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

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 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 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, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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

Yes o No x

 

Number of common units outstanding as of May 11, 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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 ("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. The accompanying consolidated statements of operations and cash flows and related notes thereto for the three months ended March 31, 2008 preceded the completion of the Offering. Consequently, those 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 proceeds from the exercise of the underwriters' over-allotment option in connection with the Offering were used by the Partnership to purchase incremental working interests in certain Partnership Properties, thereby effecting a change in the reporting entity as defined by generally accepted accounting principles in the United States ("GAAP"). The change in reporting entity has been retrospectively applied to the accompanying statements of operations and cash flows and related disclosures for the three months ended March 31, 2008. As a result of the change, net income increased to $23.6 million for the three months ended March 31, 2008, as compared to $22.3 million previously reported for the same period.

 

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 for the three months ended March 31, 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 March 31, 2009, and for the three months ended March 31, 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 a net distribution to owner in the accompanying consolidated statement of cash flows for the three months ended March 31, 2008.

 

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. As of March 31, 2009, title and risk of loss of the NGL inventory had transferred to the purchaser. However, the sales price of the NGLs will not be determined until the NGLs undergo further processing by the purchaser during the second quarter of 2009. In accordance with SAB Topic 13 "Revenue Recognition – Revised as of December 2003," the Partnership has deferred revenue recognition of the NGLs held in storage by the purchaser as of March 31, 2009. 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 March 31, 2009 and December 31, 2008, the Partnership's inventories were net of $5 thousand and $159 thousand, respectively, of valuation reserve allowances. See "Revenue recognition" for information regarding the Partnership's accounting policy for revenue recognition.

 

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

 

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

 

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

 

In accordance with Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the Partnership reviews its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If an impairment is

 

indicated based on a comparison of the asset's carrying value to its undiscounted expected future net cash flows, then 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 proved 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 net income. Under the provisions of SFAS 133, the Partnership may designate a derivative instrument as hedging the exposure to changes in the fair value of an asset or a liability or an identified portion thereof that is attributable to a particular risk (a "fair value hedge") or as hedging the exposure to variability in expected future cash flows that are attributable to a particular risk (a "cash flow hedge"). Both at the inception of a hedge and on an ongoing basis, a fair value hedge must be expected to be highly effective in achieving offsetting changes in fair value attributable to the hedged risk during the periods that a hedge is designated. Similarly, a cash flow hedge must be expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. The expectation of hedge effectiveness must be supported by matching the essential terms of the hedged asset, liability or forecasted transaction to the derivative hedge contract or by effectiveness assessments using statistical measurements. The Partnership's policy is to assess hedge effectiveness at the end of each calendar quarter.

 

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

 

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

 

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

 

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 March 31, 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 G 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 three months ended March 31, 2008.

 

Employee benefit plans. The Partnership does not have its own employees. However, for the three months ended March 31, 2008, 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, as described in Note H below, and pays an industry standard fee (commonly referred to as the Council of Petroleum Accountants Societies (or "COPAS") fee) with respect to 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 on May 18, 2006 for tax years beginning on January 1, 2007, which caused the Texas franchise tax to be applicable to numerous types of entities that previously were not subject to the tax, including the Partnership. Accordingly, the Partnership reflects its deferred tax position associated with the future tax effect of the Texas Margin tax in the accompanying consolidated balance sheets. 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 March 31, 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 March 31, 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 the three months ended March 31, 2008 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 the three months ended March 31, 2008, Pioneer has allocated general and administrative expenses to the Partnership Predecessor based on the Partnership Properties' share of Pioneer's total production as measured on a per barrel of oil equivalent basis. In management's estimation, the allocation methodologies used are reasonable and result in an allocation of the cost of doing business incurred by Pioneer on behalf of the Partnership Predecessor; however, these allocations may not be indicative of the costs of future operations or the amount of future allocations.

 

Net income per common unit. The Partnership calculates net income per common unit in accordance with SFAS No. 128, "Earnings Per Share" ("SFAS 128"). For the three months ended March 31, 2009, net income per common unit is calculated by dividing the limited partners' interest in net income by the weighted average number of common units outstanding (representing 30,008,700 common units, comprising 20,521,200 common units held by Pioneer and the 9,487,500 common units issued in the Offering). Prior to the Offering, the Partnership was wholly owned by Pioneer. Accordingly, net income per common unit is not presented for the three months ended March 31, 2008.

 

         Allocation of net income. The Partnership's net income 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 per common unit, the Partnership allocates net income to its limited partners and its general partner each quarter under the provisions of Emerging Issues Task Force Issue No. 03-6, "Participating Securities and the Two-Class Method Under FASB Statement No. 128" ("EITF 03-6"). Under the two-class method, the Partnership’s net income is allocated among the general partner’s interest in net income and the limited partners’ interest in net income. Net income per common unit is based upon the limited partners’ interest in net income 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 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 G 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 allocation in computing basic net income 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 as provided under the provisions of FSP EITF 03-6-1 during the three months ended March 31, 2009.

 

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 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 is effective for interim and annual reporting periods ending after June 15, 2009 and is not expected to have a material impact on the Partnership's fair value measurements.

 

 

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

 

 

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Partnership's financial assets and liabilities that are measured at fair value on a recurring basis as of March 31, 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 March 31, 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:

 

 

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(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 subsequent to January 31, 2009, changes in fair value are included in derivative loss and other 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 March 31, 2009. The Partnership's credit-adjusted risk-free rate curve is based on the Partnership's borrowing rate under its $300 million unsecured revolving credit facility (the "Credit Facility"), which matures in May 2013. The asset transfer values attributable to the Partnership's oil derivative instruments as of March 31, 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 implied volatility factors provided by the derivative counterparties, adjusted for estimated volatility skews. The volatility factors are not considered significant to the fair values of the collar contracts since intrinsic and time values are the principal components of the collar values.

 

NGL derivatives. The Partnership's NGL derivatives are swap contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs. The asset 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 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 months ended March 31, 2009 and 2008:

 

 

The Partnership's deferred tax attributes represented noncurrent assets of $544 thousand and $235 thousand as of March 31, 2009 and December 31, 2008, respectively and current liabilities of $375 thousand and $521 thousand as of March 31, 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 March 31, 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 months ended March 31, 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.

 

 

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 months ended March 31, 2009, the Partnership recognized noncash revenue of $3.9 million associated with the fair value changes of the derivatives novated.

 

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

 

 

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 months ended March 31, 2009.

 

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 as of and for the three months ended March 31, 2008 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 March 31, 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 months ended March 31, 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 March 31, 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 months ended March 31, 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 March 31, 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 months ended March 31, 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 March 31, 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 March 31, 2009 and December 31, 2008, AOCI - Hedging represented net deferred gains of $136.2 million and $143.0, respectively and associated deferred tax provisions of $868 thousand and $1.4 million as of March 31, 2009 and December 31, 2008, respectively.

During the twelve months ending March 31, 2010 the Partnership expects to reclassify approximately $64.5 million of net deferred hedge gains and approximately $645 thousand of deferred Texas Margin tax provisions associated with derivative contracts from AOCI - Hedging to commodity revenues and income tax provisions, respectively.

 

 

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 months ended March 31, 2009:

 

 

As of March 31, 2009 and December 31, 2008, the Partnership's accounts payable – due to affiliates balances in the accompanying consolidated balance sheets amounted to $812 thousand and $6.0 million, respectively. The balance as of March 31, 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 March 31, 2009 and December 31, 2008, the Partnership has $576 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.

 

During May 2008, the General Partner awarded 12,630 restricted common units to the directors of the General Partner under the Pioneer Southwest Energy Partners L.P. 2008 Long-Term Incentive Plan. Associated therewith, the Partnership recognized $40 thousand of general and administrative expense during the three months ended March 31, 2009.

 

NOTE I.              Subsequent Event

 

Distribution declaration. In April 2009, the Partnership declared a cash distribution of $0.50 per common unit for the period from January 1, 2009 to March 31, 2009. The distribution is payable on May 14, 2009 to unitholders of record at the close of business on May 7, 2009. Associated therewith, the Partnership will pay approximately $15.0 million of aggregate distributions.

 

 

Financial and Operating Performance

 

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

 

 

Recent Events

 

Financial markets. During the second half of 2008, worldwide financial markets experienced significant turmoil as concerns regarding a worldwide economic slowdown increased and the availability of liquidity provided by the financial markets declined. These concerns have continued into the first quarter of 2009. In response to these circumstances, governments worldwide have taken steps to enhance confidence and support the financial markets. The success of the steps taken and the duration of the uncertainty in the financial markets cannot be predicted. The Partnership is closely monitoring the economic environment, the impact of which is mitigated by the Partnership's derivative price risk management activities. As a result, the Partnership does not expect that current market conditions will significantly impact its near-term liquidity, future results of operations or financial position. See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" and Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Partnership's derivative contracts.

 

As of March 31, 2009, the Partnership had $28.9 million of cash and cash equivalents on deposit, held approximately $10.7 million of accounts receivable related to oil, NGL and gas sales, was a party to derivative financial instruments, of which $105.9 million represent assets of the Partnership, had no outstanding long-term debt and had approximately $200 million of available borrowing capacity under its 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 has resulted in significant declines in oil, NGL and gas prices from their highs in mid-2008. 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 duration and magnitude of the commodity price declines 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.

 

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

 

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 G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Partnership's commodity derivative positions at March 31, 2009. Also see "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for disclosures about the Partnership's commodity related derivative financial instruments.

 

Second quarter 2009 outlook. Based on current estimates, the Partnership expects that production will average 4,700 to 4,900 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 $5.50 to $6.50 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 March 31, 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. Pioneer has indicated to the Partnership that it is considering offering to sell certain oil and gas assets to the Partnership. 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 $32.6 million and $36.2 million for the three months ended March 31, 2009 and 2008, respectively.

 

The decrease in oil and gas revenues during the three months ended March 31, 2009, as compared to the same period of 2008, was primarily due to decreases in commodity prices, partially offset by an increase of two percent in total sales volumes on an average daily sales volume basis. In the quarter-to-quarter comparison, the average reported oil price decreased by seven percent; the average reported NGL price decreased by 19 percent; and the average reported gas price decreased by one percent. The increase in sales volume was primarily due to the sale of approximately 320 BOEPD in the first quarter 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. Additionally, the Partnership was able to maximize revenue during the first quarter of 2009 by rejecting ethane recoveries and selling the ethane as part of the gas residue stream. This resulted in an increase in gas sales volume during the three months ended March 31, 2009, as compared to the first quarter of 2008.

 

The following table provides average daily sales volumes for the three months ended March 31, 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 months ended March 31, 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 G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information about these derivatives.

 

Oil and gas production costs. The Partnership recorded oil and gas production costs, including production and ad valorem taxes, of $9.2 million during the three months ended March 31, 2009, as compared to $9.4 million for the same respective period of 2008. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Partnership has management control, while production and ad valorem taxes are directly related to commodity price changes. During the three months ended March 31, 2009, total oil and gas production costs per BOE decreased slightly as compared to the three months ended March 31, 2008.

 

The Partnership's lease operating expenses for the three months ended March 31, 2009 increased as compared to the same respective period of 2008 primarily due to overhead charges and general oilfield services price inflation. 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 $2.81 for the three months ended March 31, 2008. Workover costs decreased for the three months ended March 31, 2009, as compared to the first quarter 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.

 

The Partnership recorded production and ad valorem taxes of $1.9 million for the three months ended March 31, 2009, as compared to $2.7 million for the same respective period of 2008. The decrease is primarily attributable to lower production taxes associated with lower commodity prices. This decrease was partially offset by an increase in ad valorem tax accruals during the three months ended March 31, 2009, as compared to the first quarter of 2008. Since ad valorem taxes in Texas are determined, in part, based on commodity prices for the previous year, the Partnership's first quarter 2009 accrual for ad valorem taxes increased due to higher commodity prices in 2008 as compared to 2007.

 

The following table provides the components of the Partnership's total oil and gas production costs per BOE for the three months ended March 31, 2009 and 2008:

 

 

Depletion, depreciation and amortization expense. The Partnership's DD&A expense was $2.8 million ($5.77 per BOE) and $1.8 million ($3.72 per BOE) for the three months ended March 31, 2009 and 2008, respectively. The increase in DD&A expense was primarily due to negative price revisions to proved reserves as a result of lower commodity prices at March 31, 2009.

 

General and administrative expense. General and administrative expense for the three months ended March 31, 2009 and 2008 was $1.3 million and $1.2 million, respectively. The increase in general and administrative expense is due primarily to legal, accounting and other costs associated with being a public company that were not necessary prior to the Offering. For periods prior to the Offering, general and administrative expense consisted of an allocation of a portion of Pioneer's general and administrative expense based on the Partnership Predecessor's production as compared to Pioneer's total production from its United States properties (other than Alaska), as measured on a per barrel of oil equivalent basis. The Partnership and Pioneer entered into an Administrative Services Agreement as of May 6, 2008, pursuant to which Pioneer agreed to perform, either itself or through its affiliates or other third parties, administrative services for the Partnership, and the Partnership agreed to reimburse Pioneer for its expenses incurred in providing such services. Pioneer has informed the Partnership that 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. Changes in the fair value of the Partnership's derivative positions from February 1, 2009, when the Partnership discontinued hedge accounting on all existing commodity derivative instruments, to March 31, 2009 resulted in a net fair value loss of $7.0 million. The Partnership was not a party to any derivative contracts during the three months ended March 31, 2008. See Note G 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 $84 thousand and $249 thousand during the three months ended March 31, 2009 and 2008, respectively. The Partnership's effective tax rate is approximately one percent of taxable income apportioned to Texas, reflective of the Texas Margin tax. 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 proved reserves. The Partnership has adopted a cash distribution policy pursuant to which it intends to declare distributions of $0.50 per unit per quarter, or $2.00 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter. The distribution for the first 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 May 14, 2009 to unitholders of record on May 7, 2009.

 

Oil and gas properties. The Partnership's cash expenditures for additions to oil and gas properties during the three month periods ended March 31, 2009, totaled $178 thousand, as compared to $83 thousand for the same period of 2008. The Partnership's expenditures for additions to oil and gas properties for the three months ended March 31, 2009 and 2008 were funded by net cash provided by operating activities.

 

Contractual obligations, including off-balance sheet obligations. As of March 31, 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 $105.8 million as of March 31, 2009; however, they continue to have market risk and represent contractual obligations of the Partnership. See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding the Partnership's derivative positions. As of March 31, 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.

 

The ultimate liquidation value of the Partnership's commodity derivatives will be dependent upon actual future commodity prices, which may differ materially from the inputs used to determine the derivatives' fair values at any point in time. The Partnership entered into these derivatives for the primary purpose of hedging commodity price risk on forecasted physical commodity sales and has an expectation of a high degree of correlation between changes in the derivative values and the hedged risks. See Notes C and G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information about valuation and composition of the Partnership's derivative instruments and market risk.

 

Capital resources. The Partnership's primary capital resources are expected to be net cash provided by operating activities, amounts available under its Credit Facility and, to the extent available, funds from future private and public equity and debt offerings. 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 months ended March 31, 2009 was $14.2 million, as compared to $25.4 million for the same respective period of 2008. The decrease in net cash provided by operating activities during the three months ended March 31, 2009, as compared to the three month period ended March 31, 2008, was primarily due to decreased oil, NGL and gas sales prices and changes in working capital.

 

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, will reduce the Partnership's internal cash flows. The duration and magnitude of the commodity price declines 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. Investing activities used $178 thousand of cash during the three months ended March 31, 2009, as compared to $83 thousand for the same respective period of 2008. The increase in net cash used in investing activities during the first quarter of 2009, as compared to the first quarter of 2008, was primarily due to additions of oil and gas properties. Future investing activities may include expenditures 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 months ended March 31, 2009 was $15.0 million, as compared to net cash used in financing activities of $25.4 million during the three months ended March 31, 2008. The decrease in net cash used in financing activities during the three months ended March 31, 2009, as compared to the three months ended March 31, 2008, was primarily due to a $10.4 million decline in distributions to the Partnership's owner and partners. The Partnership's financing activities for periods prior to the Offering were limited to distributions of cash to Pioneer.

 

Liquidity. The Partnership's principal source of short-term liquidity is cash generated from operations and availability under its Credit Facility. As of March 31, 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 $200 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. In making cash distributions, the General Partner will attempt to avoid large variations in the amount the Partnership distributes from quarter to quarter. The Partnership Agreement permits the General Partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters, and for the conduct of the Partnership's business, which includes possible acquisitions. 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, which 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.

 

In December 2007, the FASB issued SFAS 141(R), which 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 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 G 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, which 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 allocation in computing basic net income 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 as provided under the provisions of FSP EITF 03-6-1 during the three months ended March 31, 2009.

 

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 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 is effective for interim and annual reporting periods ending after June 15, 2009 and is not expected to 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 downward swings in commodity prices on its cash available for distributions. All contracts will be settled with cash and do not require the delivery of physical volumes to satisfy settlement. While in times of higher commodity prices this strategy may result in the Partnership having lower net cash inflows than would be the case if these instruments were not utilized, management believes the risk reduction benefits of this strategy outweigh the potential costs. As of March 31, 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 and, if sustained, continue to result in the recognition of significant commodity derivative assets in the Partnership’s consolidated balance sheets. 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 three months ending March 31, 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 March 31, 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. There has been no material change in the Partnership's risk factors from those described in the Annual Report on Form 10-K.

 

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

 

 

Exhibits

 

 

_____________

(a) Filed herewith.

(b) Furnished herewith.

 

SIGNATURES

 

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

 

 

 

 

 

 

Exhibit Index

 

 

 

_____________

(a) Filed herewith.

(b) Furnished herewith.