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 June 30, 2008

 

or

 

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to ________

 

Commission File Number: 001-34032

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.  

(Exact name of Registrant as specified in its charter)

 

 

 

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

Yes  x No o

 

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

 

 

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

Yes o No x

 

 

 

 

 

 

 

 

Cautionary Statement Concerning Forward-Looking Statements

 

The information in this Quarterly Report on Form 10-Q (the "Report") contains forward-looking statements that involve risks and uncertainties. When used in this document, the words "believes," "plans," "expects," "anticipates," "intends," "continue," "may," "will," "could," "should," "future," "potential," "estimate," or the negative of such terms and similar expressions as they relate to Pioneer 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 effectiveness of the Partnership's commodity price hedging strategy, reliance on Pioneer Natural Resources Company and its subsidiaries to manage the Partnership's business and identify and evaluate acquisitions, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, litigation, the costs and results of operations, access to and availability of transportation, processing and refining facilities, the Partnership's ability to replace reserves, including through acquisitions, and implement its business plans, uncertainties associated with acquisitions, access to and cost of capital, uncertainties about estimates of reserves, the assumptions underlying production forecasts, quality of technical data and environmental and weather risks. These and other risks are described in the Partnership's final prospectus dated April 30, 2008 (File No. 333-144868) and filed on May 1, 2008 with the Securities and Exchange Commission (the "SEC") pursuant to Rule 424(b)(4) under the Securities Act of 1933 (the "Prospectus") and other filings with the SEC. In addition, the Partnership may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See "Risk Factors," "Business — Environmental Matters and Regulation" and "Business — Other Regulation of the Oil and Gas Industry" in the Prospectus for a description of various factors that could materially affect the ability of the Partnership to achieve the anticipated results described in the forward-looking statements. The Partnership undertakes no duty to publicly update these statements except as required by law.

 

 

Definitions of Certain Terms and Conventions Used Herein

 

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

 

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

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

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

 

 

PART I. FINANCIAL INFORMATION

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

 

 

 

 

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED STATEMENT OF PARTNERS' EQUITY

(in thousands)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

 

 

 

 

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

 

 

 

 

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2008

(Unaudited)

 

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

 

 

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

 

The proceeds from the exercise of the underwriters' over-allotment option in connection with the Offering were used by the Partnership to purchase incremental working interests in certain Partnership Properties, thereby effecting a change in the reporting entity as defined by generally accepted accounting principles in the United States ("GAAP"). The change in reporting entity has been retrospectively applied to all prior periods presented. As a result of the change, net income increased to $25.1 million as compared to $24.0 million previously reported for the six months ended June 30, 2007.

 

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

 

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

 

 

 

Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the SEC. These financial statements should be read in connection with the financial statements and notes thereto included in the Partnership's final prospectus dated April 30, 2008 (File Number 333-144868), which the Partnership filed with the SEC on May 1, 2008 pursuant to Rule 424 (b)(4) of the Securities Act of 1933.

 

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

 

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

 

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

 

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

 

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

 

Derivatives and hedging. The Partnership follows the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income. Under the provisions of SFAS 133, the Partnership may designate a derivative instrument as hedging the exposure to changes in the fair value of an asset or a liability or an identified portion thereof that is attributable to a particular risk (a "fair value hedge") or as hedging the exposure to variability in expected future cash flows that are attributable to a particular risk (a "cash flow hedge"). Both at the inception of a hedge and on an ongoing basis, a fair value hedge must be expected to be

 

 

 

highly effective in achieving offsetting changes in fair value attributable to the hedged risk during the periods that a hedge is designated. Similarly, a cash flow hedge must be expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. The expectation of hedge effectiveness must be supported by matching the essential terms of the hedged asset, liability or forecasted transaction to the derivative hedge contract or by effectiveness assessments using statistical measurements. The Partnership's policy is to assess hedge effectiveness at the end of each calendar quarter.

 

Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments through net income. Effective changes in the fair value of derivative instruments that are cash flow hedges are recognized in accumulated other comprehensive loss - deferred hedge losses, 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.

 

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

 

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

 

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

 

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

 

Segment reporting. The Partnership has only one operating segment during the periods presented – the production and development of oil and gas reserves. Additionally, all of the Partnership Properties are located in the United States and all of the related oil, natural gas liquids ("NGL") and gas revenues are derived from customers located in the United States.

 

Income taxes. Prior to the Offering, the operations of the Partnership 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. Earnings of the Partnership became subject to the Texas Margin tax effective May 6, 2008.

 

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

 

 

 

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

 

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

 

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

 

Allocation of owner’s net equity and partners’ equity. The financial position, results of operations, cash flows and owner’s equity of the Partnership for all periods presented prior to the Offering represent those of the Partnership Predecessor. In accordance with GAAP, the contribution and purchase of the Partnership Properties and other net assets from Pioneer were accounted for as transactions between entities under common control. Therefore, the net assets were recorded on the Partnership's balance sheet at $140.5 million, representing Pioneer's carrying value of the net assets and the Partnership’s owner’s equity as of the Offering date. Accordingly, the $140.5 million carrying value of the net assets is presented as an allocation of owner’s equity to the limited and general partner’s equity of Pioneer in the accompanying consolidated statement of partners’ equity.

 

Pioneer's carrying value in the net assets acquired by the Partnership includes $2.0 million of non-cash working capital contributed by Pioneer, representing net working capital earned from the Partnership Properties during the period from May 1, 2008 through May 5, 2008.  The following table provides Pioneer’s carrying values in the assets and (liabilities) contributed to and acquired by the Partnership:

 

The Partnership acquired a portion of the Partnership Properties from Pioneer for $163.1 million on the Offering date, which amount exceeded the carrying value of the net assets by $22.5 million. The Partnership’s payment to Pioneer of $140.5 million to acquire the carrying value of the Partnership Properties is reflected as an investing activity in the accompanying consolidated statement of cash flows and was recorded as a reduction of

 

 

 

the general partner's and limited partner’s equity of Pioneer, as presented in the accompanying consolidated statement of partners’ equity. The Partnership's payment to Pioneer of $22.5 million in excess of the carrying value of the Partnership Properties is reflected in the accompanying consolidated statement of cash flows as a financing activity and as a reduction of the limited partners' equity of Pioneer, as presented in the accompanying statement of partners' equity.

 

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

 

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

 

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

 

For purposes of calculating earnings 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").

 

Net income per common unit. The Partnership calculates net income per common unit in accordance with Financial Accounting Standards Board Statement No. 128, "Earnings Per Share" ("SFAS 128"). For the three and six months ended June 30, 2008, net income per common unit is calculated by dividing the limited partners' interest in net income derived from operations subsequent to the Offering by the weighted average number of common units outstanding (representing 30,008,700 common units, comprised of 20,521,200 common units held by Pioneer and the 9,487,500 common units issued in the Offering). Prior to the Offering, the Partnership was wholly owned by Pioneer. Accordingly, net income per common unit is not presented for periods prior to the Offering.

 

New accounting pronouncements . In September 2006, the Financial Accounting Standards Board ("FASB") issued SFAS No. 157, "Fair Value Measures" ("SFAS 157"). SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. During February 2008, the FASB issued FASB Staff Position No. 157-2 ("FSP FAS 157-2"). FSP FAS 157-2 delays the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis at least annually. On January 1, 2008, the Partnership adopted the provisions of SFAS 157 as they pertain to financial assets and liabilities. See Note C for additional information regarding the Partnership's adoption of SFAS 157. The adoption of the provisions of SFAS 157 that were delayed by FSP FAS 157-2 is not expected to have a material effect on the financial condition or results of operations of the Partnership.

 

In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities" ("SFAS 159"). SFAS 159 permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The Partnership adopted the

 

 

 

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

 

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

 

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

 

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

 

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

 

 

Effective January 1, 2008, the Partnership adopted the provisions of SFAS 157 for which delayed adoption is not provided under FSP FAS 157-2. SFAS 157 retains the exchange price notion in the definition of fair value but clarifies that the exchange price is the price in an orderly transaction between market participants to sell an asset or transfer a liability in the principal or most advantageous market in which the reporting company would transact for the asset or liability.

 

 

 

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

 

 

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

 

 

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

 

 

Commodity derivative obligations. The Partnership's commodity derivative obligations represent oil, NGL and gas swap and collar contracts. All of the Partnership's oil and gas price obligation measurements represent Level 2 inputs in the hierarchy priority. The Partnership's NGL price obligation 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. The liability transfer values attributable to the Partnership's oil derivative

 

 

 

obligations as of June 30, 2008 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) the Partnership's estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar contracts. The Partnership's credit-adjusted risk-free rate is estimated based on Pioneer's market-quoted credit default swap rate plus the United States Treasury Bill yield curve as of June 30, 2008. 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 liability transfer values attributable to the Partnership's NGL derivative obligations as of June 30, 2008 are based on (i) the contracted notional volumes, (ii) independent broker-supplied forward Mont Belvieu-posted-price quotes and (iii) the Partnership's credit-adjusted risk-free rate yield curve.

 

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

 

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

 

 

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

 

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

 

Because of the net present value covenant, borrowings under the Credit Facility are currently limited to approximately $200 million. In addition, the Credit Facility contains various covenants that limit, among other things, the Partnership's ability to grant liens, incur additional indebtedness, engage in a merger, enter into transactions with affiliates, pay distributions or repurchase equity, and sell its assets. If any default or event of default (as defined in the Credit Facility) were to occur, the Credit Facility would prohibit the Partnership from making distributions to unitholders. Such events of default include, among others, nonpayment of principal or interest, violations of covenants, bankruptcy and material judgments and liabilities.

 

 

 

 

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

 

 

The Partnership's deferred tax attributes represented an $878 thousand asset as of June 30, 2008 and a $463 thousand liability as of December 31, 2007. The change in the Partnership's deferred tax position primarily resulted from the Offering, on May 6, 2008, and reflects differences in basis for tax purposes related to oil and gas properties. In connection with the Offering, the Partnership entered into a Tax Sharing Agreement with Pioneer. Under this agreement, the Partnership will pay Pioneer for its share of state and local income and other taxes (currently only the Texas Margin tax) for which the Partnership's results are included in a combined or consolidated tax return filed by Pioneer. It is possible that Pioneer may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe no tax. In such a situation, the Partnership would reimburse Pioneer for the tax it would have owed had the attributes not been available or used for its benefit, even though Pioneer had no cash expense for that period.

 

The Partnership applies the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes" ("FIN 48"). FIN 48 clarifies the accounting for uncertainty in income taxes recognized and prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of June 30, 2008, the Partnership had no 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 established a policy to account for (a) interest charges with respect to income taxes as interest expense and (b) penalties as other expense in the consolidated statements of operations.

 

 

 

 

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

 

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

 

 

 

The Partnership's title to the Partnership Properties is burdened by a volumetric production payment ("VPP") commitment of Pioneer. During April 2005, Pioneer entered into a volumetric production payment agreement, pursuant to which it sold 7.3 million barrels of oil equivalent ("MMBOE") of proved reserves in the Spraberry field. The VPP obligation required the delivery by Pioneer of specified quantities of gas through December 2007 and requires the delivery of specified quantities of oil through December 2010. Pioneer's VPP agreement represents limited-term overriding royalty interests in oil and gas reserves that: (i) entitle the purchaser to receive production volumes over a period of time from specific lease interests; (ii) do not bear any future production costs and capital expenditures associated with reserves; (iii) are nonrecourse to Pioneer, (i.e., the purchaser's only recourse is to the assets acquired); (iv) transfer title of the assets to the purchaser; and (v) allow Pioneer or the Partnership, as the case may be, to retain the assets after the VPP's volumetric quantities have been delivered.

 

Virtually all of the properties that the Partnership owns as of the closing of the Offering 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.

 

Gas production from Pioneer's retained interest in the properties subject to the VPP obligation during the three and six months ended June 30, 2007 was not adequate to meet the VPP obligation, and a portion of the Partnership Predecessor's gas production was utilized to fund the VPP obligation. Accordingly, the accompanying consolidated financial statements for the three and six months ended June 30, 2007 do not include gas revenues of $32 thousand and $173 thousand, respectively, that would have been recognized absent the VPP obligation. The production associated with the excluded gas revenues was approximately 5,971 Mcf and 33,866 Mcf for the three

 

 

 

and six months ended June 30, 2007, respectively. The gas VPP obligation expired at December 31, 2007.

 

 

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

 

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

 

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

 

 

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

 

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

 

 

 

 

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

 

 

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

 

 

 

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

 

 

 

 

 

 

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

 

 

 

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

 

 

 

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

 

 

AOCI - Hedging. As of June 30, 2008 and December 31, 2007, AOCI - Hedging represented net deferred losses of $60.2 million and $0 million, respectively. The increase in AOCI - Hedging during the six months ended June 30, 2008 was primarily attributable to increases in future oil, NGL and gas prices relative to the commodity prices stipulated in the hedge contracts, partially offset by the reclassification of net deferred hedge losses to net income as derivatives matured. The net deferred losses associated with open cash flow hedges remain subject to market price fluctuations until the positions are either settled under the terms of the hedge contracts or terminated

 

 

 

prior to settlement. The Partnership recorded no hedge ineffectiveness associated with hedging activities during the six months ended June 30, 2008.

During the twelve months ending June 30, 2009, based on June 30, 2008 estimates of future commodity prices and interest rates, the Partnership expects to reclassify approximately $41.8 million of net deferred losses associated with open commodity hedges from AOCI - Hedging to oil and gas revenues.

 

 

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

 

Administrative Services Agreement  

 

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

 

Omnibus Agreement  

 

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

 

 

 

Omnibus Operating Agreement  

 

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

 

Tax Sharing Agreement  

 

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

 

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

 

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

 

2008 Long-Term Incentive Plan

 

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

 

During May 2008, Pioneer GP awarded 12,630 restricted units to directors of Pioneer GP under the LTIP, of which 6,315 represented the initial restricted unit grant and will vest ratably over three years and 6,315 represented the initial annual restricted unit grant and will vest in May 2009. Associated therewith, the Partnership recognized $27 thousand of general and administrative expense from May 6 through June 30, 2008

 

Indemnification Agreements  

 

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

 

 

 

In accordance with the agreements described above, the Partnership incurred the following charges from Pioneer during the period from May 6, 2008 through June 30, 2008:

 

 

 

As of June 30, 2008, the Partnership's accounts payable-affiliate balance in the accompanying consolidated balance sheet is comprised of $5.3 million of Offering costs paid by Pioneer and approximately $1.4 million of unpaid COPAS fees, lease operating expenses and general and administrative expense.

 

 

During July 2008, the Partnership declared a pro rated cash distribution of $0.31 per common unit for the period from the closing of the Offering to June 30, 2008. Associated therewith, the Partnership paid $9.3 million of aggregate distributions on August 12, 2008.

 

 

 

 

 

Financial and Operating Performance

 

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

 

 

Recent Events

 

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 and see Part II, Item 2, "Unregistered Sales of Equity Securities and Use of Proceeds" for additional information regarding the initial public offering and the use of proceeds.

 

Novation of derivative agreements. On May 6, 2008, novation agreements were entered into between Pioneer, the Partnership and certain derivative instrument counterparties, which transferred Pioneer's rights and responsibilities under certain derivative instruments to the Partnership. The novated derivative agreements were designated as cash flow hedges of portions of the Partnership's oil, NGL and gas commodity price risk for forecasted sales for the periods from May 2008 through December 2008 and the years of 2009 and 2010. As of May 6, 2008, the aggregate fair value of the derivative instruments novated to the Partnership represented a liability of approximately $37.2 million. Future changes in the fair values of the derivative instruments, to the extent that they are effective as hedges of the designated commodity price risk, will be deferred and recognized in the Partnership's earnings in the same periods as the forecasted sales being hedged. See Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding these derivative instruments.

 

Midkiff-Benedum Gas Processing System . Pioneer owns a 27 percent interest in the Spraberry Midkiff-Benedum gas processing system (the “System”) in West Texas and, in July 2007, entered into an agreement with Atlas Pipeline Partners (“Atlas”) under which Pioneer obtained an option to purchase an additional 22 percent interest in the System for $230 million, subject to normal closing adjustments. The option may be exercised for up to an additional 14.56 percent interest in 2008, and any unexercised portion of the option may be exercised in 2009. The System processes a portion of the wet gas from the Partnership’s wells and retains as compensation approximately 20 percent of the Partnership’s dry gas residue and NGL value. During the year ended December 31,

 

 

 

2007, approximately 67 percent of the Partnership’s total NGL and gas revenues was from the sale of NGL and gas processed through the System.

 

Pioneer has informed the Partnership that it is considering the assignment to the Partnership of the portion of the option that is exercisable in 2008. The Partnership has commenced an evaluation of the option and the underlying assets of the System, but the transaction terms of the possible assignment from Pioneer have not been determined at this time. Any such assignment would be subject to negotiation of definitive agreements and the approval of the board of directors of Pioneer GP and the Conflicts Committee of the board. There can be no assurance that Pioneer will assign all or any portion of the option to the Partnership or as to the terms of any such assignment.

 

Third Quarter 2008 Outlook

 

Based on current estimates, the Partnership expects that third quarter 2008 production will average 4,900 to 5,100 BOEPD.

 

Third quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $24.00 to $27.00 per BOE based on current NYMEX strip prices for oil and gas. Depletion, depreciation and amortization ("DD&A") expense is expected to average $3.50 to $4.00 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 third quarter 2008 cash taxes and effective income tax rate are expected to be approximately one percent as a result of the Partnership being subject to the Texas Margin tax.

 

Operations Highlights

 

The Partnership's properties are entirely comprised of producing oil and gas properties. Producing oil and gas reservoirs are characterized by declining production rates. Because the Partnership does not own any undeveloped properties or leasehold acreage, its reserves and production are expected to decline continually over time unless the Partnership acquires additional properties to replace its declining production. Consequently, the Partnership must offset declining production with future acquisitions of oil and gas assets from third parties or Pioneer. Accordingly, the Partnership anticipates reserving a portion of its net cash provided by operating activities to fund future property acquisitions. The Partnership may also use external financing sources to fund acquisitions, including borrowings under its $300 million revolving credit facility and funds from future private and public equity and debt offerings.

 

Longer-term, the Partnership may benefit from production and reserve enhancements as a result of infill drilling and secondary recovery initiatives that are in the early stages of development by Pioneer. These initiatives involve obtaining regulatory approval for downspacing and initiating waterflood projects in the Spraberry field. The ultimate outcome and impact to the Partnership of these initiatives cannot be predicted at this time.

 

During the three and six months ended June 30, 2008, the Partnership invested approximately $174 thousand and $257 thousand, respectively, of development capital on its producing properties, which primarily represented expenditures incurred on existing horizontal wells owned by the Partnership.

 

 

 

Results of Operations

 

Oil and gas revenues. Oil and gas revenues totaled $41.0 million and $77.2 million for the three and six months ended June 30, 2008, respectively, as compared to $24.6 million and $47.5 million for the same respective periods of 2007.

 

The increase in oil and gas revenues during the three and six months ended June 30, 2008, as compared to the same periods of 2007, is primarily due to increases in commodity prices, partially offset by a five percent decrease in total sales volumes on an average daily sales volume basis. In the quarter-to-quarter and six month-to-six month comparison, the average reported oil price increased by 86 percent and 78 percent, respectively; the average reported NGL price increased by 43 percent and 49 percent, respectively; and the average reported gas price increased by 43 percent and 32 percent, respectively. The decrease in sales volumes is due to normal production decline.

 

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

 

 

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

 

 

As seen in the above table, NGL prices for the second quarter of 2008 did not increase proportionately to the increase in oil prices. The Partnership's NGL price realization was approximately 56 percent of NYMEX oil price during the second quarter of 2007; however, in the second quarter of 2008, the Partnership's NGL price realization decreased to approximately 43 percent of the average NYMEX oil price. The decrease is primarily due to propane and ethane prices (the principal components of the Partnership's NGL stream) not increasing proportionately with NYMEX oil prices due to the supply and demand fundamentals specific to those products.

 

Hedging activities . The Partnership expects to utilize commodity swap and option contracts primarily to reduce the impact on the Partnership's net cash provided by operating activities and results of operations from the price volatility of the commodities the Partnership produces and sells. During the three and six months ended June 30, 2007, the Partnership Predecessor had no hedging activities. On May 6, 2008, Pioneer novated oil, NGL and gas swap contracts to the Partnership that have been designated as hedges of portions of the Partnership's forecasted May through December 2008, and annual 2009 and 2010 oil, NGL and gas sales. See Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information about these derivatives.

 

 

 

          Oil and gas production costs. The Partnership recorded oil and gas production costs of $11.1 million and $20.4 million during the three and six months ended June 30, 2008, respectively, as compared to $8.2 million and $15.6 million for the same respective periods of 2007. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Partnership has management control, while production and ad valorem taxes are directly related to commodity price changes. Total oil and gas production costs per BOE increased by 41 percent and 37 percent during the three and six months ended June 30, 2008, as compared to the three and six months ended June 30, 2007, primarily due to (i) increases in lease operating expense due to increased oilfield well servicing activity, increased electricity costs and general oilfield services price inflation, (ii) increases in production taxes due to commodity price increases and (iii) increases in workover costs incurred to maximize production volumes as wells mature, partially offset by (iv) a slight decline in ad valorem taxes, primarily resulting from the effects of tax reform legislation in Texas.

 

In addition to the above explanation of higher lease operating expenses, the Partnership's lease operating expense also included an allocation of Pioneer's direct internal costs associated with the operation of the Partnership Properties for periods prior to the Offering. In May 2008, Pioneer, as operator, began charging the Partnership overhead charges associated with operating the Partnership Properties (commonly referred to as the Council of Petroleum Accountants Societies, or COPAS fee), instead of the direct internal costs incurred by Pioneer. Assuming the COPAS fee had been charged in the Partnership Predecessor's historical results, the lease operating expense would have been higher on a BOE basis by $1.03 and $3.18 for the three months ended June 30, 2008 and 2007, respectively, and $1.94 and $3.00 for the six months ended June 30, 2008 and 2007, respectively.

 

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

 

 

Depletion, depreciation and amortization expense. The Partnership's DD&A expense was $1.6 million ($3.60 per BOE) and $3.4 million ($3.66 per BOE) for the three and six months ended June 30, 2008, respectively, as compared to $2.2 million ($4.51 per BOE) and $4.3 million ($4.48 per BOE) for the three and six months ended June 30, 2007, respectively. The decrease in DD&A expense was primarily due to proved reserve increases reflecting commodity price increases and, to a lesser extent, positive 2007 drilling results.

 

General and administrative expense. General and administrative expense was $1.5 million and $2.7 for the three and six months ended June 30, 2008, respectively, as compared to $1.1 million and $2.2 million for the three and six months ended June 30, 2007, 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. Subsequent to the Offering, the Partnership is responsible for paying for third-party services. The Partnership and Pioneer entered into an Administrative Services Agreement as of May 6, 2008, pursuant to which Pioneer agreed to perform, either itself or through its affiliates or other third parties, administrative services for the Partnership, and the Partnership agreed to reimburse Pioneer for its expenses incurred in providing such services. Pioneer has informed the Partnership that, initially, expenses will

 

 

 

be reimbursed based on a methodology of determining the Partnership's share, on a per BOE basis, of certain of the general and administrative costs incurred by Pioneer. See Note I of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the general and administrative expense allocations to the Partnership.

 

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $30 thousand and $59 thousand for the three and six months ended June 30, 2008, respectively, as compared to $27 thousand and $53 thousand for the same respective periods of 2007.

 

Income tax provision. The Partnership recognized income tax provisions of $279 thousand and $528 thousand during the three and six months ended June 30, 2008, respectively, as compared to $141 thousand and $275 thousand for the same respective periods of 2007. The Partnership's effective tax rate is approximately one percent, reflective of the Texas Margin tax.

 

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

 

Capital Commitments, Capital Resources and Liquidity

 

Capital commitments. The Partnership's primary needs for cash will be for asset growth through acquisitions and for unitholder distributions. The Partnership may use any combination of internally- and externally-financed sources to fund acquisitions and unitholder distributions, including borrowings under the Partnership's $300 million revolving credit facility and funds from future private and public equity and debt offerings.

 

The Partnership Agreement requires that the Partnership distribute all of its available cash to its partners. In general, available cash is defined to mean cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves for future capital expenditures (including acquisitions), operational needs and distributions for any one or more of the next four quarters. Because the Partnership's proved reserves and production decline continually over time, the Partnership will need to acquire income producing assets to sustain its level of distributions to unitholders over time. Currently, the Partnership expects to reserve approximately 25 percent to 35 percent of its cash flow to acquire oil and gas assets in order to maintain its production and proved reserves. The Partnership has adopted a cash distribution policy pursuant to which it intends to declare an initial distribution 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 period from the closing of the Offering to June 30, 2008 was pro rated at $0.31 per unit for unitholders of record on July 29, 2008 and was paid on August 12, 2008.

 

Although Pioneer has no obligation to sell assets to the Partnership, and the Partnership is not obligated to purchase from Pioneer any additional assets, Pioneer has informed the Partnership that it intends to offer to the Partnership in 2008 and periodically thereafter the opportunity to purchase from Pioneer assets in the Partnership's area of operations. The Partnership also may make acquisitions of oil and gas assets in its area of operations from third parties and may participate jointly in acquisitions with Pioneer in which the Partnership could acquire the producing oil and gas properties and Pioneer could acquire the undeveloped properties. Any assets that the Partnership acquires from either Pioneer or third parties may include interests in midstream assets.

 

Oil and gas properties. The Partnership's cash expenditures for additions to oil and gas properties during the three and six month periods ended June 30, 2008, totaled $174 thousand and $257 thousand, respectively, as compared to $2.1 million and $6.8 million for the same respective periods of 2007. The Partnership's expenditures for additions to oil and gas properties for the three and six month periods ended June 30, 2008 and 2007 were funded by net cash provided by operating activities.

 

Contractual obligations, including off-balance sheet obligations. As of June 30, 2008, the Partnership's contractual obligations were limited to asset retirement obligations, which had not changed materially since December 31, 2007, contingent VPP obligations and derivative obligations. The fair value of the Partnership's derivative instruments represented a liability of $94.6 million as of June 30, 2008. As of June 30, 2008, the Partnership was not a party to any off-balance sheet arrangements. See Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding the Partnership's derivative obligations.

 

 

 

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

 

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

 

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

 

Capital resources. The Partnership's primary capital resources are expected to be net cash provided by operating activities, amounts available under its credit facility, and funds from future private and public equity and debt offerings. The Partnership expects that these resources will be sufficient to fund its acquisitions and unitholder distributions during the foreseeable future.

 

Operating activities. Net cash provided by operating activities during the three and six months ended June 30, 2008 was $35.6 million and $61.0 million, respectively, as compared to $15.1 million and $30.8 million for the same respective periods of 2007. The increase in net cash provided by operating activities during the first and second quarters of 2008, as compared to the first and second quarters of 2007, is primarily due to increased oil, NGL and gas sales prices, partially offset by a decline in sales volumes and increased production costs.

 

Investing activities. Investing activities used $140.7 million and $140.8 million of cash during the three and six month periods ended June 30, 2008, respectively, as compared to $2.1 million and $6.8 million for the same respective periods of 2007. The increase in net cash used in investing activities during the second quarter of 2008, as compared to the second quarter of 2007, is primarily due to the acquisition of properties related to the Offering.

 

Financing activities. Net cash provided by financing activities during the three and six months ended June 30, 2008 was $117.6 million and $92.3 million respectively, as compared to net cash used in financing activities of $13.0 million and $24.0 million during the same respective periods of 2007. The increases in net cash provided by financing activities during the three and six months ended June 30, 2008, as compared to the same period of 2007, were due primarily to proceeds received from the Offering, partially offset by the acquisition of Partnership Properties in excess of carrying value. The Partnership's financing activities for periods prior to the Offering were limited to distributions of cash to Pioneer.

 

 

 

During July 2008, the Partnership declared a cash distribution of $0.31 per common unit for the quarter ended June 30, 2008. The distribution was paid on August 12, 2008 to unitholders of record on July 29, 2008.

 

Liquidity. The Partnership's principal source of short-term liquidity has been cash generated from its operations. In connection with the Offering, the Partnership closed on its $300 million revolving credit facility on May 6, 2008. See Note D of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information regarding the credit facility.

 

The Partnership expects that its primary sources of liquidity will be cash generated from operations, amounts available under the credit facility and 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 and because the Partnership does not own any undeveloped properties or leasehold acreage, the Partnership will need to make acquisitions to sustain its level of distributions to unitholders over time. Accordingly, the Partnership's primary needs for cash will be for distributions to partners and asset growth through acquisitions. In making cash distributions, the general partner will attempt to avoid large variations in the amount the Partnership distributes from quarter to quarter. The Partnership Agreement permits the general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters, and for the conduct of the Partnership's business, which includes possible acquisitions. If cash flow from operations does not meet the Partnership's expectations, the Partnership may reduce its level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of its capital expenditures using borrowings under its 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 hedge a significant portion of its production. The Partnership generally will be required to settle its commodity hedge derivatives within five days of the end of the month. As is typical in the oil and gas industry, the Partnership does not generally receive the proceeds from the sale of its hedged production until 45 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the derivative contracts, the Partnership will be required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before the Partnership receives the proceeds from the sale of the hedged production. If this occurs, the Partnership may make working capital borrowings to fund its distributions.

 

New accounting pronouncements. In September 2006, the FASB issued SFAS No. 157, "Fair Value Measures" ("SFAS 157"). SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. During February 2008, the FASB issued FASB Staff Position No. 157-2 ("FSP FAS 157-2"). FSP FAS 157-2 delays the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis at least annually. On January 1, 2008, the Partnership adopted the provisions of SFAS 157 as they pertain to financial assets and liabilities. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Partnership's adoption of SFAS 157. The adoption of the provisions of SFAS 157 that were delayed by FSP FAS 157-2 is not expected to have a material effect on the financial condition or results of operations of the Partnership.

 

In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities" ("SFAS 159"). SFAS 159 permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The Partnership adopted the provisions of SFAS 159 on January 1, 2008 and its implementation did not have a material effect on the financial condition or results of operations of the Partnership.

 

 

 

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

 

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

 

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

 

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

 

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

 

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 plans to enter into various derivative instruments to manage its exposure to volatility of commodity market prices. The Partnership has adopted a policy that contemplates hedging the prices for approximately 65 to 85 percent of expected production for a period of up to five years, as appropriate. Implementation of this policy is expected to mitigate, but will not eliminate, the Partnership's sensitivity to short-term changes in commodity prices. The Partnership's credit facility requires it to enter into hedging arrangements for not less than 65 percent (nor more than 85 percent) of the Partnership's projected oil, NGL and gas production attributable to proved developed producing reserves through December 31, 2010. In addition, within the next year, the credit facility requires that the Partnership enter into hedging arrangements for not less than 50 percent of the Partnership's projected oil, NGL and gas production attributable to proved developed producing reserves through December 31, 2011. The Partnership may use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in commodity prices on its cash available for distributions. All contracts will be settled with cash and do not require the delivery of physical volumes to satisfy settlement. While in times of higher commodity prices this strategy may result in the Partnership having lower net cash inflows than would be the case if these instruments were not utilized, management believes the risk reduction benefits of this strategy outweigh the potential costs.

 

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

 

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

 

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

 

 

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

 

Oil, NGL and Gas Price Sensitivity

Derivative Financial Instruments as of June 30, 2008

 

 

 

_____________

 

 

 

 

Evaluation of disclosure controls and procedures. Management of the Partnership's general partner, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the "Exchange Act"), the 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 management of the Partnership's general partner, including the principal executive officer and principal financial officer of the Partnership's general partner, to allow timely decisions regarding required disclosure.

 

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

 

 

 

PART II. OTHER INFORMATION

 

 

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

 

 

In addition to the other information set forth in this Report, you should carefully consider the risks discussed in the Partnership's final prospectus dated April 30, 2008 (File No. 333-144868) and filed on May 1, 2008 with the SEC pursuant to Rule 424(b)(4) under the Securities Act of 1933 (the "Prospectus"), 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 Prospectus. 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.

 

 

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

 

On May 6, 2008, the Partnership consummated the initial public offering of a total of 9,487,500 common units at $19.00 per unit, or $17.67 per unit after payment of an underwriting discount. The number of units sold included 1,237,500 common units that were exercised pursuant to an over allotment option granted to the underwriters in connection with the initial public offering. The underwriters gave the Partnership notice of their exercise on May 2, 2008, and closed the purchase of the common units concurrently with the closing of the initial public offering on May 6, 2008. The initial public offering was priced on April 30, 2008, and was made pursuant to a registration statement on Form S-1 (File No. 333-144868) that was declared effective by the SEC on April 29, 2008. Deutsche Bank Securities Inc., Citigroup Global Markets Inc. and UBS Securities LLC served as joint book-running managers for the underwriters in the initial public offering. 

 

Net proceeds to the Partnership from the sale of the common units were approximately $163.1 million, after underwriters' discounts and estimated offering expenses. The Partnership used the net proceeds of approximately $163.1 million from the initial public offering as follows:

 

 

 

After completion of the initial public offering and the exercise of the underwriters' over-allotment option, there are no additional common units available for sale under the registration statement on Form S-1.

 

 

 

Item 6. Exhibits

 

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.