**EXHIBIT 99.1**

 

**REPORT OF INDEPENDENT REGISTERED PUBLIC**

**ACCOUNTING FIRM**

 

To the Board of Directors of

Pioneer Natural Resources GP LLC:

 

We have audited the accompanying consolidated balance sheet of Pioneer Natural Resources GP LLC (the "Company") as of December 31, 2008. This balance sheet is the responsibility of the Company's management. Our responsibility is to express an opinion on this balance sheet based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our            audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting            principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the financial position of Pioneer Natural Resources GP LLC at December 31, 2008, in conformity with U.S. generally accepted accounting principles.

 

|   | Ernst & Young LLP |
|--------|----------------------------|

 

Dallas, Texas

March 5, 2009

 

 

----

 

 

**PIONEER NATURAL RESOURCES GP LLC**

 

**CONSOLIDATED BALANCE SHEET**

**(in thousands)**

 

 

|                                                                            |   |   | **December 31,****2008** |   |
|---------------------------------------------------------------------------------|--------|--------|--------------------------|--------|
| **ASSETS**                                                                      |   |
| Current assets:                                                                 |   |   |                     |   |
| Cash and cash equivalents                                                       |   | $      | 30,028                   |   |
| Accounts receivable                                                             |   |   | 10,965                   |   |
| Inventories                                                                     |   |   | 1,659                    |   |
| Prepaid expenses                                                                |   |   | 105                      |   |
| Derivatives                                                                     |   |   | 51,261                   |   |
| Total current assets                                                            |   |   | 94,018                   |   |
| Property, plant and equipment, at cost:                                         |   |   |                     |   |
| Oil and gas properties, using the successful efforts method of accounting:      |   |   |                     |   |
| Proved properties                                                               |   |   | 225,092                  |   |
| Accumulated depletion, depreciation and amortization                            |   |   | (83,335                  | )      |
| Total property, plant and equipment                                             |   |   | 141,757                  |   |
| Deferred income taxes                                                           |   |   | 235                      |   |
| Derivatives                                                                     |   |   | 65,804                   |   |
| Other, net                                                                      |   |   | 806                      |   |
|                                                                            |   | $      | 302,620                  |   |
|                                                                            |   |   |                     |   |
| **LIABILITIES AND OWNER'S NET EQUITY**                                          |   |
| Current liabilities:                                                            |   |   |                     |   |
| Accounts payable:                                                               |   |   |                     |   |
| Trade                                                                           |   | $      | 4,739                    |   |
| Due to affiliates                                                               |   |   | 5,928                    |   |
| Income taxes payable to affiliate                                               |   |   | 492                      |   |
| Deferred income taxes                                                           |   |   | 521                      |   |
| Asset retirement obligations                                                    |   |   | 23                       |   |
| Total current liabilities                                                       |   |   | 11,703                   |   |
|                                                                            |   |   |                     |   |
| Asset retirement obligations                                                    |   |   | 5,683                    |   |
| Minority interest                                                               |   |   | 44,524                   |   |
| Owner's equity:                                                                 |   |   |                     |   |
| Owner's net equity                                                              |   |   | 99,067                   |   |
| Accumulated other comprehensive income – deferred hedge gains, net of tax |   |   | 141,643                  |   |
| Total owner's net equity                                                        |   |   | 240,710                  |   |
| Commitments and contingencies                                                   |   |   |                     |   |
|                                                                            |   | $      | 302,620                  |   |

 

 

The accompanying notes are an integral part of this consolidated balance sheet.

1

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

 

| **NOTE A.** | **Organization and Nature of Operations** |
|-------------|-------------------------------------------|

 

Pioneer Natural Resources GP LLC, a Delaware limited liability company ("Pioneer GP" or the "General Partner"), was formed on June 19, 2007, to own a .1 percent general partner interest in Pioneer Southwest Energy Partners L.P., a Delaware limited partnership (the "Partnership"). The General Partner is a wholly-owned subsidiary of Pioneer Natural Resources USA, Inc. ("Pioneer            USA"), which is a wholly-owned subsidiary of Pioneer Natural Resources Company, a publicly traded Delaware corporation ("Pioneer"). As of December 31, 2008, Pioneer also owned 68.4 percent of the Partnership's outstanding limited partner common units.

 

The General Partner is deemed to control the Partnership because, under Delaware laws and the partnership agreement, the General Partner has the power to direct or cause the direction of the management and policies of the Partnership. As a result of this substantive control, the Partnership is fully consolidated and, therefore, the consolidated balance sheet includes all assets            and liabilities of the Partnership and its subsidiaries. The General Partner does not have any business other than holding its .1 percent general partner interest in the Partnership.

 

The Partnership was formed in June 2007 by Pioneer to own and acquire oil and gas assets in the Partnership's area of operations. The Partnership's area of operations consists of onshore Texas and eight counties in the southeast region of New Mexico. On May 6, 2008, the Partnership completed an initial public offering of 9,487,500 common units, representing limited partner            interests, at a per unit offering price of $19.00 (the "Offering"). Prior to the Offering, Pioneer owned all of the general and limited partner interests in the Partnership. Pioneer formed Pioneer Southwest Energy Partners USA LLC, a Texas limited liability company ("Pioneer Southwest USA"), to hold certain of the Partnership's oil and gas properties located in the Spraberry field in the Permian Basin of West Texas ("Spraberry field"). To effect the Offering, Pioneer (i) contributed            to the Partnership a portion of its interest in Pioneer Southwest USA for additional general and limited partner interests in the Partnership, (ii) sold to the Partnership its remaining interest in Pioneer Southwest USA for $141.1 million, (iii) sold incremental working interests in certain of the oil and gas properties owned by Pioneer Southwest USA to the Partnership for $22.0 million, which amount represented the net proceeds from the exercise by the underwriters of the            over-allotment option, and (iv) caused the General Partner to contribute $24 thousand to the Partnership to maintain the General Partner's 0.1 percent general partner interest in conjunction with the exercise of the underwriters' over-allotment option. As a result of the transactions described in (i) and (ii) above, Pioneer Southwest USA became a wholly-owned subsidiary of the Partnership. The transactions described in (i), (ii), (iii) and (iv) above represent transactions between            entities under common control. Consequently, the Partnership recorded the assets at Pioneer's carrying value. The oil and gas properties owned by Pioneer Southwest USA are referred to as the "Partnership Properties." Effective with the completion of the Offering on May 6, 2008, references herein to the Partnership are identifying Pioneer Southwest Energy Partners L.P. and its wholly-owned subsidiary, Pioneer Southwest USA.

 

| **NOTE B.** | **Summary of Significant Accounting Policies** |
|-------------|------------------------------------------------|

 

***Presentation.***   In accordance with Emerging Issues Task Force Issue No. 04-5,*“Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,”*the General            Partner consolidates the Partnership in its financial statements. The General Partner’s consolidated balance sheet includes the accounts of the General Partner and the Partnership, its controlled subsidiary. The public unitholders’ interest is reflected as "Minority interest" in the accompanying consolidated balance sheet. The General Partner elected to account for gains on the Partnership's issuance of common units as equity transactions as permitted by Staff Accounting            Bulletin ("SAB") Topic 5H, "Accounting for Sales of Stock by a Subsidiary". During 2008, the General Partner reclassified $132.6 million from "Minority interest" to "Owner's net equity" on the accompanying consolidated balance sheet to recognize the gain on the sale of the Partnership's common units in connection with the Offering.

 

The General Partner's consolidated balance sheet has been prepared in accordance with Regulation S-X, Article 3 "General instructions as to financial statements."

            

***Principles of consolidation.***The consolidated balance sheet of the General Partner includes the accounts of the General Partner and its subsidiaries. All material intercompany balances and transactions have been eliminated.

 

 

2

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

            As of December 31, 2008, minority interest in the accompanying consolidated balance sheet totaled $44.5 million and represents the unaffiliated limited partners' 31.6 percent ownership in the Partnership's net assets.  Pioneer USA's 68.3 percent ownership in the Partnership's net assets is included in the General Partner's owner's net            equity in the accompanying consolidated balance sheet.

 

***Use of estimates in the preparation of financial statements.***Preparation of the accompanying consolidated financial statement in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial            statements. Depletion of oil and gas properties and impairment of oil and gas properties, in part, is 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 oil and gas properties are subject to numerous uncertainties including, among others,            estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized.

 

***Cash equivalents.***  Cash and cash equivalents include cash on hand and depository and money market investment accounts held by banks.

 

        ***Inventories.***The General Partner's inventories consist of oil held in storage tanks and natural gas liquids ("NGLs") held in storage by the purchaser of the NGLs as of December 31, 2008. As of December 31, 2008, title and risk of loss of the NGL inventory had transferred to the purchaser. However, the sales price of the            NGLs will not be determined until the NGLs undergo further processing by the purchaser during the first quarter of 2009. In accordance with SAB Topic 13 "Revenue Recognition – Revised as of December 2003," the General Partner has deferred revenue recognition of the NGL sales as of December 31, 2008. The General Partner's oil and NGL inventories are carried at the lower of average cost or market, on a first-in, first-out basis. As of December 31, 2008, the General Partner's            inventories were net of $159 thousand of valuation reserve allowances.

 

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

 

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

 

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

 

In accordance with Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the General Partner reviews its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying            value of those assets may not be recoverable. If an impairment is indicated based on a comparison of the asset's carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent that the asset's carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserve and production information and pricing assumptions that management believes are reasonable. Any impairment charge incurred is            expensed and reduces the General Partner's recorded basis in the asset.

 

***Asset retirement obligations.***The General Partner 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.

 

 

3

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

 

***Derivatives and hedging.***The General Partner 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 General Partner 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 General Partner's policy is to assess hedge effectiveness at the end of each calendar quarter.

 

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

 

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

 

Effective February 1, 2009, the General Partner discontinued hedge accounting on all existing commodity derivative instruments, and from that date forward will account for derivative instruments using the mark-to-market accounting method. Therefore, the General Partner will recognize all future changes in the fair values of its derivative contracts as gains or losses in the            earnings of the period in which they occur.

 

See Notes C and G for a description of the specific types of derivative transactions in which the General Partner participates.

 

***Income taxes.***The General Partner is not a taxable entity for federal and state income tax purposes. The General Partner is included in the consolidated tax return of Pioneer and the tax on the General Partner's income is borne by Pioneer.

 

The Partnership's operations are treated as a partnership for federal and state income tax purposes with each partner being separately taxed on its share of the Partnership's taxable income. 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 sheet.

 

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

 

 

4

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

***Environmental.***The General Partner'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 December 31, 2008, the General Partner had no material environmental liabilities.

 

***New accounting pronouncements.***The following discussions provide information about new accounting pronouncements that have been issued by the Financial Accounting Standards Board ("FASB"):

 

***SFAS 157.***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"). FSP FAS 157-2 delayed the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis, but no less often than annually. On January 1, 2008, the General Partner adopted the            provisions of SFAS 157 for financial assets and liabilities. See Note C for additional information regarding the General Partner'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 General Partner.

 

***SFAS 159.***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 General Partner 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 General Partner.

 

***SFAS 141(R).***In December 2007, the FASB issued SFAS No. 141(R), "Business Combinations" ("SFAS 141(R)"). SFAS 141(R) replaces SFAS 141 and provides greater consistency in the accounting and financial reporting of business combinations. SFAS 141(R) requires the acquiring entity in a business combination to recognize all assets acquired and            liabilities assumed in the transaction and any noncontrolling interest in the acquired entity at the acquisition date, measured at their fair values as of the date that the acquirer achieves control over the business acquired. This includes the measurement of the acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the recognition of pre-acquisition contractual and certain non-contractual gain and loss contingencies, the            recognition of capitalized research and development costs and the recognition of changes in the acquirer's income tax valuation allowance and deferred taxes. The provisions of SFAS 141(R) also require that restructuring costs resulting from the business combination that the acquirer expects but is not required to incur and costs incurred to effect the acquisition be recognized separate from the business combination. SFAS 141(R) is effective for fiscal years and interim periods            within those fiscal years, beginning on or after December 15, 2008, and is to be applied prospectively as of the beginning of the fiscal year in which the statement is applied. SFAS 141(R) became effective for the General Partner on January 1, 2009. The implementation of SFAS 141(R) did not materially impact the financial condition or results of operations of the General Partner on the date of adoption.

 

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

 

***SFAS*** ***162.***In May 2008, the FASB issued SFAS No. 162 "The Hierarchy of Generally Accepted Accounting Principles" ("SFAS 162"). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements            presented in conformity with generally

 

5

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

accepted accounting principles in the United States ("GAAP"). SFAS 162 became effective for the General Partner on November 15, 2008. The adoption of SFAS 162 did not have a significant impact on the General Partner's financial statements.

 

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

 

| **NOTE C.** | **Disclosures About Fair Value of Financial Instruments** |
|-------------|-----------------------------------------------------------|

 

Effective January 1, 2008, the General Partner adopted the provisions of SFAS 157 for financial assets and liabilities. SFAS 157 retains the exchange price notion in the definition of fair value but clarifies that the exchange price is the price in an orderly transaction between market participants to sell an asset or transfer a liability in the principal or most advantageous            market in which the reporting company would transact for the asset or liability.

 

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

 

|   | **•** | Level 1 – quotedprices for identical assets or liabilities in active markets. |
|--------|------------|-------------------------------------------------------------------------------------|

|   | **•** | Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates); and inputs derived principally from or corroborated by observable market                            data by correlation or other means. |
|--------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

|   | **•** | Level 3 – unobservable inputs for the asset or liability. |
|--------|------------|-----------------------------------------------------------------|

 

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 General Partner's financial assets that are measured at fair value on a recurring basis as of December 31, 2008, for each of the fair value input            hierarchy levels:

 

|                           |   | **Fair Value Measurement at Reporting Date Using** |                 |   |   |            |
|--------------------------------|--------|----------------------------------------------------|----------------------|--------|--------|-----------------|
|                           |   |                                               | **Quoted Prices In** |   |   | **Significant** |   |   |   |   |   |   |   |
|                           |   |                                               | **Active Markets**   |   |   | **Other**       |   |   | **Significant** |   |   |   |   |
|                           |   |                                               | **for Identical**    |   |   | **Observable**  |   |   | **Unobservable** |   |   | **Fair Value at** |   |
|                           |   |                                               | **Assets**           |   |   | **Inputs**      |   |   | **Inputs** |   |   | **December 31,** |   |
|                           |   |                                               | **(Level 1)**        |   |   | **(Level 2)**   |   |   | **(Level 3)** |   |   | **2008** |   |
|                           |   | **(in thousands)**                                 |                 |
| **Assets:**                    |   |                                               |                 |   |   |            |   |   |   |   |   |   |   |
| Commodity derivative contracts |   | $                                                  | —              |   | $      | 103,237         |   | $ | 13,828 |   | $ | 117,065 |   |

 

|   | The General Partner was not a party to any financial liabilities as of December 31, 2008. |
|--------|-------------------------------------------------------------------------------------------|

 

 

 

6

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

 

The General Partner's commodity price derivative assets that were classified as Level 3 in the fair value hierarchy at December 31, 2008 represented NGL derivative contracts. The following table presents the changes in the fair values of the General Partner's commodity price derivative assets classified as Level 3 in the fair value hierarchy:

 

| **Fair Value Measurements Using Significant****Unobservable Inputs (Level 3)** |   | **Year Ended****December 31,****2008** |    |
|--------------------------------------------------------------------------------|--------|----------------------------------------|---------|
|                                                                           |   | **(in thousands)**                     |    |
| **Assets (liabilities):**                                                      |   |                                   |    |   |
| Beginning balance                                                              |   | $                                      | — |   |
| Novated derivatives                                                            |   |                                   | (3,134  | ) |
| Settlements                                                                    |   |                                   | 822     |   |
| Total gains (losses):                                                          |   |                                   |    |   |
| Included in earnings                                                           |   |                                   | (1,220  | ) |
| Included in other comprehensive income                                         |   |                                   | 17,360  |   |
|                                                                           |   |                                   |    |   |
| Ending balance                                                                 |   | $                                      | 13,828  |   |

 

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

 

*Oil derivatives.*The General Partner's oil derivatives are swap and collar contracts for notional barrels ("Bbls") of oil at fixed (in the case of swaps contracts) or interval (in the case of collar contracts) NYMEX West Texas Intermediate ("WTI") oil prices. Commodity price derivative asset values are determined, in part, by utilization of the            derivative counterparties' credit-adjusted risk-free rates and commodity price derivative liability values are determined, in part, by utilization of the Partnership's credit-adjusted risk-free rate. The counterparties' credit-adjusted risk-free rates are based on independent market-quoted credit default swap rate curves for the counterparties' debt plus the United States Treasury Bill yield curve as of December 31, 2008. The Partnership's credit-adjusted risk-free rate curve is            based on the Partnership's borrowing rate under its $300 million unsecured revolving credit facility (the "Credit Facility"), which matures in May 2013. The asset transfer values attributable to the General Partner's oil derivative instruments as of December 31, 2008 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) the applicable credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility            inherent in the collar contracts. The implied rates of volatility inherent in the General Partner'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 General Partner's NGL derivatives are swap contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs. The asset values attributable to the General Partner's NGL derivative instruments are based on (i) the contracted notional volumes, (ii) average independent broker-supplied forward Mont Belvieu-posted-price quotes and            (iii) the applicable credit-adjusted risk-free rate yield curve. NGL swap contracts are not as actively traded as oil and gas derivatives. Consequently, fair values determined on the basis of average independent broker-supplied forward Mont Belvieu-posted-price quotes may be less reliable than independent broker-supplied forward price quotes of more actively-traded commodities.

 

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

 

 

7

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

 

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

 

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

 

| **NOTE D.** | **Long-term Debt** |
|-------------|--------------------|

 

In May 2008, the Partnership entered into the Credit Facility. The Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions. Borrowings under the Credit Facility may be in the form of Eurodollar rate loans, base rate committed loans or swing line loans. Eurodollar rate loans bear interest annually at LIBOR,            plus a margin (the "Applicable Rate") (currently 0.875 percent) that is determined by a reference grid based on the Partnership's consolidated leverage ratio. Base rate committed loans bear interest annually at a base rate equal to the higher of (i) the Federal Funds Rate plus 0.5 percent or (ii) the Bank of America prime rate (the "Base Rate") plus a margin (currently zero percent). Swing line loans bear interest annually at the Base Rate plus the Applicable Rate. As of December            31, 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 consolidated leverage ratio (representing a ratio of consolidated indebtedness of the Partnership to consolidated earnings before depreciation, depletion and amortization; impairment of long-lived assets; exploration expense; accretion of discount on asset retirement            obligations; interest expense; income taxes; gain or loss on the disposal of assets; noncash commodity hedge related activity; and noncash equity-based compensation, "EBITDAX") of not more than 3.5 to 1.0, (ii) an interest coverage ratio (representing a ratio of EBITDAX to interest expense) of not less than 2.5 to 1.0 and (iii) the maintenance of a ratio of the net present value of the Partnership's projected future cash flows from its oil and gas assets to total debt of at least            1.75 to 1.0.

 

Because of the net present value covenant, borrowing capacity under the Credit Facility was limited to approximately $200 million as of December 31, 2008. The variables on which the calculation of net present value is based (including assumed commodity prices and discount rate) are subject to adjustment by the lenders. As a result, further declines in commodity prices could reduce            the Partnership's borrowing capacity under the Credit Facility. In addition, the Credit Facility contains various covenants that limit, among other things, the Partnership's ability to grant liens, incur additional indebtedness, engage in a merger, enter into transactions with affiliates, pay distributions or repurchase equity, and sell its assets. If any default or event of default (as defined in the Credit Facility) were to occur, the Credit Facility would prohibit the Partnership            from making distributions to unitholders. Such events of default include, among others, nonpayment of principal or interest, violations of covenants, bankruptcy and material judgments and liabilities.

 

| **NOTE E.** | **Related Party Transactions** |
|-------------|--------------------------------|

 

Set forth below are descriptions of certain agreements the Partnership entered into with related parties in connection with the Offering. The full text of the agreements have been filed by the Partnership as exhibits to filings with the SEC and are available for review without charge on the SEC's website at www.sec.gov.

 

Administrative Services Agreement 

 

Pursuant to an Administrative Services Agreement among Pioneer Natural Resources USA, Inc. ("Pioneer USA"), a wholly-owned subsidiary of Pioneer, the General Partner, Pioneer Southwest USA and the Partnership, entered into on May 6, 2008, Pioneer USA agreed to perform, either itself or through its affiliates or other third parties, administrative services for the Partnership, and            the Partnership agreed to reimburse Pioneer USA for its expenses incurred in providing such services. These administrative services may include accounting, internal audit, business development, finance, land, legal, engineering, investor relations, management, marketing, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. Initially, expenses will be reimbursed based on a methodology of determining the            Partnership's share, on a per BOE basis, of certain of the general and administrative costs incurred by Pioneer USA. Under this initial

 

 

8

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

 

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, the General Partner, 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 volumetric production payment obligation, as described in Note F below.

 

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's 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. As of December 31, 2008, the General Partner's            income taxes payable to affiliate balance in the accompanying consolidated balance sheet represents amounts due to Pioneer under the Tax Sharing Agreement.

 

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 the General Partner, 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.

 

 

9

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

 

2008 Long-Term Incentive Plan

 

The Board of Directors of the General Partner has adopted the Pioneer Southwest Energy Partners L.P. 2008 Long-Term Incentive Plan (the "LTIP") for directors, employees and consultants of the General Partner 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.

 

Indemnification Agreements 

 

Pursuant to Indemnification Agreements entered into with each of the independent directors of the General Partner, 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 the General Partner or is or was serving at the General Partner's request as a director, officer, employee or agent of another corporation or other entity if the indemnitee meets the standard of conduct provided in the Partnership Agreement. Also, as permitted under the Partnership Agreement, the indemnification            agreements require the Partnership to advance expenses in defending such an action provided that the director undertakes to repay the amounts if the person ultimately is determined not to be entitled to indemnification from the Partnership. The Partnership will also make the indemnitee whole for taxes imposed on the indemnification payments and for costs in any action to establish the indemnitee's right to indemnification, whether or not wholly successful.

 

In accordance with standard industry operating agreements and the agreements described above, the Partnership incurred the following charges from Pioneer during the period from May 6, 2008 through December 31, 2008:

 

|                                                                              |   | **From May 6,****2008 Through****December 31,****2008** |   |
|-----------------------------------------------------------------------------------|--------|---------------------------------------------------------|--------|
|                                                                              |   | **(in thousands)**                                      |   |
|                                                                              |   |                                                    |   |   |
| Producing well overhead (Council of Petroleum Accountants Society, or COPAS) fees |   | $                                                       | 5,476  |   |
| Payment of lease operating and supervision charges                                |   |                                                    | 3,977  |   |
| General and administrative expenses                                               |   |                                                    | 1,567  |   |
|                                                                              |   |                                                    |   |   |
| Total                                                                             |   | $                                                       | 11,020 |   |

 

As of December 31, 2008, the General Partner's accounts payable-affiliate balance in the accompanying consolidated balance sheet is comprised of approximately $6.0 million of unpaid COPAS fees, lease operating expenses and general and administrative expenses.

 

| **NOTE F.** | **Commitments and Contingencies** |
|-------------|-----------------------------------|

 

***Volumetric Production Payments.***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 requires the delivery of specified quantities of oil through December 2010. Pioneer's VPP agreement represents limited-term overriding royalty interests in oil 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.

 

 

10

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

 

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

 

| **NOTE G.** | **Derivative Financial Instruments** |
|-------------|--------------------------------------|

 

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

 

On May 6, 2008, novation agreements were entered into among Pioneer, the Partnership and certain derivative instrument counterparties, which transferred Pioneer's rights and responsibilities under certain derivative instruments to the Partnership. As of May 6, 2008, the aggregate fair value of the derivative instruments novated to the Partnership represented a liability of            approximately $37.2 million. Changes in the fair values of the derivative instruments subsequent to May 6, 2008, to the extent that they are effective as hedges of the designated commodity price risk, are being deferred and recognized in the Partnership's earnings in the same periods as the forecasted sales being hedged. During 2008, the Partnership settled derivatives which represented liabilities of $11.3 million on the date of novation.

 

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

 

|                 |   | **2009**           |   | **2010** |   |
|----------------------|--------|--------------------|--------|----------|--------|
|                 |   | **(in thousands)** |   |
|                 |   |               |   |
| Oil                  |   | $                  | 12,637 |     | $      | 8,528 |   |
| NGL                  |   |               | 1,364  |     |   | 948 |   |
| Gas                  |   |               | 1,746  |     |   | 684 |   |
|                 |   |               |   |     |   |   |   |
| Total novated hedges |   | $                  | 15,747 |     | $      | 10,160 |   |

 

 

 

11

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

 

         All derivatives are recorded on the balance sheet at estimated fair value. Fair value is determined in accordance with SFAS 157 and is generally determined based on the present value difference between the fixed contract price and the underlying market price at the determination date, and/or the value confirmed by the counterparty. Changes in the            fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income (loss), 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 changes in the fair value of 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 General Partner primarily utilizes commodity swap and collar contracts to (i) reduce the impact on the Partnership's net cash provided by operating activities from the price volatility of the commodities the Partnership produces and sells and (ii) help sustain unitholder distributions.

 

*Oil prices.*All material physical sales contracts governing the Partnership's oil production have been tied directly or indirectly to the New York Mercantile Exchange ("NYMEX") prices. The following table sets forth the volumes hedged in barrels ("Bbl") underlying the Partnership's outstanding oil hedge contracts and the weighted average NYMEX prices            per Bbl for those contracts as of December 31, 2008:

 

|                                |   | **Year Ended December 31,** |    |
|-------------------------------------|--------|-----------------------------|---------|
|                                |   | **2009**                    |    | **2010** |   | **2011** |   |
| **Oil Derivatives**                 |   |                        |    |   |   |   |   |
| Average daily notional Bbl volumes: |   |                        |    |   |   |   |   |
| Swap contracts:                     |   |                        |    |   |   |   |   |   |   |   |
| Volume (Bbl)                        |   |                        | 2,500   |   |   | 2,000 |   |   | — |   |
| Price per Bbl                       |   | $                           | 99.26   |   | $ | 98.32 |   | $ | — |   |
| Collar contracts:                   |   |                        |    |   |   |   |   |   |   |   |
| Volume (Bbl)                        |   |                        | — |   |   | — |   |   | 2,000 |   |
| Price per Bbl                       |   | $                           | — |   | $ | — |   | $ | 115.00-$170.00 |   |

 

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 settlements of oil price hedges on            oil revenue for the year ended December 31, 2008:

 

| Average price reported per Bbl                               |   | $ | 110.27 |   |
|--------------------------------------------------------------|--------|---|--------|--------|
| Average price realized per Bbl                               |   | $ | 99.78  |   |
| Increase to oil revenue from hedging activity (in thousands) |   | $ | 11,654 |   |

 

 

*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 derivative contracts and the weighted average Mont Belvieu prices per Bbl for those contracts at            December 31, 2008:

 

|                                |   | **Year Ended December 31,** |   |
|-------------------------------------|--------|-----------------------------|--------|
|                                |   | **2009**                    |   | **2010** |   |
| **NGL Derivatives**                 |   |                        |   |   |   |
| Average daily notional Bbl volumes: |   |                        |   |   |   |
| Swap contracts:                     |   |                        |   |   |   |   |   |
| Volume (Bbl)                        |   |                        | 750    |   |   | 750 |   |
| Price per Bbl                       |   | $                           | 53.80  |   | $ | 52.52 |   |

 

 

 

12

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

 

The Partnership reports average NGL prices per Bbl including the effects of NGL quality adjustments and the net effect of NGL hedges (for periods subsequent to the Offering). The following table sets forth (i) the Partnership's NGL prices, both reported (including hedge results) and realized (excluding hedge results) and (ii) the net effect of NGL price hedges on NGL revenue for            the year ended December 31, 2008:

 

| Average price reported per Bbl                               |   | $ | 48.81 |   |
|--------------------------------------------------------------|--------|---|-------|--------|
| Average price realized per Bbl                               |   | $ | 45.55 |   |
| Increase to NGL revenue from hedging activity (in thousands) |   | $ | 1,220 |   |

 

*Gas prices.*The General Partner employs a policy of hedging a portion of the Partnership's 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 million British thermal units ("MMBtu") under outstanding gas derivative contracts and the weighted average index prices per MMBtu for those contracts as of December 31, 2008:

 

|                                  |   | **Year Ended December 31,** |   |
|---------------------------------------|--------|-----------------------------|--------|
|                                  |   | **2009**                    |   | **2010** |   |
|                                  |   |                        |   |   |   |
| **Gas Derivatives**                   |   |                        |   |   |   |
| Average daily notional MMBtu volumes: |   |                        |   |   |   |
| Swap contracts:                       |   |                        |   |   |   |   |   |
| Volume (MMBtu)                        |   |                        | 2,500  |   |   | 2,500 |   |
| Price per MMBtu                       |   | $                           | 8.52   |   | $ | 8.14 |   |

 

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            settlements of gas price hedges on gas revenue for the year ended December 31, 2008:

 

| Average price reported per Mcf                               |   | $ | 7.30  |   |
|--------------------------------------------------------------|--------|---|-------|--------|
| Average price realized per Mcf                               |   | $ | 6.23  |   |
| Increase to gas revenue from hedging activity (in thousands) |   | $ | 1,767 |   |

 

***            Hedge ineffectiveness*****.**The General Partner recognizes ineffectiveness amounts when (i) hedged volumes that exceeded revised forecasts of production volumes and (ii) reduced correlations between the indexes of the financial hedge derivatives and the indexes of the hedged            forecasted production are not highly correlated. Ineffectiveness can be associated with closed contracts (i.e. realized) or can be associated with open positions (i.e. unrealized). The General Partner recorded $22 thousand of hedge ineffectiveness as a net charge to other expense associated with hedging activities for the year ended December 31, 2008. The General Partner did not enter into any derivative transactions prior to the Offering.

 

***AOCI - Hedging.***As of December 31, 2008, AOCI - Hedging represented net deferred gains of $143.0 million and an associated deferred tax provision of $1.4 million. The increase in AOCI – Hedging during the year ended December 31, 2008 was primarily due to decreases in future oil, NGL and gas prices relative to the commodity prices            stipulated in the hedge contracts and the reclassification of net deferred hedge losses to net income as derivatives matured during the period from May 6, 2008 through December 31, 2008. The net deferred gains associated with open cash flow hedges remain subject to market price fluctuations until the positions are either settled under the terms of the hedge contracts or terminated prior to settlement.

 

During the year ending December 31, 2009, based on current estimates of future commodity prices, the General Partner expects to reclassify $67.0 million of net deferred hedge gains from AOCI - Hedging to oil and gas revenues. The Partnership also expects to reclassify approximately $620 thousand of net deferred Texas Margin tax

 

 

13

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**NOTES TO CONSOLIDATED BALANCE SHEET**

 

 

provision associated with commodity hedges during the year ending December 31, 2009 from AOCI - Hedging to income tax provision.

 

Effective February 1, 2009, the General Partner discontinued hedge accounting on all existing commodity derivative instruments, and from that date forward will account for derivative instruments using the mark-to-market accounting method. The fair value of the effective portion of the derivative contracts on January 31, 2009 will be reflected in AOCI - Hedging and amortized to oil            and gas revenue over the remaining term of the derivative contract. Therefore, the General Partner will recognize all future changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

 

| **NOTE H.** | **Asset Retirement Obligations** |
|-------------|----------------------------------|

 

The General Partner's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The General Partner does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The General Partner has no assets that are legally restricted for purposes of            settling asset retirement obligations. The following table summarizes the General Partner's asset retirement obligation transactions during the year ended December 31, 2008 (in thousands):

 

| Beginning asset retirement obligations                      |   | $      | 1,600  |   |
|-------------------------------------------------------------|--------|--------|--------|--------|
| Net wells placed on production and changes in estimates (a) |   |   | 4,034  |   |
| Liabilities settled                                         |   |   | (46    | )      |
| Accretion of discount                                       |   |   | 118    |   |
|                                                        |   |   |   |   |
| Ending asset retirement obligation                          |   | $      | 5,706  |   |

 

_________

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

 

| **NOTE I.** | **Subsequent Events ** |
|-------------|-----------------------------|

 

***Derivative designations.***Effective February 1, 2009, the General Partner discontinued its application of hedge accounting to all commodity derivatives. As a result of this change, both realized and unrealized gains and losses on derivative instruments are recognized in earnings. Net derivative losses attributable to derivatives previously            subject to hedge accounting and residing in AOCI - Hedging will be reclassified to earnings in future periods as the economic transactions to which the derivatives relate affect earnings.

 

***Distribution declaration.***In January 2009, the Board of Directors of the General Partner declared a cash distribution of $0.50 per common unit for the period from October 1, 2008 to December 31, 2008. The distribution was paid on February 12, 2009 to unitholders of record at the close of business on February 6, 2009. Associated therewith, the            Partnership paid $15.0 million of aggregate distributions.

 

14

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**UNAUDITED SUPPLEMENTARY INFORMATION**

 

 

***Capitalized Costs***

 

|                                                      |   |   | **December 31,**   |   |
|-----------------------------------------------------------|--------|--------|--------------------|--------|
|                                                      |   |   | **2008**           |   |
|                                                      |   |   | **(in thousands)** |   |
| **Oil and gas properties:**                               |   |   |               |   |
| Proved properties                                         |   | $      | 225,092            |   |
| Less accumulated depletion, depreciation and amortization |   |   | (83,335            | )      |
| Net capitalized cost for oil and gas properties           |   | $      | 141,757            |   |

 

***Costs Incurred for Oil and Gas Producing Activities***

 

|                          |   |   | **Year Ended****December 31,** |   |
|-------------------------------|--------|--------|--------------------------------|--------|
|                          |   |   | **2008**                       |   |
|                          |   |   | **(in thousands)**             |   |
|                          |   |   |                           |   |
| Acquisition of carrying value |   | $      | 141,770                        |   |
| Development costs (a)         |   |   | 5,111                          |   |
| Total costs incurred          |   | $      | 146,881                        |   |

_________

| (a) | Includes $4.0 million increase of asset retirement obligations and excludes $1.0 million of development costs incurred prior to the Offering that are included in the acquisition of carrying value on May 6, 2008. |
|-----|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

***Reserve Quantity Information***

 

The estimates of the General Partner's proved reserves as of December 31, 2008 were based on evaluations prepared by Pioneer's engineers and audited by independent petroleum engineers. Reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with            no provision for price and cost escalations except by contractual arrangements. The reserve estimates as of December 31, 2008 and 2007 utilized respective oil prices of $44.14 and $95.75 per Bbl (reflecting adjustments for oil quality), respective NGL prices of $17.19 and $52.52 per Bbl, and respective gas prices of $4.41 and $6.12 per Mcf (reflecting adjustments for Btu content, gas processing and shrinkage).

 

Proved reserve quantity estimates are subject to 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. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of            subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The General Partner emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as            additional information becomes available in the future.

 

 

15

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**UNAUDITED SUPPLEMENTARY INFORMATION**

 

 

The following table provides a rollforward of total proved reserves for the years ended December 31, 2008 and 2007, as well as proved developed reserves. Oil and NGL volumes are expressed in MBbls, gas volumes are expressed in MMcf and total volumes are expressed in thousands of barrels of oil equivalent ("MBOE").

 

|                            |   | **Oil****(MBbls)** |   | **NGL****(MBbls)** |   | **Gas****(MMcf)** |   | **Total****(MBOE)** |    |
|---------------------------------|--------|--------------------|--------|--------------------|--------|-------------------|--------|---------------------|---------|
|                            |   |               |   |               |   |              |   |                |    |   |   |   |   |
| **Total Proved Reserves:**      |   |               |   |               |   |              |   |                |    |   |   |   |   |
| Balance, December 31, 2007      |   |               | 21,692 |               |   | 8,533             |   |                | 35,624  |   |   | 36,162 |   |
| Revisions on previous estimates |   |               | (6,932 | )                  |   | (2,841            | )      |                | (11,910 | ) |   | (11,758 | ) |
| Production                      |   |               | (1,111 | )                  |   | (374              | )      |                | (1,658  | ) |   | (1,761 | ) |
| Balance, December 31, 2008      |   |               | 13,649 |               |   | 5,318             |   |                | 22,056  |   |   | 22,643 |   |

 

 

| **Proved Developed Reserves:** |   |   |   |   |   |   |   |   |   |   |   |   |   |
|--------------------------------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|
| December 31:                   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| 2007                           |   |   | 21,692 |   |   | 8,533  |   |   | 35,624 |   |   | 36,162 |   |
| 2008                           |   |   | 13,649 |   |   | 5,318  |   |   | 22,056 |   |   | 22,643 |   |

 

**Standardized Measure of Discounted Future Net Cash Flows**

 

The standardized measure of discounted future net cash flows is computed by applying year-end commodity prices (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves,            discounted using a rate of ten percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and gas properties plus available carryforwards and credits and applying the current tax rates to the difference. The discounted future cash flow estimates do not include the effects of the General Partner's commodity derivative contracts. Utilizing December 31, 2008, commodity            prices held constant over each derivative contract's term, the net present value of the General Partner's derivative assets, less associated estimated income taxes and discounted at ten percent, was an asset of approximately $143 million at December 31, 2008.

 

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider probable reserves, anticipated future commodity prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other            considerations, any estimate of fair value is necessarily subjective and imprecise.

 

 

 

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**PIONEER NATURAL RESOURCES GP LLC**

 

**UNAUDITED SUPPLEMENTARY INFORMATION**

 

 

The following tables provide the standardized measure of discounted future cash flows as of December 31, 2008 and 2007, as well as a roll forward for the year:

 

|                                                    |   |   | **Year Ended****December 31,** |   |
|---------------------------------------------------------|--------|--------|--------------------------------|--------|
|                                                    |   |   | **2008**                       |   |
|                                                    |   |   | **(in thousands)**             |   |
| Oil and gas producing activities:                       |   |   |                           |   |
| Future cash inflows                                     |   | $      | 794,858                        |   |
| Future production costs                                 |   |   | (580,537                       | )      |
| Future development costs (a)                            |   |   | (7,496                         | )      |
| Future income tax expense                               |   |   | (179                           | )      |
|                                                    |   |   | 206,646                        |   |
| 10% annual discount factor                              |   |   | (84,750                        | )      |
| Standardized measure of discounted future netcash flows |   | $      | 121,896                        |   |

_________

| (a) | Includes $15.2 million ($7.5 million net of salvage value) of undiscounted future asset retirement expenditures estimated as of December 31, 2008, using current estimates of future abandonment costs. See Note H for corresponding information regarding the General Partner's discounted asset retirement obligations. |
|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

**Changes in Standardized Measure of Discounted Future Net Cash Flows**

 

|                                               |   |   | **Year Ended****December 31,** |   |
|----------------------------------------------------|--------|--------|--------------------------------|--------|
|                                               |   |   | **2008**                       |   |
|                                               |   |   | **(in thousands)**             |   |
|                                               |   |   |                           |   |
| Oil and gas sales, net of production costs         |   | $      | (94,990                        | )      |
| Net changes in prices and production costs         |   |   | (499,315                       | )      |
| Development costs incurred during the period       |   |   | —                        |   |
| Revisions of estimated future development costs    |   |   | (921                           | )      |
| Revisions of previous quantity estimates           |   |   | (46,673                        | )      |
| Accretion of discount                              |   |   | 68,814                         |   |
| Changes in production rates, timing and other      |   |   | 7,017                          |   |
| Change in present value of future net revenues     |   |   | (566,068                       | )      |
| Net change in present value of future income taxes |   |   | 6,313                          |   |
|                                               |   |   | (559,755                       | )      |
| Balance, beginning of year                         |   |   | 681,651                        |   |
| Balance, end of year                               |   | $      | 121,896                        |   |

 

 

 

 

 

 

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