Delaware		75-2702753
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
5205 N. O'Connor Blvd., Suite 200, Irving, Texas		75039
(Address of principal executive offices)		(Zip Code)

(972) 444-9001

(Registrant's telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Large accelerated filer	x		Accelerated filer	o
Non-accelerated filer	o	(Do not check if a smaller reporting company)	Smaller reporting company	o

Number of shares of Common Stock outstanding as of November 5, 2008

117,689,829

11/7/2008 11:17:33 AM

 

 

 

 

 

 

 

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, the financial strength of counterparties to the Company's credit facility and derivative contracts and the purchasers of the Company's oil, NGL and gas production, 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, the 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 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 September 30, 2008 and for the three and nine months ended September 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 R for additional information regarding discontinued operations.

 

Allowances for doubtful accounts. As of September 30, 2008 and December 31, 2007, the Company's allowances for doubtful accounts totaled $35.4 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 periods during which failure to collect an estimable portion is determined to be probable.

 

Inventories. Inventories consisted of $142.5 million and $94.3 million of materials and supplies and $3.6 million and $3.3 million of commodities as of September 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, net in the consolidated statements of operations. As of September 30, 2008 and December 31, 2007, the Company's materials and supplies inventory was net of $0.3 million and $1.1 million, respectively, of valuation reserve allowances.

 

Derivative assets and liabilities. In accordance with Financial Accounting Standards Board ("FASB") Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts" ("FIN 39"), the Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, whichever the case may be.

 

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 2008, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment.

 

Minority interest in consolidated subsidiaries. On May 6, 2008, Pioneer Southwest Energy Partners L.P. ("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. Associated therewith, the Company recognized $166.0 million of net proceeds from the issuance of Pioneer Southwest common units in net cash provided by financing activities in the Company's consolidated statement of cash flows for the nine months ended September 30, 2008 and recognized a $133.1 million noncash gain on the sale of Pioneer Southwest common units in the Company's consolidated statement of stockholders' equity. 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 financial position, results of operations, and cash flows of Pioneer Southwest are consolidated with those of the Company. The Company elected to account for gains on Pioneer Southwest's issuance of common units as equity transactions as permitted by Staff Accounting Bulletin ("SAB") Topic 5H, "Accounting for Sales of Stock by a Subsidiary".

 

In addition to Pioneer Southwest, the Company owns the majority interests in certain other subsidiaries with operations in the United States. Minority interest in the net assets of consolidated subsidiaries totaled $57.9 million and $11.9 million as of September 30, 2008 and December 31, 2007, respectively, which are included as liabilities in the accompanying consolidated balance sheets. Minority interest in the net income (loss) of the Company's consolidated subsidiaries was a net expense of $8.4 million and $15.4 million for the three and nine months ended September 30, 2008, respectively (principally related to Pioneer Southwest), and a net expense of $172 thousand and income of $1.0 million for the three and nine months ended September 30, 2007, respectively.

 

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 awards' vesting periods based on their fair values on the dates of grant. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the stock price on the date of grant for the fair value of restricted stock awards and (iii) the Monte Carlo simulation method for the fair value of performance unit awards.

 

For the three and nine months ended September 30, 2008, the Company recorded $8.3 million and $25.5 million of stock-based compensation costs for all plans, respectively, as compared to $8.5 million and $24.8 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 September 30, 2008 and December 31, 2007, do not include 1,086,349 and 1,960,475, respectively, of unvested issued and voting shares awarded under stock-based compensation plans.

 

The following table summarizes all stock-based awards, lapses and forfeitures that occurred during the nine months ended September 30, 2008:

 

 

 

 

 

         As of September 30, 2008, there was approximately $57.3 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 their remaining vesting periods, which on a weighted average basis is approximately 27 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 their fair values as of the date that the acquirer achieves control over the business acquired. This includes the measurement of the acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the recognition of pre-acquisition contractual and certain non-contractual gain and loss contingencies, the recognition of capitalized research and development costs and the recognition of changes in the acquirer's income tax valuation allowance and deferred taxes. The provisions of SFAS 141(R) also require that restructuring costs resulting from the business combination that the acquirer expects but is not required to incur and costs incurred to effect the acquisition be recognized separate from the business combination. 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 (i) how and why an entity uses derivative instruments, (ii) 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 (iii) 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 entity's 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 States Securities 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 adoption of FSP EITF 03-6-1 is not expected to have a material effect on the Company's 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 nine months ended September 30, 2008:

 

_____________

 

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

 

 

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

 

 

 

 

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 September 30, 2008, for each of the fair value hierarchy levels:

 

 

The following table presents the changes in the fair values of the Company's net commodity price derivative liabilities 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, to a lesser extent, 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 September 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 derivatives. 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. In accordance with FIN 39, the Company classifies derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties. The Company's derivative assets and liabilities are comprised of assets and liabilities due from derivative counterparties that are net derivative creditors or net derivative debtors of the Company as of September 30, 2008. Net derivative asset transfer values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates are based on an independent market-quoted credit default swap rate curve for the Company's or the counterparties' debt plus the United States Treasury Bill yield curve as of September 30, 2008. The net derivative asset values attributable to the Company's interest rate derivative contracts as of September 30, 2008 are based on (i) the contracted notional amounts, (ii) forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative asset measurements represent Level 2 inputs in the hierarchy priority.

 

Commodity price derivatives. The Company's commodity price derivatives represent oil, NGL and gas swap and collar contracts. The Company's commodity price 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 asset and liability values attributable to the Company's oil derivatives as of September 30, 2008 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar contracts. 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 asset and liability values attributable to the Company's NGL derivatives as of September 30, 2008 are based on (i) the contracted notional volumes, (ii) independent broker-supplied forward Mont Belvieu-posted-price quotes and (iii) the applicable 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 swap contracts that convert the HH price index point to other price indexes. The asset and liability values attributable to the Company's gas derivatives as of September 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 applicable 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 September 30, 2008 and December 31, 2007, the Company's valuation allowances (relating primarily to foreign tax jurisdictions) were $33.7 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 September 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 interest charges with respect to income taxes as interest expense and any penalties, with respect to income taxes, as other expense in the consolidated statements of operations. The Company files income tax returns in the U.S. federal 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 September 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 nine months ended September 30, 2008, the Company recorded $2.3 million and $12.0 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 nine months ended September 30, 2008 and 2007:

 

_____________

(a)        The Company's effective tax rate for the three months ended September 30, 2008 is unusually high, primarily as a result of the Company consolidating a U.S. loss with foreign income in high tax jurisdictions.

 

 

 

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

 

 

 

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 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 September 30, 2008, the Company had $679.0 million of outstanding borrowings under the Credit Facility and $45.8 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $775.2 million of unused borrowing capacity under the Credit Facility.

 

Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $150 million. Revolving loans bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by JPMorgan Chase Bank or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus .5 percent or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the "Applicable Margin") that is determined by a reference grid based on the Company's debt rating (currently .75 percent). Swing line loans bear interest at a rate per annum equal to the "ASK" rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus .125 percent.

The Credit Facility contains certain financial covenants, which include the maintenance of a ratio of total debt to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset impairments not to exceed .60 to 1.0. The covenants also include the maintenance of a ratio of the net present value of the Company's oil and gas properties to total debt of at least 1.75 to 1.0 until the Company achieves an investment grade rating by Moody's Investors Service, Inc. or Standard & Poors Ratings Group, Inc.

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 Southwest's consolidated leverage ratio. Base rate committed loans bear interest annually at a base rate equal to the higher of (i) the Federal Funds Rate plus 0.5 percent or (ii) the Bank of America prime rate (the "Base Rate") plus a

 

 

 

margin (currently zero percent). Swing line loans bear interest annually at the Base Rate plus the Applicable Rate. As of September 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 may 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. Generally, the Company does not enter into derivative financial instruments for speculative or trading purposes. The Company may also enter into physical delivery contracts that effectively hedge commodity prices. 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.

 

Derivative instruments are recorded in the consolidated balance sheets at their estimated fair values. 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 are later transferred to earnings when the hedged transaction occurs. Changes in the fair values of derivatives that are not designated as hedges, as well as the ineffective portions of hedge derivatives, are recorded in earnings. The ineffective portions of hedge derivatives are calculated as the differences between the changes in fair value of the derivatives and the estimated changes 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 the Company's costs of capital. As of September 30, 2008 and December 31, 2007, the Company was not a party to any 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 September 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 September 30, 2008:

 

 

_____________

 

 

 

         The Company reports average oil prices per Bbl including the effects of oil quality adjustments, amortization of 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 VPP revenue) and realized (excluding hedge results and amortization of VPP revenue), (ii) amortization of 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 nine months ended September 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-posted-prices per Bbl for those contracts as of September 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 nine months ended September 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 September 30, 2008:

 

 

_____________

 

 

 

The Company reports average gas prices per Mcf including the effects of Btu content, gas processing, shrinkage adjustments, amortization of 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 VPP revenue) and realized (excluding hedge results and amortization of VPP revenue), (ii) amortization of 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 nine months ended September 30, 2008 and 2007:

 

_____________

Interest rates. 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 had an effective start date of February 2008, with $200 million terminating during February 2010 and $200 million during February 2011. The Company did not record any ineffectiveness in connection with the interest rate swap contracts.

Hedge ineffectiveness. During the three and nine months ended September 30, 2008, the Company recorded net ineffectiveness charges of $5.0 million and $4.6 million, as compared to net ineffectiveness charges of $1.0 million and $1.9 million for the three and nine months ended September 30, 2007. Hedge ineffectiveness represents the ineffective portions of changes in the fair values of the Company's cash flow hedging instruments.  The primary causes of hedge ineffectiveness are changes in forecasted hedged sales volumes and commodity price correlations.

AOCI - Hedging. As of September 30, 2008 and December 31, 2007, AOCI - Hedging represented net deferred losses of $90.4 million and $228.3 million, respectively. The AOCI - Hedging balance as of September 30, 2008 was comprised of $56.6 million of net deferred losses on the effective portions of open cash flow hedges, $84.2 million of net deferred losses on terminated cash flow hedges (including $2.9 million of net deferred losses on terminated cash flow interest rate hedges) and $50.4 million of associated net deferred tax benefits. The decrease in net deferred hedge losses comprising AOCI - Hedging during the nine months ended September 30, 2008 was primarily attributable to decreases in future oil, NGL and gas prices relative to the commodity prices stipulated in the hedge contracts and the reclassification of net deferred hedge losses to net income as derivatives matured. Decreases in forward interest rate yield curves also reduced the fair value of 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 September 30, 2009, based on current estimates of future commodity prices and interest rates, the Company expects to reclassify approximately $53.9 million of net deferred losses associated with open commodity and interest rate hedges and $48.7 million of net deferred losses on terminated commodity hedges from AOCI - Hedging to oil and gas revenues and interest expense. The Company also expects to reclassify approximately $37.9 million of net deferred income tax benefits associated with commodity and interest rate hedges during the twelve months ending September 30, 2009 from AOCI - Hedging to income tax benefit or as a reduction to the income tax provision.

 

 

 

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 approximate the low price of the commodity prior to the scheduled settlement of the open commodity hedge position. These terminations allow 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 during which the hedged production was scheduled to occur.

The following table sets forth, as of September 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 nine months ended September 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 September 30, 2008 and December 31, 2007, the current portion of the Company's asset retirement obligations amounted to $29.0 million and $86.9 million, respectively.

 

As of September 30, 2008 and December 31, 2007, the Company had recorded $9.9 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 September 30, 2008 or December 31, 2007. Other than participants in 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 nine months ended September 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 the other proceedings and claims involve inherent uncertainty, the Company believes that the amount of the liabilities, 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 legal actions 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 (the "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 ("Unitholder Group") each filed a Petition in Intervention in the lawsuit to assert the same claims against the defendants. The Unitholder Group was recently voluntarily non-suited leaving only Dagger-Spine and MOSH Holding, L.P. as Plaintiffs/Interveners in this lawsuit (collectively MOSH Holding L.P. and Dagger-Spine are referred to as "Plaintiffs"). Plaintiffs are unit holders 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. Plaintiffs also allege that the Company did not act as a prudent operator regarding certain activities undertaken with respect to a producing well and that the Company should have undertaken to drill additional wells for the benefit of the Partnership. 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.

 

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.

 

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 as well as request for a stay of the trial proceedings with the court of appeals seeking a reversal of the trial court's refusal to dismiss the lawsuit based upon Plaintiffs' lack of standing. That application and stay motion were denied by the court of appeals, and the Company appealed both denials to the Texas Supreme Court, where the appeal is currently pending. Trial on the merits of the lawsuit is scheduled for March 30, 2009, although it is unclear what effect, if any, the mandamus application may have on the trial schedule.

 

On October 10, 2008, the Company unconditionally offered without compensation its complete interest, including its working interest, in the Brazos Block A-39 tract to Plaintiffs and to the Trustee (on behalf of all the unit holders). To date, Plaintiffs and the Trustee have neither accepted nor rejected the Company's tender.

 

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 EG, Atlas and Osborne in turn, brought counterclaims against Pioneer EG in respect to alleged breaches of the farm-in agreements relating to Block H. On September 4, 2008, the parties entered into a settlement agreement whereby Pioneer EG will pay the Block H parties the aggregate amount of $5.5 million, transfer all of Pioneer EG's interest in Block H to the other parties and assign to ROC EG Pioneer's option to a slot on a deepwater drill ship. The settlement is conditioned upon the Government of Equatorial Guinea's consent to the transfer of Pioneer EG's interest in Block H to the other parties and the novation of the optional drill slot under the operative drill ship agreements to ROC EG.

 

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 purchased condensate from the Company and, at the time of the bankruptcy filings, was indebted to the Company for approximately $29.6 million, of which approximately $17.1 million was outstanding at June 30, 2008 and approximately $12.5 million represented amounts owing to the Company for purchased condensate from July 1 through the date of the bankruptcy filings. Subsequent to the bankruptcy filings, SemGroup continued to purchase condensate from the Company until the end of July 2008, at which time the Company suspended condensate sales to SemGroup. During August 2008, SemGroup paid the Company approximately $5.3 million, representing amounts due for post-petition purchases. As of September 30,

 

 

 

2008, the Company had approximately $29.6 million of delinquent receivables from SemGroup, representing pre-petition claims.

 

The Company believes that it is probable that the collection of the pre-petition claims will not occur for a protracted period of time and that some of its claims may be uncollectible. Consequently, the Company recorded a bad debt expense of approximately $19.6 million during the three months ended September 30, 2008, which reduced the carrying value of the claims to approximately $10.0 million.

 

SemGroup's reorganization effort is still in its early stages and determination of the exact amount of uncollectible claims is not presently determinable. It is reasonably possible that the Company will not collect the claims or that collected amounts will be less than $10.0 million. If those circumstances occur, the Company would recognize additional bad debt expense to further reduce the carrying value of its claims. 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 was produced from Pioneer's West Panhandle gas field and processed at Pioneer's Fain plant in the Texas Panhandle. During August 2008, the Company began selling its condensate to alternate purchasers. The Company has not experienced 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. During periods that the Company realizes a loss from continuing operations, securities or other contracts to issue common stock would be dilutive to loss per share and conversion into common stock is assumed not to occur.

 

 

 

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

 

_____________

 

 

The Company's only operations are oil and gas exploration and producing activities; 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 R for information regarding the Company's discontinued operations.

 

The following tables provide the Company's geographic operating segment data for the three and nine months ended September 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 nine months of 2008, events and circumstances indicated that (a) approximately $24.5 million of net assets in the Company's Mississippi area and (b) approximately $130.0 million of net assets in the Company's Uinta/Piceance 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 declines in commodity prices and well performance. The Company's estimate, as of September 30, 2008, of undiscounted future cash flows attributed to the Mississippi assets indicated that their carrying amounts were expected to be recovered. However, the Company's estimate, as of September 30, 2008, of the undiscounted future cash flows attributable to the Uinta/Piceance area assets indicated that their carrying amounts were not expected to be recovered. Consequently, the Company recorded an $89.8 million noncash charge during the three months ended September 30, 2008 to reduce the Uinta/Piceance area assets' carrying amounts to their estimated fair value, represented by the estimated discounted future cash flows attributable to the assets.

 

The Company's primary assumptions of the estimated future cash flows are based on (a) proved reserves and appropriate risk-adjusted probable and possible reserves and (b) management's commodity price outlook. It is reasonably possible that the Company's estimate of undiscounted future cash flows attributable to the Mississippi assets or other assets may change in the future resulting in the need to impair such assets' carrying amount. 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) changes in management's outlook on commodity prices and (d) increases or decreases in production and capital costs associated with these assets.

 

During the nine months ended September 30, 2007, the Company recorded a $5.7 million impairment provision to reduce the carrying values of certain proved oil and gas properties located in 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. Also, as a result of due diligence efforts that emerged as part of the Company's compliance efforts, and with assistance from outside counsel, the Company determined that it could not, consistent with its legal obligations, fund or approve future operations in connection with Block 320. As a result, during the third quarter of 2007, the Company engaged in a process to withdraw from the production sharing contract relating to Block 320 and related agreements. As a part of this process, the Company transferred the shares in its Nigeria subsidiary to an unaffiliated third party. During the nine months ended September 30, 2007, the Company recorded a $9.6 million impairment charge related to the exit from Nigeria, including a $2.6 million decrease to the impairment charge during the three months ended September 30, 2007.

 

 

 

 

NOTE N.       Volumetric Production Payments

 

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 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 from May 2005 through December 2007, 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 $200 million. Currently, no better estimate within the range can be determined. Thus the Company has recorded the estimated provision of $176 million, of which approximately $149.6 million has been expended through September 30, 2008.

 

 

 

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.

 

 

 

 

_____________

 

 

 

NOTE R.      Discontinued Operations

 

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 nine months ended September 30, 2008 and 2007:

 

____________

 

 

 

Financial and Operating Performance

 

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

 

 

Recent Events

 

Financial markets. During the third quarter of 2008, worldwide financial markets experienced significant turmoil as concerns regarding a worldwide economic slowdown increased and the availability of liquidity provided by the financial markets declined. These concerns have continued into the fourth quarter of 2008. In response to these circumstances, governments worldwide have taken steps to enhance confidence in and support for the financial markets. The success of the steps taken and the duration of the uncertainty in financial markets cannot be predicted. The Company is closely monitoring the economic environment, but does not expect the current market conditions to significantly impact its liquidity, financial position or future results of operations.

 

As of September 30, 2008, the Company had $66.8 million of cash and equivalents and $2.8 billion in outstanding long-term debt, with $775.2 million of liquidity under its senior unsecured credit facility that matures in 2012. As of September 30, 2008, the Company was also a party to derivative financial instruments, of which approximately $50.4 million represent assets. Accordingly, management is closely monitoring the credit standings of its counterparties, including its banks, purchasers and derivative counterparties.

 

Commodity prices. The reduced liquidity provided by the worldwide financial markets and other factors have resulted in an economic slowdown in the United States and other industrialized countries. Concerns that this slowdown will impact energy demand have contributed to a significant drop in commodity prices from their highs earlier in 2008. The price of gas, and gas price differentials in the areas the Company produces gas relative to NYMEX quoted prices, have been negatively impacted by increasing supplies resulting from the rise in domestic unconventional production. The duration and magnitude of the commodity price declines cannot be predicted.

 

Low price environment initiatives. As a result of the significant drop in commodity prices, the Company has started implementing initiatives to reduce capital spending and preserve financial flexibility. Specifically, the Company is implementing a plan for a near-term $60 per Bbl of oil and $6 per Mcf of gas environment. This plan includes minimizing drilling activities until margins improve as a result of (i) commodity prices increasing, (ii) gas price differentials in the areas where the Company produces gas narrowing relative to NYMEX quoted prices and/or (iii) well cost reductions. As a result, the Company is reducing its rig activity by approximately 60 percent and is pursuing reductions in well costs to align costs with the lower commodity price environment that currently exists. Rigs are being terminated or stacked in the Spraberry, Raton, Edwards Trend, Barnett Shale and Mid-Continent

 

 

 

areas. The Company is also reducing the number of well service units running in the Spraberry field from 42 to 30, 15 of which are lower-cost well service units that are owned by Pioneer.

 

In 2009, the Company expects to reduce the capital budget by 30 percent to 60 percent compared to 2008. Even with a significantly reduced capital budget in 2009, Pioneer expects 5 percent to 10 percent production growth. The low end of the production growth estimate reflects a $60 per Bbl/$6 per Mcf environment, while the high end of the range reflects early November strip prices.

 

Hurricanes Gustav and Ike. During the first two weeks of September 2008, Hurricanes Gustav and Ike struck the Louisiana and Texas gulf coasts. The following areas of Texas and Louisiana were adversely impacted:

 

Spraberry. The Company's Spraberry facilities in West Texas were not directly impacted by either hurricane. This field produces oil and associated liquid-rich gas. The gas includes natural gas liquids ("NGLs") which are separated at various Permian Basin plants. These NGLs are then transported to a third-party facility in Mont Belvieu, Texas for fractionation. This facility sustained power interruptions and physical damage from Hurricane Ike, disrupting its ability to receive the Company’s NGLs. As a result, a portion of the Company's Spraberry and other Permian Basin area production has been shut-in or curtailed since early September while repairs and maintenance to the facility are being completed. The Company expects to be able to restore full production by mid-November.

 

Fort Worth Barnett Shale. The Company's Barnett Shale facilities were not directly impacted by the recent hurricanes. However, as in the Spraberry field, the Company's Barnett Shale gas includes NGLs that are processed at the Mont Belvieu fractionation facilities. However, the Company only experienced a temporary shut-in of its Barnett Shale production, and production was fully resumed by the end of September.

 

South Texas Edwards Trend. No significant hurricane damage occurred at the Company's facilities in the Edwards Trend area of South Texas. However, power interruptions to third-party pipelines which transport gas production from the field resulted in the temporary curtailment of portions of the Company's total Edwards Trend net production.

 

Gulf of Mexico Shelf. The Company's shallow-water offshore platforms did not experience any significant damage as a result of the hurricanes. However, production of approximately 1,800 BOEPD has been shut-in since August 31 due to the significant damage that has been incurred by the third-party pipeline facilities utilized to transport production to shore. The pipeline facilities have been repaired and production is expected to be restored by mid-November.

 

SemGroup receivables.The Company is a creditor in the bankruptcy of SemGroup, which filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code in July 2008. SemGroup purchased condensate from the Company and, at the time of the bankruptcy filings, was indebted to the Company for approximately $29.6 million, of which approximately $17.1 million was outstanding at June 30, 2008 and approximately $12.5 million represented amounts owing to the Company for purchased condensate from July 1 through the date of the bankruptcy filings. Subsequent to the bankruptcy filings, SemGroup continued to purchase condensate from the Company until the end of July 2008, at which time the Company suspended condensate sales to SemGroup. During August 2008, SemGroup paid the Company approximately $5.3 million, representing amounts due for post-petition purchases. As of September 30, 2008, the Company had approximately $29.6 million of delinquent receivables from SemGroup, representing pre-petition claims.

 

The Company believes that it is probable that the collection of the pre-petition claims will not occur for a protracted period of time and that some of its claims may be uncollectible. Consequently, the Company recorded a bad debt expense of approximately $19.6 million during the three months ended September 30, 2008, which reduced the carrying value of the claims to approximately $10.0 million.

 

SemGroup's reorganization effort is still in its early stages and determination of the exact amount of uncollectible claims is not presently determinable. It is reasonably possible that the Company will not collect the claims or that collected amounts will be less than $10.0 million. If those circumstances occur, the Company would recognize additional bad debt expense to further reduce the carrying value of its claims. 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. See Notes J of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's SemGroup bankruptcy claims.

 

Fourth Quarter 2008 Outlook

 

Based on current estimates, the Company expects that fourth quarter 2008 production will average 114,000 to 119,000 BOEPD. Production growth during the fourth quarter of 2008 will be driven primarily by increasing production in the Spraberry field, Edwards Trend and Tunisia, plus a full quarter of production from the Company's, Alaska Oooguruk project and increased production as a result of the start-up of the most productive well in the South Coast Gas project in South Africa. Fourth quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $14.00 to $15.00 per BOE based on early November NYMEX strip prices for oil and gas. Depletion, depreciation and amortization ("DD&A") expense is expected to average $13.00 to $14.00 per BOE, an increase over prior quarters due to lower anticipated year-end commodity prices, which will have the effect of lowering proved reserves as a result of certain wells becoming uneconomical to produce earlier than in a higher commodity price environment.

 

Total exploration and abandonment expense is expected to be $40 million to $70 million and could include up to $45 million from drilling and seismic activities in the Company's resource plays in the Edwards Trend in South Texas, the Rockies 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 also expects to recognize approximately $40 million to $45 million of charges in other expense associated with certain drilling rigs being terminated or stacked as a result of the Company's low price environment initiatives discussed above.

 

The Company's fourth 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 $15 million to $20 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.

 

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 ("Net Capital"), to internally-generated operating cash flow. During the nine month period ended September 30, 2008, the Company spent approximately $947 million of Net Capital.

 

 

 

         The following table summarizes by geographic area the Company's finding and development costs incurred during the nine month period ended September 30, 2008:

 

 

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

 

 

 

Permian Basin area. The Company drilled 291 wells during the nine months ended September 30, 2008, principally in the Spraberry field. The Company currently has 16 rigs drilling in the field, but has started implementing its plans to reduce the rig count until well costs are reduced to reflect current commodity prices. Under a reduced drilling program for 2008, the Company expects to drill approximately 360 wells. The majority of these Spraberry wells are being drilled deeper to add the Wolfcamp formation, which provides incremental production and proved reserves.

 

During the nine months 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. In conjunction with its improvement initiatives, during the third quarter of 2008, the Company applied for Spraberry field rule changes with the Railroad Commission of Texas to allow for optional 20-acre well downspacing. The rule changes were approved during the fourth quarter of 2008. The Company has drilled nine 20-acre wells in 2008 and the results are encouraging.

 

 

 

The Company is also pursuing waterflooding activities, non-traditional shale/silt internal testing and horizontal well testing initiatives. The Company's Spraberry field waterflood project includes plans to initiate drilling injection wells during the first half of 2009, with water injection expected to begin during the third quarter of 2009. The Company is currently evaluating non-traditional shale/silt intervals in two wells and plans to test these intervals in eight additional wells before year end. Additionally, the Company reentered and fractured three existing horizontal open hole completions during the nine months ended September 30, 2008, plans to fracture two additional existing horizontal wells during the fourth quarter of 2008. The Company is also continuing to evaluate acreage expansion opportunities and bolt-on acquisitions in the area.

 

The 20-acre well spacing and other initiatives described above are being performed to enhance the Spraberry field recovery rates in those areas of the field that are expected to be ideal for 20-acre infill drilling and 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 options to purchase an additional aggregate 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 entered into negotiations with Pioneer Southwest relating to the assignment of the portion of the option that is exercisable in 2008. However, the Company and Pioneer Southwest have decided not to pursue the assignment or acquisition of an interest in the System in 2008 due to the uncertainty underlying current market conditions. The Company will consider the assignment of the option, or some portion thereof, to Pioneer Southwest in the future if market conditions indicate that doing so is expected to be financially accretive to the Company and Pioneer Southwest. 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 its Conflicts Committee. There can be no assurance 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 is continuing to enhance field production through production optimization and gathering efficiency in both the Hugoton and West Panhandle fields. In the Hugoton field, the Company has proceeded with plans to test 16 wells under regulatory relief received during 2007 that allows Pioneer to commingle production from the Chase and Council Grove formations. This initiative is expected to increase Hugoton field operating efficiencies and available well locations. In the West Panhandle field, the Company is drilling four Brown Dolomite wells on recently acquired acreage in the fourth quarter of 2008.

 

Rocky Mountains area. The Company's Raton Basin production volumes increased approximately 10 percent during the nine months ended September 30, 2008, as compared to the nine months ended September 30, 2007. The production growth is principally attributable to production added from properties acquired by the Company in December 2007 and 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 and has drilled two horizontal Pierre Shale wells to assess its potential. Initial results from the horizontal drilling indicate a high frequency of natural fracturing. Fracing operations are underway on the first well and are being designed for the second well. During the first nine months of 2008, the Company drilled 136 wells in the Raton coal bed methane field and 11 were drilled in the Pierre Shale. During 2008, the Company plans to drill a total of approximately 146 wells in the Raton coal bed methane field and 11 wells are planned for the Pierre Shale. The Company is also enhancing its gathering and compression facilities in the area. 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 the Piceance Basin located in western Colorado and the Uinta Basin located in Utah, the Company's pilot programs to evaluate the CBM resource potential at Castlegate and Columbine Springs are progressing.

 

 

 

However, the Company has been testing its Uinta/Piceance area assets for impairment throughout 2008 due to its carrying value’s sensitivity to gas prices. As a result of lower gas prices at the end of the third quarter of 2008, the Company determined that the Uinta/Piceance assets' carrying amounts were impaired. See Note M of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Uinta/Piceance area assets' impairment.

 

The Company's Lay Creek project is a coal bed methane pilot program located in northwestern Colorado. The success of the pilot project was dependent on the ability to dewater the formation and determining that commercial quantities of gas could be produced. During October 2008, the Company concluded that the project was not commercial and is abandoning future dewatering activities. See "Results of Operations – Exploration and Abandonments Expense" for additional information regarding the Lay Creek project.

 

Onshore Gulf Coast area. The Company drilled 26 wells in the Edwards Trend during the nine months ended September 30, 2008. During 2008, the Company has reduced the drilling time for wells as a result of rig improvements and wellbore design enhancements. The Company is reducing its drilling activities until well costs are reduced to reflect current commodity prices. The Company continues to add infrastructure, primarily gas treating capacity and pipeline systems, to accommodate higher producing rates from recent well completions.

 

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 are expected to be completed during the fourth quarter of 2008. The seismic data will allow the Company to more accurately locate and orient the horizontal wells for optimal results.

 

The Company is also currently coring its first Eagle Ford shale horizontal well. The Company holds 310,000 acres in the Edwards Trend and the Eagle Ford Shale overlays all of the Company's acreage position.

 

Barnett Shale. During the nine months ended September 30, 2008, the Company participated in the drilling of seven successful exploration wells on approximately 75,000 gross acres in the Barnett Shale play that it acquired in 2007 and 2008. Drilling activities in the area are being reduced until well costs are better aligned with current commodity prices.

 

Alaska area. On the Oooguruk project, the Company continued development drilling operations and commenced production during the second quarter of 2008. Gross production averaged approximately 2,400 barrels per day during June and early-July. In mid-July 2008, production was shut in for scheduled maintenance at third-party, onshore production facilities. Following the completion of maintenance work in late-September 2008, production resumed. 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 on 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 early 2010.

 

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. In the third quarter of 2008, Sable oil production was shut in and operations to convert Sable's gas injection well to a producing well commenced. Gas sales from the Sable gas well were initiated in mid-October 2008 and the other wells resumed production in late-October. 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 four successful appraisal wells in the nine months ended September 30, 2008. Furthermore, during the nine months ended September 30, 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.

 

43

 

 

 

 

          In the Cherouq Concession, first sales occurred during the first quarter of 2008. The Company has drilled four exploration wells in the concession area during the first nine months of 2008. One of the exploration wells was determined to be a discovery and is currently on production whereas two other wells are being evaluated prior to completion and testing. The Company also acquired an additional 295 square kilometers of 3-D seismic data over the Cherouq Concession during the nine months ended September 30, 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. The Company drilled one exploration well in the permit during the first nine months of 2008. The Company will evaluate the results of the well during the fourth quarter 2008.

 

In the Borj El Khadra Permit, the Company drilled one exploration well and acquired 700 linear kilometers of 2-D seismic data in the nine months ended September 30, 2008. The Company will evaluate the results of the exploration well during the fourth quarter 2008. During the remainder of 2008, the Company plans to drill one additional exploration well and complete the processing of the seismic data. The Company plans to drill two to three wells in Tunisia during the fourth quarter of 2008.

 

The Company is continuing to assess its capital programs in light of expected internal cash flows. Existing plans for allocating capital resources to drilling and facilities investment alternatives will be impacted by continuing developments in the Company's well cost reduction initiatives and to fluctuations in commodity prices, along with ongoing developments in the worldwide economic environment.

 

Results of Operations

 

Oil and gas revenues. Oil and gas revenues from continuing operations totaled $612.2 million and $1.8 billion for the three and nine months ended September 30, 2008, respectively, as compared to $458.9 million and $1.2 billion for the same respective periods of 2007.

 

The increase in oil and gas revenues from continuing operations during the three and nine months ended September 30, 2008, as compared to the same periods of 2007, is reflective of increases in revenues for all geographic operating segments. The increase in revenues in the United States was due to increases in average reported oil, natural gas liquids ("NGLs") 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 nine months ended September 30, 2008, as compared to the comparable 2007 period 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.

 

44 

 

 

 

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

 

 

On a quarter-to-quarter BOE comparison, average daily sales volumes increased by 7 percent in the United States, by 61 percent in South Africa and by 62 percent in Tunisia. For the nine months ended September 30, 2008, as compared to the nine months ended September 30, 2007, average daily BOE sales volumes increased by 16 percent in the United States, by 44 percent in South Africa and by 35 percent in Tunisia.

 

During the three and nine month periods ended September 30, 2008, as compared to the three and nine month periods ended September 30, 2007, oil volumes delivered under the Company's VPPs decreased by 40 MBOE (5 percent) and 115 MBOE (5 percent), respectively, while gas volumes delivered under the Company's VPPs decreased by 761 MMcf (22 percent) and 2,250 MMcf (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 nine months ended September 30, 2008 and 2007:

 

 

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 nine months ended September 30, 2008, the Company's commodity price hedges decreased oil, NGL and gas revenues from continuing operations by $144.1 million and $388.3 million, respectively, as compared to decreasing oil and gas revenues from continuing operations by $2.8 million and $51.1 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 derivatives mature or are terminated.

 

Deferred revenue. During the three and nine months ended September 30, 2008, the Company's amortization of deferred VPP revenue increased oil and gas revenues from continuing operations by $39.7 million and $118.6 million, respectively, as compared to increases of $45.6 million and $135.9 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.

 

46 

 

 

Interest and other income. Interest and other income from continuing operations for the three and nine months ended September 30, 2008 was $3.4 million and $36.9 million, respectively, as compared to $30.7 million and $68.3 million for the same respective periods in 2007. The $27.3 million decrease in interest and other income from continuing operations during the three months ended September 30, 2008, as compared to the same period in 2007, was primarily due to a $28.3 million decrease in realized Alaskan Petroleum Production Tax ("PPT") credits. The $31.4 million decrease in interest and other income from continuing operations during the nine months ended September 30, 2008, as compared to the same period in 2007, was primarily due to a $35.6 million decrease in realized PPT credits, 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 regarding interest and other income.

 

Oil and gas production costs. The Company recorded oil and gas production costs from continuing operations of $155.8 million and $432.9 million during the three and nine months ended September 30, 2008, respectively, as compared to $113.6 million and $308.4 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 24 percent and 19 percent during the three and nine months ended September 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, primarily due to fixed production costs associated with first sales from the Alaskan Oooguruk development and 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.

 

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

 

 

 

 

47 

 

 

Depletion, depreciation and amortization expense. The Company's total DD&A expense from continuing operations was $127.5 million ($12.39 per BOE) and $351.8 million ($11.46 per BOE) for the three and nine months ended September 30, 2008, respectively, as compared to $113.9 million ($12.28 per BOE) and $280.9 million ($10.79 per BOE) during the same respective periods of 2007. The increases of $13.6 million and $70.9 million in total DD&A expense during the three and nine months ended September 30, 2008, as compared to the same respective periods in 2007, are primarily comprised of increases in depletion of oil and gas properties of $13.6 million and $70.2 million, respectively.

 

Depletion expense from continuing operations was $11.68 per BOE and $10.75 per BOE during the three and nine months ended September 30, 2008, respectively, as compared to $11.49 per BOE and $9.98 per BOE during the same respective periods in 2007. The two percent and eight percent increases in per BOE depletion expense from continuing operations during the three and nine months ended September 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 Oooguruk development and South African South Coast Gas projects, partially offset by (iii) positive price revisions of proved reserves since September 30, 2007. During the third quarter of 2008, the Company's proved reserves were negatively impacted by commodity price declines, which have declined further since September 30, 2008. Sustained declines in commodity prices will likely increase the Company's depletion expense per BOE in future periods due to a reduction in proved reserves as a result of certain wells becoming uneconomical to produce earlier than in a higher commodity price environment. See "Recent Events" for additional information regarding commodity price declines since September 30, 2008.

 

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

 

 

Impairment of oil and gas properties. During the three and nine months ended September 30, 2008, the Company recognized impairment charges of $89.8 million as compared to an impairment credit of $2.6 million and an impairment charge of $15.3 million during the same respective periods of 2007. The increase is due to the impairment of the Company's net assets in the Uinta/Piceance area during the third quarter of 2008. The events and circumstances indicating the impairment are primarily related to the decline in gas prices. See Note M of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information on the impairment charges.

 

48

 

 

         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 nine months ended September 30, 2008 and 2007:

 

 

The Company's exploration and abandonment expense from continuing operations during the three and nine month periods ended September 30, 2008 is primarily attributable to continued seismic activity in the Company's Utah, Mississippi, Permian Basin, South Texas and Tunisian areas and dry hole expense and unproved property abandonments. During the three and nine month periods ended September 30, 2008, the Company's exploration and abandonment expense included dry hole and leasehold abandonment and other exploration expenses of $89.7 million and $95.7 million, respectively, which is primarily comprised of the Company's unsuccessful Lay Creek CBM pilot project, the unsuccessful Delaware Basin exploration project and the unsuccessful Sligo exploration well in South Texas.

 

The Company's Lay Creek project was a CBM pilot program located in northwestern Colorado. The Company 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. The success of the pilot program was dependent on the ability to dewater the formation and determining that commercial quantities of gas could be produced. During October 2008, the Company concluded that the project was not commercial and is abandoning future dewatering activities. Consequently, the Company recorded a charge of $44.2 million to exploration and abandonments expense in the accompanying consolidated statements of operations for the three and nine month periods ended September 30, 2008, to reduce the carrying value of the Lay Creek project.

 

During the nine months ended September 30, 2007, the Company's exploration and abandonment expense included dry hole and leasehold abandonment and other exploration expenses of $94.9 million, which was primarily comprised of unsuccessful exploration wells in Alaska and Block 256 in the deepwater offshore Nigeria, together with associated unproved leasehold abandonment provisions.

 

49 

 

 

         During the nine months ended September 30, 2008, the Company drilled and evaluated 52 exploration/extension wells, 37 of which were successfully completed as discoveries. During the same period in 2007, the Company drilled and evaluated 47 exploration/extension wells, 34 of which were successfully completed as discoveries.

 

General and administrative expense. General and administrative expense from continuing operations for the three and nine months ended September 30, 2008 were $31.6 million and $103.6 million, respectively, as compared to $32.3 million and $94.3 million during the same respective periods of 2007. In the nine month comparisons, 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 September 30, 2008, the Company had $57.3 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 27 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 $6.5 million for the three and nine months ended September 30, 2008, respectively, as compared to $1.7 million and $5.0 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 $37.7 million and $113.4 million for the three and nine months ended September 30, 2008, respectively, as compared to $35.5 million and $94.4 million during the same respective periods of 2007. The weighted average interest rate on the Company's indebtedness for the three and nine months ended September 30, 2008, including the effects of interest rate derivatives and capitalized interest, was 5.5 percent for each period as compared to 6.6 percent for the same respective periods in 2007. The $2.2 million increase in interest expense from continuing operations during the three months ended September 30, 2008, as compared to the same period of 2007, was primarily due to (i) a $5.1 million decrease in capitalized interest primarily related to completion of the Company's South Coast Gas development project in South Africa and declining capitalized interest on the Oooguruk project as development wells are placed on production, partially offset by (ii) a $2.6 million decrease in cash interest expense on long-term borrowings. The $19.0 million increase in interest expense from continuing operations during the nine months ended September 30, 2008, as compared to the same period of 2007, was primarily due to (i) an $11.6 million decrease in capitalized interest on the Company's Oooguruk and South Coast Gas development projects and (ii) a $9.3 million increase in cash interest expense on long-term borrowings, primarily due to an increase in average debt outstanding Capitalized interest on the Company's Oooguruk project in Alaska will continue, but decline over time as development wells are completed and placed on production.

 

Hurricane activity, net. The Company recorded net hurricane related activity expenses of $541 thousand and $2.4 million during the three and nine months ended September 30, 2008, respectively, and $110 thousand and $60.7 million during the same respective periods of 2007. Hurricane activity, net is 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 approximately $149.6 million has been expended through September 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.

 

50 

 

 

Minority interest in consolidated subsidiaries' net income (loss). Minority interest in consolidated subsidiaries' net income (loss) from continuing operations for the three and nine months ended September 30, 2008 were charges of $8.4 million and $15.4 million, respectively, as compared to a net charge of $172 thousand and a net credit of $1.0 million for the same respective periods in 2007. The $8.2 million increase in minority interest in consolidated subsidiaries' net income (loss) of the three months ended September 30, 2008, as compared to the same period of 2007, is primarily due to $7.7 million of minority interest in the third quarter 2008 net income of Pioneer Southwest. Similarly, the $16.4 million increase in minority interest in consolidated subsidiaries' net income (loss) of the nine months ended September 30, 2008, as compared to the same period of 2007, is primarily due to $12.7 million of minority interest in the net income of Pioneer Southwest attributable to the period from May 6, 2008 (the date of completion of Pioneer Southwest's IPO) through September 30, 2008 and a $2.8 million decrease in minority interest in the net losses of Pioneer Natural Resources Nigeria (320) Limited, which was sold by the Company during 2007. See Note B of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding Pioneer Southwest and the Company's minority interest in consolidated subsidiaries' net income (loss).

 

Other expense. Other expense from continuing operations for the three and nine months ended September 30, 2008 was $38.9 million and $58.8 million, respectively, as compared to $7.0 million and $21.7 million for the same respective periods in 2007. The $31.9 million increase in other expenses for the three months ended September 30, 2008, is primarily attributable to (i) $19.6 million of bad debt expense associated with the Company's delinquent SemGroup accounts receivable, (ii) a $6.0 million increase in contingency accrual adjustments, (iii) a $3.9 million increase in commodity hedge ineffectiveness and (iv) a $3.8 million increase in the cost of idle drilling equipment. The $37.1 million increase in other expenses for the nine months ended September 30, 2008, as compared to the nine months ended September 30, 2007, is primarily attributable to (i) the aforementioned $19.6 million SemGroup bad debt expense and (ii) a $15.4 million increase in the cost of idle drilling equipment. See Note Q of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

 

Income tax provision. The Company recognized income tax provisions on continuing operations of $14.9 million and $227.9 million during the three and nine months ended September 30, 2008, respectively, as compared to $60.9 million and $92.2 million during the same respective periods of 2007. The $46.0 million decrease in income tax provisions for the three months ended September 30, 2008, as compared to the same period of 2007, is primarily due to a $141.6 million decrease in income from continuing operations before income taxes. The $135.7 million increase in the income tax provision for the nine months ended September 30, 2008, as compared to the same period of 2007, was primarily due to a $261.4 million increase 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 121 percent and 45 percent during the three and nine months ended September 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.

 

51 

 

 

         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 R 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 capital expenditures and acquisition expenditures on oil and gas assets, payment of contractual obligations, dividends/distributions 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 external financing sources as discussed in "Capital resources" below. The Company expects that it will be able to fund its needs for cash (excluding acquisitions) with internal operating cash flows. Acquisitions may be funded with internal operating cash flows or availability under the Company's revolving credit facilities. Although the Company expects that internal operating cash flows will be adequate to fund capital expenditures and dividend/distribution payments, and that available borrowing capacity under the Company's credit facilities will provide adequate liquidity to fund future acquisitions, no assurances can be given that such funding sources will be adequate to meet the Company's future needs.

 

Concerns that the worldwide economic slowdown will negatively impact the demand for energy have caused a significant drop in commodity prices since their highs earlier in 2008. As a result of the significant drop in commodity prices, the Company has started implementing initiatives to reduce capital spending and preserve financial flexibility. Specifically, the Company plans to minimize drilling activities until commodity prices increase, gas price differentials in the areas where the Company produces gas narrow relative to NYMEX quoted gas prices and/or well cost reductions can be achieved. As a result, the Company is reducing its rig activity by approximately 60 percent and is pursuing reductions in well costs to align costs with the lower commodity price environment that currently exists. Rigs are being terminated or stacked in the Spraberry, Raton, Edwards Trend, Barnett Shale and Mid-Continent areas. The Company is also reducing the number of well service units running in the Spraberry field from 42 to 30, 15 of which are lower-cost well service units that are owned by Pioneer.

 

Oil and gas properties. The Company's cash expenditures for additions to oil and gas properties during the three and nine months ended September 30, 2008, totaled $380.1 million and $996.7 million, respectively, as compared to $355.5 million and $1.3 billion for the same respective periods of 2007. During the three and nine months ended September 30, 2008, the Company's expenditures for additions to oil and gas properties were funded by $302.8 million and $813.6 million of net cash provided by operating activities, borrowings under the Company's credit facility and $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 nine months ended September 30, 2007, the Company's expenditures for additions to oil and gas properties were funded by $190.6 million and $538.0 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 September 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 $67.9 million increase in outstanding long-term borrowings, a $118.6 million decrease in the Company's VPP obligations, a $195.0 million decrease in the Company's net derivative obligations, a $157.8 million decrease in the Company's drilling commitments and, subject to the counterparties' construction of associated gas pipelines, a $534 million increase in the Company's transportation commitments. See Note F of Notes to

 

52 

 

 

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 nine months ended September 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 September 30, 2008, these contracts represented net liabilities of $110.8 million, including approximately $58.6 million of terminated hedge liabilities that are no longer subject to market risk. The ultimate liquidation value of the Company's commodity and interest rate derivatives that are subject to market risk 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 September 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. While the Company expects that these resources will be sufficient to fund its capital commitments during the foreseeable future, the recent circumstances in worldwide financial markets have resulted in the availability of external sources of short- and long-term capital funding being less certain. For 2008, the Company expects that cash flow from operations and proceeds from asset sales will be sufficient to fund the Company's capital expenditures.

 

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 nine months ended September 30, 2008 was $302.8 million and $813.6 million, respectively, as compared to $190.6 million and $538.0 million for the same respective periods in 2007. The increase in net cash provided by operating activities during the three and nine month periods ended September 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.

 

As described in "Recent Events –Commodity prices," the commodity price declines that have occurred since September 30, 2008, although mitigated by the Company's hedging activities, will reduce the Company's internal cash flows. The duration and magnitude of the commodity price declines cannot be predicted.

 

53 

 

 

         Investing activities. Investing activities used $393.2 million and $884.7 million of cash during the three and nine months ended September 30, 2008, respectively, as compared to $418.6 million and $1.4 billion for the same respective periods in 2007. The $25.4 million decrease in net cash used in investing activities during the third quarter of 2008, as compared to the third quarter of 2007, is primarily due to a $49.4 million decrease in additions to other assets and other property and equipment, net, partially offset by a $24.6 million increase in additions to oil and gas properties. The $520.3 million decrease in net cash used in investing activities during the nine months ended September 30, 2008, as compared to the nine months ended September 30, 2007, is primarily due to a (i) $333.6 million decrease in additions to oil and gas properties, (ii) a $128.3 million increase in proceeds from disposition of assets, primarily comprised of a portion of the proceeds from the fourth quarter 2007 sale of the Company's Canadian subsidiaries, which were released from escrow during the first quarter of 2008 and (iii) a $58.5 million decrease in additions to other assets and other property and equipment, net.

 

Financing activities. Net cash provided by financing activities during the three and nine months ended September 30, 2008 was $113.9 million and $125.8 million, respectively, as compared to $221.2 million and $877.9 million during the same respective periods in 2007. The $107.3 million decrease in net cash provided by financing activities during the three months ended September 30, 2008, as compared to the same period of 2007, was primarily due to (i) a $199.9 million decrease in long-term debt net borrowings and (ii) an $8.4 million increase in payments of other liabilities, partially offset by (iii) a $101.8 million decrease in treasury stock purchases. The $752.1 decrease in net cash provided by financing activities during nine months ended September 30, 2008, as compared to the same period of 2007, was primarily due to (i) a $1.0 billion decrease in long-term debt net borrowings and (ii) an $8.1 million increase in financing fees paid, partially offset by (iii) $166.0 million of Pioneer Southwest IPO proceeds and (iv) a $128.5 million decrease in treasury stock purchases.

 

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). During October 2008, the Company paid $19.2 million of aggregate dividends ($0.16 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 nine months ended September 30, 2008 and 2007, the Company expended $69.9 million to acquire 1.3 million shares of treasury stock and $214.7 million to acquire 5.0 million shares of treasury stock, respectively, under share repurchase programs. As of September 30, 2008, approximately $467.3 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 Southwest's 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

 

54

 

 

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, to the extent available, 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 facilities. There was $679 million of borrowings under the credit facilities as of September 30, 2008. After deducting $45.8 million of undrawn and outstanding letters of credit under the credit facilities, the Company had $775.2 million of unused borrowing capacity as of September 30, 2008. If internal cash flows do not meet the Company's expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its credit facilities, issuances of debt or equity securities or from other sources, such as asset sales. The Company cannot provide any assurance that needed short- or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that internal cash flows will be adequate to fund capital expenditures and dividend payments, and that available borrowing capacity under the Company's credit facilities will provide adequate liquidity to fund future acquisitions, no assurances can be given that such funding sources will be adequate to meet the Company's future needs.

 

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 September 30, 2008, the Company was in compliance with all of its debt covenants.

 

Book capitalization and current ratio. The Company's net book capitalization at September 30, 2008 was $6.3 billion, consisting of $66.8 million of cash and cash equivalents, debt of $2.8 billion and stockholders' equity of $3.5 billion. The Company's net debt to net book capitalization was 44 percent and 47 percent at September 30, 2008 and December 31, 2007, respectively. The Company's ratio of current assets to current liabilities was 0.84 to 1.00 at September 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.

 

55 

 

 

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 their fair values as of the date that the acquirer achieves control over the business acquired. This includes the measurement of the acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the recognition of pre-acquisition contractual and certain non-contractual gain and loss contingencies, the recognition of capitalized research and development costs and the recognition of changes in the acquirer's income tax valuation allowance and deferred taxes. The provisions of SFAS 141(R) also require that restructuring costs resulting from the business combination that the acquirer expects but is not required to incur and costs incurred to effect the acquisition be recognized separate from the business combination. 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 (i) how and why an entity uses derivative instruments, (ii) 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 (iii) 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 entity's 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,

 

56 

 

 

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 adoption of FSP EITF 03-6-1 is not expected to have a material effect on the Company's net income per share calculations.

 

 

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:

 

_____________

 

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.

 

57 

 

 

         The following table provides information about financial instruments to which the Company was a party as of September 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 September 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 October 31, 2008.

 

Interest Rate Sensitivity

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

 

 

_____________

 

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 September 30, 2008. As of September 30, 2008, substantially all of the Company's oil, NGL and gas derivative financial instruments qualified as hedges.

 

Since September 30, 2008, market-quoted commodity prices have declined significantly from levels reported by the Company as of and for the periods ended September 30, 2008. Although mitigated by the Company's hedging activities, a decline in commodity prices will reduce the Pioneer's revenues and internal cash flows. Recent uncertainties in worldwide financial markets may have the effect of reducing liquidity in the financial derivatives market, hampering the Company's ability to enter into hedge derivatives under acceptable derivative terms. See "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations."    

 

58

 

 

        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 September 30, 2008

 

 

_____________

 

59 

 

 

Item 4.Controls and Procedures

 

Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 ("the Exchange Act"), the 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.

 

60

 

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," which risks could materially affect the Company's business, financial condition or future results. Except as stated below, there has been no material change in the Company's risk factors from those described in the Annual Report on Form 10-K.

 

A subsidiary of the Company acts as the general partner of a publicly-traded limited partnership. As such, the subsidiary's operations may involve a greater risk of liability than ordinary business operations.

 

A subsidiary of the Company acts as the general partner of Pioneer Southwest Energy Partners L.P., a publicly-traded limited partnership formed by the Company to own and acquire oil and gas assets in its area of operations. As general partner, the subsidiary may be deemed to have undertaken fiduciary obligations to the partnership. Activities determined to involve fiduciary obligations to others typically involve a higher standard of conduct than ordinary business operations and therefore may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Any such liability may be material.

 

The Company is subject to regulations that may cause it to incur substantial costs.

 

As previously disclosed in the Company's Annual Report on Form 10-K, including in "Item 1. Business — Competition, Markets and Regulations," the Company's business is regulated by a variety of federal, state, local and foreign laws and regulations. For example, our properties located in Colorado are subject to the authority of the Colorado Oil & Gas Conservation Commission (the "COGCC").  The COGCC has published proposed rules that could increase the Company's costs of permitting and environmental compliance. The COGCC initiated formal rule-making in the first quarter of 2008, and final rules could be effective during the second quarter of 2009. While this regulatory development has not adversely affected the Company's operations to date, these additional rules could cause additional costs, delay and uncertainty in the Company's operations in Colorado and may be emulated in other jurisdictions in which the Company operates. There can be no assurance that present or future regulations will not adversely affect the Company's business and operations. See "Item 1. Business — Competition, Markets and Regulations" in the Annual Report on Form 10-K for additional discussion regarding government regulation.

 

Our expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing.

 

The Company has identified drilling locations and prospects for infill drilling and enhanced recovery activities. These drilling locations and prospects represent a significant part of the Company's future drilling plans. The Company's ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs and drilling results. Because of these uncertainties, the Company can not give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or meet the Company's expectations for success. As such, the Company's actual drilling and secondary activities may materially differ from the Company's current expectations, which could have a significant adverse effect on the Company's financial condition and results of operations.

 

61 

 

 

The failure by counterparties to the Company's hedging activities to perform their obligations could have a material adverse effect on the Company's results of operations.

 

To achieve more predictable cash flow and to reduce the Company's exposure to adverse fluctuations in the prices of oil, NGL and gas, the Company's strategy is to enter into derivative arrangements covering a portion of its oil, NGL and gas production. The use of hedging transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company's derivative contracts are with multiple counterparties to mitigate its exposure to any individual counterparty. If any of these counterparties were to default in its obligations under the Company's hedging arrangements, such a default could have a material, adverse effect on the Company's results of operations, and could result in a larger percentage of the Company's future production being subject to commodity price changes. In addition, in light of the current economic outlook, it is possible that fewer counterparties will participate in hedging transactions, which could result in a greater concentration of the Company's exposure to any one counterparty, or a larger percentage of the Company's future production could be subject to commodity price changes.

 

A failure by purchasers of the Company's production to perform their obligations to the Company could require the Company to recognize a pre-tax charge in earnings and have a material adverse effect on the Company's results of operation.

 

Recently, there has been a significant decline in the credit markets and the availability of credit, and equity values have substantially declined. To the extent that purchasers of the Company's production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to the Company. If for any reason the Company were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of the Company's production were uncollectible, the Company would recognize a pre-tax charge in the earnings of that period for the probable loss.

 

The Company may not be able to obtain funding, obtain funding on acceptable terms or obtain funding under its current credit facility because of the deterioration of the credit and capital markets. This may hinder or prevent the Company from meeting its future capital needs.

 

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the repricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding. In addition, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to the Company's current debt and reduced and, in some cases, ceased to provide funding to borrowers. In addition, the Company may be unable to obtain adequate funding under its current credit facility because (i) the Company's lending counterparties may be unwilling or unable to meet their funding obligations or (ii) the amount the Company may borrow under its current credit facility could be reduced as a result of lower oil, NGL or gas prices, declines in reserves, lending requirements or regulations, or for other reasons. Due to these factors, the Company cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, the Company may be unable to implement its business plans, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures any of which could have a material adverse effect on the Company's production, revenues and results of operations.

 

Declining general economic, business or industry conditions may have a material adverse affect on the Company's results of operations.

 

Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market and a declining real estate market in the United States have contributed to increased volatility and diminished expectations for the global economy and expectations of recession or slower global economic growth going forward.

 

62 

 

 

These factors, combined with volatile oil prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a possible recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices, both of which have contributed to a decline in the Company's share price and corresponding market capitalization. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could diminish, which could impact the price at which the Company can sell its oil, NGLs and gas and ultimately decrease the Company's net revenue and profitability.

 

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 September 30, 2008:

 

_____________

 

 

Exhibits

 

 

_____________

(a) Filed herewith.

(b) Furnished herewith.

 

 

 

63 

 

 

 

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.

 

 

 

 

 

 

64 

 

 

 

Exhibit Index

 

 

_____________

(a) Filed herewith.

(b) Furnished herewith.

 

65