EXHIBIT 99.2

 

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

In August 2009, the Partnership completed the 2009 Acquisition. Because the 2009 Acquisition represents a transaction between entities under common control, the Partnership’s historical financial information has been recast, similar to a pooling of interests, to include the financial position, results of operations and cash flows of the assets acquired and liabilities assumed in the 2009 Acquisition for all periods presented. The recast historical financial information presents the Partnership Properties as if they were owned by the Partnership for all periods owned by Pioneer. Accordingly, the following Management’s Discussion and Analysis of Financial Condition and Results of Operations has been recast from that presented in the Partnership’s 2008 Annual Report on Form 10-K.

The Partnership's Recast Financial Statements are included as Exhibit 99.3 to this Report that includes this recast Management’s Discussion and Analysis of Financial Condition and Results of Operations. The following discussion and analysis of the Partnership’s financial condition and results of operations should be read in conjunction with the Recast Financial Statements, including the accompanying notes and the unaudited supplementary information included therein.

 

Financial and Operating Performance

 

 

 

Historical Results of Operations

 

The financial statements and financial information for the years ended December 31, 2008, 2007 and 2006 reflect the operations of the Partnership combined with the Partnership Predecessor for all periods presented. The Partnership commenced operations on May 6, 2008 upon completion of the Offering and the related transactions.

 

The 2008 IPO Acquisitions and 2009 Acquisition represented reorganizations of entities under common control and are recorded at Pioneer’s carrying value. Accordingly, the Partnership’s Recast Financial Statements include the historical results of operations of the Partnership Predecessor.

 

Significant Events

 

August 2009 property acquisition. On August 31, 2009, Pioneer Southwest LLC completed the 2009 Acquisition of the 2009 Acquired Property Interests from Pioneer USA pursuant to a Purchase and Sale Agreement dated August 31, 2009 among Pioneer Southwest LLC, the Partnership and Pioneer USA. The effective date of the transaction was July 1, 2009. The 2009 Acquired Property Interests represent oil and gas properties located in the Spraberry field in the Permian Basin of West Texas.

 

Pioneer Southwest LLC paid $169.6 million in cash, including estimated customary closing adjustments, for the 2009 Acquired Property Interests and assumed net obligations associated with certain commodity price derivative positions and certain other liabilities that were assigned by Pioneer USA to Pioneer Southwest LLC. The Partnership funded the acquisition with $31.6 million of cash on hand and borrowings under the Partnership's Credit Facility.

 

Financial markets. During the second half of 2008, worldwide financial markets experienced significant turmoil as a result of a worldwide economic slowdown and a significant decline in the availability of liquidity provided by the financial markets. While these conditions continued through the first quarter of 2009, the availability of liquidity in the financial markets has seen some improvement since April of 2009. In response to the economic slowdown, governments worldwide have taken steps to enhance confidence and support the financial

 

markets. The success of the steps taken and the duration of the uncertainty in the financial markets cannot be predicted. The Partnership is closely monitoring the economic environment, including changes in energy demand and fluctuations in commodity prices, the impact of which is mitigated by the Partnership's derivative price risk activities. Depending on the severity and duration of the worldwide economic decline, these market conditions could negatively impact the Partnership’s liquidity, financial position and future results of operations. See Note H of Notes to the Recast Financial Statements included in Exhibit 99.3 to this Report for additional information about the Partnership's derivative contracts, and "Quantitative and Qualitative Disclosures About Market Risk" below, for information about the Partnership's commodity related derivative financial instruments.

 

As of December 31, 2008, the Partnership had $29.9 million of cash and cash equivalents on deposit, held approximately $12.6 million of accounts receivable related to oil, NGL and gas sales, was a party to derivative financial instruments, of which $117.1 million represent assets of the Partnership, had no outstanding long-term debt and had approximately $200 million of available borrowing capacity under the Credit Facility (the Partnership had approximately $135 million of available borrowing capacity under its Credit Facility after the completion of the purchase of the 2009 Acquired Property Interests in August 2009). The amount of liquidity under the Credit Facility is subject to a covenant requiring that the Partnership maintain a specified ratio of the net present value of the Partnership's projected future cash flows from its oil and gas assets to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. Therefore, the amount that the Partnership may borrow under the Credit Facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items. The Partnership is monitoring the liquidity and the credit standings of its counterparties, including its banks, derivative counterparties and purchasers of the commodities the Partnership produces and sells.

 

Commodity prices. The reduced liquidity provided by the worldwide financial markets and other factors have resulted in an economic slowdown in the United States and other industrialized countries, which has further resulted in significant reductions in worldwide energy demand. At the same time, North American gas supply has increased as a result of the rise in domestic unconventional gas production. The combination of lower demand due to the economic slowdown and higher North American gas supply resulted in significant declines in oil, NGL and gas prices during the second half of 2008 and the first half of 2009. During the first half of 2009, commodity prices increased modestly, but remained volatile. Although the Partnership has entered into derivative contracts on a large portion of its production volumes through 2013, a sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Partnership could enter into derivative contracts on additional volumes in the future. As a result, the Partnership's internal cash flows would be reduced for affected periods. The timing and magnitude of commodity price declines or recoveries cannot be predicted. A sustained decline in commodity prices could result in a shortfall in expected cash flows and require the Partnership to reduce its distributions. Additionally, a sustained decline in commodity prices could reduce the Partnership's borrowing capacity under its Credit Facility.

 

Hurricane Ike. During the second week of September 2008, Hurricane Ike struck the Texas gulf coast. The Partnership's Spraberry field production facilities were not directly impacted by the hurricane. However, third-party downstream production handling and processing facilities were damaged, which had the effect of delaying sales of portions of the Partnership's third quarter and fourth quarter 2008 NGL volumes and temporarily curtailing oil and gas production from certain of the Partnership's properties. As a result of the damage caused by the hurricane, fourth quarter production was negatively impacted by the loss of approximately 625 BOEPD of production. Production was fully restored in mid-November.

 

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

 

Novation of derivative agreements. On May 6, 2008, novation agreements were entered into among Pioneer, the Partnership and certain derivative instrument counterparties, which transferred Pioneer's rights and responsibilities under certain derivative instruments to the Partnership. The novated derivative agreements were designated as cash flow hedges of portions of the Partnership's oil, NGL and gas commodity price risk for forecasted sales for the periods from May 2008 through December 2008 and the years of 2009 and 2010. As of May 6, 2008, the aggregate fair value of the derivative instruments novated to the Partnership represented a liability of

 

 

approximately $37.2 million. Effective on February 1, 2009, the Partnership discontinued hedge accounting on all existing commodity derivative instruments, and from that date forward began accounting for derivative instruments using the mark-to-market accounting method. Changes in the fair values of the derivative instruments subsequent to May 6, 2008 through January 31, 2009, to the extent that they are effective as hedges of the designated commodity price risk, are being deferred and recognized in the Partnership's earnings in the same periods as the forecasted commodity sales being hedged. See Note H of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report and "Quantitative and Qualitative Disclosures About Market Risk" below, for additional information about the Partnership's commodity related derivative financial instruments.

 

2009 Outlook

 

Commodity prices. See "Commodity Prices," above for information about commodity prices and Note H of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report and "Quantitative and Qualitative Disclosures About Market Risk" below, for information regarding the Partnership's commodity related derivative financial instruments.

 

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

 

Drilling opportunities. The Partnership acquired undeveloped leasehold acreage in the 2009 Acquisition and has recently commenced a two-rig drilling program to develop its acreage. Based on current plans, the Partnership expects to drill 50 to 60 wells by the end of 2010.

 

Results of Operations

 

Oil and gas revenues. Oil and gas revenues totaled $193.4 million, $144.0 million and $126.9 million during 2008, 2007 and 2006, respectively. The revenue increase during 2008, as compared to 2007, was primarily due to increases in commodity prices, partially offset by a 10 percent decrease in average daily sales volumes, principally due to normal production declines and the curtailment of production during the third and fourth quarters as a result of damage done by Hurricane Ike to third-party fractionation facilities. The average reported oil price increased by 51 percent and the average reported NGL price increased by 29 percent. Average reported gas prices increased 42 percent. The revenue increase during 2007, as compared to 2006, was primarily reflective of an increase in reported oil, NGL and gas prices.

 

 

 

 

 

 

         The following table provides average reported prices, including the results of hedging activities, and average realized prices, excluding the results of hedging activities, for 2008, 2007 and 2006:

 

 

Derivative activities. The Partnership expects to utilize commodity swap and option contracts primarily to reduce the impact on the Partnership's net cash provided by operating activities from the price volatility of the commodities the Partnership produces and sells. Prior to the Offering, the Partnership had no derivative activities. On May 6, 2008, Pioneer novated oil, NGL and gas swap contracts to the Partnership that were designated as hedges of portions of the Partnership's forecasted May through December 2008, and annual 2009 and 2010 oil, NGL and gas sales. In addition to the novated hedges, the Partnership has entered into incremental 2009 and 2010 NGL swap contracts and an oil collar contract for a portion of the Partnership's forecasted 2011 oil sales. In connection with the 2009 Acquisition, 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 on August 31, 2009. See Note H of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report and "Quantitative and Qualitative Disclosures About Market Risk" below, for additional information about novated derivative agreements and the Partnership's commodity related derivative financial instruments.

 

Interest. The Partnership's interest income totaled $192 thousand during 2008. Prior to the Offering, the Partnership did not maintain cash balances and did not earn interest income.

 

Oil and gas production costs. The Partnership's oil and gas production costs totaled $38.8 million, $27.9 million and $24.1 million during 2008, 2007 and 2006, respectively. Total production costs per BOE increased during 2008 by 55 percent as compared to 2007 primarily due to (i) declines in volumes over which the fixed portion of production costs per BOE are attributed, which declines were due to normal production declines and to production declines related to facilities damage caused by Hurricane Ike (ii) increases in lease operating expense due to increased electricity costs, salt water disposal fees and oilfield well servicing activity and general oilfield services price inflation and (iii) increases in workover costs incurred to maximize production volumes as wells mature.

 

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 Predecessor. In May 2008, Pioneer, as operator, began charging the Partnership COPAS Fees associated with operating the properties owned by the Partnership, 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, $2.63 and $2.54 for 2008, 2007 and 2006, respectively.

 

Total production costs per BOE increased during 2007 by 13 percent as compared to 2006 primarily due to (i) increases in oilfield services and utility costs, primarily associated with general price inflation and rising commodity prices, and (ii) increases in workover costs.

 

 

         The following table provides the components of the Partnership's production costs per BOE for 2008, 2007 and 2006:

 

Production and ad valorem taxes. The Partnership recorded production and ad valorem taxes of $14.2 million, $11.5 million and $11.1 million during 2008 2007 and 2006, respectively. The increase for the current year were primarily attributable to higher production taxes associated with higher commodity prices.

 

The following table provides the components of the Partnership's total production and ad valorem taxes per BOE for 2008, 2007 and 2006:

 

Depletion, depreciation and amortization expense. The Partnership's depletion expense was $5.10, $4.50 and $3.89 per BOE for 2008, 2007 and 2006, respectively. During 2008, the increase in per BOE depletion expense was primarily due to negative price revisions to proved reserves during the fourth quarter as a result of lower year-end commodity prices.

 

During 2007, the increase in per BOE depletion expense was primarily due to a generally increasing trend in the Partnership's oil and gas properties' cost bases per BOE of proved reserves as a result of cost inflation in drilling rig rates and drilling supplies.

 

General and administrative expense. General and administrative expense totaled $6.2 million, $5.6 million and $5.3 million during 2008, 2007 and 2006, respectively. The increase in general and administrative expense during 2008, as compared to 2007, was primarily due to legal, accounting and other costs associated with being a public company that were not necessary prior to the Offering. The Partnership Predecessor’s general and administrative expense consisted of an allocation of a portion of Pioneer's general and administrative expense based on the Partnership Predecessor's production as compared to Pioneer's total production from its United States properties (other than Alaska), as measured on a per-barrel-of-oil-equivalent basis. The Partnership and Pioneer entered into an Administrative Services Agreement as of May 6, 2008, pursuant to which Pioneer agreed to perform, either itself or through its affiliates or other third parties, administrative services for the Partnership, and the Partnership agreed to reimburse Pioneer for its expenses incurred in providing such services. Pioneer has informed the Partnership that expenses will be reimbursed based on a methodology of determining the Partnership's share, on a per BOE basis, of certain of the general and administrative costs incurred by Pioneer. Subsequent to the Offering, the Partnership is also responsible for paying for direct third-party services. See Note E of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report, for additional information regarding the general and administrative expense allocations to the Partnership.

 

Interest expense. Interest expense was $621 thousand during 2008. The Partnership’s interest expense related primarily to fees associated with the Partnership’s Credit Facility that became effective with the Offering. Prior to the Offering, the Partnership had no outstanding debt or credit facility in place. On August 31, 2009, the Partnership borrowed $138.0 million under the Credit Facility in partial funding of the cash consideration associated with the 2009 Acquisition. The Partnership’s 2009 interest expense will increase as a result of this increase in indebtedness. See Note D of Notes to Consolidated Financial Statements included in "Financial Statements and Supplementary Data", included in Exhibit 99.3 to this Report, for additional information about the Partnership's long-term debt and interest expense.

 

Other expenses. Other expenses were $890 thousand during 2008, as compared to $5 thousand during 2007 and $25 thousand during 2006. The increase in other expense during 2008, as compared to 2007, is primarily

 

 

attributable to the professional costs associated with the Partnership’s evaluation of the potential assignment by Pioneer to the Partnership of Pioneer’s option to acquire an incremental interest in the Midkiff-Benedum gas processing plant.

 

Income tax provision. The Partnership recognized income tax provisions of $1.3 million, $920 thousand and $323 thousand during 2008, 2007 and 2006, respectively. The Partnership's effective tax is approximately one percent, reflective of the Texas Margin tax. See "Critical Accounting Estimates" below and Note L of Notes to Consolidated Financial Statements included in "Financial Statements and Supplementary Data", included in Exhibit 99.3 to this Report, for additional information regarding the Partnership's tax position.

 

Capital Commitments, Capital Resources and Liquidity

 

Capital commitments. The Partnership's primary needs for cash will be for production growth through drilling initiatives, acquisitions and/or production enhancements and for unitholder distributions. The Partnership may use any combination of internally- and externally-financed sources to fund acquisitions and unitholder distributions, including borrowings under its Credit Facility and funds from future private and public equity and debt offerings. In conjunction with the 2009 Acquisition, the Partnership has recently commenced a two-rig drilling program to drill 50 to 60 wells by the end of 2010, and expects to invest approximately $60 million to develop a portion of the proved undeveloped reserves acquired. The Partnership expects to fund the 2009 and 2010 drilling programs primarily from internal operating cash flows and, to a lesser extent, from borrowings under the Credit Facility. As a result of the current circumstances in worldwide financial markets, the availability of external sources of short- and long-term capital funding is uncertain. Although the Partnership expects that internal cash flows and available borrowing capacity under its Credit Facility will be adequate to fund capital expenditures and planned unitholder distributions, no assurances can be given that such funding sources will be adequate to meet the Partnership's future needs.

 

The Partnership Agreement requires that the Partnership distribute all of its available cash to its partners. In general, available cash is defined to mean cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves for future capital expenditures (including acquisitions), operational needs and distributions for any one or more of the next four quarters. Because the Partnership's proved reserves and production decline continually over time, the Partnership will need to mitigate the declines through drilling initiatives, production enhancement, and/or acquisitions of income producing assets that provide cash margins that allow the Partnership to sustain its level of distributions to unitholders over time. Currently, the Partnership is reserving approximately 25 percent of its cash flow to fund drilling activities in order to maintain its production and cash flow. The Partnership has adopted a cash distribution policy pursuant to which it intends to declare distributions of $0.50 per unit per quarter, or $2.00 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter. The distribution for the second quarter of 2009 of $0.50 per unit was declared by the Board of Directors of the General Partner and was paid on August 12, 2009 to unitholders of record on August 4, 2009. The distribution for the third quarter of 2009 of $0.50 per unit was declared by the Board of Directors of the General Partner and is to be paid on November 12, 2009 to unitholders of record on November 5, 2009.

 

Oil and gas properties. Excluding the 2008 IPO Acquisitions with the net proceeds from the Offering, the Partnership's cash expenditures for additions to oil and gas properties during 2008, 2007 and 2006 totaled $15.6 million, $18.6 million and $42.9 million, respectively. The Partnership's expenditures for additions to oil and gas properties for 2008, 2007 and 2006 were funded by net cash provided by operations.

 

Contractual obligations, including off-balance sheet obligations. As of December 31, 2008, the Partnership's contractual obligations were limited to asset retirement obligations, derivative instruments and contingent VPP obligations. As of December 31, 2008, the Partnership’s derivative instruments represented assets of $117.1 million; however, they continue to have market risk and represent contractual obligations of the Partnership. In connection with the 2009 Acquisition, the Partnership borrowed $138.0 million under its Credit Facility and was assigned derivative instruments representing net liabilities of approximately $5.2 million. See Note H of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report and "Quantitative and Qualitative Disclosures About Market Risk" above, for additional information regarding the Partnership’s derivative instruments. As of December 31, 2008, the Partnership's asset retirement obligations had increased approximately $4.4 million from December 31, 2007, reflecting that lower year-end commodity prices being used to calculate proved reserves at December 31, 2008 had the effect of shortening the economic life of many wells thus increasing the present value of future retirement obligations. As of December 31, 2008, the Partnership was not a party to any material off-balance sheet arrangements.

 

 

A substantial portion 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. 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 either (i) 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 or (ii) deliver to the Partnership volumes equal to the volumes delivered pursuant to the VPP obligation. Accordingly, the VPP obligation is not expected to affect the liquidity of the Partnership. If Pioneer were to default in its obligation with respect to the Partnership's volumes delivered pursuant to the VPP obligation, the decrease in the Partnership's production would result in a decrease in the Partnership's cash available for distribution.

 

The following table summarizes by period the payments due by the Partnership for contractual obligations estimated as of December 31, 2008:

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(a) The Partnership's other liabilities represent current and noncurrent other liabilities that are comprised of asset retirement obligations for which neither the ultimate settlement amounts nor their timings can be precisely determined in advance.

 

Capital resources. The Partnership's primary capital resources are expected to be net cash provided by operating activities, amounts available under its Credit Facility and, to the extent available, funds from future private and public equity and debt offerings. For 2009, the Partnership currently expects that cash flow from operations will be sufficient to fund the Partnership's capital expenditures and planned unitholder distributions, and that available borrowing capacity under its Credit Facility will provide adequate liquidity to fund acquisitions.

 

Operating activities.Net cash provided by operating activities during 2008, 2007 and 2006 was $132.5 million, $94.0 million and $87.1 million, respectively. The increase in net cash provided by operating activities in 2008, as compared to that of 2007, was primarily due to increased oil, NGL and gas sales prices, partially offset by declines in sales volumes and increased production costs. The decrease in net cash provided by operating activities in 2007, as compared to that of 2006, was primarily due to an increase in working capital.

 

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

 

Investing activities.Net cash used in investing activities during 2008 was $157.9 million, as compared to $18.6 million during 2007 and $42.9 million during 2006. The increase in net cash used in investing activities during 2008 as compared to 2007 is primarily due to the acquisition of Pioneer’s carrying value in the properties included in the 2008 IPO Acquisitions. Future investing activities will include expenditures to drill proved undeveloped well locations acquired with the 2009 Acquired Property Interests. Currently, a two-rig drilling program is expected to commence in the fourth quarter of 2009. The decrease in net cash used by investing activities during 2007, as compared to 2006, was primarily due to a reduction in development drilling operations during 2007.

 

Financing activities.Net cash provided by financing activities for 2008 was $55.4 million, as compared to net cash used in financing activities of $75.4 million for 2007 and $44.2 million during 2006. The increase in net cash provided by financing activities during 2008, as compared to 2007, was due primarily to proceeds received from the Offering, partially offset by the 2008 IPO Acquisition purchase price in excess of Pioneer’s carrying value and a decrease in aggregate distributions to the Partnership's owner and partners. The Partnership's financing activities for periods prior to the Offering were limited to distributions of cash to Pioneer.

 

 

During 2008, the Partnership paid cash distributions to unitholders of $24.3 million ($0.81 per unit). Future distributions and the timing and amount thereof are at the discretion of the Board of Directors of the General Partner. See "Capital commitments" for information about the Partnership’s cash distributions paid during 2009.

 

Liquidity. The Partnership's principal source of short-term liquidity has been cash generated from its operations. In connection with the Offering, the Partnership entered into the Credit Facility. As of December 31, 2008, the Partnership had approximately $200 million of available borrowing capacity under the Credit Facility. During August 2009, the Partnership borrowed $138.0 million under the Credit Facility and had approximately $135 million of remaining borrowing capacity under the Credit Facility after completing the 2009 Acquisition. The Partnership's borrowing capacity under the Credit Facility is subject to a covenant requiring that the Partnership maintain a specified ratio of the net present value of the Partnership's projected future cash flows from its oil and gas assets to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. As a result, declines in commodity prices could reduce the Partnership's borrowing capacity under the facility and could reduce its distributions to unitholders. See Note D of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report for more information regarding the Partnership's Credit Facility.

 

The Partnership expects that its primary sources of liquidity will be cash generated from operations, amounts available under the Credit Facility and, to the extent available, funds from future private and public equity and debt offerings. As discussed above under "Capital commitments," the Partnership Agreement requires that the Partnership distribute all of its available cash to its unitholders and the General Partner. In addition, because the Partnership's proved reserves and production decline continually over time, the Partnership will need to replace production to sustain its level of distributions to unitholders over time. Accordingly, the Partnership's primary needs for cash will be for production growth through drilling initiatives (such as the two-rig drilling program announced in conjunction with the 2009 Acquisition), acquisitions, production enhancements and for distributions to partners. In making cash distributions, the General Partner will attempt to avoid large variations in the amount the Partnership distributes from quarter to quarter. The Partnership Agreement permits the General Partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters, and for the conduct of the Partnership's business, which includes possible acquisitions. A sustained decline in commodity prices could result in a shortfall in expected cash flows. If cash flow from operations does not meet the Partnership's expectations, the Partnership may reduce its level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of its capital expenditures using borrowings under the Credit Facility, issuances of debt or equity securities or from other sources, such as asset sales or reduced distributions. The Partnership cannot provide any assurance that needed capital will be available on acceptable terms or at all.

 

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

 

Critical Accounting Estimates

 

The Partnership prepares its consolidated financial statements for inclusion in this Report in accordance with GAAP. See Note B of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report, for a comprehensive discussion of the Partnership's significant accounting policies. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of the Partnership's most critical accounting estimates, judgments and uncertainties that are inherent in the Partnership's application of GAAP.

 

Derivative assets. The Partnership is a party to derivative contracts that represent material assets as of December 31, 2008. In accordance with GAAP, the Partnership records its derivative assets and liabilities at their estimated fair values, the determination of which requires management to make judgments and estimates about

 

 

observable and unobservable inputs such as forward commodity prices, credit-adjusted interest rates and volatility factors. See Notes C and H of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report and "Quantitative and Qualitative Disclosures About Market Risk" below, for additional information regarding the Partnership’s derivative instruments.

 

Asset retirement obligations. The Partnership has significant obligations to remove tangible equipment and facilities and to restore the land at the end of oil and gas production operations. The Partnership's removal and restoration obligations are primarily associated with plugging and abandoning wells operated by Pioneer. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

 

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is generally made to the oil and gas property balance. See Notes B and J of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report for additional information regarding the Partnership's asset retirement obligations.

 

Successful efforts method of accounting. The Partnership utilizes the successful efforts method of accounting for oil and gas properties as opposed to the alternatively acceptable full cost method. The critical difference between the successful efforts method of accounting and the full cost method is as follows: under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of depletion expense. Historically, the Partnership has not had any exploratory drilling activities or incurred geological and geophysical costs, and therefore the financial results utilizing the successful efforts method did not significantly differ from that of the full cost method. However, in the future, if the Partnership drills unsuccessful exploratory wells or incurs geological and geophysical costs, these activities will negatively impact its future financial results.

 

Proved reserve estimates. Estimates of the Partnership's proved reserves included in this Report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

 

 

The Partnership's proved reserve information included in this Report as of December 31, 2008, 2007 and 2006 were prepared by Pioneer's reservoir engineers and, except for reserves associated with the 2009 Acquired Property Interests and incremental 2007 and 2006 reserves associated with the Over-allotment Property Interests, were audited by independent petroleum engineers. Estimates prepared by third parties may be higher or lower than those included herein.

 

Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.

 

It should not be assumed that the Standardized Measure as of December 31, 2008 included in the Unaudited Supplementary Information included in "Financial Statements and Supplementary Data", included in Exhibit 99.3 to this Report, is the current market value of the Partnership's estimated proved reserves. In accordance with SEC requirements, the Partnership based the Standardized Measure on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. See "Item 1A. Risk Factors" in the Partnership’s 2008 Annual Report on Form 10-K for additional information regarding estimates of proved reserves.

 

 

The Partnership's estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which the Partnership records depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of the Partnership's assessment of its proved properties for impairment.

 

Impairment of proved oil and gas properties. The Partnership reviews its proved properties to be held and used whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon its outlook of future commodity prices and net cash flows that may be generated by the properties and if a significant downward revision has occurred to the estimated proved reserves. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated.

 

New Accounting Pronouncements

 

In September 2006, the FASB issued SFAS 157. SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. In February 2008, the FASB issued FSP FAS 157-2. FSP FAS 157-2 delayed the effective date of SFAS 157 for nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008, except for items that were recognized or disclosed at fair value in the financial statements on a recurring basis at least annually. On January 1, 2008, the Partnership adopted the provisions of SFAS 157 as they pertain to financial assets and liabilities. See Note C of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report for additional information regarding the Partnership's adoption of SFAS 157. On January 1, 2009, the Partnership adopted the provisions of SFAS 157 that were delayed by FSP FAS 157-2.

 

In December 2007, the FASB issued SFAS 141(R). SFAS 141(R) replaced SFAS 141 and provides greater consistency in the accounting and financial reporting of business combinations. SFAS 141(R) requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction and any noncontrolling interest in the acquired entity at the acquisition date, measured at their fair values as of the date that the acquirer achieves control over the business acquired. This includes the measurement of the acquirer unit or shares issued in consideration for a business combination, the recognition of contingent consideration, the recognition of pre-acquisition contractual and certain non-contractual gain and loss contingencies, the recognition of capitalized research and development costs and the recognition of changes in the acquirer's income tax valuation allowance and deferred taxes. The provisions of SFAS 141(R) also require that restructuring costs resulting from the business combination that the acquirer expects but is not required to incur and costs incurred to effect the acquisition be recognized separate from the business combination. The Partnership became subject to the provisions of SFAS 141(R) on January 1, 2009.

 

In March 2008, the FASB issued SFAS 161. SFAS 161 changed the disclosure requirements for derivative instruments and hedging activities by requiring entities to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance and cash flows. The Partnership adopted the provisions of SFAS 161 on January 1, 2009.

 

In May 2008, the FASB issued SFAS 162. SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements presented in conformity with GAAP. SFAS 162 became effective for the Partnership on November 15, 2008. The adoption of SFAS 162 did not have a significant impact on the Partnership's financial statements.

 

In June 2008, the FASB issued FSP EITF 03-6-1 which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the net income (loss) allocation in computing basic net income (loss) per unit under the two-class method prescribed under SFAS 128. The Partnership adopted the provisions of FSP EITF 03-6-1 on January 1, 2009. All share-based payments of the Partnership’s common units represent grants of outstanding common units by the General Partner. Consequently, the Partnership has no participating share-based payments under the provisions of FSP EITF 03-6-1.

 

In December 2008, the SEC released the Reserve Ruling. The Reserve Ruling revises oil and gas reporting disclosures. The Reserve Ruling also permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The

 

 

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

 

In April 2009, the FASB issued FSP FAS 107-1, which amends FASB Statement No. 107, "Disclosures about Fair Value of Financial Instruments" and Accounting Principles Board Opinion No. 28, "Interim Financial Reporting". FSP FAS 107-1 requires fair value disclosures by publicly traded companies of financial instruments for interim reporting purposes. The Partnership adopted FSP FAS 107-1 in the first half of 2009. See Note C of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report for disclosures about the fair values of the Partnership's financial instruments.

 

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

 

In May 2009, the FASB issued SFAS 165. SFAS 165 provides additional guidelines for disclosing subsequent events in an issuer's financial statements and further requires an issuer to disclose a finite time period for which the company has evaluated subsequent events. SFAS 165 was adopted by the Partnership during the first half of 2009 and did not have a significant impact on the Partnership's recognition or disclosure of subsequent events.

 

In June 2009, the FASB issued SFAS 168. SFAS 168 replaces SFAS 162 and identifies the sources of accounting guidance and the framework for selecting the principles to be used in the preparation of financial statements presented in conformity with GAAP. On the effective date of SFAS 168, the codification prescribed in SFAS 168 will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in SFAS 168 will become non-authoritative. SFAS 168 is effective for interim and annual reporting periods ending after September 15, 2009 and is not expected to have a material impact on the Partnership's financial statements.

 

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

The following quantitative and qualitative information is provided about financial instruments to which the Partnership was a party as of December 31, 2008 and 2007, and from which the Partnership may incur future gains or losses from changes in commodity prices.

 

The fair value of the Partnership's derivative contracts is determined based on valuation models that are validated by counterparties' estimates. The Partnership did not change its valuation method during 2008. During 2008, the Partnership was a party to commodity swap and collar contracts. See Note H of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report for additional information regarding the Partnership's derivative contracts. The following table reconciles the changes that occurred in the fair values of the Partnership's open derivative contracts during 2008 (in thousands):

 

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Effective February 1, 2009, the Partnership 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 Partnership will recognize all future changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

 

Associated with the purchase of the 2009 Acquisition, Pioneer assigned certain commodity derivative contracts to the Partnership on August 31, 2009. The assigned derivative instruments represented a net liability of $5.2 million on August 31, 2009. See the footnotes to the tabular disclosures in "Quantitative Disclosures" for information regarding the assigned derivative contracts.

 

Quantitative Disclosures

 

Commodity price sensitivity. The following tables provide information about the Partnership's oil and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of December 31, 2008. As of December 31, 2008, all of the Partnership's oil, NGL and gas derivative financial instruments qualified as hedges.

 

Commodity derivative instruments. The Partnership uses derivative contracts, such as swap and collar contracts, to reduce the impact on the Partnership's net cash provided by operating activities from the price volatility of the commodities the Partnership produces and sells. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum ("floor") and maximum ("ceiling") prices for the Partnership on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price.

 

See Notes B, C and H of Notes to Recast Financial Statements included in Exhibit 99.3 to this Report for a description of the accounting procedures followed by the Partnership relative to its derivative financial instruments and for specific information regarding the terms of the Partnership's derivative financial instruments that are sensitive to changes in oil, NGL or gas prices.

 

 

 

Oil Price Sensitivity

Derivative Financial Instruments as of December 31, 2008

______

 

NGL Price Sensitivity

Derivative Financial Instruments as of December 31, 2008

_______

 

 

Gas Price Sensitivity

Derivative Financial Instruments as of December 31, 2008

 

______

 

 

Qualitative Disclosures

 

Derivative instruments. The Partnership utilizes commodity price derivative contracts to reduce the impact on the Partnership's net cash provided by operating activities from the price volatility of the commodities the Partnership produces and sells in accordance with policies and guidelines approved by the Board of Directors of the General Partner. In accordance with those policies and guidelines, the Partnership's management determines the appropriate timing and extent of derivative transactions.