UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009

 

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

 

 

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 

 

Number of common units outstanding as of August 10, 2009                                                          30,008,700

 

 

 

 

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 derivative 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 drilling and operations, access to and availability of drilling equipment and transportation, processing and refining facilities, the Partnership's ability to replace reserves, including through acquisitions, and implement its business plans or complete its development activities as scheduled, 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 Annual Report on Form 10-K, this Report, other Quarterly Reports on Form 10-Q and other filings with the United States Securities and Exchange Commission. 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 "Item 1. Business — Competition, Markets and Regulations," "Item 1A. Risk Factors" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2008 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:

 

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

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

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

•    All currency amounts are expressed in U.S. dollars.

 

 

 

 

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)

 

 

 

 

 

 

 

 

 

 

NOTE A.         Partnership and Nature of Operations

     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. On May 6, 2008, the Partnership completed an initial public offering of 9,487,500 common units representing limited partner interests, at a per unit offering price of $19.00 (the "Offering"). Prior to 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 (the "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 (the "General Partner") to contribute $24 thousand to the Partnership to maintain the General Partner'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 the Offering, the accompanying consolidated financial statements and related notes represent the results of operations, cash flows and related disclosures of the Partnership Properties (the "Partnership Predecessor") and, for periods after the completion of the Offering, the accompanying consolidated financial statements and related notes represent the financial position, results of operations, cash flows and changes in partners' equity of the Partnership.

     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 June 30, 2009, and for the three and six months ended June 30, 2009 and 2008 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 consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2008.

 

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

     Cash and cash equivalents. Cash and cash equivalents include cash on hand and depository and money market investment 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 Partnership maintained only $1 thousand of cash balances prior to the Offering. Cash received or paid by the Partnership Predecessor is reflected as net distributions to owner in the accompanying consolidated statements of cash flows for periods prior to the Offering.

     Inventories. The Partnership's inventories consist of oil held in storage tanks and natural gas liquids ("NGLs") held in storage by the purchaser of the NGLs. The Partnership's oil and NGL inventories are carried at the lower of average cost or market, on a first-in, first-out basis. Any impairments of inventory are reflected in other expense in the consolidated statements of operations. As of December 31, 2008, the Partnership's inventories were presented net of $159 thousand of valuation reserve allowances. As of June 30, 2009, there were no valuation reserve allowances recorded by the Partnership. 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 and 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. If impairment is indicated based on a comparison of the asset's carrying value to its undiscounted expected future net cash flows, an impairment charge is recognized to the extent that the asset's carrying value exceeds its fair value. Expected future net cash flows are based on oil and gas reserve and production information and pricing assumptions that management believes are reasonable. Any impairment charge incurred is expensed and reduces the Partnership's recorded basis in 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.

     Asset retirement obligation expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows.

 

     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 earnings. 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, a liability, a firm commitment 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, firm commitment or forecasted cash 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 during which it is a party to derivatives that are designated as hedges.

     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 earnings. 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 earnings. 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 by commodity, whichever 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.

     Effective February 1, 2009, the Partnership discontinued hedge accounting on all existing commodity derivative instruments, and since that date it has accounted for derivative instruments using the mark-to-market accounting method. Therefore, for the period from February 1, 2009 through June 30, 2009, the Partnership has recognized, and in the future will recognize, all changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

     See Notes C and 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 existed related to the Partnership Properties. Therefore, the changes in net assets during periods prior to the Offering that were not attributable to the then 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, for the periods presented prior to the Offering, a portion of the general and administrative expenses and lease operating expenses

 

allocated to the Partnership Predecessor was noncash stock-based compensation recorded on the books of Pioneer. Subsequent to the Offering, the Partnership pays its allocated share of general and administrative expenses pursuant to an Administrative Services Agreement and pays an industry standard fee (commonly referred to as the Council of Petroleum Accountants Societies (or "COPAS") fee) with respect to lease expenses. See Note I for additional information about the Partnership's allocated general and administrative expenses and lease expenses.

     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 during 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. See Note D for additional information regarding the Partnership’s current and deferred tax provisions and obligations.

     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 accompanying consolidated balance sheets. The Partnership had no material oil, NGL or gas entitlement assets or liabilities as of June 30, 2009 or December 31, 2008.

     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 June 30, 2009 and December 31, 2008, 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 costs. The accompanying consolidated financial statements for periods prior to the Offering 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.

     Net income (loss) per common unit. The Partnership calculates net income (loss) per common unit in accordance with SFAS No. 128, "Earnings Per Share" ("SFAS 128"). For the three and six months ended June 30, 2009, net income (loss) per common unit is calculated by dividing the limited partners' interest in net income (loss) 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 for the three and six month periods ended June 30, 2008 is attributable to net income applicable to the Partnership during the period from the Offering, on May 6, 2008, through June 30, 2008.

     Allocation of net income (loss). The Partnership's net income (loss) is allocated to partners' equity accounts in accordance with the provisions of the First Amended and Restated Agreement of Limited Partnership of Pioneer Southwest Energy Partners L.P. (the "Partnership Agreement").

     For purposes of calculating net income (loss) per common unit, the Partnership allocates net income (loss) 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"). Under the two-class method, the Partnership’s net income (loss) is allocated among the general partner’s interest in net income (loss) and the limited partners’ interest in net income (loss). Net income (loss) per common unit is based upon the limited partners’ interest in net income (loss) and weighted average common units outstanding during the periods of calculation.

     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 delayed the effective date of SFAS 157 for nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008, except for items that were 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. On January 1, 2009, the Partnership adopted the provisions of SFAS 157 that were delayed by FSP FAS 157-2.

     In December 2007, the FASB issued SFAS No. 141(R), "Business Combinations" ("SFAS 141(R)"). SFAS 141(R) replaced 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's units or 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. The Partnership became subject to the provisions of SFAS 141(R) on January 1, 2009.

     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 changed 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 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance and cash flows. The Partnership adopted the provisions of SFAS 161 on January 1, 2009. See Note H for derivative disclosures provided in accordance with SFAS 133 and SFAS 161.

     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 became effective for the Partnership on November 15, 2008. The adoption of SFAS 162 did not 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 (loss) allocation in computing basic net income (loss) per unit under the two-class method prescribed under SFAS 128. The Partnership adopted the provisions of FSP EITF 03-6-1 on January 1, 2009. All share-based payments of the Partnership’s common units represent grants of outstanding common units by the General Partner. Consequently, the Partnership had no participating share-based payments under the provisions of FSP EITF 03-6-1 during the three and six months ended June 30, 2009 and 2008.

     In December 2008, the SEC released Final Rule, "Modernization of Oil and Gas Reporting" (the "Reserve Ruling"). The Reserve Ruling revises oil and gas reporting disclosures. The Reserve Ruling also permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The Reserve Ruling will also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor, (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit and (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price. The Reserve Ruling becomes effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. During February 2009, the FASB announced a project to amend SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" ("SFAS 19") to conform to the Reserve Ruling. The Partnership is currently assessing the impact that adoption of the provisions of the Reserve Ruling will have on its financial position, results of operations and disclosures.

     In April 2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1, "Interim Disclosures about Fair Value of Financial Instruments" ("FSP FAS 107-1"), which amends FASB Statement No. 107, "Disclosures about Fair Value of Financial Instruments" and Accounting Principles Board Opinion No. 28, "Interim Financial Reporting". FSP FAS 107-1 requires fair value disclosures by publicly traded companies of financial instruments for interim reporting purposes. The Partnership adopted FSP FAS 107-1 in the second quarter of 2009. See Note C for disclosures about the fair values of the Partnership's financial instruments.

     In April 2009, the FASB issued FASB Staff Position No. FAS 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly" ("FSP FAS 157-4"), which provides additional guidelines for estimating fair value in accordance with SFAS 157 when the volume and level of activity for the asset or liability have decreased and guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 was adopted by the Partnership during the second quarter of 2009 and did not have a material impact on the Partnership's fair value measurements.

     In May 2009, the FASB issued SFAS No. 165, "Subsequent Events" ("SFAS 165"). SFAS 165 provides additional guidelines for disclosing subsequent events in an issuer's financial statements and further requires an

 

issuer to disclose a finite time period for which the company has evaluated subsequent events. SFAS 165 was adopted by the Partnership during the second quarter of 2009 and did not have a significant impact on the Partnership's recognition or disclosure of subsequent events.

     In June 2009, the FASB issued SFAS No. 168, "The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles" ("SFAS 168"). SFAS 168 replaces SFAS 162 and identifies the sources of accounting guidance and the framework for selecting the principles to be used in the preparation of financial statements presented in conformity with GAAP. On the effective date of SFAS 168, the codification prescribed in SFAS 168 will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered, non-SEC accounting literature not included in SFAS 168 will become non-authoritative. SFAS 168 is effective for interim and annual reporting periods ending after September 15, 2009 and is not expected to have a significant impact on the Partnership's financial statements.

     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 as of June 30, 2009, for each of the fair value input hierarchy levels:

 

 

     The Partnership's commodity derivative assets that are classified as Level 3 in the fair value hierarchy at June 30, 2009 represent NGL derivative contracts. The following table presents the changes in the fair values of the Partnership's commodity derivative assets classified as Level 3 in the fair value hierarchy:

___________
(a)      For periods prior to February 1, 2009, the hedge-effective portion of realized gains and losses on commodity hedge derivatives are included in oil, NGL and gas revenues in the accompanying consolidated statements of operations. For periods beginning February 1, 2009, changes in fair value are included in derivative loss, net in the accompanying consolidated statements of operations.

     Commodity derivative instruments. The Partnership's commodity derivative assets and liabilities represent oil, NGL and gas swap and collar contracts. All of the Partnership's oil and gas derivative asset and liability measurements represent Level 2 inputs in the hierarchy priority. The Partnership's NGL derivative asset 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 derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rates, and commodity 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 June 30, 2009. The Partnership's credit-adjusted risk-free rate curve is based on independent market-quoted forward LIBOR curves plus 250 basis points, representing the Partnership's estimated borrowing rate if it were to finance future settlements. The asset transfer values attributable to the Partnership's oil derivative instruments as of June 30, 2009 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 independent third-party volatility quotes that were corroborated against other independent third-party volatility quotes. 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 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 derivative contracts. 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 swap 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 derivative contracts 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.

     The carrying value of the Partnership's cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities approximate fair value due to the short maturity of these instruments.

     The Partnership's income tax provisions, which amounts were entirely attributable to the Texas Margin tax (which currently approximates one percent of the Partnership's taxable income apportioned to Texas), consisted of the following for the three and six months ended June 30, 2009 and 2008:

     The Partnership's deferred tax attributes represented noncurrent assets of $688 thousand and $235 thousand as of June 30, 2009 and December 31, 2008, respectively and current liabilities of $370 thousand and $521 thousand as of June 30, 2009 and December 31, 2008, respectively.

     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 June 30, 2009, 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 six months ended June 30, 2009 and 2008:

___________
(a)    The change in the asset retirement obligations balance from the prior period is primarily due to lower year-end prices for oil, NGLs and gas being used to calculate proved reserves at December 31, 2008, which had the effect of shortening the economic life of many wells, thus increasing the present value of future retirement obligations.

     In May 2008, the Partnership entered into the $300 million revolving credit facility (the "Credit Facility").  As of June 30, 2009, there were no outstanding borrowings under the Credit Facility.

     The Credit Facility contains certain financial convenants, including (i) the maintenance of a quarter end consolidated leverage ratio (representing a ratio of consolidated indebtedness of the Partnership to consolidated 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 derivative related activity; and noncash equity-based compensation, ("EBITDAX") of not more than 3.5 to 1.0, (ii) an interest coverage ratio (representing a ratio of EBITDAX to interest expense) of not less than 2.5 to 1.0 and (iii) the maintenance of a ratio of the net present value of 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 convenant, borrowing capacity under the Credit Facility was limited to approximately $190 million as of June 30, 2009.  The Partnership was in compliance with all of its debt covenants as of June 30, 2009.

     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 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.

     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 accounted for as derivative financial instruments 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 from May 6, 2008 through January 31, 2009 (the date upon which the derivative instruments were de-designated as hedges), to the extent that they were effective as hedges of the designated commodity price risk, were deferred and are being recognized in the Partnership's earnings in the same periods as the forecasted sales that they hedged. During the three and six months ended June 30, 2009, the Partnership's net gains attributable to the novated derivative instruments included noncash revenue of $3.9 million and $7.8 million, respectively.

     The following table provides the noncash portions of revenue to be recognized in future periods associated with the novated derivatives:

     All derivatives are recorded in the Partnership’s consolidated balance sheets at their estimated fair values. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date. Changes in the fair value of effective cash flow hedges were 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 the fair value of the derivative and the estimated change in cash flows from the item hedged. Cash inflows and outflows attributable to the Partnership’s commodity derivatives are included in net cash provided by operating activities in the Partnership’s accompanying consolidated statement of cash flows for the three and six months ended June 30, 2009 and 2008.

    

      Cash flow hedges and derivative price risk management. The Partnership primarily utilizes commodity swap and collar contracts to (i) reduce the impact on the Partnership's net cash provided by operating activities from the price volatility of the commodities the Partnership produces and sells and (ii) help sustain unitholder distributions. Pioneer did not designate derivative hedges to forecasted sales at the well level. Consequently, the Partnership’s consolidated financial statements for periods prior to the Offering do not include the recognition of hedge gains or losses or derivative assets or liabilities.

         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 in Bbls under outstanding oil derivative contracts and the weighted average NYMEX prices per Bbl for those contracts as of June 30, 2009:

     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 six months ended June 30, 2009 and 2008:

 

  

     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 in Bbls under outstanding NGL derivative contracts and the weighted average Mont Belvieu-posted-prices per Bbl for those contracts as of June 30, 2009:

         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 six months ended June 30, 2009 and 2008:

     Gas prices. The Partnership employs a policy of managing price risk for 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 in MMBtus under outstanding gas derivative contracts and the weighted average index prices per MMBtu for those contracts as of June 30, 2009:

 

    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 six month periods ended June 30, 2009 and 2008:

        Tabular disclosures about derivative instruments. Effective February 1, 2009, the Partnership discontinued hedge accounting on all existing commodity derivative instruments, and since that date has accounted for derivative instruments using the mark-to-market accounting method. Consequently, all of the Partnership’s commodity derivatives were non-hedge derivatives as of June 30, 2009 and hedge derivatives as of December 31, 2008. The following tables provide tabular disclosures of the Partnership's commodity derivative instruments:

 

 

     AOCI - Hedging. The fair value of the effective portion of the derivative contracts on January 31, 2009 is reflected in AOCI-Hedging and is being transferred to oil and gas revenue over the remaining term of the derivative contract. In accordance with the mark-to-market method of accounting, the Partnership will recognize all future changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

     As of June 30, 2009 and December 31, 2008, AOCI - Hedging represented net deferred gains of $118.6 million and $143.0, respectively, and associated deferred tax provisions of $847 thousand and $1.4 million as of June 30, 2009 and December 31, 2008, respectively.

     During the twelve months ending June 30, 2010, the Partnership expects to reclassify approximately $58.6 million of net deferred hedge gains and approximately $586 thousand of deferred Texas Margin tax provisions associated with derivative contracts from AOCI - Hedging to commodity revenues and income tax provisions, respectively.

     Discontinued commodity hedges. At the time of hedge discontinuation, the amounts recorded in AOCI – Hedging were maintained and are being transferred to earnings in the periods during which the hedged transactions are recorded.

 

    The following table sets forth, as of June 30, 2009, the scheduled transfers of the net deferred gains on discontinued commodity hedges that will be recognized as increases to the Partnership's future oil and gas revenues (see the table on page 20, which provides the noncash portions of the deferred gains  scheduled below):

NOTE I.               Related Party Transactions

     Related party charges. In accordance with standard industry operating agreements and the various agreements entered into between the Partnership and Pioneer in connection with the Offering, the Partnership incurred the following charges from Pioneer during the three and six months ended June 30, 2009 and 2008:

     As of June 30, 2009 and December 31, 2008, the Partnership's accounts payable – due to affiliates balances in the accompanying consolidated balance sheets amounted to $365 thousand and $6.0 million, respectively. The balance as of June 30, 2009 is comprised primarily of general and administrative expenses. The balance as of December 31, 2008 is comprised primarily of lease operating expenses, including COPAS fees, and general and administrative expenses.

     As of June 30, 2009 and December 31, 2008, the Partnership has $710 thousand and $492 thousand, respectively, of income taxes payable to affiliate recorded in the accompanying consolidated balances sheets, representing amounts due to Pioneer under the tax sharing agreement between Pioneer and the Partnership.

     The General Partner awarded 12,909 and 12,630 restricted common units to directors during the six months ended June 30, 2009 and 2008, respectively, under the Pioneer Southwest Energy Partners L.P. 2008 Long-Term Incentive Plan. Associated therewith, the Partnership recognized $51 thousand and $91 thousand of general and administrative expense during the three and six months ended June 30, 2009, respectively, and $27 thousand during the same respective periods of 2008.

Financial and Operating Performance

     The Partnership's financial and operating performance for the second quarter of 2009 included the following highlights:

Recent Events

     Financial markets. During the second half of 2008, worldwide financial markets experienced significant turmoil as a result of a worldwide economic slowdown and a significant decline in the availability of liquidity provided by the financial markets. While these conditions continued through the first half of 2009, the availability of liquidity in the financial markets saw some improvement during the second quarter of 2009. In response to the economic slowdown, 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 predicted. The Partnership is closely monitoring the economic environment, including changes in energy demand and fluctuations in commodity prices, the impact of which is mitigated by the Partnership's derivative price risk activities. Depending on the severity and duration of the worldwide economic decline, these market conditions could negatively impact the Partnership's liquidity, financial position and future results of operations.   See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" and Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Partnership's derivative contracts.

     As of June 30, 2009, the Partnership had $34.3 million of cash and cash equivalents on deposit, held approximately $10.1 million of accounts receivable related to oil, NGL and gas sales, was a party to derivative financial instruments, of which $68.7 million represent assets of the Partnership, had no outstanding long-term debt and had approximately $190 million of available borrowing capacity under the Credit Facility. The amount of liquidity under the Credit Facility is subject to a covenant requiring that the Partnership maintain a specified ratio of the net present value of the Partnership's projected future cash flows from its oil and gas assets to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. Therefore, the amount that the Partnership may borrow under the Credit Facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items. The Partnership is monitoring the liquidity and the credit standings of its counterparties, including its banks, derivative counterparties and purchasers of the commodities the Partnership produces and sells.

     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, which has further resulted in significant reductions in worldwide energy demand. At the same time, North American gas supply has increased as a result of the rise in domestic unconventional gas production. The combination of lower demand due to

 

the economic slowdown and higher North American gas supply resulted in significant declines in oil, NGL and gas prices during the second half of 2008 and the first quarter of 2009. During the second quarter of 2009, commodity prices increased modestly, but remained volatile. Although the Partnership has entered into derivative contracts on a large portion of its production volumes through 2011, a sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Partnership could enter into derivative contracts on additional volumes in the future. As a result, the Partnership's internal cash flows would be reduced for affected periods. The timing and magnitude of commodity price declines or recoveries cannot be predicted. A sustained decline in commodity prices could result in a shortfall in expected cash flows and require the Partnership to reduce its distributions. Additionally, a sustained decline in commodity prices could reduce the Partnership's borrowing capacity under its Credit Facility.

     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.

2009 Outlook

     Commodity prices. The oil, NGL and gas markets are highly volatile, and the Partnership cannot predict future oil, NGL and gas prices. Prices for oil, NGL and gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, NGL and gas, market uncertainty and a variety of additional factors that are beyond the Partnership's control, such as worldwide economic conditions, developments in the issues currently impacting Iraq and Iran and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries ("OPEC") and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of weather conditions and increasing LNG deliveries to the United States. Although the Partnership cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that the Partnership produces will generally approximate current market prices in the geographic region of the production. From time to time, the Partnership expects that it may use derivative contracts to reduce a portion of its commodity price risk in order to mitigate the impact of price volatility on its oil, NGL and gas revenues. See Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Partnership's commodity derivative positions at June 30, 2009. Also see "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for disclosures about the Partnership's commodity related derivative financial instruments.

     Third quarter 2009 outlook. Based on current estimates, the Partnership expects that production will average 4,500 to 4,800 BOEPD.

     Production costs (including production and ad valorem taxes) are expected to average $19.00 to $22.00 per BOE based on current NYMEX strip prices for oil, NGLs and gas. Depletion, depreciation and amortization ("DD&A") expense is expected to average $4.50 to $5.50 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 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.

      Derivative designations. Effective February 1, 2009, the Partnership discontinued hedge accounting on all existing commodity derivative instruments, and since that date has accounted for derivative instruments using the mark-to-market accounting method. Therefore, for the period from February 1, 2009 through June 30, 2009,  

  the Partnership has recognized, and in the future will recognize, all changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

     Acquisition and drilling opportunities. The Partnership is evaluating a $100 million to $200 million potential acquisition of certain developed and undeveloped oil and gas properties from Pioneer. Any such acquisition would be subject to negotiation of definitive agreements and the approval of the board of directors of the General Partner and the Conflicts Committee of the board. There can be no assurance that an acquisition will be completed or as to its terms. Additionally, the Partnership continues to evaluate the potential benefits of initiating a development drilling program in the Spraberry field as costs decrease and margins improve. The Partnership also continues to evaluate third-party acquisition opportunities.

Results of Operations

     Oil and gas revenues. Oil and gas revenues totaled $35.0 million and $67.5 million for the three and six months ended June 30, 2009, respectively, as compared to $41.0 million and $77.2 million for the same respective periods of 2008.

     The decreases in oil and gas revenues during the three and six months ended June 30, 2009, as compared to the same periods of 2008, were primarily due to decreases in commodity prices and to decreases of nine percent and four percent, respectively, in average daily sales volumes. In the quarter-to-quarter and year-to-date comparisons, the average reported oil price decreased by five percent and six percent, respectively; the average reported NGL price decreased by six percent and 14 percent, respectively; and the average reported gas price decreased by 26 percent and 15 percent, respectively. The decreases in sales volume were due to declines in workover operations in support of cost reduction initiatives and normal production declines. In the year-to-date comparison, the decrease in sales volume was partially offset by the sale of approximately 169 BOEPD in the first six months of 2009 of stored NGL volumes that were previously deferred as a result of damage caused to Gulf Coast fractionation facilities by Hurricane Ike in September 2008.

     The following table provides average daily sales volumes for the three and six months ended June 30, 2009 and 2008:

 

     The following table provides the Partnership's average reported prices, including the results of derivative activities, and average realized prices, excluding the results of derivative activities, for the three and six months ended June 30, 2009 and 2008:

      Derivative 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 from the price volatility of the commodities the Partnership produces and sells. 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 recognized oil and gas production costs of $6.4 million and $13.7 million, respectively, during the three months and six months ended June 30, 2009, as compared to $7.9 million and $14.6 million for the same respective periods of 2008. During the three and six months ended June 30, 2009, total oil and gas production costs per BOE decreased by 11 percent and two percent, as compared to the three and six months ended June 30, 2008, respectively.

     The Partnership's production costs for the three and six months ended June 30, 2009 decreased as compared to the same respective periods of 2008 primarily due to cost reduction initiatives implemented by Pioneer to mitigate commodity price declines that have occurred since the first half of 2008, including reduced workovers and overall reductions in oilfield services costs. Workover costs decreased for the three and six months ended June 30, 2009, as compared to the same respective periods of 2008, primarily as a result of lower commodity prices reducing the return on investment associated with certain workovers such that they were not economical to perform.

     For periods prior to the Offering, the Partnership's lease operating expense included an allocation of Pioneer's direct internal costs associated with the operation of the Partnership Properties. 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, lease operating expense would have been higher on a BOE basis by $1.03 and $1.94, respectively, for the three and six months ended June 30, 2008.

      The following table provides the components of the Partnership's oil and gas production costs per BOE for the three and six months ended June 30, 2009 and 2008:

     Production and ad valorem taxes. The Partnership recorded production and ad valorem taxes of $1.9 million and $3.8 million, respectively, for the three and six months ended June 30, 2009, as compared to $3.1 million and $5.8 million, respectively, for the same respective periods of 2008. The decreases were primarily attributable to lower production taxes associated with lower commodity prices. These decreases were partially offset by increases in ad valorem tax accruals during the three and six months ended June 30, 2009, as compared to the same respective periods of 2008. Since ad valorem taxes in Texas are determined, in part, based on commodity prices for the previous year, the Partnership's accrual for the three and six months ended June 30, 2009 for ad valorem taxes increased due to higher commodity prices in 2008 as compared to 2007.

        The following table provides the Partnership's production and ad valorem taxes per BOE and total production and ad valorem taxes per BOE for the three and six months ended June 30, 2009 and 2008:

     Depletion, depreciation and amortization expense. The Partnership's DD&A expense was $2.0 million ($4.78 per BOE) and $4.7 million ($5.31 per BOE) for the three and six months ended June 30, 2009, respectively, as compared to $1.6 million ($3.60 per BOE) and $3.4 million ($3.66 per BOE) for the same respective periods of 2008. The increases in DD&A expense were primarily due to negative price revisions to proved reserves as a result of lower commodity prices in the first half of 2009 as compared to the same period in 2008.

     General and administrative expense. General and administrative expense was $780 thousand and $2.0 million for the three and six months ended June 30, 2009, respectively, as compared to $1.5 million and $2.7 million for the same respective periods of 2008. The decreases in general and administrative expense are due primarily to a reduction in the per BOE rate used to allocate a portion of Pioneer's general and administrative expense to the Partnership. 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 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.

     Derivative loss, net. Effective February 1, 2009, the Partnership discontinued hedge accounting on all existing commodity derivative instruments, and since that date has accounted for derivative instruments using the mark-to-market accounting method. Increases in commodity prices since February 1, 2009 have reduced the fair value of the Partnership's derivative contracts and resulted in net mark-to-market derivative losses of $25.5 million and $32.5 million, respectively, for the three and six months ended June 30, 2009. For the three and six months ended June 30, 2008, the Partnership accounted for its derivative contracts as cash flow hedges and effective changes in the fair values were recognized in AOCI - Hedging. See Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the types of derivative transactions in which the Partnership participates.

     Income tax provision. The Partnership recognized income tax provisions of $5 thousand and $89 thousand for the three and six months ended June 30, 2009, respectively, as compared to $279 thousand and $528 thousand for the same respective periods of 2008. The Partnership's effective tax rate is generally approximately one percent of taxable income apportioned to Texas, reflective of the Texas Margin tax. The Partnership's tax provision for the second quarter of 2009 is primarily due to (i) the Texas Margin tax only allowing a portion of the Partnership's general and administrative expenses as a deduction from taxable margin and (ii) an increase in the projected percentage of income apportioned to Texas. See Note D 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 its 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 for the foreseeable future (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 its Credit Facility. Although the Partnership expects that internal cash flows will be adequate to fund capital expenditures and planned unitholder distributions, and that available borrowing capacity under its Credit Facility will provide adequate liquidity to fund future acquisitions or capital expenditures, 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 that provide cash margins that allow the Partnership to sustain its level of distributions to unitholders over time, or otherwise mitigate the declines through production enhancement or drilling initiatives. Currently, the Partnership is reserving approximately 25 percent of its cash flow to acquire income producing assets or drill downspaced locations in order to maintain its production and cash flow. 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 second quarter of 2009 of $0.50 per unit was declared by the Board of Directors of the General Partner and is to be paid on August 12, 2009 to unitholders of record on August 4, 2009.

     Oil and gas properties. The Partnership's cash expenditures for additions to oil and gas properties during the three and six month ended June 30, 2009, totaled $86 thousand and $264 thousand, respectively, as compared to $174 thousand and $257 thousand for the same respective periods of 2008. The Partnership's expenditures for additions to oil and gas properties for the three and six months ended June 30, 2009 and 2008 were funded by net cash provided by operating activities.

 

     Contractual obligations, including off-balance sheet obligations. As of June 30, 2009, 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, 2008. The fair value of the Partnership's derivative instruments represented net assets of approximately $68.3 million as of June 30, 2009; however, they continue to have market risk and represent contractual obligations of the Partnership. 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 reducing 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 forecasted commodity 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 regarding the Partnership's derivative positions. As of June 30, 2009, the Partnership was not a party to any material off-balance sheet arrangements.

     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.

     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. For 2009, the Partnership currently expects that cash on hand and cash flow from operations will be sufficient to fund the Partnership's capital expenditures and planned unitholder distributions, and that available borrowing capacity under its Credit Facility will provide adequate liquidity to fund future acquisitions.

     Operating activities. Net cash provided by operating activities during the three and six months ended June 30, 2009 was $20.4 million and $34.6 million, respectively, as compared to $32.7 million and $58.2 million for the same respective period of 2008. The decreases in net cash provided by operating activities during the three and six months ended June 30, 2009, as compared to the three and six months ended June 30, 2008, were primarily due to working capital changes and decreases in oil, NGL and gas revenues.

     As described in "Recent Events – Commodity prices," the commodity price declines that have occurred since mid-2008, although mitigated by the Partnership's derivative activities, have reduced the Partnership's internal cash flows. The timing and magnitude of commodity price declines and recoveries cannot be predicted, but a sustained decline in commodity prices could negatively impact the Partnership's ability to replace declining production and result in a decrease to unitholder distributions in the future.

     Investing activities. Net cash used in investing activities during the three and six months ended June 30, 2009 was $86 thousand and $264 thousand, respectively, as compared to $140.7 million and $140.8 million for the same respective periods of 2008. The decreases in net cash used in investing activities during the three and six months ended 2009, as compared to the three and six moths ended 2008, were due primarily to the acquisition of properties in connection with the Offering. Future investing activities may include expenditures to acquire income producing assets, drill wells on acquired acreage or to drill a limited number of 20-acre locations surrounding the Partnership's wells if margins improve.

     Financing activities. Net cash used in financing activities during the three and six months ended June 30, 2009 was $15.0 million and $30.0 million, respectively, as compared to net cash provided by financing activities of

$120.4 million and $95.1 million for the same respective periods of June 30, 2008. The decreases in net cash provided by financing activities during the three and six months ended June 30, 2009, as compared to the three and six months ended June 30, 2008, were primarily due to the 2008 proceeds received from the Offering.

     Liquidity. The Partnership's principal source of short-term liquidity is cash generated from operations and availability under its Credit Facility. As of June 30, 2009, the Partnership had no outstanding borrowings under its Credit Facility, but due to the net present value covenant in the Credit Facility agreement, it only had access to approximately $190 million of available borrowing capacity. The Partnership's borrowing capacity under the Credit Facility is subject to a covenant requiring that the Partnership maintain a specified ratio of the net present value of the Partnership's projected future cash flows from its oil and gas assets to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. As a result, further declines in commodity prices could reduce the Partnership's borrowing capacity under the Credit Facility and could require the Partnership to reduce its distributions to unitholders.

     The Partnership expects that its primary sources of liquidity will be cash generated from operations, amounts available under its 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. A sustained decline in commodity prices could result in a shortfall in expected cash flows. 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.

     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 use derivative contracts to protect the cash flow associated with a significant portion of its production. The Partnership is generally required to settle its commodity 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 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 its 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 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 FSP FAS 157-2. FSP FAS 157-2 delayed the effective date of SFAS 157 for nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008, except for items that were 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. On January 1, 2009, the Partnership adopted the provisions of SFAS 157 that were delayed by FSP FAS 157-2.

     In December 2007, the FASB issued SFAS 141(R). SFAS 141(R) replaced 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 unit or 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. The Partnership became subject to the provisions of SFAS 141(R) on January 1, 2009.

     In March 2008, the FASB issued SFAS 161. SFAS 161 changed 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 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance and cash flows. The Partnership adopted the provisions of SFAS 161 on January 1, 2009. See Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for derivative disclosures provided in accordance with SFAS 133 and SFAS 161.

     In May 2008, the FASB issued 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 became effective for the Partnership on November 15, 2008. The adoption of SFAS 162 did not have a significant impact on the Partnership's financial statements.

     In June 2008, the FASB issued 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 (loss) allocation in computing basic net income (loss) per unit under the two-class method prescribed under SFAS 128. The Partnership adopted the provisions of FSP EITF 03-6-1 on January 1, 2009. All share-based payments of the Partnership’s common units represent grants of outstanding common units by the General Partner. Consequently, the Partnership had no participating share-based payments under the provisions of FSP EITF 03-6-1 during the three and six months ended June 30, 2009 and 2008.

     In December 2008, the SEC released the Reserve Ruling. The Reserve Ruling revises oil and gas reporting disclosures. The Reserve Ruling also permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The Reserve Ruling will also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor, (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit and (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price. The Reserve Ruling becomes effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. During February 2009, the FASB announced a project to amend SFAS 19 to conform to the Reserve Ruling. The Partnership is currently assessing the impact that adoption of the provisions of the Reserve Ruling will have on its financial position, results of operations and disclosures.

     In April 2009, the FASB issued FSP FAS 107-1, which amends FASB Statement No. 107, "Disclosures about Fair Value of Financial Instruments" and Accounting Principles Board Opinion No. 28, "Interim Financial Reporting". FSP FAS 107-1 requires fair value disclosures by publicly traded companies of financial instruments for interim reporting purposes. The Partnership adopted FSP FAS 107-1 in the second quarter of 2009. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for disclosures about the fair values of the Partnership's financial instruments.

     In April 2009, the FASB issued FSP FAS 157-4, which provides additional guidelines for estimating fair value in accordance with SFAS 157 when the volume and level of activity for the asset or liability have decreased and guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 was adopted by the Partnership during the second quarter of 2009 and did not have a material impact on the Partnership's fair value measurements.

 

     The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2008. As such, the information contained herein should be read in conjunction with the related disclosures in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2008.

     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 expects that it will continue to be a party to various derivative instruments to manage its exposure to the volatility of commodity market prices. The Partnership has adopted a policy that contemplates using derivative contracts to protect 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 the Partnership to enter into derivative price risk 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. During the first quarter of 2009, the Partnership obtained a waiver from the lenders under its Credit Agreement so that it would not be required to enter into any additional derivative agreements for the Partnership's projected oil, NGL and gas production attributable to proved developed producing reserves for the period from January 1, 2011 through December 31, 2011. The Partnership is, however, required to maintain its existing derivative positions related to that period.

     The Partnership generally uses swap and collar derivative contracts to mitigate the impact of declines 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 June 30, 2009, the Partnership has entered into derivative price risk arrangements for approximately 75 percent, 70 percent and 45 percent of the Partnership's expected production in 2009, 2010 and 2011, respectively. Although mitigated by the Partnership's derivative price risk arrangements, the decline in commodity prices from their highs in 2008 will reduce the Partnership's revenues and distributable cash. Recent uncertainties in worldwide financial markets may have the effect of reducing liquidity in the financial derivatives market, which may hamper the Partnership's ability to enter into future derivative price risk arrangements under acceptable 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 meet capital requirements for growth while minimizing the Partnership's costs of capital.

 

     The following table reconciles the changes that occurred in the fair values of the Partnership's open derivative contracts during the six months ending June 30, 2009 (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 June 30, 2009:

_____________

 

     Evaluation of disclosure controls and procedures. The Partnership's management, 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 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 the Partnership's management, including the principal executive officer and principal financial officer of the 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 Partnership's Annual Report on Form 10-K for the year ended December 31, 2008 under the headings "Item 1. Business – Competition, Markets and Regulations," "Item 1A. Risk Factors" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk," which risks could materially affect the 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 Annual Report on Form 10-K.

The Partnership’s ability to use derivative transactions to protect it from future oil, NGL and gas price declines will be dependent upon oil, NGL and gas prices at the time the Partnership enters into future derivative transactions and its future levels of derivative activity, and as a result the Partnership’s future net cash flow may be more sensitive to commodity price changes.

     As the Partnership’s derivative contracts expire, more of its future production will be sold at market prices unless the Partnership enters into further derivative transactions. The Partnership’s credit facility requires it to enter into derivative arrangements for not less than 65 percent (nor more than 85 percent) of its projected oil, NGL and gas production attributable to proved developed producing reserves through December 31, 2010. Furthermore, by April 1, 2010, the credit facility requires that the Partnership enter into derivative transactions 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, 2012. The Partnership’s commodity price derivative strategy and future derivative transactions will be determined by the General Partner, which is not under any obligation to enter into derivative contracts on a specific portion of the Partnership’s production, other than to comply with the terms of the Partnership’s credit facility for so long as it may remain in place. The prices at which the Partnership enters into derivative contracts on its production in the future will be dependent upon commodity prices at the time the Partnership enters into these transactions, which may be substantially lower than current oil, NGL and gas prices and substantially lower than the prices provided under the expiring contracts. Additionally, the Partnership could be required by the terms of its credit facility to enter into derivative contracts at times and prices that are not considered strategically advantageous. Accordingly, the Partnership’s derivative contracts may not protect it from significant and sustained declines in oil, NGL and gas prices received for its future production. Conversely, the Partnership’s commodity price derivative strategy could limit its ability to realize cash flow from commodity price increases. It is also possible that a larger percentage of the Partnership’s future production will not be covered by derivative contracts as compared to the next few years, which would result in its oil and gas revenues becoming more sensitive to commodity price changes.

The adoption of derivatives legislation by Congress could have an adverse impact on the Partnership’s ability to use derivative instruments to reduce the effect of commodity price risk associated with its business.

     Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives. The legislation would expand the power of the Commodity Futures Trading Commission, ("CFTC"), to regulate derivative transactions related to energy commodities, including oil, NGLs and gas, until the adoption of general legislation covering derivative regulatory reform. The CFTC recently conducted hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as oil, NGLs, gas and other energy products. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all over the counter ("OTC") derivative dealers and all other major OTC derivative

 

market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Although it is not possible at this time to predict whether or when the CFTC may adopt rules or Congress may act on derivatives legislation, any laws or regulations that may be adopted could have an adverse effect on the Partnership’s ability to utilize derivative instruments to reduce the effect of commodity price risk associated with its business.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

     President Obama’s Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect the taxable income allocable to the unitholders.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil, NGLs and gas the Partnership produces.

     On June 26, 2009, the U.S. House of Representatives approved adoption of the "American Clean Energy and Security Act of 2009," ("ACESA") or also known as the "Waxman-Markey cap-and-trade legislation". The purpose of ACESA is to control and reduce emissions of "greenhouse gases," such as carbon dioxide and methane, in the United States. ACESA would establish an economy-wide cap on emissions of greenhouse gases, or "GHGs," in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission "allowances" corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and gas. The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law.

     It is not possible at this time to predict whether climate change legislation will be enacted, but any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require the Partnership to incur increased operating costs and could have an adverse effect on demand for the oil, NGLs and gas it produces.

     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.

 

_____________
(a) Filed herewith.
(b) Furnished herewith.

 

 

 

42

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

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.