EX-99.2 9 d52967exv99w2.htm MANAGEMENT'S DISCUSSION exv99w2
 

Exhibit 99.2
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
     In November 2007, the Company completed the divestiture of its Canadian assets, which are required to be presented as discontinued operations pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”). As a result, the Company has recast the Management’s Discussion and Analysis of Financial Condition and Results of Operations presented in its Annual Report on Form 10-K for the year ended December 31, 2006, to present the results of operations of the Company’s Canadian assets as discontinued operations. In addition, the Company has recast its Consolidated Financial Statements as of December 31, 2006 and 2005, and for each of the years in the three-year period ended December 31, 2006, and the notes thereto, to reflect the Company’s Canadian assets as discontinued operations, and the recast financial statements are included in this report. The following discussion should be read in conjunction with the recast financial statements included herein and the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007, which reflects the classification of the sale of its Canadian assets as discontinued operations.
     Certain terms and conventions used in this Management’s Discussion and Analysis of Financial Condition and Results of Operations are defined in “Definitions of Certain Terms and Conventions Used Herein.”
Strategic Initiatives and Goals
     During 2006, the Company accomplished significant goals underlying the strategic initiatives established in 2005 to enhance shareholder value and investment returns. Together with other important accomplishments, the Company:
  •   Substantially completed a $1 billion share repurchase program, $640.7 million of which was completed during 2005 and $345.3 million of which was completed during 2006
 
  •   Completed the divestiture of the Company’s assets in Argentina for net proceeds of $669.6 million, resulting in a gain of $10.9 million
 
  •   Completed the divestiture of the Company’s assets in the deepwater Gulf of Mexico for net proceeds of $1.2 billion, resulting in a gain of $726.2 million
 
  •   Reduced higher-risk, higher-impact exploration spending to approximately five percent of the total capital spent in 2006
 
  •   Focused capital spending on lower-risk North American onshore development and extension drilling
 
  •   Produced 33.0 MMBOE in 2006 from continuing operations
 
  •   Increased the semiannual dividend to shareholders to $0.13 per share
Financial and Operating Performance
     Pioneer’s financial and operating performance for 2006 included the following highlights:
  •   Average daily sales volumes, on a BOE basis, decreased four percent in 2006 as compared to 2005, primarily due to a 126 percent increase in the delivery of VPP volumes. Excluding the delivery of the VPP volumes in 2006 (5.6 MMBOE) and 2005 (2.5 MMBOE), the Company’s United States production increased approximately four percent, which the Company believes provides a better understanding of the actual results of the Company’s 2006 United States drilling program excluding the increased VPP deliveries.
 
  •   Oil and gas revenues increased nine percent in 2006 as compared to 2005, primarily as a result of increases in worldwide oil and NGL prices.
 
  •   Net income increased 38 percent to $739.7 million ($5.81 per diluted share) in 2006 from $534.6 million ($3.80 per diluted share) in 2005, primarily on the strength of higher oil and NGL prices and gains on the sale of deepwater Gulf of Mexico and Argentine assets.

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  •   Income from continuing operations decreased to $150.2 million ($1.19 per diluted share) for 2006, as compared to $184.3 million ($1.32 per diluted share) for 2005, primarily due to higher exploration and abandonment expenses in 2006.
 
  •   The Company recognized income from discontinued operations of $589.5 million ($4.62 per diluted share) during 2006, primarily attributable to the sale of deepwater Gulf of Mexico and Argentine assets and the 2007 sale of Canadian assets, as compared to income from discontinued operations of $350.3 million ($2.48 per diluted share) during 2005.
 
  •   Outstanding debt decreased to $1.5 billion at December 31, 2006 as compared to $2.1 billion at December 31, 2005, primarily due to the application of sales proceeds from the Company’s divestment of its assets in Argentina and the deepwater Gulf of Mexico.
 
  •   The Company’s debt-to-capitalization was 33 percent at December 31, 2006 as compared to 48 percent at December 31, 2005.
 
  •   Net cash provided by operating activities decreased by $522.3 million, or 41 percent as compared to that of 2005, primarily due to the sale of deepwater Gulf of Mexico and Argentine assets during 2006 and certain Canadian and Gulf of Mexico shelf assets during 2005.
 
  •   The Company added 91 MMBOE of proved reserves during 2006, resulting in total proved reserves of 904.9 MMBOE at December 31, 2006.
2007 Events
     Canadian divestiture. In August 2007, the Company entered into a share purchase agreement for the sale of all of the common stock of its Canadian subsidiaries for cash proceeds of $540 million, subject to normal closing adjustments. During November 2007, the Company completed the divestiture of the common stock of its Canadian subsidiaries. Associated therewith, the Company will report a gain of approximately $100 million during the fourth quarter of 2007, which will be reported in discontinued operations.
     Line of credit. During April 2007, the Company entered into an Amended and Restated 5-Year Revolving Credit Agreement (the “Credit Facility”), as amended, that matures in April 2012 unless extended in accordance with the terms of the Credit Facility. The Credit Facility provides for initial aggregate loan commitments of $1.5 billion, which may be increased to a maximum aggregate amount of $2.0 billion if the lenders increase their loan commitments or if loan commitments of new financial institutions are added.
     Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $150 million. Revolving loans 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 .5 percent or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the “Applicable Margin”) (currently .75 percent) that is determined by a reference grid based on the Company’s debt rating (currently .75 percent). Swing line loans 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, representing the Applicable Margin plus .125 percent.
     The Credit Facility contains certain financial covenants, which include the maintenance of a ratio of total debt to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset impairments not to exceed .60 to 1.0. The covenants also include the maintenance of 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 Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Group, Inc.
     Senior notes. During March 2007, the Company issued $500 million of 6.65% senior notes due 2017 (the “6.65% Notes”) and received proceeds, net of issuance discount and underwriting costs, of $494.9 million. The Company used the net proceeds from the issuance of the 6.65% Notes to reduce indebtedness under its credit facility.

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     East Cameron abandonment estimate. As is further described in Note U of the Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein, the Company’s East Cameron facility, located on the Gulf of Mexico shelf, was destroyed as a result of Hurricane Rita in 2005. During 2007, the operations to reclaim and abandon the East Cameron facility began. The estimate to reclaim and abandon the East Cameron facility contains a number of assumptions that could cause the ultimate cost to be higher or lower than estimated because there are many uncertainties when working offshore and underwater with damaged equipment and wellbores. During the nine months ended September 30, 2007, the Company recorded additional abandonment charges of $66.0 million to increase its estimate of the costs to reclaim and abandon the East Cameron facility, which increased the estimate to reclaim and abandon the East Cameron facility to $185 million. In the third quarter of 2007, the Company commenced legal actions against certain of its insurance carriers regarding policy coverage issues. However, the Company continues to expect that a substantial portion of the loss will be recoverable from insurance.
     Clipper exploratory well costs. As is further described in Note D of the Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein, during 2005, the Company announced a discovery on the Clipper prospect in the deepwater Gulf of Mexico. During 2006, the Company drilled two appraisal wells and began evaluating plans for potential development of the discovery. Projected capital costs for the project have doubled since the evaluation began. As a result, during the fourth quarter of 2007, a determination was made by the Company that no further activities would be pursued to develop the project. Accordingly, the Company recorded a charge to earnings in the fourth quarter of 2007 of approximately $71 million. As disclosed in Note D of the Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein, the Company had capitalized costs of $75.2 million attributable to the Clipper prospect as of December 31, 2006.
     Tunisia — Anaguid. During 2007, the Company concluded the remaining studies on the appraisal well that was originally drilled in 2003, as discussed in Note D of the Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein, and determined the well was not economical. Accordingly, the Company recorded a charge of $5.1 million in the second quarter of 2007.
     Nigerian impairment. In June 2007, the Company entered into an agreement to divest its interest in a subsidiary (owned 59 percent by the Company, the “Nigeria Subsidiary”) that held an interest in the deepwater Nigerian Block 320. The agreement was subject to governmental approval. The governmental approval was not obtained by the deadline and as a result, Pioneer terminated the agreement. Based on the terms of the agreement, which established the Company’s estimate of fair value, the Company recorded a $12.2 million impairment charge in the second quarter of 2007 to reduce the net basis to the estimated fair value. Also, as a result of due diligence efforts that emerged as part of the Company’s compliance efforts, and with assistance from outside counsel, the Company determined that it could not, consistent with its legal obligations, fund or approve future operations in connection with Block 320. As a result, during the third quarter of 2007, the Company engaged in a process to withdraw from the production sharing contract relating to Block 320 and related agreements. As a part of this process the Company disposed of its shares in the Nigeria Subsidiary to an unaffiliated third party. As a result ,the Company no longer owns any interest in the Nigeria Subsidiary or Block 320 and will not fund or participate in any future operations in connection with Block 320, and associated therewith the Company recorded a reduction of $2.6 million to the previous impairment charge.
     United States impairment. During the nine months ended September 30, 2007, the Company recorded a $5.7 million impairment provision to reduce the carrying values of certain proved oil and gas properties located in Louisiana. The impairment provision was determined in accordance with SFAS 144, and reduced the carrying values of the assets to their estimated fair value.
     Equatorial Guinea. During the fourth quarter of 2007, the Company recorded a charge of approximately $11 million to write-off the Company’s remaining basis in Block H in Equatorial Guinea. This charge was recorded in the context of the ongoing arbitration among the parties participating in Block H.
     2007 Significant Acquisitions. In July 2007, the Company entered into an agreement under which the Company has the option to purchase an additional 22 percent interest in the Spraberry Midkiff-Benedum gas processing system for $230 million, subject to normal closing adjustments. The additional 22 percent interest can be purchased in increments in 2008 and 2009 and, if exercised, will increase the Company’s interest in the system to 49 percent. In conjunction with this transaction, the Company extended its percent of proceeds (“POP”) contract with the plant to 2022 and negotiated incremental increases in the Company’s POP beginning in 2009.

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     In July 2007, the Company entered into an agreement to acquire an interest in approximately 44,000 gross acres of proved and unproved properties in the Spraberry field in West Texas for $90 million, subject to normal closing adjustments. Pioneer will operate the acquired properties. The acquisition closed during the fourth quarter of 2007. Currently, proved reserves associated with the acquisition are approximately 15 MMBOE. The Company estimates that the acquisition provides more than 600 potential drilling locations utilizing 40-acre spacing.
     In July 2007, the Company entered into an agreement to acquire an interest in approximately 30,000 net acres of proved and unproved properties in the Raton Basin for $205 million, subject to normal closing adjustments. The acquired interest has approximately 95 Bcf of proved reserves. The acquisition closed during the fourth quarter of 2007.
     In November 2007, the Company agreed to acquire an interest in approximately 74,000 gross acres of proved and unproved properties in the Barnett Shale play for $150 million, subject to normal closing adjustments. The acquisition closed during the fourth quarter of 2007. The Company estimates proved reserves on the acreage to be approximately 81 BCFE. The acreage being acquired contains more than 300 potential drilling locations, with most locations covered by 3-D seismic data.
     Master Limited Partnership IPO. On January 8, 2008, Pioneer Southwest Energy Partners L.P. (“Pioneer Southwest”), a subsidiary of the Company, filed an amendment to its registration statement (subject to completion) with the SEC to sell limited partner interests. Pioneer Southwest will own interests in certain oil and gas properties currently owned by the Company in the Spraberry field in the Permian Basin of West Texas. Pioneer Southwest anticipates offering 7,500,000 common units in the initial public offering representing a 35.3 percent limited partner interest in Pioneer Southwest. Upon completion of this offering, the Company will own a 0.1 percent general partner interest and a 64.6 percent limited partner interest in Pioneer Southwest. The underwriters are expected to be granted a 30-day option to purchase up to 1,125,000 additional common units. The Company’s limited partner interest would be reduced to 61.4 percent if the underwriters exercise their over-allotment option in full. Assuming an initial public offering price of $20.00 per common unit and that the underwriters do not exercise their over-allotment option, estimated gross proceeds from the offering would be $150 million. The Company expects to close the offering of the limited partner interests in the first quarter of 2008, and the Company expects that it will consolidate Pioneer Southwest into its financial statements and reflect the public ownership as minority interest.
     In October 2007, Pioneer Southwest entered into a $300 million unsecured revolving credit facility (“PSE Credit Agreement”), as amended, with a syndicate of banks which will mature 5 years following the closing of the offering of the limited partner interests in Pioneer Southwest. The closing of the public offering of Pioneer Southwest’s limited partner interests is a condition to the obligation of the lenders to make loans under the PSE Credit Agreement.
     The PSE Credit Agreement contains certain financial covenants applicable to Pioneer Southwest, which include (i) the maintenance of a maximum leverage ratio of not more than 3.5 to 1.0, (ii) an interest coverage ratio (representing a ratio of EBITDAX 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 oil and gas assets to total debt of at least 1.75 to 1.0. Because of the net present value covenant, borrowings under the PSE Credit Agreement are expected to be initially limited to approximately $150 million.
     This shall not constitute an offer to sell or the solicitation of an offer to buy any securities of Pioneer Southwest. Any offers, solicitations of offers to buy, or any sales of securities of Pioneer Southwest will be made only in accordance with the registration requirements of the Securities Act of 1933 or an exemption therefrom.
     2008 Capital Budgets. On December 19, 2007, the Company announced that its board of directors approved a 2008 capital budget of $1 billion (which excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs), down significantly from comparable 2007 capital spending. The decrease primarily relates to the completion of facilities construction for its South Coast Gas project off the coast of South Africa and its Oooguruk project on the North Slope of Alaska, the sale of all our Canadian assets and the elimination of higher-risk exploration. Using current strip prices for oil and gas, the Company anticipates that its 2008 capital budget will approximate its 2008 cash flow from operating activities.
     Share Repurchase Program. The Company’s board of directors approved a share repurchase program for $750 million of the Company’s common stock. Through September 30, 2007, the Company had repurchased approximately $207.8 million of common stock under this program.

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Future Commodity Prices
     Significant factors that may impact future commodity prices include developments in the issues currently impacting Iraq and Iran and the Middle East in general; the extent to which members of the OPEC and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of increasing LNG deliveries to the United States. Although the Company cannot predict the occurrence of events that may affect future 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. Pioneer will continue to strategically hedge a portion of its oil and gas price risk to mitigate the impact of price volatility on its oil, NGL and gas revenues.
Historical Acquisitions
     2006 acquisition expenditures. During 2006, the Company spent approximately $223.2 million to acquire proved and unproved properties, which was comprised of approximately $144.8 million of proved properties and $78.3 million of unproved properties. The proved properties were primarily bolt-on and acreage acquisitions in the Spraberry field and Edwards Trend area. In North America, the acquisition of unproved properties is comprised of acreage acquisitions in the Spraberry field, Edwards Trend area, Rockies area, Alaska and Canada. The Company also acquired an additional interest in its Jenein Nord block in Tunisia and recognized additional obligations associated with its Nigerian prospects during 2006.
     2005 acquisition expenditures. During 2005, the Company spent approximately $272.9 million to acquire proved and unproved properties. In July 2005, the Company completed the acquisition of approximately 70 MMBOE of substantially proved undeveloped oil reserves in the United States core areas of the Permian Basin and South Texas for $170.7 million.
     2004 Evergreen merger. During 2004, the Company spent approximately 2.6 billion to acquire proved and unproved properties. On September 28, 2004, Pioneer completed a merger with Evergreen Resources, Inc. (“Evergreen”). Pioneer acquired the common stock of Evergreen for a total purchase price of approximately $1.8 billion, which was comprised of cash and Pioneer common stock.
Historical Divestitures
     Argentina and Deepwater Gulf of Mexico. During March 2006, the Company sold its interests in certain oil and gas properties in the deepwater Gulf of Mexico for net proceeds of $1.2 billion, resulting in a gain of $726.2 million. During April 2006, the Company sold its Argentine assets for net proceeds of $669.6 million, resulting in a gain of $10.9 million. The historic results of these properties and the related gains on disposition are reported as discontinued operations.
     Volumetric production payments. During January 2005, the Company sold 20.5 MMBOE of proved reserves in the Hugoton and Spraberry fields, by means of two VPPs for net proceeds of $592.3 million, including the assignment of the Company’s obligations under certain derivative hedge agreements.
     During April 2005, the Company sold 7.3 MMBOE of proved reserves in the Spraberry field, by means of a VPP for net proceeds of $300.3 million, including the value attributable to certain derivative hedge agreements assigned to the buyer of the April VPP.
     The Company’s VPPs represent limited-term overriding royalty interests in oil and gas reserves which: (i) entitle the purchaser to receive production volumes over a period of time from specific lease interests; (ii) are free and clear of all associated future production costs and capital expenditures; (iii) are nonrecourse to the Company (i.e., the purchaser’s only recourse is to the assets acquired); (iv) transfers title of the assets to the purchaser and (v) allows the Company to retain the assets after the VPPs volumetric quantities have been delivered.
     Canada and Shelf Gulf of Mexico. During 2005, the Company sold its interests in the Martin Creek and Conroy Black areas of northeast British Columbia and the Lookout Butte area of southern Alberta for net proceeds of $197.2 million, resulting in a gain of $138.3 million. During 2005, the Company also sold all of its interests in certain oil and gas properties on the Gulf of Mexico shelf for net proceeds of $59.2 million, resulting in a gain of $27.9 million. The historic results of these properties and the related gains on disposition are reported as discontinued operations.

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     Gabon divestiture. In 2005, the Company closed the sale of the shares in a Gabonese subsidiary that owns the interest in the Olowi block for $47.9 million of net proceeds, resulting in a gain of $47.5 million with no associated income tax effect either in Gabon or the United States.
2006 Costs Incurred
     The following table summarizes by geographic area the Company’s costs incurred during 2006:
                                                 
    Property                     Asset        
    Acquisition Costs     Exploration     Development     Retirement        
    Proved     Unproved     Costs     Costs     Obligations     Total  
                    (in thousands)                  
Permian Basin
   $ 51,421     $ 30,703     $ 12,411     $ 285,980     $ 1,884     $ 382,399  
Mid-Continent
     133       —       156       35,759       2,650       38,698  
Rocky Mountains
     1,240       17,495       64,924       170,863       9,561       264,083  
Gulf of Mexico:
                                                
Continuing operations
     —       8       94,167       5,045       6,028       105,248  
Discontinued operations
     —       2       3,808       3,167       —       6,977  
Onshore Gulf Coast
     19,743       33,157       82,775       61,705       1,396       198,776  
Alaska
     4,800       27,956       34,684       119,309 (a)     1,350       188,099  
 
                                    
Total United States
   $ 77,337     $ 109,321     $ 292,925     $ 681,828     $ 22,869     $ 1,184,280  
 
                                    
 
                                                
Argentina—discontinued operations
     —       2       10,223       25,542       —       35,767  
Canada—discontinued operations
     —       19,932       103,245       97,188       8,299       228,664  
South Africa
     —       —       288       117,511 (a)     13,964       131,763  
Tunisia
     —       5,000       40,813       —       336       46,149  
Other
     —       —       11,358       —       —       11,358  
West Africa:
                                                
Equatorial Guinea
     —       —       (1,688 )     —       —       (1,688 )
Nigeria
     —       10,584       26,502       —       —       37,086  
 
                                    
Total International
     —       35,518       190,741       240,241       22,599       489,099  
 
                                    
 
                                                
Grand Total
   $ 77,337     $ 144,839     $ 483,666     $ 922,069     $ 45,468     $ 1,673,379  
 
                                    
 
(a)   Alaska development costs includes $6.8 million of capitalized interest related to the Oooguruk project and South Africa development costs includes $5.3 million of capitalized interest related to the South Coast Gas project.
Results of Operations
     Oil and gas revenues. Oil and gas revenues totaled $1.5 billion, $1.3 billion and $1.0 billion during 2006, 2005 and 2004, respectively. The revenue increase during 2006, as compared to 2005, was due to a 70 percent increase in reported oil prices, including the effects of commodity price hedges and VPP deliveries, and an 11 percent increase in NGL prices. Partially offsetting the effects of increased oil and NGL prices was an 11 percent decrease in reported gas prices, including the effects of commodity price hedges and VPP deliveries, and a four percent decrease in average daily sales volumes on a BOE basis. The revenue increase during 2005, as compared to 2004, was due to a 19 percent increase in reported oil prices, a 27 percent increase in NGL prices and a 39 percent increase in reported gas prices, including the effects of commodity price hedges and VPP deliveries, along with increased production in 2005 on a BOE basis.
     A significant factor contributing to the increases in reported oil prices and decreases in reported oil sales volumes in 2006 as compared to 2005 was the initiation of first deliveries of oil volumes under the Company’s VPP agreements in January 2006. Similarly, reported gas prices and decreases in gas sales volumes in 2006 and 2005 as compared to 2004 were impacted by the initiation of first deliveries of gas volumes under the Company’s VPP agreements during the first half of 2005 offset by the decline in underlying gas prices. In accordance with GAAP, VPP deliveries result in VPP deferred revenue amortization being recognized in oil and gas revenues with no associated sales volumes being recorded.

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     The following table provides average daily sales volumes from continuing operations, including the effects of delivery of the VPP volumes, by geographic area and in total, for 2006, 2005 and 2004:
                         
    Year Ended December 31,
    2006   2005   2004
Oil (Bbls):
                        
United States
     17,716       21,942       21,863  
South Africa
     4,127       6,588       9,368  
Tunisia
     2,386       3,477       2,308  
 
                        
Worldwide
     24,229       32,007       33,539  
 
                        
NGLs (Bbls):
                        
United States
     18,488       17,403       19,678  
 
                        
Gas (Mcf):
                        
United States
     284,732       271,033       209,371  
South Africa
     —       —       —  
Tunisia
     1,195       —       —  
 
                        
Worldwide
     285,927       271,033       209,371  
 
                        
Total (BOE):
                        
United States
     83,659       84,517       76,437  
South Africa
     4,127       6,588       9,368  
Tunisia
     2,585       3,477       2,308  
 
                        
Worldwide
     90,371       94,582       88,113  
 
                        
     On a BOE basis, average daily production for 2006, as compared to 2005, decreased by one percent in the United States and by 33 percent in Africa. Average daily per BOE production for 2005, as compared to 2004, increased by 11 percent in the United States and decreased by 14 percent in Africa.
     Average daily production in the United States was slightly lower during 2006, as compared to 2005, primarily due to a 126 percent increase in VPP oil and gas deliveries on a BOE basis, partially offset by accelerated development drilling in core areas. The increase in United States production volumes during 2005, as compared to 2004, was primarily due to production from properties acquired in the Evergreen merger, partially offset by first deliveries of VPP gas volumes during 2005.
     Production declined in Africa during 2006 and 2005 primarily due to (i) normal production declines from producing properties in South Africa and Tunisia, partially offset by drilling success in Tunisia and (ii) the Company’s interest in the Adam Concession in Tunisia being reduced in 2006 from 24 percent to 20 percent in accordance with the terms of the concession agreement. In Tunisia, the Company recorded gas sales volumes and revenue for the first time after finalizing a gas sales arrangement during 2006.

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     The following table provides average daily sales volumes from discontinued operations during 2006, 2005 and 2004:
                         
    Year Ended December 31,
    2006   2005   2004
Oil (Bbls):
                        
United States
     2,400       5,280       4,774  
Argentina
     2,515       7,869       8,534  
Canada
     311       238       137  
 
                        
Worldwide
     5,226       13,387       13,445  
 
                        
NGLs (Bbls):
                        
United States
     —       65       60  
Argentina
     421       1,824       1,546  
Canada
     463       615       917  
 
                        
Worldwide
     884       2,504       2,523  
 
                        
Gas (Mcf):
                        
United States
     36,038       230,171       312,468  
Argentina
     43,905       137,032       121,654  
Canada
     43,434       42,916       41,867  
 
                        
Worldwide
     123,377       410,119       475,989  
 
                        
Total (BOE):
                        
United States
     8,406       43,707       56,912  
Argentina
     10,253       32,531       30,356  
Canada
     8,013       8,005       8,031  
 
                        
Worldwide
     26,672       84,243       95,299  
 
                        
     The following table provides average reported prices from continuing operations, including the results of hedging activities and the amortization of VPP deferred revenue, and average realized prices from continuing operations, excluding the results of hedging activities and the amortization of VPP deferred revenue, by geographic area and in total, for 2006, 2005 and 2004:
                         
    Year Ended December 31,
    2006   2005   2004
Average reported prices:
                        
Oil (per Bbl):
                        
United States
   $ 65.73     $ 32.01     $ 29.53  
South Africa
   $ 65.92     $ 53.01     $ 37.87  
Tunisia
   $ 63.16     $ 52.98     $ 39.14  
Worldwide
   $ 65.51     $ 38.61     $ 32.52  
NGL (per Bbl):
                        
United States
   $ 35.24     $ 31.72     $ 25.05  
Gas (per Mcf):
                        
United States
   $ 6.15     $ 6.94     $ 4.99  
Tunisia
   $ 5.97     $ —     $ —  
Worldwide
   $ 6.15     $ 6.94     $ 4.99  
Total (per BOE):
                        
United States
   $ 42.64     $ 37.09     $ 28.57  
South Africa
   $ 65.92     $ 53.01     $ 37.87  
Tunisia
   $ 61.05     $ 52.98     $ 39.14  
Worldwide
   $ 44.23     $ 38.78     $ 29.84  
Average realized prices:
                        
Oil (per Bbl):
                        
United States
   $ 62.92     $ 54.05     $ 39.22  
South Africa
   $ 65.74     $ 53.01     $ 38.60  
Tunisia
   $ 63.16     $ 52.98     $ 39.14  
Worldwide
   $ 63.42     $ 53.72     $ 39.04  
NGL (per Bbl):
                        
United States
   $ 35.24     $ 31.72     $ 25.05  
Gas (per Mcf):
                        
United States
   $ 5.96     $ 7.26     $ 5.46  
Tunisia
   $ 5.97     $ —     $ —  
Worldwide
   $ 5.96     $ 7.26     $ 5.46  
Total (per BOE):
                        
United States
   $ 41.37     $ 43.86     $ 32.62  
South Africa
   $ 65.74     $ 53.01     $ 37.87  
Tunisia
   $ 61.05     $ 52.98     $ 39.14  
Worldwide
   $ 43.04     $ 44.84     $ 33.35  

8

 

     Hedging activities. The Company, from time to time, utilizes commodity swap and collar contracts in order to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. During 2006, 2005 and 2004, the Company’s commodity price hedges decreased oil and gas revenues from continuing operations by $151.2 million, $284.8 million and $115.7 million, respectively. The effective portions of changes in the fair values of the Company’s commodity price hedges are deferred as increases or decreases to stockholders’ equity until the underlying hedged transaction occurs. Consequently, changes in the effective portions of commodity price hedges add volatility to the Company’s reported stockholders’ equity until the hedge derivative matures or is terminated. See Note J of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for information concerning the impact to oil and gas revenues during 2006, 2005 and 2004 from the Company’s hedging activities.
     Deferred revenue. During 2006 and 2005, the Company’s recognition of previously deferred VPP revenue increased oil and gas revenues from continuing operations by $190.3 million and $75.8 million, respectively. The Company’s amortization of deferred VPP revenue is scheduled to increase 2007 oil and gas revenues by $181.2 million. See Note T of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for specific information regarding the Company’s VPPs.
     Interest and other income. The Company’s interest and other income totaled $48.4 million, $26.5 million and $1.8 million during 2006, 2005 and 2004, respectively. The $21.9 million increase during 2006, as compared to 2005, is primarily attributable to (i) a $12.9 million increase in interest income primarily attributable to the investing the proceeds from the Argentine and deepwater Gulf of Mexico divestitures during 2006, (ii) $7.4 million of hedge ineffectiveness gains recorded during 2006 and (iii) $5.6 million of Alaskan exploration incentive credits received in 2006, offset by (iv) a $6.6 million decrease in business interruption insurance claims primarily attributable to the 2005 Fain plant fire in the West Panhandle field. The increase in interest and other income during 2005, as compared to 2004, is primarily attributable to the recognition of $14.2 million in business interruption insurance claims related to the Fain plant fire. See Note M of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding interest and other income.
     Gain (loss) on disposition of assets. The Company recorded a net loss on disposition of assets of $6.5 million in 2006, as compared to net gains of $60.1 million and $292 thousand during 2005 and 2004, respectively.
     In 2005, the gain was primarily related to (i) the sale of the stock of a subsidiary that owned the interest in the Olowi block in Gabon, which resulted in a $47.5 million gain and (ii) a $14 million insurance settlement on the Company’s East Cameron facility that was destroyed by Hurricane Rita, which resulted in a $9.7 million gain.
     During 2006, the Company recognized gains on the sale of its interest in certain oil and gas properties in the deepwater Gulf of Mexico and its Argentina assets of approximately $737.1 million. During 2005, the Company also recognized gains on the sale of certain assets in Canada and the shelf of the Gulf of Mexico of approximately $166.2 million. However, pursuant to SFAS 144, these gains and the results of operations from the assets are presented as discontinued operations.
     The net cash proceeds from asset divestitures during 2006, 2005 and 2004 were used, together with net cash flows provided by operating activities, to fund additions to oil and gas properties and stock repurchase programs, and to reduce outstanding indebtedness. See Notes N and V of Notes to Consolidated Financial Statements in the Financial Statements and Supplementary Data included herein for additional information regarding asset divestitures.
     Oil and gas production costs. The Company’s oil and gas production costs totaled $349.1 million, $309.7 million and $206.1 million during 2006, 2005 and 2004, respectively. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Company has management control, while production taxes and ad valorem taxes are directly related to commodity price changes. Total production costs per BOE increased during 2006 by 18 percent as compared to 2005 primarily due to (i) the impact of a 126 percent increase in delivered volumes under VPP agreements, for which the Company bears all associated production costs and records no associated sales volumes (representing a per BOE production cost impact of approximately $1.50 during 2006 as compared to $.59 during 2005), (ii) general inflation of field service and supply costs and (iii) increases in production and ad valorem taxes and field utility costs due to increasing commodity and utility prices.

9

 

     Total production costs per BOE increased during 2005 by 40 percent as compared to 2004. The increase in total production costs per BOE during 2005 as compared to 2004 was primarily attributable to (i) increases in production and ad valorem taxes as a result of higher commodity prices, (ii) the retention of production costs related to VPP volumes sold (approximately $.59 per BOE, during 2005), (iii) new production added from the Evergreen merger, which are relatively higher per BOE operating cost properties and (iv) increases in field service and supply costs primarily associated with rising commodity prices.
     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 2006, 2005 and 2004:
                         
    Year Ended December 31,  
    2006     2005     2004  
Lease operating expenses
   $ 5.94     $ 4.95     $ 3.82  
Third-party transportation charges
     .79       .64       .20  
Taxes:
                        
Ad valorem
     1.35       1.17       .86  
Production
     1.84       1.73       1.15  
Workover costs
     .66       .48       .36  
 
                  
Total production costs
   $ 10.58     $ 8.97     $ 6.39  
 
                  
                         
    Year Ended December 31,
    2006   2005   2004
United States
   $ 10.61     $ 8.99     $ 6.24  
South Africa
   $ 14.47     $ 11.79     $ 8.31  
Tunisia
   $ 3.41     $ 3.20     $ 3.59  
Worldwide
   $ 10.58     $ 8.97     $ 6.39  
     Depletion, depreciation and amortization expense. The Company’s total DD&A expense from continuing operations was $9.52, $7.76 and $6.46 per BOE for 2006, 2005 and 2004, respectively. Depletion expense from continuing operations, the largest component of DD&A expense, was $8.80, $7.19 and $6.11 per BOE during 2006, 2005 and 2004, respectively. During 2006, the increase in per BOE depletion expense was primarily due to (i) a generally increasing trend 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, (ii) the aforementioned sale of proved reserves under VPP agreements, for which the Company removed proved reserves with no corresponding decrease in cost basis, (iii) a $.50 per BOE increase in Tunisian depletion, primarily associated with 2006 and 2005 decreases in the Company’s interest in the Adam Concession, offset by (iv) a $3.91 per BOE decrease in South Africa depletion, primarily associated with 2006 and 2005 positive revisions to proved reserves based on well performance.
     During 2005, the increase in per BOE depletion expense was due to relatively higher per BOE cost basis Rocky Mountains area production acquired in the Evergreen merger and a higher depletion rate for the Hugoton and Spraberry fields as a result of the VPP volumes sold.
     The following table provides depletion expense per BOE from continuing operations by geographic area for 2006, 2005 and 2004:
                         
    Year Ended December 31,
    2006   2005   2004
United States
   $ 9.07     $ 7.10     $ 5.34  
South Africa
   $ 6.28     $ 10.19     $ 12.86  
Tunisia
   $ 4.25     $ 3.75     $ 4.43  
Worldwide
   $ 8.80     $ 7.19     $ 6.11  
     Impairment of oil and gas properties. The Company reviews its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. During 2005 and 2004, the Company recognized noncash impairment charges of $644 thousand and $39.7 million, respectively, to reduce the carrying value of its Gabonese Olowi field assets as development of the discovery was canceled. See “Critical Accounting Estimates” below and Notes B and S of Notes to Consolidated Financial

10

 

Statements included in the Financial Statements and Supplementary Data included herein for additional information pertaining to the Company’s accounting policies regarding assessments of impairment and the Gabonese Olowi field impairment, respectively.
     Exploration, abandonments, geological and geophysical costs. The following table provides the Company’s geological and geophysical costs, exploratory dry hole expense, lease abandonments and other exploration expense by geographic area for 2006, 2005 and 2004 (in thousands):
                                         
    United     South                    
    States     Africa     Tunisia     Other     Total  
Year ended December 31, 2006:
                                        
Geological and geophysical
   $ 79,140     $ 289     $ 8,402     $ 21,536     $ 109,367  
Exploratory dry holes
     80,023       7,227       6,214       15,845       109,309  
Leasehold abandonments and other
     13,696       —       —       17,824       31,520  
 
                              
 
   $ 172,859     $ 7,516     $ 14,616     $ 55,205     $ 250,196  
 
                              
 
                                        
Year ended December 31, 2005:
                                        
Geological and geophysical
   $ 63,707     $ 282     $ 1,857     $ 32,214     $ 98,060  
Exploratory dry holes
     24,462       804       9,041       9,135       43,442  
Leasehold abandonments and other
     8,957       125       —       3,195       12,277  
 
                              
 
   $ 97,126     $ 1,211     $ 10,898     $ 44,544     $ 153,779  
 
                              
 
                                        
Year ended December 31, 2004:
                                        
Geological and geophysical
   $ 49,722     $ 868     $ 2,042     $ 11,923     $ 64,555  
Exploratory dry holes
     1,150       (338 )     —       24,798       25,610  
Leasehold abandonments and other
     4,138       —       —       6       4,144  
 
                              
 
   $ 55,010     $ 530     $ 2,042     $ 36,727     $ 94,309  
 
                              
     During 2006, significant components of the Company’s dry hole provisions and leasehold abandonments expense included (i) $34.0 million of costs associated with the Company’s unsuccessful exploratory well on its Block 256 prospect offshore Nigeria, including $17.8 million of associated unproved leasehold impairment, (ii) $21.6 million of dry hole provisions recorded for the Company’s unsuccessful Cronus, Storms and Antigua prospects in the North Slope area of Alaska, (iii) $16.9 million of dry hole provisions and abandonment costs recognized on prospects drilled in prior periods that were being evaluated for commerciality, including $7.2 million of costs associated with the Company’s Boomslang prospect offshore South Africa, $5.5 million of costs associated with two discoveries on the Gulf of Mexico shelf in 2005 and $4.2 million of costs associated with the Company’s Anaguid permit in Tunisia, (iv) $16.0 million of dry hole provision and unproved property impairment recognized on the Company’s unsuccessful Norphlet prospect in Mississippi and (v) a $14.3 million unsuccessful well on the Company’s Flying Cloud prospect in the Gulf of Mexico. During 2006, the Company completed and evaluated 414 exploration/extension wells, 384 of which were successfully completed as discoveries.
     Significant components of the Company’s dry hole expense during 2005 included (i) $21.2 million related to Alaskan well costs, (ii) $9.5 million associated with an unsuccessful Nigerian well, (iii) $3.5 million attributable to an unsuccessful suspended well in the Company’s El Hamra permit in Tunisia, (iv) $5.1 million attributable to an unsuccessful suspended well in the Company’s Anaguid permit in Tunisia and (v) various other exploratory wells. During 2005, the Company completed and evaluated 180 exploratory/extension wells, 149 of which were successfully completed as discoveries.
     Significant components of the Company’s dry hole expense during 2004 included (i) $19.0 million on the Company’s Gabonese Olowi prospect and (ii) $5.8 million associated with the Company’s Bravo prospect offshore Equatorial Guinea. During 2004, the Company completed and evaluated 103 exploratory/extension wells, 58 of which were successfully completed as discoveries.
     General and administrative expense. General and administrative expense totaled $116.6 million, $110.1 million and $69.5 million during 2006, 2005 and 2004, respectively. The increase in general and administrative expense during 2006, as compared to 2005, was primarily due to a full year effect of the 2005 staff increases associated with the Evergreen acquisition. The Company continues to review its general and administrative expenses and remains focused on initiatives to control its expenditures.
     The increase in general and administrative expense during 2005, as compared to 2004, was primarily due to increases in administrative staff, including staff increases associated with the Evergreen merger, and performance-related compensation costs, including the amortization of restricted stock awarded to officers, directors and employees during 2005.

11

 

     Interest expense. Interest expense was $107.1 million, $126.0 million and $102.0 million during 2006, 2005 and 2004, respectively. The weighted average interest rate on the Company’s indebtedness for the year ended December 31, 2006 was 6.7 percent, as compared to 6.5 percent and 5.4 percent for the years ended December 31, 2005 and 2004, respectively, including the effects of interest rate derivatives. The decrease in interest expense for 2006 as compared to 2005 was primarily due to the repayment of portions of the Company’s outstanding borrowings under the Company’s credit facility with proceeds from the divestiture of the deepwater Gulf of Mexico and Argentine assets and an $11.1 million increase in interest capitalized on the Company’s Oooguruk development project in Alaska and the South Coast Gas project in South Africa, partially offset by a $4.1 million decrease in the amortization of interest rate hedge gains.
     The increase in interest expense for 2005 as compared to 2004 was primarily due to increased average borrowings under the Company’s lines of credit, primarily as a result of the cash portion of the consideration paid in the Evergreen merger and $949.3 million of stock repurchases completed during 2005, a $15.2 million decrease in the amortization of interest rate hedge gains, the assumption of $300 million of notes in connection with the Evergreen merger and higher interest rates in 2005.
     See Note F of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information about the Company’s long-term debt and interest expense.
     Hurricane activity, net. The Company recorded net hurricane related activity expenses of $32.0 million and $39.8 million during 2006 and 2005, respectively, associated with the Company’s East Cameron platform facility, located on the Gulf of Mexico shelf, that was destroyed during 2005 by Hurricane Rita.
     The Company does not plan to rebuild the facility based on the economics of the field. During the fourth quarter of 2006, the Company’s application to “reef in-place” a substantial portion of the East Cameron debris was denied. As a result, as of December 31, 2006, the Company estimated that it would cost approximately $119 million to reclaim and abandon the East Cameron facility. Estimates to reclaim and abandon the East Cameron facility were based upon an analysis and fee proposal prepared by a third-party engineering firm for the majority of the work and an estimate by the Company for the remainder. During 2006 and 2005, the Company recorded additional abandonment obligation charges of $75 million and $39.8 million, respectively. The operations to reclaim and abandon the East Cameron facilities began in January 2007 and the Company expects to incur a substantial portion of the costs in 2007. The Company expects that a substantial portion of the total estimated cost to reclaim and abandon the facility will be covered by insurance, including 100 percent of the debris removal costs. Consequently, the Company has recorded a $43.0 million insurance recovery receivable corresponding to the estimated debris removal costs.
     See “2007 Events” for information regarding 2007 developments pertaining to the Company’s reclamation and abandonment of the East Cameron facilities.
     Other expenses. Other expenses were $36.9 million during 2006, as compared to $80.7 million during 2005 and $25.6 million during 2004. The $43.8 million decrease in other expenses during 2006, as compared to 2005, is primarily attributable to (i) a $40.4 million decrease in hedge ineffectiveness charges and (ii) a $17.9 million decrease in loss on early extinguishment of portions of the Company’s senior notes, partially offset by (iii) a $4.4 million increase in bad debt expense, (iv) a $4.0 million insurance charge, (v) a $2.7 million increase in non-hedge derivative charges and (vi) $3.4 million of other net increases in other expense components.
     The $55.1 million increase in other expenses during 2005, as compared to 2004, is primarily attributable to (i) a $26.0 million loss on the redemption and tender of portions of the Company’s senior notes, (ii) a $25.7 million increase in hedge ineffectiveness charges and (iii) a $3.9 million increase in non-hedge derivative charges. See Note O of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for a detailed description of the components included in other expenses.

12

 

     Income tax provision. The Company recognized income tax provisions on continuing operations of $141.0 million, $149.2 million and $62.1 million during 2006, 2005 and 2004, respectively. The Company’s effective tax rates for 2006, 2005 and 2004 were 48.4 percent, 44.7 percent and 28.8 percent, respectively, as compared to the combined United States federal and state statutory rates of approximately 36.5 percent. The effective tax rates of 2006 and 2005 differ from the combined United States federal and state statutory rates primarily due to:
  •   foreign tax rates,
 
  •   adjustments to the deferred tax liability for changes in enacted tax laws and rates, as discussed below,
 
  •   statutes in foreign jurisdictions that differ from those in the United States,
 
  •   recognition of $8.4 million of deferred tax benefit during 2006 as a result of the conversion of senior convertible notes prior to the Company’s repayment of the debt principal,
 
  •   recognition of $7.2 million of taxes during 2005 associated with the repatriation of foreign earnings pursuant to the American Jobs Creation Act of 2004 and
 
  •   expenses for unsuccessful well costs and associated acreage costs in foreign locations where the Company does not expect to receive income tax benefits.
     During May 2006, the State of Texas enacted legislation that changed the existing Texas franchise tax from a tax based on net income or taxable capital to an income tax based on a defined calculation of gross margin (the “Texas margin tax”). Also, during 2006, the Canadian federal and provincial governments enacted tax rate reductions that will be phased in over several years. SFAS No. 109, “Accounting for Income Taxes” requires that deferred tax balances be adjusted to reflect tax rate changes during the periods in which the tax rate changes are enacted. The adjustment due to the enactment of the Texas margin tax and the Canadian tax rate changes resulted in a $13.5 million United States tax expense and a $10.2 million Canadian tax benefit, which, for Canada, is reflected in income from discontinued operations, net of tax, during the year ended December 31, 2006, respectively.
     See “Critical Accounting Estimates” below and Note P of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s tax position.
     Discontinued operations. During 2005, 2006 and 2007, the Company sold its interests in the following oil and gas asset groups:
         
Country   Description of Asset Groups   Date Divested
Canada
  Martin Creek, Conroy Black and Lookout Butte fields   May 2005
 
        
United States
  Two Gulf of Mexico shelf fields   August 2005
 
        
United States
  Deepwater Gulf of Mexico fields   March 2006
 
        
Argentina
  Argentine assets   April 2006
 
        
Canada
  Canadian assets   November 2007
     The Company recognized income from discontinued operations of $589.5 million during 2006, as compared to $350.3 million during 2005 and $159.7 million during 2004. Pursuant to SFAS 144, the results of operations of these properties and the related gains on disposition are reported as discontinued operations. See Notes V and W of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional data on discontinued operations.
Capital Commitments, Capital Resources and Liquidity
     Capital commitments. The Company’s primary needs for cash are for exploration, development and acquisition of oil and gas properties, repayment of contractual obligations and working capital obligations. Funding for exploration, development and acquisition of oil and gas properties and repayment of contractual obligations may be provided by any combination of internally-generated cash flow, proceeds from the disposition of nonstrategic assets or alternative financing sources as discussed in “Capital resources” and “Financing activities” below. Generally, funding for the Company’s working capital obligations is provided by internally-generated cash flows.

13

 

     Payments for acquisitions, net of cash acquired. In 2004, the Company paid $880.4 million of cash, net of $12.1 million of cash acquired, and issued shares of the Company’s common stock to complete the Evergreen merger. The Company also assumed $300 million principal amount of Evergreen notes and other current and noncurrent obligations associated with the Evergreen merger. As is further discussed in “Financing activities” below, and in Note C of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein, the Company financed the cash costs utilizing credit facilities.
     Oil and gas properties. The Company’s cash expenditures for additions to oil and gas properties during 2006, 2005 and 2004 totaled $1.4 billion, $1.1 billion and $562.9 million, respectively. The Company’s 2006 expenditures for additions to oil and gas properties were funded by $754.8 million of net cash provided by operating activities and by a portion of the net proceeds from the disposition of deepwater Gulf of Mexico and Argentine assets. The Company’s 2005 and 2004 expenditures for additions to oil and gas properties were internally funded by $1.3 billion and $1.1 billion, respectively, of net cash provided by operating activities.
     The Company strives to maintain its indebtedness at levels which will provide sufficient financial flexibility to take advantage of future opportunities. For 2007, the Company’s credit facility and net cash provided by operating activities were sufficient to fund the 2007 capital expenditures budget.
     Off-balance sheet arrangements. From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of December 31, 2006, the material off-balance sheet arrangements and transactions that the Company has entered into include (i) undrawn letters of credit, (ii) operating lease agreements, (iii) drilling commitments, (iv) VPP obligations (to physically deliver volumes and pay related lease operating expenses in the future) and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable such as derivative contracts that are sensitive to future changes in commodity prices and gas transportation commitments. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. See “Contractual obligations” below for more information regarding the Company’s off-balance sheet arrangements.
     Contractual obligations. The Company’s contractual obligations include long-term debt, operating leases, drilling commitments (including commitments to pay day rates for drilling rigs), derivative obligations, other liabilities, transportation commitments and VPP obligations.
     The following table summarizes by period the payments due by the Company for contractual obligations estimated as of December 31, 2006:
                                 
    Payments Due by Year  
            2008 and     2010 and          
    2007     2009     2011     Thereafter  
            (in thousands)          
Long-term debt (a)
   $ 32,075     $ 3,777     $ 328,000     $ 1,232,985  
Operating leases (b)
     29,065       27,906       7,429       —  
Drilling commitments (c)
     330,381       307,265       —       —  
Derivative obligations (d)
     78,233       121,126       —       —  
Other liabilities (e)
     170,156       70,932       25,750       108,660  
Transportation commitments (f)
     68,630       137,396       130,992       170,546  
VPP obligations (g)
     181,232       306,044       135,166       42,069  
 
                        
 
   $ 889,772     $ 974,446     $ 627,337     $ 1,554,260  
 
                        
 
(a)   See Note F of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein. The amounts included in the table above represent principal maturities only.
 
(b)   See Note I of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein.

14

 

(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, 2006.
 
(d)   Derivative obligations represent net liabilities for oil and gas commodity derivatives that were valued as of December 31, 2006. These liabilities include $131.1 million of liabilities that are fixed in amount and are not subject to continuing market risk. The ultimate settlement amounts of the remaining portions of the Company’s derivative obligations are unknown because they are subject to continuing market risk. See Note J of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s derivative obligations.
 
(e)   The Company’s other liabilities represent current and noncurrent other liabilities that are comprised of benefit obligations, litigation and environmental contingencies, asset retirement obligations and other obligations for which neither the ultimate settlement amounts nor their timings can be precisely determined in advance. See Notes H, I and L of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s post retirement benefit obligations, litigation contingencies and asset retirement obligations, respectively.
 
(f)   Transportation commitments represent estimated transportation fees on gas throughput commitments. See Note I of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s transportation commitments.
 
(g)   These amounts represent the amortization of the deferred revenue associated with the VPPs. The Company’s ongoing obligation is to deliver the specified volumes sold under the VPPs free and clear of all associated production costs and capital expenditures. See Note T of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein.
     Environmental contingency. A subsidiary of the Company was notified by the Texas Commission on Environmental Quality (“TCEQ”) in August 2005 that the TCEQ considered the subsidiary to be a potentially responsible party with respect to the Dorchester Refining Company State Superfund Site located in Mount Pleasant, Texas. In connection with the acquisition of oil and gas assets in 1991, the Company acquired a group of companies, one of which was an entity that had owned a refinery located at the Mount Pleasant site from 1977 until 1984. According to the TCEQ, this refinery was responsible for releases of hazardous substances into the environment. The TCEQ recently informed the Company that other previous owners and operators applied for acceptance into the Texas Voluntary Cleanup Program to clean up the site. As a result, the TCEQ deleted the site from the state Superfund registry and no longer considers the Company’s subsidiary a potentially responsible party with respect to the site. See Notes I and W of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding this matter as well as other environmental and legal contingencies involving the Company.
     Capital resources. The Company’s primary capital resources are net cash provided by operating activities, proceeds from financing activities and proceeds from sales of nonstrategic assets. The Company expects that these resources will be sufficient to fund its capital commitments for the foreseeable future. For 2007, the Company’s capital commitments exceeded estimated cash flows from operations, resulting in additional borrowings under the Company’s credit facility. For 2008, the Company currently expects that cash flow from operations will be sufficient to fund the Company’s $1 billion capital budget.
     Asset divestitures. In August 2007, the Company entered into a share purchase agreement for the sale of all of the common stock of its Canadian subsidiaries for cash proceeds of $540 million, subject to normal closing adjustments. During November 2007, the Company completed the divestiture of the common stock of its Canadian subsidiaries, the proceeds from which were utilized to reduce amounts outstanding under the Company’s credit facility. Associated therewith, the Company will report a gain of approximately $100 million during the fourth quarter of 2007. The results of operations for the Canadian assets are included in the Company’s discontinued operations.
     During March 2006, the Company sold all of its interests in certain oil and gas properties in the deepwater Gulf of Mexico for net proceeds of $1.2 billion, resulting in a gain of $726.2 million. During April 2006, the Company sold its Argentine assets for net proceeds of $669.6 million, resulting in a gain of $10.9 million. The results of operations for these divestitures are included in the Company’s discontinued operations. The net cash proceeds from these divestitures were used to reduce outstanding indebtedness under the Company’s credit facility, to fund a portion of additions to oil and gas properties, for stock repurchases and for general corporate purposes.

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     During May 2005, the Company sold all of its interests in the Martin Creek, Conroy Black and Lookout Butte oil and gas properties in Canada for net proceeds of $197.2 million, resulting in a gain of $138.3 million. During August 2005, the Company sold all of its interests in certain oil and gas properties on the Gulf of Mexico shelf for net proceeds of $59.2 million, resulting in a gain of $27.9 million. During October 2005, the Company sold all of its shares in a subsidiary that owns the interest in the Olowi block in Gabon for net proceeds of $47.9 million, resulting in a gain of $47.5 million. The net cash proceeds from the 2005 divestitures were used to reduce outstanding indebtedness.
     During January 2005, the Company sold 20.5 MMBOE of proved reserves, by means of two VPPs for net proceeds of $592.3 million, including the assignment of the Company’s obligations under certain derivative hedge agreements. Proceeds from the VPPs were used to reduce outstanding indebtedness.
     During April 2005, the Company sold 7.3 MMBOE of proved reserves, by means of another VPP for net proceeds of $300.3 million, including the assignment of the Company’s obligations under certain derivative hedge agreements. Proceeds from the VPP were used to reduce outstanding indebtedness.
     See Note T of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s VPPs.
     Operating activities. Net cash provided by operating activities during 2006, 2005 and 2004 was $754.8 million, $1.3 billion and $1.1 billion, respectively. The decrease in net cash provided by operating activities in 2006, as compared to that of 2005, was primarily due to the loss of cash flow from the aforementioned asset divestitures. The increase in net cash provided by operating activities in 2005, as compared to that of 2004, was primarily due to higher commodity prices and the operations acquired in the Evergreen merger.
     Investing activities. Net cash provided by investing activities during 2006 was $145.5 million, as compared to net cash provided by investing activities of $84.7 million during 2005 and net cash used in investing activities of $1.5 billion during 2004. The increase in net cash provided by investing activities during 2006, as compared to 2005, was primarily due to a $396.2 million increase in proceeds from disposition of assets, partially offset by a $280.6 million increase in additions to oil and gas properties. The decrease in net cash used in investing activities during 2005, as compared to 2004, was primarily due to (i) $1.2 billion in proceeds from asset divestitures in 2005, which included $892.6 million of net proceeds received from VPPs sold during 2005 and (ii) $880.4 million of cash consideration paid in 2004 in connection with the Evergreen merger offset by an increase of $560.4 million in additions to oil and gas properties. See “Results of Operations” above and Note N of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding asset divestitures.
     Financing activities. Net cash used in financing activities was $913.5 million and $1.4 billion during 2006 and 2005, respectively. Net cash provided by financing activities during 2004 was $414.3 million. During 2006, significant components of financing activities included $554.7 million of net cash used to repay long-term borrowings, $348.9 million of net cash used to purchase 8.9 million shares of stock and $31.7 million of dividend payments, partially offset by $17.4 million of proceeds from the exercise of long-term incentive plan stock options and employee stock purchases. During 2005, financing activities were comprised of $353.6 million of net principal repayments on long-term debt, $60.1 million of payments of other noncurrent liabilities, primarily comprised of cash settlements of acquired hedge obligations, $30.3 million of dividends paid and $949.3 million of stock repurchases, partially offset by $41.6 million of proceeds from the exercise of long-term incentive plan stock options and employee stock purchases. During 2004, financing activities were comprised of $553.4 million of net principal borrowings on long-term debt, $54.3 million of payments of other noncurrent liabilities, primarily comprised of settlements of fair value and acquired hedge obligations and other financial obligations, $92.3 million of stock repurchases and $26.6 million of dividends paid, partially offset by $35.1 million of proceeds from the exercise of long-term incentive plan stock options and employee stock purchases.
     During September 2005, the Company announced that the board of directors had approved a share repurchase program authorizing the purchase of up to $1 billion of the Company’s common stock. During 2006 and 2005, the Company expended a total of $348.9 million to acquire 8.9 million shares of stock and $949.3 million to acquire 20.0 million shares of stock, respectively, of which $345.3 million and $940.3 million, respectively, were repurchased pursuant to the repurchase programs. In 2007, the Board authorized share repurchases of up to $750 million of the Company’s common stock. Through September 30, 2007, the Company had repurchased approximately $207.8 million of common stock under this 2007 authorized program.

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     On August 15, 2007, $32.1 million principal amount of the Company’s 8.25% senior notes matured and were repaid with borrowings under the Company’s credit facility. On January 15, 2008, $3.8 million principal amount of the Company’s 6.50% senior notes will mature. The Company intends to fund the maturities of these senior notes with borrowings under its credit facility.
     During March 2007, the Company issued $500 million of 6.65% Notes for net proceeds of $494.8 million. The Company used the net proceeds from the 6.65% Notes to reduce indebtedness under its credit facility. During April 2007, the Company entered into an amended credit facility that extended the maturity of its credit facility to April 11, 2012. See “2007 Events” above for additional information regarding the significant terms of the amended credit facility.
     During May 2006, the Company issued $450 million of 6.875% Notes for net proceeds of $447.4 million. The Company used the net proceeds, in part, from the 6.875% Notes to repurchase $346.2 million of its 6.50% Notes and for general corporate purposes.
     During 2006, holders of all of the $100 million of 4 3/4% Senior Convertible Notes due 2021 exercised their conversion rights. Associated therewith, the Company paid $79.9 million in cash, issued 2.3 million shares of common stock and recorded a $22.0 million increase to stockholders’ equity.
     During April 2005, $131.0 million of the Company’s 8 7/8% senior notes due 2005 matured and were repaid. During 2005, the Company also redeemed the remaining $64.0 million and $16.2 million, respectively, of aggregate principal amount of its 9 5/8% senior notes due 2010 and its 7.50% senior notes due 2012. During September 2005, the Company accepted tenders to purchase $188.4 million in principal amount of the 5.875% senior notes due 2012 for $199.9 million. The Company utilized unused borrowing capacity under its credit facility to fund these financing activities.
     During 2007, the Company’s board of directors declared total dividends of $.27 per common share. Associated therewith, the Company paid $16.0 million of aggregate dividends during April 2007 and $17.2 million of aggregate dividends during October 2007. Future dividends are at the discretion of the Board, and, if declared, the Board may change the current dividend amount, including in response to the Company’s liquidity and capital resources at the time.
     In 2007, Pioneer Southwest filed a preliminary registration statement (subject to completion) with the SEC to sell limited partner interests. Pioneer Southwest will own interests in certain oil and gas properties currently owned by the Company in the Spraberry field in the Permian Basin of West Texas. Pioneer Southwest expects to sell 35.3 percent (before underwriters’ over-allotment option) of its limited partner interests to the public (the “Offering”). Completion of the Offering is subject to market conditions and numerous other risks beyond the control of Pioneer Southwest, and therefore it is possible that the Offering will not be completed, will not raise the planned amount of capital even if the Offering is completed, or will not be completed when planned. If completed as planned, the Offering is estimated to result in the Company’s receipt of approximately $136 million of net cash proceeds during the first quarter of 2008.
     In October 2007, Pioneer Southwest entered into a $300 million unsecured revolving credit facility (“PSE Credit Agreement”) with a syndicate of banks which will mature 5 years following the closing of the Offering of the limited partner interests in Pioneer Southwest. The closing of the public offering of Pioneer Southwest’s limited partner interests is a condition to the obligation of the lenders to make loans under the PSE Credit Agreement. See “2007 Events” above and Note W of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding Pioneer Southwest and the PSE Credit Agreement.
     Alaskan Petroleum Production Tax. In 2006, the State of Alaska replaced its severance tax with a new tax called the PPT, for periods beginning after March 31, 2006. The major components of the new PPT are:
  •   The “basic tax”, which begins at 22.5 percent (this rate can increase based on factors tied to commodity prices) of property income for designated pools of assets in Alaska. Property income is basically defined as oil and gas revenue less lease operating expenses, qualified capital expenditures, property taxes and certain other costs. If property income is a loss then it converts to a PPT loss carryforward at a rate of 20 percent of the property loss. PPT loss carryforwards can be used to reduce future PPT liabilities or transferred to a third party. For 2006 and the nine months ended September 30, 2007, the Company estimates its PPT loss carryforwards to be approximately $21.0 million and $45.0 million, respectively.

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  •   A capital expenditure credit of 20 percent of qualified capital expenditures within Alaska. The credit can be (a) used to reduce a company’s current PPT liability, (b) carried forward and used to reduce future PPT liabilities or (c) transferred to a third party. Certain qualified exploration capital expenditures can receive up to an additional 20 percent capital expenditure credit on the expenditures previously discussed. For 2006 and the nine months ended September 30, 2007, the Company estimates its capital expenditure credits to be approximately $20.4 million and $44.5 million, respectively.
 
  •   Companies with production of less than 50,000 BOEPD within Alaska may also claim an annual non-transferable and non-refundable credit against PPT of $12 million per year for ten consecutive years, once the election is made to receive this credit.
 
  •   Companies that incurred qualified capital expenditures within Alaska in the five years preceding the PPT effective date can earn non-transferable transitional capital credits of 20 percent of such expenditures. These credits can be used to reduce a company’s present and future PPT liabilities. The Company estimates it has approximately $20 million of these credits to offset future PPT liabilities.
     The Company currently has no production in Alaska and accordingly has no PPT liabilities. The Company anticipates that it will recognize benefits from the carryforwards and credits as they are used to reduce future PPT liabilities, sold to third parties or refunded by the State of Alaska. Currently, the State of Alaska budgets annual amounts to provide for refunds of PPT credits; however, no assurances can be made that the State of Alaska will budget for future refunds. During the second quarter of 2007, the Company received a $25.0 million refund from the State of Alaska on earned PPT credits, and during the third quarter of 2007, the Company sold $28.3 million of earned PPT credits to a third party, which amounts have been recognized in interest and other income in the Company’s Consolidated Statements of Operations for the respective three and nine month periods of 2007. The Company may sell additional earned PPT credits in the future. The Company cannot predict the price that a third-party would pay for the certificates, but anticipates that it will be at a discount to the face amount of the certificates. Recently, the Alaskan legislature replaced PPT with Alaska’s Clear and Equitable Share tax (“ACES”). The Company is currently evaluating the complete effects of ACES, but believes it will not have a material impact on the Company’s Alaskan operations.
     As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined by the Board.
     Liquidity. The Company’s principal source of short-term liquidity is the Credit Agreement. There was $328.0 million of outstanding borrowings under its credit facility as of December 31, 2006. Including $150.2 million of undrawn and outstanding letters of credit under its credit facility, the Company had $1.0 billion of unused borrowing capacity as of December 31, 2006.
     Debt ratings. The Company receives debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s, which are subject to regular reviews. S&P’s rating for the Company is BB+ with a stable outlook. Moody’s rating for the Company is Ba1 with a negative outlook. S&P and Moody’s consider many factors in determining the Company’s ratings including: production growth opportunities, liquidity, debt levels and asset and reserve mix. 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. As of September 30, 2007, the Company was in compliance with all of its debt covenants.
     Book capitalization and current ratio. The Company’s book capitalization at December 31, 2006 was $4.5 billion, consisting of debt of $1.5 billion and stockholders’ equity of $3.0 billion. Consequently, the Company’s debt to book capitalization decreased to 33 percent at December 31, 2006 from 48 percent at December 31, 2005. The Company’s ratio of current assets to current liabilities was .60 to 1.00 at December 31, 2006, essentially unchanged from December 31, 2005.
Critical Accounting Estimates
     The Company prepares its consolidated financial statements for inclusion in this Report in accordance with GAAP. See Note B of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for a comprehensive discussion of the Company’s significant accounting policies. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. Following is a discussion of the Company’s most critical accounting estimates, judgments and uncertainties that are inherent in the Company’s application of GAAP.

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     Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and to restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
     Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance. See Notes B and L of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein 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 2006, 2005 and 2004, the Company recognized exploration, abandonment, geological and geophysical expense from (i) continuing operations of $250.2 million, $153.8 million and $94.3 million, respectively, and (ii) discontinued operations of $21.3 million, $73.4 million and $87.4 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, 2006, 2005 and 2004 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, 2006 is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the Standardized Measure on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. See “Item 1A. Risk Factors” for additional information regarding estimates of proved reserves.
     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.

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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 its outlook of future commodity prices and net cash flows that may be generated by the properties and if a significant downward revision has occurred to the estimated proved reserves. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated.
     Impairment of unproved oil and gas properties. At December 31, 2006, the Company carried unproved property costs of $210.3 million. Management periodically assesses unproved oil and gas properties for impairment, on a project-by-project basis. Management’s assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects impacts the amount and timing of impairment provisions, if any.
     Suspended wells. The Company suspends the costs of exploratory wells that discover hydrocarbons pending a final determination of the commercial potential of the oil and gas discovery. The ultimate disposition of these well costs is dependent on the results of future drilling activity and development decisions. If the Company decides not to pursue additional appraisal activities or development of these fields, the costs of these wells will be charged to exploration and abandonment expense.
     The Company generally does not carry the costs of drilling an exploratory well as an asset in its Consolidated Balance Sheets for more than one year following the completion of drilling unless the exploratory well finds oil and gas reserves in an area requiring a major capital expenditure and both of the following conditions are met:
  (i)   The well has found a sufficient quantity of reserves to justify its completion as a producing well.
 
  (ii)   The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
     Due to the capital intensive nature and the geographical location of certain Alaskan, deepwater Gulf of Mexico and foreign projects, it may take the Company longer than one year to evaluate the future potential of the exploration well and economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves or is noncommercial and is impaired. See Note D of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s suspended exploratory well costs.
     Assessments of functional currencies. Management determines the functional currencies of the Company’s subsidiaries based on an assessment of the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. The U.S. dollar is the functional currency of all of the Company’s international operations except Canada. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position.
     Argentine economic and currency measures. In April 2006, the Company sold its assets in Argentina for proceeds of $669.6 million, resulting in a gain of $10.9 million. Prior to the divestiture, the accounting for and remeasurement of the Company’s Argentine balance sheets as of December 31, 2005 reflect management’s assumptions regarding some uncertainties unique to Argentina’s economic environment. The Argentine economic and political situation continues to evolve and the Argentine government may enact future regulations or policies that, when finalized and adopted, may materially impact, among other items, the timing of repatriations of the sales proceeds and contingent liabilities associated with the Company’s retained obligations and its indemnifications provided to the purchaser of the assets. See Note B of Notes to Consolidated Financial Statements included in the Financial Statements included herein for a description of the assumptions utilized in the preparation of these financial statements.

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     Deferred tax asset valuation allowances. The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that its deferred tax assets will be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and reassesses the likelihood that the Company’s net operating loss carryforwards and other deferred tax attributes in each jurisdiction will be utilized prior to their expiration. There can be no assurances that facts and circumstances will not materially change and require the Company to establish deferred tax asset valuation allowances in certain jurisdictions in a future period. As of December 31, 2006, the Company does not believe there is sufficient positive evidence to reverse its valuation allowances related to certain foreign tax jurisdictions.
     Goodwill impairment. The Company reviews its goodwill for impairment at least annually. This requires the Company to estimate the fair value of the assets and liabilities of the reporting units that have goodwill. There is considerable judgment involved in estimating fair values, particularly in the estimation of proved reserves as described above. See Note B of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information.
     Litigation and environmental contingencies. The Company makes judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount of damages. Similarly, environmental remediation liabilities are 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 the Financial Statements and Supplementary Data included herein 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 “New Accounting Pronouncements” below and Note H of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s pension and accumulated postretirement benefit obligations.
     Valuation of stock-based compensation. The Company adopted the “modified prospective” approach as prescribed under SFAS No. 123(R) on January 1, 2006. Under this approach, the Company is required to expense all options and other stock-based compensation that vested during the year of adoption based on the fair value of the award on the grant date. The calculation of the fair value of stock-based compensation requires the use of estimates to derive the various inputs necessary for using the Black-Scholes valuation method elected by the Company.
New Accounting Pronouncements
     The following discussions provide information about new accounting pronouncements that were issued by the Financial Accounting Standards Board (“FASB”) during 2006:
     FIN 48. In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN No. 48”). The Interpretation clarifies the accounting for income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the financial statements. FIN No. 48 also provides guidance on measurement, classification, interim accounting and disclosure. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. The Company adopted FIN 48 on January 1, 2007 and recorded no adjustment related to the adoption.
     SFAS 157. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measures” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. SFAS 157 is effective for fiscal years beginning after November 15, 2007. The Company is continuing to assess the impact of SFAS 157.

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     SFAS 158. In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and other Postretirement Plans” (“SFAS 158”). Under SFAS 158, a business entity that sponsors one or more single-employer defined benefit plans is required to:
  •   recognize the funded status of a benefit plan in its balance sheet, measured as the difference between plan assets at fair value (with limited exceptions) and the benefit obligation,
 
  •   recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period, but are not recognized as components of net periodic benefit cost,
 
  •   measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position and
 
  •   disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations.
     An employer with publicly traded securities is required to initially recognize the funded status of its defined benefit postretirement plans and to provide the required disclosures as of the end of the first fiscal year ending after December 15, 2006. The Company has adopted the provisions of SFAS 158 effective on December 31, 2006. The Company previously recognized the funded status of its defined benefit postretirement plans and currently recognizes periodic changes in its defined benefit postretirement plans as components of service costs in the period of change as allowed by SFAS 158. Consequently, the adoption of SFAS 158 did not have a material impact on the Company’s liquidity, financial position or future results of operations. See Note H of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s postretirement plans.
     SFAS 159. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The implementation of SFAS 159 is not expected to have a material effect on the financial condition or results of operations of the Company.

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

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