PSE Pioneer Southwest Energy Partners L.P. Pioneer Southwest Energy Partners Lp

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2008

 

or

 

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to ________

 

Commission File Number: 001-34032

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.  

(Exact name of Registrant as specified in its charter)

 

 

 

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

Yes x No o

 

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

 

 

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

Yes o No x

 

 

 

 

 

 

 

 

Cautionary Statement Concerning Forward-Looking Statements

 

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

 

These risks and uncertainties include, among other things, volatility of commodity prices, the financial strength of counterparties to the Partnership's credit facility and derivative contracts and the purchasers of the Partnership's oil, NGL and gas production, the effectiveness of the Partnership's commodity price hedging strategy, reliance on Pioneer Natural Resources Company and its subsidiaries to manage the Partnership's business and identify and evaluate acquisitions, 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, litigation, the costs and results of operations, access to and availability of transportation, processing and refining facilities, the Partnership's ability to replace reserves, including through acquisitions, and implement its business plans, uncertainties associated with acquisitions, access to and cost of capital, uncertainties about estimates of reserves, the assumptions underlying production forecasts, quality of technical data and environmental and weather risks. These and other risks are described in the Partnership's final prospectus dated April 30, 2008 (File No. 333-144868) and filed on May 1, 2008 with the Securities and Exchange Commission (the "SEC") pursuant to Rule 424(b)(4) under the Securities Act of 1933 (the "Prospectus") and other filings with the SEC. In addition, the Partnership 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 Disclosure About Market Risk" and "Part II, Item 1A. Risk Factors" in this Report and "Risk Factors," "Business — Environmental Matters and Regulation" and "Business — Other Regulation of the Oil and Gas Industry" in the Prospectus for a description of various factors that could materially affect the ability of the Partnership to achieve the anticipated results described in the forward-looking statements. The Partnership 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:

 

 

 

PART I. FINANCIAL INFORMATION

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

 

 

 

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED STATEMENT OF PARTNERS' EQUITY

(in thousands)

(Unaudited)

 

 

 

 

 

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

 

 

 

 

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

(Unaudited)

 

 

 

 

 

 

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2008

(Unaudited)

 

 

Pioneer Southwest Energy Partners L.P., a Delaware limited partnership (the "Partnership"), was formed in June 2007 by Pioneer Natural Resources Company (together with its subsidiaries, "Pioneer") to own and acquire oil and gas assets in the Partnership's area of operations. The Partnership's area of operations consists of onshore Texas and eight counties in the southeast region of New Mexico. Prior to the completion on May 6, 2008 of the Partnership's initial public offering of 9,487,500 common units representing limited partner interests (the "Offering"), Pioneer owned all of the general and limited partner interests in the Partnership. Pioneer formed Pioneer Southwest Energy Partners USA LLC, a Texas limited liability company ("Pioneer Southwest USA"), to hold certain of the Partnership's oil and gas properties located in the Spraberry field in the Permian Basin of West Texas ("Spraberry field"). To effect the Offering, Pioneer (i) contributed to the Partnership a portion of its interest in Pioneer Southwest USA for additional general and limited partner interests in the Partnership, (ii) sold to the Partnership its remaining interest in Pioneer Southwest USA for $141.1 million, (iii) sold incremental working interests in certain of the oil and gas properties owned by Pioneer Southwest USA to the Partnership for $22.0 million, which amount represented the net proceeds from the exercise by the underwriters of the over-allotment option, and (iv) caused Pioneer Natural Resources GP LLC ("Pioneer GP") to contribute $24 thousand to the Partnership to maintain Pioneer GP's 0.1 percent general partner interest in conjunction with the exercise of the underwriters' over-allotment option. As a result of the transactions described in (i) and (ii) above, Pioneer Southwest USA became a wholly-owned subsidiary of the Partnership. The transactions described in (i), (ii), (iii) and (iv) above represent transactions between entities under common control. Consequently, the Partnership recorded the assets at Pioneer's carrying value. The oil and gas properties owned by Pioneer Southwest USA are referred to as the "Partnership Properties." Effective with the completion of the Offering on May 6, 2008, references herein to the Partnership are identifying Pioneer Southwest Energy Partners L.P. and its wholly-owned subsidiary, Pioneer Southwest USA.

 

 

Presentation. For periods prior to May 6, 2008, the accompanying consolidated financial statements and related notes thereto represent the financial position, results of operations, cash flows and changes in owner's equity of the Partnership Properties (the "Partnership Predecessor") and, for periods on and after May 6, 2008, the accompanying consolidated financial statements and related notes thereto represent the financial position, results of operations, cash flows and changes in partners' equity of the Partnership.

 

The proceeds from the exercise of the underwriters' over-allotment option in connection with the Offering were used by the Partnership to purchase incremental working interests in certain Partnership Properties, thereby effecting a change in the reporting entity as defined by generally accepted accounting principles in the United States ("GAAP"). The change in reporting entity has been retrospectively applied to all prior periods presented. As a result of the change, net income increased to $17.5 million and $42.6 million for the three and nine months ended September 30, 2007, respectively, as compared to $16.6 million and $40.6 million, respectively, previously reported for the same periods.

 

The Partnership's consolidated financial statements have been prepared in accordance with Regulation S-X, Article 3 "General instructions as to financial statements" and Staff Accounting Bulletin ("SAB") Topic 1-B "Allocations of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity." Certain expenses incurred by Pioneer and included in the accompanying consolidated financial statements in the periods prior to May 6, 2008 are only indirectly attributable to Pioneer's ownership of the Partnership Properties because Pioneer owns interests in numerous other oil and gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to the Partnership so that the accompanying consolidated financial statements reflect substantially all the costs of doing business. The allocation and related estimates and assumptions are described more fully in "Allocation of costs."

 

In the opinion of management, the consolidated financial statements of the Partnership as of September 30, 2008, and for the three and nine month periods 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 GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the SEC. These financial statements should be read together with the financial statements and notes thereto included in the Partnership's final prospectus dated April 30, 2008 (File Number 333-144868), which the Partnership filed with the SEC on May 1, 2008 pursuant to Rule 424(b)(4) of the Securities Act of 1933.

 

Principles of consolidation. The consolidated financial statements of the Partnership include the accounts of the Partnership and its wholly-owned subsidiary. All material intercompany balances and transactions have been eliminated.

 

Cash and cash equivalents. Cash and cash equivalents include cash on hand and depository accounts held by banks.

 

Prior to the Offering, Pioneer provided cash as needed to support the operations of the Partnership Properties and collected cash from sales of production from the Partnership Properties. Consequently, the accompanying balance sheet as of December 31, 2007 does not include any cash balances. Cash received or paid by the Partnership Predecessor is reflected as a net distribution to owner on the accompanying consolidated statement of partners' equity prior to the Offering.

 

Inventory. The Partnership's inventory consists of natural gas liquids ("NGLs") held in storage by the purchaser of the NGLs as of September 30, 2008. As of September 30, 2008, title and risk of loss of the NGL inventory had transferred to the purchaser. However, the sales price of the NGLs will not be determined until the NGLs undergo further processing by the purchaser during the fourth quarter of 2008. In accordance with SAB Topic 13 "Revenue Recognition – Revised as of December 2003," the Partnership has deferred revenue recognition of the NGL sales as of September 30, 2008. The Partnership's NGL inventory is carried at average cost on a first-in, first-out basis. See "Revenue recognition" for information regarding the Partnership's accounting policy for revenue recognition.

 

Oil and gas properties. The Partnership utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells, if any, are capitalized while nonproductive exploration costs and geological and geophysical expenditures, if any, are expensed.

 

Capitalized costs relating to proved properties are depleted using the unit-of-production method based on proved reserves.

 

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization. Generally, no gain or loss is recognized until the entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base.

 

In accordance with Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the Partnership reviews its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In this circumstance, the Partnership would recognize an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.

 

 

 

Asset retirement obligations. The Partnership accounts for asset retirement obligations in accordance with SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. Under the provisions of SFAS 143, asset retirement obligations are generally capitalized as part of the carrying value of the long-lived assets.

 

Derivatives and hedging. The Partnership follows the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income. Under the provisions of SFAS 133, the Partnership may designate a derivative instrument as hedging the exposure to changes in the fair value of an asset or a liability or an identified portion thereof that is attributable to a particular risk (a "fair value hedge") or as hedging the exposure to variability in expected future cash flows that are attributable to a particular risk (a "cash flow hedge"). Both at the inception of a hedge and on an ongoing basis, a fair value hedge must be expected to be highly effective in achieving offsetting changes in fair value attributable to the hedged risk during the periods that a hedge is designated. Similarly, a cash flow hedge must be expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. The expectation of hedge effectiveness must be supported by matching the essential terms of the hedged asset, liability or forecasted transaction to the derivative hedge contract or by effectiveness assessments using statistical measurements. The Partnership's policy is to assess hedge effectiveness at the end of each calendar quarter.

 

Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities or firm commitments through net income. Effective changes in the fair value of derivative instruments that are cash flow hedges are recognized in accumulated other comprehensive income - deferred hedge gains, net of tax ("AOCI - Hedging") in the partners' equity section of the Partnership's balance sheets until such time as the hedged items are recognized in net income. Ineffective portions of a derivative instrument's change in fair value are immediately recognized in earnings.

 

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

 

Pioneer does not designate derivative hedges to forecasted sales at the well level. Consequently, the Partnership's consolidated financial statements do not include recognition of hedge gains or losses or derivative assets or liabilities associated with Partnership Properties for periods prior to the Offering.

 

See Note H for a description of the specific types of derivative transactions in which the Partnership participates.

 

Owner's net equity. Since the Partnership Properties were not a separate legal entity during the periods prior to the Offering, none of Pioneer's debt was directly attributable to its ownership of the Partnership Properties, and no formal intercompany financial arrangement then existed related to the Partnership Properties. Therefore, the changes in net assets of periods prior to the Offering that were not attributable to current period earnings are reflected as increases or decreases to owner's net equity of those periods. Additionally, as debt cannot be specifically ascribed to the Partnership Properties, the accompanying consolidated statements of operations do not include any allocation of interest expense incurred by Pioneer to the Partnership Predecessor during the periods prior to the Offering.

 

Employee benefit plans. The Partnership does not have its own employees. However, during the periods presented, a portion of the general and administrative expenses and lease operating expenses allocated to the Partnership was noncash stock-based compensation recorded on the books of Pioneer.

 

 

 

Segment reporting. The Partnership's only operating segment is oil and gas producing activities. Additionally, all of the Partnership Properties are located in the United States and all of the related oil, NGL and gas revenues are derived from purchasers located in the United States.

 

Income taxes. Prior to the Offering, the operations of the Partnership Predecessor were included in the federal income tax return of Pioneer. Following the Offering, the Partnership's operations are treated as a partnership with each partner being separately taxed on its share of the Partnership's federal taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying consolidated financial statements. However, the Texas Margin tax was signed into law on May 18, 2006 for tax years beginning on January 1, 2007, which caused the Texas franchise tax to be applicable to numerous types of entities that previously were not subject to the tax, including the Partnership. Accordingly, the Partnership reflects its deferred tax position associated with the future tax effect of the Texas Margin tax in the accompanying consolidated balance sheets.

 

Revenue recognition. The Partnership does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectibility is reasonably assured.

 

The Partnership uses the entitlements method of accounting for oil, NGL and gas revenues. Sales proceeds, if any, in excess of the Partnership's entitlement are included in other liabilities and the Partnership's share of sales taken by others is included in other assets in the balance sheet. The Partnership had no material oil, NGL or gas entitlement assets or liabilities as of September 30, 2008 or December 31, 2007.

 

Environmental. The Partnership's environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. At September 30, 2008 and December 31, 2007, the Partnership had no material environmental liabilities.

 

Use of estimates. Preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion and impairment of oil and gas properties, in part, are determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties, if any, are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks, future production costs and environmental regulations. Actual results could differ from the estimates and assumptions utilized.

 

Allocation of owner's net equity and partners' equity. The financial position, results of operations, cash flows and owner's equity of the Partnership for all periods presented prior to the Offering represent those of the Partnership Predecessor. In accordance with GAAP, the contribution and purchase of the Partnership Properties and other net assets from Pioneer were accounted for as transactions between entities under common control. Therefore, the net assets were recorded on the Partnership's balance sheet at $140.8 million, representing Pioneer's carrying value of the net assets and the owner's equity of the Partnership as of the Offering date. Accordingly, the $140.8 million carrying value of the net assets is presented as an allocation of owner's equity to the limited and general partner's equity of Pioneer in the accompanying consolidated statement of partners' equity.

 

 

 

Pioneer's carrying value in the net assets acquired by the Partnership includes $2.0 million of noncash working capital contributed by Pioneer, representing net working capital earned from the Partnership Properties during the period from May 1, 2008 through May 5, 2008.

 

The following table provides Pioneer's carrying values in the assets and (liabilities) contributed to and acquired by the Partnership:

 

The Partnership acquired a portion of the Partnership Properties from Pioneer for $163.1 million on the date of the Offering, which amount exceeded the carrying value of the net assets by $22.2 million. The $140.8 million portion of the Partnership's payment to Pioneer attributable to the carrying value of the Partnership Properties is reflected as an investing activity in the accompanying consolidated statement of cash flows and was recorded as a reduction of Pioneer's general partners' and limited partners' equity, as presented in the accompanying consolidated statement of partners’ equity. The Partnership's payment to Pioneer of $22.2 million in excess of the carrying value of the Partnership Properties is reflected in the accompanying consolidated statement of cash flows as a financing activity and as a reduction of Pioneer's limited partners' equity, as presented in the accompanying statement of partners' equity.

 

On May 6, 2008, novation agreements were entered into among Pioneer, the Partnership and certain derivative instrument counterparties, which transferred Pioneer's rights and responsibilities under certain derivative instruments to the Partnership. As of May 6, 2008, the aggregate fair value of the derivative instruments novated to the Partnership represented a liability of approximately $37.2 million. The novation of the derivative obligations was recorded as a reduction of Pioneer's limited partners' equity, as presented in the accompanying consolidated statement of partners’ equity. See Note H for additional information regarding the novated derivative instruments.

 

Allocation of costs. The accompanying consolidated financial statements have been prepared in accordance with SAB Topic 1-B. Under these rules, all direct costs have been included in the accompanying consolidated financial statements. Further, allocations for salaries and benefits, depreciation, rent, accounting and legal services, other general and administrative expenses and other costs and expenses that are not directly identifiable costs have also been included in the accompanying consolidated financial statements. For periods prior to the Offering, Pioneer has allocated general and administrative expenses to the Partnership Predecessor based on the Partnership Properties' share of Pioneer's total production as measured on a per barrel of oil equivalent basis. In management's estimation, the allocation methodologies used are reasonable and result in an allocation of the cost of doing business incurred by Pioneer on behalf of the Partnership Predecessor; however, these allocations may not be indicative of the costs of future operations or the amount of future allocations.

 

Net income per common unit. The Partnership calculates net income per common unit in accordance with SFAS No. 128, "Earnings Per Share" ("SFAS 128"). For the three and nine months ended September 30, 2008, net income per common unit is calculated by dividing the limited partners' interest in net income derived from operations subsequent to the Offering by the weighted average number of common units outstanding (representing

 

 

 

30,008,700 common units, comprising 20,521,200 common units held by Pioneer and the 9,487,500 common units issued in the Offering). Prior to the Offering, the Partnership was wholly owned by Pioneer. Accordingly, net income per common unit is not presented for periods prior to the Offering.

 

Allocation of net income. The Partnership's net income is allocated to partners' equity accounts in accordance with the provisions of the partnership agreement.

 

For purposes of calculating net income per common unit, the Partnership allocates net income to its limited partners and its general partner each quarter under the provisions of Emerging Issues Task Force Issue No. 03-6, "Participating Securities and the Two-Class Method Under FASB Statement No. 128" ("EITF 03-6").

 

New accounting pronouncements . In September 2006, the FASB issued SFAS No. 157, "Fair Value Measures" ("SFAS 157"). SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. In February 2008, the FASB issued FASB Staff Position No. 157-2 ("FSP FAS 157-2"). FSP FAS 157-2 delays the effective date of SFAS 157 for nonfinancial assets and 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 Partnership adopted the provisions of SFAS 157 as they pertain to financial assets and liabilities. See Note C for additional information regarding the Partnership'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 Partnership.

 

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 Partnership 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 Partnership.

 

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 Partnership.

 

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

 

 

 

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 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 Partnership does not expect that the adoption of SFAS 162 will have a significant impact on the Partnership'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 unit under the two class method prescribed under SFAS 128. FSP EITF 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 unit data to conform to the provisions of the standard. The implementation of FSP EITF 03-6-1 is not expected to have a material effect on the Partnership's net income per unit calculations.

 

 

Effective January 1, 2008, the Partnership 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 valuation framework of SFAS 157 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 Partnership'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 input hierarchy levels:

 

 

The following table presents the changes in the fair values of the Partnership's commodity price derivative assets and liabilities classified as Level 3 in the fair value hierarchy:

 

_____________

 

Commodity derivative instruments. The Partnership's commodity price derivative assets and liabilities represent oil, NGL and gas swap and collar contracts. All of the Partnership's oil and gas price asset and liability measurements represent Level 2 inputs in the hierarchy priority. The Partnership's NGL price asset and liability measurements represent Level 3 inputs in the hierarchy priority.

 

Oil derivatives. The Partnership's oil derivatives are swap and collar contracts for notional barrels ("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. Commodity price derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rates and commodity price derivative liability values are determined, in part, by utilization of the Partnership's credit-adjusted risk-free rate. The counterparties' credit-adjusted risk-free rates are based on independent market-quoted credit default swap rate curves for the counterparties' debt plus the United States Treasury Bill yield curve as of September 30, 2008. The Partnership's credit-adjusted risk-free rate curve is based on the Partnership's borrowing rate under its $300 million unsecured revolving credit facility (the "Credit Facility") which matures in May 2013. The asset and liability transfer values

 

 

 

attributable to the Partnership's oil derivative instruments 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 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 Partnership'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 Partnership's NGL derivatives are swap contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs. The asset and liability values attributable to the Partnership's NGL derivative instruments are based on (i) the contracted notional volumes, (ii) average independent broker-supplied forward Mont Belvieu-posted-price quotes and (iii) the applicable credit-adjusted risk-free rate yield curve. NGL swap contracts are not as actively traded as oil and gas derivatives. Consequently, fair values determined on the basis of average independent broker-supplied forward Mont Belvieu-posted-price quotes may be less reliable than independent broker-supplied forward price quotes of more actively-traded commodities.

 

Gas derivatives. The Partnership's gas derivatives are swap contracts for notional MMBtus of gas contracted at various posted price indexes, including NYMEX Henry Hub ("HH") swap contracts coupled with basis swaps contracts that convert the HH price index point to Permian Basin index prices. The asset and liability values attributable to the Partnership's gas derivative instruments 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 Partnership corroborated independent broker-supplied forward gas price quotes by comparing price quote samples to alternate observable market data.

 

 

In May 2008, the Partnership entered into the Credit Facility. The Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions. Borrowings under the 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 the Partnership'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 Credit Facility.

 

The Credit Facility contains certain financial covenants, including (i) the maintenance of a quarter end maximum leverage ratio of not more than 3.5 to 1.0, (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 the Partnership'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, borrowing capacity under the Credit Facility was limited to approximately $200 million as of September 30, 2008. In addition, the Credit Facility contains various covenants that limit, among other things, the Partnership's ability to grant liens, incur additional indebtedness, engage in a merger, enter into transactions with affiliates, pay distributions or repurchase equity, and sell its assets. If any default or event of default (as defined in the Credit Facility) were to occur, the Credit Facility would prohibit the Partnership from making distributions to unitholders. Such events of default include, among others, nonpayment of principal or interest, violations of covenants, bankruptcy and material judgments and liabilities.

 

 

 

NOTE E.   Income Taxes

 

The Partnership's income tax provisions, which amounts were entirely attributable to the Texas Margin tax, consisted of the following for the three and nine months ended September 30, 2008 and 2007:

 

 

The Partnership's deferred tax attributes represented a $538 thousand asset as of September 30, 2008 and a $463 thousand liability as of December 31, 2007. The change in the Partnership's deferred tax position primarily resulted from the Offering, which occurred on May 6, 2008, and reflects differences in basis for tax purposes related to oil and gas properties. In connection with the Offering, the Partnership entered into a Tax Sharing Agreement with Pioneer. Under this agreement, the Partnership will pay Pioneer for its share of state and local income and other taxes (currently only the Texas Margin tax) for which the Partnership's results are included in a combined or consolidated tax return filed by Pioneer. It is possible that Pioneer may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe no tax. In such a situation, the Partnership would reimburse Pioneer for the tax it would have owed had the attributes not been available or used for its benefit, even though Pioneer had no cash expense for that period.

 

The Partnership applies the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes" ("FIN 48"). 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 Partnership had no material unrecognized tax benefits (as defined in FIN 48). The Partnership does not expect to incur interest charges or penalties related to its tax positions, but if such charges or penalties are incurred, the Partnership's policy is to account for interest charges as interest expense and penalties as other expense in the consolidated statements of operations.

 

 

The Partnership's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Partnership does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The Partnership has no assets that are legally restricted for purposes of settling asset retirement obligations.

 

 

 

 

The following table summarizes the Partnership's asset retirement obligation transactions during the three and nine month periods ended September 30, 2008 and 2007:

 

 

 

The Partnership's title to the Partnership Properties is burdened by a volumetric production payment ("VPP") commitment of Pioneer. During April 2005, Pioneer entered into a volumetric production payment agreement, pursuant to which it sold 7.3 million barrels of oil equivalent ("MMBOE") of proved reserves in the Spraberry field. The VPP obligation required the delivery by Pioneer of specified quantities of gas through December 2007 and requires the delivery of specified quantities of oil through December 2010. Pioneer's VPP agreement represents 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 any future production costs and capital expenditures associated with reserves; (iii) are nonrecourse to Pioneer (i.e., the purchaser's only recourse is to the assets acquired); (iv) transfer title of the assets to the purchaser; and (v) allow Pioneer or the Partnership, as the case may be, to retain the assets after the VPP's volumetric quantities have been delivered.

 

Virtually all of the properties that the Partnership owns are subject to the VPP. Pioneer has agreed that production from its retained properties subject to the VPP will be utilized to meet the VPP obligation prior to utilization of production from the Partnership Properties subject to the VPP, and it is expected that the VPP obligation can be fully satisfied by delivery of production from properties that are retained by Pioneer. If any production from the interests in the properties that the Partnership owns is required to meet the VPP obligation, Pioneer has agreed that it will make a cash payment to the Partnership for the value of the production (computed by taking the volumes delivered to meet the VPP obligation times the price the Partnership would have received for the related volumes, plus any out-of-pocket expenses or other expenses or losses incurred by the Partnership in connection with the delivery of such volumes) required to meet the VPP obligation. Accordingly, the VPP obligation is not expected to affect the liquidity of the Partnership. To the extent that Pioneer fails to make any cash payment associated with any of the Partnership's volumes delivered pursuant to the VPP obligation, the decrease in the Partnership's production would result in a decrease in the Partnership's cash available for distribution.

 

Gas production from Pioneer's retained interest in the properties subject to the VPP obligation during the nine months ended September 30, 2007 was not adequate to meet the VPP obligation and a portion of the Partnership Predecessor's gas production was utilized to fund the VPP obligation. Accordingly, the accompanying consolidated financial statements, for the nine months ended September 30, 2007, do not include gas revenues of $173 thousand that would have been recognized absent the VPP obligation. The production associated with the excluded gas revenue was approximately 33,866 Mcf for the nine months ended September 30, 2007. The gas VPP obligation expired at December 31, 2007.

 

 

The Partnership uses financial derivative contracts to manage exposures to commodity price fluctuations. The Partnership generally does not enter into derivative financial instruments for speculative or trading purposes. The Partnership's production may also be sold under physical delivery contracts that effectively provide commodity price hedges. Because physical delivery contracts are not expected to be net cash settled, they are considered to be

 

 

 

normal sales contracts and not derivatives. Therefore, physical delivery contracts are not recorded in the financial statements.

 

On May 6, 2008, novation agreements were entered into among Pioneer, the Partnership and certain derivative instrument counterparties, which transferred Pioneer's rights and responsibilities under certain derivative instruments to the Partnership. As of May 6, 2008, the aggregate fair value of the derivative instruments novated to the Partnership represented a liability of approximately $37.2 million. Changes in the fair values of the derivative instruments subsequent to May 6, 2008, to the extent that they are effective as hedges of the designated commodity price risk, are being deferred and recognized in the Partnership's earnings in the same periods as the forecasted sales being hedged.

 

The following table provides the settled or scheduled settlements of the novated hedge liability, but excludes changes in the fair values of the derivative instruments subsequent to the novation date:

 

_____________

(a) Novated hedge liabilities for the second and third quarters of 2008 have matured and settled with the derivative counterparties.

 

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

 

Cash flow hedges. The Partnership primarily utilizes commodity swap and collar contracts to (i) reduce the impact on the Partnership's results of operations from the price volatility of the commodities the Partnership produces and sells and (ii) help sustain unitholder distributions.

 

 

 

Oil prices. All material physical sales contracts governing the Partnership'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 Partnership reports average oil prices per Bbl including the effects of oil quality adjustments and the net effect of oil hedges (for periods subsequent to the Offering). The following table sets forth (i) the Partnership's oil prices, both reported (including hedge results) and realized (excluding hedge results), and (ii) the net effect of oil price hedges on oil revenue for the three and nine month periods ended September 30, 2008 and 2007:

 

            

Natural gas liquids prices. All material physical sales contracts governing the Partnership's NGL production have been tied directly or indirectly to Mont Belvieu-posted-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 Partnership reports average NGL prices per Bbl including the effects of NGL quality adjustments and the net effect of NGL hedges (for periods subsequent to the Offering). The following table sets forth (i) the Partnership's NGL prices, both reported (including hedge results) and realized (excluding hedge results) and (ii) the net effect of NGL price hedges on NGL revenue for the three and nine month periods ended September 30, 2008 and 2007:

 

 

 

Gas prices. The Partnership 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 Partnership reports average gas prices per Mcf including the effects of Btu content, gas processing, shrinkage adjustments and the net effect of gas hedges (for periods subsequent to the Offering). The following table sets forth (i) the Partnership's gas prices, both reported (including hedge results) and realized (excluding hedge results) and (ii) the net effect of gas price hedges on gas revenue for the three and nine month periods ended September 30, 2008 and 2007:

 

 

AOCI - Hedging. As of September 30, 2008 and December 31, 2007, AOCI - Hedging represented net deferred gains of $40.0 million and $0, respectively. The increase in 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 during the period from May 6, 2008 through September 30, 2008. The net deferred

 

 

 

gains 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 Partnership recorded $33 thousand of hedge ineffectiveness as a net charge to other expense associated with hedging activities during the three and nine months ended September 30, 2008.

During the twelve months ending September 30, 2009, based on September 30, 2008 estimates of future commodity prices and interest rates, the Partnership expects to reclassify approximately $16.7 million of net deferred hedge gains and approximately $167 thousand of deferred Texas Margin tax provisions associated with open commodity hedges from AOCI - Hedging to commodity revenues and income tax provisions, respectively.

 

 

Set forth below are descriptions of certain agreements the Partnership entered into with related parties in connection with the Offering. The descriptions are not complete and are qualified in their entirety by reference to the full text of the agreements, which have been filed by the Partnership as exhibits to filings with the SEC.

 

Administrative Services Agreement  

 

Pursuant to an Administrative Services Agreement among Pioneer Natural Resources USA, Inc. ("Pioneer USA"), a wholly-owned subsidiary of Pioneer, Pioneer GP, Pioneer Southwest USA and the Partnership, entered into on May 6, 2008, Pioneer USA agreed to perform, either itself or through its affiliates or other third parties, administrative services for the Partnership, and the Partnership agreed to reimburse Pioneer USA for its expenses incurred in providing such services. These administrative services may include accounting, internal audit, business development, finance, land, legal, engineering, investor relations, management, marketing, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. Initially, expenses will be reimbursed based on a methodology of determining the Partnership's share, on a per BOE basis, of certain of the general and administrative costs incurred by Pioneer USA. Under this initial methodology, the per BOE cost for services during any period will be determined by dividing (i) the aggregate general and administrative costs, determined in accordance with GAAP, of Pioneer (excluding the Partnership's general and administrative costs), for its United States operations during such period, excluding such costs directly attributable to Pioneer's Alaskan operations, by (ii) the sum of (x) the United States production during such period of the Partnership and Pioneer, excluding any production attributable to Alaskan operations, plus (y) the volumes delivered by Pioneer and the Partnership under all volumetric production payment obligations during such period. The costs of all awards under the Partnership's long-term incentive plan will be borne by the Partnership, and will not be included in the foregoing formula. The administrative fee will be determined by multiplying the per BOE costs by the Partnership's total production (including volumes delivered by the Partnership under volumetric production payment obligations, if any) during such period. The administrative fee may be based on amounts estimated by Pioneer if actual amounts are not available. In addition, Pioneer will be reimbursed for any out-of-pocket expenses it incurs on the Partnership's behalf. The Administrative Services Agreement can be terminated by the Partnership or Pioneer USA at any time upon 90 days notice.

 

Omnibus Agreement  

 

Pursuant to an Omnibus Agreement among Pioneer, Pioneer USA, Pioneer GP, Pioneer Southwest USA and the Partnership, entered into on May 6, 2008, the Partnership's area of operations is limited to onshore Texas and eight counties in the southeast region of New Mexico. Pioneer has the right to expand the Partnership's area of operations, but has no obligation to do so. The Omnibus Agreement also provides that Pioneer will indemnify the Partnership for (i) liabilities with respect to claims associated with the use, ownership and operation of the Partnership Properties, (ii) certain potential environmental liabilities associated with the operation of the Partnership Properties prior to May 6, 2008, (iii) losses attributable to defects in title to the Partnership's interest in then-producing intervals in the Partnership's wellbores, and (iv) taxes attributable to the operations of the Partnership Properties prior to May 6, 2008. The agreement provides limitations as to time and dollar amounts with respect to Pioneer's indemnities. The Omnibus Agreement also provides for the payment by Pioneer to the Partnership in the

 

 

 

event any production from the interests in the properties that the Partnership owns is required to meet the VPP obligation, as described above.

 

Omnibus Operating Agreement  

 

Pursuant to an Omnibus Operating Agreement between Pioneer USA and Pioneer Southwest USA entered into on May 6, 2008, certain restrictions and limitations were placed on the Partnership's ability to exercise certain rights that would otherwise be available to it under the operating agreements that govern the Partnership Properties where Pioneer USA is the operator. For example, the Partnership will not object to attempts by Pioneer USA to develop the leasehold acreage surrounding the Partnership's wells; the Partnership will be restricted in its ability to remove Pioneer USA as the operator of the wells the Partnership owns; Pioneer USA proposed well operations will take precedence over any conflicting operations that the Partnership proposes; and the Partnership will allow Pioneer USA to use certain of the Partnership's production facilities in connection with other wells operated by Pioneer USA, subject to capacity limitations.

 

Tax Sharing Agreement  

 

Pursuant to a Tax Sharing Agreement between Pioneer and the Partnership, entered into on May 6, 2008, the Partnership will pay Pioneer for its share of state and local income and other taxes, currently only the Texas Margin tax, for which the Partnership's results are included in a combined or consolidated tax return filed by Pioneer.

 

First Amended and Restated Agreement of Limited Partnership of Pioneer Southwest Energy Partners L.P. (the "Partnership Agreement")

 

The Partnership Agreement was entered into by Pioneer GP, in its capacity as the general partner of the Partnership and on behalf of the limited partners of the Partnership, and Pioneer USA, as the "Organizational Limited Partner," on May 6, 2008, and governs the rights of the partners in the Partnership.

 

2008 Long-Term Incentive Plan

 

The board of directors of Pioneer GP has adopted the Pioneer Southwest Energy Partners L.P. 2008 Long-Term Incentive Plan (the "LTIP") for directors, employees and consultants of Pioneer GP and its affiliates who perform services for the Partnership, which provides for the granting of incentive awards in the form of options, restricted units, phantom units, unit appreciation rights, unit awards and other unit-based awards. The LTIP limits the number of units that may be delivered pursuant to awards granted under the LTIP to 3,000,000 common units.

 

During May 2008, Pioneer GP awarded 12,630 restricted units to directors of Pioneer GP under the LTIP, of which 6,315 represented the initial restricted unit grant and will vest ratably over three years and 6,315 represented the initial annual restricted unit grant and will vest in May 2009. Associated therewith, the Partnership recognized $40 thousand and $67 thousand of general and administrative expense during the three months ended September 30, 2008 and the period from May 6, 2008 through September 30, 2008, respectively.

 

Indemnification Agreements  

 

Pursuant to Indemnification Agreements entered into with each of the independent directors of Pioneer GP, the Partnership is required to indemnify each indemnitee to the fullest extent permitted by the Partnership Agreement. This means, among other things, that the Partnership must indemnify the director against expenses (including attorneys' fees), judgments, penalties, fines and amounts paid in settlement that are actually and reasonably incurred in an action, suit or proceeding by reason of the fact that the person is or was a director of Pioneer GP or is or was serving at Pioneer GP's request as a director, officer, employee or agent of another corporation or other entity if the indemnitee meets the standard of conduct provided in the Partnership Agreement. Also, as permitted under the Partnership Agreement, the indemnification agreements require the Partnership to advance expenses in defending such an action provided that the director undertakes to repay the amounts if the person ultimately is determined not to be entitled to indemnification from the Partnership. The Partnership will also

 

 

 

make the indemnitee whole for taxes imposed on the indemnification payments and for costs in any action to establish the indemnitee's right to indemnification, whether or not wholly successful.

 

In accordance with standard industry operating agreements and the agreements described above, the Partnership incurred the following charges from Pioneer during the three months ended September 30, 2008 and the period from May 6, 2008 through September 30, 2008:

 

 

As of September 30, 2008, the Partnership's accounts payable-affiliate balance in the accompanying consolidated balance sheet is comprised of $5.2 million of Offering costs paid by Pioneer and approximately $3.6 million of unpaid COPAS fees, lease operating expenses and general and administrative expenses.

 

 

Distribution declaration. In October 2008, the Partnership declared a cash distribution of $0.50 per common unit for the period from July 1, 2008 to September 30, 2008. The distribution is payable on November 12, 2008 to unitholders of record at the close of business on November 3, 2008. Associated therewith, the Partnership will pay $15.0 million of aggregate distributions.

 

 

 

 

 

Financial and Operating Performance

 

The Partnership'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, the 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 and support the financial markets. The success of the steps taken and the duration of the uncertainty in the financial markets cannot be prediceted.  The Partnership is closely monitoring the economic environment, but does not expect the current market conditions to significantly impact its liquidty, future results of operations or financial position.

 

As of September 30, 2008, the Partnership had $28.8 million of cash and cash equivalents on deposit, held approximately $13.1 million of accounts receivable from purchasers of oil, NGL and gas production, was a party to derivative financial instruments, of which $16.7 million represent assets of the Partnership, had no outstanding long-term debt and had approximately $200 million of available borrowing capacity under the Credit Facility. The Partnership is monitoring the liquidity and 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 Spraberry gas price differentials relative to NYMEX quoted prices, have been negatively impacted by increasing supplies resulting from a rise in domestic production. Although the Partnership has hedged a large portion of its production volumes for the next three years, a sustained lower commodity price environment would result in lower realized prices for unhedged volumes and reduce the prices at which the Partnership could hedge additional volumes in the future. As a result, the Partnership's internal cash flows would be reduced for affected periods. The duration and magnitude of the commodity price declines cannot be predicted.

 

Hurricane Ike. During the second week of September 2008, Hurricane Ike struck the Texas gulf coast. The Partnership's Spraberry field production facilities were not directly impacted by the hurricane. However, third-party downstream production handling and processing facilities were damaged, which had the effect of delaying sales of portions of the Partnership's third quarter 2008 NGL volumes and temporarily curtailing oil and gas production from certain of the Partnership's properties. Associated therewith, the Partnership recorded $162 thousand of NGL inventories as of September 30, 2008. Third quarter production was negatively impacted by the loss of approximately 250 BOEPD of production as a result of the hurricane. Delays have continued during the fourth quarter of 2008, with full production expected to be restored by mid-November.

 

Initial public offering. On May 6, 2008, the Partnership completed its initial public offering of 9,487,500 common units, including the units issued pursuant to the exercise of the underwriters' over-allotment option, representing a 31.6 percent limited partner interest in the Partnership. Pioneer owns a 0.1 percent general partner interest and a 68.3 percent limited partner interest in the Partnership. The Partnership used the net proceeds of $163.1 million from the offering to acquire an interest in Pioneer Southwest USA, the entity through which Pioneer

 

 

 

owned the Partnership's oil and gas properties in the Spraberry field, and to acquire an incremental working interest in certain of the oil and gas properties owned by Pioneer Southwest USA.

 

The acquisition of the incremental interest in certain of the oil and gas properties owned by Pioneer Southwest USA resulted in a change in reporting entity for periods prior to May 6, 2008. Accordingly, the historic financial position, results of operations and cash flows of the Partnership Predecessor have been recast in this Report to effect the change in reporting entity. See Note B of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the change in reporting entity.

 

Novation of derivative agreements. On May 6, 2008, novation agreements were entered into among Pioneer, the Partnership and certain derivative instrument counterparties, which transferred Pioneer's rights and responsibilities under certain derivative instruments to the Partnership. The novated derivative agreements were designated as cash flow hedges of portions of the Partnership's oil, NGL and gas commodity price risk for forecasted sales for the periods from May 2008 through December 2008 and the years of 2009 and 2010. As of May 6, 2008, the aggregate fair value of the derivative instruments novated to the Partnership represented a liability of approximately $37.2 million. Changes in the fair values of the derivative instruments subsequent to May 6, 2008, to the extent that they are effective as hedges of the designated commodity price risk, are being deferred and recognized in the Partnership's earnings in the same periods as the forecasted commodity sales being hedged. See Note H 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 regarding these derivative instruments.

 

Midkiff-Benedum Gas Processing System . During the third quarter of 2008, Pioneer entered into negotiations with the Partnership relating to the assignment of a portion of Pioneer's option to acquire an interest in the Spraberry Midkiff-Benedum gas processing system (the "System") in West Texas from Atlas Pipeline Partners, and the Partnership has been evaluating the option and the underlying assets of the System. The Partnership and Pioneer have decided not to pursue the assignment or the acquisition of an interest in the System at this time due to the uncertainty underlying current market conditions.

 

Pioneer currently owns a 27 percent interest in the System and the option is exercisable for an additional 22 percent interest in the System for $230 million, subject to normal closing adjustments. Under the terms of the option agreement, the option is exercisable by Pioneer (the holder) for up to a 14.56 percent interest in 2008, and any unexercised portion of the option, up to the full 22 percent, may be exercised between June and November 2009.

 

The Partnership expects that in the future Pioneer will consider the assignment to the Partnership of the option, or some portion thereof. Any such assignment would be subject to negotiation of definitive agreements and the approval of the board of directors of Pioneer GP and the Conflicts Committee of the board. There can be no assurance that Pioneer will assign all or any portion of the option to the Partnership or as to the terms of any such assignment.

 

Fourth Quarter 2008 Outlook

 

Based on current estimates, the Partnership expects that fourth quarter 2008 production will average 4,600 to 4,800 BOEPD, reflecting the continuation of shut in and curtailed wells until the third-party NGL fractionation facilities are restored in mid-November. Production lost for the quarter is estimated to be approximately 150 BOEPD.

 

Fourth quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $24.00 to $27.00 per BOE based on current NYMEX strip prices for oil, NGLs and gas. Depletion, depreciation and amortization ("DD&A") expense is expected to average $4.00 to $4.50 per BOE.

 

General and administrative expense is expected to be $1 million to $2 million. Interest expense and accretion of discount on asset retirement obligations are both expected to be nominal.

 

The Partnership's fourth quarter 2008 cash taxes and effective income tax rate are expected to be approximately one percent as a result of the Partnership being subject to the Texas Margin tax.

 

 

 

Operations Highlights

 

The Partnership's properties are entirely composed of producing oil and gas properties. Producing oil and gas reservoirs are characterized by declining production rates. Because the Partnership does not own any undeveloped properties or leasehold acreage, its reserves and production are expected to decline continually over time unless the Partnership mitigates the declines through production enhancement or drilling initiatives or acquires additional properties to replace its declining production. The Partnership may benefit from production and reserve enhancements as a result of infill drilling and secondary recovery initiatives that are being advanced by Pioneer. At Pioneer's request, the Railroad Commission of Texas amended its rules in October 2008 to allow Pioneer and other operators, at their option, to down space well locations in the Spraberry field to 20-acre spacing. The Partnership has the right to drill the 20-acre locations surrounding its wells and is considering drilling a limited number of wells in 2009 if margins improve. Pioneer is also evaluating waterflood projects in the Spraberry field. The ultimate outcome and impact to the Partnership of these initiatives cannot be predicted at this time.

 

To fund production enhancement and drilling initiatives and future property acquisitions, the Partnership anticipates reserving a portion of its net cash provided by operating activities. The Partnership may also use, to the extent available, external financing sources to fund acquisitions, including borrowings under the Credit Facility and funds from future private and public equity and debt offerings. See "Recent Events – Financial markets" for a discussion of the recent uncertainties in traditional short- and long-term liquidity sources, and "Capital Commitments, Capital Resources and Liquidity" below.

 

During the three and nine months ended September 30, 2008, the Partnership expended approximately $1.3 million and $1.5 million, respectively, for additions to its oil and gas properties, which expenditures primarily represented development recompletions of existing horizontal wells owned by the Partnership.

 

Results of Operations

 

Oil and gas revenues. Oil and gas revenues totaled $40.2 million and $117.4 million for the three and nine months ended September 30, 2008, respectively, as compared to $29.0 million and $76.5 million for the same respective periods of 2007.

 

The increase in oil and gas revenues during the three and nine months ended September 30, 2008, as compared to the same periods of 2007, is primarily due to increases in commodity prices, partially offset by decreases of 13 percent and eight percent, respectively, in total sales volumes on an average daily sales volume basis. In the quarter-to-quarter and nine month-to-nine month comparisons, the average reported oil price increased by 58 percent and 70 percent, respectively; the average reported NGL price increased by 45 percent and 47 percent, respectively; and the average reported gas price increased by 79 percent and 46 percent, respectively. The decreases in sales volumes were due to normal production declines and to the aforementioned effect of Hurricane Ike.

 

The following table provides average daily sales volumes for the three and nine months ended September 30, 2008 and 2007:

 

 

 

 

The following table provides the Partnership's average reported prices for the three and nine months ended September 30, 2008 and 2007:

 

 

The Partnership's NGL price realizations were approximately 50 percent and 52 percent of NYMEX calendar month average oil prices for the three and nine month periods ended September 30, 2007, respectively; however, during the three and nine month periods ended September 30, 2008, the Partnership's NGL price realizations declined to approximately 47 percent and 44 percent of NYMEX calendar month average oil prices, respectively. The decreases resulted primarily from propane and ethane prices (the principal components of the Partnership's NGL stream) not increasing proportionately with NYMEX calendar month oil prices due to the supply and demand fundamentals specific to those products.

 

Since September 30, 2008, market-quoted commodity prices have significantly declined from levels reported by the Partnership as of and for the periods ended September 30, 2008. Although mitigated by the Partnership's hedging activities, the decline in commodity prices will reduce the Partnership's revenues and distributable cash. See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for information regarding commodity price risk and the Partnership's derivative financial instruments.

 

Hedging activities . The Partnership expects to utilize commodity swap and option contracts primarily to reduce the impact on the Partnership's net cash provided by operating activities and results of operations from the price volatility of the commodities the Partnership produces and sells. During the three and nine months ended September 30, 2007, the Partnership Predecessor had no hedging activities. On May 6, 2008, Pioneer novated oil, NGL and gas swap contracts to the Partnership that have been designated as hedges of portions of the Partnership's forecasted May through December 2008, and annual 2009 and 2010 oil, NGL and gas sales. In addition to the novated hedges, the Partnership has entered into incremental 2009 and 2010 NGL swap contracts and an oil collar contract for a portion of the Partnership's forecasted 2011 oil sales. See Note H 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 these derivatives.

 

Oil and gas production costs. The Partnership recorded oil and gas production costs of $12.1 million and $32.5 million during the three and nine months ended September 30, 2008, respectively, as compared to $7.9 million and $23.5 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 Partnership has management control, while production and ad valorem taxes are directly related to commodity price changes. During the three and nine months ended September 30, 2008, total oil and gas production costs per BOE increased by 76 percent and 49 percent, respectively, as compared to the three and nine months ended September 30, 2007, primarily due to (i) declines in the volumes over which the fixed portion of production costs per BOE are attributed, which declines are due to normal production declines and to production declines due to Hurricane Ike, (ii) increases in lease operating expense due to increased electricity costs, salt water disposal fees and oilfield well servicing activity and general oilfield services price inflation, (iii) increases in production taxes due to commodity price increases and (iv) increases in workover costs incurred to maximize production volumes as wells mature, partially offset by (v) a slight decline in ad valorem taxes in the nine month comparisons, primarily resulting from the effects of tax reform legislation in Texas.

 

In addition to the above explanation of higher lease operating expenses, the Partnership's lease operating expense also included an allocation of Pioneer's direct internal costs associated with the operation of the Partnership Properties for periods prior to the Offering. In May 2008, Pioneer, as operator, began charging the Partnership

 

 

 

overhead charges associated with operating the Partnership Properties (commonly referred to as the Council of Petroleum Accountants Societies (or "COPAS") fee), instead of the direct internal costs incurred by Pioneer. Assuming the COPAS fee had been charged in the Partnership Predecessor's historical results, the lease operating expense would have been higher on a BOE basis by $3.04 for the three months ended September 30, 2007 and $1.32 and $3.02 for the nine months ended September 30, 2008 and 2007, respectively.

 

The following table provides the components of the Partnership's total oil and gas production costs per BOE for the three and nine months ended September 30, 2008 and 2007:

 

 

Depletion, depreciation and amortization expense. The Partnership's DD&A expense was $1.8 million ($4.06 per BOE) and $5.2 million ($3.79 per BOE) for the three and nine months ended September 30, 2008, respectively, as compared to $2.2 million ($4.41 per BOE) and $6.6 million ($4.46 per BOE) for the three and nine months ended September 30, 2007, respectively. The decrease in DD&A expense was primarily due to production declines and proved reserve increases reflecting commodity price increases and, to a lesser extent, positive 2007 drilling results.

 

General and administrative expense. General and administrative expense was $1.1 million and $3.8 for the three and nine months ended September 30, 2008, respectively, as compared to $1.1 million and $3.3 million for the three and nine months ended September 30, 2007, respectively. The increase in general and administrative expense in the nine month comparisons is due primarily to legal, accounting and other costs associated with being a public company that were not necessary prior to the Offering. For periods prior to the Offering, general and administrative expense consisted of an allocation of a portion of Pioneer's general and administrative expense based on the Partnership Predecessor's production as compared to Pioneer's total production from its United States properties (other than Alaska), as measured on a per barrel of oil equivalent basis. The Partnership and Pioneer entered into an Administrative Services Agreement as of May 6, 2008, pursuant to which Pioneer agreed to perform, either itself or through its affiliates or other third parties, administrative services for the Partnership, and the Partnership agreed to reimburse Pioneer for its expenses incurred in providing such services. Pioneer has informed the Partnership that, initially, expenses will be reimbursed based on a methodology of determining the Partnership's share, on a per BOE basis, of certain of the general and administrative costs incurred by Pioneer. Subsequent to the Offering, the Partnership is also responsible for paying for third-party services. See Note I of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the general and administrative expense allocations to the Partnership.

 

Income tax provision. The Partnership recognized income tax provisions of $311 thousand and $839 thousand during the three and nine months ended September 30, 2008, respectively, as compared to $187 thousand and $462 thousand for the same respective periods of 2007. The Partnership's effective tax rate is approximately one percent, reflective of the Texas Margin tax. See Note E of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Partnership's income taxes.

 

Capital Commitments, Capital Resources and Liquidity

 

Capital commitments. The Partnership's primary needs for cash will be for production growth through acquisitions, production enhancements and/or drilling initiatives and for unitholder distributions. The Partnership

 

 

 

may use any combination of internally- and externally-financed sources to fund acquisitions and unitholder distributions, including borrowings under the Credit Facility and funds from future private and public equity and debt offerings. As a result of the current circumstances in worldwide financial markets, the availability of external sources of short- and long-term capital funding is uncertain. Consequently, the Partnership expects that (i) capital expenditures and unitholder distributions will be funded by internal operating cash flows and (ii) acquisitions will be funded by cash reserves and availability under the Credit Facility for the foreseeable future. Although the Partnership expects that internal cash flows will be adequate to fund capital expenditures and unitholder distributions, and that available borrowing capacity under the Credit Facility will provide adequate liquidity to fund future acquisitions, no assurances can be given that such funding sources will be adequate to meet the Partnership's future needs.

 

The Partnership Agreement requires that the Partnership distribute all of its available cash to its partners. In general, available cash is defined to mean cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves for future capital expenditures (including acquisitions), operational needs and distributions for any one or more of the next four quarters. Because the Partnership's proved reserves and production decline continually over time, the Partnership will need to acquire income producing assets to sustain its level of distributions to unitholders over time. Currently, the Partnership expects to reserve approximately 25 percent to 35 percent of its cash flow to acquire oil and gas assets in order to maintain its production and proved reserves. The Partnership has adopted a cash distribution policy pursuant to which it intends to declare distributions of $0.50 per unit per quarter, or $2.00 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter. The distribution for the third quarter of 2008 of $0.50 per unit was declared by the Board of Directors of Pioneer GP and is to be paid on November 12, 2008 to unitholders of record on November 3, 2008.

 

Although Pioneer has no obligation to sell assets to the Partnership, and the Partnership is not obligated to purchase from Pioneer any additional assets, Pioneer has informed the Partnership that it intends to offer to the Partnership periodically the opportunity to purchase from Pioneer assets in the Partnership's area of operations. The Partnership also may make acquisitions of oil and gas assets in its area of operations from third parties and may participate jointly in acquisitions with Pioneer in which the Partnership could acquire the producing oil and gas properties and Pioneer could acquire the undeveloped properties. Any assets that the Partnership acquires from either Pioneer or third parties may include interests in midstream assets.

 

Oil and gas properties. The Partnership's cash expenditures for additions to oil and gas properties during the three and nine month periods ended September 30, 2008, totaled $1.3 million and $1.5 million, respectively, as compared to $1.2 million and $7.9 million for the same respective periods of 2007. The Partnership's expenditures for additions to oil and gas properties for the three and nine month periods ended September 30, 2008 and 2007 were funded by net cash provided by operating activities.

 

Contractual obligations, including off-balance sheet obligations. As of September 30, 2008, the Partnership's contractual obligations were limited to asset retirement obligations, contingent VPP obligations and derivative obligations. The Partnership's asset retirement obligations and contingent VPP obligations have not materially changed since December 31, 2007. The fair value of the Partnership's derivative instruments represented a net asset of approximately $10.3 million as of September 30, 2008, which was comprised of approximately $16.7 million of derivative assets and approximately $6.4 million of derivative obligations. As of September 30, 2008, the Partnership was not a party to any material off-balance sheet arrangements. See Note H 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 regarding the Partnership's derivative obligations.

 

Virtually all of the properties that the Partnership owns are subject to the VPP. Pioneer has agreed that production from its retained properties subject to the VPP will be utilized to meet the VPP obligation prior to utilization of production from the Partnership Properties subject to the VPP, and it is expected that the VPP obligation can be fully satisfied by delivery of production from properties that are retained by Pioneer. If any production from the interests in the properties that the Partnership owns is required to meet the VPP obligation, Pioneer has agreed that it will make a cash payment to the Partnership for the value of the production (computed by taking the volumes delivered to meet the VPP obligation times the price the Partnership would have received for the related volumes, plus any out-of-pocket expenses or other expenses or losses incurred in connection with the delivery of such volumes) required to meet the VPP obligation. Accordingly, the VPP obligation is not expected to

 

 

 

affect the liquidity of the Partnership. To the extent Pioneer fails to make any cash payment associated with any of the Partnership's volumes delivered pursuant to the VPP obligation, the decrease in the Partnership's production would result in a decrease in the Partnership's cash available for distribution.

 

On May 6, 2008, novation agreements were entered into among Pioneer, the Partnership and certain derivative instruments counterparties, which transferred Pioneer's rights and responsibilities under certain derivative instruments to the Partnership. The novated derivative agreements were designated as cash flow hedges of portions of the Partnership's oil, NGL and gas commodity price risk for forecasted sales for the period from May 2008 through December 2008 and the years 2009 and 2010. As of May 6, 2008, the aggregate fair value of the derivative instruments novated to the Partnership represented a liability of approximately $37.2 million. Changes in the fair values of the derivative instruments subsequent to May 6, 2008, to the extent that they are effective as hedges of the designated commodity price risk, are being deferred and recognized in the Partnership's earnings in the same periods as the forecasted commodity sales being hedged.

 

The ultimate liquidation value of the Partnership's commodity derivatives will be dependent upon actual future commodity prices, which may differ materially from the inputs used to determine the derivatives' fair values at any point in time. The Partnership entered into these derivatives for the primary purpose of hedging commodity price risk on forecasted physical commodity sales and has an expectation of a high degree of correlation between changes in the derivative values and the hedged risks. See Notes C and H 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 valuation and composition of the Partnership's derivative instruments and market risk.

 

Capital resources. The Partnership's primary capital resources are expected to be net cash provided by operating activities, amounts available under its Credit Facility and, to the extent available, funds from future private and public equity and debt offerings.

 

Operating activities. Net cash provided by operating activities during the three and nine months ended September 30, 2008 was $30.9 million and $91.9 million, respectively, as compared to $20.7 million and $51.5 million for the same respective periods of 2007. The increases in net cash provided by operating activities during the three and nine month periods ended September 30, 2008, as compared to the three and nine month periods ended September 30, 2007, are primarily due to increased oil, NGL and gas sales prices, partially offset by declines in sales volumes and 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 Partnership's hedging activities, will reduce the Partnership's internal cash flows. The duration and magnitude of the commodity price declines cannot be predicted.

 

Investing activities. Investing activities used $1.6 million and $142.4 million of cash during the three and nine month periods ended September 30, 2008, respectively, as compared to $1.2 million and $7.9 million for the same respective periods of 2007. The increase 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 the payment of accruals for capital expenditures as of the Offering. The increase in net cash used in investing activities during the first nine months of 2008 as compared to the first nine months of 2007 is primarily due to the acquisition of properties in connection with the Offering in 2008. Future investing activities may include expenditures to drill a limited number of 20-acre locations surrounding its wells if margins improve.

 

Financing activities. Net cash used in financing activities during the three months ended September 30, 2008 was $13.0 million, as compared to net cash used in financing activities of $19.5 million during the three months September 30, 2007. The decrease in net cash used in financing activities during the three months ended September 30, 2008, as compared to the three months ended September 30, 2007, was primarily due to a $10.5 million decline in distributions to the Partnership's owner and partners, partially offset by a $4.3 million increase in the payment of derivative obligations. Net cash provided by financing activities during the first nine months of 2008 was $79.2 million as compared to net cash used by financing activities of $43.6 million during the same respective period of 2007. The increase in net cash provided by financing activities during the nine months ended September 30, 2008, as compared to the same period of 2007, was due primarily to proceeds received from the Offering, partially offset

 

 

 

by the acquisition of Partnership Properties in excess of carrying value, an increase in distributions to the Partnership's owner and partners and the 2008 payment of approximately $7.1 million of novated derivative obligations. The Partnership's financing activities for periods prior to the Offering were limited to distributions of cash to Pioneer.

 

Liquidity. The Partnership's principal source of short-term liquidity has been cash generated from its operations. In connection with the Offering, the Partnership closed on its $300 million revolving Credit Facility on May 6, 2008. As of September 30, 2008, the Partnership had approximately $200 million of available borrowing capacity under the Credit Facility. See Note D of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information regarding the Credit Facility.

 

The Partnership expects that its primary sources of liquidity will be cash generated from operations, amounts available under the Credit Facility and, to the extent available, funds from future private and public equity and debt offerings. As discussed above under "Capital commitments," the Partnership Agreement requires that the Partnership distribute all of its available cash to its unitholders and the general partner. In addition, because the Partnership's proved reserves and production decline continually over time, the Partnership will need to replace production to sustain its level of distributions to unitholders over time. Accordingly, the Partnership's primary needs for cash will be for production growth through acquisitions, production enhancements and/or drilling initiatives (such as 20-acre infill wells) and for distributions to partners. In making cash distributions, the general partner will attempt to avoid large variations in the amount the Partnership distributes from quarter to quarter. The Partnership Agreement permits the general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters, and for the conduct of the Partnership's business, which includes possible acquisitions. If cash flow from operations does not meet the Partnership's expectations, the Partnership may reduce its level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of its capital expenditures using borrowings under the Credit Facility, issuances of debt or equity securities or from other sources, such as asset sales or reduced distributions. The Partnership cannot provide any assurance that needed capital will be available on acceptable terms or at all. Although the Partnership expects that internal cash flows will be adequate to fund capital expenditures and unitholder distributions, and that available borrowing capacity under the Credit Facility will provide adequate liquidity to fund future acquisitions, no assurances can be given that such funding sources will be adequate to meet the Partnership's future needs.

 

The Partnership Agreement allows the Partnership to borrow funds to make distributions. The Partnership may borrow to make distributions to unitholders, for example, in circumstances where the Partnership believes that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain its level of distributions. In addition, the Partnership plans to hedge a significant portion of its production. The Partnership is generally required to settle its commodity hedge derivatives within five days of the end of a month. As is typical in the oil and gas industry, the Partnership does not generally receive the proceeds from the sale of its hedged production until 45 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the derivative contracts, the Partnership will be required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before the Partnership receives the proceeds from the sale of the hedged production. If this occurs, the Partnership may make working capital borrowings to fund its distributions.

 

New accounting pronouncements. In September 2006, the FASB issued SFAS No. 157, "Fair Value Measures" ("SFAS 157"). SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. In February 2008, the FASB issued FASB Staff Position No. 157-2 ("FSP FAS 157-2"). FSP FAS 157-2 delays 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 Partnership adopted the provisions of SFAS 157 as they pertain to financial assets and liabilities. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Partnership'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 Partnership.

 

 

 

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 Partnership 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 Partnership.

 

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 noncontractual 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 Partnership.

 

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

 

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 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 Partnership does not expect that the adoption of SFAS 162 will have a significant impact on the Partnership'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 unit under the two class method prescribed under SFAS 128 "Earnings per Share". FSP EITF 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 unit data to conform to the provisions of the standard. The implementation of FSP EITF 03-6-1 is not expected to have a material effect on the Partnership's net income per unit calculations.

 

 

 

 

              The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Partnership's potential exposure to market risks. The term "market risks", insofar as it relates to currently anticipated transactions of the Partnership, refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Partnership views and manages ongoing market risk exposures. All of the Partnership's market risk sensitive instruments are entered into for purposes other than speculative.

 

Due to the historical volatility of commodity prices, the Partnership will continue to be a party to various derivative instruments to manage its exposure to volatility of commodity market prices. The Partnership has adopted a policy that contemplates hedging the prices for approximately 65 to 85 percent of expected production for a period of up to five years, as appropriate. Implementation of this policy is expected to mitigate, but will not eliminate, the Partnership's sensitivity to short-term changes in commodity prices. The Credit Facility requires it to enter into hedging arrangements for not less than 65 percent (nor more than 85 percent) of the Partnership's projected oil, NGL and gas production attributable to proved developed producing reserves through December 31, 2010. In addition, within the next six months, the Credit Facility requires that the Partnership enter into hedging arrangements for not less than 50 percent of the Partnership's projected oil, NGL and gas production attributable to proved developed producing reserves through December 31, 2011. The Partnership may use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in commodity prices on its cash available for distributions. All contracts will be settled with cash and do not require the delivery of physical volumes to satisfy settlement. While in times of higher commodity prices this strategy may result in the Partnership having lower net cash inflows than would be the case if these instruments were not utilized, management believes the risk reduction benefits of this strategy outweigh the potential costs. As of September 30, 2008, the Partnership has entered into hedging arrangements for approximately 75 percent, 65 percent and 45 percent of the Partnership's expected production in 2009, 2010 and 2011, respectively. Since September 30, 2008, market-quoted commodity prices have declined significantly from levels reported by the Partnership as of and for the periods ended September 30, 2008. Although mitigated by the Partnership's hedging activities, the decline in commodity prices will reduce the Partnership's revenues and distributable cash and, if sustained, significantly increase the Partnership's commodity hedge assets. Recent uncertainties in worldwide financial markets may have the effect of reducing liquidity in the financial derivatives market, which hampers the Partnership'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."

 

The Partnership may, to the extent available in the financial markets, borrow under fixed rate and variable rate debt instruments that give rise to interest rate risk. The objective in borrowing under fixed or variable rate debt is to satisfy capital requirements while minimizing the Partnership's costs of capital.

 

On May 6, 2008, novation agreements were entered into among Pioneer, the Partnership and derivative instrument counterparties, which transferred Pioneer's rights and responsibilities under certain derivative instruments to the Partnership. The May 6, 2008 novation of the derivative agreements reduced the Partnership's owners' net equity. As of May 6, 2008, the aggregate fair value of the derivative instruments novated to the Partnership represented a liability of approximately $37.2 million. Changes in the fair values of the derivative instruments subsequent to May 6, 2008, to the extent that they are effective as hedges of the designated commodity price risk, are being deferred and recognized in the Partnership's earnings in the same periods as the forecasted commodity sales being hedged.

 

 

 

 

The following table reconciles the changes that occurred in the fair values of the Partnership's open derivative contracts during the first nine months of 2008 (in thousands):

 

 

_____________

 

 

 

The following table provides information about the Partnership's oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL or gas prices as of September 30, 2008, all of which qualify as hedges:

Oil, NGL and Gas Price Sensitivity

Derivative Financial Instruments as of September 30, 2008

 

 

 

_____________

 

 

 

 

Evaluation of disclosure controls and procedures. Management of the Partnership's general partner, with the participation of the general partner's 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 Partnership'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 of the Partnerhip's general partner concluded that the design and operation of the Partnership's disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Partnership 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 management of the Partnership's general partner, including the principal executive officer and principal financial officer of the Partnership's general partner, to allow timely decisions regarding required disclosure.

 

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

 

 

 

PART II. OTHER INFORMATION

 

 

Although the Partnership may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, the Partnership is not currently a party to any material legal proceedings. In addition, the Partnership is not aware of any material legal or governmental proceedings against it, or contemplated to be brought against it, under the various environmental protection statutes to which the Partnership is subject.

 

 

In addition to the other information set forth in this Report, you should carefully consider the risks discussed in the Prospectus, which risks could materially affect the Partnership's business, financial condition or future results. Except as stated below, there has been no material change in the Partnership's risk factors from those described in the Prospectus.

 

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

 

To achieve more predictable cash flow and to reduce the Partnership's exposure to adverse fluctuations in the prices of oil, NGL and gas, the Partnership's strategy is to enter into derivative arrangements covering a significant portion of its oil, NGL and gas production. The Partnership has adopted a policy that contemplates hedging the prices for approximately 65 to 85 percent of expected production for a period of up to five years. In addition, the Credit Facility requires it to enter into hedging arrangements for a significant portion of the Partnership's oil, NGL and gas production attributable to proved developed producing reserves in differing annual percentages over a three-year period. See Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for a description of the Partnership's hedging positions as of September 30, 2008. The use of hedging transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Partnership's derivative contracts are with multiple counterparties to mitigate its exposure to any individual counterparty. If any of these counterparties were to default in their obligations under the Partnership's hedging arrangements, such a default could have a material adverse effect on the Partnership's results of operations, and could result in a larger percentage of the Partnership'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 Partnership's exposure to any one counterparty or a larger percentage of the Partnership's future production could be subject to commodity price changes.

 

A failure by purchasers of the Partnership's production to perform their obligations to the Partnership could require the Partnership to recognize a pre-tax charge in earnings and have a material adverse effect on the Partnership'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 Partnership'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 Partnership. The risk to the Partnership could be exacerbated by the fact that a substantial amount of the Partnership's production is purchased by three companies. For the year ended December 31, 2007, Plains Marketing, L.P., TEPPCO Crude Oil and ONEOK Inc. accounted for approximately 58 percent, 11 percent and 10 percent of the Partnership's sales revenue, respectively. If for any reason the Partnership 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 Partnership's production were uncollectible, the Partnership would recognize a pre-tax charge in the earnings of that period for the probable loss and could suffer a material reduction in its liquidity and ability to make distributions.

 

 

 

The Partnership may not be able to obtain funding, obtain funding on acceptable terms or obtain funding under the Credit Facility because of the deterioration of the credit and capital markets. This may hinder or prevent the Partnership 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 borrower's current debt and reduced and, in some cases, ceased to provide funding to borrowers. In addition, the Partnership may be unable to obtain adequate funding under the Credit Facility if (i) the Partnership's lending counterparties become unwilling or unable to meet their funding obligations or (ii) the amount the Partnership may borrow under the 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 Partnership 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 Partnership 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 Partnership's production, revenues and results of operations.

 

Declining general economic, business or industry conditions may have a material adverse affect on the Partnership'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 slower global economic growth going forward. These factors, combined with volatile oil prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and fears of 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 Partnership's common unit 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 Partnership can sell its oil, NGLs and gas and ultimately decrease the Partnership's net revenue and profitability.

 

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

 

 

 

 

Exhibits

 

 

_____________

(a) Filed herewith.

(b) Furnished herewith.

 

 

 

 

SIGNATURES

 

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

 

 

 

 

 

 

 

Exhibit Index

 

 

 

_____________

(a) Filed herewith.

(b) Furnished herewith.