UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2008

 

or

 

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to ________

 

Commission File Number: 1-13245

 

PIONEER NATURAL RESOURCES COMPANY

(Exact name of Registrant as specified in its charter)

 

 

 

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

 

 

 

 

 

 

 

 

Cautionary Statement Concerning Forward-Looking Statements

 

The information in this Quarterly Report on Form 10-Q (the "Report") contains forward-looking statements that involve risks and uncertainties. When used in this document, the words "believes," "plans," "expects," "anticipates," "intends," "continue," "may," "will," "could," "should," "future," "potential," "estimate," or the negative of such terms and similar expressions as they relate to Pioneer Natural Resources Company ("Pioneer" or the "Company") are intended to identify forward-looking statements. The forward-looking statements are based on the Company's current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company's control.

 

These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, international operations and associated international political and economic instability, litigation, the costs and results of drilling and operations, access to and availability of drilling equipment and transportation, processing and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, and acts of war or terrorism. These and other risks are described in the Company's Annual Report on Form 10-K, this Report, other Quarterly Reports on Form 10-Q and other filings with the Securities and Exchange Commission. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See "Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk" and "Part II, Item 1A. Risk Factors" in this Report and "Item 1. Business Competition, Markets and Regulations", "Item 1A. Risk Factors" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in the Company's Annual Report on Form 10-K for the year ended December 31, 2007 for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. The Company undertakes no duty to publicly update these statements except as required by law.

 

 

Definitions of Certain Terms and Conventions Used Herein

 

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

 

(i)  Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii)Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii)Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (C) crude oil, natural gas and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

 

 

PART I. FINANCIAL INFORMATION

 

 

PIONEER NATURAL RESOURCES COMPANY

 

CONSOLIDATED BALANCE SHEETS

(in thousands)

 

 

 

 

 

PIONEER NATURAL RESOURCES COMPANY

 

CONSOLIDATED BALANCE SHEETS (Continued)

(in thousands, except share data)

 

 

 

 

 

 

PIONEER NATURAL RESOURCES COMPANY

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

 

 

 

 

 

PIONEER NATURAL RESOURCES COMPANY

 

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(in thousands, except dividends per share)

(Unaudited)

 

 

 

 

 

 

 

 

PIONEER NATURAL RESOURCES COMPANY

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

 

 

 

 

 

 

Pioneer is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company with continuing operations in the United States, South Africa and Tunisia.

 

 

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2008 and for the three and six months ended June 30, 2008 and 2007 include all adjustments and accruals, consisting only of normal recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

 

Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the SEC. These consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2007.

 

Discontinued operations. In November 2007, the Company sold its Canadian subsidiaries. In accordance with Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"), the Company has reflected the results of operations of this divestiture as discontinued operations, rather than as a component of continuing operations. See Note Q for additional information regarding discontinued operations.

 

Allowances for doubtful accounts. As of June 30, 2008 and December 31, 2007, the Company's allowances for doubtful accounts totaled $15.5 million and $12.2 million, respectively. In accordance with SFAS No. 5, Accounting for Contingencies, the Company establishes allowances for bad debts equal to the estimable portions of accounts and notes receivables for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations in the accounting period during which failure to collect an estimable portion is determined to be probable.

 

Inventories. Inventories consisted of $129.1 million and $94.3 million of materials and supplies and $2.9 million and $3.3 million of commodities as of June 30, 2008 and December 31, 2007, respectively. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items, such as tubing, casing, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out basis. Commodities inventory is carried at the lower of average cost or market, on a first-in, first-out basis. Any impairments of inventory are reflected in gain (loss) on disposition of assets in the Consolidated Statements of Operations. As of June 30, 2008 and December 31, 2007, the Company's materials and supplies inventory was net of $.3 million and $1.1 million, respectively, of valuation reserve allowances.

 

Goodwill. In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2007, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment.

 

 

 

           In addition to Pioneer Southwest, the Company owns the majority interests in certain other subsidiaries with operations in the United States. Minority interests in the net income of the Company's consolidated subsidiaries totaled $6.2 million and $7.0 million for the three and six months ended June 30, 2008, respectively, principally related to Pioneer Southwest minority interest income of $5.1 million for each of the three and six months ended June 30, 2008.

 

Stock-based compensation. For stock-based compensation awards, compensation expense is being recognized in the Company's financial statements on a straight line basis over the vesting period based on the fair value on the date of grant. The Company utilizes (a) the Black-Scholes option pricing model to measure the fair value of stock options, (b) the stock price on the date of grant for the fair value of restricted stock awards and (c) the Monte Carlo simulation method for the fair value of performance unit awards.

 

For the three and six months ended June 30, 2008, the Company recorded $8.2 million and $17.2 million of stock-based compensation costs for all plans, respectively, as compared to $8.6 million and $16.4 million for the same respective periods of 2007.

 

In accordance with GAAP, the Company's issued shares, as reflected in the Consolidated Balance Sheets at June 30, 2008 and December 31, 2007, do not include 1,184,234 shares and 1,960,475 shares, respectively, related to unvested stock-based compensation awards. During the six months ended June 30, 2008, stock-based compensation awards totaled 1,070,035 shares and units and lapses and forfeitures of stock-based compensation totaled 98 and 42,341 shares and units, respectively. Restrictions on 1,027,596 stock-based awards will lapse in future periods.

 

As of June 30, 2008, there was approximately $61.3 million of unrecognized compensation expense related to unvested share-based compensation plan awards, primarily related to restricted stock and performance unit awards. This compensation will be recognized over the remaining vesting periods, which on a weighted average basis is approximately 24 months.

 

Reclassifications. Certain reclassifications have been made to the 2007 amounts in order to conform to the 2008 presentation. 

 

New accounting pronouncements. In September 2006, the Financial Accounting Standards Board ("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. During February 2008, the FASB issued FASB Staff Position No. 157-2, "FSP FAS 157-2" ("FSP FAS 157-2"). FSP FAS 157-2 delayed the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis at least annually. On January 1, 2008, the Company adopted the provisions of SFAS 157 for financial assets and liabilities. See Note D for additional information regarding the Company's adoption of SFAS 157. The adoption of the provisions of SFAS 157 that were delayed by FSP FAS 157-2 is not expected to have a material effect on the financial condition or results of operations of the Company.

 

 

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. The Company adopted the provisions of SFAS 159 on January 1,2008 and its implementation did not have a material effect on the financial condition or results of operations of the Company.

 

In December 2007, the FASB issued SFAS No. 141(R), "Business Combinations" ("SFAS 141(R)"). SFAS 141(R) replaces SFAS 141 and provides greater consistency in the accounting and financial reporting of business combinations. SFAS 141(R) requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction and any noncontrolling interest in the acquired entity at the acquisition date, measured at the fair value as of that date. This includes the measurement of the acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for pre-acquisition gain and loss contingencies, the recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition-related transaction costs and the recognition of changes in the acquirer's income tax valuation allowance and deferred taxes. SFAS 141(R) is effective for fiscal years and interim periods within those fiscal years, beginning on or after December 15, 2008, and is to be applied prospectively as of the beginning of the fiscal year in which the statement is applied. The implementation of SFAS 141(R) is not expected to have a material effect on the financial condition or results of operations of the Company.

 

In December 2007, the FASB issued SFAS No. 160 "Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB Statement No. 51" ("SFAS 160"). SFAS 160 amends Accounting Research Bulletin ("ARB") No. 51, "Consolidated Financial Statements," to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated income statement. SFAS 160 is effective for the Company on January 1, 2009 and is not expected to have a significant impact on the Company's financial statements.

 

In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities an amendment of FASB Statement No. 133" ("SFAS 161"). SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities by requiring entities to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS 161 is effective for the Company on January 1, 2009 and will only impact future disclosures about the Company's derivative instruments and hedging activities.

 

In May 2008, the FASB issued FASB Staff Position No. APB 14-1, "Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)" ("FSP APB 14-1"). FSP APB 14-1 specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entitys nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. FSP APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008. The adoption of FSP APB 14-1 will increase the annual interest expense that the Company recognizes on its $500 million 2.875% Senior Convertible Notes from an annual yield of approximately 2.875 percent to an annual yield equivalent to a nonconvertible debt borrowing. The adoption of FSP APB 14-1 will also result in the reclassification of the estimated issuance date fair value of the 2.875% Senior Convertible Notes conversion privilege from long-term debt to shareholders equity in the Company's consolidated balance sheet. The Company is assessing the equivalent nonconvertible debt borrowing rate and the fair value of the conversion privilege.

 

 

In May 2008, the FASB issued SFAS No. 162 "The Hierarchy of Generally Accepted Accounting Principles" ("SFAS 162"). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements presented in conformity with generally accepted accounting principles in the United States ("GAAP"). SFAS 162 is effective 60 days following the United StatesSecurities and Exchange Commission's ("SEC") approval of the Public Company Accounting Oversight Board amendments to AU Section 411, "The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles." The Company does not expect that the adoption of SFAS 162 will have a significant impact on the Company's financial statements.

 

In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1 (Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF 03-6-1), which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the net income allocation in computing basic net income per share under the two class method prescribed under SFAS 128 Earnings per Share. FSP 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and, to the extent applicable, must be applied retrospectively by adjusting all prior-period net income per share data to conform to the provisions of the standard. The Company is assessing the effect that FSP EITF 03-6-1 will have on its net income per share calculations.

 

 

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are presented in proved properties in the Consolidated Balance Sheets. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense.

 

The following table reflects the Company's capitalized exploratory well activity during the three and six months ended June 30, 2008:

 

 

 

 

 

The following table provides an aging, as of June 30, 2008 and December 31, 2007, of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the date drilling was completed:

 

 

         The following table provides an aging of capitalized costs of exploration projects that have been suspended for more than one year as of June 30, 2008:

 

 

Lay Creek. The Company's Lay Creek project is a coal bed methane pilot program located in northwestern Colorado. The Company has drilled 18 wells in six separate pilot areas and completed workovers and recompletions on 14 wells drilled by a previous operator. The Company completed water treatment facilities and initiated sales of production in the second quarter of 2008. Determination of success of the pilot project is dependent on the ability to dewater the formation and determine if commercial quantities of gas can be produced. The pilot project is currently in the dewatering phase. The Company will continue its de-watering efforts so long as gas volumes grow towards commerical quantities.

 

 

Effective January 1, 2008, the Company adopted the provisions of SFAS 157 for financial assets and liabilities. SFAS 157 retains the exchange price notion in the definition of fair value but clarifies that the exchange price is the price in an orderly transaction between market participants to sell an asset or transfer a liability in the principal or most advantageous market in which the reporting company would transact for the asset or liability.

 

The SFAS 157 valuation framework is based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

 

 

 

 

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Company's financial assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2008 for each of the fair value hierarchy levels:

 

 

The following table presents the changes in the fair values of the Company's commodity derivative obligations classified as Level 3 in the fair value hierarchy:

 

 

_____________

 

Trading securities and deferred compensation plan assets. The Company's trading securities represent equity securities that are actively traded on major exchanges and trading securities that are not actively traded on major exchanges. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges plus unallocated contributions as of the measurement date. As of June 30, 2008, all significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs except inputs for trading securities that are not actively traded on major exchanges, which were provided by broker quotes representing Level 2 inputs.

 

Interest rate derivative assets. The Company's interest rate derivative assets represent swap contracts for $400 million notional amount of debt, whereby the Company pays a fixed rate of interest and the counterparty receives a variable LIBOR-based rate. The asset values attributable to the Company's interest rate derivative

contracts as of June 30, 2008 are based on (i) the contracted notional amounts, (ii) forward active market-quoted LIBOR rate yield curves and (iii) the Company's credit-adjusted risk-free rate yield curve. The Company's interest rate derivative asset measurements represent Level 2 inputs in the hierarchy priority.

 

 

 

Commodity derivative obligations. The Company's commodity derivative obligations represent oil, NGL and gas swap and collar contracts. The Company's commodity price obligation measurements for oil and gas derivative contracts represent Level 2 inputs in the hierarchy priority while NGL derivative contracts represent Level 3 inputs in the hierarchy priority.

 

Oil derivatives. The Company's oil derivatives are swap and collar contracts for notional Bbls of oil at fixed (in the case of swaps contracts) or interval (in the case of collar contracts) NYMEX West Texas Intermediate ("WTI") oil prices. The liability transfer values attributable to the Company's oil derivative obligations as of June 30, 2008 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) the Company's estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar contracts. The Company's credit-adjusted risk-free rate is based on an independent market-quoted credit default swap rate curve for the Company's debt rating category plus the United States Treasury Bill yield curve as of June 30, 2008. The implied rates of volatility inherent in the Company's collar contracts were determined based on implied volatility factors provided by the derivative counterparties, adjusted for estimated volatility skews. The volatility factors are not considered significant to the fair values of the collar contracts since intrinsic and time values are the principal components of the collar values.

 

NGL derivatives. The Company's NGL derivatives are swap contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs. The liability transfer values attributable to the Company's NGL derivative obligations as of June 30, 2008 are based on (i) the contracted notional volumes, (ii) independent broker-supplied forward Mont Belvieu-posted-price quotes and (iii) the Company's credit-adjusted risk-free rate yield curve.

 

Gas derivatives. The Company's gas derivatives are swap contracts for notional MMBtus of gas contracted at various posted price indexes, including NYMEX Henry Hub ("HH") swap contracts coupled with basis swaps contracts that convert the HH price index point to other price indexes. The liability transfer values attributable to the Company's gas derivative obligations as of June 30, 2008 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) averages of forward posted price quotes supplied by independent brokers who are active in buying and selling gas derivatives at the indexes other than HH and (iv) the Company's credit-adjusted risk-free rate yield curve.

 

The Company corroborated independent broker-supplied forward price quotes by comparing price quote samples to alternate observable market data.

 

 

The Company accounts for income taxes in accordance with the provisions of SFAS No. 109, "Accounting for Income Taxes" ("SFAS 109"). SFAS 109 requires that the Company continually assess both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors to assess the likelihood that the Company's net operating loss carryforwards ("NOLs") and other deferred tax attributes in the U.S. federal, state and local and foreign tax jurisdictions will be utilized prior to their expiration. As of June 30, 2008 and December 31, 2007, the Company's valuation allowances (relating primarily to foreign tax jurisdictions) were $31.9 million and $24.8 million, respectively.

 

The Company adopted the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes" ("FIN 48") on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized and prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of June 30, 2008, the Company had no unrecognized tax benefits (as defined in FIN 48). In connection with the adoption of FIN 48, the Company established a policy to account for (a) interest charges with respect to income taxes as interest expense and (b) penalties as other expense in the Consolidated Statements of Operations. The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. With few exceptions, the Company believes that it is no longer subject to examinations by tax authorities for years before 2003. As of June 30, 2008, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company's future results of operations or financial position.

 

 

 

Pursuant to Accounting Principles Board ("APB") Opinion No. 23 "Accounting for Income Taxes Special Areas," the Company historically treated the undistributed earnings in South Africa as permanently reinvested and did not provide for a U.S. tax on such earnings. During the second quarter of 2007, the Company made the determination that it no longer had identifiable plans to reinvest these earnings in South Africa and accordingly began recording deferred tax expense. For the three and six months ended June 30, 2008, the Company recorded $4.8 million and $9.7 million, respectively, of U.S. income taxes for the results of operations of its South African subsidiaries.

 

Income tax (provisions) benefits. The Company's income tax (provisions) benefits attributable to income from continuing operations consisted of the following for the three and six months ended June 30, 2008 and 2007:

 

 

Discontinued operations. The Company's income tax (provisions) benefits attributable to income from discontinued operations consisted of the following for three and six months ended June 30, 2008 and 2007:

 

 

 

 

 

NOTE F.        Long-term Debt

 

Lines of credit. During April 2007, the Company entered into an Amended and Restated 5-Year Revolving Credit Agreement (the "Credit Facility") that matures in April 2012, unless extended in accordance with the terms of the Credit Facility. The Credit Facility also 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. As of June 30, 2008, the Company had $500 million of outstanding borrowings under the Credit Facility and had $45.8 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $954.2 million of unused borrowing capacity under the Credit Facility.

 

In May 2008, Pioneer Southwest entered into a $300 million unsecured revolving credit facility with a syndicate of banks, which matures in May 2013 (the Pioneer Southwest Credit Facility). The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions. Borrowings under the Pioneer Southwest Credit Facility may be in the form of Eurodollar rate loans, base rate committed loans or swing line loans. Eurodollar rate loans bear interest annually at LIBOR, plus a margin (the Applicable Rate) (currently 0.875 percent) that is determined by a reference grid based on Pioneer Southwests consolidated leverage ratio. Base rate committed loans bear interest annually at a base rate equal to the higher of (i) the Federal Funds Rate plus 0.5 percent or (ii) the Bank of America prime rate (the Base Rate) plus a margin (currently 0.5 percent). Swing line loans bear interest annually at the Base Rate plus the Applicable Rate. As of June 30, 2008, there were no outstanding borrowings under the Pioneer Southwest Credit Facility.

 

The Pioneer Southwest Credit Facility contains certain financial covenants, including (i) the maintenance of a quarter end maximum leverage ratio of not more than 3.5 to 1.00, (ii) an interest coverage ratio (representing a ratio of earnings before depreciation, depletion and amortization; impairment of long-lived assets; exploration expense; accretion of discount on asset retirement obligations; interest expense; income taxes; gain or loss on the disposition of assets; noncash commodity hedge related activity; and noncash equity-based compensation to interest expense) of not less than 2.5 to 1.0 and (iii) the maintenance of a ratio of the net present value of Pioneer Southwest's projected future cash flows from its oil and gas assets to total debt of at least 1.75 to 1.0.

 

Because of the net present value covenant contained in the agreement, borrowings under the Pioneer Southwest Credit Facility are currently limited to approximately $200 million.

 

Senior Notes. On January 15, 2008, $3.8 million principal amount of the Company's 6.50% senior notes matured and were paid.

 

Senior convertible notes. During January 2008, the Company issued $500 million principal amount of 2.875% convertible senior notes due 2038 (the "2.875% Senior Convertible Notes") and received proceeds, net of approximately $11.3 million of underwriter discounts and offering costs, of approximately $488.7 million. The Company used the net proceeds from the offering to reduce outstanding borrowings under the Credit Facility.

 

The 2.875% Senior Convertible Notes will be convertible under certain circumstances, using a net share settlement process, into a combination of cash and the Company's common stock pursuant to a formula. The initial base conversion price is approximately $72.60 per share (subject to adjustment in certain circumstances), which is equivalent to an initial base conversion rate of 13.7741 common shares per $1,000 principal amount of convertible notes. In general, upon conversion of a note, the holder of such note will receive cash equal to the principal amount of the note and the Company's common stock for the note's conversion value in excess of such principal amount. If at the time of conversion the applicable price of the Company's common stock exceeds the base conversion price, holders will receive up to an additional 8.9532 shares of the Company's common stock per $1,000 principal amount of notes, limited to a maximum of 22.7273 shares per $1,000 principal amount of notes, as determined pursuant to a specified formula.

 

 

The 2.875% Senior Convertible Notes mature on January 15, 2038 (the "Maturity Date"). The Company may redeem the 2.875% Senior Convertible Notes for cash at any time on or after January 15, 2013 at a price equal to 100 percent of the principal amount plus accrued and unpaid interest. Holders of the 2.875% Senior Convertible Notes may require the Company to purchase their 2.875% Senior Convertible Notes for cash at a price equal to 100 percent of the principal amount plus accrued and unpaid interest if certain fundamental changes occur, as defined in the agreement, or on January 15, 2013, 2018, 2023, 2028 or 2033. Additionally, holders may convert their notes at their option in the following circumstances:

 

 

Interest on the principal amount of the 2.875% Senior Convertible Notes is payable semiannually in arrears on January 15 and July 15 of each year, beginning July 15, 2008. Beginning on January 15, 2013, during any six-month period thereafter from January 15 to July 14 and from July 15 to January 14, if the average trading day price of a 2.875% Senior Convertible Note for the five consecutive trading days immediately preceding the first day of the applicable six-month interest period equals or exceeds $1,200, interest on the principal amount of the 2.875% Senior Convertible Notes will be 2.375% solely for the relevant interest period.

 

 

The Company uses financial derivative contracts to manage exposures to commodity price, interest rate and foreign currency fluctuations. The Company generally does not enter into derivative financial instruments for speculative or trading purposes. The Company also may enter into physical delivery contracts that effectively provide commodity price hedges. Because physical delivery contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, physical delivery contracts are not recorded in the financial statements.

 

All derivatives are recorded in the balance sheet at estimated fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date. Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive loss deferred hedge losses, net of tax ("AOCI Hedging"), which is later transferred to earnings when the hedged transaction occurs. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of the hedge derivatives, are recorded in earnings. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged.

 

Fair value hedges. The Company monitors the debt capital markets and interest rate trends to identify opportunities to enter into and terminate interest rate derivative contracts with the objective of reducing its costs of capital. As of June 30, 2008 and December 31, 2007, the Company was not a party to any open fair value hedges.

 

Cash flow hedges. The Company utilizes commodity swap and collar contracts to (i) reduce the impact on the Company's results of operations from the price volatility of 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. As of June 30, 2008, all of the Company's open commodity hedges are hedges of United States forecasted sales. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness.

 

 

 

         Oil prices. All material physical sales contracts governing the Company's oil production have been tied directly or indirectly to NYMEX prices. The following table sets forth the volumes hedged in Bbls under outstanding oil hedge contracts and the weighted average NYMEX prices per Bbl for those contracts as of June 30, 2008:

 

 

 

 

         The Company reports average oil prices per Bbl including the effects of oil quality adjustments, amortization of deferred volumetric production payment ("VPP") revenue and the net effect of oil hedges. The following table sets forth (i) the Company's oil prices from continuing operations, both reported (including hedge results and amortization of deferred VPP revenue) and realized (excluding hedge results and amortization of deferred VPP revenue), (ii) amortization of deferred VPP revenue to oil revenue from continuing operations and (iii) the net effect of oil price hedges on oil revenue from continuing operations for the three and six months ended June 30, 2008 and 2007:

 

 

Natural gas liquids prices. All material physical sales contracts governing the Company's NGL production have been tied directly or indirectly to Mont Belvieu prices. The following table sets forth the volumes hedged in Bbls under outstanding NGL hedge contracts and the weighted average Mont Belvieu prices per Bbl for those contracts as of June 30, 2008:

 

 

 

 

 

The Company reports average NGL prices per Bbl including the effects of NGL quality adjustments and the net effect of NGL hedges. The following table sets forth (i) the Company's NGL prices from continuing operations, both reported (including hedge results) and realized (excluding hedge results) and (iii) the net effect of NGL price hedges on NGL revenue from continuing operations for the three and six months ended June 30, 2008 and 2007:

 

 

Gas prices. The Company employs a policy of hedging a portion of its gas production based on the index price upon which the gas is actually sold in order to mitigate the basis risk between NYMEX prices and actual index prices, or based on NYMEX prices if NYMEX prices are highly correlated with the index price. The following table sets forth the volumes hedged in MMBtus under outstanding gas hedge contracts and the weighted average index prices per MMBtu for those contracts as of June 30, 2008:

 

 

 

 

 

The Company reports average gas prices per Mcf including the effects of Btu content, gas processing, shrinkage adjustments, amortization of deferred VPP revenue and the net effect of gas hedges. The following table sets forth (i) the Company's gas prices from continuing operations, both reported (including hedge results and amortization of deferred VPP revenue) and realized (excluding hedge results and amortization of deferred VPP revenue), (ii) amortization of deferred VPP revenue to gas revenue from continuing operations and (iii) the net effect of gas price hedges on gas revenue from continuing operations for the three and six months ended June 30, 2008 and 2007:

 

 

_____________

Interest rate. During January 2008, the Company entered into interest rate swap contracts and designated the contracts as cash flow hedges of the forecasted interest rate risk associated with a portion of the Company's Credit Facility indebtedness. The interest rate swap contracts are variable-for-fixed-rate swaps on $400 million notional amount of debt at a weighted average fixed annual rate of 2.87 percent, excluding any applicable margins. The interest rate swaps have an effective start date of February 2008, with $200 million terminating during February 2010 and $200 million during February 2011. The Company did not realize any ineffectiveness in connection with the interest rate swap contracts.

Hedge ineffectiveness. During the three and six months ended June 30, 2008, the Company recorded net ineffectiveness income of $.9 million and $1.9 million, as compared to a net ineffectiveness charge of $.9 million for the three and six months ended June 30, 2007. Hedge ineffectiveness represents the ineffective portions of changes in fair values of the Company's cash flow hedging instruments.  The primary causes of changes in ineffectiveness are changes in correlations and derivative fair values associated with commodity price indexes of financial hedge derivatives and the commodity price indexes of the hedged forecasted production for certain fields.

AOCI - Hedging. As of June 30, 2008 and December 31, 2007, AOCI - Hedging represented net deferred losses of $546.1 million and $228.3 million, respectively. The AOCI - Hedging balance as of June 30, 2008 was comprised of $752.3 million of net deferred losses on the effective portions of open cash flow hedges, $114.2 million of net deferred losses on terminated cash flow hedges (including $3 million of net deferred losses on terminated cash flow interest rate hedges) and $320.4 million of associated net deferred tax benefits. The increase in AOCI - Hedging during the six months ended June 30, 2008 was primarily attributable to increases in future oil, NGL and gas prices relative to the commodity prices stipulated in the hedge contracts, partially offset by the reclassification of net deferred hedge losses to net income as derivatives matured. Decreases in forward interest rate yield curves also increased the Company's AOCI Hedging attributable to the Company's interest rate swap contracts. The net deferred gains and losses associated with open cash flow hedges remain subject to market price fluctuations until the positions are either settled under the terms of the hedge contracts or terminated prior to settlement. The net deferred losses on terminated cash flow hedges are fixed.

 

 

 

         During the twelve months ending June 30, 2009, based on current estimates of future commodity prices and interest rates, the Company expects to reclassify approximately $490.4 million of net deferred losses associated with open commodity hedges and $73.1 million of net deferred losses on terminated commodity and interest rate hedges from AOCI - Hedging to oil and gas revenues and interest expense. The Company also expects to reclassify approximately $208.5 million of net deferred income tax benefits associated with commodity and interest rate hedges during the twelve months ending June 30, 2009 from AOCI - Hedging to income tax benefit.

Terminated commodity hedges. At times, the Company terminates open commodity hedge positions when the underlying commodity prices reach a point that the Company believes will be the high or low price of the commodity prior to the scheduled settlement of the open commodity hedge position. This allows the Company to maximize gains or minimize losses associated with the open hedge positions. At the time of termination of the hedges, the amounts are recorded in AOCI Hedging and amortized to earnings over the periods the production was scheduled to occur.

The following table sets forth, as of June 30, 2008, the scheduled amortization of net deferred losses on terminated commodity hedges that will be recognized as decreases to the Company's future oil and gas revenues:

 

 

 

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes the Company's asset retirement obligation transactions during the three and six months ended June 30, 2008 and 2007:

 

 

_____________

 

 

 

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the Consolidated Balance Sheets. As of June 30, 2008 and December 31, 2007, the current portion of the Company's asset retirement obligations amounted to $60.0 million and $86.9 million, respectively.

 

As of June 30, 2008 and December 31, 2007, the Company had recorded $10.3 million and $10.5 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities, respectively, in the Consolidated Balance Sheets. These obligations are comprised of five plans of which four relate to predecessor entities that the Company acquired in prior years. These plans had no assets as of June 30, 2008 or December 31, 2007. Other than the Company's retirement plan, the participants of these plans are not current employees of the Company.

 

The following table reconciles changes in the Company's unfunded accumulated postretirement benefit obligations during the three and six months ended June 30, 2008 and 2007:

 

 

 

Legal actions. The Company is party to the legal actions that are described below. The Company is also party to other proceedings and claims incidental to its business. While many of these other matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company will continue to evaluate its litigation on a quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to reflect its assessment of the then current status of litigation.

 

MOSH Holding. On April 11, 2005, the Company and its principal United States subsidiary, Pioneer Natural Resources USA, Inc., were named as defendants in MOSH Holding, L.P. v Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc.; Woodside Energy (USA) Inc.; and JPMorgan Chase Bank, N.A., ("JP Morgan") as Trustee of the Mesa Offshore Trust, which is before the Judicial District Court of Harris County, Texas (334th Judicial District). Subsequently, Dagger-Spine Hedgehog Corporation ("Dagger-Spine") and a group of approximately fifty other unitholders ("Wiegand") each filed a Petition in Intervention in the lawsuit to assert the same claims against the defendants. MOSH Holding, L.P., Dagger-Spine and Wiegand (collectively, "Plaintiffs") are unitholders in the Trust, which was created in 1982 as a partner in the general partnership that holds an overriding royalty interest in certain oil and gas leases offshore Louisiana and Texas (the Partnership). The Company owns the managing general partner interest in the Partnership. Plaintiffs allege that the Company, together with Woodside Energy (USA) Inc. ("Woodside"), concealed the value of the royalty interest and worked to terminate the Mesa Offshore Trust ("MOT") prematurely and to capture for itself and Woodside profits that belong to MOT. Plaintiffs also allege breaches of fiduciary duty, misapplication of trust property, common law fraud, gross negligence, and breach of the conveyance agreement for the overriding royalty interest. The relief sought by the Plaintiffs includes monetary and punitive damages and certain equitable relief, including an accounting of expenses, a setting aside of the farmout between the Company and Woodside, and a temporary and permanent injunction.

26

 

 

In July 2007, the Company filed a motion for summary judgment challenging Plaintiffs' standing to prosecute the case and seeking dismissal. The Company also filed a motion for summary judgment challenging the substantive merits of Plaintiffs' claims and seeking dismissal.

 

On May 30, 2008, the Company requested, via a conditional proposal to JP Morgan as Trustee, that JP Morgan carry out its obligation to effect the sale of the Partnership and Trust assets and the winding down of the Trust and the Partnership in accordance with the terms of the Trust's governing document. The Company's conditional proposal to the Trustee included an offer to sell the Company's working interest in Brazos Block A-39 in connection with the liquidation of the Trust (with the proceeds from such sale being paid to MOT). The Trustee has until August 12, 2008 to accept the offer and if not accepted, the offer will terminate and will be of no further effect.

 

In July 2008, the trial court denied the Company's two summary judgment motions. The Company subsequently filed an application for a writ of mandamus with the court of appeals seeking a reversal of the trial courts refusal to dismiss the lawsuit based upon Plaintiffs lack of standing. That application is currently pending before the court of appeals. Trial on the merits of the lawsuit is scheduled for December 2008, although it is unclear what effect, if any, the mandamus application may have on the trial schedule.

 

The Company believes the claims made by the Plaintiffs in the MOSH Holding lawsuit are without merit and intends to defend the lawsuit vigorously. The Company cannot predict whether the outcome of this proceeding will be adverse to the Company and if so, whether such an outcome will materially impact the Company's liquidity, financial position or future results of operations.

 

Equatorial Guinea Block H Arbitration. On June 14, 2007, a subsidiary of the Company ("Pioneer EG") commenced arbitration in London, England against Roc Oil (Equatorial Guinea) Company ("ROC EG"), Atlas Petroleum International Limited ("Atlas") and Osborne Resources Limited ("Osborne") to determine the parties' respective rights and obligations under a joint operating agreement relating to well operations in Block H in deepwater Equatorial Guinea. ROC, Atlas and Osborne have, in turn, brought counterclaims against Pioneer EG in respect to alleged breaches of the farm-in agreements relating to Block H. In late 2006, the Republic of Equatorial Guinea ratified a new hydrocarbons law, which among other things, appears to entitle Equatorial Guinea to increase substantially its carried interest in all concessions, including Block H, either directly or through the National Oil Company. In addition, drilling costs for the well have increased significantly beyond those originally anticipated.

 

Given these and other factors, Pioneer EG maintains that it does not have an obligation to approve the drilling of a well on the block. The view of the other parties is that Pioneer EG does not have the right to prevent the drilling of the well or to refuse to pay its share of the costs thereof. ROC EG, Atlas and Osborne have also notified Pioneer EG that they reserve the right to claim damages should they suffer any loss, including any loss suffered if the underlying production sharing contract is terminated by Equatorial Guinea.

 

The parties have consolidated their respective claims under the joint operating agreement and the farm-in agreements into a single arbitration scheduled to be conducted in London, England in September 2008. Pioneer EG intends to vigorously assert its position in the arbitration. The Company cannot predict whether the outcome of this proceeding will be adverse to the Company and if so, whether such an outcome will materially impact the Company's liquidity, financial position or future results of operations.

 

Colorado Notice of Violation. On May 13, 2008, the Company was served with a Notice of Violation/Cease and Desist Order by the State of Colorado Department of Public Health and Environmental Water Quality Control Division. The Notice alleges violations of stormwater discharge permits in the Company's Raton Basin and Lay Creek operations, specifically deficiencies in the Company's stormwater management plans, failure to implement and maintain best management practices to protect stormwater runoff and failure to conduct inspections of the stormwater management system. The Company has filed an answer to the Notice asserting defenses to the allegations. The Company does not believe that the outcome of this proceeding will materially impact the Company's liquidity, financial position or future results of operations.

 

 

 

 

SemGroup accounts receivable. The Company is a creditor in the bankruptcy of SemGroup, L.P. and certain of its subsidiaries (collectively, "SemGroup"), which filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code in July 2008. SemGroup purchases condensate from the Company and, at the time of the filings, was indebted to the Company for approximately $30 million, of which approximately $17.1 million was outstanding at June 30, 2008 and is currently delinquent. Incremental receivables for post-petition deliveries through July 31, 2008 are estimated to be approximately $5 million to $6 million.

 

The Company believes that it is reasonably possible that some or all of its pre-filing claims and claims for subsequent deliveries may be uncollectible in the future. If the Company were to subsequently determine that it was probable that some or all of the SemGroup pre-filing claims and claims for subsequent deliveries were uncollectible, it would reduce the carrying value of the corresponding receivables and recognize a pre-tax charge in the earnings of that period for the probable loss. The Company believes that any losses relating to its failure to collect its SemGroup claims would not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations.

 

The condensate supplied to SemGroup is produced from Pioneer's West Panhandle gas field and is processed at Pioneer's Fain plant in the Texas Panhandle. The Company has suspended its supply of condensate to SemGroup until assurance of payment for future deliveries is provided and has made arrangements to sell its condensate to alternate purchasers. The Company does not expect any disruption in its West Panhandle operations and sales as a result of these actions.

 

Obligations following divestitures. In April 2006, the Company provided the purchaser of its Argentine assets certain indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject to defined limitations. The Company does not believe that these obligations, which primarily pertain to matters of litigation, environmental contingencies, royalty obligations and income taxes, are probable of having a material impact on its liquidity, financial position or future results of operations.

 

The Company has also retained certain liabilities and indemnified buyers for certain matters in connection with other divestitures, including the sale in 2007 of its Canadian assets. The Company does not believe that such matters are probable of having a material impact on its liquidity, financial position or future results of operations.

 

Basic income per share from continuing operations is computed by dividing income from continuing operations by the weighted average number of common shares outstanding for the period. The computation of diluted income per share from continuing operations reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive to income from continuing operations were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company.

 

 

 

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2008 and 2007:

 

 

___________

 

 

The Company has operations in only one industry segment, that being the oil and gas exploration and production industry; however, the Company is organizationally structured along geographic operating segments or regions. The Company has reportable operations in the United States, South Africa and Tunisia.

As previously referred to in Note B, during 2007, the Company sold its Canadian assets having a carrying value of $424.4 million. The results of operations for those properties have been reclassified to discontinued operations in accordance with SFAS 144 and are excluded from the geographic operating segment information provided below. See Note Q for information regarding the Company's discontinued operations.

 

The following tables provide the Company's geographic operating segment data for the three and six months ended June 30, 2008 and 2007. Geographic operating segment income tax (provisions) benefits have been determined based on statutory rates existing in the various tax jurisdictions where the Company has oil and gas producing activities. The "Headquarters" table column includes income and expenses that are not routinely included in the earnings measures internally reported to management on a geographic operating segment basis and operations in Equatorial Guinea and Nigeria, where the Company concluded exploration activities during 2007.

 

 

 

 

 

 

 

 

 

 

 

 

 

United States. During the first quarter of 2008, events and circumstances indicated that (a) approximately $29.3 million of net assets in the Company's Mississippi area and (b) approximately $134.1 million of net assets in the Company's Piceance/Uinta area may have been partially impaired. The events and circumstances indicating a potential impairment in these areas are primarily related to downward adjustments to proved reserves associated with recent well performance. However, the Company's estimate of undiscounted future cash flows indicated that such carrying amounts were expected to be recovered. The Company's primary assumptions of the estimated future cash flows include (a) utilizing proved reserves and appropriate risk-adjusted probable and possible reserves and (b) management's commodity price outlook. Nonetheless, it is reasonably possible that the estimate of undiscounted future cash flows may change in the future resulting in the need to impair the assets' carrying values. The primary factors that may affect future cash flows are (a) additional reserve adjustments, both positive and negative, (b) results of future drilling activities, (c) management's outlook on commodity prices and (d) increases or decreases in production and capital costs associated with these assets.

 

During the second quarter of 2007, the Company recorded a $5.7 million impairment provision to reduce the carrying values of certain proved oil and gas properties located in the Company's onshore Gulf Coast area. The impairment provision was determined in accordance with SFAS 144, and reduced the carrying values of the assets to their estimated fair value.

 

Nigeria. In June 2007, the Company entered into an agreement to divest its interest in a subsidiary (owned 59 percent by the Company) that held the 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 during the second quarter of 2007 to reduce the net basis to the estimated fair value.

 

 

During 2005, the Company sold 27.8 MMBOE of proved reserves by means of three VPP agreements for net proceeds of $892.6 million, including the assignment of the Company's obligations under certain derivative hedge agreements. Proceeds from the VPPs were initially used to reduce outstanding indebtedness. The first VPP sold 58 Bcf of gas volumes over an expected five-year term that began in February 2005. The second VPP sold 10.8 MMBbls of oil volumes over an expected seven-year term that began in January 2006. The third VPP sold 6.0 Bcf of gas volumes over an expected 32-month term that began in May 2005 and 6.2 MMBbls of oil volumes over an expected five-year term that began in January 2006.

 

The Company's VPPs represent limited-term overriding royalty interests in oil and gas reserves that: (i) entitle the purchaser to receive production volumes over a period of time from specific lease interests; (ii) do not bear future production costs and capital expenditures associated with the reserves; (iii) are nonrecourse to the Company (i.e., the purchaser's only recourse is to the reserves acquired); (iv) transfer title of the reserves to the purchaser; and (v) allow the Company to retain the remaining reserves after the VPPs volumetric quantities have been delivered.

 

 

 

Under SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," a VPP is considered a sale of proved reserves. As a result, the Company (i) removed the proved reserves associated with the VPPs; (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to oil and gas revenues over the term of each VPP; (iii) retained responsibility for 100 percent of the production costs and capital costs related to VPP interests; and (iv) no longer recognizes production associated with the VPP volumes.

 

 

 

The above deferred revenue amounts will be recognized in oil and gas revenues in the Consolidated Statements of Operations as noted below, assuming the related VPP production volumes are delivered as scheduled (in thousands):

 

 

 

 

 

NOTE O.      Interest and Other Income

 

 

 

_____________

 

 

As a result of Hurricane Rita in September 2005, the Company's East Cameron facility, located in the Gulf of Mexico shelf, was destroyed. The Company currently estimates that it will cost approximately $176 million to reclaim and abandon the East Cameron facility. The operations to reclaim and abandon the East Cameron facilities began in January 2007. The estimate to reclaim and abandon the East Cameron facility is based upon an analysis prepared by a third party engineering firm for a majority of the work, an estimate by the Company for the remaining work that was not covered by the third-party analysis and actual abandonment activity to date.

 

The $176 million estimate to reclaim and abandon the East Cameron facilities contains a number of assumptions that could cause the ultimate cost to be higher or lower as there are many uncertainties when working offshore and underwater with damaged equipment and wellbores. The Company currently believes costs could range from $176 million to $190 million; however, at this point no better estimate than any other amount within the range can be determined, thus the Company has recorded the estimated provision of $176 million, of which approximately $118.9 million has been expended through June 30, 2008.

 

34

 

 

 

The Company filed a claim with its insurance providers regarding the loss at East Cameron. Under the Company's insurance policies, the East Cameron facility had the following coverages: (a) $14 million of scheduled property value for the platform, which was received in 2005, (b) $4 million of scheduled business interruption insurance after a deductible waiting period, which was received in 2006, (c) $100 million of well restoration and safety, in total, for all assets per occurrence and (d) $400 million for debris removal coverage for all assets per occurrence.

 

In the first quarter of 2007, the Company received $5 million from one of its insurance providers related to debris removal. At the present, no recoveries have been reflected related to certain costs associated with plugging and abandonment and the well restoration and safety coverages. In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues, primarily related to debris removal, certain costs associated with plugging and abandonment, and the well restoration and safety coverages. The Company continues to expect that a substantial portion of the loss will be recoverable from insurance.

 

 

In April 2006 and November 2007, the Company completed the sale of its Argentine assets and Canadian subsidiaries, respectively. Pursuant to SFAS 144, the Company has reflected the results of operations of these transactions as discontinued operations, rather than as a component of continuing operations. The following table represents the components of the Company's discontinued operations for the three and six months ended June 30, 2008 and 2007:

 

___________

 

 

 

Financial and Operating Performance

 

The Company's financial and operating performance for the second quarter of 2008 included the following highlights:

 

 

Third Quarter 2008 Outlook

 

Based on current estimates, the Company expects that third quarter 2008 production will average 114,000 to 119,000 BOEPD. Production growth during the third quarter of 2008 will be driven primarily by increasing production in the Spraberry field, Edwards Trend and Tunisia. The lower end of the range primarily reflects the typical variability in the timing of oil cargo shipments in South Africa and Tunisia.

 

Third quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $13.50 to $14.50 per BOE based on early August NYMEX strip prices for oil and gas. Depletion, depreciation and amortization ("DD&A") expense is expected to average $10.75 to $11.75 per BOE.

 

Total exploration and abandonment expense is expected to be $40 million to $70 million and could include up to $45 million from activities in the Company's resource plays in the Edwards Trend in South Texas and Tunisia, and $25 million in seismic investments, personnel costs and other costs.

 

General and administrative expense is expected to be $35 million to $39 million. Interest expense is expected to be $36 million to $40 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million. Minority interest in consolidated subsidiaries' net income is expected to be $8 million to $10 million, primarily reflecting the public ownership in Pioneer Southwest.

 

The Company's third quarter 2008 effective income tax rate is expected to range from 40 percent to 50 percent based on current capital spending plans and cash taxes are estimated to be $30 million to $40 million, primarily attributable to operations in Tunisia.

 

The forecasted production range and expense estimates above include the portion of Pioneer Southwest that is attributable to the public's ownership in Pioneer Southwest.

 

 

 

SemGroup Accounts Receivable

 

The Company is a creditor in the bankruptcy of SemGroup, L.P. and certain of its subsidiaries (collectively, "SemGroup"), which filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code in July 2008. SemGroup purchases condensate from the Company and, at the time of the filings, was indebted to the Company for approximately $30 million, of which approximately $17.1 million was outstanding at June 30, 2008 and is currently delinquent. Incremental receivables for post-petition deliveries through July 31, 2008 are estimated to be approximately $5 million to $6 million.

 

The Company believes that it is reasonably possible that some or all of its pre-filing claims and claims for subsequent deliveries may be uncollectible in the future. If the Company were to subsequently determine that it was probable that some or all of the SemGroup pre-filing claims and claims for subsequent deliveries were uncollectible, it would reduce the carrying value of the corresponding receivables and recognize a pre-tax charge in the earnings of that period for the probable loss. The Company believes that any losses relating to its failure to collect its SemGroup claims would not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations.

 

The condensate supplied to SemGroup is produced from Pioneer's West Panhandle gas field and is processed at Pioneer's Fain plant in the Texas Panhandle. The Company has suspended its supply of condensate to SemGroup until assurance of payment for future deliveries is provided and has made arrangements to sell its condensate to alternate purchasers. The Company does not expect any disruptions in its West Panhandle operations and sales as a result of these actions.

 

Operations and Drilling Highlights

 

The Company intends to limit 2008 capital expenditures, excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs, to less than internally-generated operating cash flow. During the first half of 2008, the Company spent approximately $639 million of capital, excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs. During the third quarter of 2008, Pioneer increased its 2008 capital budget from $1.0 billion to $1.3 billion (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) to reflect drilling efficiencies, operational success and the current higher cost environment, primarily for tubulars, fuel and pumping costs. Drilling efficiencies in the Spraberry and Edwards fields are allowing wells to be drilled at a faster than expected pace, which will result in the Company drilling and completing more wells than originally expected during 2008. Development capital related to drilling success in the Edwards Trend and progressing front-end engineering planning for the Cosmopolitan project in Alaska is also being added to the 2008 budget.

 

 

 

         The following table summarizes by geographic area the Company's finding and development costs incurred during the first half of 2008:

 

 

The following table summarizes the Company's development and exploration/extension drilling activities for the six months ended June 30, 2008:

 

 

 

Permian Basin area. The Company's Spraberry field production volumes increased by approximately 21 percent during the first half of 2008, as compared to the first half of 2007. Production from the Spraberry field exceeded expectations due to incremental Wolfcamp formation contributions, operating efficiencies and a faster drilling pace resulting from improved drilling efficiencies. The Company drilled and tested 197 wells in the first half of 2008, principally in the Spraberry field, and currently has 17 rigs drilling in the field. Based on improved drilling efficiencies and operating margins, Pioneer has increased the 2008 Spraberry field drilling program from 350 wells to 390 wells. The majority of these Spraberry wells are being drilled deeper to add the Wolfcamp formation, which provide incremental production and proved reserves.

 

During the first half of 2008, the Company initiated a program to test 20-acre well downspacing performance as part of its announced recovery improvement initiatives, which also include secondary recovery waterflood projects, shale interval testing and fracturing previously unstimulated horizontal wells. Associated therewith, the Company intends to apply for Spraberry field rule changes with the Texas Railroad Commission during the third quarter of 2008. The Company has tested and evaluated over 120 days of production from three 20-

 

 

 

acre wells drilled during the first quarter of 2008, and plans to drill approximately 25 20-acre wells during 2008 and at least 40 20-acre wells during 2009.

 

The Company's Spraberry field waterflood project includes plans to drill 20 to 35 water injection wells during the first half of 2009, with water injection expected to begin during the third quarter of 2009. During the first half of 2008, the Company also drilled two Spraberry vertical wells to test non-traditional shale intervals. The Company has plans to drill two additional wells to further test the shale intervals. Additionally, the Company re-entered and fractured three existing horizontal open hole completions during the first half of 2008, plans to fracture two additional existing horizontal wells during the second half of 2008 and plans to drill five new horizontal wells during 2009. The Company is also continuing to pursue acreage expansion opportunities and bolt-on acquisitions in the area.

 

The 20-acre and waterflood initiatives described above are being performed to enhance the Spraberry field recovery rates in those areas of the field that are both ideal for 20-acre infill drilling and contiguous acreage that is conducive to waterflood recoveries. However, the ultimate incremental recovery rates associated with these initiatives cannot be predicted at this time.

 

Midkiff-Benedum Gas Processing System. The Company owns a 27 percent interest in the Spraberry Midkiff-Benedum gas processing system (the System) in West Texas and, in July 2007, entered into an agreement with Atlas Pipeline Partners (Atlas) under which the Company obtained an option to purchase an additional 22 percent interest in the System for $230 million, subject to normal closing adjustments. The option may be exercised for up to an additional 14.56 percent interest in 2008, and any unexercised portion of the option may be exercised in 2009.

 

The Company has informed Pioneer Southwest that it is considering assignment of the portion of the option that is exercisable in 2008 to Pioneer Southwest. The transaction terms of the possible assignment from the Company have not been determined at this time. However, any such assignment would be subject to negotiation of definitive agreements and the approval of the board of directors of the general partner of Pioneer Southwest and the Conflicts Committee of the board. There can be no assurance that the Company will assign all or any portion of the option to Pioneer Southwest or as to the terms of any such assignment.

 

Mid-Continent area. The Company continues to pursue field enhancement alternatives to optimize production in the area. In the Hugoton field, the Company has received regulatory approval to commingle production from the Chase and Council Grove formations. A commingling pilot program has been initiated and the Company continues to monitor its production performance. Pioneer has also received regulatory relief to increase the well density in certain portions of the West Panhandle field, which has added future drilling locations.

 

Rocky Mountains area. The Company's Raton Basin production volumes increased approximately 24 percent during the first half of 2008, as compared to the first half of 2007. The production growth is principally attributable to production added from properties acquired by the Company in December 2007 and the production added from the Company's ongoing development drilling program. During the first quarter 2008, the Company announced a discovery in one zone of the Pierre Shale that lies beneath a portion of the Company's Raton Basin coal bed methane acreage. The Company remains encouraged by the drilling and testing results to-date from the initial Pierre Shale zone. The Company also confirmed contributions from two additional Pierre Shale zones. During the first half of 2008, the Company drilled 82 wells in the Raton coal bed methane field and nine were drilled in the Pierre Shale. During 2008, the Company plans to drill a total of approximately 160 wells in the Raton coal bed methane field and 15 wells are planned for the Pierre Shale. The Company is also enhancing its gathering and compression facilities in the area. Current plans include increased drilling in the Raton coal bed methane field and Pierre Shale during 2009. To accommodate longer-term production growth in the Raton Basin, the Company added firm pipeline capacity to transport 75 MMcfpd from the Raton Basin to the West Coast gas markets beginning in 2011.

 

In western Colorado and eastern Utah, the Company's programs to evaluate the CBM resource potential at Lay Creek, Castlegate and Columbine Springs are progressing.

 

Onshore Gulf Coast area. The Company's United States onshore Gulf Coast area gas production increased approximately 56 percent during the first half of 2008, as compared to the first half of 2007. The Company drilled

 

 

 

22 wells in the Edwards Trend during the first half of 2008 and expects to drill 18 additional wells in the Edwards Trend during the second half of 2008. As a result of reduced drilling time related to rig improvements and wellbore design enhancements, the Company has expanded its 2008 drilling program from 35 wells to 40 wells in the Edwards Trend. The Company continues to add infrastructure, primarily gas treating capacity and pipeline systems, to accommodate the expanded drilling program and higher producing rates from recent well completions. The Company estimates that it will add 20 to 45 MMcfpd of additional treating capacity over the remainder of 2008.

 

In the Edwards Trend, the Company also continues its shooting and interpretation of approximately 900 square miles of 3-D seismic data over its new field discoveries, which is expected to be completed by the end of 2008. The seismic data will allow the Company to more accurately locate and orient the horizontal wells for optimal results.

 

Barnett Shale. During the first half of 2008, the Company participated in the drilling of four successful exploration wells on the approximate 80,000 gross acres in the Barnett Shale play that it acquired in 2007. The Company plans to drill approximately 25 wells during 2008, including eight wells operated by others, with the expectation of increasing its drilling program in 2009.

 

Alaska area. On the Oooguruk project, the Company continued development drilling operations and commenced production in the month of June. Gross production averaged approximately 2,400 barrels per day during June and early July. Production was shut in mid-July for scheduled maintenance at third-party, onshore production facilities. Production is expected to resume following the completion of maintenance work in late August. Development drilling is expected to continue through the remainder of 2008 and beyond.

 

On the Cosmopolitan project, the Company drilled a lateral sidetrack during 2007 from an existing wellbore from an onshore site to further appraise the resource potential of the unit. The initial unstimulated production test results were encouraging. The Company will conduct permitting activities and facilities planning over the remainder of 2008 and plans to drill another appraisal well in 2009.

 

South Africa. First production from the Company's South Coast Gas project commenced late in the third quarter of 2007 from four wells and sales commenced in the fourth quarter of 2007. A significant portion of the gas reserves associated with the South Coast Gas project is in the Sable field. Late in the third quarter of 2008, it is anticipated that Sable oil production will be shut in to convert Sables gas injection well to a producing well. The Sable gas well is expected to be the most productive well in the South Coast Gas project.

 

Tunisia. In the Adam Concession, the Company drilled three successful appraisal wells in the first half of 2008 with a fourth well drilling as of the end of the second quarter. All three successful appraisal wells are currently on production and the Company plans to evaluate the results of the fourth well during the third quarter 2008. Furthermore, during the first half of 2008 the Company acquired an additional 279 square kilometers of 3-D seismic data, which will provide 3-D coverage over the entire concession area.

 

In the Cherouq Concession, first sales occurred during the first quarter of 2008. The Company drilled two exploration wells with a third well drilling as of the end of the second quarter. One of the exploration wells was determined to be a discovery and is currently on production whereas the other well is being evaluated prior to completion and testing. To accommodate planned production growth, the Company has expanded gross facility production capacity to 10 MBOE per day. The Company plans to increase production capacity to 20 MBOE per day during the fourth quarter. The Company also acquired an additional 295 square kilometers of 3-D seismic data over the Cherouq Concession during the first half of 2008 and is currently processing and evaluating the data.

 

In the Anaguid permit, the Company acquired an additional 900 square kilometers of 3-D seismic data, which is being processed and evaluated prior to drilling up to two exploration wells in the second half of 2008.

 

In the Borj El Khadra Permit, the Company drilled one successful exploration well and acquired 700 linear kilometers of 2-D seismic data in the first half of 2008. During the remainder of 2008, the Company plans to drill one additional exploration well and complete the processing of the seismic data.

 

 

 

 

Results of Operations

 

Oil and gas revenues. Oil and gas revenues from continuing operations totaled $653.3 million and $1.2 billion for the three and six months ended June 30, 2008, respectively, as compared to $419.8 million and $773.4 million for the same respective periods of 2007.

 

The increase in oil and gas revenues from continuing operations during the three and six months ended June 30, 2008, as compared to the same periods of 2007, is reflective of increases in revenues for all operating segments. The increase in revenues in the United States was due to increases in average reported oil, natural gas liquids ("NGL") and gas prices and volume increases primarily resulting from successful drilling activity and reductions in scheduled volumetric production payment ("VPP") deliveries. Revenues in Tunisia increased due to increases in average reported oil and gas prices combined with increased oil volumes due to successful drilling programs and first sales from the Cherouq Concession. Gas sales volumes decreased in Tunisia during the three and six month periods ended June 30, 2008, as compared to the comparable 2007 periods when gas sales were initiated. South African revenues increased due to increases in reported oil prices and 2008 gas sales from the South Coast Gas project, which recorded first gas sales during the fourth quarter of 2007. Oil volumes decreased during the second quarter of 2008, as compared to the second quarter of 2007, due to normal Sable production declines and the timing of oil liftings.

 

The following table provides average daily sales volumes from continuing operations, by geographic area and in total, for the three and six months ended June 30, 2008 and 2007:

 

 

On a quarter-to-quarter BOE comparison, average daily sales volumes increased by 18 percent in the United States, by 22 percent in South Africa and by 37 percent in Tunisia. For the six months ended June 30, 2008, as compared to the six months ended June 30, 2007, average daily BOE sales volumes increased by 21 percent in the United States, by 37 percent in South Africa and by 21 percent in Tunisia.

 

During the three and six month periods ended June 30, 2008, as compared to the three and six month periods ended June 30, 2007, oil volumes delivered under the Company's VPPs decreased by 40 MBOE (5 percent) and 75 MBOE (5 percent), respectively, while gas volumes delivered under the Company's VPPs decreased by 127 MBOE (22 percent) and 248 MBOE (21 percent), respectively.

 

 

 

The oil, NGL and gas prices that the Company reports are based on the market price received for the commodities adjusted by the results of the Company's cash flow hedging activities and the amortization of deferred VPP revenue. The following table provides average reported prices from continuing operations (including the results of hedging activities and the amortization of deferred VPP revenue) and average realized prices from continuing operations (excluding the results of hedging activities and the amortization of deferred VPP revenue) by geographic area and in total, for the three and six months ended June 30, 2008 and 2007:

 

 

As seen in the above table, NGL prices for the second quarter of 2008 did not increase proportionately to the increase in oil prices. Historically, the Company's NGL price realizations have been approximately 55 percent to 60 percent of NYMEX oil price; however, in the second quarter of 2008 the Company's NGL price realizations decreased to approximately 46 percent of the average NYMEX oil price for the period. The decrease is primarily due to propane and ethane prices (the principal components of the Company's NGL stream) not increasing proportionately with NYMEX oil prices due to the supply and demand fundamentals specific to those products.

 

Hedging activities. The Company utilizes commodity swap and collar contracts to (i) reduce the impact on the Company's results of operations from the price volatility of 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 the three and six months ended June 30, 2008, the Company's commodity price hedges decreased oil, NGL and gas revenues from continuing operations by $163.6 million and $244.2 million, respectively, as compared to decreasing oil and gas revenues from continuing operations by $21.3 million and $48.3 million during the same respective periods of 2007. 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.

 

 

 

Deferred revenue. During the three and six months ended June 30, 2008, the Company's amortization of deferred VPP revenue increased oil and gas revenues from continuing operations by $39.5 million and $78.9 million, respectively, as compared to increases of $45.3 million and $90.4 million during the same respective periods of 2007. See Notes G and N of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for specific information regarding the Company's VPPs.

 

Interest and other income. Interest and other income from continuing operations for the three and six months ended June 30, 2008 was $8.5 million and $33.5 million, respectively, as compared to $26.2 million and $37.6 million for the same respective periods in 2007. The $17.7 million decrease in interest and other income from continuing operations during the three months ended June 30, 2008, as compared to the same period in 2007, was primarily due to an $18.4 million decrease in Alaskan Petroleum Production Tax ("PPT") credit dispositions realized during the second quarter of 2008 versus the second quarter of 2007. The $4.1 million decrease in interest and other income from continuing operations during the six months ended June 30, 2008, as compared to the same period in 2007, was primarily due to a $7.2 million decrease in the aforementioned PPT credit, partially offset by $4.4 million of 2008 positive adjustments to asset retirement obligations. See Note O of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

 

Oil and gas production costs. The Company recorded oil and gas production costs from continuing operations of $144.5 million and $277.2 million during the three and six months ended June 30, 2008, respectively, as compared to $105.4 million and $194.8 million for the same respective periods of 2007. 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 and ad valorem taxes are directly related to commodity price changes and third-party transportation charges are related to volumes produced. Total oil and gas production costs per BOE from continuing operations increased by 15 percent and 17 percent during the three and six months ended June 30, 2008, as compared to the same periods in 2007, primarily due to (i) increases in production taxes due to commodity price increases and (ii) increases in lease operating expense, due to fixed production costs associated with declining South African Sable oil production, initial production operations in the Tunisian Cherouq concession, unscheduled compressor repairs and maintenance in the Raton field and general inflation of oilfield service costs and electricity charges, partially offset by (iii) declines in ad valorem taxes, primarily resulting from the effects of tax reform legislation in Texas.

 

The following tables provide the components of the Company's total oil and gas production costs per BOE from continuing operations and total oil and gas production costs per BOE from continuing operations by geographic area for the three and six months ended June 30, 2008 and 2007:

 

 

 

 

 

 

Depletion, depreciation and amortization expense. The Company's total DD&A expense from continuing operations was $114.7 million ($11.06 per BOE) and $224.3 million ($10.99 per BOE) for the three and six months ended June 30, 2008, respectively, as compared to $88.2 million ($10.11 per BOE) and $167.0 million ($9.97 per BOE) during the same respective periods of 2007. The increases of $26.5 million and $57.3 million in total DD&A expense during the three and six months ended June 30, 2008, as compared to the same respective periods in 2007, are primarily comprised of increases in depletion of oil and gas properties of $26.3 million and $56.6 million, respectively.

 

Depletion expense from continuing operations was $10.36 per BOE and $10.28 per BOE during the three and six months ended June 30, 2008, respectively, as compared to $9.31 per BOE and $9.14 per BOE during the same respective periods in 2007. The 11 percent and 12 percent increases in per BOE depletion expense from continuing operations during the three and six months ended June 30, 2008, respectively, as compared to the same periods in 2007, 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 and (ii) the relatively higher depletion rate per BOE associated with production from the South Coast Gas project in South Africa.

 

The following table provides depletion expense per BOE from continuing operations by geographic area for the three and six months ended June 30, 2008 and 2007:

 

 

 

 

 

         Exploration and abandonments expense. The following tables provide the Company's geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense from continuing operations by geographic area for the three and six months ended June 30, 2008 and 2007:

 

 

The Company's exploration and abandonment expense from continuing operations during the three and six month periods ended June 30, 2008 is primarily attributable to continued seismic activity in the Company's Edwards Trend and Tunisian plays and modest leasehold abandonment and dry hole expense. During the three and six month periods ended June 30, 2007, the Company's exploration and abandonment expense included dry hole and leasehold abandonment and other exploration expenses of $40.6 million and $84.8 million, respectively, of which $23.2 million was attributable to unsuccessful exploration of Block 256 in the deepwater offshore Nigeria. The remainder was primarily related to dry holes and related leasehold abandonment expenses attributable to exploration in the North Slope of Alaska and Tunisia.

 

The significant decline in the Company's dry hole and abandonment expenses during 2008 as compared to 2007 is a result of the Company's decision in 2007 to exit operations in West Africa and allocate increasing portions of its capital spending to development activities in the United States. During the first half of 2008, the Company drilled and evaluated 19 exploration/extension wells, 18 of which were successfully completed as discoveries. During the same period in 2007, the Company drilled and evaluated 34 exploration/extension wells, 23 of which were successfully completed as discoveries. The decline in the number of exploration/extension wells drilled by the Company is primarily due to the Company's sale of its Canadian assets during November 2007 and the aforementioned strategic initiatives.

 

General and administrative expense. General and administrative expense from continuing operations for the three and six months ended June 30, 2008 were $35.5 million and $72.0 million, respectively, as compared to $29.4 million and $62.0 million during the same respective periods of 2007. The increase in general and administrative expense from continuing operations was primarily due to an increase in performance-related compensation costs, including the amortization of share-based compensation to officers, directors and employees. As of June 30, 2008,

 

 

 

the Company had $61.3 million of deferred compensation expense related to unvested restricted stock awards that will be charged to earnings over a weighted average remaining period of approximately 24 months. The Company continues to monitor its general and administrative expense and is focused on administrative cost control. However, the Company anticipates that the ongoing administration of Pioneer Southwest will over time necessitate an increase in the Company's general and administrative expenses.

 

Accretion of discount on asset retirement obligations.Accretion of discount on asset retirement obligations from continuing operations was $2.2 million and $4.3 million for the three and six months ended June 30, 2008, respectively, as compared to $1.7 million and $3.3 million during the same respective periods of 2007. The increase in accretion of discount on asset retirement obligations during 2008 is primarily due to new wells placed on production. See Note H of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding the Company's asset retirement obligations.

 

Interest expense. Interest expense from continuing operations was $38.3 million and $75.7 million for the three and six months ended June 30, 2008, respectively, as compared to $30.5 million and $59.0 million during the same respective periods of 2007. The weighted average interest rate on the Company's indebtedness for the three and six months ended June 30, 2008, including the effects of interest rate derivatives and capitalized interest, was 5.5 percent for each period as compared to 6.5 percent and 6.6 percent for the same respective periods in 2007. The increase in interest expense from continuing operations during the three months ended June 30, 2008, as compared to the same period of 2007, was primarily due to (i) a $4.2 million decrease in capitalized interest on the Company's South Coast Gas development project in South Africa and (ii) a $2.9 million increase in interest on senior notes borrowings. The increase in interest expense from continuing operations during the six months ended June 30, 2008, as compared to the same period of 2007, was primarily due to (i) an $11.5 million increase in interest on senior notes borrowings and (ii) a $6.5 million decrease in capitalized interest on the Company's Oooguruk and South Coast Gas development projects in Alaska and South Africa. Capitalized interest on the Company's Oooguruk project in Alaska will continue at a declining rate as development wells are completed and placed on production.

 

Hurricane activity, net. The Company recorded net hurricane related activity expenses of $1.4 million and $1.9 million during the three and six months ended June 30, 2008, respectively, and $47.0 million and $60.5 million during the same respective periods of 2007, associated with the Company's East Cameron platform facility, located on the Gulf of Mexico shelf, which was destroyed during 2005 by Hurricane Rita.

 

The Company estimates that it will cost approximately $176 million to reclaim and abandon the East Cameron facility, of which amount approximately $118.9 million has been expended through June 30, 2008. The operations to reclaim and abandon the East Cameron facilities began in January 2007. The estimate to reclaim and abandon the East Cameron facility is based upon an analysis prepared by a third party engineering firm for a majority of the work, an estimate by the Company for the remaining work that was not covered by the third-party analysis and actual abandonment activity to date. During 2007, the Company commenced legal actions against its insurance carriers regarding certain policy coverage issues. The Company continues to expect that a substantial portion of the loss will be recoverable by insurance. See Note P of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for specific information regarding the Company's East Cameron facility reclamation and abandonment.

 

Minority interest in consolidated subsidiaries' net income (loss). Minority interest in consolidated subsidiaries' net income from continuing operations for the three and six months ended June 30, 2008 were $6.2 million and $7.0 million, respectively, as compared to $199 thousand and a loss of $1.2 million for the same respective periods in 2007. The increase is primarily due to $5.1 million of minority interest in the net income of Pioneer Southwest attributable to the period from May 6, 2008 (the date of completion of the IPO) through June 30, 2008. See Notes B and R of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for specific information regarding the IPO of Pioneer Southwest and the Company's minority interest in consolidated subsidiaries' net income (loss).

 

Other expenses. Other expenses from continuing operations for the three and six months ended June 30, 2008 were $9.0 million and $19.9 million, respectively, as compared to $7.0 million and $14.7 million for the same respective periods in 2007. The $2.0 million increase in other expenses for the three months ended June 30, 2008, is primarily attributable to (i) a $5.8 million increase in the cost of idle drilling equipment and (ii) a $3.4 million

 

 

 

increase in rig impairment charges, partially offset by (iii) a $3.8 million decrease in legal contingency accrual adjustments and (iv) $4.3 million in litigation settlement recoveries. The $5.2 million increase in other expenses for the six months ended June 30, 2008, is primarily attributable to (i) a $11.9 million increase in the cost of idle drilling equipment and (ii) the $3.4 million rig impairment charge, partially offset by (iii) a $6.1 million decrease in legal contingency accrual adjustments and (iv) the $4.3 million litigation settlement recovery.

 

Income tax provision. The Company recognized income tax provisions on continuing operations of $125.8 million and $213.0 million during the three and six month ended June 30, 2008, respectively, as compared to $16.6 million and $31.2 million during the same respective periods of 2007. The increases in income tax provisions during the three and six months ended June 30, 2008, as compared to the respective periods of 2007, were primarily due to increases in income from continuing operations before income taxes, reflecting increasing commodity prices and sales volumes. The Company's effective tax rate on continuing operations of 44 percent and 43 percent during the three and six months ended June 30, 2008, respectively, differs from the combined United States federal and state statutory rate of approximately 37 percent primarily due to:

 

 

See Note E of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's income taxes.

 

Discontinued operations. In April 2006 and November 2007, the Company sold its Argentine assets and Canadian subsidiaries. The historic results of these transactions and the related gains on disposition are reported as discontinued operations. See Note Q of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding discontinued operations.

 

Capital Commitments, Capital Resources and Liquidity

 

Capital commitments. The Company's primary needs for cash are for development, exploration and acquisition of oil and gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs, as well as funding for any stock repurchases that the Company may undertake, may be provided by any combination of internally-generated cash flow, proceeds from the disposition of nonstrategic assets or alternative financing sources as discussed in "Capital resources" below.

 

Oil and gas properties. The Company's cash expenditures for additions to oil and gas properties during the three and six months ended June 30, 2008, totaled $319.3 million and $616.6 million, respectively, as compared to $536.2 million and $974.8 million for the same respective periods of 2007. During the three and six months ended June 30, 2008, the Company's expenditures for additions to oil and gas properties were funded by $333.1 million and $510.7 million of net cash provided by operating activities and, for the six months ended June 30, 2008, $130.8 million of the remaining proceeds received in January 2008 from the sale of the Company's Canadian assets in November 2007. During the three and six months ended June 30, 2007, the Company's expenditures for additions to oil and gas properties were funded by $217.4 million and $347.4 million, respectively, of net cash provided by operating activities and borrowings on the Company's credit facility.

 

Contractual obligations, including off-balance sheet obligations. The Company's contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, other liabilities, transportation commitments and VPP obligations. 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 June 30, 2008, the material off-balance sheet arrangements and transactions that the Company has entered into included (i) undrawn letters of credit, (ii) operating lease agreements, (iii) drilling and transportation 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. 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. Since December 31, 2007, the material changes in the Company's contractual obligations included a $113.0 million decrease in outstanding long-term borrowings, a $78.9 million decrease in the Company's VPP obligations, a $518.5 million increase in the Company's net derivative obligations, a $110.8 million decrease in the Company's drilling commitments and, subject to counterparty performance contingencies, a $534 million increase in the Company's transportation commitments. See Note F of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's long-term debt and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for information regarding the interest on the Company's long-term debt and a table of changes in the fair value of the Company's open derivative obligations during the six months ended June 30, 2008.

 

In accordance with GAAP, the Company periodically measures and records certain financial assets and liabilities at fair value. Effective January 1, 2008, the Company adopted the provisions of SFAS 157 for which delayed adoption is not provided under FSP FAS 157-1. SFAS 157 retains the exchange price notion in the definition of fair value but clarifies that the exchange price is the price in an orderly transaction between market participants to sell an asset or transfer a liability in the principal or most advantageous market in which the reporting company would transact for the asset or liability.

 

The financial assets and liabilities that the Company periodically measures and records at fair value include trading securities, deferred compensation plan assets, commodity derivative contracts and interest rate derivative contracts. See Note D of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding these financial assets and liabilities and the valuation techniques used to measure their fair values.

 

The Company's commodity and interest rate derivative contracts that are periodically measured and recorded at fair value represent those derivatives that continue to be subject to market or credit risk. As of June 30, 2008, these contracts represented liabilities of $824.3 million, including terminated hedges no longer subject to market risk. The ultimate liquidation value of the Company's commodity and interest rate derivatives will be dependent upon actual future commodity prices and interest rates, which may differ materially from the inputs used to determine the derivatives' fair values as of June 30, 2008. The Company enters into these derivatives for the primary purpose of hedging commodity price risk on forecasted physical commodity sales and interest rate risk on variable rate indebtedness and has an expectation of a high degree of correlation between changes in the derivative values and the hedged risks. See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information about the Company's derivative instruments and market risk.

 

Capital resources. The Company's primary capital resources are net cash provided by operating activities, proceeds from financing activities and proceeds from sales of nonstrategic assets. The Company expects that these resources will be sufficient to fund its capital commitments during the foreseeable future. For 2008, the Company expects that cash flow from operations will be sufficient to fund the Company's capital expenditures, excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs.

 

Asset divestitures. In November 2007, the Company sold all of the common stock of its Canadian subsidiaries for net proceeds of $525.7 million, $132.8 million of which was deposited in a Canadian escrow account pending receipt from the Canada Revenue Agency of appropriate tax certifications. The tax certifications were received in January 2008 and the escrowed funds were subsequently released to the Company.

 

 

 

         Operating activities. Net cash provided by operating activities during the three and six months ended June 30, 2008 was $333.1 million and $510.7 million, respectively, as compared to $217.4 million and $347.4 million for the same respective periods in 2007. The increase in net cash provided by operating activities during the three and six month periods ended June 30, 2008, as compared to the same periods in 2007, is primarily due to increased sales volumes and increased oil, NGL and gas prices from continuing operations, partially offset by increased production costs.

 

Investing activities. Investing activities used $313.9 million and $491.5 million of cash during the three and six months ended June 30, 2008, respectively, as compared to $539.0 million and $986.4 million for the same respective periods in 2007. The decrease in net cash used in investing activities during the second quarter of 2008, as compared to the second quarter of 2007, is primarily due to a $216.8 million decrease in additions to oil and gas properties and a $7.9 million decrease in additions to other assets and other property and equipment, net. The decrease in net cash used in investing activities during the first half of 2008, as compared to the first half of 2007, is primarily due to a (i) $358.2 million decrease in additions to oil and gas properties, (ii) a $9.0 million decrease in additions to other assets and other property and equipment, net and (iii) a $127.7 million increase in proceeds from disposition of assets, primarily comprised of a portion of the proceeds from the 2007 sale of the Company's Canadian subsidiaries, which were released from escrow during the first quarter of 2008.

 

Financing activities. Net cash provided by financing activities during the three and six months ended June 30, 2008 was $6.9 million and $11.9 million, respectively, as compared to $333.1 million and $656.7 million during the same respective periods in 2007. The decrease in net cash provided by financing activities during the three and six months ended June 30, 2008, as compared to the same periods of 2007, was primarily due to net principal payments on long term debt during the 2008 periods, partially offset by $166.0 million of proceeds from the issuance of Pioneer Southwest common units.

 

On January 15, 2008, $3.8 million principal amount of the Company's 6.50% senior notes matured and were paid.

 

During January 2008, the Company issued $500 million principal amount of 2.875% convertible senior notes due 2038 (the "2.875% Senior Convertible Notes") and received proceeds, net of approximately $11.3 million of underwriter discounts and offering costs, of approximately $488.7 million. The Company used the net proceeds from the offering to reduce outstanding borrowings under the Credit Facility. See Note F of Notes to Consolidated Financial Statements included in Item 1. Financial Statements for additional information regarding the 2.875% Senior Convertible Notes.

 

During April 2008, the Company paid $16.8 million of aggregate dividends ($0.14 per common share). Future dividends and the timing and amount thereof are at the discretion of the Board.

 

During February 2007, the Board approved a share repurchase program authorizing the purchase of up to $750 million of the Company's common stock. During the six months ended June 30, 2008 and 2007, the Company expended $12.8 million to acquire 293 thousand shares of treasury stock and $54.2 million to acquire 1.3 million shares of treasury stock, respectively, under share repurchase programs. As of June 30, 2008, approximately $524.5 million of stock may be purchased in the future under the $750 million Board authorization.

 

On May 6, 2008, Pioneer Southwest, a subsidiary of the Company, completed its initial public offering of 9,487,500 common units, representing a 31.6 percent limited partner interest in Pioneer Southwest. Pioneer Southwest owns interests in certain oil and gas properties previously owned by the Company in the Spraberry field in the Permian Basin of West Texas. The Company owns a 0.1 percent general partner interest and a 68.3 percent limited partner interest in Pioneer Southwest. The Company received $166.0 million of net proceeds from Pioneer Southwest in consideration for (i) an ownership interest in a subsidiary of the Company that owned the oil and gas properties prior to the initial public offering and (ii) an incremental ownership interest in certain of the same properties as a result of the exercise of the over-allotment option. The net proceeds from the initial public offering were used to reduce the Company's outstanding indebtedness. The Company consolidates Pioneer Southwest into its financial statements and reflects the public ownership as a minority interest in Pioneer Southwests net assets.

 

 

 

In conjunction with the completion of the initial public offering, Pioneer Southwest completed a $300 million unsecured revolving credit facility with a syndicate of banks, which matures in May 2013 (the Pioneer Southwest Credit Facility). The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions.

 

See Notes B and F of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the formation of Pioneer Southwest and the Pioneer Southwest Credit Facility, respectively.

 

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 cash on hand and unused borrowing capacity under its credit facility. There was $500 million of borrowings under the credit facility as of June 30, 2008. After deducting $45.8 million of undrawn and outstanding letters of credit under the credit facility, the Company had $954.2 million of unused borrowing capacity as of June 30, 2008.

 

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. The Company believes that S&P and Moody's consider many factors in determining the Company's ratings including: production growth opportunities, liquidity, debt levels and asset and proved reserve mix. A reduction in the Company's debt ratings could negatively impact the Company's ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. As of June 30, 2008, the Company was in compliance with all of its debt covenants.

 

Book capitalization and current ratio. The Company's book capitalization at June 30, 2008 was $5.7 billion, consisting of debt of $2.6 billion and stockholders' equity of $3.1 billion. The Company's debt to book capitalization was 46 percent and 48 percent at June 30, 2008 and December 31, 2007, respectively. The Company's ratio of current assets to current liabilities was 0.64 to 1.00 at June 30, 2008 as compared to 0.77 to 1.00 at December 31, 2007.

 

New accounting pronouncements. In September 2006, the FASB issued 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. During February 2008, the FASB issued FSP FAS 157-2. FSP FAS 157-2 delayed the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis at least annually. On January 1, 2008, the Company adopted the provisions of SFAS 157 for financial assets and liabilities. See Note D of Notes to Consolidated Financial Statements included in "Item 1 Financial Statements" for additional information regarding the Company's adoption of SFAS 157. The adoption of the provisions of SFAS 157 that were delayed by FSP FAS 157-2 is not expected to have a material effect on the financial condition or results of operations of the Company.

 

In February 2007, the FASB issued 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. The Company adopted the provisions of SFAS 159 on January 1, 2008 and its implementation did not have a material effect on the financial condition or results of operations of the Company.

 

In December 2007, the FASB issued SFAS 141(R). SFAS 141(R) replaces SFAS 141 and provides greater consistency in the accounting and financial reporting of business combinations. SFAS 141(R) requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction and any noncontrolling interest in the acquired entity at the acquisition date, measured at the fair value as of that date. This includes the measurement of the acquirer shares issued in consideration for a business combination, the recognition

 

 

 

of contingent consideration, the accounting for pre-acquisition gain and loss contingencies, the recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition-related transaction costs and the recognition of changes in the acquirer's income tax valuation allowance and deferred taxes. SFAS 141(R) is effective for fiscal years and interim periods within those fiscal years, beginning on or after December 15, 2008, and is to be applied prospectively as of the beginning of the fiscal year in which the statement is applied. The implementation of SFAS 141(R) is not expected to have a material effect on the financial condition or results of operations of the Company.

 

In December 2007, the FASB issued SFAS 160. SFAS 160 amends ARB No. 51, "Consolidated Financial Statements," to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as a minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure of the amounts of consolidated net income attributable to the parent and to the non-controlling interest on the face of the consolidated income statement. SFAS 160 is effective for the Company on January 1, 2009 and is not expected to have a significant impact on the Company's financial statements.

 

In March 2008, the FASB issued SFAS 161. SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities by requiring entities to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS 161 is effective for the Company on January 1, 2009 and will only impact future disclosures about the Company's derivative instruments and hedging activities

 

On May 9, 2008, the FASB issued FSP APB 14-1. FSP APB 14-1 specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entitys nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. FSP APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008. The adoption of FSP APB 14-1 will increase the annual interest expense that the Company recognizes on its $500 million 2.875% Senior Convertible Notes from an annual yield of approximately 2.875 percent to an annual yield equivalent to a nonconvertible debt borrowing. The adoption of FSP APB 14-1 will also result in the reclassification of the estimated issuance date fair value of the 2.875% Senior Convertible Notes conversion privilege from long-term debt to shareholders equity in the Company's consolidated balance sheet. The Company is assessing the equivalent nonconvertible debt borrowing rate and the fair value of the conversion privilege.

 

During May 2008, the FASB issued SFAS No. 162. SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements presented in conformity with GAAP. SFAS 162 is effective 60 days following the SEC's approval of the Public Company Accounting Oversight Board amendments to AU Section 411, "The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles". The Company does not expect that the adoption of SFAS 162 will have a significant impact on the Company's financial statements.

 

In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1 (Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF 03-6-1), which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the net income allocation in computing basic net income per share under the two class method prescribed under SFAS 128 Earnings per Share. FSP 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and, to the extent applicable, must be applied retrospectively by adjusting all prior-period net income per share data to conform to the provisions of the standard. The Company is assessing the effect that FSP EITF 03-6-1 will have on its net income per share calculations.

 

 

 

Item 3.        Quantitative and Qualitative Disclosures About Market Risk

 

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company's Annual Report on Form 10-K for the year ended December 31, 2007. As such, the information contained herein should be read in conjunction with the related disclosures in the Company's Annual Report on Form 10-K for the year ended December 31, 2007.

 

Although certain derivative contracts to which the Company has been a party did not qualify as hedges, the Company does not enter into derivative or other financial instruments for trading purposes.

 

The following table reconciles the changes that occurred in the fair values of the Company's open derivative contracts during the first half of 2008:

 

 

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Interest rate sensitivity. See Note F of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and Capital Commitments, Capital Resources and Liquidity included in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information regarding debt transactions.

 

 

 

         The following table provides information about financial instruments to which the Company was a party as of June 30, 2008 and that are sensitive to changes in interest rates. For debt obligations, the table presents maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions and the debt's estimated fair value. For fixed rate debt, the weighted average interest rate represents the contractual fixed rates that the Company was obligated to periodically pay on the debt as of June 30, 2008. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on August 4, 2008.

 

Interest Rate Sensitivity

Debt and Interest Rate Derivative Financial Instruments as of June 30, 2008

 

 

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        Commodity price sensitivity. The following table provides information about the Company's oil and gas derivative financial instruments that were sensitive to changes in oil, NGL or gas price as of June 30, 2008. As of June 30, 2008, all of the Company's oil, NGL and gas derivative financial instruments qualified as hedges.

 

See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for information regarding the terms of the Company's derivative financial instruments that are sensitive to changes in oil, NGL or gas prices as well as hedge volumes and weighted average prices by calendar quarter.

 

Oil, NGL and Gas Price Sensitivity

Derivative Financial Instruments as of June 30, 2008

 

 

 

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Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 ("the Exchange Act"), the Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of the Company's disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms and is accumulated and communicated to the Company's management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

 

Changes in internal control over financial reporting. There have been no changes in the Company's internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the Company's last fiscal quarter that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting.

 

 

 

PART II. OTHER INFORMATION

 

 

The Company is party to the legal proceedings that are described under "Legal actions" in Note J of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements." The Company is also party to other proceedings and claims incidental to its business. While many of these other matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations.

 

 

In addition to the other information set forth in this Report, you should carefully consider the risks discussed in the Company's Annual Report on Form 10-K for the year ended December 31, 2007, under the headings "Item 1. Business Competition, Markets and Regulations," "Item 1A. Risk Factors" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk," as updated by the discussion in Part II of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, under the heading "Item 1A. Risk Factors," which risks could materially affect the Company's business, financial condition or future results. There has been no material change in the Company's risk factors from those described in the Annual Report on Form 10-K, as updated by that Quarterly Report on Form 10-Q.

 

These risks are not the only risks facing the Company. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may materially adversely affect the Company's business, financial condition or future results.

 

 

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

 

The following table summarizes the Company's purchases of treasury stock during the three months ended June 30, 2008:

 

 

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During 2007, the Board approved a share repurchase program authorizing the purchase of up to $750 million of the Company's common stock.

 

 

 

Item 4.         Submission of Matters to a Vote of Security Holders

 

The Company's annual meeting of stockholders was held on May 16, 2008 in Irving, Texas. At the meeting, two proposals were submitted for a vote of stockholders (as described in the Company's Proxy Statement dated April 4, 2008). The following is a brief description of each proposal and results of the stockholders' votes.

 

Election of Directors. Prior to the meeting, the Board designated four nominees as Class II Directors with their terms to expire at the annual meeting in 2011 when their successors are elected and qualified. James R. Baroffio, Edison C. Buchanan, Scott D. Sheffield and Jim A. Watson were, at the time of such nomination and at the time of the meeting, directors of the Company. Each nominee was elected as a director of the Company, with the results of the stockholder voting being as follows:

 

 

In addition, the term of office for the following directors continued after the annual meeting: R. Hartwell Gardner, Linda K. Lawson, Andrew D. Lundquist, Charles E. Ramsey, Jr., Frank A. Risch, Mark S. Sexton and Robert A. Solberg.

 

Ratification of selection of independent auditors. The engagement of Ernst & Young LLP as the Company's independent auditors for 2008 was submitted to the stockholders for ratification. Such engagement was ratified, with the results of the stockholder voting being as follows:

 

 

 

Exhibits

 

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(a) Filed herewith.

(b) Furnished herewith.

 

 

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereto duly authorized.

 

 

 

 

 

 

 

Exhibit Index

 

 

 

_____________

(a) Filed herewith.

(b) Furnished herewith.