and fracture stimulate two additional Torok wells in 2011 to further evaluate the productivity of the formation and possibility of a future development project.
International
During 2010, the Company’s international operations were located offshore South Africa and in Tunisia. See Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the sale of the Company’s Tunisia subsidiaries during February 2011.
The following table summarizes the Company’s Tunisia exploration/extension and development drilling activities during 2010:
| Beginning Wells In Progress |
Wells Spud |
Successful Wells |
Unsuccessful Wells |
Ending Wells In Progress |
||||||||||||||||
| Exploration/extension drilling |
5 | 3 | 5 | — | 3 | |||||||||||||||
| Development drilling |
— | 4 | 3 | — | 1 | |||||||||||||||
| Total |
5 | 7 | 8 | — | 4 | |||||||||||||||
The following table summarizes the Company’s international average daily oil, NGL, gas and total production during 2010:
| Oil (Bbls) | NGLs (Bbls) | Gas (Mcf) | Total (BOE) | |||||||||||||
| South Africa |
616 | — | 29,760 | 5,576 | ||||||||||||
| Tunisia |
4,880 | — | 2,849 | 5,355 | ||||||||||||
| Total International |
5,496 | — | 32,609 | 10,931 | ||||||||||||
35
PIONEER NATURAL RESOURCES COMPANY
The following table summarizes the Company’s international costs incurred by geographic area during 2010:
| Property Acquisition Costs |
Exploration Costs |
Development Costs |
Asset Retirement Obligations |
Total | ||||||||||||||||||||
| Proved | Unproved | |||||||||||||||||||||||
| (in thousands) | ||||||||||||||||||||||||
| South Africa |
$ | — | $ | — | $ | 512 | $ | (53 | ) | $ | 1,835 | $ | 2,294 | |||||||||||
| Tunisia |
— | — | 30,630 | 39,053 | 820 | 70,503 | ||||||||||||||||||
| Other |
— | — | 329 | — | — | 329 | ||||||||||||||||||
| Total International |
$ | — | $ | — | $ | 31,471 | $ | 39,000 | $ | 2,655 | $ | 73,126 | ||||||||||||
South Africa
The Company has production and exploration agreements covering over 3.6 million acres offshore the southern coast of South Africa in water depths generally less than 650 feet. The Company’s initial discovery, Sable oil field, began producing in August 2003 and over its five-year life recovered approximately 23.6 million gross barrels of oil. During the life of the Sable oil field, the majority of the gas produced in conjunction with the oil production was injected back into the reservoir. The Company had a 40 percent working interest in the oil production from the Sable field.
In 2005, the Company sanctioned the non-operated South Coast Gas development project, which included a subsea tie-back of gas from the Sable field and five additional gas accumulations to an existing production facility on the F-A platform for transportation via existing pipelines to a gas-to-liquids plant. Pioneer has a 45 percent working interest in the project. As part of sanctioning of the South Coast Gas project, the Company signed a six-year contract for the sale of its gas and condensate production from the project. The contract contains an obligation for the purchaser to take or pay for a total of 91.4 Bcf and associated condensate if the anticipated deliverability estimates are achieved. The price for both gas and condensate is indexed to Dated Brent oil prices. First production from the South Coast Gas project was achieved in the third quarter of 2007.
A significant portion of the gas reserves associated with the South Coast Gas project is in the Sable field. In the third quarter of 2008, Sable oil production was shut in and operations to convert Sable’s gas injection well to a producing well commenced. Gas sales from the Sable gas well were initiated in mid-October 2008 and the other South Coast Gas wells resumed production in late-October. The Sable gas well is the most productive well in the South Coast Gas project.
Tunisia
The Company held interests in four separate onshore permits located in the southern portion of Tunisia. During February 2011, the Company completed the sale of 100 percent of its share holdings in its Tunisian subsidiaries for cash proceeds of $866 million, before normal closing adjustments. The Company’s Tunisian permits covered a gross area of approximately 12,740 square kilometers containing three production concessions targeting the Acacus formation with additional future upside exploration potential from this and other formations. See Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information about the divestiture of the Company’s Tunisian subsidiaries.
Selected Oil and Gas Information
The following tables set forth selected oil and gas information from continuing operations for the Company as of and for each of the years ended December 31, 2010, 2009 and 2008. Because of normal production declines, increased or decreased drilling activities and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.
Production, price and cost data. Oil and gas are commodities. The price that the Company receives for the oil and gas produced is largely a function of market supply and demand. Demand for oil and gas in the United States has increased dramatically during this decade. However, the economic slowdown reduced this demand during the second half of 2008 and through 2009. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or gas can result in substantial price volatility. Historically, commodity prices have been volatile and the Company expects that volatility to continue in the future. A substantial or extended decline in oil or gas prices or poor drilling results could have a material adverse effect on the Company’s financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and the Company’s ability to access capital markets.
36
PIONEER NATURAL RESOURCES COMPANY
The following tables set forth production, price and cost data with respect to the Company’s properties for 2010, 2009 and 2008. These amounts represent the Company’s historical results from continuing operations without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the respective years. The production amounts will not agree to the reserve volume tables in the “Unaudited Supplementary Information” section included in “Item 8. Financial Statements and Supplementary Data” due to field fuel volumes and production associated with completed divestitures (reflected as discontinued operations) being included in the reserve volume tables.
PRODUCTION, PRICE AND COST DATA
| Year Ended December 31, 2010 | ||||||||||||||||||||||||
| United States | South Africa |
Tunisia | Total | |||||||||||||||||||||
| Spraberry Field |
Raton Field |
Total | ||||||||||||||||||||||
| Production information: |
||||||||||||||||||||||||
| Annual sales volumes: |
||||||||||||||||||||||||
| Oil (MBbls) |
6,314 | — | 10,297 | 225 | 1,781 | 12,303 | ||||||||||||||||||
| NGLs (MBbls) |
3,725 | — | 7,203 | — | — | 7,203 | ||||||||||||||||||
| Gas (MMcf) |
14,242 | 62,311 | 122,369 | 10,862 | 1,040 | 134,271 | ||||||||||||||||||
| Total (MBOE) |
12,413 | 10,385 | 37,895 | 2,035 | 1,954 | 41,885 | ||||||||||||||||||
| Average daily sales volumes: |
||||||||||||||||||||||||
| Oil (Bbls) |
17,300 | — | 28,211 | 616 | 4,880 | 33,707 | ||||||||||||||||||
| NGLs (Bbls) |
10,206 | — | 19,736 | — | — | 19,736 | ||||||||||||||||||
| Gas (Mcf) |
39,020 | 170,716 | 335,256 | 29,760 | 2,849 | 367,865 | ||||||||||||||||||
| Total (BOE) |
34,009 | 28,453 | 103,823 | 5,576 | 5,355 | 114,754 | ||||||||||||||||||
| Average prices, including hedge results and amortization of deferred VPP revenue (a): |
||||||||||||||||||||||||
| Oil (per Bbl) |
$ | 91.53 | $ | — | $ | 90.56 | $ | 78.07 | $ | 78.42 | $ | 88.57 | ||||||||||||
| NGL (per Bbl) |
$ | 33.11 | $ | — | $ | 38.14 | $ | — | $ | — | $ | 38.14 | ||||||||||||
| Gas (per Mcf) |
$ | 3.41 | $ | 4.20 | $ | 4.18 | $ | 6.20 | $ | 11.25 | $ | 4.40 | ||||||||||||
| Revenue (per BOE) |
$ | 60.40 | $ | 25.19 | $ | 45.34 | $ | 41.74 | $ | 77.46 | $ | 46.67 | ||||||||||||
| Average prices, excluding hedge results and amortization of deferred VPP revenue (a): |
||||||||||||||||||||||||
| Oil (per Bbl) |
$ | 77.24 | $ | — | $ | 74.21 | $ | 78.07 | $ | 78.42 | $ | 74.89 | ||||||||||||
| NGL (per Bbl) |
$ | 33.11 | $ | — | $ | 37.12 | $ | — | $ | — | $ | 37.12 | ||||||||||||
| Gas (per Mcf) |
$ | 3.41 | $ | 4.20 | $ | 4.15 | $ | 6.20 | $ | 11.25 | $ | 4.37 | ||||||||||||
| Revenue (per BOE) |
$ | 53.14 | $ | 25.19 | $ | 40.61 | $ | 41.74 | $ | 77.46 | $ | 42.39 | ||||||||||||
| Average costs (per BOE): |
||||||||||||||||||||||||
| Production costs: |
||||||||||||||||||||||||
| Lease operating |
$ | 11.40 | $ | 6.11 | $ | 7.74 | $ | 0.68 | $ | 4.98 | $ | 7.28 | ||||||||||||
| Third-party transportation charges |
— | 2.35 | 0.87 | — | 1.50 | 0.86 | ||||||||||||||||||
| Net natural gas plant/gathering |
(1.66 | ) | 1.93 | 0.08 | — | — | 0.08 | |||||||||||||||||
| Workover |
1.88 | 0.07 | 0.92 | — | 0.36 | 0.85 | ||||||||||||||||||
| Total |
$ | 11.62 | $ | 10.46 | $ | 9.61 | $ | 0.68 | $ | 6.84 | $ | 9.07 | ||||||||||||
| Production and ad valorem taxes: |
||||||||||||||||||||||||
| Ad valorem |
$ | 2.30 | $ | 0.46 | $ | 1.49 | $ | — | $ | — | $ | 1.35 | ||||||||||||
| Production |
3.53 | 0.52 | 1.47 | — | — | 1.33 | ||||||||||||||||||
| Total |
$ | 5.83 | $ | 0.98 | $ | 2.96 | $ | — | $ | — | $ | 2.68 | ||||||||||||
| Depletion expense |
$ | 9.02 | $ | 14.39 | $ | 12.40 | $ | 36.50 | $ | 12.07 | $ | 13.56 | ||||||||||||
| (a) | The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its hedging activities at a field level. |
37
PIONEER NATURAL RESOURCES COMPANY
PRODUCTION, PRICE AND COST DATA - (Continued)
| Year Ended December 31, 2009 | ||||||||||||||||||||||||
| United States | South Africa |
Tunisia | Total | |||||||||||||||||||||
| Spraberry Field |
Raton Field |
Total | ||||||||||||||||||||||
| Production information: |
||||||||||||||||||||||||
| Annual sales volumes: |
||||||||||||||||||||||||
| Oil (MBbls) |
5,836 | — | 9,113 | 137 | 2,384 | 11,634 | ||||||||||||||||||
| NGLs (MBbls) |
3,454 | — | 7,183 | — | — | 7,183 | ||||||||||||||||||
| Gas (MMcf) |
15,313 | 67,991 | 128,753 | 9,321 | 609 | 138,683 | ||||||||||||||||||
| Total (MBOE) |
11,842 | 11,332 | 37,756 | 1,690 | 2,485 | 41,931 | ||||||||||||||||||
| Average daily sales volumes: |
||||||||||||||||||||||||
| Oil (Bbls) |
15,989 | — | 24,968 | 375 | 6,531 | 31,874 | ||||||||||||||||||
| NGLs (Bbls) |
9,461 | — | 19,680 | — | — | 19,680 | ||||||||||||||||||
| Gas (Mcf) |
41,954 | 186,278 | 352,749 | 25,538 | 1,668 | 379,955 | ||||||||||||||||||
| Total (BOE) |
32,443 | 31,046 | 103,440 | 4,631 | 6,809 | 114,880 | ||||||||||||||||||
| Average prices, including hedge results and amortization of deferred VPP revenue (a): |
||||||||||||||||||||||||
| Oil (per Bbl) |
$ | 73.12 | $ | — | $ | 75.60 | $ | 65.94 | $ | 60.98 | $ | 72.49 | ||||||||||||
| NGL (per Bbl) |
$ | 25.91 | $ | — | $ | 29.76 | $ | — | $ | — | $ | 29.76 | ||||||||||||
| Gas (per Mcf) |
$ | 2.84 | $ | 3.26 | $ | 3.88 | $ | 5.17 | $ | 8.14 | $ | 3.99 | ||||||||||||
| Revenue (per BOE) |
$ | 47.27 | $ | 19.59 | $ | 37.15 | $ | 33.85 | $ | 60.49 | $ | 38.40 | ||||||||||||
| Average prices, excluding hedge results and amortization of deferred VPP revenue (a): |
||||||||||||||||||||||||
| Oil (per Bbl) |
$ | 56.25 | $ | — | $ | 55.04 | $ | 65.94 | $ | 60.98 | $ | 56.38 | ||||||||||||
| NGL (per Bbl) |
$ | 25.91 | $ | — | $ | 28.45 | $ | — | $ | — | $ | 28.45 | ||||||||||||
| Gas (per Mcf) |
$ | 2.84 | $ | 3.26 | $ | 3.32 | $ | 5.17 | $ | 8.14 | $ | 3.47 | ||||||||||||
| Revenue (per BOE) |
$ | 38.96 | $ | 19.59 | $ | 30.02 | $ | 33.85 | $ | 60.49 | $ | 31.98 | ||||||||||||
| Average costs (per BOE): |
||||||||||||||||||||||||
| Production costs: |
||||||||||||||||||||||||
| Lease operating |
$ | 10.47 | $ | 5.14 | $ | 7.39 | $ | 3.26 | $ | 7.38 | $ | 7.22 | ||||||||||||
| Third-party transportation charges |
— | 2.39 | 0.95 | — | 1.69 | 0.96 | ||||||||||||||||||
| Net natural gas plant/gathering |
(1.23 | ) | 1.79 | 0.27 | — | — | 0.25 | |||||||||||||||||
| Workover |
1.30 | 0.10 | 0.55 | — | 2.58 | 0.65 | ||||||||||||||||||
| Total |
$ | 10.54 | $ | 9.42 | $ | 9.16 | $ | 3.26 | $ | 11.65 | $ | 9.08 | ||||||||||||
| Production and ad valorem taxes: |
||||||||||||||||||||||||
| Ad valorem |
$ | 2.10 | $ | 0.39 | $ | 1.51 | $ | — | $ | — | $ | 1.36 | ||||||||||||
| Production |
2.72 | 0.12 | 1.10 | — | — | 0.99 | ||||||||||||||||||
| Total |
$ | 4.82 | $ | 0.51 | $ | 2.61 | $ | — | $ | — | $ | 2.35 | ||||||||||||
| Depletion expense |
$ | 8.69 | $ | 18.19 | $ | 14.20 | $ | 38.33 | $ | 8.77 | $ | 14.85 | ||||||||||||
| (a) | The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its hedging activities at a field level. |
38
PIONEER NATURAL RESOURCES COMPANY
PRODUCTION, PRICE AND COST DATA - (Continued)
| Year Ended December 31, 2008 | ||||||||||||||||||||||||
| United States | South Africa |
Tunisia | Total | |||||||||||||||||||||
| Spraberry Field |
Raton Field |
Total | ||||||||||||||||||||||
| Production information: |
||||||||||||||||||||||||
| Annual sales volumes: |
||||||||||||||||||||||||
| Oil (MBbls) |
5,713 | — | 7,720 | 880 | 2,261 | 10,861 | ||||||||||||||||||
| NGLs (MBbls) |
2,981 | — | 6,971 | — | — | 6,971 | ||||||||||||||||||
| Gas (MMcf) |
14,069 | 72,386 | 134,248 | 3,745 | 866 | 138,859 | ||||||||||||||||||
| Total (MBOE) |
11,038 | 12,064 | 37,065 | 1,504 | 2,406 | 40,975 | ||||||||||||||||||
| Average daily sales volumes: |
||||||||||||||||||||||||
| Oil (Bbls) |
15,612 | — | 21,091 | 2,405 | 6,178 | 29,674 | ||||||||||||||||||
| NGLs (Bbls) |
8,141 | — | 19,048 | — | — | 19,048 | ||||||||||||||||||
| Gas (Mcf) |
38,440 | 197,775 | 366,796 | 10,232 | 2,367 | 379,395 | ||||||||||||||||||
| Total (BOE) |
30,161 | 32,963 | 101,271 | 4,110 | 6,573 | 111,954 | ||||||||||||||||||
| Average prices, including hedge results and amortization of deferred VPP revenue (a): |
||||||||||||||||||||||||
| Oil (per Bbl) |
$ | 117.10 | $ | — | $ | 65.74 | $ | 110.21 | $ | 90.64 | $ | 74.53 | ||||||||||||
| NGL (per Bbl) |
$ | 46.49 | $ | — | $ | 51.31 | $ | — | $ | — | $ | 51.31 | ||||||||||||
| Gas (per Mcf) |
$ | 6.33 | $ | 7.16 | $ | 7.66 | $ | 5.83 | $ | 12.04 | $ | 7.64 | ||||||||||||
| Revenue (per BOE) |
$ | 81.24 | $ | 42.95 | $ | 51.08 | $ | 79.00 | $ | 89.53 | $ | 54.36 | ||||||||||||
| Average prices, excluding hedge results and amortization of deferred VPP revenue (a): |
||||||||||||||||||||||||
| Oil (per Bbl) |
$ | 98.88 | $ | — | $ | 95.82 | $ | 110.21 | $ | 90.64 | $ | 95.91 | ||||||||||||
| NGL (per Bbl) |
$ | 46.49 | $ | — | $ | 51.56 | $ | — | $ | — | $ | 51.56 | ||||||||||||
| Gas (per Mcf) |
$ | 6.33 | $ | 7.16 | $ | 7.39 | $ | 5.83 | $ | 12.04 | $ | 7.37 | ||||||||||||
| Revenue (per BOE) |
$ | 71.81 | $ | 42.95 | $ | 56.41 | $ | 79.00 | $ | 89.53 | $ | 59.18 | ||||||||||||
| Average costs (per BOE): |
||||||||||||||||||||||||
| Production costs: |
||||||||||||||||||||||||
| Lease operating |
$ | 12.57 | $ | 5.16 | $ | 7.66 | $ | 25.98 | $ | 6.26 | $ | 8.26 | ||||||||||||
| Third-party transportation charges |
— | 2.56 | 1.06 | — | 1.93 | 1.07 | ||||||||||||||||||
| Net natural gas plant/gathering |
(2.73 | ) | 2.90 | 0.16 | — | — | 0.15 | |||||||||||||||||
| Workover |
2.61 | 0.09 | 0.93 | — | — | 0.84 | ||||||||||||||||||
| Total |
$ | 12.45 | $ | 10.71 | $ | 9.81 | $ | 25.98 | $ | 8.19 | $ | 10.32 | ||||||||||||
| Production and ad valorem taxes: |
||||||||||||||||||||||||
| Ad valorem |
$ | 2.31 | $ | 0.81 | $ | 1.58 | $ | — | $ | — | $ | 1.43 | ||||||||||||
| Production |
5.05 | 1.11 | 2.86 | — | — | 2.58 | ||||||||||||||||||
| Total |
$ | 7.36 | $ | 1.92 | $ | 4.44 | $ | — | $ | — | $ | 4.01 | ||||||||||||
| Depletion expense |
$ | 7.61 | $ | 12.90 | $ | 11.30 | $ | 18.37 | $ | 5.96 | $ | 11.25 | ||||||||||||
| (a) | The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its hedging activities at a field level. |
39
PIONEER NATURAL RESOURCES COMPANY
Productive wells. The following table sets forth the number of productive oil and gas wells attributable to the Company’s properties as of December 31, 2010, 2009 and 2008:
PRODUCTIVE WELLS (a)
| Gross Productive Wells | Net Productive Wells | |||||||||||||||||||||||
| Oil | Gas | Total | Oil | Gas | Total | |||||||||||||||||||
| As of December 31, 2010: |
||||||||||||||||||||||||
| United States |
5,533 | 4,836 | 10,369 | 4,769 | 4,347 | 9,116 | ||||||||||||||||||
| South Africa |
— | 6 | 6 | — | 3 | 3 | ||||||||||||||||||
| Tunisia |
33 | — | 33 | 10 | — | 10 | ||||||||||||||||||
| Total |
5,566 | 4,842 | 10,408 | 4,779 | 4,350 | 9,129 | ||||||||||||||||||
| As of December 31, 2009: |
||||||||||||||||||||||||
| United States |
5,332 | 5,021 | 10,353 | 4,566 | 4,604 | 9,170 | ||||||||||||||||||
| South Africa |
— | 6 | 6 | — | 3 | 3 | ||||||||||||||||||
| Tunisia |
29 | — | 29 | 9 | — | 9 | ||||||||||||||||||
| Total |
5,361 | 5,027 | 10,388 | 4,575 | 4,607 | 9,182 | ||||||||||||||||||
| As of December 31, 2008: |
||||||||||||||||||||||||
| United States |
5,374 | 4,988 | 10,362 | 4,561 | 4,685 | 9,246 | ||||||||||||||||||
| South Africa |
— | 6 | 6 | — | 3 | 3 | ||||||||||||||||||
| Tunisia |
28 | — | 28 | 8 | — | 8 | ||||||||||||||||||
| Total |
5,402 | 4,994 | 10,396 | 4,569 | 4,688 | 9,257 | ||||||||||||||||||
| (a) | Productive wells consist of producing wells and wells capable of production, including shut-in wells and gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. One or more completions in the same well bore are counted as one well. If any well in which one of the multiple completions is an oil completion, then the well is classified as an oil well. As of December 31, 2010, the Company owned interests in one gross well containing multiple completions. |
Leasehold acreage. The following table sets forth information about the Company’s developed, undeveloped and royalty leasehold acreage as of December 31, 2010:
LEASEHOLD ACREAGE
| Developed Acreage | Undeveloped Acreage | Royalty Acreage |
||||||||||||||||||
| Gross Acres | Net Acres | Gross Acres | Net Acres | |||||||||||||||||
| United States: |
||||||||||||||||||||
| Onshore |
1,501,102 | 1,287,560 | 796,549 | 622,091 | 297,599 | |||||||||||||||
| Offshore |
— | — | — | — | 5,000 | |||||||||||||||
| 1,501,102 | 1,287,560 | 796,549 | 622,091 | 302,599 | ||||||||||||||||
| South Africa |
119,579 | 53,281 | 3,508,421 | 1,578,789 | — | |||||||||||||||
| Tunisia |
297,424 | 83,009 | 2,645,012 | 1,930,582 | — | |||||||||||||||
| Total |
1,918,105 | 1,423,850 | 6,949,982 | 4,131,462 | 302,599 | |||||||||||||||
40
PIONEER NATURAL RESOURCES COMPANY
The following table sets forth the expiration dates of the leases on the Company’s gross and net undeveloped acres as of December 31, 2010:
| Acres Expiring (a) | ||||||||
| Gross | Net | |||||||
| 2011 (b) |
1,967,292 | 1,498,990 | ||||||
| 2012 |
1,000,166 | 673,954 | ||||||
| 2013 |
230,115 | 187,613 | ||||||
| 2014 |
77,121 | 65,997 | ||||||
| 2015 |
38,697 | 22,390 | ||||||
| Thereafter |
3,636,591 | 1,682,518 | ||||||
| Total |
6,949,982 | 4,131,462 | ||||||
| (a) | Acres expiring are based on contractual lease maturities. |
| (b) | All acres subject to expiration during 2011 are in North America. The Company may extend the leases prior to their expiration based upon 2011 planned activities or for other business reasons. In certain leases, the extension is only subject to the Company’s election to extend and the fulfillment of certain capital expenditures commitments. In other cases, the extensions are subject to the consent of third parties, and no assurance can be given that the requested extensions will be granted. See “Description of Properties” above for information regarding the Company’s drilling operations. |
Drilling and other exploratory and development activities. The following table sets forth the number of gross and net wells drilled by the Company during 2010, 2009 and 2008 that were productive or dry holes. This information should not be considered indicative of future performance, nor should it be assumed that there was any correlation between the number of productive wells drilled and the oil and gas reserves generated thereby or the costs to the Company of productive wells compared to the costs of dry holes.
DRILLING ACTIVITIES
| Gross Wells | Net Wells | |||||||||||||||||||||||
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||
| United States: |
||||||||||||||||||||||||
| Productive wells: |
||||||||||||||||||||||||
| Development |
433 | 60 | 526 | 378 | 58 | 504 | ||||||||||||||||||
| Exploratory |
34 | 13 | 56 | 22 | 7 | 46 | ||||||||||||||||||
| Dry holes: |
||||||||||||||||||||||||
| Development |
3 | — | 7 | 3 | — | 7 | ||||||||||||||||||
| Exploratory |
3 | 2 | 17 | 1 | 2 | 9 | ||||||||||||||||||
| 473 | 75 | 606 | 404 | 67 | 566 | |||||||||||||||||||
| Tunisia: |
||||||||||||||||||||||||
| Productive wells: |
||||||||||||||||||||||||
| Development |
3 | 1 | — | 2 | — | — | ||||||||||||||||||
| Exploratory |
5 | — | 6 | 2 | — | 3 | ||||||||||||||||||
| Dry holes: |
||||||||||||||||||||||||
| Development |
— | — | — | — | — | — | ||||||||||||||||||
| Exploratory |
— | 2 | 2 | — | 1 | 1 | ||||||||||||||||||
| 8 | 3 | 8 | 4 | 1 | 4 | |||||||||||||||||||
| Total |
481 | 78 | 614 | 408 | 68 | 570 | ||||||||||||||||||
| Success ratio (a) |
99 | % | 95 | % | 96 | % | 99 | % | 96 | % | 97 | % | ||||||||||||
| (a) | Represents the ratio of those wells that were successfully completed as producing wells or wells capable of producing to total wells drilled and evaluated. |
41
PIONEER NATURAL RESOURCES COMPANY
Present activities. The following table sets forth information about the Company’s wells that were in process of being drilled as of December 31, 2010:
| Gross Wells | Net Wells | |||||||
| United States: |
||||||||
| Development |
23 | 22 | ||||||
| Exploratory |
38 | 25 | ||||||
| Total |
61 | 47 | ||||||
| Tunisia: |
||||||||
| Development |
1 | 1 | ||||||
| Exploratory |
3 | 2 | ||||||
| 4 | 3 | |||||||
| Total |
65 | 50 | ||||||
| ITEM 3. | LEGAL PROCEEDINGS |
The Company is party to the legal proceedings that are described under “Legal actions” in Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.” The Company is also party to other proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations.
| ITEM 4. | REMOVED AND RESERVED |
42
PIONEER NATURAL RESOURCES COMPANY
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
The Company’s common stock is listed and traded on the NYSE under the symbol “PXD.” The Board declared dividends to the holders of the Company’s common stock totaling $.08 per share during the first and third quarters of each of the years ended December 31, 2010 and 2009, respectively.
The following table sets forth quarterly high and low prices of the Company’s common stock and dividends declared per share for the years ended December 31, 2010 and 2009:
| High | Low | Dividends Declared Per Share |
||||||||||
| Year ended December 31, 2010 |
||||||||||||
| Fourth quarter |
$ | 88.00 | $ | 64.97 | $ | — | ||||||
| Third quarter |
$ | 67.77 | $ | 54.89 | $ | 0.04 | ||||||
| Second quarter |
$ | 74.00 | $ | 54.72 | $ | — | ||||||
| First quarter |
$ | 56.88 | $ | 41.88 | $ | 0.04 | ||||||
| Year ended December 31, 2009 |
||||||||||||
| Fourth quarter |
$ | 50.00 | $ | 33.49 | $ | — | ||||||
| Third quarter |
$ | 36.74 | $ | 21.78 | $ | 0.04 | ||||||
| Second quarter |
$ | 30.56 | $ | 15.67 | $ | — | ||||||
| First quarter |
$ | 20.44 | $ | 11.88 | $ | 0.04 | ||||||
On February 23, 2011, the last reported sales price of the Company’s common stock, as reported in the NYSE composite transactions, was $100.67 per share.
As of February 23, 2011, the Company’s common stock was held by approximately 16,500 holders of record.
On February 17, 2011, the Board declared a cash dividend of $.04 per share on the Company’s outstanding common stock. The dividend is payable April 14, 2011 to stockholders of record at the close of business on March 31, 2011.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes the Company’s purchases of treasury stock during the three months ended December 31, 2010:
| Period |
Total Number of Shares (or Units) Purchased (a) |
Average Price Paid per Share (or Unit) |
Total Number of
Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs |
Approximate Dollar Amount of Shares that May Yet Be Purchased under Plans or Programs |
||||||||||||
| October 2010 |
334 | $ | 65.12 | — | ||||||||||||
| November 2010 |
1,481 | $ | 80.12 | — | ||||||||||||
| December 2010 |
1,524 | $ | 80.11 | — | ||||||||||||
| Total |
3,339 | $ | 78.61 | — | $ | 355,789,018 | ||||||||||
| (a) | Consists of shares withheld to satisfy tax withholding on employees’ share-based awards. |
During 2007, the Board approved a share repurchase program authorizing the purchase of up to $750 million of the Company’s common stock, of which $355.8 million remains available. During 2010, the Company did not repurchase any common stock pursuant to the 2007 program.
43
PIONEER NATURAL RESOURCES COMPANY
| ITEM 6. | SELECTED FINANCIAL DATA |
The following selected consolidated financial data of the Company as of and for each of the five years ended December 31, 2010 should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data.”
| Year Ended December 31, | ||||||||||||||||||||
| 2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
| (in millions, except per share data) | ||||||||||||||||||||
| Statements of Operations Data: |
||||||||||||||||||||
| Oil and gas revenues (a) |
$ | 1,803.3 | $ | 1,459.7 | $ | 2,012.2 | $ | 1,589.0 | $ | 1,334.1 | ||||||||||
| Total revenues (b) |
$ | 2,471.6 | $ | 1,347.7 | $ | 2,046.0 | $ | 1,615.1 | $ | 1,342.7 | ||||||||||
| Total costs and expenses |
$ | 1,683.1 | $ | 1,595.1 | $ | 1,745.2 | $ | 1,344.3 | $ | 1,117.5 | ||||||||||
| Income (loss) from continuing operations |
$ | 516.2 | $ | (159.2 | ) | $ | 186.9 | $ | 202.7 | $ | 123.9 | |||||||||
| Income (loss) from discontinued operations, net of tax (c) |
$ | 129.8 | $ | 116.9 | $ | 44.8 | $ | 169.7 | $ | 613.6 | ||||||||||
| Net income (loss) attributable to common stockholders |
$ | 605.2 | $ | (52.1 | ) | $ | 210.0 | $ | 372.7 | $ | 739.7 | |||||||||
| Income (loss) from continuing operations per share: |
||||||||||||||||||||
| Basic |
$ | 4.04 | $ | (1.48 | ) | $ | 1.38 | $ | 1.64 | $ | 0.92 | |||||||||
| Diluted |
$ | 3.99 | $ | (1.48 | ) | $ | 1.38 | $ | 1.63 | $ | 0.90 | |||||||||
| Net income (loss) attributable to common stockholders per share: |
||||||||||||||||||||
| Basic |
$ | 5.14 | $ | (0.46 | ) | $ | 1.76 | $ | 3.05 | $ | 5.85 | |||||||||
| Diluted |
$ | 5.08 | $ | (0.46 | ) | $ | 1.76 | $ | 3.04 | $ | 5.75 | |||||||||
| Dividends declared per share |
$ | 0.08 | $ | 0.08 | $ | 0.30 | $ | 0.27 | $ | 0.25 | ||||||||||
| Balance Sheet Data (as of December 31): |
||||||||||||||||||||
| Total assets |
$ | 9,679.1 | $ | 8,867.3 | $ | 9,161.8 | $ | 8,617.0 | $ | 7,355.4 | ||||||||||
| Long-term obligations |
$ | 4,683.9 | $ | 4,653.0 | $ | 4,787.2 | $ | 4,568.1 | $ | 3,469.4 | ||||||||||
| Total stockholders’ equity |
$ | 4,226.0 | $ | 3,643.0 | $ | 3,679.6 | $ | 3,054.7 | $ | 2,999.0 | ||||||||||
| (a) | The Company’s oil and gas revenues for 2010, as compared to those of 2009, increased by $343.6 million (or 24 percent) due to increases in worldwide commodity prices and United States oil and NGL sales volumes, partially offset by decreases in United States and South Africa gas sales volumes. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for discussions about oil and gas revenues and factors impacting the comparability of such revenues. |
| (b) | The Company recognized $448.4 million of net derivative gains in its total revenues of 2010, including $364.4 million of noncash MTM gains as compared to $195.6 million of net derivative losses during 2009, including $191.6 million of noncash MTM losses. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Notes B and I of Notes to Consolidated Financial Statements included in “Item 8 Financial Statements and Supplementary Data” for information about the Company’s derivative contracts and associated accounting methods. The Company also recognized $138.9 million of net hurricane activity gains during 2010, primarily associated with East Cameron 322 insurance recoveries, as compared to $17.3 million of net hurricane activity charges during 2009. See Note T of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information about the East Cameron 322 project. |
| (c) | During February 2011, the Company sold 100 percent of its share holdings in its Tunisian subsidiaries, pursuant to a plan committed to during 2010. In accordance with GAAP, the Company has classified the Tunisia results of operations as discontinued operations, rather than a component of continuing operations. During 2010, the Company received $35.3 million of interest on excess royalties paid on oil and gas production from its deepwater Gulf of Mexico properties during the period from January 1, 2003 through December 31, 2005. During 2009, the Company recorded $119.3 million of pretax income for the recovery of the excess royalties previously mentioned and a $17.5 million pretax gain, primarily from the sale of substantially all of its Gulf of Mexico shelf properties. The Company’s Gulf of Mexico shelf and deepwater properties were sold effective July 1, 2009 and January 1, 2006, respectively. The results of operations of these properties, and certain other properties sold during the periods presented are classified as discontinued operations in accordance with GAAP. See Notes B and U of Notes to Consolidated Financial Statements included in “Item 8 Financial Statements and Supplementary Data” for more information about the Company’s discontinued operations. |
44
PIONEER NATURAL RESOURCES COMPANY
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Financial and Operating Performance
Pioneer’s financial and operating performance for 2010 included the following highlights:
| • | Earnings attributable to common stockholders was $605.2 million ($5.08 per diluted share), as compared to a net loss attributable to common stockholders of $52.1 million ($0.46 per diluted share) in 2009. The increase in earnings attributable to common stockholders is primarily due to: |
| • | A $343.6 million pretax increase in oil and gas revenues as a result of commodity price increases; |
| • | A $644.0 million pretax increase in net derivative gains, primarily due to decreases in future commodity prices, principally gas prices, relative to the contract prices in the Company’s derivative position portfolio at December 31, 2010; |
| • | A $156.2 million increase in net hurricane activity gains during 2010, primarily attributable to East Cameron 322 reclamation and abandonment insurance recoveries; and |
| • | A $54.8 million pretax decrease in depreciation, depletion and amortization (“DD&A”) expense, primarily due to increases in proved reserves from the Company’s 2010 capital program and positive price revisions as a result of higher average commodity prices during 2010 as compared to 2009; partially offset by: |
| • | A $33.8 million increase in general and administrative expenses due to increases in performance-related compensation expenses and staffing increases to support the Company’s increased activity level; and |
| • | A $13.8 million increase in production and ad valorem taxes due to the increase in commodity prices. |
| • | Daily sales volumes from continuing operations increased on a BOE basis by one percent to 109,399 BOEPD during 2010, as compared to 108,071 BOEPD during 2009. |
| • | Average reported oil, NGL and gas prices from continuing operations increased during 2010 to $90.29 per Bbl, $38.14 per Bbl and $4.34 per Mcf, respectively, as compared to respective prices of $75.45 per Bbl, $29.76 per Bbl and $3.97 per Mcf during 2009. |
| • | Average oil and gas production costs and total ad valorem and production taxes per BOE from continuing operations increased during 2010 to $9.17 and $2.81, respectively, as compared to respective per BOE costs of $8.90 and $2.49 during 2009, primarily as a result of inflation of well servicing costs, increased workover expenditures and higher commodity prices. |
| • | Net cash provided by operating activities increased by $742.0 million, or 137 percent, to $1.3 billion for 2010, as compared to $543.1 million in 2009, primarily due to the increase in commodity prices, an increase in cash derivative gains and working capital changes. |
| • | Long-term debt was reduced by $159.3 million and cash balances increased by $83.8 million during 2010. |
| • | During June 2010, the Company entered into an Eagle Ford Shale joint venture transaction. Pursuant to the transaction, the Company entered into a purchase and sale agreement to sell 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds, including normal closing adjustments. Under the terms of the transaction, the purchaser is also paying 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. The Company’s current expectations are that the purchaser’s obligation to pay 75 percent of the Company’s defined exploration, drilling and completion costs attributable to Eagle Ford Shale assets will be satisfied by mid-2013. |
| • | In conjunction with the Eagle Ford Shale joint venture transaction, the Company also sold a 49.9 percent member interest in its subsidiary EFS Midstream LLC (“EFS Midstream”) to the purchaser for $46.4 million of cash proceeds and deferred a $46.2 million associated net gain. After the sale, the Company no longer has voting control of EFS Midstream. The Company no longer consolidates the financial statements of EFS Midstream and is accounting for its investment in the venture under the equity method. |
45
PIONEER NATURAL RESOURCES COMPANY
| • | During December 2010, the Company committed to a plan to sell its Tunisian assets and liabilities and during February 2011 sold 100 percent of the Company’s share holdings in its Tunisian subsidiaries for $866 million, before normal closing adjustments. Accordingly, the Company has classified its Tunisian assets and liabilities as discontinued operations held for sale as of December 31, 2010, and has classified its historic Tunisian revenues and expenses as income from discontinued operations in the accompanying consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” |
The Company’s first quarter of 2011 outlook below does not reflect the effects of recent weather-related downtime and associated repairs in several of Pioneer’s operating areas.
The Company expects that first quarter 2011 production will average 114 to 118 BOEPD, reflecting increased 2011 drilling activity and the expiration at December 31, 2010 of one of the Company’s VPP obligations.
First quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $11.75 to $13.75 per BOE, based on current NYMEX strip prices for oil, NGLs and gas. DD&A expense is expected to average $13.50 to $15.00 per BOE.
Total exploration and abandonment expense for the quarter is expected to be $25 million to $35 million. General and administrative expense is expected to be $45 million to $49 million. Interest expense is expected to be $44 million to $47 million, and other expense is expected to be $20 million to $25 million. Accretion of discount on asset retirement obligations from continuing operations is expected to be $2 million to $4 million.
Noncontrolling interest in consolidated subsidiaries’ net income, excluding noncash derivative MTM adjustments, is expected to be $9 million to $12 million, primarily reflecting the public ownership in Pioneer Southwest.
The Company’s first quarter effective income tax rate from continuing operations is expected to range from 35 percent to 45 percent, assuming current capital spending plans and no significant derivative MTM changes in the Company’s derivative position. Cash income taxes are expected to be $5 million to $10 million, principally related to South African income taxes.
Pioneer’s capital program for 2011 totals $1.8 billion, consisting of $1.6 billion for drilling operations and $0.2 billion for vertical integration and facilities. The 2011 budget excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical general and administrative expense.
The 2011 drilling capital of $1.6 billion continues to be focused on oil- and liquids-rich drilling, with 75 percent of the capital allocated to the Spraberry field and Eagle Ford Shale plays. Following is a breakdown of the forecasted spending by asset area:
| • | Spraberry field – $1.1 billion; |
| • | Eagle Ford Shale – $110 million (reflecting 25 percent of anticipated 2011 drilling costs, with the remaining 75 percent to be funded by a contractual drilling carry benefit); |
| • | Barnett Shale Combo play – $170 million; |
| • | Alaska – $115 million; and |
| • | Other areas –$120 million, including land capital for existing assets. |
Funds for the expansion of Pioneer’s integrated well service operations in the Spraberry field, the establishment of similar services in the Eagle Ford Shale and Barnett Shale Combo plays, and the build-out of facilities to support vertical integration (such as yards, buildings and shops) are budgeted at $200 million in 2011.
The 2011 capital budget is expected to be funded from forecasted operating cash flow and by redeploying a portion of the proceeds from the sale of the Company’s Tunisian subsidiaries (see Divestitures, below).
46
PIONEER NATURAL RESOURCES COMPANY
During 2010, 2009 and 2008, the Company spent approximately $181.6 million, $88.9 million and $137.6 million, respectively, to acquire proved and unproved properties. The 2010 acquisitions primarily increased the Company’s acreage positions in the South Texas Eagle Ford Shale play, Barnett Shale play and West Texas Spraberry field. The 2009 acquisitions primarily increased the Company’s acreage positions in the South Texas Eagle Ford Shale play. The 2008 acquisitions primarily added proved reserves and increased the Company’s acreage positions in the Spraberry field, South Texas Edwards Trend and Barnett Shale play.
Tunisian Subsidiaries. As referred to in Financial and Operating Performance above, the Company committed to a plan to sell its Tunisian subsidiaries during December 2010 and in February 2011 sold 100 percent of its share holdings in its Tunisian subsidiaries for cash proceeds of $866 million, before normal closing adjustments (see Notes B and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” and “Divestitures,” below).
Eagle Ford Shale. In June 2010, the Company entered into an Eagle Ford Shale joint venture. Associated therewith, the Company sold 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds, including normal closing adjustments. Under the terms of the transaction, the purchaser is also paying 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. The Company’s current expectations are that the purchaser’s obligation to pay 75 percent of the Company’s defined exploration, drilling and completion costs attributable to Eagle Ford Shale assets will be satisfied by mid-2013.
Uinta/Piceance. During the first half of 2010, the Company sold certain proved and unproved oil and gas properties in the Uinta/Piceance area for net proceeds of $11.8 million and the assumption of certain asset retirement obligations, resulting in a pretax gain of $17.3 million.
Mississippi and Gulf of Mexico Shelf. In June and August 2009, the Company sold its Mississippi and shelf properties in the Gulf of Mexico, respectively, for aggregate net proceeds of $23.6 million, resulting in a pretax gain of $17.5 million. The historical results of these assets and the related gain on disposition are reported as discontinued operations.
Oil and gas revenues. Oil and gas revenues totaled $1.8 billion, $1.5 billion and $2.0 billion during 2010, 2009 and 2008, respectively.
The increase in 2010 oil and gas revenues relative to 2009 was due to commodity price increases and the increase in production. In the United States, the Company’s 2010 average reported oil, NGL and gas prices increased 20 percent, 28 percent and nine percent, respectively, as compared to 2009, and average daily sales volumes, on a BOE basis, during 2010 were one percent higher than 2009. In South Africa, the Company’s 2010 average reported oil and gas prices increased 18 percent and 20 percent, respectively, as compared to 2009, and average daily sales volumes, on a BOE basis, increased 20 percent during 2010, as compared to 2009.
The decrease in 2009 oil and gas revenues relative to 2008 was due to commodity price declines during 2009 and a reduction in production from fewer new wells drilled due to cost reduction initiatives implemented during 2008 and 2009. In the United States, the Company’s 2009 average reported NGL and gas prices declined 42 percent and 49 percent, respectively, as compared to 2008. These 2009 declines were partially offset by a 15 percent increase in the 2009 average reported oil price and a two percent increase in 2009 average daily sales volumes, on a BOE basis, as compared to 2008. In South Africa, the Company’s average reported oil and gas prices in 2009 decreased 40 percent and 11 percent, respectively, partially offset by a 13 percent increase in average daily sales volumes, on a BOE basis, as compared to 2008.
47
PIONEER NATURAL RESOURCES COMPANY
The following table provides average daily sales volumes from continuing operations by geographic area and in total for 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Oil (Bbls): |
||||||||||||
| United States |
28,211 | 24,968 | 21,091 | |||||||||
| South Africa |
616 | 375 | 2,405 | |||||||||
| Worldwide |
28,827 | 25,343 | 23,496 | |||||||||
| NGLs (Bbls): |
||||||||||||
| United States |
19,736 | 19,680 | 19,048 | |||||||||
| Gas (Mcf): |
||||||||||||
| United States |
335,256 | 352,749 | 366,796 | |||||||||
| South Africa |
29,760 | 25,538 | 10,232 | |||||||||
| Worldwide |
365,016 | 378,287 | 377,028 | |||||||||
| Total (BOE): |
||||||||||||
| United States |
103,823 | 103,440 | 101,271 | |||||||||
| South Africa |
5,576 | 4,631 | 4,110 | |||||||||
| Worldwide |
109,399 | 108,071 | 105,381 | |||||||||
During the year ended December 31, 2010, oil and gas volumes delivered under the Company’s VPP agreements decreased by 43 percent, as compared to 2009. During the year ended December 31, 2009, oil and gas volumes delivered under the Company’s VPP agreements decreased by seven percent, as compared to 2008. The Company completed its obligations to deliver gas volumes at the end of 2009 and completed oil delivery obligations under one of the VPP agreements at the end of 2010. As a result, oil volumes delivered under the VPP agreements will decline by 45 percent during 2011 as compared to 2010. The Company’s oil delivery obligations under its only remaining VPP agreement will be completed at the end of 2012.
The following table provides average daily sales volumes from discontinued operations by geographic area and in total during 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Oil (Bbls): |
||||||||||||
| United States |
— | 554 | 953 | |||||||||
| Tunisia |
4,880 | 6,531 | 6,178 | |||||||||
| Worldwide |
4,880 | 7,085 | 7,131 | |||||||||
| NGLs (Bbls): |
||||||||||||
| United States |
— | 29 | 35 | |||||||||
| Gas (Mcf): |
||||||||||||
| United States |
— | 1,899 | 3,428 | |||||||||
| Tunisia |
2,849 | 1,668 | 2,367 | |||||||||
| Worldwide |
2,849 | 3,567 | 5,795 | |||||||||
| Total (BOE): |
||||||||||||
| United States |
— | 900 | 1,559 | |||||||||
| Tunisia |
5,355 | 6,809 | 6,573 | |||||||||
| Worldwide |
5,355 | 7,709 | 8,132 | |||||||||
48
PIONEER NATURAL RESOURCES COMPANY
The following table provides average reported prices from continuing operations, including recorded commodity hedge gains and losses and the amortization of VPP deferred revenue, and average realized prices from continuing operations, excluding recorded commodity hedge gains and losses and the amortization of VPP deferred revenue, by geographic area and in total for 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Average reported prices: |
||||||||||||
| Oil (per Bbl): |
||||||||||||
| United States |
$ | 90.56 | $ | 75.60 | $ | 65.74 | ||||||
| South Africa |
$ | 78.07 | $ | 65.94 | $ | 110.21 | ||||||
| Worldwide |
$ | 90.29 | $ | 75.45 | $ | 70.29 | ||||||
| NGL (per Bbl): |
||||||||||||
| United States |
$ | 38.14 | $ | 29.76 | $ | 51.31 | ||||||
| Gas (per Mcf): |
||||||||||||
| United States |
$ | 4.18 | $ | 3.88 | $ | 7.66 | ||||||
| South Africa |
$ | 6.20 | $ | 5.17 | $ | 5.83 | ||||||
| Worldwide |
$ | 4.34 | $ | 3.97 | $ | 7.61 | ||||||
| Total (per BOE): |
||||||||||||
| United States |
$ | 45.34 | $ | 37.15 | $ | 51.08 | ||||||
| South Africa |
$ | 41.74 | $ | 33.85 | $ | 79.00 | ||||||
| Worldwide |
$ | 45.16 | $ | 37.00 | $ | 52.17 | ||||||
| Average realized prices: |
||||||||||||
| Oil (per Bbl): |
||||||||||||
| United States |
$ | 74.21 | $ | 55.04 | $ | 95.82 | ||||||
| South Africa |
$ | 78.07 | $ | 65.94 | $ | 110.21 | ||||||
| Worldwide |
$ | 74.30 | $ | 55.20 | $ | 95.84 | ||||||
| NGL (per Bbl): |
||||||||||||
| United States |
$ | 37.12 | $ | 28.45 | $ | 51.56 | ||||||
| Gas (per Mcf): |
||||||||||||
| United States |
$ | 4.15 | $ | 3.32 | $ | 7.39 | ||||||
| South Africa |
$ | 6.20 | $ | 5.17 | $ | 5.83 | ||||||
| Worldwide |
$ | 4.31 | $ | 3.45 | $ | 7.37 | ||||||
| Total (per BOE): |
||||||||||||
| United States |
$ | 40.61 | $ | 30.02 | $ | 56.41 | ||||||
| South Africa |
$ | 41.74 | $ | 33.85 | $ | 79.00 | ||||||
| Worldwide |
$ | 40.67 | $ | 30.19 | $ | 57.07 | ||||||
Derivative activities. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts in order to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts. Changes in the fair value of effective cash flow hedges prior to the Company’s discontinuance of hedge accounting were recorded as a component of accumulated other comprehensive income – deferred hedge gains, net of tax (“AOCI – Hedging”), in the stockholders’ equity section of the Company’s consolidated balance sheets, and are being transferred to earnings during the same periods in which the hedged transactions are recognized in the Company’s earnings. Since February 1, 2009, the Company has recognized all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.
49
PIONEER NATURAL RESOURCES COMPANY
The following table summarizes the transfers of deferred hedge gains and losses associated with oil, NGL and gas cash flow hedges from AOCI – Hedging to oil, NGL and gas revenues for the years ending December 31, 2010, 2009 and 2008 (in thousands):
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Increase (decrease) to oil revenue from AOCI—Hedging transfers |
$ | 78,052 | $ | 88,873 | $ | (336,249 | ) | |||||
| Increase (decrease) to NGL revenue from AOCI—Hedging transfers |
7,297 | 9,402 | (1,781 | ) | ||||||||
| Increase (decrease) to gas revenue from AOCI—Hedging transfers |
3,691 | 22,791 | (17,533 | ) | ||||||||
| Total |
$ | 89,040 | $ | 121,066 | $ | (355,563 | ) | |||||
See Note I of Notes to Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data” for further information concerning the Company’s commodity derivatives and scheduled amortization of net deferred gains and losses on discontinued commodity hedges that will be recognized as increases or decreases to future oil and gas revenues.
Deferred revenue. During 2010, the Company’s amortization of deferred VPP revenue increased annual oil revenues by $90.2 million and, during 2009 and 2008, increased oil and gas revenues by $147.9 million and $158.1 million, respectively. The Company’s amortization of deferred VPP revenue will increase 2011 annual oil revenues by $45.0 million. See Note S of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for specific information regarding the Company’s VPP agreements.
Interest and other income. The Company’s interest and other income from continuing operations totaled $61.9 million, $101.7 million and $56.5 million during 2010, 2009 and 2008, respectively. The $39.8 million decrease during 2010, as compared to 2009, is primarily attributable to (i) a $47.3 million decrease in Alaskan Petroleum Production Tax (“PPT”) credit recoveries and (ii) increases of $2.2 million, $1.7 million, $1.2 million, and $1.8 million in interest income, insurance recoveries, retirement obligation revaluation and carbon dioxide revenues, respectively. The $45.2 million increase during 2009, as compared to 2008, is primarily attributable to (i) a $76.4 million increase in PPT credit dispositions, partially offset by (ii) a $20.5 million 2008 gain on early extinguishment of debt and (iii) a $6.6 million decrease in foreign exchange gains.
At December 31, 2010, the Company had $27.5 million of available PPT-related carryforwards that were reimbursed in cash during February 2011. The Company anticipates recognizing future benefits from the PPT-related carryforwards from (i) reductions in PPT liabilities or (ii) reimbursement directly from the State of Alaska.
Derivative gains (losses), net. The following table summarizes the Company’s net derivative gains (losses) for the years ending December 31, 2010, 2009 and 2008 (in thousands):
| December 31, 2010 |
December 31, 2009 |
December 31, 2008 |
||||||||||
| Unrealized mark-to-market changes in fair value: |
||||||||||||
| Oil derivative gains (losses) |
$ | 41,094 | $ | (150,799 | ) | $ | (18,566 | ) | ||||
| NGL derivative gains (losses) |
10,690 | (20,206 | ) | 7 | ||||||||
| Gas derivative gains (losses) |
277,585 | (6,612 | ) | 8,405 | ||||||||
| Interest rate derivative gains (losses) |
35,040 | (13,928 | ) | — | ||||||||
| Total unrealized mark-to-market derivative gains (losses), net (a) |
364,409 | (191,545 | ) | (10,154 | ) | |||||||
| Cash settled changes in fair value: |
||||||||||||
| Oil derivative losses |
(27,305 | ) | (60,604 | ) | (1,479 | ) | ||||||
| NGL derivative losses |
(7,180 | ) | (8,340 | ) | — | |||||||
| Gas derivative gains |
119,417 | 66,428 | 1,485 | |||||||||
| Interest rate derivative losses |
(907 | ) | (1,496 | ) | — | |||||||
| Total cash derivative gains (losses), net |
84,025 | (4,012 | ) | 6 | ||||||||
| Total derivative gains (losses), net |
$ | 448,434 | $ | (195,557 | ) | $ | (10,148 | ) | ||||
| (a) | Unrealized mark-to-market changes in fair value are subject to continuing market risk. |
Gain (loss) on disposition of assets. The Company recorded net gains on the disposition of assets of $19.1 million during 2010 and net losses of $774 thousand and $381 thousand in 2009 and 2008, respectively.
During 2010, the Company recorded a $17.3 million net gain associated with the sale of proved and unproved oil and gas properties in the Uinta/Piceance area and a $6.0 million net gain associated with the Eagle Ford Shale joint venture transaction, partially offset by net losses primarily associated with the sale of excess lease and well equipment inventory.
The Company used the net cash proceeds from asset divestitures during 2010, 2009 and 2008, together with net cash flows provided by operating activities, to fund additions to oil and gas properties, stock repurchase programs and to reduce outstanding indebtedness. See Notes M and U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s asset divestitures and discontinued operations.
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PIONEER NATURAL RESOURCES COMPANY
Hurricane activity, net. The Company recorded net hurricane activity gains of $138.9 during 2010 and recorded net hurricane activity expenses of $17.3 million and $12.2 million during 2009 and 2008, respectively.
As a result of Hurricane Rita in September 2005, the Company’s East Cameron 322 facility, located on the Gulf of Mexico shelf, was completely destroyed. Operations to reclaim and abandon the East Cameron 322 facility began in 2006 and are substantially complete. The Company estimates that it will expend approximately $2.5 million during 2011 to complete the operations to reclaim and abandon the East Cameron 322 facility.
In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues for the cost of reclamation and abandonment of the East Cameron 322 facility. During the fourth quarter of 2010, the Company and the insurance carriers agreed to settle the insurance policy dispute, resulting in an additional payment to the Company of $140 million during November 2010. Since 2005, the Company has recovered from its insurance providers (i) $199.8 million attributable to reclamation and abandonment costs incurred, (ii) $18.0 million related to business interruption and property damage losses and (iii) $3.0 million of reimbursed interest costs. See Note T of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for specific information regarding the Company’s East Cameron platform facilities reclamation and abandonment.
Oil and gas production costs. The Company’s oil and gas production costs totaled $366.1 million, $351.4 million and $402.9 million during 2010, 2009 and 2008, respectively. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company’s gas, reduced by net revenues earned from gathering and processing of third party gas in Company-owned facilities.
During 2010, total production costs per BOE increased by three percent as compared to 2009. The increase in United States production costs per BOE is primarily due to inflation in well servicing costs and increases in workover expenditures incurred to mitigate production declines, partially offset by the expiration of one of the Company’s VPP delivery commitments. South Africa production costs per BOE decreased during 2010 due to continuing efficiencies being realized in South Coast Gas project operations, $1.4 million of production cost refunds received for operator overbills and the effects of higher sales volumes on the fixed components of South Africa production costs.
Total production costs per BOE decreased during 2009 by 15 percent as compared to 2008. During 2008, the Company’s oil and gas production costs increased throughout the first nine months of the year, primarily due to inflation of well servicing expense, electricity expense and water hauling costs. As a result of the Company’s cost reduction initiatives that were started in late 2008 and continued in 2009, Pioneer realized significant production cost reductions in 2009, as compared to 2008. The decrease in South Africa production costs was directly attributable to the shut in of the Sable oil field, which had a high fixed-cost component of production costs as compared to the South Coast Gas project, which has significantly lower production costs.
The following tables provide the components of the Company’s total production costs per BOE and total production costs per BOE by geographic area for 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Lease operating expenses |
$ | 7.39 | $ | 7.21 | $ | 8.38 | ||||||
| Third-party transportation charges |
0.83 | 0.91 | 1.02 | |||||||||
| Net natural gas plant/gathering charges |
0.08 | 0.26 | 0.16 | |||||||||
| Workover costs |
0.87 | 0.52 | 0.90 | |||||||||
| Total production costs |
$ | 9.17 | $ | 8.90 | $ | 10.46 | ||||||
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PIONEER NATURAL RESOURCES COMPANY
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| United States |
$ | 9.61 | $ | 9.16 | $ | 9.81 | ||||||
| South Africa |
$ | 0.68 | $ | 3.26 | $ | 25.98 | ||||||
| Worldwide |
$ | 9.17 | $ | 8.90 | $ | 10.46 | ||||||
Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $112.1 million during 2010, as compared to $98.4 million and $164.4 million for 2009 and 2008, respectively. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. During 2010, the Company’s production taxes per BOE increased by 32 percent, reflecting the year-to-year increase in commodity prices, while ad valorem taxes decreased one percent. During 2009, the Company’s production taxes per BOE declined 62 percent, reflecting the year-to-year decline in commodity prices, while ad valorem taxes decreased slightly.
The following table provides the Company’s production and ad valorem taxes per BOE from continuing operations and total production and ad valorem taxes per BOE from continuing operations for 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Ad valorem taxes |
$ | 1.42 | $ | 1.44 | $ | 1.52 | ||||||
| Production taxes |
1.39 | 1.05 | 2.74 | |||||||||
| Total ad valorem and production taxes |
$ | 2.81 | $ | 2.49 | $ | 4.26 | ||||||
Depletion, depreciation and amortization expense. The Company’s total DD&A expense was $14.38, $15.95 and $12.31 per BOE for 2010, 2009 and 2008, respectively. Depletion expense, the largest component of DD&A expense, was $13.63, $15.23 and $11.58 per BOE during 2010, 2009 and 2008, respectively.
During the fourth quarter of 2009, the Company adopted the provisions of the Reserve Ruling and ASU 2010-03. The provisions of the Reserve Ruling and ASU 2010-03, which became effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009, changed the definition of proved oil and gas reserves to require the use of an average of the first-day-of-the-month commodity prices during the 12-month period ending on the balance sheet date rather than the period-end commodity prices; added to and amended certain definitions used in estimating proved oil and gas reserves, such as “reliable technology” and “reasonable certainty”; and broadened the types of technology that an issuer may use to establish reserves estimates and categories. During 2009, the Company’s cost reduction initiatives and a declining trend in drilling costs mitigated the 2009 increase in per BOE depletion expense.
During 2010, the decrease in per BOE depletion expense was primarily due to (i) proved reserve additions associated with the Company’s successful 2010 capital expenditures program and (ii) adding end-of-life reserves that became economic as a result of commodity price increases since December 31, 2009.
During 2009, the increase in per BOE depletion expense was primarily due to (i) losing end-of-life reserves that became uneconomic as a result of commodity price declines since December 31, 2008, (ii) a generally increasing trend through 2008 in the Company’s oil and gas properties’ cost bases per BOE of proved and proved developed reserves as a result of cost inflation in drilling rig rates and drilling supplies and (iii) the relatively higher depletion rate per BOE associated with production from the Oooguruk development, which began first production in June 2008, and the South African South Coast Gas project, which became fully operational in October 2008.
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PIONEER NATURAL RESOURCES COMPANY
The following table provides depletion expense per BOE from continuing operations by geographic area for 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| United States |
$ | 12.40 | $ | 14.20 | $ | 11.30 | ||||||
| South Africa |
$ | 36.50 | $ | 38.33 | $ | 18.37 | ||||||
| Worldwide |
$ | 13.63 | $ | 15.23 | $ | 11.58 | ||||||
Impairment of oil and gas properties and other assets. The Company reviews its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. During the year ended December 31, 2010, the Company assessed its oil and gas properties for impairment and found no impairment of their carrying values to exist. During the year ended December 31, 2009, the Company recognized impairment charges of $21.1 million to reduce the carrying value of the Company’s oil and gas properties in the Uinta/Piceance areas. During the year ended December 31, 2008, the Company recognized impairment charges of $104.3 million, including $14.5 million attributable to discontinued operations, to reduce the carrying value of its net assets in the Uinta/Piceance and Mississippi areas. Declines in gas prices and downward adjustments to the economically recoverable resource potential of these properties led to the impairment charges.
The Company assesses goodwill for impairment at least annually. The Company’s assessments of goodwill for impairment during 2010 and 2009 confirmed that the Company’s carrying value of goodwill was not impaired.
See Notes B and R of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information about the Company’s impairment assessments.
Exploration and abandonments expense. The following tables provide the Company’s geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense by geographic area for 2010, 2009 and 2008 (in thousands):
| United States |
South Africa |
Other | Total | |||||||||||||
| Year ended December 31, 2010 |
||||||||||||||||
| Geological and geophysical |
$ | 58,016 | $ | 512 | $ | — | $ | 58,528 | ||||||||
| Exploratory dry holes |
91,922 | — | — | 91,922 | ||||||||||||
| Leasehold abandonments and other |
39,659 | — | — | 39,659 | ||||||||||||
| $ | 189,597 | $ | 512 | $ | — | $ | 190,109 | |||||||||
| Year ended December 31, 2009 |
||||||||||||||||
| Geological and geophysical |
$ | 40,919 | $ | 623 | $ | — | $ | 41,542 | ||||||||
| Exploratory dry holes |
6,873 | — | — | 6,873 | ||||||||||||
| Leasehold abandonments and other |
31,303 | — | — | 31,303 | ||||||||||||
| $ | 79,095 | $ | 623 | $ | — | $ | 79,718 | |||||||||
| Year ended December 31, 2008 |
||||||||||||||||
| Geological and geophysical |
$ | 72,146 | $ | 143 | $ | 1,585 | $ | 73,874 | ||||||||
| Exploratory dry holes |
73,741 | — | 487 | 74,228 | ||||||||||||
| Leasehold abandonments and other |
43,841 | — | — | 43,841 | ||||||||||||
| $ | 189,728 | $ | 143 | $ | 2,072 | $ | 191,943 | |||||||||
During 2010, the Company’s exploration and abandonment expense was primarily attributable to $58.0 million of United States geological and geophysical personnel costs, $96.7 million of dry hole and leasehold abandonment charges resulting from the Company’s decision not to pursue development of the Cosmopolitan Unit in the Cook Inlet of Alaska and other United States dry hole provisions and unproved property abandonments. The significant components of the Company’s 2010 unproved abandonments included $6.3 million in the Raton Basin area, $6.0 million in the Permian Basin area and $4.9 million in the Barnett Shale area. During 2010, the Company completed and evaluated 42 exploration/extension wells, 39 of which were successfully completed as discoveries.
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PIONEER NATURAL RESOURCES COMPANY
During 2009, the Company’s exploration and abandonment expense was primarily attributable to United States geological and geophysical personnel costs, South Texas, Lay Creek and Raton Basin areas dry hole expense and unproved property abandonments in the Permian Basin, Barnett Shale and Raton Basin areas. The significant components of the Company’s 2009 exploratory dry hole provisions and leasehold abandonments expense included (i) $6.9 million of dry hole provisions, primarily associated with the write off of suspended well costs and (ii) $29.4 million of unproved property abandonments. During 2009, the Company completed and evaluated 17 exploration/extension wells, 13 of which were successfully completed as discoveries.
During 2008, the Company’s exploration and abandonment expense was primarily attributable to seismic activity in the Company’s Utah and South Texas areas, dry hole expense and unproved property abandonments. The significant components of the Company’s exploratory dry hole provisions and unproved property abandonments expense included (i) $47.1 million of costs associated with the unsuccessful Lay Creek CBM pilot project, (ii) $12.2 million of costs associated with the unsuccessful Delaware Basin exploration project, (iii) $11.3 million of costs associated with the unsuccessful Sligo exploration well in South Texas and (iv) $41.1 million of U.S. unproved property abandonments. During 2008, the Company completed and evaluated 81 exploration/extension wells, 62 of which were successfully completed as discoveries.
General and administrative expense. General and administrative expense totaled $165.3 million, $131.5 million and $132.6 million during 2010, 2009 and 2008, respectively. The increase in general and administrative expense during 2010, as compared to 2009, was primarily due to increases in performance-related compensation expense and staffing increases to support the Company’s increased activity level during 2010.
The decrease in general and administrative expense during 2009, as compared to 2008, was primarily due to the Company’s cost reduction initiatives, partially offset by an increases in compensation and occupancy expenses and a decline in general and administrative cost recoveries.
Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations from continuing operations was $10.4 million, $10.6 million and $7.7 million during 2010, 2009 and 2008, respectively. Accretion of discount on asset retirement obligations decreased slightly during 2010 as compared to 2009 due to incremental accretion associated with higher commodity prices having the effect of extending the economic life of the Company’s wells. The increase in accretion of discount on asset retirement obligations during 2009 was primarily due to the accretion associated with higher asset retirement obligations that resulted from declining commodity prices having the effect of reducing the economic life of the Company’s wells, thus accelerating their forecasted abandonment date, plus the accretion attributable to new wells placed on production. See Note K 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.
Interest expense. Interest expense was $183.1 million, $173.4 million and $166.8 million during 2010, 2009 and 2008, respectively. The weighted average interest rate on the Company’s indebtedness for the year ended December 31, 2010 was 6.4 percent, as compared to 5.2 percent and 5.5 percent for the years ended December 31, 2009 and 2008, respectively, including the effects of interest rate derivatives.
The $9.7 million increase in interest expense during the year ended December 31, 2010, as compared to 2009, was primarily due to (i) a $29.0 million increase in cash interest expense on senior notes due to an increase in average senior note borrowings, which was primarily attributable to the issuance of $450 million of 7.5% Senior Notes during November 2009, partially offset by a (ii) $10.6 million decrease in cash interest expense on lines of credit and a (iii) $5.6 million increase in capitalized interest related to the Oooguruk project in Alaska as a result of the Company’s weighted average interest rate increasing.
The $6.6 million increase in interest expense during the year ended December 31, 2009, as compared to 2008, was primarily due to (i) a $9.2 million decrease in capitalized interest related to the Oooguruk project as development wells were placed on production, partially offset by (ii) a $4.8 million decrease in cash interest expense on long-term borrowings.
See Notes B and E 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.
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PIONEER NATURAL RESOURCES COMPANY
Other expenses. Other expenses were $81.7 million during 2010, as compared to $100.1 million during 2009 and $114.5 million during 2008. The $18.4 million decrease in other expense during 2010, as compared to 2009, is primarily due to a $16.7 million decrease in excess and terminated rig-related costs, a $5.3 million decrease in transportation commitment charges, a $4.8 million decrease in bad debt expense and a $2.2 million decrease in contingency and environmental accrual adjustments, partially offset by an $8.5 million increase in inventory impairment and a $2.9 million increase in severance and ad valorem tax audit adjustments.
The $14.4 million decrease in other expense during 2009, as compared to 2008, is primarily attributable to (i) a $25.8 million decrease in bad debt expense, partially offset by (ii) a $9.1 million increase in idle well servicing operations.
See Note N of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s other expenses.
Income tax benefit (provision). The Company recognized an income tax provision attributable to earnings from continuing operations of $272.3 million during 2010, an income tax benefit of $88.2 million during 2009 and an income tax provision of $113.9 million during 2008. The Company’s effective tax rates for 2010, 2009 and 2008 were 36 percent, 35 percent and 40 percent, respectively, as compared to the combined United States federal and state statutory rates of approximately 37 percent. The effective tax rates differ from the combined United States federal and state statutory rates primarily due to:
| • | foreign tax rates and |
| • | a $4.8 million U.S. tax benefit during 2009 and a $15.8 million U.S. tax provision during 2008 related to the Company no longer having identifiable plans to reinvest South Africa earnings in South Africa. |
See “Critical Accounting Estimates” below and Note O of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s tax position.
Income (loss) from discontinued operations, net of tax. During December 2010, the Company committed to a plan to sell its Tunisian subsidiaries and in February 2011 sold 100 percent of the Company’s share holdings in its Tunisian subsidiaries for $866 million, before normal closing adjustments. Accordingly, the Company has classified its Tunisian assets and liabilities as discontinued operations held for sale as of December 31, 2010, and has classified its historic Tunisian revenues and expenses as income from discontinued operations in the accompanying consolidated financial statements. During 2009, the Company sold its oil and gas properties in Mississippi and substantially all of its shelf properties in the Gulf of Mexico. The results of operations of these assets and the related gains on disposition are reported as discontinued operations in the accompanying consolidated statements of operations.
The Company recognized income from discontinued operations of $129.8 million during 2010 as compared to income from discontinued operations of $116.9 million during 2009 and $44.8 million during 2008. The $12.9 million increase in income from discontinued operations during 2010, as compared to 2009 is attributable to the 2010 receipt of $35.3 million of interest associated with the recovery of excess deepwater Gulf of Mexico oil and gas royalties paid during 2003 through 2005, (ii) a $24.0 million increase in Tunisian income from discontinued operations and (iii) a 2010 deferred tax benefit adjustment related to Tunisia of $56.5 million, partially offset by (iv) the after tax impact of the 2009 recognition of $119.3 million of pretax gain from the aforementioned excess royalty recovery.
The $72.1 million increase in income from discontinued operations during 2009, as compared to 2008, is attributable to (i) the aforementioned $119.3 million excess royalty gain, (ii) a $5.6 million increase in discontinued operations tax provisions and (iii) a $17.5 million pretax gain from the divestiture of the Company’s Mississippi assets and substantially all of the Company’s Gulf of Mexico shelf properties during 2009, partially offset by (iv) a $68.2 million decrease in Tunisian pretax income. See Note U of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s discontinued operations.
Net (income) loss attributable to noncontrolling interest. Net income attributable to noncontrolling interests was $40.8 million, $9.8 million and $21.6 million for the years ended December 31, 2010, 2009 and 2008,
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PIONEER NATURAL RESOURCES COMPANY
respectively. The Company’s net income attributable to noncontrolling interest is primarily associated with the net income of Pioneer Southwest that is allocated to limited partners. The $31.0 million increase in net income attributable to noncontrolling interest in 2010, as compared to 2009, is primarily due to an increase in Pioneer Southwest’s noncash mark-to-market derivative gains.
The $11.8 million decrease in net income attributable to noncontrolling interest in 2009, compared to 2008, is primarily due to an increase in Pioneer Southwest mark-to-market derivative losses during 2009. See Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding Pioneer Southwest and the Company’s noncontrolling interest in consolidated subsidiaries’ net income.
Capital Commitments, Capital Resources and Liquidity
Capital commitments. The Company’s primary needs for cash are for capital expenditures and acquisition expenditures on oil and gas assets, payment of contractual obligations, including funding of EFS Midstream, dividends/distributions and working capital obligations. Funding for these cash needs, as well as funding for any stock or debt repurchases that the Company may undertake, may be provided by any combination of internally-generated cash flow, proceeds from the disposition of nonstrategic assets or external financing sources as discussed in “Capital resources” below. The Company expects that it will be able to fund its needs for cash (excluding acquisitions) with internally-generated cash flows and with its liquidity under its credit facility. Although the Company expects that internal operating cash flows will be adequate to fund capital expenditures and dividend/distribution payments, and that available borrowing capacity under the Company’s credit facility will provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet the Company’s future needs.
The Company intends to limit its capital expenditures to a level that allows the Company to deliver net cash flow from operating activities in excess of capital requirements in order to enhance and preserve financial flexibility. However, during 2011, the Company expects to redeploy a portion of the proceeds from the sale of its Tunisian subsidiaries to accelerate drilling in the Eagle Ford Shale, Spraberry and Barnett Shale Combo areas. During 2010, the Company’s capital expenditures totaled $855.6 million (excluding effects of asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream investments), as compared to $312.9 million in 2009, representing a 173 percent increase.
During 2011, the Company plans to continue its oil- and liquids-rich-gas-focused drilling activities. The Company’s 2011 capital budget totals $1.8 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream capital contributions), consisting of $1.6 billion for drilling operations and $200 million for vertical integration and facilities. Based on current NYMEX commodity prices, the Company expects its cash flow from operating activities plus a portion of the proceeds from the sale of its Tunisian subsidiaries to be sufficient to fund its planned capital expenditures and contractual obligations.
Investing activities. Net cash used in investing activities during 2010 was $954.9 million, as compared to net cash used in investing activities of $411.0 million and $1.2 billion during 2009 and 2008, respectively. The increase in net cash flow used in investing activities during 2010, as compared to 2009, was comprised of a $574.2 million increase in additions to oil and gas properties, a $159.0 million increase in additions to other assets and other property and equipment and a $72.9 million increase in investment in unconsolidated subsidiaries, partially offset by an increase of $262.2 million in proceeds from disposition of assets. During 2010, the $313.8 million of proceeds from disposition of assets was mainly comprised of $212.0 million of joint venture cash proceeds from the sale of a 45 percent interest in the Company’s Eagle Ford Shale properties, $23.7 million of past cost recoveries from ETAP associated with the participation in the Cherouq concession and $77.4 million of net proceeds from the sale of other assets. The decrease in net cash used in investing activities during 2009, as compared to 2008, was primarily due to cost reduction initiatives, which resulted in a $966.0 million decrease in additions to oil and gas properties and a $15.7 million decrease in additions to other assets and other property and equipment, partially offset by a $241.3 million decrease in proceeds from disposition of assets. See “— Results of Operations” above and Note M of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding asset divestitures.
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PIONEER NATURAL RESOURCES COMPANY
During December 2010, the Company committed to a plan to sell its Tunisian subsidiaries and in February 2011 sold 100 percent of the Company’s share holdings in its Tunisian subsidiaries for $866 million, before normal closing adjustments.
Dividends/distributions. During each of 2010 and 2009, the Board declared semiannual dividends of $0.04 per common share. Associated therewith, the Company paid $9.5 million and $9.4 million of aggregate dividends during 2010 and 2009, respectively. Future dividends are at the discretion of the Board, and, if declared, the Board may change the dividend amount based on the Company’s liquidity and capital resources at the time.
During January, April, July and October 2010 and 2009, the board of directors of the general partner of Pioneer Southwest (the “Pioneer Southwest Board”) declared quarterly distributions of $0.50 per limited partner unit. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $25.2 million and $19.0 million during 2010 and 2009, respectively. Future distributions of Pioneer Southwest are at the discretion of the Pioneer Southwest Board, and, if declared, the Pioneer Southwest Board may change the distribution amount based on Pioneer Southwest’s liquidity and capital resources at the time.
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, 2010, 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 and firm transportation commitments, (iv) VPP obligations (to physically deliver volumes and pay related lease operating expenses in the future), (v) open purchase commitments, (vi) EFS Midstream capital funding commitments and (vii) 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 or interest rates and gathering, treating and transportation commitments on uncertain volumes of future throughput. 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 (including commitments to pay day rates for drilling rigs), capital funding obligations, derivative obligations, other liabilities, firm transportation commitments, minimum annual gathering, treating and transportation commitments, and VPP obligations. The Company’s contractual obligations include obligations to purchase goods and services for properties that the Company operates, including certain drilling commitments, open purchase commitments and firm gathering, processing and transportation commitments. Other joint owners in the properties operated by the Company will incur portions of the costs represented by these commitments, including qualifying Eagle Ford Shale costs that are subject to a counterparty’s obligation to carry up to 75 percent of the Company’s costs (see “- Financial and Operating Performance” and Note M of Notes to Consolidated Financial Statements included in “Item 8. Consolidated Financial Statements and Supplementary Data”).
The following table summarizes by period the payments due by the Company for contractual obligations estimated as of December 31, 2010:
| Payments Due by Year | ||||||||||||||||
| 2011 | 2012 and 2013 |
2014 and 2015 |
Thereafter | |||||||||||||
| (in thousands) | ||||||||||||||||
| Long-term debt (a) |
$ | — | $ | 610,200 | $ | — | $ | 2,089,985 | ||||||||
| Operating leases (b) |
16,719 | 31,586 | 26,604 | 52,387 | ||||||||||||
| Drilling commitments (c) |
287,207 | 312,073 | 19,018 | — | ||||||||||||
| Derivative obligations (d) |
80,998 | 55,060 | 1,514 | — | ||||||||||||
| Open purchase commitments (e) |
403,921 | 96,563 | — | — | ||||||||||||
| Other liabilities (f) |
36,210 | 54,586 | 17,390 | 160,258 | ||||||||||||
| Firm gathering, processing and transportation commitments (g) |
83,448 | 248,128 | 252,056 | 669,421 | ||||||||||||
| VPP obligations (h) |
44,951 | 42,069 | — | — | ||||||||||||
| $ | 953,454 | $ | 1,450,265 | $ | 316,582 | $ | 2,972,051 | |||||||||
| (a) | Long-term debt includes $480.0 million principal amount of the Company’s 2.875% Convertible Senior Notes due 2038 (the “2.875% Convertible Senior Notes”). Holders of the 2.875% Convertible Senior Notes may elect to convert their notes if the last reported sale price of the Company’s common stock is greater than 130 percent of the base conversion price as defined in the indenture. The price of the Company’s common stock has recently been trading at prices above 130 percent of the base conversion price and, accordingly, if the Company’s common stock continues to trade above 130 percent of the base conversion price, the holders of the 2.875% Convertible Senior Notes may, at their option, be able to convert the notes as early as the second quarter of 2011. If any holders elect to convert, the Company expects that the cash portion of the conversion payment will be available from cash on hand or borrowings under the Credit Facility and that the conversion of the 2.875% Convertible Senior Notes would not have a material adverse effect on the Company’s liquidity. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for information regarding estimated future interest payment obligations under long-term debt obligations and Note E 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. |
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PIONEER NATURAL RESOURCES COMPANY
| (b) | See Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.” |
| (c) | Drilling commitments represent future minimum expenditure commitments for drilling rig services and well commitments under contracts to which the Company was a party on December 31, 2010. |
| (d) | Derivative obligations represent net liabilities for oil and gas commodity derivatives that were valued as of December 31, 2010. The ultimate settlement amounts 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 I 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) | Open purchase commitments primarily represent expenditure commitments for inventory and other property, plant and equipment ordered, but not received, as of December 31, 2010. |
| (f) | The Company’s other liabilities represent current and noncurrent other liabilities that are comprised of postretirement 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 G, H and K of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s postretirement benefit obligations, litigation and environmental contingencies and asset retirement obligations, respectively. |
| (g) | Gathering, processing and transportation commitments represent estimated fees on production throughput commitments. See “Item 2. Properties” and Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s gathering, processing and transportation commitments. |
| (h) | 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 S of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.” |
Capital resources. The Company’s primary capital resources are net cash provided by operating activities, proceeds from sales of nonstrategic assets and proceeds from financing activities (principally borrowings under the Company’s credit facility). If internal cash flows do not meet the Company’s expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its credit facility, issuances of debt or equity securities or from other sources, such as asset sales.
Operating activities. Net cash provided by operating activities during 2010, 2009 and 2008 was $1.3 billion, $543.1 million and $1.0 billion, respectively. The increase in net cash flow provided by operating activities in 2010, as compared to 2009, was primarily due to increases in average oil, NGL and gas prices, an increase in cash derivative gains and working capital changes, partially offset by decreases in NGL and gas sales volumes. The decrease in net cash provided by operating activities in 2009, as compared to that of 2008, was primarily due to decreased oil, NGL and gas prices from continuing operations, partially offset by an increase in commodity sales volumes and decreased production costs.
Asset divestitures. During 2010, the Company (i) committed to the sale of 100 percent of the Company’s share holdings in its Tunisian subsidiaries, which were sold during February 2011, (ii) sold certain proved and unproved oil and gas properties associated with an Eagle Ford Shale joint venture transaction for net proceeds of $212.0 million, (iii) sold certain proved and unproved properties in the Uinta/Piceance area for net proceeds of $11.8 million and (iv) received $23.7 million from ETAP as contractual reimbursement of a portion of the Company’s past capital costs incurred in Tunisia. See Note M of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information regarding the 2010 divestitures.
During June and August 2009, the Company sold its Mississippi assets and shelf properties in the Gulf of Mexico, respectively, for a net gain of $17.8 million. Also during August 2009, Pioneer USA sold certain of its
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PIONEER NATURAL RESOURCES COMPANY
properties in the Spraberry Field in West Texas to Pioneer Southwest for proceeds of $168.3 million including normal closing adjustments. The transaction value also included the assignment of 2009 through 2013 commodity price derivative positions to Pioneer Southwest. Pioneer Southwest is a partially-owned and consolidated subsidiary of the Company. Consequently, the sale of the properties from Pioneer USA to Pioneer Southwest represented a transfer among entities under common control and did not reduce the Company’s oil and gas properties’ carrying values. Proceeds from the sale were used to reduce Pioneer’s credit facility indebtedness. Pioneer Southwest funded the acquisition with cash on hand and borrowings on its credit facility.
During 2008, the Company terminated derivative assets prior to their contractual maturity dates. The accompanying consolidated statement of cash flows for the year ended December 31, 2008 includes $155.0 million of proceeds from disposition of assets attributable to these derivative terminations.
Financing activities. Net cash used in financing activities for 2010 was $246.4 million, as compared to net cash used in financing activities of $153.0 million and net cash provided by financing activities of $153.7 million for 2009 and 2008, respectively. During 2010, significant components of financing activities included $182.9 million of net principal payments on long-term debt and $36.3 million of payments associated with dividends and distributions to noncontrolling interests. During 2009, significant components of financing activities included $159.9 million of net principal payments on long-term debt and $61.0 million of net proceeds from a secondary unit offering by Pioneer Southwest, partially offset by $63.3 million of payments associated with dividends, distributions to noncontrolling interests, financing fees and stock repurchases. During 2008, significant components of financing activities included $225.8 million of net borrowings of long-term debt and $166.0 million of proceeds from the initial public offering by Pioneer Southwest, partially offset by $181.7 million used to purchase 4.7 million shares of treasury stock.
The following provides a description of the Company’s significant financing activities during 2010, 2009 and 2008:
| • | During 2010, the Company reduced borrowings under its $1.5 billion credit facility due April 2012 by $191.0 million. |
| • | During March 2010, the Company redeemed for cash all of its outstanding 5.875% senior notes due 2012 for a price equal to the principal amount plus accrued and unpaid interest. Associated therewith, the Company paid $6.3 million. |
| • | During November 2009, the Company issued 7.50% senior notes due 2020 and received proceeds, net of $11.4 million of offering discounts and costs, of $438.6 million. The Company used the net proceeds to reduce outstanding borrowings under its credit facility. |
| • | During November 2009, Pioneer Southwest, a subsidiary of the Company, completed a public offering of 3,105,000 common units, which represented a six percent increase in limited partner interests in Pioneer Southwest, for net proceeds of $61.0 million. Pioneer Southwest used the net proceeds to repay amounts outstanding under its revolving credit facility. |
| • | During December 2008, the Company repurchased $20.0 million principal amount of its outstanding 2.875% Senior Convertible Notes, $71.5 million principal amount of its outstanding 5.875% senior notes due 2016, $14.9 million principal amount of its outstanding 6.65% senior notes due 2017 and $500 thousand principal amount of its outstanding 6.875% senior notes due 2018. Associated therewith, the Company recognized a gain of $20.5 million, which is included in interest and other income in the accompanying consolidated statements of operations for the year ended December 31, 2008. |
| • | On May 6, 2008, Pioneer Southwest completed its initial public offering of 9,487,500 common units, representing a 31.6 percent limited partner interest in Pioneer Southwest. Pioneer Southwest owns interests in certain oil and gas properties previously owned by the Company in the Spraberry field in the Permian Basin of West Texas. The Company received $166.0 million of net proceeds from Pioneer Southwest in consideration for (i) an ownership interest in a subsidiary of Pioneer that owned the oil and gas properties prior to the initial public offering and (ii) an incremental ownership interest in certain of the same properties as a result of the exercise of the over-allotment option. The net proceeds from the initial public offering were used to reduce the Company’s outstanding indebtedness. The Company consolidates Pioneer Southwest into its financial statements and reflects the public ownership as a noncontrolling interest in Pioneer Southwest’s net assets. |
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PIONEER NATURAL RESOURCES COMPANY
| • | In conjunction with the completion of the initial public offering, Pioneer Southwest completed a $300 million unsecured revolving credit facility with a syndicate of banks, which matures in May 2013 (the “Pioneer Southwest Credit Facility”). The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions. |
| • | During January 2008, the Company issued 2.875% Senior Convertible Notes and received proceeds, net of approximately $11.3 million of underwriter discounts and offering costs, of $488.7 million. The Company used the net proceeds from the offering to reduce outstanding borrowings under its credit facility. |
The Company has begun preliminary plans towards replacement of its $1.5 billion corporate credit facility that matures in April 2012, with a new corporate credit facility. The Company anticipates that it will successfully negotiate a new credit facility with terms that provide for borrowing capacity, borrowing alternatives, interest rates, fees and financial covenants similar to those of its existing facility. Current plans are to finalize a new corporate credit facility during the first quarter of 2011.
See Note E of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the significant financing activities.
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 cannot predict the timing or ultimate outcome of any such actions as they are subject to market conditions, among other factors. 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 cash on hand and unused borrowing capacity under its credit facility. There were $49.0 million of outstanding borrowings under the credit facility as of December 31, 2010. Including $65.1 million of undrawn and outstanding letters of credit under the credit facility, the Company had $1.4 billion of unused borrowing capacity as of December 31, 2010. If internal cash flows do not meet the Company’s expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its credit facility, issuances of debt or equity securities or from other sources, such as asset sales. The Company cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that internal cash flows will be adequate to fund capital expenditures and dividend payments, and that available borrowing capacity under the Company’s credit facility will provide adequate liquidity, no assurances can be given that such funding sources will be adequate to meet the Company’s future needs. For instance, the amount that the Company may borrow under the credit facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items.
Debt ratings. The Company receives debt credit ratings from several of the major ratings agencies, which are subject to regular reviews. The Company believes that each of the rating agencies considers many factors in determining the Company’s ratings including: production growth opportunities, liquidity, debt levels and asset composition and proved reserve mix. A reduction in the Company’s debt ratings could negatively impact the Company’s ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.
Book capitalization and current ratio. The Company’s net book capitalization at December 31, 2010 was $6.7 billion, consisting of $111.2 million of cash and cash equivalents, debt of $2.6 billion and stockholders’ equity of $4.2 billion. The Company’s debt to book capitalization decreased to 37 percent at December 31, 2010 from 43 percent at December 31, 2009, primarily due to a decrease in indebtedness. The Company’s ratio of current assets to current liabilities was 1.56 to 1.00 at December 31, 2010, as compared to 1.08 to 1.00 at December 31, 2009.
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
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PIONEER NATURAL RESOURCES COMPANY
requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The 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.
Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and to restore the land or seabeds 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.
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 generally made to the oil and gas property balance. See Notes B and K 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 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 2010, 2009 and 2008, the Company recognized exploration, abandonment, geological and geophysical expense from continuing operations of $190.1 million, 79.7 million and $191.9 million, respectively. During 2010, 2009 and 2008, the Company recognized exploration, abandonment, geological and geophysical expense from discontinued operations of $15.4 million, $18.6 million and $43.6 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, 2010, 2009 and 2008 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, 2010 is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the 2010 Standardized Measure on a 12-month average of commodity prices on the first day of the month and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See “Item 1A. Risk Factors” and “Item 2. Properties” for additional information regarding estimates of proved reserves.
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PIONEER NATURAL RESOURCES COMPANY
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 proved properties and goodwill for impairment.
Impairment of proved oil and gas properties. The Company reviews its 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 estimated future recoverable proved and risk-adjusted probable and possible reserves, its outlook of future commodity prices, production and capital costs expected to be incurred to recover the reserves; discount rates commensurate with the nature of the properties and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated. See Note R of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the Company’s impairment assessments.
Impairment of unproved oil and gas properties. At December 31, 2010, the Company carried unproved property costs of $191.1 million. Management assesses unproved oil and gas properties for impairment on a project-by-project basis. Management’s impairment assessments include evaluating the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects.
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.
The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless 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 projects, it may take an extended period of time 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 C 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 current international operations. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position.
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 assurance 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, 2010, the Company does not believe there is sufficient positive evidence to reverse its valuation allowances related to certain foreign tax jurisdictions.
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PIONEER NATURAL RESOURCES COMPANY
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 in determining the valuation methodologies to utilize, the estimation of proved reserves as described above and the weighting of different valuation methodologies applied. The carrying value of the Company’s goodwill was assessed and found not to be impaired during the years ended December 31, 2010, 2009 and 2008. See Notes B and R of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding goodwill and assessments of goodwill for impairment.
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 subject to change because of changes in laws and regulations, developing information 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 estimable. 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.
Valuations of defined benefit pension and postretirement plans. The Company is the sponsor of certain defined benefit pension and postretirement plans. In accordance with GAAP, the Company is required to estimate the present value of its unfunded pension and accumulated postretirement benefit obligations. Based on those values, the Company records the unfunded obligations of those plans and records ongoing service costs and associated interest expense. The valuation of the Company’s pension and accumulated postretirement benefit obligations requires management assumptions and judgments as to benefit cost inflation factors, mortality rates and discount factors. Changes in these factors may materially change future benefit costs and pension and accumulated postretirement benefit obligations. See Note G of Notes to Consolidated Financial Statements included in “Item 8. Consolidated Financial Statements and Supplementary Data” for additional information regarding the Company’s pension and accumulated postretirement benefit obligations.
Valuation of stock-based compensation. In accordance with GAAP, the Company calculates the fair value of stock-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. The Company utilizes (a) the Black-Scholes option pricing model to measure the fair value of stock options, (b) the closing stock price on the day prior to the date of grant for the fair value of restricted stock awards and (c) the Monte Carlo simulation method for the fair value of performance unit awards.
Valuation of other assets and liabilities at fair value. In accordance with GAAP, the Company periodically measures and records certain assets and liabilities at fair value. The assets and liabilities that the Company periodically measures and records at fair value include trading securities, commodity derivative contracts and interest rate contracts. The Company also measures and reports certain financial assets and liabilities at fair value, such as notes receivable and long-term debt. The valuation methods used by the Company to measure the fair values of these assets and liabilities require considerable management judgment and estimates to derive the inputs necessary to determine fair value estimates, such as future prices, credit-adjusted risk-free rates and current volatility factors. See Note D of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the methods used by management to estimate the fair values of these assets and liabilities.
The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”
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PIONEER NATURAL RESOURCES COMPANY
| 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, 2010, and from which the Company may incur future gains or losses from changes in commodity prices, interest rates or foreign exchange rates.
The fair values of the Company’s derivative contracts are determined based on the Company’s valuation models and applications. During 2010, the Company changed its valuation inputs for NGL derivative contracts and used component price inputs presently available from independent active market quoted sources. As of December 31, 2009, the Company’s NGL component price inputs were obtained from independent brokers active in buying and selling NGL derivative contracts. As of December 31, 2010, the Company was a party to commodity swap contracts, interest rate swap contracts, commodity collar contracts and commodity collar contracts with short put options. 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 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 2010:
| Derivative Contract Net Assets (Liabilities) (a) | ||||||||||||
| Commodities | Interest Rate | Total | ||||||||||
| (in thousands) | ||||||||||||
| Fair value of contracts outstanding as of December 31, 2009 |
$ | (121,562 | ) | $ | (17,841 | ) | $ | (139,403 | ) | |||
| Changes in contract fair values (b) |
414,302 | 34,132 | 448,434 | |||||||||
| Contract maturities |
(125,173 | ) | 1,261 | (123,912 | ) | |||||||
| Fair value of contracts outstanding as of December 31, 2010 |
$ | 167,567 | $ | 17,552 | $ | 185,119 | ||||||
| (a) | Represents the fair values of open derivative contracts subject to market risk. |
| (b) | At inception, new derivative contracts entered into by the Company generally have no intrinsic value. |
Interest rate sensitivity. The following tables provide information about financial instruments to which the Company was a party as of December 31, 2010 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 rates represent the contractual fixed rates that the Company was obligated to periodically pay on the debt as of December 31, 2010. 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 22, 2011.
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PIONEER NATURAL RESOURCES COMPANY
INTEREST RATE SENSITIVITY
DEBT OBLIGATIONS AND DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2010
| Year Ending December 31, | Asset (Liability) Fair Value at December 31, |
|||||||||||||||||||||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | 2010 | |||||||||||||||||||||||||
| Total Debt: |
||||||||||||||||||||||||||||||||
| Fixed rate principal maturities (a) |
$ | — | $ | — | $ | 480,000 | $ | — | $ | — | $ | 2,089,985 | $ | 2,569,985 | $ | (2,954,690 | ) | |||||||||||||||
| Weighted average interest rate |
6.05 | % | 6.05 | % | 6.74 | % | 6.78 | % | 6.78 | % | 7.13 | % | ||||||||||||||||||||
| Variable rate principal maturities: |
||||||||||||||||||||||||||||||||
| Pioneer credit facility |
$ | — | $ | 49,000 | $ | — | $ | — | $ | — | $ | — | $ | 49,000 | $ | (58,382 | ) | |||||||||||||||
| Weighted average interest rate |
2.48 | % | 3.48 | % | ||||||||||||||||||||||||||||
| Pioneer Southwest credit facility |
$ | — | $ | — | $ | 81,200 | $ | — | $ | — | $ | — | $ | 81,200 | $ | (77,241 | ) | |||||||||||||||
| Weighted average interest rate |
1.35 | % | 2.36 | % | 3.52 | % | ||||||||||||||||||||||||||
| Interest Rate Swaps: |
||||||||||||||||||||||||||||||||
| Notional debt amount (b) |
$ | 23,625 | $ | (887 | ) | |||||||||||||||||||||||||||
| Fixed rate payable (%) |
3.00 | % | ||||||||||||||||||||||||||||||
| Variable rate receivable (%) |
0.48 | % | ||||||||||||||||||||||||||||||
| Notional debt amount (b) |
$ | 470,000 | $ | 470,000 | $ | 470,000 | $ | 470,000 | $ | 470,000 | $ | 100,625 | $ | 18,439 | ||||||||||||||||||
| Fixed rate receivable (%) |
2.92 | % | 2.92 | % | 2.92 | % | 2.92 | % | 2.92 | % | 3.12 | % | ||||||||||||||||||||
| Variable rate payable (%) |
0.48 | % | 1.48 | % | 2.64 | % | 3.42 | % | 3.73 | % | 3.68 | % | ||||||||||||||||||||
| (a) | Represents maturities of principal amounts excluding debt issuance discounts and premiums and net deferred fair value hedge losses. |
| (b) | Represents weighted average notional contract amounts of interest rate derivatives. |
Commodity derivative instruments and price sensitivity. The following tables provide information about the Company’s oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of December 31, 2010. Although mitigated by the Company’s derivative activities, declines in commodity prices will reduce Pioneer’s revenues and internally-generated cash flows.
The Company manages commodity price risk with derivative swap contracts, collar contracts and collar contracts with short put options. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum (“floor”) and maximum (“ceiling”) prices on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other collar contracts by virtue of the short put option price, below which the Company’s realized price will exceed the variable market prices by the floor-to-short put price differential.
See Notes B, D and I 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 its derivative financial instruments and for specific information regarding the terms of the Company’s derivative financial instruments that are sensitive to changes in oil, NGL or gas prices.
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PIONEER NATURAL RESOURCES COMPANY
OIL PRICE SENSITIVITY
DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2010
| Year Ending December 31, | Asset (Liability) Fair Value at December 31, |
|||||||||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2010 | ||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Oil Derivatives: |
||||||||||||||||||||
| Average daily notional Bbl volumes (a): |
||||||||||||||||||||
| Swap contracts |
750 | 3,000 | 3,000 | — | $ | (31,182 | ) | |||||||||||||
| Weighted average fixed price per Bbl |
$ | 77.25 | $ | 79.32 | $ | 81.02 | $ | — | ||||||||||||
| Collar contracts |
2,000 | — | — | — | $ | 16,875 | ||||||||||||||
| Weighted average ceiling price per Bbl |
$ | 170.00 | $ | — | $ | — | $ | — | ||||||||||||
| Weighted average floor price per Bbl |
$ | 115.00 | $ | — | $ | — | $ | — | ||||||||||||
| Collar contracts with short puts |
32,000 | 37,000 | 21,250 | 4,000 | $ | (86,076 | ) | |||||||||||||
| Weighted average ceiling price per Bbl |
$ | 99.33 | $ | 118.34 | $ | 117.38 | $ | 120.50 | ||||||||||||
| Weighted average floor price per Bbl |
$ | 73.75 | $ | 80.41 | $ | 80.18 | $ | 85.00 | ||||||||||||
| Weighted average short put price per Bbl |
$ | 59.31 | $ | 65.00 | $ | 65.18 | $ | 70.00 | ||||||||||||
| Average forward NYMEX oil prices (b) |
$ | 98.18 | $ | 100.07 | $ | 99.58 | $ | 99.40 | ||||||||||||
| (a) | Subsequent to December 31, 2010, the Company entered into additional collar contracts with short puts for 8,000 Bbls per day of the Company’s 2014 production with a ceiling price of $131.99 per Bbl, a floor price of $89.38 per Bbl and a short put price of $74.38 per Bbl. |
| (b) | The average forward NYMEX oil prices are based on February 22, 2011 market quotes. |
NGL PRICE SENSITIVITY
DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2010
| Year Ending December 31, | Liability Fair Value at December 31, |
|||||||||||||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2010 | ||||||||||||||||||||
| (in thousands) | ||||||||||||||||||||||||
| NGL Derivatives: |
||||||||||||||||||||||||
| Average daily notional Bbl volumes: |
||||||||||||||||||||||||
| Swap contracts |
1,150 | 750 | — | — | $ | (6,519 | ) | |||||||||||||||||
| Weighted average fixed price per Bbl |
$ | 51.41 | $ | 35.03 | $ | — | $ | — | ||||||||||||||||
| Collar contracts |
2,650 | — | — | — | $ | (3,037 | ) | |||||||||||||||||
| Weighted average ceiling price per Bbl |
$ | 64.23 | $ | — | $ | — | $ | — | ||||||||||||||||
| Weighted average floor price per Bbl |
$ | 53.29 | $ | — | $ | — | $ | — | ||||||||||||||||
| Average forward NGL prices (a) |
$ | 65.91 | $ | 47.96 | $ | — | $ | — | ||||||||||||||||
| (a) | Forward component NGL prices are not available as formal market quotes. These forward prices represent estimates as of February 22, 2011 provided by third parties who actively trade in the derivatives weighted equivalent to the NGL component volumes covered by the derivative contracts. Accordingly, these prices are subject to estimates and assumptions. |
66
PIONEER NATURAL RESOURCES COMPANY
GAS PRICE SENSITIVITY
DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2010
| Year Ending December 31, | Asset (Liability) Fair Value at December 31, |
|||||||||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2010 | ||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Gas Derivatives: |
||||||||||||||||||||
| Average daily notional MMBtu volumes: |
||||||||||||||||||||
| Swap contracts |
117,500 | 105,000 | 67,500 | 50,000 | $ | 122,495 | ||||||||||||||
| Weighted average fixed price per MMbtu |
$ | 6.13 | $ | 5.82 | $ | 6.11 | $ | 6.05 | ||||||||||||
| Collar contracts |
— | 65,000 | 100,000 | 40,000 | $ | 16,931 | ||||||||||||||
| Weighted average ceiling price per MMbtu |
$ | — | $ | 6.60 | $ | 6.50 | $ | 6.73 | ||||||||||||
| Weighted average floor price per MMbtu |
$ | — | $ | 5.00 | $ | 5.00 | $ | 5.00 | ||||||||||||
| Collar contracts with short puts |
200,000 | 190,000 | 45,000 | 50,000 | $ | 160,593 | ||||||||||||||
| Weighted average ceiling price per MMbtu |
$ | 8.55 | $ | 7.96 | $ | 7.49 | $ | 8.08 | ||||||||||||
| Weighted average floor price per MMbtu |
$ | 6.32 | $ | 6.12 | $ | 6.00 | $ | 6.00 | ||||||||||||
| Weighted average short put price per MMbtu |
$ | 4.88 | $ | 4.55 | $ | 4.50 | $ | 4.50 | ||||||||||||
| Average forward NYMEX gas prices (a) |
$ | 4.13 | $ | 4.73 | $ | 5.12 | $ | 5.44 | ||||||||||||
| Basis swap contracts |
148,500 | 116,000 | 32,500 | 10,000 | $ | (22,513 | ) | |||||||||||||
| Weighted average fixed price per MMbtu |
$ | (0.54 | ) | $ | (0.37 | ) | $ | (0.34 | ) | $ | (0.16 | ) | ||||||||
| Average forward basis differential prices (b) |
$ | (0.24 | ) | $ | (0.24 | ) | $ | (0.20 | ) | $ | (0.13 | ) | ||||||||
| (a) | The average forward NYMEX gas prices are based on February 22, 2011 market quotes. |
| (b) | The average forward basis differential prices are based on February 17, 2011 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices. |
The Company’s primary market risk exposures are to changes in interest rates, foreign exchange rates and commodity prices. These risks did not change materially from December 31, 2009 to December 31, 2010.
Non-derivative financial instruments. The Company is a borrower under fixed rate and variable rate debt instruments that give rise to interest rate risk. The Company’s objective in borrowing under fixed or variable rate debt is to satisfy capital requirements while minimizing the Company’s costs of capital. See Note E of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a discussion of the Company’s debt instruments.
Derivative financial instruments. The Company, from time to time, utilizes commodity price, interest rate and foreign exchange rate derivative contracts to mitigate commodity price, interest rate and foreign exchange rate risks in accordance with policies and guidelines approved by the Board. In accordance with those policies and guidelines, the Company’s executive management determines the appropriate timing and extent of derivative transactions.
Foreign currency, operations and price risk. International investments represent, and are expected to continue to represent, a portion of the Company’s total assets. Pioneer currently has international continuing operations in South Africa, which represented five percent of the Company’s 2010 oil and gas revenues from continuing operations. During December 2010 the Company committed to a plan to sell its Tunisian assets and during February 2011, the Company sold 100 percent of the Company’s share holdings in its Tunisian subsidiaries. The Company has reflected all Tunisian assets and liabilities as of December 31, 2010 and historical results of operations as discontinued operations (see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes B and V of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information about the sale of the Company’s Tunisian subsidiaries).
67
PIONEER NATURAL RESOURCES COMPANY
As a result of such foreign operations, the Company’s financial results and international operations could be affected by factors such as changes in foreign currency exchange rates, changes in the legal or regulatory environment, economic conditions or changes in political or economic climates and other factors. For example:
| • | local political and economic developments could restrict, or increase the cost of, Pioneer’s foreign operations; |
| • | exchange controls and currency fluctuations could result in financial losses; |
| • | royalty and tax increases and retroactive tax claims could increase costs of the Company’s foreign operations; |
| • | expropriation of the Company’s property could result in loss of revenue, property and equipment; |
| • | civil uprising, riots, terrorist attacks and wars could make it impractical to continue operations, resulting in financial losses; |
| • | compliance with applicable U.S. law could be in conflict with the Company’s contractual obligations, the laws of foreign governments or local customs; |
| • | import and export regulations and other foreign laws or policies could result in loss of revenues; |
| • | repatriation levels for export revenues could restrict the availability of cash to fund operations outside a particular foreign country; and |
| • | laws and policies of the U.S. affecting foreign trade, taxation and investment could restrict the Company’s ability to fund foreign operations or may make foreign operations more costly. |
The Company does not currently maintain political risk insurance. Pioneer evaluates on a country-by-country basis whether obtaining political risk coverage is necessary and may add such insurance in the future if the Company believes it is prudent to do so.
Africa. With the completion of the sale of the Company’s Tunisian subsidiaries in February 2011, the Company’s only remaining producing assets in Africa will be in South Africa. The Company views the operating environment in South Africa as stable and the economic stability as good. While the value of South Africa’s currency fluctuates in relation to the U.S. dollar, the Company believes that any currency risk associated with Pioneer’s South African operations would not have a material impact on the Company’s results of operations given that such operations are closely tied to oil prices, which are denominated in U.S. dollars.
68
PIONEER NATURAL RESOURCES COMPANY
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Index to Consolidated Financial Statements
| Page | ||||
| Consolidated Financial Statements of Pioneer Natural Resources Company: |
||||
| 70 | ||||
| Consolidated Balance Sheets as of December 31, 2010 and 2009 |
71 | |||
| Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008 |
73 | |||
| Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008 |
74 | |||
| Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008 |
76 | |||
| 77 | ||||
| 78 | ||||
| 121 | ||||
69
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
The Board of Directors and Stockholders of
Pioneer Natural Resources Company:
We have audited the accompanying consolidated balance sheets of Pioneer Natural Resources Company (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, cash flows and comprehensive income (loss) for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Pioneer Natural Resources Company at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
As discussed in Note B to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements resulting from Accounting Standards Update No. 2010-03, “Oil and Gas Reserve Estimation and Disclosures,” effective December 31, 2009.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pioneer Natural Resources Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2011 expressed an unqualified opinion thereon.
Ernst & Young LLP
Dallas, Texas
February 25, 2011
70
PIONEER NATURAL RESOURCES COMPANY
(in thousands)
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| ASSETS |
||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 111,160 | $ | 27,368 | ||||
| Accounts receivable: |
||||||||
| Trade, net of allowance for doubtful accounts of $1,155 and $1,310 as of December 31, 2010 and 2009, respectively |
237,511 | 330,711 | ||||||
| Due from affiliates |
7,792 | 1,037 | ||||||
| Income taxes receivable |
30,901 | 25,022 | ||||||
| Inventories |
173,615 | 139,177 | ||||||
| Prepaid expenses |
11,441 | 9,011 | ||||||
| Deferred income taxes |
156,650 | 26,857 | ||||||
| Discontinued operations held for sale |
281,741 | — | ||||||
| Other current assets: |
||||||||
| Derivatives |
171,679 | 48,713 | ||||||
| Other, net of allowance for doubtful accounts of nil and $5,689 as of December 31, 2010 and 2009, respectively |
14,693 | 8,222 | ||||||
| Total current assets |
1,197,183 | 616,118 | ||||||
| Property, plant and equipment, at cost: |
||||||||
| Oil and gas properties, using the successful efforts method of accounting: |
||||||||
| Proved properties |
10,739,114 | 10,276,244 | ||||||
| Unproved properties |
191,112 | 236,660 | ||||||
| Accumulated depletion, depreciation and amortization |
(3,366,440 | ) | (2,946,048 | ) | ||||
| Total property, plant and equipment |
7,563,786 | 7,566,856 | ||||||
| Deferred income taxes |
— | 387 | ||||||
| Goodwill |
298,182 | 309,259 | ||||||
| Other property and equipment, net |
283,542 | 154,830 | ||||||
| Other assets: |
||||||||
| Investment in unconsolidated affiliate |
72,045 | — | ||||||
| Derivatives |
151,011 | 43,631 | ||||||
| Other, net of allowance for doubtful accounts of $2,519 and $7,300 as of December 31, 2010 and 2009, respectively |
113,353 | 176,184 | ||||||
| $ | 9,679,102 | $ | 8,867,265 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
71
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS (Continued)
(in thousands, except share data)
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
| Current liabilities: |
||||||||
| Accounts payable: |
||||||||
| Trade |
$ | 354,890 | $ | 221,359 | ||||
| Due to affiliates |
64,260 | 32,224 | ||||||
| Interest payable |
59,008 | 47,009 | ||||||
| Income taxes payable |
19,168 | 17,411 | ||||||
| Deferred income taxes |
1,144 | 128 | ||||||
| Discontinued operations held for sale |
108,592 | — | ||||||
| Other current liabilities: |
||||||||
| Derivatives |
80,997 | 116,015 | ||||||
| Deferred revenue |
44,951 | 90,215 | ||||||
| Other |
36,210 | 46,830 | ||||||
| Total current liabilities |
769,220 | 571,191 | ||||||
| Long-term debt |
2,601,670 | 2,761,011 | ||||||
| Derivatives |
56,574 | 133,645 | ||||||
| Deferred income taxes |
1,751,310 | 1,470,899 | ||||||
| Deferred revenue |
42,069 | 87,021 | ||||||
| Other liabilities |
232,234 | 200,467 | ||||||
| Stockholders’ equity: |
||||||||
| Common stock, $.01 par value; 500,000,000 shares authorized; 126,212,256 and 125,203,502 shares issued at December 31, 2010 and 2009, respectively |
1,262 | 1,252 | ||||||
| Additional paid-in capital |
3,022,768 | 2,981,450 | ||||||
| Treasury stock, at cost: 10,903,743 and 10,828,171 shares at December 31, 2010 and 2009, respectively |
(421,235 | ) | (415,211 | ) | ||||
| Retained earnings |
1,510,427 | 917,688 | ||||||
| Accumulated other comprehensive income - deferred hedge gains, net of tax |
7,361 | 51,009 | ||||||
| Total stockholders’ equity attributable to common stockholders |
4,120,583 | 3,536,188 | ||||||
| Noncontrolling interest in consolidating subsidiaries |
105,442 | 106,843 | ||||||
| Total stockholders’ equity |
4,226,025 | 3,643,031 | ||||||
| Commitments and contingencies |
||||||||
| $ | 9,679,102 | $ | 8,867,265 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
72
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Revenues and other income: |
||||||||||||
| Oil and gas |
$ | 1,803,257 | $ | 1,459,654 | $ | 2,012,196 | ||||||
| Interest and other |
61,907 | 101,669 | 56,463 | |||||||||
| Derivative gains (losses), net |
448,434 | (195,557 | ) | (10,148 | ) | |||||||
| Gain (loss) on disposition of assets, net |
19,074 | (774 | ) | (381 | ) | |||||||
| Hurricane activity, net |
138,918 | (17,313 | ) | (12,150 | ) | |||||||
| 2,471,590 | 1,347,679 | 2,045,980 | ||||||||||
| Costs and expenses: |
||||||||||||
| Oil and gas production |
366,146 | 351,392 | 402,875 | |||||||||
| Production and ad valorem taxes |
112,141 | 98,371 | 164,417 | |||||||||
| Depletion, depreciation and amortization |
574,170 | 628,987 | 474,608 | |||||||||
| Impairment of oil and gas properties |
— | 21,091 | 89,753 | |||||||||
| Exploration and abandonments |
190,109 | 79,718 | 191,943 | |||||||||
| General and administrative |
165,301 | 131,524 | 132,637 | |||||||||
| Accretion of discount on asset retirement obligations |
10,433 | 10,599 | 7,717 | |||||||||
| Interest |
183,084 | 173,353 | 166,770 | |||||||||
| Other |
81,723 | 100,073 | 114,463 | |||||||||
| 1,683,107 | 1,595,108 | 1,745,183 | ||||||||||
| Income (loss) from continuing operations before income taxes |
788,483 | (247,429 | ) | 300,797 | ||||||||
| Income tax benefit (provision) |
(272,317 | ) | 88,246 | (113,916 | ) | |||||||
| Income (loss) from continuing operations |
516,166 | (159,183 | ) | 186,881 | ||||||||
| Income from discontinued operations, net of tax |
129,829 | 116,916 | 44,774 | |||||||||
| Net income (loss) |
645,995 | (42,267 | ) | 231,655 | ||||||||
| Net income attributable to noncontrolling interests |
(40,787 | ) | (9,839 | ) | (21,635 | ) | ||||||
| Net income (loss) attributable to common stockholders |
$ | 605,208 | $ | (52,106 | ) | $ | 210,020 | |||||
| Basic earnings per share: |
||||||||||||
| Income (loss) from continuing operations attributable to common stockholders |
$ | 4.04 | $ | (1.48 | ) | $ | 1.38 | |||||
| Income from discontinued operations attributable to common stockholders |
1.10 | 1.02 | 0.38 | |||||||||
| Net income (loss) attributable to common stockholders |
$ | 5.14 | $ | (0.46 | ) | $ | 1.76 | |||||
| Diluted earnings per share: |
||||||||||||
| Income (loss) from continuing operations attributable to common stockholders |
$ | 3.99 | $ | (1.48 | ) | $ | 1.38 | |||||
| Income from discontinued operations attributable to common stockholders |
1.09 | 1.02 | 0.38 | |||||||||
| Net income (loss) attributable to common stockholders |
$ | 5.08 | $ | (0.46 | ) | $ | 1.76 | |||||
| Weighted average shares outstanding: |
||||||||||||
| Basic |
115,062 | 114,176 | 117,462 | |||||||||
| Diluted |
116,330 | 114,176 | 117,947 | |||||||||
| Amounts attributable to common stockholders: |
||||||||||||
| Income (loss) from continuing operations, net of tax |
$ | 475,379 | $ | (169,022 | ) | $ | 165,246 | |||||
| Discontinued operations, net of tax |
129,829 | 116,916 | 44,774 | |||||||||
| Net income (loss) |
$ | 605,208 | $ | (52,106 | ) | $ | 210,020 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
73
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands, except dividends per share)
| Stockholders’ Equity Attributable to Common Stockholders | ||||||||||||||||||||||||||||||||
| Shares Outstanding |
Common Stock |
Additional Paid-in Capital |
Treasury Stock |
Retained Earnings |
Accumulated Other Comprehensive Income (Loss) |
Noncontrolling Interests |
Total Stockholders’ Equity |
|||||||||||||||||||||||||
| Balance as of December 31, 2007 |
117,727 | $ | 1,234 | $ | 2,693,257 | $ | (245,601 | ) | $ | 822,089 | $ | (228,257 | ) | $ | 11,942 | $ | 3,054,664 | |||||||||||||||
| Dividends declared ($0.30 per share) |
— | — | — | — | (35,952 | ) | — | — | (35,952 | ) | ||||||||||||||||||||||
| Exercise of long-term incentive plan stock options and employee stock purchases |
355 | — | — | 15,439 | (7,371 | ) | — | — | 8,068 | |||||||||||||||||||||||
| Purchase of treasury stock |
(4,714 | ) | — | — | (181,497 | ) | — | — | (240 | ) | (181,737 | ) | ||||||||||||||||||||
| Tax benefits related to stock-based compensation |
— | — | 367 | — | — | — | — | 367 | ||||||||||||||||||||||||
| Compensation costs: |
||||||||||||||||||||||||||||||||
| Vested compensation awards, net |
1,178 | 12 | (12 | ) | — | — | — | — | — | |||||||||||||||||||||||
| Compensation costs included in net income |
— | — | 33,970 | — | — | — | 107 | 34,077 | ||||||||||||||||||||||||
| Issuance of 2.875% senior convertible notes |
— | — | 49,527 | — | — | — | — | 49,527 | ||||||||||||||||||||||||
| Issuance of Pioneer Southwest common units |
— | — | 132,626 | — | — | — | 33,171 | 165,797 | ||||||||||||||||||||||||
| Cash distributions to noncontrolling interests |
— | — | — | — | — | — | (8,635 | ) | (8,635 | ) | ||||||||||||||||||||||
| Net income |
— | — | — | — | 210,020 | — | 21,635 | 231,655 | ||||||||||||||||||||||||
| Other comprehensive income (loss): |
||||||||||||||||||||||||||||||||
| Deferred hedging activity, net of tax: |
||||||||||||||||||||||||||||||||
| Hedge fair value changes, net |
— | — | — | — | — | 89,152 | 49,361 | 138,513 | ||||||||||||||||||||||||
| Net hedge (gains) losses included in continuing operations |
— | — | — | — | — | 227,893 | (4,624 | ) | 223,269 | |||||||||||||||||||||||
| Balance as of December 31, 2008 |
114,546 | $ | 1,246 | $ | 2,909,735 | $ | (411,659 | ) | $ | 988,786 | $ | 88,788 | $ | 102,717 | $ | 3,679,613 | ||||||||||||||||
| Dividends declared ($0.08 per share) |
— | — | — | — | (9,388 | ) | — | — | (9,388 | ) | ||||||||||||||||||||||
| Exercise of long-term incentive plan stock options and employee stock purchases |
468 | — | — | 18,110 | (9,604 | ) | — | — | 8,506 | |||||||||||||||||||||||
| Purchase of treasury stock |
(1,276 | ) | — | — | (21,662 | ) | — | — | (259 | ) | (21,921 | ) | ||||||||||||||||||||
| Tax benefits related to stock-based compensation |
— | — | 1 | — | — | — | — | 1 | ||||||||||||||||||||||||
| Compensation costs: |
||||||||||||||||||||||||||||||||
| Vested compensation awards, net |
637 | 6 | (6 | ) | — | — | — | — | — | |||||||||||||||||||||||
| Compensation costs included in net loss |
— | — | 38,332 | — | — | — | 232 | 38,564 | ||||||||||||||||||||||||
| Issuance of Pioneer Southwest common units |
— | — | 33,388 | — | — | (5,844 | ) | 33,439 | 60,983 | |||||||||||||||||||||||
| Cash contributions from noncontrolling interests |
— | — | — | — | — | — | 150 | 150 | ||||||||||||||||||||||||
| Cash distributions to noncontrolling interests |
— | — | — | — | — | — | (20,012 | ) | (20,012 | ) | ||||||||||||||||||||||
| Net income (loss) |
— | — | — | — | (52,106 | ) | — | 9,839 | (42,267 | ) | ||||||||||||||||||||||
| Other comprehensive income (loss): |
||||||||||||||||||||||||||||||||
| Deferred hedging activity, net of tax: |
||||||||||||||||||||||||||||||||
| Hedge fair value changes, net |
— | — | — | — | — | 10,477 | 3,692 | 14,169 | ||||||||||||||||||||||||
| Net hedge gains included in continuing operations |
— | — | — | — | — | (42,412 | ) | (22,955 | ) | (65,367 | ) | |||||||||||||||||||||
| Balance as of December 31, 2009 |
114,375 | $ | 1,252 | $ | 2,981,450 | $ | (415,211 | ) | $ | 917,688 | $ | 51,009 | $ | 106,843 | $ | 3,643,031 | ||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
74
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (continued)
(in thousands, except dividends per share)
| Shares Outstanding |
Stockholders’ Equity Attributable to Common Stockholders | Noncontrolling Interests |
Total Stockholders’ Equity |
|||||||||||||||||||||||||||||
| Common Stock |
Additional Paid-in Capital |
Treasury Stock |
Retained Earnings |
Accumulated Other Comprehensive Income |
||||||||||||||||||||||||||||
| Balance as of December 31, 2009 |
114,375 | $ | 1,252 | $ | 2,981,450 | $ | (415,211 | ) | $ | 917,688 | $ | 51,009 | $ | 106,843 | $ | 3,643,031 | ||||||||||||||||
| Dividends declared ($0.08 per share) |
— | — | — | — | (9,455 | ) | — | — | (9,455 | ) | ||||||||||||||||||||||
| Exercise of long-term incentive plan stock options and employee stock purchases |
266 | 1 | 2,577 | 7,811 | (3,014 | ) | — | — | 7,375 | |||||||||||||||||||||||
| Treasury stock purchases |
(278 | ) | — | — | (13,835 | ) | — | — | (204 | ) | (14,039 | ) | ||||||||||||||||||||
| Tax benefits related to stock-based compensation |
— | — | (153 | ) | — | — | — | — | (153 | ) | ||||||||||||||||||||||
| Compensation costs: |
||||||||||||||||||||||||||||||||
| Vested compensation awards, net |
946 | 9 | (8 | ) | — | — | — | — | 1 | |||||||||||||||||||||||
| Compensation costs included in net income |
— | — | 38,902 | — | — | — | 1,283 | 40,185 | ||||||||||||||||||||||||
| Cash contributions from noncontrolling interests |
— | — | — | — | — | — | 1,151 | 1,151 | ||||||||||||||||||||||||
| Cash distributions to noncontrolling interests |
(26,837 | ) | (26,837 | ) | ||||||||||||||||||||||||||||
| Net income |
— | — | — | — | 605,208 | — | 40,787 | 645,995 | ||||||||||||||||||||||||
| Other comprehensive loss: |
||||||||||||||||||||||||||||||||
| Deferred hedging activity, net of tax: |
||||||||||||||||||||||||||||||||
| Net hedge gains included in continuing operations |
— | — | — | — | — | (43,648 | ) | (17,581 | ) | (61,229 | ) | |||||||||||||||||||||
| Balance as of December 31, 2010 |
115,309 | $ | 1,262 | $ | 3,022,768 | $ | (421,235 | ) | $ | 1,510,427 | $ | 7,361 | $ | 105,442 | $ | 4,226,025 | ||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
75
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Cash flows from operating activities: |
||||||||||||
| Net income (loss) |
$ | 645,995 | $ | (42,267 | ) | $ | 231,655 | |||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||
| Depletion, depreciation and amortization |
574,170 | 628,987 | 474,608 | |||||||||
| Impairment of oil and gas properties |
— | 21,091 | 89,753 | |||||||||
| Exploration expenses, including dry holes |
132,772 | 37,375 | 115,497 | |||||||||
| Hurricane activity, net |
4,508 | 19,850 | 9,000 | |||||||||
| Deferred income taxes |
248,146 | (75,813 | ) | 131,215 | ||||||||
| (Gain) loss on disposition of assets, net |
(19,074 | ) | 774 | 381 | ||||||||
| Gain on extinguishment of debt |
— | — | (20,515 | ) | ||||||||
| Accretion of discount on asset retirement obligations |
10,433 | 10,599 | 7,717 | |||||||||
| Discontinued operations |
10,494 | (30,601 | ) | 87,594 | ||||||||
| Interest expense |
30,472 | 27,996 | 28,491 | |||||||||
| Derivative related activity |
(419,809 | ) | 75,633 | 45,166 | ||||||||
| Amortization of stock-based compensation |
39,854 | 37,638 | 34,077 | |||||||||
| Amortization of deferred revenue |
(90,216 | ) | (147,905 | ) | (158,139 | ) | ||||||
| Other noncash items |
26,581 | 35,994 | 61,751 | |||||||||
| Change in operating assets and liabilities |
||||||||||||
| Accounts receivable, net |
36,653 | 16,293 | 45,446 | |||||||||
| Income taxes receivable |
(5,878 | ) | 36,030 | (20,528 | ) | |||||||
| Inventories |
(26,281 | ) | (46,708 | ) | (82,403 | ) | ||||||
| Prepaid expenses |
(3,874 | ) | (3,387 | ) | (3,405 | ) | ||||||
| Other current assets |
(14,270 | ) | 87,642 | (11,745 | ) | |||||||
| Accounts payable |
128,927 | (65,862 | ) | 65,644 | ||||||||
| Interest payable |
11,999 | 3,762 | 1,227 | |||||||||
| Income taxes payable |
4,007 | 13,793 | (9,225 | ) | ||||||||
| Other current liabilities |
(40,586 | ) | (97,855 | ) | (89,399 | ) | ||||||
| Net cash provided by operating activities |
1,285,023 | 543,059 | 1,033,863 | |||||||||
| Cash flows from investing activities: |
||||||||||||
| Proceeds from disposition of assets, net of cash sold |
313,780 | 51,600 | 292,920 | |||||||||
| Investment in unconsolidated subsidiary |
(72,864 | ) | — | — | ||||||||
| Additions to oil and gas properties |
(1,011,442 | ) | (437,240 | ) | (1,403,272 | ) | ||||||
| Additions to other assets and other property and equipment, net |
(184,330 | ) | (25,345 | ) | (41,058 | ) | ||||||
| Net cash used in investing activities |
(954,856 | ) | (410,985 | ) | (1,151,410 | ) | ||||||
| Cash flows from financing activities: |
||||||||||||
| Borrowings under long-term debt |
292,342 | 1,015,842 | 1,032,998 | |||||||||
| Principal payments on long-term debt |
(475,252 | ) | (1,175,703 | ) | (807,239 | ) | ||||||
| Contributions from noncontrolling interests |
1,151 | 150 | — | |||||||||
| Distributions to noncontrolling interests |
(26,837 | ) | (20,012 | ) | (8,635 | ) | ||||||
| Proceeds from issuance of partnership common units, net of issuance costs |
— | 60,983 | 165,978 | |||||||||
| Borrowings (payments) of other liabilities |
(21,329 | ) | 486 | (7,793 | ) | |||||||
| Exercise of long-term incentive plan stock options and employee stock purchases |
7,375 | 8,506 | 8,068 | |||||||||
| Purchase of treasury stock |
(14,039 | ) | (21,921 | ) | (181,737 | ) | ||||||
| Excess tax benefits from share-based payment arrangements |
(153 | ) | 1 | 367 | ||||||||
| Payment of financing fees |
(145 | ) | (12,005 | ) | (12,377 | ) | ||||||
| Dividends paid |
(9,488 | ) | (9,370 | ) | (35,917 | ) | ||||||
| Net cash provided by (used in) financing activities |
(246,375 | ) | (153,043 | ) | 153,713 | |||||||
| Net increase (decrease) in cash and cash equivalents |
83,792 | (20,969 | ) | 36,166 | ||||||||
| Cash and cash equivalents, beginning of period |
27,368 | 48,337 | 12,171 | |||||||||
| Cash and cash equivalents, end of period |
$ | 111,160 | $ | 27,368 | $ | 48,337 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
76
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Net income (loss) |
$ | 645,995 | $ | (42,267 | ) | $ | 231,655 | |||||
| Other comprehensive income (loss): |
||||||||||||
| Hedge activity: |
||||||||||||
| Hedge fair value changes, net |
— | 12,974 | 218,202 | |||||||||
| Net hedge (gains) losses included in continuing operations |
(84,877 | ) | (114,231 | ) | 356,731 | |||||||
| Income tax provision (benefit) |
23,648 | 50,059 | (213,151 | ) | ||||||||
| Other comprehensive income (loss) |
(61,229 | ) | (51,198 | ) | 361,782 | |||||||
| Comprehensive income (loss) |
584,766 | (93,465 | ) | 593,437 | ||||||||
| Comprehensive (income) loss attributable to noncontrolling interest |
(23,206 | ) | 9,424 | (66,372 | ) | |||||||
| Comprehensive income (loss) attributable to common stockholders |
$ | 561,560 | $ | (84,041 | ) | $ | 527,065 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
77
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
NOTE A. Organization and Nature of Operations
Pioneer is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company with continuing operations in the United States and South Africa.
NOTE B. Summary of Significant Accounting Policies
Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. In accordance with generally accepted accounting principles in the United States (“GAAP”), the Company proportionately consolidates certain affiliate partnerships that are less than wholly-owned and are involved in oil and gas producing activities. All material intercompany balances and transactions have been eliminated.
Discontinued operations. During December 2010, the Company committed to a plan to divest 100 percent of the capital stock of its Tunisian subsidiaries, which own all of the Company’s oil and gas properties in Tunisia. The Company completed the sale of its Tunisian subsidiaries during February 2011 (see Note U for more information about the sale of the Tunisian subsidiaries). Accordingly, the Company has classified the assets and liabilities of its Tunisia operations as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2010, and the historic results of operations of its Tunisia operations as income from discontinued operations, net of tax in the accompanying consolidated statements of operations.
During 2009, the Company sold its oil and gas asset properties in Mississippi and substantially all of its shelf properties in the Gulf of Mexico. In accordance with GAAP, the Company classified the results of operations attributable to these divestitures as discontinued operations, rather than as a component of continuing operations.
During 2009, the Company recorded a $119.3 million trade receivable from the Bureau of Ocean Energy Management, Regulation, and Enforcement (the “BOEMRE”) for the recovery of excess royalties paid by the Company on qualifying deepwater leases in the Gulf of Mexico. The BOEMRE paid the Company the $119.3 million receivable and associated interest of $35.3 million during 2010. The properties that were the source of these royalty and interest recoveries were sold by the Company during 2006. Accordingly, the Company has recorded these receipts as income from discontinued operations, net of tax in the accompanying consolidated statements of operations. See Note U for additional information regarding the Company’s discontinued operations.
Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves; commodity price outlooks; foreign laws, restrictions and currency exchange rates; and export and excise taxes. Actual results could differ from the estimates and assumptions utilized.
Cash equivalents. Cash and cash equivalents include cash on hand and depository accounts held by banks.
Accounts and notes receivable. As of December 31, 2010 and 2009, the Company had accounts receivable – trade, net of allowances for bad debts, of $237.5 million and $330.7 million, respectively, and notes receivable, net of allowances for bad debts, of nil and $4.7 million as of December 31, 2010 and 2009, respectively. The Company’s accounts receivable – trade are primarily comprised of oil and gas sales receivable, joint operations receivables and other receivables for which the Company does not require collateral security. The Company’s notes receivable are primarily comprised of notes collateralized by drilling rigs and long-lived assets.
As of December 31, 2010 and 2009, the Company’s allowances for doubtful accounts totaled $3.7 million and $14.3 million, respectively. In accordance with GAAP, the Company establishes allowances for bad debts equal to the estimable portions of accounts and notes receivables for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint
78
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company’s consolidated balance sheets and as charges to other expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable.
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
| (in thousands) | ||||||||
| Beginning allowance for doubtful accounts balance |
$ | 14,299 | $ | 32,365 | ||||
| Amount charged (credited) to costs and expenses, net |
(442 | ) | 4,356 | |||||
| Other net decreases (a) |
(10,183 | ) | (22,422 | ) | ||||
| Ending allowance for doubtful accounts balance |
$ | 3,674 | $ | 14,299 | ||||
| (a) | Includes $19.6 million of SemGroup bad debt allowance written off upon sale of claims receivable during 2009. See Note N additional information. |
Investments. Investments in unaffiliated equity securities that have a readily determinable fair value are classified as “trading securities” if management’s current intent is to hold them for the near term; otherwise, they are accounted for as “available-for-sale” securities. The Company reevaluates the classification of investments in unaffiliated equity securities at each balance sheet date. The carrying value of trading securities and available-for-sale securities are adjusted to fair value as of each balance sheet date and are included in other noncurrent assets in the accompanying balance sheets.
Unrealized holding gains are recognized for trading securities in interest and other income, and unrealized holding losses are recognized in other expense during the periods in which changes in fair value occur.
Unrealized holding gains and losses are recognized for available-for-sale securities as credits or charges to stockholders’ equity and other comprehensive income (loss) during the periods in which changes in fair value occur. Realized gains and losses on the divestiture of available-for-sale securities are determined using the average cost method. The Company had no investments in available-for-sale securities as of December 31, 2010 or 2009.
Investments in unaffiliated equity securities that do not have a readily determinable fair value are measured at the lower of their original cost or the net realizable value of the investment. The Company had no significant equity security investments that did not have a readily determinable fair value as of December 31, 2010 or 2009.
Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 61.9 percent limited partner interest in Pioneer Southwest Energy Partners L.P. (“Pioneer Southwest”). Pioneer Southwest owns interests in certain oil and gas properties previously owned by the Company in the Spraberry field in the Permian Basin of West Texas. The financial position, results of operations, and cash flows of Pioneer Southwest are consolidated with those of the Company.
During January 2010, Pioneer Natural Resources USA, Inc. (“PNR USA,” a wholly-owned subsidiary of the Company) formed Sendero Drilling Company, LLC (“Sendero”). Sendero was formed to own and operate land-based drilling rigs in the United States. As of December 31, 2010, Sendero owned 12 drilling rigs operating under contract to PNR USA in the Spraberry field. PNR USA is the majority owner of Sendero.
The Company also owns the majority interests in certain other subsidiaries with operations in the United States. Noncontrolling interests in the net assets of consolidated subsidiaries totaled $105.4 million and $106.8 million as of December 31, 2010 and 2009, respectively. The Company recorded net income attributable to the noncontrolling interests of $40.8 million, $9.8 million and $21.6 million for the years ended December 31, 2010, 2009 and 2008 (principally related to Pioneer Southwest), respectively.
Investment in unconsolidated affiliate. During 2010, the Company formed EFS Midstream LLC (“EFS Midstream”) to own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale area of South Texas. During June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an
79
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
unaffiliated third party for $46.4 million of cash proceeds. Associated therewith, the Company recorded a $46.2 million deferred gain that is being amortized as a reduction in production costs over a 20 year period, representing the term of a continuing commitment of Pioneer to deliver production volumes through EFS Midstream handling and gathering facilities. The deferred gain is included in other current and noncurrent liabilities in the Company’s accompanying consolidated balance sheet as of December 31, 2010.
The Company does not have voting control of EFS Midstream. Consequently, the Company accounts for this investment under the equity method of accounting for investments in unconsolidated affiliates. Under the equity method, the Company’s investment in unconsolidated affiliates is increased for investments made and the investor’s share of the investee’s net income, and decreased for distributions received, the carrying value of member interests sold and the investor’s share of the investee’s net losses. The Company’s equity interest in the net income of EFS Midstream is recorded in other expense in the Company’s accompanying consolidated statement of operations.
Inventories. Inventories were comprised of $197.0 million and $205.6 million of materials and supplies and $3.9 million and $3.2 million of commodities as of December 31, 2010 and 2009, respectively. The Company’s materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. “Market,” in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. Valuation reserve allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supply inventories in the Company’s consolidated balance sheets and as other expense in the accompanying consolidated statements of operations. As of December 31, 2010 and 2009, the Company’s materials and supplies inventory was net of $3.6 million and $5.2 million, respectively, of valuation reserve allowances. As of December 31, 2010 and 2009, the Company estimated that $24.1 million and $69.6 million, respectively, of its materials and supplies inventory would not be utilized within one year. Accordingly, those inventory values have been classified as other noncurrent assets in the accompanying consolidated balance sheets as of December 31, 2010 and 2009. As of December 31, 2010, the Company’s inventory in Tunisia totaled $13.6 million and is classified as discontinued operations held for sale in the accompanying consolidated balance sheets.
Commodities inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company’s commodities inventories consist of oil held in storage and gas pipeline fill volumes. Any valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included in the Company’s consolidated balance sheets and as charges to other expense in the consolidated statements of operations.
Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. For large development projects requiring significant upfront development costs to support the drilling and production of a planned group of wells, the Company continues to capitalize interest on the portion of the development costs attributable to the planned wells yet to be drilled.
The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless 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 projects, it may take an extended period of time to evaluate the future potential of an exploration well and the 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 data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company’s
80
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found proved reserves or is noncommercial and is charged to exploration and abandonments expense. See Note C for additional information regarding the Company’s suspended exploratory well costs.
The Company owns interests in four gas processing plants and 11 treating facilities. The Company operates two of the gas processing plants and all eleven of the treating facilities. The Company’s ownership interests in the gas processing plants and treating facilities is primarily to accommodate handling the Company’s gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third party revenues generated from the processing plants and treating facilities for the three years ended December 31, 2010, 2009 and 2008 were $34.0 million, $26.5 million and $39.4 million, respectively. Third party expenses attributable to the processing plants and treating facilities for the same respective periods were $14.3 million, $13.7 million and $14.4 million. The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service.
Capitalized costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until such time as the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.
Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization. Generally, no gain or loss is recognized until the entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base.
The Company reviews its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Estimates of the sum of expected future cash flows requires management to estimate future recoverable proved and risk-adjusted probable and possible reserves, forecasts of future commodity prices, production timing, drilling and production costs and discount rates. Uncertainties about these future cash flow variables cause impairment estimates to be inherently imprecise. See Note R for additional information regarding the Company’s impairment assessments.
Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of 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 an impairment loss at that time.
Goodwill. During 2004, the Company recorded $327.8 million of goodwill associated with a business combination. The goodwill was recorded to the Company’s United States reporting unit. The Company has reduced goodwill by $29.6 million since the date of the business combination. The Company reduced the carrying value of goodwill by $10.6 million and $1.3 million, respectively, during 2010 and 2009 as a charge to the gain from the sale of a portion of its United States reporting unit. The remaining $17.7 million reduction in goodwill was primarily for tax benefits associated with the exercise of fully-vested stock options assumed in conjunction with the business combination. In accordance with GAAP, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2010, the Company performed its annual assessment of goodwill for impairment and determined that there was no impairment. See Note R for additional information regarding the Company’s impairment assessments.
81
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Other property and equipment, net. Other property and equipment is recorded at cost and primarily consists of owned land and buildings, drilling rigs, well servicing rigs, fracture stimulation equipment, other well servicing equipment, transportation equipment, furniture and fixtures and leasehold improvements. At December 31, 2010 and 2009, other property and equipment was net of accumulated depreciation of $235.3 million and $203.6 million, respectively.
Other items of equipment are generally depreciated by individual components on a straight line basis over their economic useful lives, which are generally from two to 12 years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases.
The Company evaluates other property and equipment for potential impairment whenever indicators of impairment are present. Circumstances that could indicate potential impairment include significant adverse changes in industry trends, economic outlook, legal actions, regulatory changes and significant declines in utilization rates or oil and gas prices. If it is determined that other property and equipment is potentially impaired, the Company performs an impairment evaluation by estimating the future undiscounted net cash flow from the use and eventual disposition of other property and equipment grouped at the lowest level that cash flows can be identified. If the sum of the future undiscounted net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the properties’ net book value over its estimated fair value.
Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated.
Asset retirement obligation expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows.
Derivatives and hedging. The Company recognizes all derivative instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through earnings. Under the provisions of GAAP, the Company may designate a derivative instrument as hedging the exposure to changes in the fair value of an asset or a liability or an identified portion thereof that is attributable to a particular risk (a “fair value hedge”) or as hedging the exposure to variability in the expected future cash flows that are attributable to a particular risk (a “cash flow hedge”). Both at the inception of a hedge and on an ongoing basis, a fair value hedge must be expected to be highly effective in achieving offsetting changes in fair value attributable to the hedged risk during the periods that a hedge is designated. Similarly, a cash flow hedge must be expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. The expectation of hedge effectiveness must be supported by matching the essential terms of the hedged asset, liability or forecasted transaction to the derivative hedge contract or by effectiveness assessments using statistical measurements.
Changes in the fair values of derivative instruments that are fair value hedges are offset against changes in the fair values of the hedged assets, liabilities, or firm commitments through earnings. Effective changes in the fair values of derivative instruments that are cash flow hedges are recognized in accumulated other comprehensive income-deferred hedge gains, net of tax (“AOCI-Hedging”) in the stockholders’ equity section of the Company’s consolidated balance sheets until such time as the hedged items are recognized in earnings. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in earnings.
Prior to December 2008, the Company had elected to designate the majority of its commodity derivative instruments as cash flow hedges. During December 2008, the Company began entering into commodity derivative contracts that were not designated as hedges. Changes in the fair values of non-hedge derivative instruments are recognized as gains or losses in the earnings of the periods in which they occur. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts. The effective portions of the discontinued deferred hedges as of February 1, 2009 are included in AOCI – Hedging and have been and will continue to be transferred to earnings during the same periods in which the forecasted hedged transactions are recognized in the Company’s earnings. Since February 1, 2009, the Company has recognized, and in the future will recognize, changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.
The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, whichever the case may be, by commodity and
82
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
master netting counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company’s credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates are based on an independent market-quoted credit default swap rate curve for the Company’s or the counterparties’ debt plus the United States Treasury Bill yield curve as of the valuation date.
As of December 31, 2010 and 2009, the Company was not a party to any fair value hedges. See Note I for a description of the specific types of cash flow derivative transactions in which the Company participates.
Environmental. The Company’s environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs.
Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.
Revenue recognition. The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.
The Company uses the entitlements method of accounting for oil, natural gas liquids (“NGL”) and gas revenues. Sales proceeds in excess of the Company’s entitlement are included in other liabilities and the Company’s share of sales taken by others is included in other assets in the accompanying consolidated balance sheets.
The Company had no material oil entitlement assets or NGL entitlement assets or liabilities as of December 31, 2010 or 2009. The following table presents the Company’s oil entitlement liabilities and gas entitlement assets and liabilities with their associated volumes as of December 31, 2010 and 2009:
| December 31, | ||||||||||||||||
| 2010 | 2009 | |||||||||||||||
| Amount | Volume | Amount | Volume | |||||||||||||
| (dollars in millions) | ||||||||||||||||
| Oil entitlement liabilities (volumes in MBbls) |
$ | 1.2 | 13 | $ | 1.6 | 22 | ||||||||||
| Gas entitlement assets (volumes in MMcf) |
$ | 7.6 | 3,015 | $ | 7.6 | 2,967 | ||||||||||
| Gas entitlement liabilities (volumes in MMcf) |
$ | 1.6 | 439 | $ | 3.3 | 781 | ||||||||||
Stock-based compensation. For stock-based compensation awards granted or modified, compensation expense is being recognized in the Company’s financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant. The amount of compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day’s closing stock price on the date of grant for the fair value of restricted stock awards settled wholly or partially in the Company’s common stock or restricted stock units (“Equity Awards”), (iii) the Monte Carlo simulation method for the fair value of performance unit awards, and (iv) a probabilistic forecasted fair value method for Series B unit awards issued by Sendero.
Stock-based compensation liability awards are awards that are expected to be settled wholly or partially in cash on their vesting dates, rather than in equity shares or units (“Liability Awards”). Stock-based Liability Awards are recorded as accounts payable—affiliates based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense.
83
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
New accounting pronouncements. Effective December 31, 2009, the Company adopted the SEC’s final rule on “Modernization of Oil and Gas Reporting” (the “Reserve Ruling”) and the Financial Accounting Standards Board’s (the “FASB”) Accounting Standards Update (“ASU”) 2010-03, which conforms Accounting Standards Codification (“ASC”) 932 to the Reserve Ruling. The Reserve Ruling revises oil and gas reporting disclosures, permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes and allows companies the option to disclose probable and possible oil and gas reserves. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor, (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit and (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than a period-end price. See Unaudited Supplementary Information for information regarding the adoption of the Reserve Ruling and ASU 2010-03.
During January 2010, the FASB issued ASU No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820).” ASU No. 2010-06 amends ASC Topic 820 to (i) require separate disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers, (ii) require separate disclosure of purchases, sales, issuances and settlements in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), (iii) clarify the level of disaggregation for fair value measurements of assets and liabilities and (iv) clarify disclosures about inputs and valuation techniques used to measure fair values for both recurring and nonrecurring fair value measurements. ASU No. 2010-06 became effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the rollforward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years. The Company adopted the provisions of ASU No. 2010-06 on January 1, 2010. The adoption of the provisions of ASU No. 2010-06 did not impact the Company’s financial position, results of operations or liquidity. See Note D for the Company’s disclosures about fair value measurements.
During February 2010, the FASB issued ASU No. 2010-09, “Subsequent Events (Topic 855).” ASU No. 2010-09 amends ASC Topic 855 to include the definition of “SEC filer” and alleviate the obligation of SEC filers to disclose the date through which subsequent events have been evaluated. ASU No. 2010-09 became effective during February 2010. See Note V for the Company’s disclosures of subsequent events.
During December 2010, the FASB issued ASU No. 2010-28, “Intangibles-Goodwill and Other (Topic 350).” ASU No. 2010-28 modifies step one of the goodwill impairment test for reporting units with zero or negative carrying amounts, requiring that an entity perform step two of the goodwill impairment test if it is more likely than not that a goodwill impairment exists for those reporting units. ASU No. 2010-28 is effective for fiscal years beginning after December 15, 2010. The adoption of ASU No. 2010-28 is not expected to have an impact on the goodwill impairment test performed by the Company.
NOTE C. Exploratory Well Costs
The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves or is impaired. The Company’s capitalized exploratory well and project costs are presented in proved properties in the consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.
The following table reflects the Company’s capitalized exploratory well and project activity during each of the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Beginning capitalized exploratory well costs |
$ | 127,574 | $ | 124,014 | $ | 130,630 | ||||||
| Additions to exploratory well costs pending the determination of proved reserves |
238,905 | 80,222 | 403,692 | |||||||||
| Reclassification due to determination of proved reserves |
(160,879 | ) | (58,792 | ) | (321,436 | ) | ||||||
| Disposition of assets sold |
(17,601 | ) | — | — | ||||||||
| Exploratory well costs charged to exploration expense (a) |
(91,806 | ) | (17,870 | ) | (88,872 | ) | ||||||
| Ending capitalized exploratory well costs |
$ | 96,193 | $ | 127,574 | $ | 124,014 | ||||||
| (a) | Includes an exploratory well credit from discontinued operations of $117 thousand in 2010, and exploratory well costs from discontinued operations of $9.9 million and $14.6 million in 2009 and 2008, respectively. |
84
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
During the fourth quarter of 2010, the Company determined that further appraisal drilling in its Cosmopolitan Unit in the Cook Inlet of Alaska would not be funded based on the project’s limited impact to the Company’s future Alaskan and overall growth profile. As a result, an exploration and abandonment charge of $97.7 million was recorded in the fourth quarter of 2010 to write off the Cosmopolitan project’s carrying value. Included in the write off was suspended well costs of $76.0 million, $14.3 million of acreage costs, $6.4 million of estimated property abandonment costs and $1.0 million of inventory impairment charges to reduce the carrying value of its pipe inventory to its resale value.
The following table provides an aging, as of December 31, 2010, 2009 and 2008 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands, except well counts) | ||||||||||||
| Capitalized exploratory well costs that have been suspended: |
||||||||||||
| One year or less |
$ | 70,635 | $ | 21,634 | $ | 54,423 | ||||||
| More than one year |
25,558 | 105,940 | 69,591 | |||||||||
| $ | 96,193 | $ | 127,574 | $ | 124,014 | |||||||
| Number of projects with exploratory well costs that have been suspended for a period greater than one year |
3 | 8 | 4 | |||||||||
The following table provides an aging of capitalized costs of exploration projects that have been suspended for more than one year as of December 31, 2010:
| Total | 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||||||||||||
| (in thousands) | ||||||||||||||||||||||||||||
| Tunisia |
$ | 25,558 | $ | 209 | $ | 274 | $ | 21,145 | $ | (15 | ) | $ | 3,945 | |||||||||||||||
During December 2010, the Company committed to a plan to divest 100 percent of the capital stock of its Tunisian subsidiaries, which own all of the Company’s oil and gas operations in Tunisia. The Company completed the sale of its Tunisian subsidiaries during February 2011. See Notes B and U for additional information about the Company’s discontinued operations. The following describes the exploration projects in Tunisia that have been suspended for more than one year.
Tunisia – Cherouq. As of December 31, 2010, the Company had $17.8 million of suspended well costs recorded for the Hayatt #1 well in the Company’s Cherouq production concession area, which is operated by the Company. The Hayatt #1 well began drilling in April 2008 to test several targeted formations. Mechanical failures were encountered during the testing of the well that did not allow completion of the formation assessments. As of December 31, 2010, the Company had project personnel at appropriate levels committed to and actively participating in analyzing seismic and other data to determine the optimal plan forward for completing the well.
Tunisia – Borj El Khadra. As of December 31, 2010, the Company had $7.8 million of suspended well costs attributable to the Nahkil #1 and Abir #1 wells in the Borj El Khadra exploration permit area, which is operated by a third-party. The Nahkil #1 well encountered oil-bearing sands and the Abir #1 well encountered gas-bearing sands. As of December 31, 2010, the third-party operator and the Company had project personnel at appropriate levels committed to and actively participating in infrastructure planning and assessment of the area. During 2010, a $13.8 million 3-D seismic program was initiated.
85
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
NOTE D. Disclosures About Fair Value Measurements
In accordance with GAAP, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:
| • | Level 1 – quoted prices for identical assets or liabilities in active markets. |
| • | Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means. |
| • | Level 3 – unobservable inputs for the asset or liability. |
The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.
The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2010 and 2009 for each of the fair value hierarchy levels:
| Fair Value Measurements at Reporting Date Using | ||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets (Level 1) |
Significant
Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Fair Value
at December 31, 2010 |
|||||||||||||
| (in thousands) | ||||||||||||||||
| Assets: |
||||||||||||||||
| Trading securities |
$ | 316 | $ | 151 | $ | — | $ | 467 | ||||||||
| Commodity derivatives |
— | 304,434 | — | 304,434 | ||||||||||||
| Interest rate derivatives |
— | 18,256 | — | 18,256 | ||||||||||||
| Deferred compensation plan assets |
36,162 | — | — | 36,162 | ||||||||||||
| Total assets |
$ | 36,478 | $ | 322,841 | $ | — | $ | 359,319 | ||||||||
| Liabilities: |
||||||||||||||||
| Commodity derivatives |
$ | — | $ | 127,311 | $ | 9,556 | $ | 136,867 | ||||||||
| Interest rate derivatives |
— | 704 | — | 704 | ||||||||||||
| Pioneer credit facility |
— | 58,382 | — | 58,382 | ||||||||||||
| Pioneer Southwest credit facility |
— | 77,241 | — | 77,241 | ||||||||||||
| 5.875% senior notes due 2016 |
475,194 | — | — | 475,194 | ||||||||||||
| 6.65% senior notes due 2017 |
516,632 | — | — | 516,632 | ||||||||||||
| 6.875% senior notes due 2018 |
480,969 | — | — | 480,969 | ||||||||||||
| 7.50% senior notes due 2020 |
494,145 | — | — | 494,145 | ||||||||||||
| 7.20% senior notes due 2028 |
259,350 | — | — | 259,350 | ||||||||||||
| 2.875% convertible senior notes due 2038 (a) |
728,400 | — | — | 728,400 | ||||||||||||
| Total liabilities |
$ | 2,954,690 | $ | 263,638 | $ | 9,556 | $ | 3,227,884 | ||||||||
| (a) | The fair value of the 2.875% convertible senior notes includes the fair value of the conversion privilege. |
86
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
| Fair Value Measurements at Reporting Date Using | ||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Fair Value at December 31, 2009 |
|||||||||||||
| (in thousands) | ||||||||||||||||
| Assets: |
||||||||||||||||
| Trading securities |
$ | 251 | $ | 84 | $ | — | $ | 335 | ||||||||
| Commodity derivatives |
— | 82,678 | 1,402 | 84,080 | ||||||||||||
| Interest rate derivatives |
— | 8,264 | — | 8,264 | ||||||||||||
| Deferred compensation plan assets |
27,890 | — | — | 27,890 | ||||||||||||
| Notes receivable |
— | — | 4,727 | 4,727 | ||||||||||||
| Total assets |
$ | 28,141 | $ | 91,026 | $ | 6,129 | $ | 125,296 | ||||||||
| Liabilities: |
||||||||||||||||
| Commodity derivatives |
$ | — | $ | 209,249 | $ | 14,306 | $ | 223,555 | ||||||||
| Interest rate derivatives |
— | 26,105 | — | 26,105 | ||||||||||||
| Pioneer credit facility |
— | 259,461 | — | 259,461 | ||||||||||||
| Pioneer Southwest credit facility |
— | 68,495 | — | 68,495 | ||||||||||||
| 5.875% senior notes due 2012 |
6,154 | — | — | 6,154 | ||||||||||||
| 5.875% senior notes due 2016 |
437,170 | — | — | 437,170 | ||||||||||||
| 6.65% senior notes due 2017 |
472,546 | — | — | 472,546 | ||||||||||||
| 6.875% senior notes due 2018 |
438,402 | — | — | 438,402 | ||||||||||||
| 7.50% senior notes due 2020 |
449,566 | — | — | 449,566 | ||||||||||||
| 7.20% senior notes due 2028 |
230,868 | — | — | 230,868 | ||||||||||||
| 2.875% convertible senior notes due 2038 (a) |
508,320 | — | — | 508,320 | ||||||||||||
| Total liabilities |
$ | 2,543,026 | $ | 563,310 | $ | 14,306 | $ | 3,120,642 | ||||||||
| (a) | The fair value of the 2.875% convertible senior notes includes the fair value of the conversion privilege. |
The following tables present the changes in the fair values of the Company’s net commodity derivative assets (liabilities) and notes receivable classified as Level 3 in the fair value hierarchy for the year ended December 31, 2010:
| Fair Value Measurements Using Significant Unobservable Inputs (Level 3) |
Year Ended December 31, 2010 | |||||||||||
| NGL Swap Contracts |
Notes Receivable |
Total | ||||||||||
| (in thousands) | ||||||||||||
| Beginning asset (liability) balance |
$ | (12,904 | ) | $ | 4,727 | $ | (8,177 | ) | ||||
| Total gains and losses: |
||||||||||||
| Net unrealized losses included in earnings (a) |
10,690 | — | 10,690 | |||||||||
| Net realized gains transferred to earnings (a) |
(7,180 | ) | — | (7,180 | ) | |||||||
| Notes receivable valuation allowance recoveries included in earnings (b) |
— | 187 | 187 | |||||||||
| Settlement receipts (c) |
(162 | ) | (4,914 | ) | (5,076 | ) | ||||||
| Ending liability balance |
$ | (9,556 | ) | $ | — | $ | (9,556 | ) | ||||
| (a) | The hedge-effective portions of realized gains and losses on commodity derivatives in AOCI— Hedging are included in oil and gas revenues, while non-hedge derivative gains and losses or ineffective portions of realized and unrealized hedge derivatives gains and losses are included in net derivative gains (losses) in the accompanying consolidated statements of operations. |
| (b) | The valuation allowance recoveries associated with the Company’s notes receivable are included in other expense in the accompanying consolidated statements of operations. |
| (c) | During 2010, the Company settled the notes receivable by taking possession of a drilling rig that was the collateral for the notes receivable. |
87
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following table presents the carrying amounts and fair values of the Company’s financial instruments as of December 31, 2010 and 2009:
| December 31, 2010 | December 31, 2009 | |||||||||||||||
| Carrying Value |
Fair Value | Carrying Value |
Fair Value | |||||||||||||
| (in thousands) | ||||||||||||||||
| Assets: |
||||||||||||||||
| Commodity price derivatives |
$ | 304,434 | $ | 304,434 | $ | 84,080 | $ | 84,080 | ||||||||
| Interest rate derivatives |
$ | 18,256 | $ | 18,256 | $ | 8,264 | $ | 8,264 | ||||||||
| Trading securities |
$ | 467 | $ | 467 | $ | 335 | $ | 335 | ||||||||
| Deferred compensation plan assets |
$ | 36,162 | $ | 36,162 | $ | 27,890 | $ | 27,890 | ||||||||
| Notes receivable |
$ | — | $ | — | $ | 4,727 | $ | 4,727 | ||||||||
| Liabilities: |
||||||||||||||||
| Commodity price derivatives |
$ | 136,867 | $ | 136,867 | $ | 223,555 | $ | 223,555 | ||||||||
| Interest rate derivatives |
$ | 704 | $ | 704 | $ | 26,105 | $ | 26,105 | ||||||||
| Pioneer credit facility |
$ | 49,000 | $ | 58,382 | $ | 240,000 | $ | 259,461 | ||||||||
| Pioneer Southwest credit facility |
$ | 81,200 | $ | 77,241 | $ | 67,000 | $ | 68,495 | ||||||||
| 5.875 % senior notes due 2012 |
$ | — | $ | — | $ | 6,168 | $ | 6,154 | ||||||||
| 5.875 % senior notes due 2016 |
$ | 396,880 | $ | 475,194 | $ | 389,109 | $ | 437,170 | ||||||||
| 6.65 % senior notes due 2017 |
$ | 484,045 | $ | 516,632 | $ | 483,914 | $ | 472,546 | ||||||||
| 6.875 % senior notes due 2018 |
$ | 449,192 | $ | 480,969 | $ | 449,161 | $ | 438,402 | ||||||||
| 7.50 % senior notes due 2020 |
$ | 446,433 | $ | 494,145 | $ | 446,172 | $ | 449,566 | ||||||||
| 7.20 % senior notes due 2028 |
$ | 249,925 | $ | 259,350 | $ | 249,924 | $ | 230,868 | ||||||||
| 2.875% convertible senior notes due 2038 (a) |
$ | 444,994 | $ | 728,400 | $ | 429,563 | $ | 508,320 | ||||||||
| (a) | The fair value of the 2.875% convertible senior notes includes the fair value of the conversion privilege. |
Trading securities and deferred compensation plan assets. The Company’s trading securities represent securities that are both actively traded and not actively traded on major exchanges. The Company’s deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges plus unallocated contributions as of the measurement date. As of December 31, 2010, all significant inputs to these exchange-traded asset values represented Level 1 independent active exchange market price inputs except inputs for certain trading securities that are not actively traded on major exchanges, which were provided by broker quotes representing Level 2 inputs.
Interest rate derivatives. The Company’s interest rate derivative assets and liabilities as of December 31, 2010 and 2009 represent (i) swap contracts for $189 million and $289 million notional amount of debt, respectively, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate and (ii) swap contracts for $470 million and $400 million notional amount of debt, respectively, whereby the Company pays a variable LIBOR-based rate and the counterparty pays a fixed rate of interest. The net derivative asset and liability values attributable to the Company’s interest rate derivative contracts as of December 31, 2010 and 2009 were determined based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy priority.
Commodity derivatives. The Company’s commodity derivative assets and liabilities represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts (which are also known as three-way collar contracts). The Company’s oil and gas swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority and NGL derivative contract asset and liability measurements represent Level 3 inputs in the hierarchy priority.
Oil derivatives. The Company’s oil derivatives are swap, collar and three-way collar contracts for notional barrels (“Bbls”) of oil at fixed (in the case of swap contracts) or interval (in the case of collar and three-way collar contracts) New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices and (for certain oil derivatives that the Company was a party to as of December 31, 2009) Dated Brent oil prices. The asset and liability values attributable to the Company’s oil derivatives were determined based on (i) the contracted notional
88
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) independent active market-quoted Dated Brent price quotes, (iv) the applicable estimated credit-adjusted risk-free rate yield curve and (v) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company’s collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling oil options and were corroborated by market-quoted volatility factors.
NGL derivatives. The Company’s NGL derivatives include swap and collar contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs, Conway-posted-price NGLs or NGL component prices per Bbl. The asset and liability values attributable to the Company’s NGL derivatives were determined based on (i) the contracted notional volumes, (ii) independent active market-quoted NGL component prices and (iii) the applicable credit-adjusted risk-free rate yield curve. The implied rates of volatility inherent in the Company’s collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling NGL options and were corroborated by market-quoted volatility factors. As of December 31, 2009, the Company’s NGL component price inputs were obtained from independent brokers active in buying and selling NGL derivative contracts.
Gas derivatives. The Company’s gas derivatives are swap, collar and three-way collar contracts for notional volumes of gas (expressed in millions of British thermal units “MMBtus”) contracted at various posted price indexes, including NYMEX Henry Hub (“HH”) swap contracts coupled with basis swap contracts that convert the HH price index point to other price indexes. The asset and liability values attributable to the Company’s gas derivative contracts were determined based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices, (iv) the applicable credit-adjusted risk-free rate yield curve and (v) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company’s collar contracts and three-way collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling gas options and were corroborated by market-quoted volatility factors.
Credit facility. The fair value of the Company’s credit facility and Pioneer Southwest’s credit facility is based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.
Senior notes. The Company’s senior notes represent debt securities that are actively traded on major exchanges. The fair values of the Company’s senior notes are based on their periodic values as quoted on the major exchanges.
Concentrations of credit risk. As of December 31, 2010, the Company’s primary concentration of credit risks are the risks of collecting accounts receivable – trade and the risk of counterparties’ failure to perform under derivative obligations. See Note B for information regarding the Company’s accounts receivable – trade and Note J for information regarding the Company’s major customers.
The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note I for additional information regarding the Company’s derivative activities and Note J for information regarding derivative assets and liabilities by counterparty.
89
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
NOTE E. Long-term Debt
Long-term debt, including the effects of net deferred fair value hedge losses and issuance discounts and premiums, consisted of the following components at December 31, 2010 and 2009:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (in thousands) | ||||||||
| Outstanding debt principal balances: |
||||||||
| Pioneer credit facility |
$ | 49,000 | $ | 240,000 | ||||
| Pioneer Southwest credit facility |
81,200 | 67,000 | ||||||
| 5.875% senior notes due 2012 |
— | 6,110 | ||||||
| 5.875% senior notes due 2016 |
455,385 | 455,385 | ||||||
| 6.65% senior notes due 2017 |
485,100 | 485,100 | ||||||
| 6.875 % senior notes due 2018 |
449,500 | 449,500 | ||||||
| 7.500 % senior notes due 2020 |
450,000 | 450,000 | ||||||
| 7.20% senior notes due 2028 |
250,000 | 250,000 | ||||||
| 2.875% convertible senior notes due 2038 |
480,000 | 480,000 | ||||||
| 2,700,185 | 2,883,095 | |||||||
| Issuance discounts and premiums, net |
(96,515 | ) | (119,819 | ) | ||||
| Net deferred fair value hedge losses |
(2,000 | ) | (2,265 | ) | ||||
| Total long-term debt |
$ | 2,601,670 | $ | 2,761,011 | ||||
Credit Facility. During April 2007, the Company entered into an Amended and Restated 5-Year Revolving Credit Agreement (the “Credit Facility”) with a syndicate of financial institutions that matures in April 2012, unless extended in accordance with the terms of the Credit Facility. The Credit Facility provides for aggregate loan commitments of $1.5 billion. As of December 31, 2010, the Company had $49.0 million of outstanding borrowings under the Credit Facility and $65.1 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $1.4 billion of unused borrowing capacity under the Credit Facility.
Effective April 29, 2009, the Company and the lenders amended the Credit Facility to provide the Company additional financial flexibility. The Credit Facility contained certain financial covenants, one of which required the Company to maintain a ratio of the net present value of the Company’s oil and gas properties to total debt of at least 1.75 to 1.0 until the Company achieves an investment grade rating by certain independent rating agencies. The amendment changed the ratio maintenance requirement to 1.5 to 1.0 through the period ending March 31, 2011, after which time the ratio reverts to 1.75 to 1.0, and further provides that the Company may include in the calculation of the present value of its oil and gas properties 75 percent of the market value of its ownership of limited partner units of Pioneer Southwest. The covenant requiring the Company to maintain a ratio of total debt to total capitalization of no more than 0.60 to 1.0 was not changed. The variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) are subject to adjustment by the lenders and, therefore, the amount that the Company may borrow under the Credit Facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items. The lenders may declare any outstanding obligations under the Credit Facility immediately due and payable upon the occurrence, and during the continuance of, an event of default. As of December 31, 2010, the Company was in compliance with all of its debt covenants.
The amendment also adjusted certain borrowing rates and commitment fees, and changed certain provisions relating to the consequences if a lender under the Credit Facility defaults in its obligations under the agreement. After taking into account the amendment, revolving loans under the Credit Facility bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by JPMorgan Chase Bank or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin (“ABR Margin”), which is currently one percent based on the Company’s debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the “Applicable Margin”), which is currently two percent and is also determined by the Company’s debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the “ASK” rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee,
90
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company’s debt rating (currently 0.375 percent).
In May 2008, Pioneer Southwest entered into a $300 million unsecured revolving credit facility with a syndicate of financial institutions, which matures in May 2013 (the “Pioneer Southwest Credit Facility”). As of December 31, 2010, there were $81.2 million of outstanding borrowings under the Pioneer Southwest Credit Facility. The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions. Borrowings under the Pioneer Southwest Credit Facility may be in the form of Eurodollar rate loans, base rate committed loans or swing line loans. Eurodollar rate loans bear interest annually at LIBOR, plus a margin (the “Applicable Rate”) (currently 0.875 percent) that is determined by a reference grid based on Pioneer Southwest’s consolidated leverage ratio. Base rate committed loans bear interest annually at a base rate equal to the higher of (i) the Federal Funds Rate plus 0.5 percent or (ii) the Bank of America prime rate (the “Base Rate”) plus a margin (currently zero percent). Swing line loans bear interest annually at the Base Rate plus the Applicable Rate.
The Pioneer Southwest Credit Facility contains certain financial covenants, including (i) the maintenance of a quarter end maximum leverage ratio of not more than 3.5 to 1.00, (ii) an interest coverage ratio (representing a ratio of earnings before depreciation, depletion and amortization; impairment of long-lived assets; exploration expense; accretion of discount on asset retirement obligations; interest expense; income taxes; gain or loss on the disposition of assets; noncash commodity hedge and derivative related activity; and noncash equity-based compensation to interest expense) of not less than 2.5 to 1.0 and (iii) the maintenance of a ratio of the net present value of Pioneer Southwest’s projected future cash flows from its oil and gas assets to total debt of at least 1.75 to 1.0. As of December 31, 2010, Pioneer Southwest was in compliance with all of its debt covenants.
As of December 31, 2010, the borrowing capacity under the Pioneer Southwest Credit Facility was approximately $219 million. However, because of the net present value covenant, Pioneer Southwest’s borrowing capacity under the credit facility may be limited in the future. The variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) are subject to adjustment by the lenders. As a result, further declines in commodity prices could reduce Pioneer Southwest’s borrowing capacity under the Pioneer Southwest Credit Facility. In addition, the Pioneer Southwest Credit Facility contains various covenants that limit, among other things, Pioneer Southwest’s ability to grant liens, incur additional indebtedness, engage in a merger, enter into transactions with affiliates, pay distributions or repurchase equity and sell its assets. If any default or event of default (as defined in the Pioneer Southwest Credit Facility) were to occur, the Pioneer Southwest Credit Facility would prohibit Pioneer Southwest from making distributions to unitholders. Such events of default include, among other things, nonpayment of principal or interest, violations of covenants, bankruptcy and material judgments and liabilities.
Pioneer Southwest pays a commitment fee on the undrawn amounts under the Pioneer Southwest Credit Facility. The commitment fee is variable based on the Partnership’s consolidated leverage ratio. For 2010, the commitment fee was 0.175 percent.
Senior notes. During November 2009, the Company issued $450 million of 7.50% Senior Notes due 2020 and received proceeds, net of approximately $11.4 million of offering discounts and costs, of approximately $438.6 million. The Company used the net proceeds to reduce outstanding borrowings under the Credit Facility.
Senior notes redemption. On March 15, 2010, the Company redeemed for cash all of its outstanding 5.875% senior notes due 2012 for $6.3 million, which represented the outstanding principal plus accrued and unpaid interest.
Convertible senior notes. During January 2008, the Company issued $500 million of 2.875% Convertible Senior Notes, of which $480 million remains outstanding at December 31, 2010. Effective January 1, 2009, the Company adopted the new provisions of FASB Accounting Standards Codification (“ASC”) Topic 470, the provisions of which were applied on a retrospective basis. The adoption of the new provisions of ASC Topic 470 effective January 1, 2009 decreased the carrying value of the 2.875% Convertible Senior Notes by $63.5 million, increased stockholders’ equity by $39.5 million and increased deferred tax liabilities by $24.0 million.
The Company’s 2.875% Convertible Senior Notes are convertible under certain circumstances, using a net share settlement process, into a combination of cash and the Company’s common stock pursuant to a formula. The initial base conversion price is approximately $72.60 per share (subject to adjustment in certain circumstances), which is equivalent to an initial base conversion rate of 13.7741 common shares per $1,000 principal amount of convertible notes. In general, upon conversion of a note, the holder of such note will receive cash equal to the principal amount of
91
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
the note and the Company’s common stock for the note’s conversion value in excess of such principal amount. If at the time of conversion the applicable price of the Company’s common stock exceeds the base conversion price, holders will receive up to an additional 8.9532 shares of the Company’s common stock per $1,000 principal amount of notes, as determined pursuant to a specified formula.
The 2.875% Convertible Senior Notes mature on January 15, 2038 (the “Maturity Date”). The Company may redeem the 2.875% Convertible Senior Notes for cash at any time on or after January 15, 2013 at a price equal to full principal amount plus accrued and unpaid interest. Holders of the 2.875% Convertible Senior Notes may require the Company to purchase their 2.875% Convertible Senior Notes for cash at a price equal to 100 percent of the principal amount plus accrued and unpaid interest if certain defined fundamental changes occur, as defined in the agreement, or on January 15, 2013, 2018, 2023, 2028 or 2033. Additionally, holders may convert their notes at their option in the following circumstances:
| • | Following defined periods during which the reported sales prices of the Company’s common stock exceeds 130 percent of the base conversion price (initially $72.60 per share); |
| • | During five-day periods following defined circumstances when the trading price of the 2.875% Convertible Senior Notes is less than 97 percent of the price of the Company’s common stock times a defined conversion rate; |
| • | Upon notice of redemption by the Company; and |
| • | During the period beginning October 15, 2037, and ending at the close of business on the business day immediately preceding the Maturity Date. |
As of December 31, 2010, the 2.875% Convertible Senior Notes were not convertible at the option of the holders. However, if the 2.875% Convertible Senior Notes had been convertible as of December 31, 2010, the note holders would have received $480 million of cash and approximately 1.6 million shares of the Company’s common stock, which was valued at $142.3 million at December 31, 2010.
Interest on the principal amount of the 2.875% Convertible Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. Beginning on January 15, 2013, during any six-month period thereafter from January 15 to July 14 and from July 15 to January 14, if the average trading day price of a 2.875% Convertible Senior Note for the five consecutive trading days immediately preceding the first day of the applicable six-month interest period equals or exceeds $1,200, interest on the principal amount of the 2.875% Convertible Senior Notes will be 2.375% solely for the relevant interest period.
As of December 31, 2010 and 2009, the 2.875% Convertible Senior Notes had an unamortized discount of $35.0 million and $50.4 million, respectively, and a net carrying value of $445.0 million and $429.6 million, respectively. The unamortized discount is being amortized ratably through January 2013. For the years ended December 31, 2010, 2009 and 2008, the Company recorded $31.1 million, $29.9 million and 28.8 million, respectively, of interest expense relating to the 2.875% Convertible Senior Notes, which had an effective interest rate of 6.75 percent.
The Company’s senior notes and convertible senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes and senior convertible notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company’s senior notes and senior convertible notes is payable semiannually.
Principal maturities. Principal maturities of long-term debt at December 31, 2010, are as follows (in thousands):
| 2011 |
$ | — | ||
| 2012 |
$ | 49,000 | ||
| 2013 |
$ | 561,200 | ||
| 2014 |
$ | — | ||
| 2015 |
$ | — | ||
| Thereafter |
$ | 2,089,985 |
92
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The principal maturities during 2013 in the preceding table represent the Company’s 2.875% Convertible Senior Notes, which are subject to repurchase at the option of the holders in 2013, and the Pioneer Southwest Credit Facility.
Interest expenses. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Cash payments for interest |
$ | 155,854 | $ | 151,246 | $ | 155,987 | ||||||
| Accretion/amortization of discounts or premiums on loans |
23,304 | 21,388 | 20,523 | |||||||||
| Accretion of discount on derivative obligations |
521 | 874 | 3,151 | |||||||||
| Accretion of discount on postretirement benefit obligations |
433 | 657 | 631 | |||||||||
| Amortization of net deferred hedge losses (see Note I) |
517 | 465 | 483 | |||||||||
| Amortization of capitalized loan fees |
5,698 | 4,612 | 3,703 | |||||||||
| Net changes in accruals |
11,999 | 3,762 | 1,227 | |||||||||
| Interest incurred |
198,326 | 183,004 | 185,705 | |||||||||
| Less capitalized interest |
(15,242 | ) | (9,651 | ) | (18,935 | ) | ||||||
| Total interest expense |
$ | 183,084 | $ | 173,353 | $ | 166,770 | ||||||
NOTE F. Related Party Transactions
The Company, through a wholly-owned subsidiary, (i) serves as operator of properties in which it and its affiliated partnerships have an interest and (ii) owns a noncontrolling interest in its unconsolidated affiliate EFS Midstream, which it manages. Through these relationships, the Company is a party to transactions with the affiliated partnerships and EFS Midstream that represent related party transactions.
Transactions with affiliated partnerships. The Company receives producing well overhead and other fees related to the operation of the properties in which it and its affiliated partnerships have an interest. The affiliated partnerships also reimburse the Company for their allocated share of general and administrative charges. Reimbursements of fees are recorded as reductions to general and administrative expenses in the Company’s consolidated statements of operations.
The related party transactions with affiliated partnerships are summarized below for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Receipt of lease operating and supervision charges in accordance with standard industry operating agreements |
$ | 2,184 | $ | 2,224 | $ | 2,064 | ||||||
| Reimbursement of general and administrative expenses |
$ | 344 | $ | 265 | $ | 415 | ||||||
Transactions with EFS Midstream. The Company, through a wholly-owned subsidiary, (i) provides certain services as the manager of EFS Midstream in accordance with a Master Services Agreement and (ii) is the operator of Eagle Ford Shale properties for which EFS Midstream provides certain services under a Hydrocarbon Gathering and Handling Agreement (the “HGH Agreement”).
Master Services Agreement. The terms of the Master Services Agreement provide that the Company will perform certain manager services for EFS Midstream and be compensated by monthly fixed payments and variable payments attributable to expenses incurred by employees whose time is substantially dedicated to EFS Midstream’s business. During 2010, the Company received $1.1 million of fixed payments and $1.9 million of variable payments from EFS Midstream. The Company also received $1.1 million of proceeds from the sale of an amine plant to EFS Midstream during 2010.
93
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Hydrocarbon Gathering and Handling Agreement. During June 2010, the Company entered into the HGH Agreement with EFS Midstream. In accordance with the terms of the HGH Agreement, EFS Midstream is obligated to construct certain equipment and facilities capable of gathering, treating and transporting oil and gas production from the Eagle Ford Shale properties operated by the Company. The HGH Agreement also obligates the Company and its Eagle Ford Shale working interest partners to use the EFS Midstream gathering, treating and transportation equipment and facilities. In accordance with the terms of the HGH Agreement, the Company paid EFS Midstream $404 thousand of gathering and treating fees during 2010. See Note H for additional information about commitments under the HGH Agreement.
NOTE G. Incentive Plans
Retirement Plans
Deferred compensation retirement plan. In August 1997, the Compensation Committee of the Board of Directors (the “Board”) approved a deferred compensation retirement plan for the officers and certain key employees of the Company. Each officer and key employee is allowed to contribute up to 25 percent of their base salary and 100 percent of their annual bonus. The Company will provide a matching contribution of 100 percent of the officer’s and key employee’s contribution limited to the first ten percent of the officer’s base salary and eight percent of the key employee’s base salary. The Company’s matching contribution vests immediately. A trust fund has been established by the Company to accumulate the contributions made under this retirement plan. The Company’s matching contributions were $1.9 million, $1.7 million and $1.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.
401(k) plan. The Pioneer USA 401(k) and Matching Plan (the “401(k) Plan”) is a defined contribution plan established under the Internal Revenue Code Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute an amount up to 80 percent of their annual salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a participant’s contributions to the 401(k) Plan that are not in excess of five percent of the participant’s base compensation (the “Matching Contribution”). Each participant’s account is credited with the participant’s contributions, Matching Contributions and allocations of the 401(k) Plan’s earnings. Participants are fully vested in their account balances except for Matching Contributions and their proportionate share of 401(k) Plan earnings attributable to Matching Contributions, which proportionately vest over a four-year period that begins with the participant’s date of hire. During the years ended December 31, 2010, 2009 and 2008, the Company recognized compensation expense of $13.4 million, $11.8 million and $11.4 million, respectively, as a result of Matching Contributions.
Pioneer Long-Term Incentive Plan
In May 2006, the Company’s stockholders approved a Long-Term Incentive Plan (the “LTIP”), which provides for the granting of incentive awards in the form of stock options, stock appreciation rights, performance units, restricted stock and restricted stock units to directors, officers and employees of the Company. The LTIP provides for the issuance of 9.1 million shares pursuant to awards under the plan. The shares to be delivered under the LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company, including shares purchased on the open market.
The following table shows the number of shares available for issuance pursuant to awards under the Company’s LTIP at December 31, 2010:
| Approved and authorized awards |
9,100,000 | |||
| Awards issued after May 3, 2006 |
(5,754,473 | ) | ||
| Awards available for future grant |
3,345,527 | |||
Compensation costs. In accordance with GAAP, the Company records compensation expense, equal to the fair value of share-based payments, ratably over the vesting periods of the LTIP awards, the Series B unit awards issued by Sendero and the Pioneer Southwest Long-Term Incentive Plan (“Pioneer Southwest LTIP”) awards and for payments associated with the Company’s Employee Stock Purchase Plan (“ESPP”).
94
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following table reflects compensation expense recorded for each type of incentive award and the associated income tax benefit for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Restricted stock-equity awards (a) |
$ | 31,712 | $ | 31,929 | $ | 29,907 | ||||||
| Restricted stock-liability awards |
4,900 | — | — | |||||||||
| Stock options (b) |
1,522 | 629 | (17 | ) | ||||||||
| Performance unit awards |
4,635 | 4,868 | 3,658 | |||||||||
| Pioneer Southwest LTIP |
475 | 217 | 107 | |||||||||
| Sendero Series B units |
1,020 | — | — | |||||||||
| ESPP |
1,034 | 907 | 422 | |||||||||
| Total |
$ | 45,298 | $ | 38,550 | $ | 34,077 | ||||||
| Income tax benefit |
$ | 14,019 | $ | 11,675 | $ | 9,779 | ||||||
| (a) | For the year ended December 31, 2010, compensation expense included a charge of $1.3 million for the modification of equity awards associated with termination agreements made with 12 employees affected by the divestiture of the Company’s Tunisian subsidiaries. The modification accelerated vesting of all unvested equity awards for the 12 participants to the closing date of the transaction if the employee is not offered a position with the Company or if the employee decides to sever employment with the Company. The $1.3 million charge, net of the associated tax benefit, is included in income from discontinued operations, net of tax, in the accompanying consolidated statement of operations for the year ended December 31, 2010. |
| (b) | Cash proceeds received from stock option exercises during 2010, 2009 and 2008 amounted to $4.8 million, $6.6 million and $6.3 million, respectively. |
As of December 31, 2010, there was $55.0 million of unrecognized share-based compensation expense related to awards of unvested restricted stock, restricted stock units, performance units, stock options and phantom units issued under the Pioneer Southwest LTIP and Series B unit awards issued by Sendero. As of December 31, 2010, unrecognized compensation expense related to unvested share-based compensation plan awards is being recognized on a straight-line basis over the remaining vesting periods of the awards, which is a remaining weighted average period of less than three years.
Restricted stock awards. During 2010, the Company issued 741,131 restricted shares or units of the Company’s common stock as compensation to directors, officers and employees of the Company (including 229,555 shares or units representing Liability Awards). The Company’s issued shares, as reflected in the consolidated balance sheets as of December 31, 2010 do not include 825,796 of issued but unvested shares awarded under stock-based compensation plans that have voting rights.
The following table reflects the outstanding restricted stock awards as of December 31, 2010:
| Equity Awards | Liability Awards | |||||||||||
| Number of Shares |
Weighted Average Grant- Date Fair Value |
Number of Shares | ||||||||||
| Outstanding at beginning of year |
2,984,981 | $ | 25.69 | — | ||||||||
| Shares granted |
511,576 | $ | 48.32 | 229,555 | ||||||||
| Shares forfeited |
(82,258 | ) | $ | 29.22 | (13,604 | ) | ||||||
| Shares vested |
(854,520 | ) | $ | 29.43 | (817 | ) | ||||||
| Outstanding at end of year |
2,559,779 | $ | 28.85 | 215,134 | ||||||||
The weighted average grant-date fair value of restricted stock Equity Awards awarded during 2010, 2009 and 2008 was $48.32, $15.47 and $46.98, respectively. The fair value of shares for which restrictions lapsed during 2010, 2009 and 2008 was $42.9 million, $11.7 million and $54.5 million, respectively, based on the market price on the vesting date.
95
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
As of December 31, 2010, accounts payable – due to affiliates in the accompanying consolidated balance sheet includes $4.9 million of liabilities attributable to the Liability Awards, representing the fair value of employee services rendered in consideration for the awards as of that date. There were no Liability Awards issued in 2009 or 2008. The fair value of shares for which restrictions lapsed during 2010 was $54 thousand, based on the market price on the vesting date.
For the 2009-2010 director year, the Company’s non-employee directors were offered a choice to receive their annual fee retainers as (i) 100 percent in restricted stock units, (ii) 100 percent in cash or (iii) a combination of 50 percent cash and 50 percent restricted stock units. All non-employee directors also received an annual equity grant of restricted stock units. For the 2010-2011 director year, all of the Company’s non-employee directors received 100 percent of their annual fee retainers in restricted stock units.
Stock option awards. Certain employees may be granted options to purchase shares of the Company’s common stock with an exercise price equal to the fair market value of Pioneer common stock on the date of grant.
The fair value of stock option awards is determined using the Black-Sholes option-pricing model. Option awards have a 10 year contract life. The expected life of an option is estimated based on historical and expected exercise behavior. The volatility assumption was estimated based upon expectations of volatility over the life of the option as measured by historical volatility. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the option. The dividend yield was based upon a 7 year average dividend yield. The Company used the following weighted-average assumptions to estimate the fair value of stock options granted during 2010 and 2009 (no options were issued during 2008):
| 2010 | 2009 | |||||||
| Expected option life - years |
7 | 7 | ||||||
| Volatility |
46.8 | % | 43.0 | % | ||||
| Risk-free interest rate |
3.4 | % | 3.3 | % | ||||
| Dividend yield |
0.4 | % | 1.9 | % | ||||
A summary of the Company’s stock option awards activity for the year ended December 31, 2010 is presented below:
| Number of Shares |
Weighted Average Exercise Price |
Weighted Average Remaining Contractual Life |
Aggregate Intrinsic Value |
|||||||||||||
| (in years) | (in thousands) | |||||||||||||||
| Nonstatutory stock options: |
||||||||||||||||
| Outstanding at beginning of year |
596,033 | $ | 18.62 | |||||||||||||
| Options awarded |
116,120 | $ | 47.10 | |||||||||||||
| Options expired and forfeited |
(1,799 | ) | $ | 24.76 | ||||||||||||
| Options exercised |
(202,815 | ) | $ | 23.65 | ||||||||||||
| Outstanding and expected to vest at end of year |
507,539 | $ | 23.11 | 3.75 | $ | 32,337 | ||||||||||
| Exercisable at end of year |
30,398 | $ | 20.36 | 0.50 | $ | 2,020 | ||||||||||
The weighted average grant-date fair value of options awarded during 2010 and 2009 was $23.79 and $6.27, respectively, using the Black-Sholes option-pricing model. The intrinsic value of options exercised during 2010, 2009 and 2008 was $6.9 million, $3.1 million and $11.5 million, respectively, based on the difference between the market price at the exercise date and the option exercise price.
Performance unit awards. During 2010, the Company awarded performance units to certain of the Company’s officers under the LTIP. The number of shares of common stock to be issued is determined by comparing the Company’s total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The performance unit awards vest over a 34-month service period. The grant-date fair
96
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
values per unit of the 2010, 2009, and 2008 performance unit awards are $63.52, $15.29 and $37.01, respectively, which amounts were determined using the Monte Carlo simulation method and are being recognized as compensation expense ratably over the performance period. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. Expected volatilities utilized in the model were estimated using a historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant. The Company used the following assumptions to estimate the fair value of performance unit awards granted during 2010, 2009 and 2008:
| 2010 | 2009 | 2008 | ||||
| Risk-free interest rate |
1.36% | 1.33% | 2.13% | |||
| Range of volatilities |
50.4% - 83.0% | 47.1% - 73.0% | 26.1% - 43.4% |
The following table summarizes the performance unit activity for the year ended December 31, 2010:
| Number of Units (a) |
Weighted Average Grant-Date Fair Value |
|||||||
| Beginning performance unit awards |
347,031 | $ | 25.17 | |||||
| Units granted |
74,482 | $ | 63.52 | |||||
| Units vested (b) |
(157,784 | ) | $ | 37.01 | ||||
| Ending performance unit awards |
263,729 | $ | 28.91 | |||||
| (a) | These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date. |
| (b) | On December 31, 2010, the service period lapsed on these performance unit awards. They earned two shares for each vested award representing 315,568 aggregate shares of common stock issued in 2011. |
The fair value of shares for which restrictions lapsed during 2010 and 2009 was $27.4 million and $4.8 million, respectively, based on the market price on the vesting date. No shares vested during 2008.
Pioneer Southwest Long-Term Incentive Plan
In May 2008, the Board of Directors of the general partner (the “General Partner”) of Pioneer Southwest adopted the Pioneer Southwest LTIP, which provides for the granting of incentive awards in the form of options, unit appreciation rights, phantom units, restricted units, unit awards and other unit-based awards to directors, employees and consultants of the General Partner and its affiliates who perform services for Pioneer Southwest. The Pioneer Southwest LTIP limits the number of units that may be delivered pursuant to awards granted under the plan to 3.0 million common units.
The following table shows the number of awards available under the Pioneer Southwest LTIP at December 31, 2010:
| Approved and authorized awards |
3,000,000 | |||
| Awards issued after May 6, 2008 |
(69,401 | ) | ||
| Awards available for future grant |
2,930,599 | |||
During 2010, the General Partner awarded 8,744 restricted common units to directors of the General Partner under the Pioneer Southwest LTIP, which vest in May 2011. During 2009, the General Partner awarded 12,909 restricted common units to directors of the General Partner under the Pioneer Southwest LTIP, of which 2,038 units vest ratably over three years and 10,871 units vested in May 2010. During 2008, the General Partner awarded 12,630 restricted common units to directors of the General Partner under the Pioneer Southwest LTIP.
97
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
| Restricted Unit Awards | Phantom Unit Awards | |||||||||||||||
| Number of Units |
Weighted Average Grant-Date Fair Value |
Number of Units |
Weighted Average Grant-Date Fair Value |
|||||||||||||
| Outstanding at beginning of year |
17,121 | $ | 18.45 | — | $ | — | ||||||||||
| Units granted |
8,744 | $ | 22.87 | 35,118 | $ | 22.74 | ||||||||||
| Lapse of restrictions |
(13,653 | ) | $ | 18.24 | — | $ | — | |||||||||
| Outstanding at end of year |
12,212 | $ | 21.84 | 35,118 | $ | 22.74 | ||||||||||
The weighted average grant-date fair value of restricted common units awarded during 2010, 2009 and 2008 was $22.87, $18.26 and $19.00, respectively. The fair value of common units for which restrictions lapsed during 2010 and 2009 was $324 thousand and $145 thousand, respectively, based on the market price at the vesting date.
During 2010, the General Partner awarded phantom units to certain members of management of the General Partner under Pioneer Southwest’s LTIP. The phantom units entitle the recipients to a total of 35,118 common units of Pioneer Southwest after a three-year vesting period. No phantom units were issued prior to 2010.
Subsidiary Issuances of Unit-Based Compensation
During 2010, Sendero entered into restricted unit agreements with two key employees, granting 1,000 Series B units in Sendero. The Series B unit awards had a grant date fair value of $5.1 million, vest ratably over a five year service period and do not earn equity rights unless certain defined performance conditions are achieved by Sendero.
Employee Stock Purchase Plan
The Company has an ESPP that allows eligible employees to annually purchase the Company’s common stock at a discounted price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to 15 percent of an employee’s pay (subject to certain ESPP limits) during the eight-month offering period (January 1 to August 31). Participants in the ESPP purchase the Company’s common stock at a price that is 15 percent below the closing sales price of the Company’s common stock on either the first day or the last day of each offering period, whichever closing sales price is lower.
Postretirement Benefit Obligations
At December 31, 2010 and 2009, the Company had $7.4 million and $9.1 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. These obligations are comprised of five plans of which four relate to predecessor entities that the Company acquired in prior years. These plans had no assets as of December 31, 2010 or 2009. Other than the Company’s retirement plan, the participants of these plans are not current employees of the Company.
At December 31, 2010, the accumulated postretirement benefit obligations related to these plans were determined by independent actuaries for four plans representing $4.6 million of unfunded accumulated postretirement benefit obligations and by the Company for one plan representing $2.8 million of unfunded accumulated postretirement benefit obligations. For the years ended December 31, 2010, 2009 and 2008, the undiscounted accumulated post retirement benefit obligations were discounted at four percent, five percent and six percent to value the benefit obligations. Certain of the aforementioned plans provide for medical cost subsidies for plan participants. Annual medical cost escalation trends of nine percent were forecasted for 2011, declining annually to eight percent in 2015 and five percent in 2025 and thereafter, were employed to estimate the accumulated postretirement benefit obligations associated with the medical cost subsidies.
98
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following table reconciles changes in the Company’s unfunded accumulated postretirement benefit obligations during the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Beginning accumulated postretirement benefit obligations |
$ | 9,075 | $ | 9,612 | $ | 10,494 | ||||||
| Net benefit payments |
(1,491 | ) | (1,430 | ) | (1,526 | ) | ||||||
| Service costs |
321 | 228 | 190 | |||||||||
| Net actuarial losses (gains) |
(930 | ) | 8 | (177 | ) | |||||||
| Accretion of interest |
433 | 657 | 631 | |||||||||
| Ending accumulated postretirement benefit obligations |
$ | 7,408 | $ | 9,075 | $ | 9,612 | ||||||
Estimated benefit payments and service/interest costs associated with the plans for the year ending December 31, 2011 are $889 thousand and $558 thousand, respectively.
Future postretirement benefits the Company expects to pay at December 31, 2010 are as follows (in thousands):
| 2011 |
$ | 889 | ||
| 2012 |
$ | 943 | ||
| 2013 |
$ | 1,000 | ||
| 2014 |
$ | 1,058 | ||
| 2015 |
$ | 1,053 | ||
| Thereafter |
$ | 2,465 |
NOTE H. Commitments and Contingencies
Severance agreements. The Company has entered into severance and change in control agreements with its officers and certain key employees. The current annual salaries for the officers and key employees covered under such agreements total $44.2 million.
Indemnifications. The Company has indemnified its directors and certain of its officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.
Legal actions. In addition to the legal actions described below, the Company is 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. The Company will continue to evaluate its litigation on a quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to reflect its assessment of the then current status of litigation.
Colorado Notice of Violation. On May 13, 2008, the Company was served with a Notice of Violation/Cease and Desist Order by the State of Colorado Department of Public Health and Environmental Water Quality Control Division. The Notice alleges violations of stormwater discharge permits in the Company’s Raton Basin and former Lay Creek operations; deficiencies in the Company’s stormwater management plans, failure to implement and maintain best management practices to protect stormwater runoff and failure to conduct inspections of the stormwater management system. On November 12, 2010, the Company entered into an administrative settlement of the enforcement action under the Colorado Water Quality Control Act pursuant to which it will pay cash fines of approximately $27,000 and fund two local environmental projects in the amount of approximately $139,000.
Investigation by the Alaska Oil and Gas Conservation Commission (the “AOGCC”). During the second quarter of 2010, the AOGCC commenced an investigation into allegations by a former Pioneer employee regarding the Company’s Oooguruk facility on the North Slope of Alaska. Among the allegations are claims that the Company did
99
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
not have authorization to inject certain non-hazardous substances into its enhanced oil recovery well, that the Company mishandled disposal of waste products and that the Company’s operating practices are harmful to the project’s oil reservoirs. Upon initially becoming aware of the allegations, the Company informed the AOGCC and other relevant federal, state and local agencies and commenced its own investigation, which confirmed injections of non-hazardous fluids into the Oooguruk enhanced oil recovery well without prior authorizations to do so. The results of the Company’s investigation were reported to the agencies. In December, the AOGCC investigator submitted a report outlining its findings, which (i) found that the Company’s operating practices have not harmed the project’s oil reservoirs and (ii) raised certain regulatory compliance issues, all of which the Company previously reported or has since taken actions to remedy. Although the Company does not know at this time what action the AOGCC will take in response to the report, based on the facts as known to date, the Company believes that compliance with any order or other action of the AOGCC will not materially and negatively affect the Company’s liquidity, financial position or future results of operations.
Obligations following divestitures. In April 2006, the Company provided the purchaser of its Argentine assets certain indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject to defined limitations. The Company does not believe that these obligations, which primarily pertain to matters of litigation, environmental contingencies, royalty obligations and income taxes, are probable of having a material impact on its liquidity, financial position or future results of operations.
The Company has also retained certain liabilities and indemnified buyers for certain matters in connection with other divestitures, including the sale in 2007 of its Canadian assets and the February 2011 sale of the Company’s Tunisian subsidiaries.
Drilling commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future. The Company also enters into agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which the well is drilled or rig services are contracted.
Lease agreements. The Company leases equipment and office facilities under noncancellable operating leases. Lease payments associated with these operating leases for the years ended December 31, 2010, 2009 and 2008 were $29.5 million, $30.5 million and $49.6 million, respectively. Future minimum lease commitments under noncancellable operating leases at December 31, 2010 are as follows (in thousands):
| 2011 |
$ | 16,719 | ||
| 2012 |
$ | 16,015 | ||
| 2013 |
$ | 15,571 | ||
| 2014 |
$ | 14,002 | ||
| 2015 |
$ | 12,602 | ||
| Thereafter |
$ | 52,387 |
Gathering, Processing and Transportation agreements. The Company is party to contractual commitments with midstream service companies and pipeline carriers for the future gathering, processing and transportation of oil, NGL and gas production from certain of the Company’s properties located in the Raton Basin and Eagle Ford Shale area.
The Raton Basin transportation commitments averaged approximately 238 million cubic feet (“MMcf”) of gross gas volumes per day during 2010, including fuel commitments, and will average approximately 361 MMcf per day of gross gas volume during 2011, increasing to approximately 400 MMcf per day during 2012 and declining thereafter to approximately 194 MMcf per day during 2022.
In December 2009, the Company entered into a ten-year firm transportation contract that commences upon completion of a new 675-mile pipeline spanning from Opal, Wyoming to Malin, Oregon. Upon the pipeline’s completion (currently expected during the second or third quarter of 2011) and in accordance with the transportation contract, the Company is committed to transport 75,000 Mcf per day of gas for a minimum transportation fee of $0.95 per Mcf plus fuel, depending on the receipt point and other conditions. The Company has issued and outstanding a $39.0 million letter of credit in accordance with the terms of this agreement. In 2010, the Company entered additional agreements to allow Raton field production to reach the receipt point at Opal, Wyoming. The Company is committed to transport 75,000 to 100,000 Mcf per day of gas plus fuel volumes for an aggregate transportation fee of up to $0.76 per Mcf on transportation intervals from the Raton field to Opal, Wyoming.
100
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The Raton Basin volumetric transportation commitments exceed the Company’s forecasted controlled gas production in the Raton field for certain future periods. The Company may purchase third party gas volumes to satisfy certain volumetric commitments or pay demand fees for commitment shortfalls, should they occur.
During 2010, the Company entered into contractual agreements with third parties to gather, transport, process and fractionate certain portions of the future oil, gas and NGLs produced and recovered from the Company’s Eagle Ford Shale properties. The Company entered into a ten year oil gathering agreement, under which the counterparty is obligated to build a 111-mile oil pipeline that will transport approximately 7,100 Bbls of oil per day in 2012, increasing to approximately 17,400 Bbls per day in 2017, and declining thereafter until the contract term ends in 2022. The Company has firm transportation commitments under this contract after the counterparty builds the pipeline.
The Company entered into two five-year gas transportation agreements, under which it is committed to provide approximately 20,600 Mcf per day of gas throughput from Eagle Ford Shale wells beginning in mid-2011. Transportation commitments under these agreements increase to approximately 88,600 Mcf per day in 2015 before terminating in mid-2016. All but 28,300 Mcf per day of the commitments under these agreements is subject to a counterparty’s obligation to build infrastructure facilities.
The Company also entered into a ten-year contractual agreement with at third party for the transportation and processing of Eagle Ford Shale gas production and the fractionation of recovered NGLs. The firm transportation commitments under this agreement are for approximately 18,000 Mcf per day in 2011, increasing to approximately 170,000 Mcf per day in 2020; processing commitments under the agreement are for approximately 15,000 Mcf per day in 2011, increasing to approximately 139,000 Mcf per day in 2020’; and, fractionation commitments under the agreement are for approximately 1,500 Bbls per day of NGLs in 2011, increasing to approximately 15,000 Bbls per day in 2020.
The Company entered into the HGH Agreement with EFS Midstream to gather, treat and transport certain Eagle Ford Shale oil and gas production. The HGH Agreement has sequential start dates linked to commencement of Eagle Ford Shale production spanning the next 24 months and has a primary term of 20 years and continuing year-to-year thereafter. EFS Midstream is obligated to construct various gathering and field facilities to handle the Eagle Ford Shale area production, and the Company has dedicated the areas’ reserves to the contract. See Notes B and F for additional information about EFS Midstream and the HGH Agreement.
Future minimum gathering, processing and transportation fees under the Company’s oil, NGL and gas gathering, processing and transportation commitments at December 31, 2010 are as follows (in thousands):
| 2011 |
$ | 83,448 | ||
| 2012 |
$ | 130,488 | ||
| 2013 |
$ | 117,640 | ||
| 2014 |
$ | 121,155 | ||
| 2015 |
$ | 130,901 | ||
| Thereafter |
$ | 669,421 |
NOTE I. Derivative Financial Instruments
The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness and forward currency exchange rate agreements to reduce the effect of exchange rate volatility.
101
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Oil prices. All material physical sales contracts governing the Company’s oil production are tied directly or indirectly to NYMEX WTI or Dated Brent oil prices. The following table sets forth the volumes in Bbls outstanding as of December 31, 2010 under the Company’s oil derivative contracts and the weighted average oil prices per Bbl for those contracts:
| First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Outstanding Average |
||||||||||||||||
| Average daily oil production derivatives (a): |
||||||||||||||||||||
| 2011 – Swap contracts |
||||||||||||||||||||
| Volume (Bbl) |
750 | 750 | 750 | 750 | 750 | |||||||||||||||
| Price per Bbl |
$ | 77.25 | $ | 77.25 | $ | 77.25 | $ | 77.25 | $ | 77.25 | ||||||||||
| 2011 – Collar contracts |
||||||||||||||||||||
| Volume (Bbl) |
2,000 | 2,000 | 2,000 | 2,000 | 2,000 | |||||||||||||||
| Price per Bbl: |
||||||||||||||||||||
| Ceiling |
$ | 170.00 | $ | 170.00 | $ | 170.00 | $ | 170.00 | $ | 170.00 | ||||||||||
| Floor |
$ | 115.00 | $ | 115.00 | $ | 115.00 | $ | 115.00 | $ | 115.00 | ||||||||||
| 2011 – Collar Contracts with short puts |
||||||||||||||||||||
| Volume (Bbl) |
32,000 | 32,000 | 32,000 | 32,000 | 32,000 | |||||||||||||||
| Price per Bbl: |
||||||||||||||||||||
| Ceiling |
$ | 99.33 | $ | 99.33 | $ | 99.33 | $ | 99.33 | $ | 99.33 | ||||||||||
| Floor |
$ | 73.75 | $ | 73.75 | $ | 73.75 | $ | 73.75 | $ | 73.75 | ||||||||||
| Short put |
$ | 59.31 | $ | 59.31 | $ | 59.31 | $ | 59.31 | $ | 59.31 | ||||||||||
| 2012 – Swap contracts |
||||||||||||||||||||
| Volume (Bbl) |
3,000 | 3,000 | 3,000 | 3,000 | 3,000 | |||||||||||||||
| Price per Bbl |
$ | 79.32 | $ | 79.32 | $ | 79.32 | $ | 79.32 | $ | 79.32 | ||||||||||
| 2012 – Collar contracts with short puts |
||||||||||||||||||||
| Volume (Bbl) |
37,000 | 37,000 | 37,000 | 37,000 | 37,000 | |||||||||||||||
| Price per Bbl: |
||||||||||||||||||||
| Ceiling |
$ | 118.34 | $ | 118.34 | $ | 118.34 | $ | 118.34 | $ | 118.34 | ||||||||||
| Floor |
$ | 80.41 | $ | 80.41 | $ | 80.41 | $ | 80.41 | $ | 80.41 | ||||||||||
| Short put |
$ | 65.00 | $ | 65.00 | $ | 65.00 | $ | 65.00 | $ | 65.00 | ||||||||||
| 2013 – Swap contracts |
||||||||||||||||||||
| Volume (Bbl) |
3,000 | 3,000 | 3,000 | 3,000 | 3,000 | |||||||||||||||
| Price per Bbl |
$ | 81.02 | $ | 81.02 | $ | 81.02 | $ | 81.02 | $ | 81.02 | ||||||||||
| 2013 – Collar contracts with short puts |
||||||||||||||||||||
| Volume (Bbl) |
21,250 | 21,250 | 21,250 | 21,250 | 21,250 | |||||||||||||||
| Price per Bbl: |
||||||||||||||||||||
| Ceiling |
$ | 117.38 | $ | 117.38 | $ | 117.38 | $ | 117.38 | $ | 117.38 | ||||||||||
| Floor |
$ | 80.18 | $ | 80.18 | $ | 80.18 | $ | 80.18 | $ | 80.18 | ||||||||||
| Short put |
$ | 65.18 | $ | 65.18 | $ | 65.18 | $ | 65.18 | $ | 65.18 | ||||||||||
| 2014 – Collar contracts with short puts |
||||||||||||||||||||
| Volume (Bbl) |
4,000 | 4,000 | 4,000 | 4,000 | 4,000 | |||||||||||||||
| Price per Bbl: |
||||||||||||||||||||
| Ceiling |
$ | 120.50 | $ | 120.50 | $ | 120.50 | $ | 120.50 | $ | 120.50 | ||||||||||
| Floor |
$ | 85.00 | $ | 85.00 | $ | 85.00 | $ | 85.00 | $ | 85.00 | ||||||||||
| Short put |
$ | 70.00 | $ | 70.00 | $ | 70.00 | $ | 70.00 | $ | 70.00 | ||||||||||
| (a) | Subsequent to December 31, 2010, the Company entered into additional collar contracts with short puts for 8,000 Bbls per day of the Company’s 2014 production with a ceiling price of $131.99 per Bbl, a floor price of $89.38 per Bbl and a short put price of $74.38 per Bbl. |
102
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Natural gas liquids prices. All material physical sales contracts governing the Company’s NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities’ NGL product component prices. The following table sets forth the volumes in Bbls outstanding as of December 31, 2010 under the Company’s NGL derivative contracts and the weighted average NGL prices per Bbl for those contracts:
| First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Outstanding Average |
||||||||||||||||
| Average daily NGL production derivatives: |
||||||||||||||||||||
| 2011 – Swap contracts |
||||||||||||||||||||
| Volume (Bbl) |
1,150 | 1,150 | 1,150 | 1,150 | 1,150 | |||||||||||||||
| Price per Bbl |
$ | 51.26 | $ | 51.38 | $ | 51.50 | $ | 51.50 | $ | 51.41 | ||||||||||
| 2011 – Collar contracts |
||||||||||||||||||||
| Volume (Bbl) |
2,650 | 2,650 | 2,650 | 2,650 | 2,650 | |||||||||||||||
| Price per Bbl: |
||||||||||||||||||||
| Ceiling |
$ | 64.23 | $ | 64.23 | $ | 64.23 | $ | 64.23 | $ | 64.23 | ||||||||||
| Floor |
$ | 53.29 | $ | 53.29 | $ | 53.29 | $ | 53.29 | $ | 53.29 | ||||||||||
| 2012 – Swap contracts |
||||||||||||||||||||
| Volume (Bbl) |
750 | 750 | 750 | 750 | 750 | |||||||||||||||
| Price per Bbl |
$ | 35.03 | $ | 35.03 | $ | 35.03 | $ | 35.03 | $ | 35.03 | ||||||||||
Gas prices. All material physical sales contracts governing the Company’s gas production are tied directly or indirectly to regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and reduce basis risk between NYMEX Henry Hub prices and actual index prices upon which the gas is sold. The following table sets forth the volumes in MMBtus outstanding as of December 31, 2010 under the Company’s gas derivative contracts and the weighted average gas prices per MMBtu for those contracts:
| First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Outstanding Average |
||||||||||||||||
| Average daily gas production derivatives: |
||||||||||||||||||||
| 2011 – Swap contracts |
||||||||||||||||||||
| Volume (MMBtu) |
117,500 | 117,500 | 117,500 | 117,500 | 117,500 | |||||||||||||||
| Price per MMBtu |
$ | 6.13 | $ | 6.13 | $ | 6.13 | $ | 6.13 | $ | 6.13 | ||||||||||
| 2011 – Collar contracts with short puts |
||||||||||||||||||||
| Volume (MMBtu) |
200,000 | 200,000 | 200,000 | 200,000 | 200,000 | |||||||||||||||
| Price per MMBtu: |
||||||||||||||||||||
| Ceiling |
$ | 8.55 | $ | 8.55 | $ | 8.55 | $ | 8.55 | $ | 8.55 | ||||||||||
| Floor |
$ | 6.32 | $ | 6.32 | $ | 6.32 | $ | 6.32 | $ | 6.32 | ||||||||||
| Short put |
$ | 4.88 | $ | 4.88 | $ | 4.88 | $ | 4.88 | $ | 4.88 | ||||||||||
| 2011 – Basis swap contracts |
||||||||||||||||||||
| Volume (MMBtu) |
153,500 | 153,500 | 143,500 | 143,500 | 148,500 | |||||||||||||||
| Price per MMBtu |
$ | (0.53 | ) | $ | (0.53 | ) | $ | (0.56 | ) | $ | (0.56 | ) | $ | (0.54 | ) | |||||
| 2012 – Swap contracts |
||||||||||||||||||||
| Volume (MMBtu) |
105,000 | 105,000 | 105,000 | 105,000 | 105,000 | |||||||||||||||
| Price per MMBtu |
$ | 5.82 | $ | 5.82 | $ | 5.82 | $ | 5.82 | $ | 5.82 | ||||||||||
| 2012 – Collar contracts |
||||||||||||||||||||
| Volume (MMBtu) |
65,000 | 65,000 | 65,000 | 65,000 | 65,000 | |||||||||||||||
| Price per MMBtu: |
||||||||||||||||||||
| Ceiling |
$ | 6.60 | $ | 6.60 | $ | 6.60 | $ | 6.60 | $ | 6.60 | ||||||||||
| Floor |
$ | 5.00 | $ | 5.00 | $ | 5.00 | $ | 5.00 | $ | 5.00 | ||||||||||
| 2012 – Collar contracts with short puts |
||||||||||||||||||||
| Volume (MMBtu) |
190,000 | 190,000 | 190,000 | 190,000 | 190,000 | |||||||||||||||
| Price per MMBtu: |
||||||||||||||||||||
| Ceiling |
$ | 7.96 | $ | 7.96 | $ | 7.96 | $ | 7.96 | $ | 7.96 | ||||||||||
| Floor |
$ | 6.12 | $ | 6.12 | $ | 6.12 | $ | 6.12 | $ | 6.12 | ||||||||||
| Short put |
$ | 4.55 | $ | 4.55 | $ | 4.55 | $ | 4.55 | $ | 4.55 | ||||||||||
103
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
| 2012 – Basis swap contracts |
||||||||||||||||||||
| Volume (MMBtu) |
116,000 | 116,000 | 116,000 | 116,000 | 116,000 | |||||||||||||||
| Price per MMBtu |
$ | (0.37 | ) | $ | (0.37 | ) | $ | (0.37 | ) | $ | (0.37 | ) | $ | (0.37 | ) | |||||
| 2013 – Swap contracts |
||||||||||||||||||||
| Volume (MMBtu) |
67,500 | 67,500 | 67,500 | 67,500 | 67,500 | |||||||||||||||
| Price per MMBtu |
$ | 6.11 | $ | 6.11 | $ | 6.11 | $ | 6.11 | $ | 6.11 | ||||||||||
| 2013 – Collar contracts |
||||||||||||||||||||
| Volume (MMBtu) |
100,000 | 100,000 | 100,000 | 100,000 | 100,000 | |||||||||||||||
| Price per MMBtu: |
||||||||||||||||||||
| Ceiling |
$ | 6.50 | $ | 6.50 | $ | 6.50 | $ | 6.50 | $ | 6.50 | ||||||||||
| Floor |
$ | 5.00 | $ | 5.00 | $ | 5.00 | $ | 5.00 | $ | 5.00 | ||||||||||
| 2013 – Collar contracts with short puts |
||||||||||||||||||||
| Volume (MMBtu) |
45,000 | 45,000 | 45,000 | 45,000 | 45,000 | |||||||||||||||
| Price per MMBtu: |
||||||||||||||||||||
| Ceiling |
$ | 7.49 | $ | 7.49 | $ | 7.49 | $ | 7.49 | $ | 7.49 | ||||||||||
| Floor |
$ | 6.00 | $ | 6.00 | $ | 6.00 | $ | 6.00 | $ | 6.00 | ||||||||||
| Short put |
$ | 4.50 | $ | 4.50 | $ | 4.50 | $ | 4.50 | $ | 4.50 | ||||||||||
| 2013 – Basis swap contracts |
||||||||||||||||||||
| Volume (MMBtu) |
32,500 | 32,500 | 32,500 | 32,500 | 32,500 | |||||||||||||||
| Price per MMBtu |
$ | (0.34 | ) | $ | (0.34 | ) | $ | (0.34 | ) | $ | (0.34 | ) | $ | (0.34 | ) | |||||
| 2014 – Swap contracts |
||||||||||||||||||||
| Volume (MMBtu) |
50,000 | 50,000 | 50,000 | 50,000 | 50,000 | |||||||||||||||
| Price per MMBtu |
$ | 6.05 | $ | 6.05 | $ | 6.05 | $ | 6.05 | $ | 6.05 | ||||||||||
| 2014 – Collar contracts |
||||||||||||||||||||
| Volume (MMBtu) |
40,000 | 40,000 | 40,000 | 40,000 | 40,000 | |||||||||||||||
| Price per MMBtu: |
||||||||||||||||||||
| Ceiling |
$ | 6.73 | $ | 6.73 | $ | 6.73 | $ | 6.73 | $ | 6.73 | ||||||||||
| Floor |
$ | 5.00 | $ | 5.00 | $ | 5.00 | $ | 5.00 | $ | 5.00 | ||||||||||
| 2014 – Collar contracts with short puts |
||||||||||||||||||||
| Volume (MMBtu) |
50,000 | 50,000 | 50,000 | 50,000 | 50,000 | |||||||||||||||
| Price per MMBtu: |
||||||||||||||||||||
| Ceiling |
$ | 8.08 | $ | 8.08 | $ | 8.08 | $ | 8.08 | $ | 8.08 | ||||||||||
| Floor |
$ | 6.00 | $ | 6.00 | $ | 6.00 | $ | 6.00 | $ | 6.00 | ||||||||||
| Short put |
$ | 4.50 | $ | 4.50 | $ | 4.50 | $ | 4.50 | $ | 4.50 | ||||||||||
| 2014 – Basis swap contracts |
||||||||||||||||||||
| Volume (MMBtu) |
10,000 | 10,000 | 10,000 | 10,000 | 10,000 | |||||||||||||||
| Price per MMBtu |
$ | (0.16 | ) | $ | (0.16 | ) | $ | (0.16 | ) | $ | (0.16 | ) | $ | (0.16 | ) | |||||
Interest rates. The following table sets forth as of December 31, 2010 the notional amount of the Company’s debt subject to outstanding variable-for-fixed and fixed-for-variable interest rate swap contracts, the weighted average fixed annual interest rate and the termination dates for those contracts:
| Type |
Notional Amount |
Weighted Average Fixed Interest Rate |
Termination Date |
|||||||||
| (in thousands) | ||||||||||||
| Variable-for-fixed |
$ | 189,000 | 3.0 percent | February 2011 | ||||||||
| Fixed-for-variable |
$ | 400,000 | 2.87 percent | July 2016 | ||||||||
| Fixed-for-variable |
$ | 70,000 | 3.23 percent | March 2017 | ||||||||
Tabular disclosure of derivative fair value. All of the Company’s derivatives are accounted for as non-hedge derivatives as of December 31, 2010 and 2009, except for $17.9 million of net obligations on terminated hedges as of December 31, 2009. The following tables provide disclosure of the Company’s derivative instruments:
104
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
| Fair Value of Derivative Instruments as of December 31, 2010 |
||||||||||||||||
| Asset Derivatives (a) | Liability Derivatives (a) | |||||||||||||||
| Type |
Balance Sheet Location |
Fair Value | Balance Sheet Location |
Fair Value |
||||||||||||
| (in thousands) | (in thousands) | |||||||||||||||
| Derivatives not designated as hedging instruments |
||||||||||||||||
| Commodity price derivatives |
Derivatives - current |
$ | 167,406 | Derivatives - current |
$ | 87,741 | ||||||||||
| Interest rate derivatives |
Derivatives - current |
11,903 | Derivatives - current |
886 | ||||||||||||
| Commodity price derivatives |
Derivatives - noncurrent |
152,731 | Derivatives - noncurrent |
64,829 | ||||||||||||
| Interest rate derivatives |
Derivatives - noncurrent |
15,762 | Derivatives - noncurrent |
9,227 | ||||||||||||
| Total derivatives not designated as hedging instruments |
347,802 | 162,683 | ||||||||||||||
| Total derivatives |
$ | 347,802 | $ | 162,683 | ||||||||||||
| Fair Value of Derivative Instruments as of December 31, 2009 |
||||||||||||||||
| Asset Derivatives (a) | Liability Derivatives (a) | |||||||||||||||
| Type |
Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value |
||||||||||||
| (in thousands) | (in thousands) | |||||||||||||||
| Derivatives not designated as hedging instruments |
||||||||||||||||
| Commodity price derivatives |
Derivatives - current |
$ | 66,442 | Derivatives - current |
$ | 120,112 | ||||||||||
| Interest rate derivatives |
Derivatives - current |
9,450 | Derivatives - current |
5,169 | ||||||||||||
| Commodity price derivatives |
Derivatives - noncurrent |
48,341 | Derivatives - noncurrent |
116,233 | ||||||||||||
| Interest rate derivatives |
Derivatives - noncurrent | 2,192 | Derivatives - noncurrent | 24,314 | ||||||||||||
| Total derivatives not designated as hedging instruments |
126,425 | 265,828 | ||||||||||||||
| Derivatives designated as hedging instruments |
||||||||||||||||
| Commodity price derivatives (b) |
Derivatives - current |
— | Derivatives - current |
17,913 | ||||||||||||
| Total derivatives designated as hedging instruments |
— | 17,913 | ||||||||||||||
| Total derivatives |
$ | 126,425 | $ | 283,741 | ||||||||||||
| (a) | Derivative assets and liabilities shown in the tables above are presented as gross assets and liabilities, without regard to master netting arrangements which are considered in the presentations of derivative assets and liabilities in the accompanying consolidated balance sheets. |
| (b) | Represent derivative obligations under terminated hedge arrangements. |
| Amount of Gain/(Loss) Recognized in AOCI on Effective Portion |
||||||||||||||
| Year Ended December 31, | ||||||||||||||
| Derivatives in Cash Flow Hedging Relationships |
2010 | 2009 | 2008 | |||||||||||
| (in thousands) | ||||||||||||||
| Interest rate derivatives |
$ | — | $ | (433 | ) | $ | (10,405 | ) | ||||||
| Commodity price derivatives |
— | 13,407 | 228,607 | |||||||||||
| Total |
$ | — | $ | 12,974 | $ | 218,202 | ||||||||
| Derivatives in Cash Flow Hedging Relationships |
Location of Gain/(Loss) | Amount of Gain/(Loss) Reclassified from AOCI into Earnings |
||||||||||||
| Reclassified from AOCI | Year Ended December 31, | |||||||||||||
| into Earnings |
2010 | 2009 | 2008 | |||||||||||
| (in thousands) | ||||||||||||||
| Interest rate derivatives |
Interest expense |
$ | (1,698 | ) | $ | (6,835 | ) | $ | (1,168 | ) | ||||
| Interest rate derivatives |
Derivative gains (losses), net |
(2,465 | ) | — | — | |||||||||
| Commodity price derivatives |
Oil and gas revenue |
89,040 | 121,066 | (355,563 | ) | |||||||||
| Total |
$ | 84,877 | $ | 114,231 | $ | (356,731 | ) | |||||||
105
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
| Location of Loss | Amount of Loss Recognized in Earnings
on Ineffective Portion |
|||||||||||||
| Recognized in Earnings on | Year Ended December 31, | |||||||||||||
| Derivatives in Cash Flow Hedging Relationships |
Ineffective Portion |
2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||||
| Commodity price derivatives |
Derivative gains (losses), net |
$ | — | $ | — | $ | (499 | ) | ||||||
| Derivatives Not Designated as Hedging Instruments |
Location of Gain (Loss) | Amount of Gain (Loss) Recognized in Earnings on Derivatives |
||||||||||||
| Recognized in Earnings on | Year Ended December 31, | |||||||||||||
| Derivatives |
2010 | 2009 | 2008 | |||||||||||
| (in thousands) | ||||||||||||||
| Interest rate derivatives |
Derivative gains (losses), net |
$ | 36,597 | $ | (15,423 | ) | $ | — | ||||||
| Commodity price derivatives |
Derivative gains (losses), net |
414,302 | (180,134 | ) | (9,649 | ) | ||||||||
| Total |
$ | 450,899 | $ | (195,557 | ) | $ | (9,649 | ) | ||||||
AOCI - Hedging. The effective portions of deferred cash flow hedge gains and losses, net of associated taxes are reflected in AOCI-Hedging as of December 31, 2010 and 2009, and are being transferred to oil and gas revenue (for deferred commodity hedge gains and losses) and to interest expense (for deferred interest rate hedge gains and losses) in the same periods in which the hedged transactions are recorded in earnings. In accordance with the change to the MTM method of accounting on February 1, 2009, the Company recognizes changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which the changes occur.
As of December 31, 2010 and 2009, AOCI - Hedging represented net deferred gains of $7.4 million and $51.0 million, respectively. The AOCI - Hedging balance as of December 31, 2010 was comprised of $29.8 million of net deferred gains on the effective portions of discontinued commodity hedges, $2.0 million of net deferred losses on the effective portions of discontinued interest rate hedges and $6.7 million of associated net deferred tax provisions, reduced by $13.7 million of AOCI – Hedging net deferred gains attributable to and classified as noncontrolling interests in consolidated subsidiaries.
During the 12 months ending December 31, 2011, the Company expects to reclassify $32.9 million of AOCI – Hedging net deferred gains to oil revenues (including $13.9 million related to noncontrolling interests) and $282 thousand of AOCI – Hedging net deferred losses to interest expense. The Company also expects to reclassify $11.7 million of net deferred income tax provisions associated with hedge derivatives during the 12 months ending December 31, 2011 from AOCI – Hedging to income tax expense. During 2012, the Company expects to reclassify deferred losses on discontinued commodity hedges of $3.2 million to oil revenues. The $2.0 million of net deferred hedge losses on the effective portion of interest rate hedges will be transferred from AOCI – Hedging to interest expense ratably through April 2018.
NOTE J. Major Customers and Derivative Counterparties
Sales to major customers. The Company’s share of oil and gas production is sold to various purchasers who must be prequalified under the Company’s credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts. The Company is of the opinion that the loss of any one purchaser would not have an adverse effect on the ability of the Company to sell its oil and gas production.
106
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following purchasers individually accounted for ten percent or more of the Company’s consolidated oil, NGL and gas revenues, including the revenues from discontinued operations, in at least one of the years in the three years ended December 31, 2010. The table provides the percentages of the Company’s consolidated oil, NGL and gas revenues represented by the purchasers during the periods presented:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Plains Marketing LP |
12 | % | 10 | % | 13 | % | ||||||
| Enterprise Products Partners L.P. |
10 | % | 6 | % | 10 | % | ||||||
Derivative counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures. The following table provides the Company’s derivative assets and liabilities by counterparty as of December 31, 2010:
| Assets | Liabilities | |||||||
| (in thousands) | ||||||||
| JP Morgan Chase |
$ | 72,038 | $ | 6,199 | ||||
| Citibank, N.A. |
61,986 | 4,774 | ||||||
| BNP Paribas |
43,844 | 4,167 | ||||||
| Barclays Capital |
39,568 | 8,995 | ||||||
| Calyon Corporate and Investment Bank |
34,961 | 3,202 | ||||||
| Morgan Stanley |
26,316 | — | ||||||
| Deutsche Bank |
13,826 | 14,244 | ||||||
| Societe Generale |
9,941 | 43,751 | ||||||
| Toronto Dominion |
6,956 | 1,069 | ||||||
| Credit Suisse |
5,095 | 4,112 | ||||||
| Wells Fargo Bank, N.A. |
3,764 | 34,063 | ||||||
| J. Aron & Company |
2,396 | 1,837 | ||||||
| BMO Financial Group |
1,999 | 10,689 | ||||||
| UBS |
— | 469 | ||||||
| Total |
$ | 322,690 | $ | 137,571 | ||||
NOTE K. Asset Retirement Obligations
The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. The following table summarizes the Company’s asset retirement obligation activity during the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Beginning asset retirement obligations |
$ | 166,434 | $ | 172,433 | $ | 208,184 | ||||||
| Liabilities assumed in acquisitions |
6 | — | 2,237 | |||||||||
| New wells placed on production |
5,218 | 625 | 8,459 | |||||||||
| Changes in estimates (a) |
24,075 | 40,153 | 15,178 | |||||||||
| Liabilities reclassified to discontinued operations held for sale |
(5,779 | ) | — | — | ||||||||
| Disposition of wells |
(30,693 | ) | (13,334 | ) | — | |||||||
| Liabilities settled |
(17,838 | ) | (45,010 | ) | (70,325 | ) | ||||||
| Accretion of discount on continuing operations |
10,433 | 10,599 | 7,717 | |||||||||
| Accretion of discount on discontinued operations |
435 | 968 | 983 | |||||||||
| Ending asset retirement obligations |
$ | 152,291 | $ | 166,434 | $ | 172,433 | ||||||
| (a) | The change in the 2010 estimate is primarily due to increases in abandonment cost estimates based on recent actual costs incurred and a decline in credit-adjusted risk-free discount rates used to value increases in asset retirement obligations. These increases were partially offset by higher commodity prices used to calculate proved reserves at December 31, 2010, which had the effect of lengthening the economic life of certain wells and decreasing what would otherwise have been the present value of future retirement obligations. The change in the 2009 estimate is primarily due to (i) lower gas prices used to calculate proved reserves at December 31, 2009, which had the effect of shortening the economic life of wells and increasing the present value of future retirement obligations primarily in the Raton Basin, Hugoton and West Panhandle gas fields and (ii) a $19.9 million increase in East Cameron facilities reclamation and abandonment estimates. The change in the 2008 estimate is primarily due to lower year-end prices for oil, NGL and gas being used to calculate proved reserves at December 31, 2008, which had the effect of shortening the economic life of many wells and increasing the present value of future retirement obligations. |
107
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of December 31, 2010 and December 31, 2009, the current portions of the Company’s asset retirement obligations were $19.9 million and $13.9 million, respectively.
NOTE L. Interest and Other Income
The following table provides the components of the Company’s interest and other income during the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Alaskan Petroleum Production Tax credits and refunds (a) |
$ | 47,652 | $ | 94,989 | $ | 18,636 | ||||||
| Interest income |
4,192 | 1,943 | 3,256 | |||||||||
| Other income |
2,972 | 2,500 | 1,440 | |||||||||
| Insurance claim recovery |
1,665 | — | — | |||||||||
| Retirement obligation revaluation |
1,230 | — | — | |||||||||
| Deferred compensation plan income |
1,228 | 1,034 | 2,007 | |||||||||
| Carbon dioxide revenue |
1,818 | — | — | |||||||||
| Credit card rebates |
975 | 864 | 1,178 | |||||||||
| Foreign currency remeasurement and exchange gains (b) |
175 | 339 | 6,936 | |||||||||
| Gain on early extinguishment of debt |
— | — | 20,515 | |||||||||
| Legal settlements |
— | — | 2,495 | |||||||||
| Total interest and other income |
$ | 61,907 | $ | 101,669 | $ | 56,463 | ||||||
| (a) | The Company earns Alaskan Petroleum Production Tax (“PPT”) credits on qualifying capital expenditures. The Company recognizes income from PPT credits when they are realized through cash refunds from the State of Alaska. During 2010, the Company recorded interest and other income of $7.7 million attributable to PPT overpayment refunds. |
| (b) | The Company’s operations in South Africa periodically recognize monetary assets and liabilities in currencies other than its functional currency. Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses. |
NOTE M. Asset Divestitures
During the years ended December 31, 2010, 2009 and 2008, the Company completed asset divestitures for net proceeds of $313.8 million, $51.6 million and $292.9 million, respectively. Associated therewith, the Company recorded gains on disposition of assets in continuing operations of $19.1 million, during the year ended December 31, 2010, and losses on disposition of assets in continuing operations of $774 thousand and $381 thousand during the years ended December 31, 2009 and 2008, respectively. The Company recorded gains from the disposition of discontinued operations of $17.5 million during 2009 and losses from the disposition of discontinued operations of $392 thousand during 2008. The following describes the significant divestitures:
108
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Eagle Ford Shale. In June 2010, the Company entered into an Eagle Ford Shale joint venture and associated therewith the Company sold 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of cash proceeds, including normal closing adjustments, resulting in a pretax gain of $6.0 million. Under the terms of the transaction, the purchaser is also paying 75 percent (up to $886.8 million) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets.
Uinta/Piceance. During 2010, the Company sold certain proved and unproved oil and gas properties in the Uinta/Piceance area for net proceeds of $11.8 million and the assumption of certain asset retirement obligations, resulting in a pretax gain of $17.3 million.
Other Assets. During 2010, the Company also sold unproved leaseholds, inventory and other property and equipment and recorded a pretax net loss of $4.2 million.
Mississippi and Gulf of Mexico Shelf. During June and August 2009, the Company sold its oil and gas properties in Mississippi and substantially all of its shelf properties in the Gulf of Mexico, respectively. In accordance with GAAP, the Company classified the results of operations of the Mississippi and shelf properties in the Gulf of Mexico as discontinued in its accompanying consolidated statements of operations for 2009.
Tunisian Cherouq Concession. During 2007, Enterprise Tunisiene d’Activities Petrolieres (“ETAP”) exercised its right to participate with the Company as a 50 percent owner in the Company-operated Cherouq Concession. Associated therewith, ETAP became obligated to compensate the Company for $74.5 million of past Cherouq Concession costs, subject to ETAP’s audit. During 2010 and 2009, ETAP paid the Company $23.7 million and $27.2 million, respectively, of the Cherouq Concession past costs. This cash receipt is classified as proceeds from disposition of assets in the accompanying consolidated statement of cash flows for the years ended December 31, 2010 and 2009.
Derivative asset divestitures. During 2008, the Company terminated derivative assets prior to their contractual maturity dates. The accompanying consolidated statement of cash flows for the year ended December 31, 2008 includes $155.0 million of proceeds from disposition of assets attributable to these derivative terminations. See Note I for additional information regarding the Company’s derivative activities.
NOTE N. Other Expense
The following table provides the components of the Company’s other expense during the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Excess and terminated rig related costs (a) |
$ | 37,516 | $ | 54,223 | $ | 54,539 | ||||||
| Well servicing operations (b) |
13,065 | 12,437 | 3,289 | |||||||||
| Inventory impairment (c) |
10,729 | 2,275 | — | |||||||||
| Other |
6,061 | 5,130 | 1,715 | |||||||||
| Contingency and environmental accrual adjustments |
5,581 | 7,796 | 12,449 | |||||||||
| Severance and ad valorem tax audit adjustments |
2,931 | — | 5,730 | |||||||||
| Foreign currency remeasurement and exchange losses (d) |
2,283 | 4,970 | 27 | |||||||||
| Cancelled wells |
1,591 | 2,047 | 3,213 | |||||||||
| Transportation commitment charge (e) |
1,589 | 6,839 | — | |||||||||
| Equity interest in losses of unconsolidated affiliate |
819 | — | — | |||||||||
| Bad debt expense (f) |
(442 | ) | 4,356 | 30,119 | ||||||||
| Rig impairment |
— | — | 3,382 | |||||||||
| Total other expense |
$ | 81,723 | $ | 100,073 | $ | 114,463 | ||||||
| (a) | Represents above market drilling rig costs, idle rig costs and costs incurred to terminate contractual drilling rig commitments prior to their contractual maturities. |
| (b) | Represents idle well servicing costs. |
| (c) | Represents impairment charges to reduce the carrying value of excess lease and well equipment and supplies inventories to their estimated net realizable values. |
109
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
| (d) | The Company’s operations in Africa periodically recognize monetary assets and liabilities in currencies other than their functional currencies. Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses. |
| (e) | Primarily represents firm transportation contract deficiency payment obligations. |
| (f) | The change in 2008 includes a $19.6 million bad debt allowance attributable to $29.6 million of SemGroup, L.P. receivables. The Company recovered the remaining $10.0 million of SemGroup, L.P. receivables carrying value during 2009. |
NOTE O. Income Taxes
The Company and its eligible subsidiaries file a consolidated United States federal income tax return. Certain subsidiaries are not eligible to be included in the consolidated United States federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject to examination by United States federal, state, local and foreign taxing authorities. The Company made current and estimated tax payments of $36.6 million (net of tax refunds) during 2010, received tax refunds (net of tax payments) during 2009 of $42.6 million and made current and estimated tax payments (net of tax refunds) of $70.3 million during 2008. These payments and net refunds include tax payments related to Tunisian operations of $17.8 million during 2010, $10.6 million during 2009 and $69.8 million during 2008. During 2009, the Company received $61.6 million of refunds as a result of carrying back 2007 and 2008 net operating losses. In November 2009, President Obama signed into law the Worker, Homeownership, and Business Assistance Act of 2009, which expanded the carryback period from two years to five years and suspended certain loss utilization limitations. Pursuant to this new legislation, the Company filed an amended carryback claim and received an additional $19.9 million refund during 2010.
The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and assesses the likelihood that the Company’s net operating loss carryforwards (“NOLs”) and other deferred tax attributes in the United States, state, local and foreign tax jurisdictions will be utilized prior to their expiration. As of December 31, 2010 and 2009, the Company’s valuation allowances were $33.1 million and $44.2 million, respectively. These allowances include $26.5 million for 2010 (classified as discontinued operations held for sale) and $40.5 million for 2009 related to Tunisian operations.
Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2010, the Company had no unrecognized tax benefits. The Company’s policy is to account for interest charges with respect to income taxes as interest expense and any penalties, with respect to income taxes, as other expense in the consolidated statements of operations. The Company files income tax returns in the U.S. federal jurisdiction, and various state and foreign jurisdictions. With few exceptions, the Company believes that it is no longer subject to examinations by tax authorities for years before 2005. The Internal Revenue Service is concluding an examination of the 2007 and 2008 tax years. As of December 31, 2010, there are no proposed adjustments or uncertain positions in any jurisdiction that would have a significant effect on the Company’s future results of operations or financial position. The Company’s earliest open years in its key jurisdictions are as follows:
| United States |
2006 | |||
| Various U.S. states |
2005 | |||
| Tunisia |
2005 | |||
| South Africa |
2005 |
110
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The Company’s income tax (provision) benefit and amounts separately allocated were attributable to the following items for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Income from continuing operations |
$ | (272,317 | ) | $ | 88,246 | $ | (113,916 | ) | ||||
| Income from discontinued operations |
2,960 | (90,578 | ) | (84,985 | ) | |||||||
| Changes in goodwill – tax benefits related to stock-based compensation |
453 | 124 | 307 | |||||||||
| Changes in stockholders’ equity: |
||||||||||||
| Net deferred hedge gains (losses) |
23,648 | 50,059 | (213,151 | ) | ||||||||
| Tax benefits related to stock-based compensation |
(153 | ) | 1 | 367 | ||||||||
The Company’s income tax (provision) benefit attributable to income from continuing operations consisted of the following for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Current: |
||||||||||||
| U.S. federal |
$ | — | $ | 21,714 | $ | 19,954 | ||||||
| U.S. state |
(9,863 | ) | (10,010 | ) | (665 | ) | ||||||
| Foreign |
(14,308 | ) | 729 | (1,990 | ) | |||||||
| (24,171 | ) | 12,433 | 17,299 | |||||||||
| Deferred: |
||||||||||||
| U.S. federal |
(263,554 | ) | 64,046 | (118,909 | ) | |||||||
| U.S. state |
3,300 | 8,072 | (423 | ) | ||||||||
| Foreign |
12,108 | 3,695 | (11,883 | ) | ||||||||
| (248,146 | ) | 75,813 | (131,215 | ) | ||||||||
| Income tax (provision) benefit |
$ | (272,317 | ) | $ | 88,246 | $ | (113,916 | ) | ||||
Income (loss) from continuing operations before income taxes less net income attributable to the noncontrolling interests consists of the following for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| U.S. federal |
$ | 741,817 | $ | (234,175 | ) | $ | 227,442 | |||||
| Foreign |
5,879 | (23,093 | ) | 51,720 | ||||||||
| $ | 747,696 | $ | (257,268 | ) | $ | 279,162 | ||||||
111
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Reconciliations of the United States federal statutory tax rate to the Company’s effective tax rate for income from continuing operations are as follows for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, |
||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in percentages) | ||||||||||||
| U.S. federal statutory tax rate |
35.0 | 35.0 | 35.0 | |||||||||
| State income taxes (net of federal benefit) |
0.5 | (0.4) | 0.4 | |||||||||
| U.S. tax on foreign income inclusions and distributions |
0.1 | 1.8 | 5.3 | |||||||||
| Other |
0.7 | (1.9) | (0.6) | |||||||||
| Consolidated effective tax rate |
36.3 | 34.5 | 40.1 | |||||||||
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows as of December 31, 2010 and 2009:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (in thousands) | ||||||||
| Deferred tax assets: |
||||||||
| Net operating loss carryforwards |
$ | — | $ | 136,676 | ||||
| Foreign tax credit carryforward |
174,054 | — | ||||||
| Asset retirement obligations |
50,886 | 55,553 | ||||||
| Net deferred hedge losses |
— | 50,870 | ||||||
| Other |
78,014 | 45,520 | ||||||
| Total deferred tax assets |
302,954 | 288,619 | ||||||
| Valuation allowances |
(6,632 | ) | (44,210 | ) | ||||
| Net deferred tax assets |
296,322 | 244,409 | ||||||
| Deferred tax liabilities: |
||||||||
| Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes |
(1,695,336 | ) | (1,525,359 | ) | ||||
| State taxes and other |
(144,558 | ) | (162,833 | ) | ||||
| Net deferred hedge gains |
(52,232 | ) | — | |||||
| Total deferred tax liabilities |
(1,892,126 | ) | (1,688,192 | ) | ||||
| Net deferred tax liability |
$ | (1,595,804 | ) | $ | (1,443,783 | ) | ||
During 2010, the Company utilized all available NOLs in the United States and South Africa. At December 31, 2010, the Company has $174.1 million of foreign tax credit carryforwards, which are available to offset future U.S. regular taxable income, if any. These carryforwards expire in 2015; however, as a result of the sale of the Company’s Tunisian subsidiaries during February 2011, the Company expects to realize substantially all of these carryforwards in 2011. Pursuant to GAAP, the Company’s $174.1 million deferred tax asset related to the foreign tax credit carryforwards is net of $12.2 million of unrealized excess tax benefits from stock based compensation.
112
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The Company’s income tax (provision) benefit attributable to income from discontinued operations consisted of the following for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Current: |
||||||||||||
| U.S. federal |
$ | — | $ | — | $ | — | ||||||
| U.S. state |
(538 | ) | (1,300 | ) | — | |||||||
| Foreign |
(10,641 | ) | (20,037 | ) | (66,290 | ) | ||||||
| (11,179 | ) | (21,337 | ) | (66,290 | ) | |||||||
| Deferred: |
||||||||||||
| U.S. federal |
44,070 | (48,581 | ) | 2,489 | ||||||||
| U.S. state |
3 | — | — | |||||||||
| Foreign |
(29,934 | ) | (20,660 | ) | (21,184 | ) | ||||||
| 14,139 | (69,241 | ) | (18,695 | ) | ||||||||
| Income tax (provision) benefit |
$ | 2,960 | $ | (90,578 | ) | $ | (84,985 | ) | ||||
NOTE P. Net Income (Loss) Per Share Attributable To Common Stockholders
In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. The computation of diluted net income (loss) per share attributable to common stockholders reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would not be dilutive to net loss per share and conversion into common stock is assumed not to occur. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. For each of the three years in the period ended December 31, 2010, the two-class method of calculating the Company’s diluted net income (loss) per share was more dilutive than the treasury stock method.
The Company’s basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company’s diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding. The following table is a reconciliation of the Company’s net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and to diluted net income (loss) attributable to common stockholders for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Net income (loss) attributable to common stockholders |
$ | 605,208 | $ | (52,106 | ) | $ | 210,020 | |||||
| Participating basic distributed earnings (a) |
(13,896 | ) | (196 | ) | (2,745 | ) | ||||||
| Basic net income (loss) attributable to common stockholders |
591,312 | (52,302 | ) | 207,275 | ||||||||
| Diluted adjustments to share- and unit-based earnings (a) |
180 | — | 9 | |||||||||
| Diluted net income (loss) attributable to common stockholders |
$ | 591,492 | $ | (52,302 | ) | $ | 207,284 | |||||
| (a) | Unvested restricted stock awards and Pioneer Southwest phantom unit awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity owners of the Company or Pioneer Southwest, as applicable. Participating share- and unit-based earnings represent the distributed and |
113
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
| undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually obligated to do so. |
The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Weighted average common shares outstanding (a): |
||||||||||||
| Basic |
115,062 | 114,176 | 117,462 | |||||||||
| Dilutive common stock options (b) |
212 | — | 247 | |||||||||
| Contingently issuable—performance shares (b) |
646 | — | 90 | |||||||||
| Convertible notes dilution (c) |
410 | — | 148 | |||||||||
| Diluted |
116,330 | 114,176 | 117,947 | |||||||||
| (a) | In 2007, the Company’s Board of Directors (“Board”) approved a $750 million share repurchase program of which $355.8 million remained available for purchase as of December 31, 2010. The Company did not purchase any common stock pursuant to the program during 2010. During 2009, the Company purchased $16.2 million of common stock pursuant to the program. |
| (b) | Diluted earnings per share were calculated using the two-class method for the years ended December 31, 2010, 2009 and 2008. The following common stock equivalents were excluded from the diluted loss per share calculations for the year ended 2009 because they would have been anti-dilutive to the calculations: 173,915 outstanding options to purchase the Company’s common stock and 223,969 performance shares. |
| (c) | During January 2008, the Company issued $500 million of 2.875% Convertible Senior Notes. Weighted average common shares outstanding have been increased to reflect the dilutive effect that would have resulted if the 2.875% Convertible Senior Notes had qualified for and been converted during the years ended December 31, 2010 and 2008, respectively. The 2.875% Convertible Senior Notes were not dilutive to the per share calculations of 2009. |
NOTE Q. Geographic Operating Segment Information
The Company has operations in only one industry segment, that being the oil and gas exploration and production industry; however, the Company is organizationally structured along geographic operating segments or regions. The Company has reportable continuing operations in the United States and South Africa.
The following tables provide the Company’s geographic operating segment data as of and for the years ended December 31, 2010, 2009 and 2008. Geographic operating segment income tax benefits (provisions) have been determined based on statutory rates existing in the various tax jurisdictions where the Company has oil and gas producing activities. The “Headquarters” table column includes income and expenses that are not routinely included in the earnings measures internally reported to management on a geographic operating segment basis.
114
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
| United States |
South Africa | Headquarters | Consolidated Total |
|||||||||||||
| (in thousands) | ||||||||||||||||
| Year Ended December 31, 2010: |
||||||||||||||||
| Revenues and other income: |
||||||||||||||||
| Oil and gas |
$ | 1,718,296 | $ | 84,961 | $ | — | $ | 1,803,257 | ||||||||
| Interest and other |
— | — | 61,907 | 61,907 | ||||||||||||
| Derivative gains, net |
— | — | 448,434 | 448,434 | ||||||||||||
| Gain (loss) on disposition of assets, net |
25,289 | — | (6,215 | ) | 19,074 | |||||||||||
| Hurricane activity, net |
138,918 | — | 138,918 | |||||||||||||
| 1,882,503 | 84,961 | 504,126 | 2,471,590 | |||||||||||||
| Costs and expenses: |
||||||||||||||||
| Oil and gas production |
364,763 | 1,383 | — | 366,146 | ||||||||||||
| Production and ad valorem taxes |
112,141 | — | — | 112,141 | ||||||||||||
| Depletion, depreciation and amortization |
470,077 | 74,288 | 29,805 | 574,170 | ||||||||||||
| Exploration and abandonments |
189,597 | 512 | — | 190,109 | ||||||||||||
| General and administrative |
— | — | 165,301 | 165,301 | ||||||||||||
| Accretion of discount on asset retirement obligations |
7,945 | 2,488 | — | 10,433 | ||||||||||||
| Interest |
— | — | 183,084 | 183,084 | ||||||||||||
| Other |
37,516 | — | 44,207 | 81,723 | ||||||||||||
| 1,182,039 | 78,671 | 422,397 | 1,683,107 | |||||||||||||
| Income from continuing operations before income taxes |
700,464 | 6,290 | 81,729 | 788,483 | ||||||||||||
| Income tax provision |
(259,172 | ) | (1,824 | ) | (11,321 | ) | (272,317 | ) | ||||||||
| Income from continuing operations |
$ | 441,292 | $ | 4,466 | $ | 70,408 | $ | 516,166 | ||||||||
| Year Ended December 31, 2009: |
||||||||||||||||
| Revenues and other income: |
||||||||||||||||
| Oil and gas |
$ | 1,402,437 | $ | 57,217 | $ | — | $ | 1,459,654 | ||||||||
| Interest and other |
— | — | 101,669 | 101,669 | ||||||||||||
| Derivative losses, net |
— | — | (195,557 | ) | (195,557 | ) | ||||||||||
| Gain (loss) on disposition of assets, net |
82 | — | (856 | ) | (774 | ) | ||||||||||
| Hurricane activity, net |
(17,313 | ) | — | — | (17,313 | ) | ||||||||||
| 1,385,206 | 57,217 | (94,744 | ) | 1,347,679 | ||||||||||||
| Costs and expenses: |
||||||||||||||||
| Oil and gas production |
345,885 | 5,507 | — | 351,392 | ||||||||||||
| Production and ad valorem taxes |
98,371 | — | — | 98,371 | ||||||||||||
| Depletion, depreciation and amortization |
536,075 | 64,802 | 28,110 | 628,987 | ||||||||||||
| Impairment of oil and gas properties |
21,091 | — | — | 21,091 | ||||||||||||
| Exploration and abandonments |
79,095 | 623 | — | 79,718 | ||||||||||||
| General and administrative |
— | — | 131,524 | 131,524 | ||||||||||||
| Accretion of discount on asset retirement obligations |
8,050 | 2,549 | — | 10,599 | ||||||||||||
| Interest |
— | — | 173,353 | 173,353 | ||||||||||||
| Other |
54,223 | — | 45,850 | 100,073 | ||||||||||||
| 1,142,790 | 73,481 | 378,837 | 1,595,108 | |||||||||||||
| Income (loss) from continuing operations before income taxes |
242,416 | (16,264 | ) | (473,581 | ) | (247,429 | ) | |||||||||
| Income tax benefit (provision) |
(89,694 | ) | 4,717 | 173,223 | 88,246 | |||||||||||
| Income (loss) from continuing operations |
$ | 152,722 | $ | (11,547 | ) | $ | (300,358 | ) | $ | (159,183 | ) | |||||
115
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
| United States |
South Africa | Other Foreign |
Headquarters | Consolidated Total |
||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Year Ended December 31, 2008 |
||||||||||||||||||||
| Revenues and other income: |
||||||||||||||||||||
| Oil and gas |
$ | 1,893,360 | $ | 118,836 | $ | — | $ | — | $ | 2,012,196 | ||||||||||
| Interest and other |
— | — | — | 56,463 | 56,463 | |||||||||||||||
| Derivative losses, net |
— | — | — | (10,148 | ) | (10,148 | ) | |||||||||||||
| Gain (loss) on disposition of assets, net |
513 | — | — | (894 | ) | (381 | ) | |||||||||||||
| Hurricane activity, net |
(12,150 | ) | — | — | — | (12,150 | ) | |||||||||||||
| 1,881,723 | 118,836 | — | 45,421 | 2,045,980 | ||||||||||||||||
| Costs and expenses: |
||||||||||||||||||||
| Oil and gas production |
363,796 | 39,079 | — | — | 402,875 | |||||||||||||||
| Production and ad valorem taxes |
164,417 | — | — | — | 164,417 | |||||||||||||||
| Depletion, depreciation and amortization |
418,847 | 27,629 | — | 28,132 | 474,608 | |||||||||||||||
| Impairment of oil and gas properties |
89,753 | — | — | — | 89,753 | |||||||||||||||
| Exploration and abandonments |
189,728 | 143 | 2,072 | — | 191,943 | |||||||||||||||
| General and administrative |
— | — | — | 132,637 | 132,637 | |||||||||||||||
| Accretion of discount on asset retirement obligations |
5,509 | 2,208 | — | — | 7,717 | |||||||||||||||
| Interest |
— | — | — | 166,770 | 166,770 | |||||||||||||||
| Other |
54,539 | — | — | 59,924 | 114,463 | |||||||||||||||
| 1,286,589 | 69,059 | 2,072 | 387,463 | 1,745,183 | ||||||||||||||||
| Income (loss) from continuing operations before income taxes |
595,134 | 49,777 | (2,072 | ) | (342,042 | ) | 300,797 | |||||||||||||
| Income tax benefit (provision) |
(220,200 | ) | (14,435 | ) | — | 120,719 | (113,916 | ) | ||||||||||||
| Income (loss) from continuing operations |
$ | 374,934 | $ | 35,342 | $ | (2,072 | ) | $ | (221,323 | ) | $ | 186,881 | ||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Segment Assets: |
||||||||||||||||||||
| United States |
$ | 8,987,141 | $ | 8,333,414 | $ | 8,524,622 | ||||||||||||||
| South Africa |
134,901 | 179,000 | 241,619 | |||||||||||||||||
| Tunisia (a) |
325,942 | 266,342 | 299,168 | |||||||||||||||||
| Headquarters |
231,118 | 88,509 | 96,376 | |||||||||||||||||
| Total consolidated assets |
$ | 9,679,102 | $ | 8,867,265 | $ | 9,161,785 | ||||||||||||||
| (a) | Tunisia assets are classified as discontinued operations held for sale within current assets in the accompanying consolidated balance sheet as of December 31, 2010 (see Notes B and U for additional information about the Company’s discontinued operations). |
NOTE R. Impairment
The Company reviews its assets for impairment, including intangible assets, oil and gas properties and other long-lived assets, whenever events or circumstances indicate that their carrying values may not be recoverable. During the years ended December 31, 2009 and 2008, the Company recognized charges for the impairment of oil and gas properties in continuing operations of $21.1 million and $89.8 million, respectively, and $14.5 million of impairment in discontinued operations during the year ended December 31, 2008.
United States impairment. During the first quarter of 2009 and the second half of 2008, declines in commodity prices provided indications that the carrying values of the Company’s oil and gas properties in the Uinta/Piceance area and Mississippi may have been impaired. The Company’s estimates of the undiscounted future cash flows attributed to the assets indicated that their carrying amounts were not expected to be recovered. Consequently, the Company recorded noncash charges during the first quarter of 2009 and the third quarter of 2008 of $21.1 million and $89.8 million, respectively, to reduce the carrying value of the Uinta/Piceance area oil and gas properties, and $14.5 million during the fourth quarter of 2008 to reduce the carrying value of its Mississippi assets. During 2009, the Company sold its Mississippi assets and during the first half of 2010, the Company sold substantially all of its oil and gas properties in the Uinta/Piceance area. The results of operations and impairment charge attributable to the Mississippi assets are
116
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
included in discontinued operations, referred to in more detail in Note U. See Note M for more information on asset divestitures. The impairment charges reduced the oil and gas properties’ carrying values to their estimated fair values on those dates, represented by the estimated discounted future cash flows attributable to the assets, which were derived from Level 3 fair value inputs.
During the fourth quarter of 2010, declines in future gas prices indicated that the Company’s $2.4 billion carrying value of Raton Basin oil and gas properties may have been at risk for impairment. The Company tested the Raton Basin assets for impairment as of December 31, 2010 and determined that the future undiscounted cash flows attributable to the Raton Basin proved reserves exceeded the carrying value of the assets. Accordingly, the assets were not impaired. The Company will continue to assess its Raton Basin assets for impairment when impairment indicators are determined to exist.
The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves and risk-adjusted probable reserves, (ii) management’s commodity price outlook, including assumptions as to inflation of costs and expenses, (iii) the estimated discount rate that would be used by purchasers to assess the fair value of the assets and (iv) future income tax expense attributable to the net cash flows.
Goodwill assessments. The Company’s goodwill is attributable to a business combination that was completed in 2004 and is entirely attributable to United States reporting unit. The Company assesses its goodwill for impairment annually, during the third quarter using a July 1 assessment date, and whenever facts or circumstances indicate that the carrying value of its goodwill may be impaired. The Company’s assessments of goodwill during the third quarters of 2010 and 2009 indicated that it was not impaired.
The Company’s assessments of goodwill for impairment include estimates of the fair value of its United States reporting unit and comparisons of those fair value estimates with the United States reporting unit’s carrying value. The Company’s estimates of the fair value of its United States reporting unit entail estimating the fair values of the reporting unit’s assets and liabilities. The primary component of those assets and liabilities is comprised of the reporting unit’s oil and gas properties, whose estimated values were based on the estimated discounted future net cash flows expected to be recovered from the properties. The Company’s primary assumptions in preparing the estimated discounted future net cash flows expected to be recovered from the properties are based on (i) proved reserves and risk-adjusted probable reserves, (ii) management’s price outlook, including assumptions as to inflation of costs and expenses, (iii) the estimated discount rate that would be used by purchasers to assess the fair value of the assets and liabilities attributable to the United States reporting unit and (iv) future income tax expense attributable to the net cash flows.
The Company will assess its goodwill for impairment when facts and circumstances indicate that it may be impaired, but no less often than annually, and such assessments may be affected by (i) additional reserve adjustments, both positive and negative, (ii) results of drilling activities, (iii) changes in management’s outlook on commodity prices and costs and expenses, (iv) changes in the Company’s market capitalization, (v) changes in the Company’s weighted average cost of capital and (vi) changes in income taxes related to the Company’s United States reporting unit.
NOTE S. Volumetric Production Payments
The Company’s VPPs represent limited-term overriding royalty interests in oil and gas reserves that: (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 associated with the reserves, (iii) are nonrecourse to the Company (i.e., the purchaser’s only recourse is to the reserves acquired), (iv) transfer title of the reserves to the purchaser and (v) allow the Company to retain the remaining reserves after the VPPs volumetric quantities have been delivered.
At the inception of the VPP agreements, the Company (i) removed the proved reserves associated with the VPPs, (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to oil revenues over the term of each VPP, (iii) retained responsibility for 100 percent of the production costs and capital costs related to VPP interests and (iv) no longer recognizes production associated with the VPP volumes.
117
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following table provides information about the deferred revenue carrying values of the Company’s VPPs (in thousands):
| Deferred revenue at December 31, 2009 |
$ | 177,236 | ||
| Less: 2010 amortization |
(90,216 | ) | ||
| Deferred revenue at December 31, 2010 |
$ | 87,020 | ||
The remaining deferred revenue amounts will be recognized in oil revenues in the consolidated statements of operations as noted below, assuming the related VPP production volumes are delivered as scheduled (in thousands):
| 2011 |
$ | 44,951 | ||
| 2012 |
42,069 | |||
| $ | 87,020 | |||
NOTE T. Insurance Claims
As a result of Hurricane Rita in September 2005, the Company’s East Cameron 322 facility, located on the Gulf of Mexico shelf, was completely destroyed. Operations to reclaim and abandon the East Cameron 322 facility began in 2006 and are substantially complete. The Company estimates that it will expend approximately $2.5 million during 2011 to complete the operations to reclaim and abandon the East Cameron 322 facility.
In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues for the cost of reclamation and abandonment of the East Cameron 322 facility. During the fourth quarter of 2010, the Company and the insurance carriers agreed to settle the insurance policy dispute, resulting in an additional payment to the Company of $140 million during November 2010. Since 2005, the Company has recovered from its insurance providers (i) $199.8 million attributable to reclamation and abandonment costs incurred, (ii) $18.0 million related to business interruption and property damage losses and (iii) $3.0 million of reimbursed interest costs.
NOTE U. Discontinued Operations
During December 2010, the Company committed to a plan to sell its Tunisia subsidiaries and in February 2011 completed a sale to an unaffiliated third party of 100 percent of the Company’s share holdings in Pioneer Natural Resources Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as “Pioneer Tunisia”) for cash proceeds of $866 million, before normal closing adjustments. Pioneer Tunisia represents all of the Company’s Tunisian oil and gas operations. Accordingly, assets, liabilities and historic results of operations of Pioneer Tunisia have been classified as discontinued operations herein.
The Company sold substantially all of its Mississippi assets and shelf properties in the Gulf of Mexico during June and August 2009, respectively. The Company has reflected the results of operations of these divestitures as discontinued operations, rather than as a component of continuing operations.
During the fourth quarter of 2009, the Company recorded a $119.3 million receivable from the BOEMRE for the recovery of excess royalties paid by the Company on qualifying deepwater leases in the Gulf of Mexico. During 2010, BOEMRE paid the Company the $119.3 million receivable plus an additional $35.3 million of associated interest on the excess royalty payments. The properties that were the source of these royalty and interest recoveries were sold by the Company during 2006. Accordingly, the income recorded during 2010 has been classified as a component of income from discontinued operations, net of tax in the accompanying consolidated statements of operations.
118
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following table represents the components of the Company’s discontinued operations for the years ended December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Revenues and other income: |
||||||||||||
| Oil and gas |
$ | 151,382 | $ | 164,062 | $ | 265,134 | ||||||
| Interest and other (a) |
44,961 | 119,982 | 3,355 | |||||||||
| Gain (loss) on disposition of assets, net (b) |
36 | 17,491 | (392 | ) | ||||||||
| 196,379 | 301,535 | 268,097 | ||||||||||
| Costs and expenses: |
||||||||||||
| Oil and gas production |
13,371 | 34,114 | 27,746 | |||||||||
| Production and ad valorem taxes |
— | (27 | ) | 204 | ||||||||
| Depletion, depreciation and amortization (b) |
24,181 | 26,435 | 37,237 | |||||||||
| Impairment of oil and gas properties (c) |
— | — | 14,516 | |||||||||
| Exploration and abandonments (b) |
15,396 | 18,617 | 43,588 | |||||||||
| General and administrative |
4,728 | 8,987 | 10,011 | |||||||||
| Accretion of discount on asset retirement obligations (b) |
435 | 968 | 982 | |||||||||
| Interest |
— | 8 | 46 | |||||||||
| Other |
11,399 | 4,938 | 4,008 | |||||||||
| 69,510 | 94,040 | 138,338 | ||||||||||
| Income from discontinued operations before income taxes |
126,869 | 207,495 | 129,759 | |||||||||
| Income tax benefit (provision): |
||||||||||||
| Current |
(11,179 | ) | (21,338 | ) | (66,290 | ) | ||||||
| Deferred |
14,139 | (69,241 | ) | (18,695 | ) | |||||||
| Income from discontinued operations |
$ | 129,829 | $ | 116,916 | $ | 44,774 | ||||||
| (a) | Primarily comprised of (i) $119.3 million receivable from the BOEMRE recorded in the fourth quarter of 2009 for the recovery of excess royalties paid by the Company on qualifying deepwater leases in the Gulf of Mexico, (ii) $35.3 million of associated interest on the aforementioned excess royalty payments received during the second quarter of 2010, (iii) $2.8 million of legal settlements paid to the Company during the third quarter of 2010 on Gulf of Mexico discontinued operations sold during 2006, (iv) $2.1 million of Canadian sales tax refunds paid to the Company during the second quarter of 2010 attributable Canadian discontinued operations sold during 2007 and (v) $3.8 million of Argentine value added tax contingency charge reversals recorded during 2010 on Argentine discontinued operations sold during 2006. |
| (b) | Represents the significant noncash components of discontinued operations. |
| (c) | During 2008, the Company recognized $14.5 million of impairment to reduce the carrying value of its Mississippi assets that were sold during 2009. See Note R for additional information regarding impairment of oil and gas properties and other assets. |
119
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
As of December 31, 2010, the carrying values of the Company’s Tunisia operations were included in discontinued operations held for sale in the accompanying consolidated balance sheet and are comprised of the following (in thousands):
| Composition of assets included in discontinued operations held for sale: |
||||
| Current assets |
$ | 43,500 | ||
| Property, plant and equipment |
184,357 | |||
| Deferred tax assets |
14,731 | |||
| Other assets, net |
39,153 | |||
| Total assets |
$ | 281,741 | ||
| Composition of liabilities included in discontinued operations held for sale: |
||||
| Current liabilities |
$ | 30,148 | ||
| Deferred tax liabilities |
72,663 | |||
| Other liabilities |
5,781 | |||
| Total liabilities |
$ | 108,592 | ||
NOTE V. Subsequent Events
On February 17, 2011, the Board declared a cash dividend of $.04 per common share. The dividend is payable April 14, 2011 to stockholders of record at the close of business on March 31, 2011.
The Company has evaluated subsequent events through the date of issuance of the consolidated financial statements. Except as described above and in Notes O and U, the Company is not aware of any reportable subsequent events.
120
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2010, 2009 and 2008
Capitalized Costs
| December 31, | ||||||||
| 2010 (a) | 2009 | |||||||
| (in thousands) | ||||||||
| Oil and gas properties: |
||||||||
| Proved |
$ | 11,003,805 | $ | 10,276,244 | ||||
| Unproved |
191,112 | 236,660 | ||||||
| Capitalized costs for oil and gas properties |
11,194,917 | 10,512,904 | ||||||
| Less accumulated depletion, depreciation and amortization |
(3,447,740 | ) | (2,946,048 | ) | ||||
| Net capitalized costs for oil and gas properties |
$ | 7,747,177 | $ | 7,566,856 | ||||
| (a) | Includes $264.7 million of proved property and $81.3 million of accumulated depletion, depreciation and amortization related to Tunisia, which was classified as held for sale at December 31, 2010. |
Costs Incurred for Oil and Gas Producing Activities (a)
| Property Acquisition Costs |
Exploration | Development | Total Costs | |||||||||||||||||
| Proved | Unproved | Costs | Costs | Incurred | ||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Year Ended December 31, 2010: |
||||||||||||||||||||
| United States |
$ | 6,566 | $ | 175,007 | $ | 246,186 | $ | 685,670 | $ | 1,113,429 | ||||||||||
| South Africa |
— | — | 512 | 1,782 | 2,294 | |||||||||||||||
| Tunisia |
— | — | 30,629 | 39,874 | 70,503 | |||||||||||||||
| Other |
— | — | 329 | — | 329 | |||||||||||||||
| Total |
$ | 6,566 | $ | 175,007 | $ | 277,656 | $ | 727,326 | $ | 1,186,555 | ||||||||||
| Year Ended December 31, 2009: |
||||||||||||||||||||
| United States |
$ | 8,770 | $ | 80,088 | $ | 90,737 | $ | 255,538 | $ | 435,133 | ||||||||||
| South Africa |
65 | — | 623 | (1,448 | ) | (760 | ) | |||||||||||||
| Tunisia |
— | — | 19,931 | 17,470 | 37,401 | |||||||||||||||
| Other |
— | — | 724 | — | 724 | |||||||||||||||
| Total |
$ | 8,835 | $ | 80,088 | $ | 112,015 | $ | 271,560 | $ | 472,498 | ||||||||||
| Year Ended December 31, 2008: |
||||||||||||||||||||
| United States |
$ | 87,482 | $ | 50,126 | $ | 322,086 | $ | 860,754 | $ | 1,320,448 | ||||||||||
| South Africa |
— | — | 145 | 7,062 | 7,207 | |||||||||||||||
| Tunisia |
— | — | 104,343 | 28,902 | 133,245 | |||||||||||||||
| Total |
$ | 87,482 | $ | 50,126 | $ | 426,574 | $ | 896,718 | $ | 1,460,900 | ||||||||||
| (a) | The costs incurred for oil and gas producing activities includes the following amounts of asset retirement obligations: |
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Proved property acquisition costs |
$ | 6 | $ | — | $ | 2,237 | ||||||
| Exploration costs |
6,820 | 1,068 | 749 | |||||||||
| Development costs |
14,369 | 19,859 | 22,515 | |||||||||
| Total |
$ | 21,195 | $ | 20,927 | $ | 25,501 | ||||||
Information about the Company’s results of operations for oil and gas producing activities by geographic operating segment is presented in Note Q of the accompanying notes to consolidated financial statements.
121
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2010, 2009 and 2008
Reserve Quantity Information
The estimates of the Company’s proved reserves as of December 31, 2010, 2009, and 2008, which were located in the United States, South Africa and Tunisia, were based on evaluations prepared by the Company’s engineers and audited by independent petroleum engineers with respect to the Company’s major properties and prepared by the Company’s engineers with respect to all other properties. Proved reserves were estimated in accordance with guidelines established by the United States Securities and Exchange Commission and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements.
During 2009, the SEC issued the Reserve Ruling and the FASB issued an ASU to ASC Topic 932 that aligns Topic 932 estimation and disclosure requirements with the Reserve Ruling. The Reserve Ruling and the Topic 932 ASU became effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. The key provisions of the Reserve Ruling and Topic 932 ASU are as follows:
| • | Expanding the definition of oil- and gas-producing activities to include the extraction of saleable hydrocarbons, in the solid, liquid or gaseous state, from oil sands, coalbeds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction; |
| • | Amending the definition of proved oil and gas reserves to require the use of an average of the first-day-of-the-month commodity prices during the 12-month period ending on the balance sheet date rather than the period-end commodity prices; |
| • | Adding to and amending other definitions used in estimating proved oil and gas reserves, such as “reliable technology” and “reasonable certainty”; |
| • | Broadening the types of technology that a registrant may use to establish reserves estimates and categories; and |
| • | Changing disclosure requirements and providing formats for tabular reserve disclosures, including the following new disclosure provisions: |
| • | Disclosure of reserves from non-traditional sources as oil and gas reserves, |
| • | Optional disclosure of probable and possible reserves, |
| • | Disclosure based on a new definition of the term “geographic area” and |
| • | Disclosure of significant portions of reserve quantities and standardized measure of discounted future net cash flows attributable to a consolidated subsidiary in which there is a significant noncontrolling interest. |
The Company reports all 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 for production sharing arrangements reported under the “economic interest” method are subject to fluctuations in the commodity prices of 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. The reserve estimates as of December 31, 2010, 2009 and 2008 utilized respective oil prices of $77.16, $59.49 and $43.00 per Bbl (reflecting adjustments for oil quality), respective NGL prices of $37.82, $28.41 and $20.07 per Bbl, and respective gas prices of $4.07, $3.19 and $4.63 per Mcf (reflecting adjustments for Btu content, gas processing and shrinkage).
Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
The following table provides a rollforward of total proved reserves by geographic area and in total for the years ended December 31, 2010, 2009 and 2008, as well as proved developed and undeveloped reserves by geographic area and in total as of the beginning and end of each respective year. Oil and NGL volumes are expressed in MBbls, gas volumes are expressed in MMcf and total volumes are expressed in thousands of barrels of oil equivalent (“MBOE”).
122
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2010, 2009 and 2008
| Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf)(a) |
Total (MBOE) |
Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf)(a) |
Total (MBOE) |
Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf)(a) |
Total (MBOE) |
|||||||||||||||||||||||||||||||||||||
| Total Proved Reserves: |
||||||||||||||||||||||||||||||||||||||||||||||||
| UNITED STATES |
||||||||||||||||||||||||||||||||||||||||||||||||
| Balance, January 1 |
315,593 | 156,834 | 2,450,131 | 880,781 | 294,357 | 154,535 | 2,917,029 | 935,063 | 291,381 | 159,710 | 2,903,055 | 934,933 | ||||||||||||||||||||||||||||||||||||
| Revisions of previous estimates |
12,897 | 19,291 | 188,109 | 63,540 | 21,910 | 8,263 | (335,006 | ) | (25,660 | ) | (8,577 | ) | (6,077 | ) | (92,794 | ) | (30,120 | ) | ||||||||||||||||||||||||||||||
| Purchases of minerals-in-place |
1,944 | 555 | 3,364 | 3,060 | — | — | — | — | 2,425 | 2,045 | 58,758 | 14,263 | ||||||||||||||||||||||||||||||||||||
| Extensions and discoveries |
31,428 | 15,669 | 155,448 | 73,005 | 10,413 | 1,229 | 18,865 | 14,785 | 17,196 | 5,841 | 202,284 | 56,751 | ||||||||||||||||||||||||||||||||||||
| Improved recovery |
9,716 | — | — | 9,716 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
| Production (b) |
(10,297 | ) | (7,203 | ) | (139,658 | ) | (40,777 | ) | (9,315 | ) | (7,193 | ) | (147,473 | ) | (41,088 | ) | (8,068 | ) | (6,984 | ) | (154,274 | ) | (40,764 | ) | ||||||||||||||||||||||||
| Sales of minerals-in-place |
(565 | ) | (928 | ) | (21,692 | ) | (5,108 | ) | (1,772 | ) | — | (3,284 | ) | (2,319 | ) | — | — | — | — | |||||||||||||||||||||||||||||
| Balance, December 31 (c) |
360,716 | 184,218 | 2,635,702 | 984,217 | 315,593 | 156,834 | 2,450,131 | 880,781 | 294,357 | 154,535 | 2,917,029 | 935,063 | ||||||||||||||||||||||||||||||||||||
| SOUTH AFRICA |
||||||||||||||||||||||||||||||||||||||||||||||||
| Balance, January 1 |
217 | — | 25,790 | 4,516 | 471 | — | 38,624 | 6,909 | 757 | — | 40,565 | 7,520 | ||||||||||||||||||||||||||||||||||||
| Revisions of previous estimates |
282 | — | 743 | 406 | (117 | ) | — | (3,513 | ) | (703 | ) | 594 | — | 1,804 | 894 | |||||||||||||||||||||||||||||||||
| Production (b) |
(225 | ) | — | (10,862 | ) | (2,035 | ) | (137 | ) | — | (9,321 | ) | (1,690 | ) | (880 | ) | — | (3,745 | ) | (1,505 | ) | |||||||||||||||||||||||||||
| Balance, December 31 |
274 | — | 15,671 | 2,887 | 217 | — | 25,790 | 4,516 | 471 | — | 38,624 | 6,909 | ||||||||||||||||||||||||||||||||||||
| TUNISIA |
||||||||||||||||||||||||||||||||||||||||||||||||
| Balance, January 1 |
9,526 | — | 22,880 | 13,339 | 13,587 | — | 24,104 | 17,604 | 17,850 | — | 20,794 | 21,314 | ||||||||||||||||||||||||||||||||||||
| Revisions of previous estimates |
1,927 | — | 1,309 | 2,145 | (1,678 | ) | — | (615 | ) | (1,780 | ) | (3,376 | ) | — | 4,176 | (2,679 | ) | |||||||||||||||||||||||||||||||
| Extensions and discoveries |
10,707 | — | — | 10,707 | — | — | — | — | 2,026 | — | — | 2,026 | ||||||||||||||||||||||||||||||||||||
| Production (b) |
(1,781 | ) | — | (1,040 | ) | (1,954 | ) | (2,383 | ) | — | (609 | ) | (2,485 | ) | (2,261 | ) | — | (866 | ) | (2,405 | ) | |||||||||||||||||||||||||||
| Sales of minerals-in-place |
(560 | ) | — | — | (560 | ) | — | — | — | — | (652 | ) | — | — | (652 | ) | ||||||||||||||||||||||||||||||||
| Balance, December 31 |
19,819 | — | 23,149 | 23,677 | 9,526 | — | 22,880 | 13,339 | 13,587 | — | 24,104 | 17,604 | ||||||||||||||||||||||||||||||||||||
| TOTAL |
||||||||||||||||||||||||||||||||||||||||||||||||
| Balance, January 1 |
325,336 | 156,834 | 2,498,801 | 898,636 | 308,415 | 154,535 | 2,979,757 | 959,576 | 309,988 | 159,710 | 2,964,414 | 963,767 | ||||||||||||||||||||||||||||||||||||
| Revisions of previous estimates |
15,106 | 19,291 | 190,161 | 66,091 | 20,115 | 8,263 | (339,134 | ) | (28,143 | ) | (11,359 | ) | (6,077 | ) | (86,814 | ) | (31,905 | ) | ||||||||||||||||||||||||||||||
| Purchases of minerals-in-place |
1,944 | 555 | 3,364 | 3,060 | — | — | — | — | 2,425 | 2,045 | 58,758 | 14,263 | ||||||||||||||||||||||||||||||||||||
| Extensions and discoveries |
42,135 | 15,669 | 155,448 | 83,712 | 10,413 | 1,229 | 18,865 | 14,785 | 19,222 | 5,841 | 202,284 | 58,777 | ||||||||||||||||||||||||||||||||||||
| Improved recovery |
9,716 | — | — | 9,716 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
| Production (b) |
(12,303 | ) | (7,203 | ) | (151,560 | ) | (44,766 | ) | (11,835 | ) | (7,193 | ) | (157,403 | ) | (45,263 | ) | (11,209 | ) | (6,984 | ) | (158,885 | ) | (44,674 | ) | ||||||||||||||||||||||||
| Sales of minerals-in-place |
(1,125 | ) | (928 | ) | (21,692 | ) | (5,668 | ) | (1,772 | ) | — | (3,284 | ) | (2,319 | ) | (652 | ) | — | — | (652 | ) | |||||||||||||||||||||||||||
| Balance, December 31 |
380,809 | 184,218 | 2,674,522 | 1,010,781 | 325,336 | 156,834 | 2,498,801 | 898,636 | 308,415 | 154,535 | 2,979,757 | 959,576 | ||||||||||||||||||||||||||||||||||||
| (a) | The proved gas reserves as of December 31, 2010, 2009 and 2008 include 303,748 MMcf, 310,463 MMcf, and 360,340 MMcf, respectively, of gas that will be produced and utilized as field fuel. Field fuel is gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point. |
| (b) | Production for 2010, 2009 and 2008 includes approximately 17,289 MMcf, 18,027 MMcf and 18,771 MMcf of field fuel, respectively. Also, for 2010, 2009 and 2008, production includes 1,954 MBOE, 328 MBOE and 571 MBOE of production associated with discontinued operations. See Note U for additional information. |
| (c) | As of December 31, 2010 , 2009 and 2008, the portions of the Company’s United States proved reserves attributable to noncontrolling interests in Pioneer Southwest were as follows: |
123
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2010, 2009 and 2008
| Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf)(a) |
Total (MBOE) |
Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf)(a) |
Total (MBOE) |
Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf)(a) |
Total (MBOE) |
|||||||||||||||||||||||||||||||||||||
| Total Proved Reserves: |
||||||||||||||||||||||||||||||||||||||||||||||||
| Noncontrolling interest in total proved reserves |
11,852 | 4,753 | 18,843 | 19,745 | 10,539 | 3,741 | 15,448 | 16,854 | 4,311 | 1,680 | 6,966 | 7,152 | ||||||||||||||||||||||||||||||||||||
The following table provides the Company’s proved developed and proved undeveloped reserves as of January 1 and December 31, 2010, 2009 and 2008:
| Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf) | Total (MBOE) |
Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf) | Total (MBOE) |
Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf) | Total (MBOE) |
|||||||||||||||||||||||||||||||||||||
| Proved Developed Reserves: |
||||||||||||||||||||||||||||||||||||||||||||||||
| United States |
135,568 | 93,015 | 1,671,052 | 507,092 | 119,964 | 91,456 | 1,907,719 | 529,373 | 136,571 | 101,501 | 1,976,080 | 567,419 | ||||||||||||||||||||||||||||||||||||
| South Africa |
217 | — | 25,790 | 4,516 | 471 | — | 38,624 | 6,909 | 757 | — | 40,565 | 7,520 | ||||||||||||||||||||||||||||||||||||
| Tunisia |
8,478 | — | 22,880 | 12,291 | 13,587 | — | 24,104 | 17,604 | 17,850 | — | 20,794 | 21,314 | ||||||||||||||||||||||||||||||||||||
| Balance, January 1 |
144,263 | 93,015 | 1,719,722 | 523,899 | 134,022 | 91,456 | 1,970,447 | 553,886 | 155,178 | 101,501 | 2,037,439 | 596,253 | ||||||||||||||||||||||||||||||||||||
| United States |
160,421 | 108,785 | 1,736,765 | 558,667 | 135,568 | 93,015 | 1,671,052 | 507,092 | 119,964 | 91,456 | 1,907,719 | 529,373 | ||||||||||||||||||||||||||||||||||||
| South Africa |
274 | — | 15,671 | 2,886 | 217 | — | 25,790 | 4,516 | 471 | — | 38,624 | 6,909 | ||||||||||||||||||||||||||||||||||||
| Tunisia |
12,121 | — | 23,175 | 15,984 | 8,478 | — | 22,880 | 12,291 | 13,587 | — | 24,104 | 17,604 | ||||||||||||||||||||||||||||||||||||
| Balance, December 31 |
172,816 | 108,785 | 1,775,611 | 577,537 | 144,263 | 93,015 | 1,719,722 | 523,899 | 134,022 | 91,456 | 1,970,447 | 553,886 | ||||||||||||||||||||||||||||||||||||
| Proved Undeveloped Reserves (a): |
||||||||||||||||||||||||||||||||||||||||||||||||
| United States |
180,025 | 63,819 | 779,079 | 373,689 | 174,393 | 63,079 | 1,009,310 | 405,690 | 154,810 | 58,209 | 926,975 | 367,514 | ||||||||||||||||||||||||||||||||||||
| Tunisia |
1,048 | — | — | 1,048 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
| Balance, January 1 |
181,073 | 63,819 | 779,079 | 374,737 | 174,393 | 63,079 | 1,009,310 | 405,690 | 154,810 | 58,209 | 926,975 | 367,514 | ||||||||||||||||||||||||||||||||||||
| United States |
200,295 | 75,433 | 898,937 | 425,550 | 180,025 | 63,819 | 779,079 | 373,689 | 174,393 | 63,079 | 1,009,310 | 405,690 | ||||||||||||||||||||||||||||||||||||
| Tunisia |
7,698 | — | (26 | ) | 7,694 | 1,048 | — | — | 1,048 | — | — | — | ||||||||||||||||||||||||||||||||||||
| Balance, December 31 |
207,993 | 75,433 | 898,911 | 433,244 | 181,073 | 63,819 | 779,079 | 374,737 | 174,393 | 63,079 | 1,009,310 | 405,690 | ||||||||||||||||||||||||||||||||||||
124
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2010, 2009 and 2008
| (a) | As of December 31, 2010, the Company has 4,727 proved undeveloped well locations (all of which are expected to be developed during the five year period ending December 31, 2015), as compared to 4,582 and 4,977 at December 31, 2009 and 2008, respectively. During 2010, the Company’s development drilling costs incurred increased by 168 percent, as compared to 2009, and the Company converted 19,158 MBOE of proved undeveloped reserves to proved developed reserves. The increase in development drilling costs during 2010 is reflective of the Company’s expansion of oil- and liquids-focused drilling expenditures during 2010. The Company significantly reduced its development drilling expenditures during 2009 in support of cost reduction initiatives implemented during the second half of 2008 and 2009 in response to significant declines in energy demand and commodity prices. The Company’s proved undeveloped well locations that have remained undeveloped for five years or more decreased by 12 percent to 1,467 as of December 31, 2010, as compared to 1,675 well locations at December 31, 2009. Of these undeveloped well locations, 85 percent are in the Spraberry field in the Permian Basin of West Texas. The significant concentration of well locations that have remained undeveloped for five years or more in the Spraberry field is reflective of the Company’s large inventory of drilling locations in the field and the aforementioned curtailment of development drilling activity during 2008 and 2009 in support of cost reduction initiatives. The Company expects to continue to reduce the average age of its undeveloped well locations in the Spraberry field as a result of increases in development drilling budgets in 2011 and future years. |
125
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2010, 2009 and 2008
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is computed by applying commodity prices used in determining proved reserves (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved reserves less estimated future expenditures (based on year-end estimated costs) to be incurred in developing and producing the proved reserves, discounted using a rate of ten percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and gas properties plus available carryforwards and credits and applying the current tax rates to the difference. The discounted future cash flow estimates do not include the effects of the Company’s commodity derivative contracts. Utilizing the first-day-of-the-month commodity prices during the 12-month period ending on December 31, 2010, held constant over each derivative contract’s term, the net present value of the Company’s derivative contracts, less associated estimated income taxes and discounted at ten percent, was an asset of $490.4 million at December 31, 2010.
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
126
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2010, 2009 and 2008
The following tables provide the standardized measure of discounted future cash flows by geographic area and in total as of December 31, 2010, 2009 and 2008, as well as a roll forward in total for each respective year:
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| UNITED STATES |
||||||||||||
| Oil and gas producing activities: |
||||||||||||
| Future cash inflows |
$ | 44,100,276 | $ | 29,884,670 | $ | 27,779,303 | ||||||
| Future production costs |
(17,313,651 | ) | (12,527,319 | ) | (11,605,862 | ) | ||||||
| Future development costs |
(6,663,322 | ) | (4,623,978 | ) | (4,840,604 | ) | ||||||
| Future income tax expense |
(6,453,833 | ) | (3,468,973 | ) | (2,831,642 | ) | ||||||
| 13,669,470 | 9,264,400 | 8,501,195 | ||||||||||
| 10% annual discount factor |
(8,822,857 | ) | (6,193,552 | ) | (5,530,053 | ) | ||||||
| Standardized measure of discounted future cash flows (a) |
$ | 4,846,613 | $ | 3,070,848 | $ | 2,971,142 | ||||||
| SOUTH AFRICA |
||||||||||||
| Oil and gas producing activities: |
||||||||||||
| Future cash inflows |
$ | 123,215 | $ | 147,022 | $ | 140,031 | ||||||
| Future production costs |
(7,805 | ) | (11,130 | ) | (18,594 | ) | ||||||
| Future development costs |
(42,281 | ) | (41,445 | ) | (46,516 | ) | ||||||
| Future income tax expense |
(27,052 | ) | (21,830 | ) | (9,431 | ) | ||||||
| 46,077 | 72,617 | 65,490 | ||||||||||
| 10% annual discount factor |
1,502 | (712 | ) | (629 | ) | |||||||
| Standardized measure of discounted future cash flows |
$ | 47,579 | $ | 71,905 | $ | 64,861 | ||||||
| TUNISIA |
||||||||||||
| Oil and gas producing activities: |
||||||||||||
| Future cash inflows |
$ | 1,771,661 | $ | 750,078 | $ | 574,417 | ||||||
| Future production costs |
(218,785 | ) | (193,420 | ) | (214,566 | ) | ||||||
| Future development costs |
(64,184 | ) | (75,083 | ) | (58,335 | ) | ||||||
| Future income tax expense |
(754,238 | ) | (213,847 | ) | (102,187 | ) | ||||||
| 734,454 | 267,728 | 199,329 | ||||||||||
| 10% annual discount factor |
(216,637 | ) | (79,927 | ) | (47,945 | ) | ||||||
| Standardized measure of discounted future cash flows |
$ | 517,817 | $ | 187,801 | $ | 151,384 | ||||||
| TOTAL |
||||||||||||
| Oil and gas producing activities: |
||||||||||||
| Future cash inflows |
$ | 45,995,152 | $ | 30,781,770 | $ | 28,493,751 | ||||||
| Future production costs |
(17,540,241 | ) | (12,731,869 | ) | (11,839,022 | ) | ||||||
| Future development costs(b) |
(6,769,787 | ) | (4,740,506 | ) | (4,945,455 | ) | ||||||
| Future income tax expense |
(7,235,123 | ) | (3,704,650 | ) | (2,943,260 | ) | ||||||
| 14,450,001 | 9,604,745 | 8,766,014 | ||||||||||
| 10% annual discount factor |
(9,037,992 | ) | (6,274,191 | ) | (5,578,627 | ) | ||||||
| Standardized measure of discounted future cash flows |
$ | 5,412,009 | $ | 3,330,554 | $ | 3,187,387 | ||||||
| (a) | Includes $214.2 million and $99.6 million, respectively, attributable to a 38 percent noncontrolling interest in Pioneer Southwest for 2010 and 2009 and $38.5 million attributable to a 32 percent minority interest in Pioneer Southwest in 2008. |
| (b) | Includes $823.5 million, $453.5 million and $443.0 million of undiscounted future asset retirement expenditures estimated as of December 31, 2010, 2009 and 2008, respectively, using current estimates of future abandonment costs. See Note K for corresponding information regarding the Company’s discounted asset retirement obligations. |
127
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2010, 2009 and 2008
Changes in Standardized Measure of Discounted Future Net Cash Flows
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Oil and gas sales, net of production costs |
$ | (1,373,943 | ) | $ | (1,018,798 | ) | $ | (2,037,654 | ) | |||
| Net changes in prices and production costs |
2,098,422 | 1,006,250 | (9,019,111 | ) | ||||||||
| Extensions, discoveries and improved recovery |
1,017,597 | 82,431 | 867,528 | |||||||||
| Development costs incurred during the period |
380,754 | 183,936 | 632,359 | |||||||||
| Sales of minerals-in-place |
(42,043 | ) | (22,006 | ) | (64,384 | ) | ||||||
| Purchases of minerals-in-place |
20,957 | — | 243,412 | |||||||||
| Revisions of estimated future development costs |
(952,508 | ) | (151,029 | ) | (915,265 | ) | ||||||
| Revisions of previous quantity estimates |
626,693 | (229,369 | ) | (175,159 | ) | |||||||
| Accretion of discount |
437,523 | 385,681 | 1,336,401 | |||||||||
| Changes in production rates, timing and other |
1,415,999 | 281,326 | (375,321 | ) | ||||||||
| Change in present value of future net revenues |
3,629,451 | 518,422 | (9,507,194 | ) | ||||||||
| Net change in present value of future income taxes |
(1,547,996 | ) | (375,255 | ) | 3,677,697 | |||||||
| 2,081,455 | 143,167 | (5,829,497 | ) | |||||||||
| Balance, beginning of year |
3,330,554 | 3,187,387 | 9,016,884 | |||||||||
| Balance, end of year |
$ | 5,412,009 | $ | 3,330,554 | $ | 3,187,387 | ||||||
128
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2010, 2009 and 2008
Selected Quarterly Financial Results
The following table provides selected quarterly financial results for the years ended December 31, 2010 and 2009:
| Quarter | ||||||||||||||||
| First | Second | Third | Fourth | |||||||||||||
| (In thousands, except per share data) | ||||||||||||||||
| Year ended December 31, 2010: |
||||||||||||||||
| Oil and gas revenues: |
||||||||||||||||
| As reported |
$ | 507,796 | $ | 462,142 | $ | 471,372 | $ | 471,759 | ||||||||
| Less discontinued operations |
(35,751 | ) | (40,100 | ) | (33,961 | ) | — | |||||||||
| Adjusted |
$ | 472,045 | $ | 422,042 | $ | 437,411 | $ | 471,759 | ||||||||
| Total revenues: |
||||||||||||||||
| As reported |
$ | 817,428 | $ | 662,394 | $ | 616,652 | $ | 486,659 | ||||||||
| Less discontinued operations |
(37,546 | ) | (43,411 | ) | (30,586 | ) | — | |||||||||
| Adjusted |
$ | 779,882 | $ | 618,983 | $ | 586,066 | $ | 486,659 | ||||||||
| Total costs and expenses: |
||||||||||||||||
| As reported |
$ | 396,348 | $ | 405,168 | $ | 426,499 | $ | 501,738 | ||||||||
| Less discontinued operations |
(17,268 | ) | (16,243 | ) | (13,136 | ) | — | |||||||||
| Adjusted |
$ | 379,080 | $ | 388,925 | $ | 413,363 | $ | 501,738 | ||||||||
| Net income |
$ | 260,606 | $ | 188,689 | $ | 114,574 | $ | 82,126 | ||||||||
| Net income attributable to common stockholders |
$ | 245,254 | $ | 167,576 | $ | 112,036 | $ | 80,342 | ||||||||
| Net income attributable to common stockholders per share: |
||||||||||||||||
| Basic |
$ | 2.09 | $ | 1.42 | $ | 0.95 | $ | 0.68 | ||||||||
| Diluted |
$ | 2.08 | $ | 1.41 | $ | 0.94 | $ | 0.67 | ||||||||
| Year ended December 31, 2009: |
||||||||||||||||
| Oil and gas revenues: |
||||||||||||||||
| As reported |
$ | 373,837 | $ | 370,692 | $ | 409,969 | $ | 461,472 | ||||||||
| Less discontinued operations |
(34,246 | ) | (38,502 | ) | (39,097 | ) | (44,471 | ) | ||||||||
| Adjusted |
$ | 339,591 | $ | 332,190 | $ | 370,872 | $ | 417,001 | ||||||||
| Total revenues: |
||||||||||||||||
| As reported |
$ | 483,870 | $ | 273,044 | $ | 393,035 | $ | 354,683 | ||||||||
| Less discontinued operations |
(34,869 | ) | (38,312 | ) | (39,220 | ) | (44,552 | ) | ||||||||
| Adjusted |
$ | 449,001 | $ | 234,732 | $ | 353,815 | $ | 310,131 | ||||||||
| Total costs and expenses: |
||||||||||||||||
| As reported |
$ | 495,946 | $ | 405,017 | $ | 408,515 | $ | 377,102 | ||||||||
| Less discontinued operations |
(32,031 | ) | (24,063 | ) | (19,019 | ) | (16,359 | ) | ||||||||
| Adjusted |
$ | 463,915 | $ | 380,954 | $ | 389,496 | $ | 360,743 | ||||||||
| Net income (loss) |
$ | (10,813 | ) | $ | (87,518 | ) | $ | 1,833 | $ | 54,230 | ||||||
| Net income (loss) attributable to common stockholders |
$ | (14,606 | ) | $ | (86,995 | ) | $ | (7,165 | ) | $ | 56,660 | |||||
| Net income (loss) attributable to common stockholders per share: |
||||||||||||||||
| Basic |
$ | (0.13 | ) | $ | (0.76 | ) | $ | (0.06 | ) | $ | 0.48 | |||||
| Diluted |
$ | (0.13 | ) | $ | (0.76 | ) | $ | (0.06 | ) | $ | 0.48 | |||||
129
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
| Item 9A. | Controls and Procedures |
Evaluation of disclosure controls and procedures. The Company’s management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (“the Exchange Act”), the effectiveness of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that Company’s disclosure controls and procedures were effective, as of the end of the period covered by this Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Changes in internal control over financial reporting. There have been no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed by or under the supervision of the Company’s principal executive officer and principal financial officer and effected by the Board, Management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.
The Company’s management, with the participation of its principal executive officer and principal financial officer assessed the effectiveness, as of December 31, 2010, of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control — Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting at a reasonable assurance level as of December 31, 2010, based on those criteria.
Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”
130
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
The Board of Directors and Stockholders of
Pioneer Natural Resources Company:
We have audited Pioneer Natural Resources Company’s (the “Company”) internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Pioneer Natural Resources Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Pioneer Natural Resources Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pioneer Natural Resources Company as of December 31, 2010 and 2009 and the related consolidated statements of operations, stockholders’ equity, cash flows and comprehensive income (loss) for each of the three years in the period ended December 31, 2010, and our report dated February 25, 2010 expressed an unqualified opinion thereon.
Ernst & Young LLP
Dallas, Texas
February 25, 2011
131
| Item 9B. | Other Information |
None.
| Item 10. | Directors, Executive Officers and Corporate Governance |
The information required in response to this Item will be set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held during May 2011 and is incorporated herein by reference.
| Item 11. | Executive Compensation |
The information required in response to this Item will be set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held during May 2011 and is incorporated herein by reference.
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Securities Authorized for Issuance under Equity Compensation Plans
The following table summarizes information about the Company’s equity compensation plans as of December 31, 2010:
| Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) |
Weighted-average exercise price of outstanding options, warrants and rights |
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in first column) (b) |
||||||||||
| Equity compensation plans approved by security holders: |
||||||||||||
| Pioneer Natural Resources Company: |
||||||||||||
| 2006 Long-Term Incentive Plan (c) |
— | — | 3,345,527 | |||||||||
| Long-Term Incentive Plan |
17,625 | $ | 25.19 | — | ||||||||
| Employee Stock Purchase Plan |
— | — | 171,307 | |||||||||
| Predecessor plans |
12,773 | 13.71 | — | |||||||||
| Equity compensation plans not approved by security holders |
— | — | — | |||||||||
| Total: |
30,398 | $ | 20.36 | 3,516,834 | ||||||||
| (a) | There are no outstanding warrants or equity rights awarded under the Company’s equity compensation plans. The securities listed do not include restricted stock awarded under the Company’s previous Long-Term Incentive Plan and the Company’s 2006 Long-Term Incentive Plan. |
| (b) | In May 2006, the stockholders of the Company approved the Long-Term Incentive Plan, which provides for the issuance of up to 9.1 million awards, as was supplementally approved by the shareholders of the Company during May 2009. Awards under the Long-Term Incentive Plan can be in the form of stock options, stock appreciation rights, performance units, restricted stock and restricted stock units. No additional awards may be made under the prior Long-Term Incentive Plan. The number of remaining securities available for future issuance under the Company’s Employee Stock Purchase Plan is based on the original authorized issuance of 750,000 shares less 578,693 cumulative shares issued through December 31, 2010. See Note G 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) | The number of remaining securities for future issuance reflect the deduction of the maximum number of shares that could be issued pursuant to grants of performance units outstanding at December 31, 2010. |
The remaining information required in response to this Item will be set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held during May 2011 and is incorporated herein by reference.
132
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
The information required in response to this Item will be set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held during May 2011 and is incorporated herein by reference.
| Item 14. | Principal Accounting Fees and Services |
The information required in response to this Item will be set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held during May 2011 and is incorporated herein by reference.
| Item 15. | Exhibits, Financial Statement Schedules |
| (a) | Listing of Financial Statements |
Financial Statements
The following consolidated financial statements of the Company are included in “Item 8. Financial Statements and Supplementary Data”:
| • | Report of Independent Registered Public Accounting Firm |
| • | Consolidated Balance Sheets as of December 31, 2010 and 2009 |
| • | Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008 |
| • | Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008 |
| • | Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008 |
| • | Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2010, 2009 and 2008 |
| • | Notes to Consolidated Financial Statements |
| • | Unaudited Supplementary Information |
| (b) | Exhibits |
The exhibits to this Report required to be filed pursuant to Item 15(b) are listed below and in the “Exhibit Index” attached hereto.
| (c) | Financial Statement Schedules |
No financial statement schedules are required to be filed as part of this Report or they are inapplicable.
133
Exhibits
| Exhibit |
Description | |||
| 2.1 |
— |
Purchase and Sale Agreement by and between Pioneer as Seller and Marubeni Offshore Production (USA) Inc. as Purchaser (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 28, 2006). | ||
| 2.2 * (a) |
— |
Agreement for the Sale and Purchase of the Entire Issued Share Capital of Pioneer Natural Resources Anaguid Ltd. and Pioneer Natural Resources Tunisia Ltd. between Pioneer Natural Resources USA, Inc. and OMV (Tunesien) Production GmbH dated January 6, 2011. | ||
| 3.1 |
— |
Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951). | ||
| 3.2 |
— |
Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, dated November 17, 2006, File No. 1-13245). | ||
| 4.1 |
— |
Form of Certificate of Common Stock, par value $.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951). | ||
| 4.2 |
— |
Rights Agreement dated July 24, 2001, between the Company and Continental Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form 8-A, File No. 1-13245, filed with the SEC on July 24, 2001). | ||
| 4.3 |
— |
Amendment No. 1 to Rights Agreement, dated as of May 22, 2006, between the Company and Continental Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.2 to Amendment No. 1 the Company’s Registration Statement on Form 8-A/A, File No. 1-13245, filed with the SEC on May 23, 2006). | ||
| 4.4 |
— |
Certificate of Designation of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit A to Exhibit 4.1 to the Company’s Registration Statement on Form 8-A, File No. 1-13245, filed with the SEC on July 24, 2001). | ||
| 4.5 |
— |
Indenture dated January 13, 1998, between the Company and The Bank of New York, as trustee (incorporated by reference to Exhibit 99.1 to the Company’s and Pioneer USA’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998). | ||
| 4.6 |
— |
First Supplemental Indenture dated as of January 13, 1998, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 99.2 to the Company’s and Pioneer USA’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998). | ||
| 4.7 |
— |
Second Supplemental Indenture dated as of April 11, 2000, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-13245). | ||
| 4.8 |
— |
Third Supplemental Indenture dated as of April 30, 2002, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 1-13245). | ||
| 4.9 |
— |
Fourth Supplemental Indenture dated as of July 15, 2004, among the Company and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004). | ||
| 4.10 |
— |
Fifth Supplemental Indenture dated as of July 15, 2004, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004). | ||
| 4.11 |
— |
Sixth Supplemental Indenture, dated as of May 1, 2006, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York Trust Company, N.A., as Trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 4, 2006). | ||
| 4.12 |
— |
Seventh Supplemental Indenture, dated as of March 12, 2007, among the Company, Pioneer Natural Resources USA, Inc., The Bank of New York Trust Company, N.A, as original trustee under the indenture, and Wells Fargo Bank, National Association, as series trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 12, 2007). | ||
134
| 4.13 |
— | Indenture dated as of March 10, 2004, among Evergreen and Wachovia Bank, National Association, as trustee, relating to Evergreen’s 5.875% Senior Subordinated Notes due 2012 (incorporated by reference to Exhibit 4.1 to Evergreen’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File No. 1-13171). | ||
| 4.14 |
— | First Supplemental Indenture dated as of September 28, 2004, among Pioneer Evergreen Properties, LLC (as successor to Evergreen) and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on October 1, 2004). | ||
| 4.15 |
— | Second Supplemental Indenture dated as of September 30, 2004, among Pioneer Debt Sub, LLC and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004). | ||
| 4.16 |
— | Third Supplemental Indenture dated as of September 30, 2004, among the Company and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.15 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004). | ||
| 4.17 |
— | Fourth Supplemental Indenture dated as of November 1, 2004, among the Company, Pioneer USA, as guarantor, and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004). | ||
| 4.18 |
— | Fifth Supplemental Indenture dated as of September 16, 2005 among the Company, Pioneer USA, as Guarantor, and Wachovia Bank, National Association, as Trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on September 21, 2005). | ||
| 4.19 |
— | Indenture dated January 22, 2008 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008). | ||
| 4.20 |
— | First Supplemental Indenture dated January 22, 2008 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.19 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008). | ||
| 4.21 |
— | Second Supplemental Indenture dated November 9, 2009 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.19 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 13, 2009). | ||
| 10.1 H |
— | The Company’s Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-8, Registration No. 333-35087, filed with the SEC on September 8, 1997). | ||
| 10.2 H |
— | First Amendment to the Company’s Long-Term Incentive Plan, effective as of November 23, 1998 (incorporated by reference to Exhibit 10.72 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245). | ||
| 10.3 H |
— | Amendment No. 2 to the Company’s Long-Term Incentive Plan, effective as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245). | ||
| 10.4 H |
— | Amendment No. 3 to the Company’s Long-Term Incentive Plan, effective as of February 17, 2000 (incorporated by reference to Exhibit 10.76 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245). | ||
| 10.5 H |
— | Amendment No. 4 to the Company’s Long-Term Incentive Plan, effective as of November 20, 2003 (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245). | ||
| 10.6 H |
— | Amendment No. 5 to the Company’s Long-Term Incentive Plan, effective as of May 12, 2004 (incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245). | ||
| 10.7 H |
— | Amendment No. 6 to the Company’s Long-Term Incentive Plan, effective as of December 17, 2004 (incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245). | ||
135
| 10.8 H |
— |
Amendment No. 7 to the Company’s Long Term Incentive Plan effective November 20, 2008 (incorporated by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.9 H |
— |
Form of Omnibus Nonstatutory Stock Option Agreement for Option Award Participants with respect to grants under the Company’s Long-Term Incentive Plan (Group 1) (incorporated by reference to Exhibit 10.20 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245). | ||
| 10.10 H |
— |
Pioneer Natural Resources Company Employee Stock Purchase Plan, as amended and restated effective September 1, 2007 (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, File No. 1-13245). | ||
| 10.11 H |
— |
The Company’s Executive Deferred Compensation Plan, Amended and Restated Effective as of August 1, 2002 (incorporated by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245). | ||
| 10.12 H |
— |
Amendment No. 1 to the Company’s Executive Deferred Compensation Plan, effective as of January 1, 2007 (incorporated by reference to Exhibit 10.15 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-13245). | ||
| 10.13 H |
— |
Pioneer USA 401(k) and Matching Plan, Amended and Restated Effective as of January 1, 2008 (incorporated by reference to Exhibit 10.15 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-13245). | ||
| 10.14 H |
— |
First Amendment to the Pioneer USA 401(k) and Matching Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245). | ||
| 10.15 H |
— |
Amendment No. 2 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-13245). | ||
| 10.16 H |
— |
Amendment No. 3 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed October 28, 2009 effective as of the dates specified therein (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-13245). | ||
| 10.17 H |
— |
Amendment No. 4 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, effective January 1, 2010 (incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, File No. 1-13245). | ||
| 10.18 |
— |
Amended and Restated 5-Year Revolving Credit Agreement dated as of April 11, 2007 among the Company, as Borrower, JPMorgan Chase Bank, N.A. as Administrative Agent and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 1-13245). | ||
| 10.19 |
— |
First Amendment to Amended and Restated Credit Agreement dated as of November 20, 2007 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 2008). | ||
| 10.20 |
— |
Second Amendment to Amended and Restated Credit Agreement dated as of January 1, 2009 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-13245). | ||
| 10.21 |
— |
Third Amendment to Amended and Restated Credit Agreement dated as of April 29, 2009 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 5, 2009). | ||
| 10.22 |
— |
Production Payment Purchase and Sale Agreement dated as of January 26, 2005 among the Company, as the Seller, and Royalty Acquisition Company, LLC, as the Buyer (related to Spraberry oil) (incorporated by reference to Exhibit 99.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 1, 2005). | ||
| 10.23 |
— |
Production Payment Purchase and Sale Agreement dated as of April 19, 2005 among the Company, as the Seller, and Wolfcamp Oil and Gas Trust, as the Buyer (incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on April 21, 2005). | ||
| 10.24 H |
— |
2000 Stock Incentive Plan of Evergreen (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-8, File No. 333-119355, filed with the SEC on September 29, 2004). | ||
136
| 10.25 H |
— | Indemnification Agreement between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its non-employee directors and executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 27, 2009). | ||
| 10.26 H |
— | Severance Agreement dated August 16, 2005, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Severance Agreement (incorporated by reference to Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13245). | ||
| 10.27 H |
— | Amended and restated Severance Agreement dated February 17, 2010, between the Company and David McManus (incorporated by reference to Exhibit 10.30 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009). | ||
| 10.28 H |
— | Change in Control Agreement, dated August 16, 2005, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 17, 2005). | ||
| 10.29 H |
— | Change in Control Agreement, dated August 10, 2005, between the Company and William F. Hannes (incorporated by reference to Exhibit 10.38 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, File No. 1-13245). | ||
| 10.30 H |
— | Form of Change in Control Agreement dated September 10, 2005, between the Company and each of Jay P. Still and David McManus (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 2008). | ||
| 10.31 H |
— | Pioneer Natural Resources Company 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 9, 2006). | ||
| 10.32 H |
— | First Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective November 20, 2008 (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.33 H |
— | Second Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective May 28, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 28, 2009). | ||
| 10.34 H |
— | Third Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009). | ||
| 10.35 H |
— | Fourth Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009). | ||
| 10.36 H |
— | Form of restricted stock unit Award Agreement for non-employee directors with respect to grants under the Company’s 2006 Long-Term Incentive Plan, together with a schedule identifying substantially identical agreements between the Company and each of its non-employee directors identified on the schedule and identifying the material differences between each of those agreements and the filed Award Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 9, 2006). | ||
| 10.37 H |
— | Form of Restricted Stock Unit Agreement for Non-Employee Directors to be used in connection with annual equity awards under the Company’s 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 1-13245). | ||
| 10.38 H |
— | Form of Restricted Stock Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company’s 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 2, 2007). | ||
137
| 10.39 H |
— | Form of Performance Unit Award Agreement, dated February 12, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company’s 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 19, 2008). | ||
| 10.40 |
— | First Amended and Restated Agreement of Limited Partnership of Pioneer Southwest Energy Partners L.P. dated May 6, 2008, between Pioneer Natural Resources GP LLC, as the General Partner, and Pioneer Natural Resources USA, Inc., as the Organizational Limited Partner, together with any other persons who become Partners (as defined in such agreement) in the Partnership (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 001-34032, of Pioneer Southwest Energy Partners L.P. filed with the SEC on May 9, 2008). | ||
| 10.41 |
— | Administrative Services Agreement, dated effective May 6, 2008, among Pioneer Natural Resources GP LLC, Pioneer Southwest Energy Partners L.P., Pioneer Southwest Energy Partners USA LLC, and Pioneer Natural Resources USA, Inc. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, File No. 001-34032, of Pioneer Southwest Energy Partners L.P. filed with the SEC on May 9, 2008). | ||
| 10.42 |
— | Credit Agreement entered into as of October 29, 2007, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference). | ||
| 10.43 |
— | Amendment to Credit Agreement dated as of December 14, 2007, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.8 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference). | ||
| 10.44 |
— | Second Amendment to Credit Agreement dated as of February 15, 2008, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.13 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference). | ||
| 10.45 |
— | Third Amendment to Credit Agreement dated as of April 15, 2008, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.15 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference). | ||
| 10.46 |
— | Limited Waiver Regarding Credit Agreement, entered into as of March 26, 2009, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and the other lenders signatory thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Pioneer Southwest Energy Partners L.P., File No. 001-34032, filed with the SEC on March 31, 2009). | ||
| 10.47 H |
— | Severance Agreement, dated May 19, 2008, between the Company and Frank W. Hall (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-13245). | ||
| 10.48 H |
— | Change in Control Agreement, dated May 19, 2008, between the Company and Frank W. Hall (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-13245). | ||
| 10.49 H |
— | Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.50 H |
— | Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
138
| 10.51 H |
— | Form of Amendment to Change in Control Agreement, dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.52 H |
— | Form of Amendment to Change in Control Agreement, dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.53 H |
— | Form of First Amendment to Performance Unit Award Agreements, dated November 20, 2008 (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.54 H |
— | Amended and Restated Executive Deferred Compensation Plan, effective as of January 1, 2009 (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.55 H |
— | Amendment No. 1 to the Company’s Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245). | ||
| 10.56 H (a) |
— | Amendment No. 2 to the Company’s Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2011. | ||
| 10.57 |
— | Letter Agreement dated March 18, 2009 between the Company and Southeastern Asset Management, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 19, 2009). | ||
| 10.58 H |
— | Form of Performance Unit Award Agreement, dated February 18, 2009, between the Company and Scott D. Sheffield, with respect to awards made under the Company’s 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13245). | ||
| 10.59 H |
— | Form of Nonstatutory Stock Option Agreement, dated February 18, 2009, between the Company and Scott D. Sheffield, with respect to awards made under the Company’s 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13245). | ||
| 10.60 H |
— | Form of Restricted Stock Unit Award Agreement, dated February 18, 2009, between the Company and Frank W. Hall and other officers of the Company, with respect to awards made under the Company’s 2006 Long Term Incentive Plan (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13245). | ||
| 10.61 H |
— | Pioneer Southwest Energy Partners L.P. 2008 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-1 of Pioneer Southwest Energy Partners L.P., Registration No. 333-144868). | ||
| 10.62 H |
— | Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company’s 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13245). | ||
| 10.63 H |
— | Form of Nonstatutory Stock Option Agreement between the Company and Scott D. Sheffield, with respect to awards made under the Company’s 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13245). | ||
| 10.64 H (a) |
— | Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to awards made under the Company’s 2006 Long Term Incentive Plan. | ||
139
| 21.1 (a) |
— |
Subsidiaries of the registrant. | ||
| 23.1 (a) |
— |
Consent of Ernst & Young LLP. | ||
| 23.2 (a) |
— |
Consent of Netherland, Sewell & Associates, Inc. | ||
| 31.1 (a) |
— |
Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002. | ||
| 31.2 (a) |
— |
Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002. | ||
| 32.1 (b) |
— |
Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002. | ||
| 32.2 (b) |
— |
Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002. | ||
| 99.1 (a) |
— |
Report of Netherland, Sewell & Associates, Inc. | ||
| 101. INS (b) |
— |
XBRL Instance Document. | ||
| 101. SCH (b) |
— |
XBRL Taxonomy Extension Schema. | ||
| 101. CAL (b) |
— |
XBRL Taxonomy Extension Calculation Linkbase Document. | ||
| 101. DEF (b) |
— |
XBRL Taxonomy Extension Definition Linkbase Document. | ||
| 101. LAB (b) |
— |
XBRL Taxonomy Extension Label Linkbase Document. | ||
| 101. PRE (b) |
— |
XBRL Taxonomy Extension Presentation Linkbase Document. | ||
| (a) | Filed herewith. |
| (b) | Furnished herewith. |
| H | Executive Compensation Plan or Arrangement. |
| * | Pursuant to the rules of the Commission, certain of the schedules and similar attachments to the Agreement have not been filed. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request. |
140
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| PIONEER NATURAL RESOURCES COMPANY | ||||||
| Date: February 25, 2011 |
||||||
| By: |
/s/ Scott D. Sheffield | |||||
| Scott D. Sheffield, | ||||||
| Chairman of the Board and Chief Executive Officer | ||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature |
Title |
Date | ||
| /s/ Scott D. Sheffield Scott D. Sheffield |
Chairman of the Board and Chief Executive Officer |
February 25, 2011 | ||
| /s/ Richard P. Dealy Richard P. Dealy |
Executive Vice President and Chief Financial Officer |
February 25, 2011 | ||
| /s/ Frank W. Hall Frank W. Hall |
Vice President and Chief Accounting Officer |
February 25, 2011 | ||
| /s/ Thomas D. Arthur Thomas D. Arthur |
Director |
February 25, 2011 | ||
| /s/ Edison C. Buchanan Edison C. Buchanan |
Director |
February 25, 2011 | ||
| /s/ Andrew F. Cates Andrew F. Cates |
Director |
February 25, 2011 | ||
| /s/ R. Hartwell Gardner R. Hartwell Gardner |
Director |
February 25, 2011 | ||
| /s/ Andrew D. Lundquist Andrew D. Lundquist |
Director |
February 25, 2011 | ||
| /s/ Charles E. Ramsey, Jr. Charles E. Ramsey, Jr. |
Director |
February 25, 2011 | ||
| /s/ Scott J. Reiman Scott J. Reiman |
Director |
February 25, 2011 | ||
| /s/ Frank A. Risch Frank A. Risch |
Director |
February 25, 2011 | ||
| /s/ Jim A. Watson Jim A. Watson |
Director |
February 25, 2011 | ||
141
| Exhibit |
Description | |||
| 2.1 |
— | Purchase and Sale Agreement by and between Pioneer as Seller and Marubeni Offshore Production (USA) Inc. as Purchaser (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 28, 2006). | ||
| 2.2*(a) |
— | Agreement for the Sale and Purchase of the Entire Issued Share Capital of Pioneer Natural Resources Anaguid Ltd. and Pioneer Natural Resources Tunisia Ltd. between Pioneer Natural Resources USA, Inc. and OMV (Tunesien) Production GmbH dated January 6, 2011. | ||
| 3.1 |
— | Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951). | ||
| 3.2 |
— | Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, dated November 17, 2006, File No. 1-13245). | ||
| 4.1 |
— | Form of Certificate of Common Stock, par value $.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951). | ||
| 4.2 |
— | Rights Agreement dated July 24, 2001, between the Company and Continental Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form 8-A, File No. 1-13245, filed with the SEC on July 24, 2001). | ||
| 4.3 |
— | Amendment No. 1 to Rights Agreement, dated as of May 22, 2006, between the Company and Continental Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.2 to Amendment No. 1 the Company’s Registration Statement on Form 8-A/A, File No. 1-13245, filed with the SEC on May 23, 2006). | ||
| 4.4 |
— | Certificate of Designation of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit A to Exhibit 4.1 to the Company’s Registration Statement on Form 8-A, File No. 1-13245, filed with the SEC on July 24, 2001). | ||
| 4.5 |
— | Indenture dated January 13, 1998, between the Company and The Bank of New York, as trustee (incorporated by reference to Exhibit 99.1 to the Company’s and Pioneer USA’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998). | ||
| 4.6 |
— | First Supplemental Indenture dated as of January 13, 1998, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 99.2 to the Company’s and Pioneer USA’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998). | ||
| 4.7 |
— | Second Supplemental Indenture dated as of April 11, 2000, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-13245). | ||
| 4.8 |
— | Third Supplemental Indenture dated as of April 30, 2002, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 1-13245). | ||
| 4.9 |
— | Fourth Supplemental Indenture dated as of July 15, 2004, among the Company and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004). | ||
| 4.10 |
— | Fifth Supplemental Indenture dated as of July 15, 2004, among the Company, Pioneer USA, as the subsidiary guarantor, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004). | ||
| 4.11 |
— | Sixth Supplemental Indenture, dated as of May 1, 2006, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York Trust Company, N.A., as Trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 4, 2006). | ||
| 4.12 |
— | Seventh Supplemental Indenture, dated as of March 12, 2007, among the Company, Pioneer Natural Resources USA, Inc., The Bank of New York Trust Company, N.A, as original trustee under the indenture, and Wells Fargo Bank, National Association, as series trustee, with respect to the indenture identified above as Exhibit 4.5 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 12, 2007). | ||
142
| 4.13 |
— | Indenture dated as of March 10, 2004, among Evergreen and Wachovia Bank, National Association, as trustee, relating to Evergreen’s 5.875% Senior Subordinated Notes due 2012 (incorporated by reference to Exhibit 4.1 to Evergreen’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File No. 1-13171). | ||
| 4.14 |
— | First Supplemental Indenture dated as of September 28, 2004, among Pioneer Evergreen Properties, LLC (as successor to Evergreen) and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on October 1, 2004). | ||
| 4.15 |
— | Second Supplemental Indenture dated as of September 30, 2004, among Pioneer Debt Sub, LLC and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004). | ||
| 4.16 |
— | Third Supplemental Indenture dated as of September 30, 2004, among the Company and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.15 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004). | ||
| 4.17 |
— | Fourth Supplemental Indenture dated as of November 1, 2004, among the Company, Pioneer USA, as guarantor, and Wachovia Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 5, 2004). | ||
| 4.18 |
— | Fifth Supplemental Indenture dated as of September 16, 2005 among the Company, Pioneer USA, as Guarantor, and Wachovia Bank, National Association, as Trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on September 21, 2005). | ||
| 4.19 |
— | Indenture dated January 22, 2008 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008). | ||
| 4.20 |
— | First Supplemental Indenture dated January 22, 2008 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.19 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008). | ||
| 4.21 |
— | Second Supplemental Indenture dated November 9, 2009 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.19 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 13, 2009). | ||
| 10.1 H |
— | The Company’s Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-8, Registration No. 333-35087, filed with the SEC on September 8, 1997). | ||
| 10.2 H |
— | First Amendment to the Company’s Long-Term Incentive Plan, effective as of November 23, 1998 (incorporated by reference to Exhibit 10.72 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245). | ||
| 10.3 H |
— | Amendment No. 2 to the Company’s Long-Term Incentive Plan, effective as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245). | ||
| 10.4 H |
— | Amendment No. 3 to the Company’s Long-Term Incentive Plan, effective as of February 17, 2000 (incorporated by reference to Exhibit 10.76 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245). | ||
| 10.5 H |
— | Amendment No. 4 to the Company’s Long-Term Incentive Plan, effective as of November 20, 2003 (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245). | ||
| 10.6 H |
— | Amendment No. 5 to the Company’s Long-Term Incentive Plan, effective as of May 12, 2004 (incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245). | ||
| 10.7 H |
— | Amendment No. 6 to the Company’s Long-Term Incentive Plan, effective as of December 17, 2004 (incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245). | ||
143
| 10.8 H |
— | Amendment No. 7 to the Company’s Long Term Incentive Plan effective November 20, 2008 (incorporated by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.9 H |
— | Form of Omnibus Nonstatutory Stock Option Agreement for Option Award Participants with respect to grants under the Company’s Long-Term Incentive Plan (Group 1) (incorporated by reference to Exhibit 10.20 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245). | ||
| 10.10 H |
— | Pioneer Natural Resources Company Employee Stock Purchase Plan, as amended and restated effective September 1, 2007 (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, File No. 1-13245). | ||
| 10.11 H |
— | The Company’s Executive Deferred Compensation Plan, Amended and Restated Effective as of August 1, 2002 (incorporated by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245). | ||
| 10.12 H |
— | Amendment No. 1 to the Company’s Executive Deferred Compensation Plan, effective as of January 1, 2007 (incorporated by reference to Exhibit 10.15 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-13245). | ||
| 10.13 H |
— | Pioneer USA 401(k) and Matching Plan, Amended and Restated Effective as of January 1, 2008 (incorporated by reference to Exhibit 10.15 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-13245). | ||
| 10.14 H |
— | First Amendment to the Pioneer USA 401(k) and Matching Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245). | ||
| 10.15 H |
— | Amendment No. 2 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-13245). | ||
| 10.16 H |
— | Amendment No. 3 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed October 28, 2009 effective as of the dates specified therein (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-13245). | ||
| 10.17 H |
— | Amendment No. 4 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, effective January 1, 2010 (incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, File No. 1-13245). | ||
| 10.18 |
— | Amended and Restated 5-Year Revolving Credit Agreement dated as of April 11, 2007 among the Company, as Borrower, JPMorgan Chase Bank, N.A. as Administrative Agent and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 1-13245). | ||
| 10.19 |
— | First Amendment to Amended and Restated Credit Agreement dated as of November 20, 2007 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 2008). | ||
| 10.20 |
— | Second Amendment to Amended and Restated Credit Agreement dated as of January 1, 2009 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-13245). | ||
| 10.21 |
— | Third Amendment to Amended and Restated Credit Agreement dated as of April 29, 2009 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 5, 2009). | ||
| 10.22 |
— | Production Payment Purchase and Sale Agreement dated as of January 26, 2005 among the Company, as the Seller, and Royalty Acquisition Company, LLC, as the Buyer (related to Spraberry oil) (incorporated by reference to Exhibit 99.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 1, 2005). | ||
| 10.23 |
— | Production Payment Purchase and Sale Agreement dated as of April 19, 2005 among the Company, as the Seller, and Wolfcamp Oil and Gas Trust, as the Buyer (incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on April 21, 2005). | ||
| 10.24 H |
— | 2000 Stock Incentive Plan of Evergreen (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-8, File No. 333-119355, filed with the SEC on September 29, 2004). | ||
144
| 10.25 H |
— | Indemnification Agreement between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its non-employee directors and executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 27, 2009). | ||
| 10.26 H |
— | Severance Agreement dated August 16, 2005, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Severance Agreement (incorporated by reference to Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13245). | ||
| 10.27 H |
— | Amended and restated Severance Agreement dated February 17, 2010, between the Company and David McManus (incorporated by reference to Exhibit 10.30 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009). | ||
| 10.28 H |
— | Change in Control Agreement, dated August 16, 2005, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 17, 2005). | ||
| 10.29 H |
— | Change in Control Agreement, dated August 10, 2005, between the Company and William F. Hannes (incorporated by reference to Exhibit 10.38 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, File No. 1-13245). | ||
| 10.30 H |
— | Form of Change in Control Agreement dated September 10, 2005, between the Company and each of Jay P. Still and David McManus (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 2008). | ||
| 10.31 H |
— | Pioneer Natural Resources Company 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 9, 2006). | ||
| 10.32 H |
— | First Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective November 20, 2008 (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.33 H |
— | Second Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective May 28, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 28, 2009). | ||
| 10.34 H |
— | Third Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009). | ||
| 10.35 H |
— | Fourth Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009). | ||
| 10.36 H |
— | Form of restricted stock unit Award Agreement for non-employee directors with respect to grants under the Company’s 2006 Long-Term Incentive Plan, together with a schedule identifying substantially identical agreements between the Company and each of its non-employee directors identified on the schedule and identifying the material differences between each of those agreements and the filed Award Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 9, 2006). | ||
| 10.37 H |
— | Form of Restricted Stock Unit Agreement for Non-Employee Directors to be used in connection with annual equity awards under the Company’s 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 1-13245). | ||
| 10.38 H |
— | Form of Restricted Stock Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company’s 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 2, 2007). | ||
145
| 10.39 H |
— | Form of Performance Unit Award Agreement, dated February 12, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company’s 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 19, 2008). | ||
| 10.40 |
— | First Amended and Restated Agreement of Limited Partnership of Pioneer Southwest Energy Partners L.P. dated May 6, 2008, between Pioneer Natural Resources GP LLC, as the General Partner, and Pioneer Natural Resources USA, Inc., as the Organizational Limited Partner, together with any other persons who become Partners (as defined in such agreement) in the Partnership (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 001-34032, of Pioneer Southwest Energy Partners L.P. filed with the SEC on May 9, 2008). | ||
| 10.41 |
— | Administrative Services Agreement, dated effective May 6, 2008, among Pioneer Natural Resources GP LLC, Pioneer Southwest Energy Partners L.P., Pioneer Southwest Energy Partners USA LLC, and Pioneer Natural Resources USA, Inc. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, File No. 001-34032, of Pioneer Southwest Energy Partners L.P. filed with the SEC on May 9, 2008). | ||
| 10.42 |
— | Credit Agreement entered into as of October 29, 2007, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference). | ||
| 10.43 |
— | Amendment to Credit Agreement dated as of December 14, 2007, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.8 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference). | ||
| 10.44 |
— | Second Amendment to Credit Agreement dated as of February 15, 2008, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.13 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference). | ||
| 10.45 |
— | Third Amendment to Credit Agreement dated as of April 15, 2008, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.15 to the Registration Statement on Form S-1 (No. 333-144868) of Pioneer Southwest Energy Partners L.P. and incorporated herein by reference). | ||
| 10.46 |
— | Limited Waiver Regarding Credit Agreement, entered into as of March 26, 2009, among Pioneer Southwest Energy Partners L.P., as the Borrower, Bank of America, N.A., as Administrative Agent, and the other lenders signatory thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Pioneer Southwest Energy Partners L.P., File No. 001-34032, filed with the SEC on March 31, 2009). | ||
| 10.47 H |
— | Severance Agreement, dated May 19, 2008, between the Company and Frank W. Hall (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-13245). | ||
| 10.48 H |
— | Change in Control Agreement, dated May 19, 2008, between the Company and Frank W. Hall (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-13245). | ||
| 10.49 H |
— | Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.50 H |
— | Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.51 H |
— | Form of Amendment to Change in Control Agreement, dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
146
| 10.52 H |
— | Form of Amendment to Change in Control Agreement, dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.53 H |
— | Form of First Amendment to Performance Unit Award Agreements, dated November 20, 2008 (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.54 H |
— | Amended and Restated Executive Deferred Compensation Plan, effective as of January 1, 2009 (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008). | ||
| 10.55 H |
— | Amendment No. 1 to the Company’s Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245). | ||
| 10.56 H (a) |
— | Amendment No. 2 to the Company’s Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2011. | ||
| 10.57 |
— | Letter Agreement dated March 18, 2009 between the Company and Southeastern Asset Management, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 19, 2009). | ||
| 10.58 H |
— | Form of Performance Unit Award Agreement, dated February 18, 2009, between the Company and Scott D. Sheffield, with respect to awards made under the Company’s 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13245). | ||
| 10.59 H |
— | Form of Nonstatutory Stock Option Agreement, dated February 18, 2009, between the Company and Scott D. Sheffield, with respect to awards made under the Company’s 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13245). | ||
| 10.60 H |
— | Form of Restricted Stock Unit Award Agreement, dated February 18, 2009, between the Company and Frank W. Hall and other officers of the Company, with respect to awards made under the Company’s 2006 Long Term Incentive Plan (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13245). | ||
| 10.61 H |
— | Pioneer Southwest Energy Partners L.P. 2008 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-1 of Pioneer Southwest Energy Partners L.P., Registration No. 333-144868). | ||
| 10.62 H |
— | Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company’s 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13245). | ||
| 10.63 H |
— | Form of Nonstatutory Stock Option Agreement between the Company and Scott D. Sheffield, with respect to awards made under the Company’s 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13245). | ||
| 10.64 H (a) |
— | Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to awards made under the Company’s 2006 Long Term Incentive Plan. | ||
| 21.1 (a) |
— | Subsidiaries of the registrant. | ||
147
| 23.1 (a) |
— | Consent of Ernst & Young LLP. | ||
| 23.2 (a) |
— | Consent of Netherland, Sewell & Associates, Inc. | ||
| 31.1 (a) |
— | Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002. | ||
| 31.2 (a) |
— | Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002. | ||
| 32.1 (b) |
— | Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002. | ||
| 32.2 (b) |
— | Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002. | ||
| 99.1 (a) |
— | Report of Netherland, Sewell & Associates, Inc. | ||
| 101. INS (b) |
— | XBRL Instance Document. | ||
| 101. SCH (b) |
— | XBRL Taxonomy Extension Schema. | ||
| 101. CAL (b) |
— | XBRL Taxonomy Extension Calculation Linkbase Document. | ||
| 101. DEF (b) |
— | XBRL Taxonomy Extension Definition Linkbase Document. | ||
| 101. LAB (b) |
— | XBRL Taxonomy Extension Label Linkbase Document. | ||
| 101. PRE (b) |
— | XBRL Taxonomy Extension Presentation Linkbase Document. | ||
| (a) | Filed herewith. |
| (b) | Furnished herewith. |
| H | Executive Compensation Plan or Arrangement. |
| * | Pursuant to the rules of the Commission, certain of the schedules and similar attachments to the Agreement have not been filed. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request. |
148