UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

 

Commission File Number: 001-34032

Pioneer Southwest Energy Partners L.P.

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code: (972) 444-9001

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

Securities registered pursuant to Section 12(g) of the Act: None

 

 

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

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

 

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

 

 

 

 

Documents Incorporated by Reference:

 

None.

 

 

 

 

 

 

Cautionary Statement Concerning Forward-Looking Statements

 

Parts I and II of this annual report on Form 10-K (the "Report") contain forward-looking statements that involve risks and uncertainties. When used in this document, the words "believes," "plans," "expects," "anticipates," "intends," "continue," "may," "will," "could," "should," "future," "potential," "estimate," or the negative of such terms and similar expressions as they relate to Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest" or the "Partnership") are intended to identify forward-looking statements. The forward-looking statements are based on the Partnership's current expectations, assumptions, estimates and projections about the Partnership and the industry in which the Partnership operates. Although the Partnership believes that the expectations and assumptions reflected in the forward-looking statements are reasonable, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Partnership's control. In addition, the Partnership may be subject to currently unforeseen risks that may have a materiel adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See "Item 1. Business — Competition, Markets and Regulations," "Item 1A. Risk Factors" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for a description of various factors that could materially affect the ability of the Partnership to achieve the anticipated results described in the forward-looking statements. The Partnership undertakes no duty to publicly update these statements except as required by law.

 

 

Definitions of Certain Terms and Conventions Used Herein

 

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

 

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

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

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

 

 

 

 

PART I

 

 

General

 

Pioneer Southwest is a Delaware limited partnership that was formed in June 2007 by Pioneer Natural Resources Company (together with its subsidiaries, "Pioneer") to own and acquire oil and gas assets in the Partnership's area of operations. The Partnership's area of operations consists of onshore Texas and eight counties in the southeast region of New Mexico.

 

In May 2008, the Partnership completed its initial public offering of 9,487,500 common units representing limited partner interests (the "Offering"). Prior to the Offering, Pioneer owned all of the general and limited partner interests in the Partnership. To effect the Offering, the following transactions occurred either prior to or in conjunction with the Offering:

 

 

As a result, Pioneer Southwest USA became a wholly-owned subsidiary of the Partnership and owns all of the Partnership’s oil and gas properties. The oil and gas properties formerly owned by Pioneer and now owned by Pioneer Southwest USA are referred to in this Report as the "Partnership Properties." See Note A of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Offering.

 

The Partnership's only operating segment is oil and gas producing activities. Additionally, all of the Partnership Properties are located in the United States and all of the related oil, NGL and gas revenues are derived from purchasers located in the United States.

 

The Partnership’s executive offices are located at 5205 N. O’Connor Blvd., Suite 200, Irving, Texas 75039. The Partnership’s telephone number is (972) 969-3586. Pioneer Natural Resources GP LLC (the "General Partner"), a subsidiary of Pioneer, is the Partnership’s general partner and manages its operations and activities. Neither the Partnership, its operating subsidiary nor the General Partner has employees. The Partnership, the General Partner and Pioneer have entered into an administrative services agreement pursuant to which Pioneer manages all of the Partnership’s assets and performs administrative services for the Partnership. As of December 31, 2008, Pioneer had approximately 1,800 full time employees, approximately 357 of whom are dedicated to operating the Spraberry field. None of these employees are represented by labor unions or covered by any collective bargaining agreement. Pioneer believes that relations with these employees are satisfactory.

 

Available Information

 

The Partnership files or furnishes annual, quarterly and current reports and other documents with the SEC under the Securities Exchange Act of 1934 (the "Exchange Act"). The public may read and copy any materials that the Partnership files with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including the Partnership, that file electronically with the SEC. The public can obtain any documents that the Partnership files with the SEC at http://www.sec.gov.

 

The Partnership also makes available free of charge through its internet website (www.pioneersouthwest.com) its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after it electronically files such material with, or furnishes it to, the SEC.

 

 

Business Strategy

 

The Partnership’s primary business objective is to maintain quarterly cash distributions to its unitholders at its initial distribution rate and, over time, to increase its quarterly cash distributions. Because the Partnership does not own any undeveloped properties or leasehold acreage, its reserves and production are expected to decline continually over time unless the Partnership acquires additional income producing assets to replace its declining production or mitigates the declines through production enhancement or drilling initiatives. The Partnership expects to reserve approximately 25 percent of its cash flow to acquire income producing assets or drill downspaced locations in order to maintain its production and proved reserves.

 

The Partnership’s strategy for achieving its objective to maintain, and increase over time, its cash distributions to unitholders is to:

 

 

 

 

 

 

 

 

In the future, the Partnership may also expand its operations to include ownership of undeveloped properties.

 

Relationship with Pioneer

 

The Partnership believes that one of its principal strengths is its relationship with Pioneer, which owns the General Partner and common units representing a 68.3 percent limited partner interest in the Partnership. Pioneer is a large independent oil and gas exploration and production company with current operations in the United States and Africa. Pioneer’s proved reserves at December 31, 2008, including the Partnership’s properties, were 960 MMBOE, of which 477 MMBOE, or 50 percent, were in the Spraberry field. Of the 477 MMBOE of proved reserves in the Spraberry field, 205 MMBOE were proved developed reserves and 272 MMBOE were proved undeveloped reserves. These proved undeveloped reserves represent approximately 3,800 future drilling locations held by Pioneer in the Spraberry field.

 

Pioneer views the Partnership as an integral part of its overall growth strategy and has publicly announced that it intends to offer the Partnership over time the opportunity to purchase from Pioneer producing oil and gas assets in the Partnership’s area of operations, provided that such transactions can be done in an economic manner and depending upon market conditions at the time. The Partnership also plans to participate jointly with Pioneer in acquisitions that include mature producing assets in the Partnership’s area of operations.

 

The Partnership has entered into an omnibus agreement with Pioneer that limits the Partnership’s area of operations to onshore Texas and eight counties in the southeast region of New Mexico.

 

Competitive Strengths

 

The Partnership believes the following competitive strengths will allow it to achieve its objectives of generating and growing cash available for distribution:

 

 

 

 

 

Business Activities

 

Petroleum industry. During the second half of 2008 and continuing into the first quarter of 2009, worldwide financial markets experienced significant turmoil as a worldwide economic decline gained momentum and the availability of liquidity provided by the financial markets declined. The economic decline has significantly reduced worldwide energy consumption and demand for oil, NGLs and gas. Resulting hydrocarbon supply and demand

 

 

imbalances have significantly reduced market prices for oil, NGLs and gas since the record high levels that were realized in mid-2008. Additionally, demand for drilling rigs and vessels, oilfield supplies, drill pipe and utilities reached record highs during 2008, affecting reserve finding costs and production costs. Although those costs have begun to decline, their declines have lagged significantly behind the declines in oil, NGL and gas prices, severely constricting operating margins during the second half of 2008 and resulting in negative proved reserve price revisions at the end of 2008.

 

For the several years preceding the 2008 worldwide economic decline, the petroleum industry had generally been characterized by volatile but upward trending oil, NGL and gas commodity prices. During that period, world oil prices increased in response to increases in demand from developing economies and the perceived threat of supply disruptions in the Middle East, Nigeria, Venezuela and other areas. In 2007 and the first half of 2008, oil prices increased due to supply uncertainty surrounding Middle East conflicts and increasing world demand for both oil and refined products. A significant increase in refinery outages led to tightness in products markets which was responsible for oil price strength throughout much of 2007 and the early part of 2008. North American gas prices during 2008 increased during the first half of 2008 as a result of reduced inventory levels and a perceived shortage of North American gas supply and an anticipation that the United States would become a larger importer of LNG, which was selling at a substantial premium to United States gas prices in the world market. However, by mid-year 2008, it became increasingly apparent that the capital investment in gas drilling and discoveries of significant gas reserves in United States shale plays would be more than sufficient to meet the United States demand. Coupled with the economic downturn experienced in the second half of 2008, the increased supply of gas resulted in a sharp decline in North American gas prices.

 

Significant factors that will impact 2009 commodity prices include: the impact of economic stimulus initiatives being implemented in the United States and worldwide in response to the worldwide economic decline; developments in the issues currently impacting the Middle East in general; demand of Asian and European markets; the extent to which members of the Organization of Petroleum Exporting Countries ("OPEC") and other oil exporting nations are able to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of increasing LNG deliveries to the United States.

 

To mitigate the impact of commodity price volatility on the Partnership’s net cash provided by operating activities, the Partnership utilizes commodity derivative contracts. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the impact to oil and gas revenues during 2008 from the Partnership’s derivative price risk management activities and the Partnership’s open derivative positions at December 31, 2008.

 

The Partnership. Currently, the Partnership’s oil and gas properties consist only of nonoperated working interests in approximately 1,100 producing wells, all of which are operated by Pioneer. The Partnership does not own any undeveloped properties or leasehold acreage. See "Item 2- Description of Properties". All of the Partnership’s properties are located in the Spraberry field in the Permian Basin of West Texas. According to the Energy Information Administration, the Spraberry field is the fifth largest oil field in the United States, and the Partnership believes that Pioneer is the largest operator in the field based on recent production information. Because Pioneer is the largest producer in the Spraberry field and has a significantly greater asset base than the Partnership does, the Partnership believes it will benefit from Pioneer’s experience and scale of operations. Although Pioneer has no obligation to sell assets to the Partnership, and the Partnership is not obligated to purchase from Pioneer any additional assets, Pioneer has informed the Partnership that it intends to offer to the Partnership from time to time the opportunity to purchase from Pioneer oil and gas assets in the Partnership’s area of operations. The Partnership believes that a substantial portion of Pioneer’s assets in the Partnership’s area of operations have or in the future will have the characteristics that will make them well-suited for ownership by a limited partnership such as the Partnership. The Partnership also expects to make acquisitions in its area of operations from third parties and to participate jointly in acquisitions with Pioneer in which it will acquire the producing oil and gas properties and Pioneer will acquire the undeveloped properties. Any assets that the Partnership acquires from either Pioneer or third parties may include interests in midstream assets associated with its oil and gas properties.

 

Production and Drilling Activities. During the year ended December 31, 2008, the Partnership's average daily production, on a BOE basis was 4,811. Production, price and cost information with respect to the Partnership's properties for 2008, 2007 and 2006 is set forth under "Item 2. Properties — Selected Oil and Gas Information — Production, Price and Cost Data." During the three years ended December 31, 2008, the Partnership drilled 29 gross (22 net) wells, all of which were successfully completed as productive wells.

 

 

            

Marketing of Production

 

General. As operator of the Partnership Properties, Pioneer is responsible for marketing the Partnership’s production in a commercially reasonable manner, and for paying the Partnership the sales proceeds attributable to its production. The production sales agreements entered into by Pioneer that are related to the Partnership’s production contain customary terms and conditions for the oil and gas industry, provide for sales based on prevailing market prices and have terms ranging from 30 days to three years. Sales prices for oil, NGL and gas production are negotiated based on factors normally considered in the industry, such as the index or spot price for gas or the spot price for oil, price regulations, distance from the well to the pipeline, well pressure, estimated reserves, commodity quality and prevailing supply conditions. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for additional discussion of operations and price risk.

 

Significant purchasers. During 2008, the Partnership's significant purchasers were Plains Marketing LP (62 percent) and TEPPCO Crude Oil (11 percent). The Partnership believes that the loss of any one purchaser would not have an adverse effect on its ability to sell its oil, NGL and gas production.

 

Derivative activities. The Partnership, from time to time, utilizes commodity swap and collar contracts in order 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. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a description of the Partnership's derivative activities, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information concerning the impact on oil and gas revenues during 2008 from commodity derivative activities and the Partnership's commodity derivative positions that were accounted for as cash flow hedges at December 31, 2008.

 

Competition, Markets and Regulations

 

Competition. The oil and gas industry is highly competitive. A large number of companies, including major integrated and other independent companies, and individuals engage in the development of oil and gas properties, and there is a high degree of competition for oil and gas properties suitable for development. Acquisitions of oil and gas properties will be an important element of the Partnership's growth. The principal competitive factors in the acquisition of oil and gas assets include the staff and data necessary to identify, evaluate and acquire such assets and the financial resources necessary to acquire and develop the assets. Many of the Partnership's competitors are substantially larger and have financial and other resources greater than those of the Partnership.

 

Markets. As operator of the Partnership Properties, Pioneer is responsible for marketing the Partnership’s production. The Partnership's ability to produce and Pioneer's ability to market oil, NGLs and gas profitably depends on numerous factors beyond the Partnership's control. The effect of these factors cannot be accurately predicted or anticipated. Although the Partnership cannot predict the occurrence of events that may affect these commodity prices or the degree to which these prices will be affected, the prices for any commodity that the Partnership produces will generally approximate current market prices in the geographic region of the production.

 

Governmental regulations. Enterprises that sell securities in public markets are subject to regulatory oversight by agencies such as the SEC and the NYSE. This regulatory oversight imposes on the Partnership the responsibility for establishing and maintaining disclosure controls and procedures that are designed to ensure that material information relating to the Partnership is made known to management and that the financial statements and other information included in submissions to the SEC do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made in such submissions not misleading. Compliance with some of these regulations is costly and regulations are subject to change or reinterpretation.

 

Environmental matters and regulations. The Partnership's operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

 

 

 

 

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and state legislatures, and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on the Partnership's operating costs.

 

The following is a summary of some of the existing laws, rules and regulations to which the Partnership's business operations are subject.

 

Waste handling. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency ("EPA"), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil or gas are currently regulated under RCRA's non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in the Partnership's costs to manage and dispose of wastes, which could have a material adverse effect on the Partnership's results of operations and financial position. Also, in the course of the Partnership's operations, it generates some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, that may be regulated as hazardous wastes.

 

Wastes containing naturally occurring radioactive materials ("NORM") may also be generated in connection with the Partnership's operations. Certain processes used to produce oil and gas may enhance the radioactivity of NORM, which may be present in oilfield wastes. NORM is not subject to regulation under the Atomic Energy Act of 1954, or the Low Level Radioactive Waste Policy Act. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration ("OSHA"). These state and OSHA regulations impose certain requirements concerning worker protection; the treatment, storage and disposal of NORM waste; the management of waste piles, containers and tanks containing NORM; as well as restrictions on the uses of land with NORM contamination.

 

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

 

The Partnership currently owns or leases numerous properties that have been producing oil and gas for many years. Although the Partnership believes Pioneer has utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by the Partnership, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of the Partnership's properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under Pioneer's or the Partnership's control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by the Partnership. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Partnership could be required to remove previously disposed substances

 

 

and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

 

Water discharges and use. The Clean Water Act (the "CWA") and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the Environmental Protection Agency ("EPA") or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

 

The primary federal law imposing liability for oil spills is the Oil Pollution Act ("OPA"), which sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities and onshore facilities. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil spill cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

 

Operations associated with the Partnership's properties also produce wastewaters that are disposed via injection in underground wells. These activities are regulated by the Safe Drinking Water Act (the "SDWA") and analogous state and local laws. The underground injection well program under the SDWA classifies produced wastewaters and imposes restrictions on the drilling and operation of disposal wells as well as the quality of injected wastewaters. This program is designed to protect drinking water sources and requires permits from the EPA or an analogous state agency for the Partnership's disposal wells. Currently, the Partnership believes that disposal well operations on the Partnership's properties comply with all applicable requirements under the SDWA. However, a change in the regulations or the inability to obtain permits for new injection wells in the future may affect the Partnership's ability to dispose of produced waters and ultimately increase the cost of the Partnership's operations.

 

Air emissions. The Federal Clean Air Act (the "CAA") and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions; obtain or strictly comply with air permits containing various emissions and operational limitations; or utilize specific emission control technologies to limit emissions of certain air pollutants. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Moreover, states can impose air emissions limitations that are more stringent than the federal standards imposed by EPA. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.

 

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require the Partnership to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies for oil and gas drilling and production operations. In addition, some oil and gas production facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Oil and gas drilling and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

 

Health and safety. Operations associated with the Partnership's properties are subject to the requirements of the federal Occupational Safety and Health Act (the "OSH Act") and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSH Act hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statues require that the Partnership organize and/or disclose information about hazardous materials used or produced in the Partnership's operations. The Partnership believes that it is in substantial compliance with these applicable requirements and with other OSH Act and comparable requirements.

 

 

Global warming and climate change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere. In response to such studies, Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states (not including Texas) have already taken legal measures to reduce emissions of greenhouse gases. Also, as a result of the U.S. Supreme Court's decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations have already agreed to regulate emissions of greenhouse gases, pursuant to the United Nations Framework Convention on Climate Change, also known as the "Kyoto Protocol," an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Passage of climate control legislation or other regulatory initiatives by Congress or various states or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which the Partnership conducts business could have an adverse effect on the Partnership's operations and demand for oil and gas.

 

The Partnership believes it is in substantial compliance with all existing environmental laws and regulations applicable to the Partnership's current operations and that its continued compliance with existing requirements will not have a material adverse impact on the Partnership's financial condition and results of operations. For instance, the Partnership did not incur any material capital expenditures for remediation or pollution control activities for the three years ending December 31, 2008. Additionally, the Partnership is not aware of any environmental issues or claims that will require material capital expenditures during 2009. However, accidental spills or releases may occur in the course of the Partnership's operations, and the Partnership cannot give any assurance that it will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, the Partnership cannot give any assurance that the passage of more stringent laws or regulations in the future will not have a negative impact on the Partnership's business, financial condition and results of operations.

 

Other regulation of the oil and gas industry. The oil and gas industry is regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry may increase the Partnership's cost of doing business by increasing the cost of transporting its production to market, these burdens generally do not affect the Partnership any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

The Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security ("DHS") to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present "high levels of security risk." The DHS is currently in the process of adopting regulations that will determine whether some of the Partnership's facilities or operations will be subject to additional DHS-mandated security requirements. Presently, it is not possible to accurately estimate the costs the Partnership could incur, directly or indirectly, to comply with any such facility security laws or regulations, but such expenditures could be substantial.

 

Development and production. Development and production operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, the posting of bonds in connection with various types of activities and filing reports concerning operations. Most states, and some counties and municipalities, in which the Partnership operates also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate drilling and production while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Partnership's interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and

 

 

regulations may limit the amount of oil and gas the Partnership can produce from its wells or limit the number of wells or the locations at which the Partnership can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGL and gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from the Partnership's wells, negatively impact the economics of production from these wells and/or to limit the number of locations the Partnership can drill.

Regulation of transportation and sale of gas. The availability, terms and cost of transportation significantly affect sales of gas. Federal and state regulations govern the price and terms for access to gas pipeline transportation. The interstate transportation and sale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission ("FERC"). The FERC's regulations for interstate gas transmission in some circumstances may also affect the intrastate transportation of gas.

Although gas prices are currently unregulated, Congress historically has been active in the area of gas regulation. The Partnership cannot predict whether new legislation to regulate gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on the Partnership's operations. Sales of condensate and gas liquids are not currently regulated and are made at market prices.

Gas gathering. The Partnership depends on gathering facilities owned and operated by third parties to gather production from its properties, and therefore the Partnership is impacted by the rates charged by such third parties for gathering services. To the extent that changes in federal and/or state regulation affect the rates charged for gathering services, the Partnership also may be affected by such changes. Accordingly, the Partnership does not anticipate that it would be affected any differently than similarly situated gas producers.

 

ITEM 1A. RISK FACTORS

 

The nature of the business activities conducted by the Partnership subjects it to certain hazards and risks. The following is a summary of some of the material risks relating to the Partnership's business activities. Other risks are described in "Item 1. Business — Competition, Markets and Regulations" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk." These risks are not the only risks facing the Partnership. The Partnership's business could also be impacted by additional risks and uncertainties not currently known to the Partnership or that it currently deems to be immaterial. If any of these risks actually occur, they could materially harm the Partnership's business, financial condition or results of operations. In that case, the Partnership might not be able to pay the distributions on its common units and the market price of the Partnership's common units could decline.

 

Risks Related to the Partnership’s Business

 

The Partnership may not have sufficient cash flow from operations to pay quarterly distributions on its common units following the establishment of cash reserves and payment of fees and expenses, including reimbursement of expenses to the General Partner and its affiliates.

 

The Partnership may not have sufficient available cash each quarter to pay its quarterly distribution of $0.50 per unit or any other amount.

 

Under the terms of the First Amended and Restated Agreement of Limited Partnership of Pioneer Southwest Energy Partners L.P. (the "Partnership Agreement"), the amount of cash otherwise available for distribution will be reduced by the Partnership’s operating expenses and the amount of any cash reserve amounts that the General Partner establishes to provide for future operations, future capital expenditures, including acquisitions of additional oil and gas assets, future debt service requirements and future cash distributions to unitholders. The Partnership plans to reinvest a sufficient amount of its cash flow in acquisitions and downspaced drilling in order to maintain its production and proved reserves, and the Partnership plans to use external financing sources to increase its production and proved reserves.

 

 

The amount of cash the Partnership actually generates will depend upon numerous factors related to its business that may be beyond its control, including among other things:

 

 

In addition, the actual amount of cash that the Partnership will have available for distribution will depend on other factors, including:

 

 

See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of additional restrictions and factors that could affect the Partnership’s ability to make cash distributions.

 

The price of oil, NGL and gas are highly volatile. A sustained decline in these commodity prices will cause a decline in the Partnership’s cash flow from operations, which could force it to reduce its distributions or cease paying distributions altogether.

 

The oil, NGL and gas markets are highly volatile, and the Partnership cannot predict future oil, NGL and gas prices. Prices for oil and gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond the Partnership’s control, such as:

 

 

 

 

In the past, prices of oil, NGL and gas have been extremely volatile, and the Partnership expects this volatility to continue. For example, during the year ended December 31, 2008, the NYMEX oil price ranged from a high of $145.29 per Bbl to a low of $33.87 per Bbl, while the NYMEX Henry Hub gas price ranged from a high of $13.58 per MMBtu to a low of $5.29 per MMBtu.

 

Significant or extended price declines could also adversely affect the amount of oil and gas that the Partnership can produce economically. A reduction in production could result in a shortfall in expected cash flows and may negatively impact the Partnership’s ability to pay distributions.

 

The Partnership’s revenue, profitability and cash flow depend upon the prices and demand for oil and gas, and a drop in prices can significantly affect its financial results and impede its growth. If the Partnership raises its distribution levels in response to increased cash flow during periods of higher commodity prices, the Partnership may not be able to sustain those distribution levels during subsequent periods of lower commodity prices. A sustained decline in commodity prices could force the Partnership to reduce its distributions or possibly cease paying distributions altogether.

 

The Partnership’s assets consist primarily of working interests in identified producing wells, and the Partnership does not own undeveloped properties or leasehold acreage that it can develop to maintain its production.

 

The Partnership only owns mineral interests and leasehold interests in identified producing wells (often referred to as wellbore assignments), and the Partnership does not own any undeveloped properties or leasehold acreage. The Partnership’s rights as to each wellbore are limited to only those rights that are necessary to produce hydrocarbons from that particular wellbore, and do not include the right to drill additional wells (other than replacement wells or downspaced wells) within the area covered by the mineral or leasehold interest to which that wellbore relates. In addition, the Partnership’s operations with respect to each wellbore are limited to the interval from the surface to the depth of the deepest producing perforation in the wellbore, plus an additional 100 feet as a vertical easement for operating purposes only. The wellbore assignments also prohibit the Partnership from extending the horizontal reach of the assigned interest. As a result, the Partnership currently has no ability to drill or participate in the drilling of additional wells (other than replacement wells or downspaced wells). These restrictions on the Partnership’s ability to extend the vertical and horizontal limits of its existing wellbores could materially adversely affect its ability to maintain and grow its production and reserves and to make cash distributions to its unitholders.

 

Because oil and gas properties are a depleting asset and the Partnership’s assets consist primarily of working interests in producing wells, the Partnership will have to make acquisitions or otherwise mitigate production declines in order to maintain its production and reserves and sustain its distributions over time.

 

Producing oil and gas reservoirs are characterized by declining production rates. Because the Partnership’s proved reserves and production decline continually over time, the Partnership will need to acquire income producing assets, or mitigate the declines through production enhancements or drilling initiatives, to sustain its level of distributions to unitholders over time. The Partnership may be unable to make such acquisitions if:

 

 

Because the timing and amount of these acquisitions is uncertain, the Partnership expects to reserve cash each quarter to finance these acquisitions or drill downspaced locations in order to maintain its production and proved reserves, which will reduce its cash available for distribution. The Partnership may use the reserved cash to reduce indebtedness, if any, until the Partnership makes an acquisition.

 

The Partnership will require substantial capital expenditures to replace its production and reserves, which will reduce its cash available for distribution. The Partnership could be unable to obtain needed capital or financing due to its financial condition, the covenants in its credit agreement or adverse market conditions, which could adversely affect its ability to replace its production and proved reserves.

 

To fund its acquisitions and capital commitments, the Partnership will be required to use cash generated from its operations, borrowings or the proceeds from the issuance of additional partnership interests, or some combination

 

 

thereof, which could limit its ability to sustain its level of distributions. For example, the Partnership plans to use approximately 25 percent of its cash flow to acquire income producing assets and drill downspaced locations in order to maintain its production and proved reserves. To the extent its production declines faster than the Partnership anticipates or the cost to acquire or drill for additional reserves is greater than the Partnership anticipates, the Partnership will require a greater amount of capital to maintain its production and proved reserves. The use of cash generated from operations to fund acquisitions or drilling will reduce cash available for distribution to its unitholders. The Partnership’s ability to obtain bank financing or to access the capital markets for future equity or debt offerings could be limited by its financial condition at the time of any such financing or offering, the covenants in its credit facility or future financing agreements, adverse market conditions or other contingencies and uncertainties that are beyond the Partnership’s control. The Partnership’s failure to obtain the funds necessary for future acquisitions could materially affect its business, results of operations, financial condition and ability to pay distributions. Even if the Partnership is successful in obtaining the necessary funds, the terms of such financings could limit its ability to pay distributions to its unitholders. In addition, incurring additional debt could significantly increase the Partnership’s interest expense and financial leverage, and issuing additional partnership interests could result in significant unitholder dilution thereby increasing the aggregate amount of cash required to maintain the then current distribution rate, which could reduce its distributions materially.

 

The Partnership may be unable to make attractive acquisitions, and any acquisitions the Partnership completes are subject to substantial risks that could reduce its ability to make distributions to unitholders.

 

Even if the Partnership does make acquisitions that the Partnership believes will increase distributable cash per unit, these acquisitions could nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:

 

 

The Partnership’s decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, the Partnership’s reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential problems. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

 

The Partnership’s proved reserves could be subject to drainage from offset drilling locations.

 

Many of the Partnership’s wells directly offset potential drilling locations held by Pioneer or third parties. The owners of leasehold interests lying contiguous or adjacent to or adjoining the Partnership’s interests could take actions, such as drilling additional wells, that could adversely affect its operations. It is in the nature of petroleum reservoirs that when a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of the Partnership’s proved reserves. The Partnership has agreed not to object to such drilling by Pioneer. The depletion of the

 

 

Partnership’s proved reserves from offset drilling locations could materially adversely affect its ability to maintain and grow its production and reserves and to make cash distributions to its unitholders.

 

The amount of cash the Partnership has available for distribution to unitholders depends primarily on its cash flow and not solely on profitability.

 

The amount of cash the Partnership has available for distribution depends primarily on its cash flow, including cash from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by noncash items. As a result, the Partnership may make cash distributions during periods when the Partnership records losses and may not make cash distributions during periods when the Partnership records net income.

 

Future price declines could result in a reduction in the carrying value of the Partnership’s proved oil and gas properties which could adversely affect the Partnership’s results of operations and limit its ability to borrow and make distributions.

 

Declines in oil and gas prices could result in the Partnership having to make substantial downward adjustments to its estimated proved reserves. If this occurs, or if the Partnership’s estimates of production or economic factors change, accounting rules could require it to write down, as a noncash charge to earnings, the carrying value of its oil and gas properties for impairments. The Partnership is required to perform impairment tests on its assets whenever events or changes in circumstances warrant a review of its assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of its assets, the carrying value may not be recoverable and therefore require a write-down. The Partnership could incur impairment charges in the future, which could materially affect its results of operations in the period incurred. In addition, the Partnership's borrowing capacity under its credit facility is subject to a covenant requiring that the Partnership maintain a specified ratio of the net present value of the Partnership's projected future cash flows from its oil and gas assets to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. As a result, further declines in commodity prices could reduce the Partnership's borrowing capacity under its credit facility, which in turn could adversely affect its ability to make cash distributions to its unitholders.

 

Changes in the differential between NYMEX or other benchmark prices of oil, NGL and gas and the reference or regional index price used to price the commodities the Partnership sells could have a material adverse effect on its results of operations, financial condition and cash flows.

 

The reference or regional index prices that the Partnership uses to price its oil, NGL and gas sales sometimes trade at a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price the Partnership references in its sales contract is called a differential. The Partnership cannot accurately predict oil, NGL and gas differentials. Increases in the differential between the benchmark price for oil, NGL and gas and the reference or regional index price the Partnership references in its sales contract could have a material adverse effect on its results of operations, financial condition and cash flows.

 

The Partnership’s derivative activities could result in financial losses or could reduce its income, which could adversely affect its ability to pay distributions to its unitholders.

 

To achieve more predictable cash flow and to reduce the Partnership’s exposure to fluctuations in commodity prices, the Partnership is a party to, and in the future the Partnership may enter into, derivative arrangements covering a significant portion of the Partnership’s oil, NGL and gas production that could result in both realized and unrealized derivative losses. The Partnership has direct commodity price exposure on the portion of its production volumes not covered by derivative contracts. These derivative arrangements are subject to mark-to-market accounting treatment, and the change in fair market value of the arrangements will be reported in the Partnership’s statement of operations each quarter, which may in the future result in significant net losses. Failure to protect against declines in commodity prices exposes the Partnership to reduced revenue and liquidity when prices decline, as occurred in late 2008 and has continued into 2009. Approximately 25 percent, 30 percent and 55 percent of the Partnership's estimated total production for 2009, 2010 and 2011, respectively, is not covered by derivative contracts. See "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk."

 

 

The failure by counterparties to the Partnership's derivative contracts to perform their obligations could have a material adverse effect on the Partnership's results of operations.

The Partnership has adopted a policy that contemplates protecting the prices for approximately 65 to 85 percent of expected production for a period of up to five years. In addition, as described below, the Partnership's credit facility requires it to enter into derivative contracts for a significant portion of its oil, NGL and gas production attributable to proved developed producing reserves in differing annual percentages over a rolling three-year period. See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a description of the Partnership's derivative positions as of December 31, 2008. The use of derivative contracts involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default in their obligations under the Partnership's derivative contracts, such a default could have a material adverse effect on the Partnership's results of operations, and could result in a larger percentage of the Partnership's future production being subject to commodity price changes. In addition, in light of the current economic outlook, it is possible that fewer counterparties will participate in derivative transactions, which could result in a greater concentration of the Partnership's exposure to any one counterparty or a larger percentage of the Partnership's future production could be subject to commodity price changes.

The Partnership’s derivative transactions could be ineffective in reducing the volatility of its cash flows and in certain circumstances could actually increase the volatility of its cash flows.

 

The Partnership’s actual future production during a period may be significantly higher or lower than the Partnership estimates at the time the Partnership enters into derivative transactions for such period. If the actual amount is higher than the Partnership estimates, the Partnership will have more production not covered by derivative contracts and therefore greater commodity price exposure than the Partnership intended. If the actual amount is lower than the nominal amount that is subject to its derivative financial instruments, the Partnership might be forced to satisfy all or a portion of its derivative transactions without the benefit of the cash flow from its sale of the underlying physical commodity, resulting in a substantial diminution of its liquidity. As a result of these factors, the Partnership’s derivative activities may not be as effective as it intends in reducing the volatility of its cash flows, and in certain circumstances could actually increase the volatility of its cash flows.

 

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

 

Approximately 75 percent, 70 percent and 45 percent of the Partnership’s estimated total production for 2009, 2010 and 2011, respectively, have been matched with fixed price commodity swaps or collar contracts. As the Partnership’s derivative contracts expire, more of its future production will be sold at market prices unless the Partnership enters into further derivative transactions. The Partnership’s credit facility requires it to enter into derivative arrangements for not less than 65 percent (nor more than 85 percent) of its projected oil, NGL and gas production attributable to proved developed producing reserves through December 31, 2010. Furthermore, by April 1, 2009 and April 1, 2010, the credit facility requires that the Partnership enter into derivative transactions for not less than 50 percent of the Partnership's projected oil, NGL and gas production attributable to proved developed producing reserves through December 31, 2011 and December 31, 2012, respectively. The Partnership’s commodity price derivative strategy and future derivative transactions will be determined by the General Partner, which is not under any obligation to enter into derivative contracts on a specific portion of the Partnership’s production, other than to comply with the terms of the Partnership’s credit facility for so long as it may remain in place. The prices at which the Partnership enters into derivative contracts on its production in the future will be dependent upon commodity prices at the time the Partnership enters into these transactions, which may be substantially lower than current oil, NGL and gas prices. Additionally, the Partnership could be required by the terms of its credit facility to enter into derivative contracts at times and prices that are not considered strategically advantageous. Accordingly, the Partnership’s derivative contracts may not protect it from significant and sustained declines in oil, NGL and gas prices received for its future production. Conversely, the Partnership’s commodity price derivative strategy could limit its ability to realize cash flow from commodity price increases. It is also possible that a larger percentage of the Partnership’s future production will not be covered by derivative contracts as compared to the next few years, which would result in its oil and gas revenues becoming more sensitive to commodity price changes.

 

 

Estimates of proved reserves and future net cash flows are not precise. The actual quantities and net cash flows of the Partnership’s proved reserves could prove to be lower than estimated.

 

Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. The estimates of proved reserves and related future net cash flows set forth in this Report are based on various assumptions, which may ultimately prove to be inaccurate.

 

Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:

 

 

Because all reserve estimates are to some degree subjective, each of the following items could differ materially from those assumed in estimating reserves:

 

 

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. The Partnership's actual production, revenues and expenditures with respect to reserves will likely be different from estimates, and the differences may be material.

 

As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

 

 

Standardized Measure is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. It requires the use of commodity prices, as well as operating and development costs, prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and gas production because of seasonal price fluctuations or other varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates included herein of future net cash flows could be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Partnership or the oil and gas industry in general. Therefore, the estimates of discounted future net cash flows or Standardized Measure in this Report should not be construed as accurate estimates of the current market value of the Partnership's proved reserves.

 

Producing oil and gas involves numerous risks and uncertainties that could adversely affect the Partnership’s financial condition or results of operations and, as a result, its ability to pay distributions to its unitholders.

 

The operating cost of a well includes variable costs, and increases in these costs can adversely affect the economics of a well. Furthermore, the Partnership’s producing operations could be curtailed or delayed or become uneconomical as a result of other factors, including:

 

 

 

 

 

If any of these factors were to occur with respect to a particular area of the Spraberry field, the Partnership could lose all or a part of its investment in that area, or the Partnership could fail to realize the expected benefits from that area of the Spraberry field, either of which could materially and adversely affect its revenue and profitability.

 

Additionally, the Partnership relies to a large extent on the facilities owned and operated by third parties, and damage to or destruction of those third-party facilities could affect the ability of the Partnership to produce, transport and sell its hydrocarbons. For example, damage caused by Hurricane Ike to a third-party facility that fractionates NGLs from a portion of the Partnership's production resulted in a portion of the Partnership's production being shut-in or curtailed from early September to mid-November 2008 while repairs and maintenance to the facility were being completed.

 

Pioneer is the operator of all of the Partnership’s properties, and the Partnership has limited ability to influence or control the operation of these properties.

 

The Partnership does not operate any of its properties. Pioneer operates all of the Partnership Properties pursuant to operating agreements. The Partnership has limited ability to influence or control the operation of these properties or the amount of maintenance capital that the Partnership is required to fund with respect to them. The Partnership has agreed that it will not object to Pioneer's development of the leasehold acreage surrounding the Partnership’s wells, that any well operations Pioneer proposes will take precedence over any conflicting operations the Partnership proposes, and that the Partnership will allow Pioneer to use certain of the Partnership’s production facilities in connection with other wells operated by Pioneer, subject to capacity limitations. In addition, the Partnership is restricted in its ability to remove Pioneer as the operator of the wells the Partnership owns. The Partnership’s dependence on Pioneer and other working interest owners for these projects and its limited ability to influence or control the operation of these properties could materially adversely affect the realization of its targeted returns, resulting in smaller distributions to its unitholders.

 

Virtually all of the Partnership’s wells are subject to a volumetric production payment, which could cause a decrease in the Partnership’s production and could result in a decrease in its revenue and cash available for distribution.

 

Of the approximately 1,100 wells that the Partnership owns, all but 16 are subject to a volumetric production payment agreement, or VPP, that Pioneer entered into in April 2005, which requires the delivery of specified quantities of oil through December 2010 from proved reserves in the Spraberry field. Pioneer’s VPP represents limited-term overriding royalty interests in oil and gas reserves that: (1) entitle the purchaser to receive production volumes over a period of time from specific lease interests; (2) do not bear any future production costs and capital expenditures associated with the reserves; (3) are nonrecourse to Pioneer (i.e., the purchaser’s only recourse is to the reserves acquired); (4) transfer title of the reserves to the purchaser; and (5) allow Pioneer to retain the remaining reserves after the VPP volumetric quantities have been delivered. 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’s 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 make a cash payment to the Partnership for the value of the Partnership’s 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. To the extent Pioneer fails to make any cash payment associated with any of the Partnership’s volumes delivered pursuant to the VPP obligation, the decrease in the Partnership’s production would result in a decrease in its cash available for distribution.

 

The Partnership’s actual production could differ materially from its forecasts.

 

From time to time the Partnership provides forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production decline rates from existing wells. Downturns in commodity prices could make certain production uneconomical, which would also adversely impact prior forecasts of production.

 

Due to the Partnership’s lack of asset and geographic diversification, adverse developments in the Spraberry field would reduce its ability to make distributions to its unitholders.

 

The Partnership relies exclusively on sales of oil and gas that it produces from, and all of its assets are currently located in, a single field in Texas. All of its oil and gas properties are producing properties, and the Partnership does not own any undeveloped properties or leasehold acreage (other than acreage related to downspaced wells). In addition, the Partnership’s operations are restricted to onshore Texas and the southeast region of New Mexico. Due to its lack of diversification in asset type and location, an adverse development in the oil and gas business of this geographic area would have a significantly greater impact on the Partnership’s results of operations and cash available for distribution to its unitholders than if the Partnership maintained more diverse assets and locations.

 

A substantial amount of the Partnership’s production is purchased by two companies. If these companies reduce the amount of the Partnership’s production that they purchase, the Partnership’s revenue and cash available for distribution will decline to the extent that substitute purchasers negotiate terms that are less favorable than the terms of the current marketing agreements. A failure by purchasers of the Partnership's production to perform their obligations to the Partnership could require the Partnership to recognize a charge in earnings and have a material adverse effect on the Partnership's results of operations.

 

For the year ended December 31, 2008, purchases by Plains Marketing, L.P. and TEPPCO Crude Oil represented approximately 62 percent and 11 percent of the Partnership’s sales revenue, respectively. If these companies were to reduce the amount of the Partnership’s production that they purchase, the Partnership’s revenue and cash available for distribution will decline to the extent that substitute purchasers negotiate terms that are less favorable than the terms of the current marketing agreements.

 

In addition, a failure by any of these companies, or any purchasers of the Partnership's production, to perform their payment obligations to the Partnership could have a material adverse effect on the Partnership's results of operation. Recently, there has been a significant decline in the credit markets and the availability of credit, and equity values have substantially declined. To the extent that purchasers of the Partnership's production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to the Partnership. If for any reason the Partnership were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of the Partnership's production were uncollectible, the Partnership would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in its liquidity and ability to make distributions.

 

Plains Marketing, L.P. and TEPPCO Crude Oil purchase the majority of the Partnership’s oil and NGL production pursuant to existing marketing agreements with Pioneer. The Partnership is not a party to the marketing agreements with Plains Marketing, L.P. and TEPPCO Crude Oil. Pursuant to the provisions of standard industry operating agreements to which the Partnership’s properties are subject and to which the Partnership is a party, Pioneer, as operator, markets the production on behalf of all working interest owners, including the Partnership, and determines in its sole discretion the terms on which the Partnership’s production is sold.

 

As is standard in the industry, the oil sold under Pioneer’s marketing agreements with Plains Marketing, L.P. and TEPPCO Crude Oil is sold at the West Texas Intermediate (Cushing) price, less the Midland, Texas location and transportation differentials at the time of sale. The primary term of Pioneer’s marketing agreement with Plains

 

 

Marketing, L.P. expires on January 1, 2011, after which time the contract will automatically be extended on a month-to-month basis until either party gives 90 days advance written notice of non-renewal. The marketing agreement between Pioneer and TEPPCO Crude Oil is currently month-to-month and may be terminated upon 30 days advance written notice by either party to the agreement.

 

The Partnership may not be able to obtain funding, obtain funding on acceptable terms or obtain funding under its credit facility because of the deterioration of the credit and capital markets. This could hinder or prevent the Partnership from meeting its future capital needs.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the repricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding. In addition, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to the borrower's current debt and reduced or, in some cases, ceased to provide funding to borrowers. In addition, the Partnership may be unable to obtain adequate funding under its credit facility if (i) the Partnership's lending counterparties become unwilling or unable to meet their funding obligations or (ii) the amount the Partnership may borrow under its credit facility is reduced as a result of lower oil, NGL or gas prices, declines in reserves, lending requirements or regulations, or for other reasons. Due to these factors, the Partnership cannot be certain that funding will be available if needed and, to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, the Partnership may be unable to implement its business plans, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on the Partnership's production, revenues and results of operations.

Declining general economic, business or industry conditions could have a material adverse affect on the Partnership's results of operations.

Recently, concerns over a worldwide economic downturn, geopolitical issues, the availability and cost of credit, the U.S. mortgage market and a declining real estate market in the United States have contributed to increased volatility and diminished expectations for the global economy. These factors, combined with volatile oil prices, declining business and consumer confidence and increased unemployment, have precipitated a worldwide recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices, both of which have contributed to a decline in the Partnership's common unit price and corresponding market capitalization. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could further diminish, which could further depress the price at which the Partnership can sell its oil, NGLs and gas and ultimately decrease the Partnership's net revenue and profitability.

The Partnership faces significant competition, and many of its competitors have resources in excess of the Partnership’s available resources.

 

The oil and gas industry is intensely competitive with respect to acquiring producing oil and gas assets, marketing oil and gas and securing equipment and trained personnel, and the Partnership competes with other companies that have greater resources. Many of the Partnership’s competitors are major and large independent oil and gas companies that possess and employ financial, technical and personnel resources substantially greater than the Partnership’s. Those companies may be able to develop and acquire more assets than the Partnership’s financial or personnel resources permit. The Partnership’s ability to acquire additional oil and gas assets in the future will depend on Pioneer’s willingness and ability to evaluate and select suitable assets and the Partnership’s ability to consummate transactions in a highly competitive environment. Many of the Partnership’s larger competitors not only drill for and produce oil and gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and gas assets and evaluate, bid for and purchase a greater number of assets than the Partnership’s financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and gas industry. These larger companies may have a greater ability to absorb the burden of present and future federal, state, local and other laws and regulations. The Partnership’s inability to compete effectively with larger companies could have a material adverse impact on its business activities, financial condition and results of operations.

 

 

The Partnership may incur debt to enable it to pay its quarterly distributions, which could negatively affect its ability to execute its business plan and pay future distributions.

 

The Partnership has the ability to incur debt under its credit facility to pay distributions. If the Partnership borrows to pay distributions, the Partnership would be distributing more cash than the Partnership generates from its operations on a current basis. This means that the Partnership would be using a portion of its borrowing capacity under its credit facility to pay distributions rather than to maintain or expand its operations. If the Partnership uses borrowings under its credit facility to pay distributions for an extended period of time rather than toward funding acquisition expenditures and other matters relating to its operations, the Partnership may be unable to support or grow its business. Such a curtailment of its business activities, combined with its payment of principal and interest on its future indebtedness to pay these distributions, will reduce the Partnership’s cash available for distribution on its units and will materially affect its business, financial condition and results of operations. If the Partnership borrows to pay distributions during periods of low commodity prices and commodity prices remain low, the Partnership would likely have to reduce its future distributions in order to avoid excessive leverage.

 

The Partnership’s future debt levels could limit its flexibility to obtain additional financing and pursue other business opportunities.

 

The level of the Partnership’s future indebtedness could have important consequences to the Partnership, including:

 

 

The Partnership’s ability to service its indebtedness will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond the Partnership’s control. If its operating results are not sufficient to service its current or future indebtedness, the Partnership will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing its indebtedness or seeking additional equity capital. The Partnership may not be able to effect any of these remedies on satisfactory terms or at all.

 

The Partnership’s credit facility has substantial restrictions and financial covenants that could restrict its business and financing activities and its ability to pay distributions.

 

The operating and financial restrictions and covenants in the Partnership’s credit facility and any future financing agreements could restrict its ability to finance future operations or capital needs or to engage, expand or pursue its business activities or to pay distributions. The Partnership’s credit facility limits, and any future credit facility could limit, its ability to:

 

 

 

 

The Partnership also is required to comply with certain financial covenants and ratios, such as a leverage ratio, an interest coverage ratio and a net present value of projected future cash flows from its oil and gas assets to total debt ratio. The Partnership’s ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from its operations and events or circumstances beyond its control. If market or other economic conditions deteriorate, the Partnership’s ability to comply with these covenants may be impaired. If the Partnership violates any of the restrictions, covenants, ratios or tests in its credit facility, its indebtedness may become immediately due and payable, its ability to make distributions may be inhibited, and its lenders’ commitment to make further loans to it may terminate. The Partnership might not have, or be able to obtain, sufficient funds to make these accelerated payments. See "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Commitments, Capital Resources and Liquidity — Liquidity."

 

The Partnership’s operations are subject to operational hazards and unforeseen interruptions for which the Partnership may not be adequately insured.

 

There are a variety of operating risks inherent in the Partnership’s wells, gathering systems and associated facilities, such as leaks, explosions, mechanical problems and natural disasters, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of its operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of its operations and substantial revenue losses. The location of the Partnership’s wells, gathering systems and associated facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.

 

The Partnership is not fully insured against all risks. In addition, pollution and environmental risks generally are not fully insurable. Additionally, the Partnership may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for the Partnership to obtain certain types of coverage. There can be no assurance that the Partnership will be able to obtain the levels or types of insurance the Partnership would otherwise have obtained prior to these market changes or that the insurance coverage the Partnership does obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and a delay in the payment of insurance proceeds could adversely affect the Partnership’s business, financial condition, results of operations and ability to make distributions to its unitholders. The Partnership is listed as a named insured on the insurance policies that Pioneer carries with respect to its own assets. Losses by Pioneer will erode the coverage levels under the policy, and if Pioneer sustains a catastrophic loss for which the coverage under the policy is entirely exhausted, the Partnership would not have coverage for its losses occurring prior to the time that the Partnership was able to obtain additional coverage.

 

The Partnership’s business depends in part on gathering, transportation, storage and processing facilities owned by Pioneer and others. Any limitation in the availability of those facilities could interfere with the Partnership’s ability to market its oil, NGL and gas production and could harm its business.

 

The marketability of the Partnership’s oil, NGL and gas production depends in part on the availability, proximity and capacity of pipelines and storage facilities, oil, NGL and gas gathering systems and processing facilities. The amount of oil, NGL and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline or processing facility interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on such systems. For example, substantially all of the Partnership’s gas is processed at the Midkiff/Benedum and Sale Ranch gas processing plants. If either or both of these plants were to be shut down, the Partnership might be required to shut in production from the wells serviced by those plants. The curtailments arising from these and similar circumstances could last from a few days to several months. In many cases, the Partnership is provided only with limited, if any, notice as to when these circumstances will arise and their duration. For example, as described in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Recent Events," during the second week of September 2008, Hurricane Ike struck the Texas gulf coast, damaging third-party downstream production handling and processing facilities. As a result, sales of portions of the Partnership's third quarter and fourth quarter 2008 NGL volumes were delayed and oil and gas production from certain of the Partnership's properties were temporarily curtailed. Any significant curtailment in gathering system, pipeline, storage or processing capacity could reduce the Partnership’s ability to market its oil, NGL and gas production and harm its business.

 

 

Shortages of drilling rigs, supplies, oilfield services, equipment and crews could delay the Partnership’s operations and reduce its cash available for distribution.

 

To the extent that in the future the Partnership acquires and develops undeveloped properties, including its rights to drill downspaced wells, higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Until recently, oil and gas companies have generally experienced increasing drilling and operating costs over the past three years. Although the Partnership has experienced decreases in these costs over the past several months, such decreases could be short-lived. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict the Partnership’s ability to drill wells and conduct operations. Any delay in the drilling of new wells or significant increase in drilling costs could reduce its future revenues and cash available for distribution.

 

Development drilling involves risks and may not result in commercially productive reserves.

 

Drilling involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

 

Any future drilling activities by the Partnership may not be successful and, if unsuccessful, such failure could have an adverse effect on the Partnership's future results of operations and financial condition.

 

The third parties on whom the Partnership relies for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting the Partnership’s business.

 

The operations of the third parties on whom the Partnership relies for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulation. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes could affect the costs that the Partnership pays for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom the Partnership relies could have a material adverse effect on the Partnership’s business, financial condition, results of operations and ability to make distributions to unitholders. See "Item 1. Business — Competition, Markets and Regulations" above for additional discussion regarding government regulation.

 

Third-party pipelines and other facilities interconnected to the Partnership’s gas pipelines and processing facilities could become partially or fully unavailable to transport gas.

 

The Partnership depends upon third-party pipelines and other facilities that provide delivery options to and from pipelines and processing facilities that the Partnership utilizes. Because the Partnership does not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within the Partnership’s control. If any of these third-party pipelines and other facilities become partially or fully unavailable to transport gas, or if the gas quality specifications for these pipelines or facilities change so as to restrict the Partnership’s ability to transport gas on these pipelines or facilities, the Partnership’s revenues and cash available for distribution could be adversely affected.

 

The nature of the Partnership’s assets exposes it to significant costs and liabilities with respect to environmental and operational safety matters.

 

The Partnership could incur significant costs and liabilities as a result of environmental and safety requirements applicable to its oil and gas production activities. These costs and liabilities could arise under a wide range of

 

 

federal, state and local environmental and safety laws and regulations, including agency interpretations of the foregoing and governmental enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property could result from environmental and other impacts of the Partnership’s operations.

 

Strict, joint and several liability may be imposed under certain environmental laws, which could cause the Partnership to become liable for the conduct of others or for consequences of its own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If the Partnership is not able to recover the resulting costs through insurance or increased revenues, its ability to make distributions to its unitholders could be adversely affected. See "Item 1. Business — Competition, Markets and Regulations" above for additional discussion regarding government regulation.

 

Risks Related to an Investment in the Partnership

 

The General Partner and its affiliates own a controlling interest in the Partnership and will have conflicts of interest with the Partnership. The Partnership Agreement limits the fiduciary duties that the General Partner owes to the Partnership, which may permit it to favor its own interests to the Partnership’s detriment, and limits the circumstances under which unitholders may make a claim relating to conflicts of interest and the remedies available to unitholders in that event.

 

Pioneer owns a 68.3 percent limited partner interest in the Partnership and Pioneer owns and controls the General Partner, which controls the Partnership. The directors and officers of the General Partner have a fiduciary duty to manage the General Partner in a manner beneficial to Pioneer. Furthermore, certain directors and officers of the General Partner are directors or officers of affiliates of the General Partner, including Pioneer. Conflicts of interest may arise between Pioneer and its affiliates, including the General Partner, on the one hand, and the Partnership on the other hand. As a result of these conflicts, the directors and officers of the General Partner may favor the interests of the General Partner and the interests of its affiliates over the Partnership’s interests. These potential conflicts include, among others, the following situations:

 

 

See Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and "Item 13. Certain Relationships and Related Transactions, and Director Independence."

 

 

The Partnership relies on Pioneer to identify and evaluate prospective oil and gas assets for the Partnership’s acquisitions. Pioneer has no obligation to present the Partnership with potential acquisitions and is not restricted from competing with the Partnership for potential acquisitions.

 

Because the Partnership does not have any officers or employees, the Partnership relies on Pioneer to identify and evaluate for the Partnership oil and gas assets for acquisition. Pioneer is not obligated to present the Partnership with potential acquisitions. The Partnership Agreement does not prohibit Pioneer from owning assets or engaging in businesses that compete directly or indirectly with the Partnership. In addition, Pioneer may acquire, develop or dispose of additional oil and gas properties or other assets in the future, without any obligation to offer the Partnership the opportunity to purchase or develop any of those properties. Pioneer is a large, established participant in the oil and gas industry, and has significantly greater resources and experience than the Partnership has, which factors could make it more difficult for the Partnership to compete with Pioneer. If Pioneer fails to present the Partnership with, or successfully competes against the Partnership for, potential acquisitions, the Partnership may not be able to replace or increase the Partnership’s production and proved reserves, which would adversely affect the Partnership’s cash from operations and the Partnership’s ability to make cash distributions.

 

Cost reimbursements to Pioneer and the General Partner and their affiliates for services provided, which are determined by the General Partner, can be substantial and reduce the Partnership’s cash available for distribution to unitholders.

 

The Partnership Agreement requires the Partnership to reimburse the General Partner and its affiliates for all actual direct and indirect expenses they incur or actual payments they make on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner or its affiliates in connection with operating the Partnership’s business, including overhead allocated to the General Partner by its affiliates, including Pioneer. These expenses include salary, bonus, incentive compensation (including equity compensation) and other amounts paid to persons who perform services for the Partnership or on the Partnership’s behalf, and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine in good faith the expenses that are allocable to the Partnership. The Partnership is a party to agreements with Pioneer, the General Partner and certain of their affiliates, pursuant to which the Partnership makes payments to the General Partner and its affiliates. Payments for these services can be substantial and reduce the amount of cash available for distribution to unitholders. See Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and "Item 13. Certain Relationships and Related Transactions, and Director Independence" for a discussion of some of these agreements.

 

The Partnership does not have any officers or employees and relies solely on officers of the General Partner and employees of Pioneer. Failure of such officers and employees to devote sufficient attention to the management and operation of the Partnership’s business could adversely affect the Partnership’s financial results and the Partnership’s ability to make distributions to unitholders.

 

None of the officers of the General Partner are employees of the General Partner. The Partnership and Pioneer have entered into an administrative services agreement pursuant to which Pioneer manages the Partnership’s assets and performs other administrative services for the Partnership. Pioneer conducts businesses and activities of its own in which the Partnership has no economic interest. If these separate activities are significantly greater than the Partnership’s activities, there could be material competition for the time and effort of the officers and employees who provide services to the General Partner and Pioneer. If the officers of the General Partner and the employees of Pioneer do not devote sufficient attention to the management and operation of the Partnership’s business, its financial results could suffer and its ability to make distributions to unitholders could be reduced.

 

The Partnership can issue an unlimited number of additional units, including units that are senior to the common units, without the approval of unitholders, which would dilute their existing ownership interests.

 

The Partnership Agreement does not limit the number of additional common units that the Partnership can issue at any time without the approval of the Partnership’s unitholders. In addition, the Partnership can issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by the Partnership of additional common units or other equity securities of equal or senior rank would have the following effects:

 

 

 

 

 

 

The Partnership Agreement provides that the General Partner’s fiduciary duties are limited and only owed to the Partnership, not to the Partnership’s unitholders, and restricts the remedies available to unitholders for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duty.

 

The Partnership Agreement contains provisions that reduce the standards to which the General Partner would otherwise be held by state fiduciary duty law. For example, the Partnership Agreement:

 

 

 

 

 

 

 

 

By purchasing a common unit, a unitholder will become bound by the provisions of the Partnership Agreement, including the provisions described above, and a unitholder will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.

 

Unitholders have limited voting rights and are not entitled to elect the General Partner or its directors or initially to remove the General Partner without its consent.

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting the Partnership’s business and, therefore, limited ability to influence management’s decisions. Unitholders have no right to elect the General Partner or its Board of Directors on an annual or other continuing basis. The Board of Directors of the General Partner is chosen entirely by Pioneer and not by the Partnership’s unitholders. Furthermore, even if unitholders are dissatisfied with the performance of the General Partner, they currently have no practical ability to remove the General Partner because Pioneer owns a sufficient number of units to prevent a removal of the General Partner. The vote of the holders of at least 66-2/3 percent of all outstanding units voting together as a single class is required to remove the General Partner and, Pioneer currently owns approximately 68.4 percent of the outstanding common units.

 

The Partnership Agreement restricts the voting rights of unitholders, other than the General Partner and its affiliates, owning 20 percent or more of the Partnership’s common units, which could limit the ability of significant unitholders to influence the manner or direction of management.

 

The Partnership Agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than the General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors of the General Partner, cannot vote on any matter. The Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about the Partnership’s operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

 

The General Partner has a limited call right that could require unitholders to sell their common units at an undesirable time or price.

 

If at any time the General Partner and its affiliates own more than 80 percent of the common units, the General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to the Partnership, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders could be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders also could incur a tax liability upon a sale of common units.

 

Unitholders who are not Eligible Holders may not be entitled to receive distributions on or allocations of income or loss on their common units, and their common units could become subject to redemption.

 

In order to comply with U.S. laws with respect to the ownership of interests in oil and gas leases on United States federal lands, the Partnership Agreement allows the Partnership to adopt certain requirements regarding those investors who may own common units. As used in this Report, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; (3) a public body, including a municipality; or (4) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases on United States federal lands or any direct or indirect interest therein may be acquired and held by aliens

 

 

only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. In the future, if the Partnership owns interests in oil and gas leases on United States federal lands, the General Partner may require unitholders to certify that they are an Eligible Holder. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder may run the risk of (1) if they have not delivered a required Eligible Holder Certification, having quarterly distributions on such units withheld or (2) having their units acquired by the Partnership at the lower of the purchase price of their units or the then current market price, as determined by the General Partner. The redemption price may be paid in cash or by delivery of an unsecured promissory note that shall be subordinated to the extent required by the terms of the Partnership’s other indebtedness, as determined by the General Partner.

 

Unitholders may not have limited liability if a court finds that unitholder action constitutes control of the Partnership’s business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. The Partnership is organized under Delaware law and will initially conduct business only in the State of Texas. Unitholders could have unlimited liability for the Partnership’s obligations if a court or government agency determined that their right to act with other unitholders to remove or replace the General Partner, to approve some amendments to the Partnership Agreement or to take other actions under the Partnership Agreement constituted "control" of the Partnership’s business.

 

Unitholders may have liability to repay distributions.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the "Delaware Act"), the Partnership may not make a distribution to unitholders if the distribution would cause the Partnership’s liabilities to exceed the fair value of its assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the Partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the Partnership that are known to such purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the Partnership Agreement.

 

The General Partner’s interest in the Partnership and the control of the General Partner may be transferred to a third party without unitholder consent.

 

The General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the Partnership Agreement on the ability of Pioneer to transfer its equity interest in the General Partner to a third party. The new equity owner of the General Partner would then be in a position to replace the Board of Directors and officers of the General Partner with their own choices and to influence the decisions taken by the Board of Directors and officers of the General Partner.

 

Affiliates of the General Partner could sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

 

Pioneer holds an aggregate of 20,521,200 common units. The sale of these units in the public markets could have an adverse impact on the price of the common units.

 

An increase in interest rates could cause the market price of the common units to decline.

 

Like all equity investments, an investment in the common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities could cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited partnership interests. Reduced demand for the common units resulting from investors seeking other more favorable investment opportunities could cause the trading price of the common units to decline.

 

 

Tax Risks to Common Unitholders

 

The Partnership’s tax treatment depends on its status as a partnership for federal income tax purposes. If the Internal Revenue Service ("IRS") were to treat the Partnership as a corporation for federal income tax purposes, the Partnership’s cash available for distribution would be substantially reduced.

 

The anticipated after-tax economic benefit of an investment in the common units depends largely on the Partnership being treated as a partnership for federal income tax purposes. The Partnership has not requested, and does not plan to request, a ruling from the IRS on this or any other tax matter affecting the Partnership.

 

Despite the fact that the Partnership is a limited partnership under Delaware law, it is possible in certain circumstances for a partnership to be treated as a corporation for federal income tax purposes. Although the Partnership does not believe, based upon its current operations, that it will be treated as a corporation, a change in its business (or a change in current law) could cause the Partnership to be treated as a corporation for federal income tax purposes or otherwise subject it to federal taxation as an entity.

 

If the Partnership were treated as a corporation for federal income tax purposes, the Partnership would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35 percent, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon the Partnership as a corporation, the Partnership’s cash available for distribution would be substantially reduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of the common units.

 

Current law could change so as to cause the Partnership to be treated as a corporation for federal income tax purposes or otherwise subject the Partnership to entity-level federal taxation. Any such changes could negatively impact the value of an investment in the common units.

 

A material amount of entity-level taxation by individual states would reduce the Partnership’s cash available for distribution.

 

Changes in current state law could subject the Partnership to entity-level taxation by those individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, beginning in 2008, the Partnership is required to pay an annual Texas Margin tax at a maximum effective rate of 0.7 percent of its gross income apportioned to Texas in the prior year. Imposition of such a tax on the Partnership by Texas and, if applicable, by any other state will reduce the cash available for distribution.

 

The IRS could challenge the Partnership’s proration of its items of income, gain, loss and deduction between transferors and transferees of common units, which could change the allocation of items of income, gain, loss and deduction among the Partnership’s unitholders.

 

The Partnership prorates its items of income, gain, loss and deduction between transferors and transferees of the Partnership’s units each month based upon the ownership of the Partnership’s units on the first day of each month, instead of on the basis of the date a particular unit is transferred. If the IRS were to challenge this method or new Treasury regulations were issued, the Partnership could be required to change the allocation of items of income, gain, loss and deduction among the Partnership’s unitholders.

 

The IRS could contest the federal income tax positions the Partnership takes.

 

The Partnership has not requested a ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes or any other matter affecting it. The IRS could adopt positions that differ from the positions the Partnership takes. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions the Partnership takes, and a court could disagree agree with some or all of the Partnership’s positions. The costs of any contest with the IRS would reduce the Partnership’s cash available for distribution.

 

 

Unitholders could be required to pay taxes on their share of the Partnership’s income even if they do not receive any cash distributions from the Partnership.

 

Because the Partnership’s unitholders are treated as partners to whom the Partnership allocates taxable income, which could be different in amount than the cash the Partnership distributes, unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of the Partnership’s taxable income even if they receive no cash distributions from the Partnership. Unitholders may not receive cash distributions from the Partnership equal to their share of the Partnership’s taxable income or even equal to the actual tax liability that results from that income.

 

Tax gain or loss on the disposition of common units could be more or less than expected.

 

If a unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and its tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of the Partnership’s net taxable income decreases its tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units the unitholders sells will, in effect, become taxable income to the unitholder if its sells such units at a price greater than its tax basis in those units, even if the price it receives is less than its original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of the Partnership’s nonrecourse liabilities, if a unitholder sells its common units, it may incur a tax liability in excess of the amount of cash it receives from the sale.

 

Tax-exempt entities and foreign persons face unique tax issues from owning common units that could result in adverse tax consequences to them.

 

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-U.S. persons, raises issues unique to them. For example, virtually all of the Partnership’s income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of the Partnership's taxable income.

 

The Partnership will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased, which could be challenged by the IRS.

 

Because the Partnership cannot match transferors and transferees of common units and because of other reasons, the Partnership has adopted depreciation, depletion and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could result in audit adjustments to a unitholder’s tax returns.

 

The sale or exchange of 50 percent or more of the Partnership’s capital and profits interests during any twelve-month period will result in the termination of the Partnership for federal income tax purposes.

 

The Partnership will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in the Partnership’s capital and profits within a twelve-month period. The Partnership’s termination would, among other things, result in the closing of the Partnership’s taxable year for all unitholders, which would result in the Partnership filing two tax returns (and unitholders receiving two Schedule K-1’s) for one fiscal year. The Partnership’s termination could also result in a deferral of depreciation deductions allowable in computing its taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of the Partnership’s taxable year may also result in more than twelve months of the Partnership’s taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Under current law, the Partnership’s termination would not affect its classification as a partnership for federal income tax purposes, but instead, the Partnership would be treated as a new partnership for tax purposes. If treated as a new partnership, the Partnership must make new tax elections and could be subject to penalties if the Partnership is unable to determine that a termination occurred.

 

 

A unitholder could become subject to state and local taxes and return filing requirements in some of the states in which the Partnership may make future acquisitions of oil and gas assets.

 

In addition to federal income taxes, a unitholder could become subject to state and local taxes that are imposed by various jurisdictions in which the Partnership extends its business or acquires assets even if the unitholder does not live in any of those jurisdictions. The Partnership currently owns assets and does business only in Texas. Texas does not currently impose a personal income tax on individuals but it does impose an entity level tax (to which the Partnership is subject) on corporations and other entities. As the Partnership makes acquisitions or expands its business, the Partnership could own assets or conduct business in additional states (such as New Mexico) that impose a personal income tax, and in that case a unitholder could be required to file state and local income tax returns and pay state and local taxes or face penalties if it fails to do so. It is the unitholder’s responsibility to file all United States federal, foreign, state and local tax returns applicable to it in its particular circumstances.

 

 

ITEM 1B.        UNRESOLVED STAFF COMMENTS

 

None.

 

 

The information included in this Report about the Partnership's proved reserves as of December 31, 2008 was based on evaluations prepared by Pioneer's engineers and audited by Netherland, Sewell & Associates, Inc. ("NSAI"). The information included in this Report about the Partnership’s proved reserves as of December 31, 2007 and 2006 represents evaluations by Pioneer’s engineers of the Partnership Predecessor’s proved reserves before the Partnership purchased incremental working interests in certain of the Partnership Properties with the proceeds from the exercise of the underwriters’ over-allotment option associated with the Offering (the "Original Evaluations"). NSAI audited the Original Evaluations of the Partnership Predecessor’s proved reserves as of December 31, 2007 and 2006. The proved reserves that NSAI audited have been increased by approximately six percent and five percent as of December 31, 2007 and 2006, respectively, to recognize the proved reserves attributable to the incremental working interests in certain of the Partnership Properties that were purchased with the proceeds from the exercise of the underwriters’ over-allotment option and, together with the NSAI audited proved reserves, form the basis for the information included in this Report about the Partnership’s proved reserves as of December 31, 2007 and 2006.

 

NSAI follows the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers ("SPE"). A reserve audit as defined by the SPE is not the same as a financial audit. The SPE's definition of a reserve audit includes the following concepts:

 

 

To further clarify, in conjunction with the audit of the Partnership's proved reserves and associated pre-tax present value discounted at ten percent, Pioneer provided to NSAI its external and internal engineering and geoscience technical data and analyses. Following NSAI's review of that data, it had the option of honoring Pioneer's interpretation, or making its own interpretation. No data was withheld from NSAI. NSAI accepted without independent verification the accuracy and completeness of the historical information and data furnished by Pioneer with respect to ownership interest; oil and gas production; well test data; commodity prices; operating and development costs; and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its evaluation something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.

 

In the course of its evaluations, NSAI prepared, for all of the audited properties, its own estimates of the Partnership's proved reserves and the pre-tax present value of such reserves discounted at ten percent. NSAI reviewed its audit differences with Pioneer, and, in a number of cases, held joint meetings with Pioneer to review additional reserves work performed by the technical teams and any updated performance data related to the reserve differences. Such data was incorporated, as appropriate, by both parties into the reserve estimates. NSAI's estimates, including any adjustments resulting from additional data, of those proved reserves and the pre-tax present value of such reserves discounted at ten percent did not differ from Pioneer's estimates by more than ten percent in the aggregate. However, when compared on a lease-by-lease basis, some of Pioneer's estimates were greater than those of NSAI and some were less than the estimates of NSAI. When such differences do not exceed ten percent in the aggregate and NSAI is satisfied that the proved reserves and pre-tax present value of such reserves discounted at ten

 

 

percent are reasonable and that its audit objectives have been met, NSAI will issue an unqualified audit opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analyses by Pioneer and NSAI. At the conclusion of the audit process, it was NSAI's opinion, as set forth in its audit letter, that Pioneer's estimates of the Partnership's proved oil and gas reserves and associated pre-tax future net revenues discounted at ten percent are, in the aggregate, reasonable and have been prepared in accordance with petroleum engineering and evaluation principles.

 

The Partnership did not provide estimates of total proved oil and gas reserves during 2008, 2007 or 2006 to any federal authority or agency, other than the SEC. The Partnership's reserve estimates do not include any probable or possible reserves. Also, see "Item 1A. Risk Factors" and "Critical Accounting Estimates" in "Item 7. Management's Discussion and Analysis and Results of Operations" for additional discussions regarding proved reserves and their related cash flows.

 

Proved Reserves

 

The Partnership's proved reserves totaled 22,643 MBOE, 36,162 MBOE and 34,615 MBOE at December 31, 2008, 2007 and 2006, respectively, representing $121.9 million, $681.7 million and $419.2 million, respectively, of Standardized Measure. Changes in the Partnership's proved reserve volumes during the year ended December 31, 2008 included production of 1,761 MBOE and revisions of previous estimates of 11,758 MBOE. Revisions of previous estimates are comprised of 9,764 MBOE of negative price revisions, 1,826 MBOE of negative revisions due to the Partnership being charged a COPAS fee beginning in May 2008 (close of the Offering) and 168 MBOE of negative technical revisions. The Partnership's proved reserves at December 31, 2008 were determined using year-end NYMEX equivalent prices of $44.60 per barrel of oil and $5.71 per Mcf of gas, compared to $95.92 per barrel of oil and $6.80 per Mcf of gas at December 31, 2007.

 

All of the Partnership's total proved reserves at December 31, 2008 were proved developed reserves. The following table provides information regarding the Partnership's proved reserves, Standardized Measure and average daily sales volumes as of and for the year ended December 31, 2008:

 

 

Description of Properties

 

Currently, the Partnership’s oil and gas properties consist only of non-operated working interests in approximately 1,100 producing wells, all of which are operated by Pioneer. The Partnership only owns mineral interests and leasehold interests in these producing wells (often referred to as wellbore assignments), and does not own any undeveloped properties or leasehold acreage. The Partnership’s rights as to each wellbore are limited to only those rights that are necessary to produce hydrocarbons from that particular wellbore, and do not include the right to drill additional wells (other than replacement wells or downspaced wells, such as 20-acre infill wells) within the area covered by the mineral or leasehold interest to which that wellbore relates. Accordingly, the Partnership’s properties do not include any undeveloped properties or leasehold acreage.

 

All of the Partnership's proved reserves at December 31, 2008 were located in the Spraberry field in the Permian Basin area of West Texas. According to the Energy Information Administration, the Spraberry field is the fifth largest oil field in the United States. The field was discovered in 1949 and encompasses eight counties in West Texas. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casinghead gas with an average energy content of 1,400 Btu. The oil and gas are produced primarily from three formations, the upper and lower Spraberry and the Dean, at depths ranging from 6,700 feet to 9,200 feet.

 

During 2008, the Partnership did not drill any wells or acquire any additional acreage. Costs incurred for 2008 totaled $146.9 million and was comprised of $141.8 million, representing Pioneer's carrying value of the net assets at the completion date of the Offering, $1.1 million of development expenditures associated with existing wells and a $4.0 million increase in asset retirement obligations due to lower year-end commodity prices which had the effect of shortening the lives of many wells thus increasing the present value of future retirement obligations.

 

 

See Note B. "Summary of Significant Accounting Policies – Allocation of Owner's Net Equity and Partners' Equity" of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data."

 

Selected Oil and Gas Information

 

The following tables set forth selected oil and gas information for the Partnership Properties as of and for each of the years ended December 31, 2008, 2007 and 2006. Because of normal production declines and drilling activities, the historical information presented below should not be interpreted as being indicative of future results.

 

Production, price and cost data. The following tables set forth production, price and cost data with respect to the Partnership Properties for the years ended December 31, 2008, 2007 and 2006. These amounts represent the Partnership's historical results without making pro forma adjustments for any drilling activity that occurred during the respective years.

 

PRODUCTION, PRICE AND COST DATA

 

 

__________

 

 

 

Productive wells. The following table sets forth the number of productive oil and gas wells attributable to the Partnership Properties as of December 31, 2008, 2007 and 2006:

 

PRODUCTIVE WELLS (a)

 

 

__________

            

Drilling activities. The following table sets forth the number of gross and net productive and dry hole wells that were drilled during 2008, 2007 and 2006, in which the Partnership owns an interest. This information should not be considered indicative of future performance, nor should it be assumed that there was any correlation between the number of productive wells drilled and the oil and gas reserves generated thereby or the costs to the Partnership of productive wells compared to the costs of dry holes.

 

DRILLING ACTIVITIES

 

 

 

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

 

 

 

 

PART II

 

 

The Partnership's common units are listed and traded on the NYSE under the symbol "PSE." The Board of Directors of the General Partner declared distributions to unitholders of $0.81 per unit during the year ended December 31, 2008. Prior to the Offering in May 2008, all distributions were made to Pioneer. On January 27, 2009, the Board of Directors of the General Partner declared a $0.50 per unit distribution payable on February 12, 2009 to unitholders of record on February 6, 2009.

 

The following table sets forth quarterly high and low prices of the Partnership's common units and distributions declared per unit for the year ended December 31, 2008:

 

__________

 

On March 4, 2009, the last reported sales price of the Partnership's common units, as reported in the NYSE composite transactions, was $13.96 per unit.

 

As of March 4, 2009, the Partnership's common units were held by approximately 11 holders of record. This number does not include owners for whom common units may be held in "street" name.

 

Cash Distributions to Unitholders

 

The Partnership Agreement requires that, within 45 days after the end of each quarter, the Partnership distribute all of its available cash quarterly. The term “available cash,” for any quarter, means the Partnership’s cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of cash reserves for future capital expenditures, operational needs and distributions for any one or more of the next four quarters.

 

There is no guarantee that unitholders will receive quarterly distributions from the Partnership. The Partnership Agreement gives the General Partner wide latitude to establish reserves for future capital expenditures and operational needs prior to determining the amount of cash available for distribution. In addition, the Partnership's credit facility prohibits the Partnership from making cash distributions if any potential default or event of default, as defined in the credit facility, occurs or would result from the distribution.

 

As described in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Events – Commodity prices, " the duration and magnitude of commodity price declines that have occurred during the second half of 2008 cannot be predicted, but a sustained decline in commodity prices could result in a decrease to unitholder distributions in the future.

 

 

ITEM 6.       SELECTED FINANCIAL DATA

 

The following selected consolidated financial data as of and for each of the five years ended December 31, 2008 for the Partnership should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 8. Financial Statements and Supplementary Data."

 

 

__________

 

 

 

 

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 from May 6, 2008, and the Partnership Predecessor, for all periods prior to May 6, 2008. The Partnership commenced operations on May 6, 2008 upon completion of the Offering and the related transactions.

 

The transfer of the ownership interests in Pioneer Southwest USA to the Partnership that took place at the closing of the Offering represented a reorganization of entities under common control and was recorded at Pioneer’s carrying value. Accordingly, the Partnership's financial statements include the historical results of operations of the Partnership Predecessor prior to the transfer to the Partnership. Associated with the Offering, the proceeds from the exercise of the underwriters' over-allotment option were used by the Partnership to purchase incremental working interests in certain Partnership Properties, thereby effecting a change in reporting entity.  As a result of the change in reporting entity, the financial position, results of operations and cash flows of the Partnership, as of and for the years ended December 31, 2007 and 2006, were recast.  See Note B "Summary of Significant Accounting Policies—Presentation" of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data."

 

Significant Events

 

Financial markets. During the second half of 2008, worldwide financial markets experienced significant turmoil as concerns regarding a worldwide economic slowdown increased and the availability of liquidity provided by the financial markets declined. These concerns have continued into the first quarter of 2009. In response to these circumstances, governments worldwide have taken steps to enhance confidence and support the financial markets. The success of the steps taken and the duration of the uncertainty in the financial markets cannot be predicted. The Partnership is closely monitoring the economic environment, the impact of which is mitigated by the Partnership's derivative price risk management activities. As a result, the Partnership does not expect that current market conditions will significantly impact its near-term liquidity, future results of operations or financial position. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Partnership's derivative contracts.

 

As of December 31, 2008, the Partnership had $29.9 million of cash and cash equivalents on deposit, held approximately $11.0 million of accounts receivable from purchasers of oil, NGL and gas production, was a party to derivative financial instruments, representing $117.1 million of Partnership assets, had no outstanding long-term debt and had approximately $200 million of available borrowing capacity under its credit facility. The amount of liquidity under the credit facility is subject to a covenant requiring that the Partnership maintain a specified ratio of the net present value of the Partnership's projected future cash flows from its oil and gas assets to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. Therefore, the amount that the Partnership may borrow under the credit facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items. The Partnership is monitoring the liquidity and the credit standings of its counterparties, including its banks, derivative counterparties and purchasers of the commodities the Partnership produces and sells.

 

 

 

Commodity prices. The reduced liquidity provided by the worldwide financial markets and other factors have resulted in an economic slowdown in the United States and other industrialized countries, which has further resulted in significant reductions in worldwide energy demand. At the same time, North American gas supply has increased as a result of the rise in domestic unconventional gas production during 2008 and prior years. The combination of lower demand due to the economic slowdown and higher North American gas supply has resulted in significant declines in oil, NGL and gas prices from their highs earlier in 2008. Although the Partnership has entered into derivative contracts on a large portion of its production volumes for the next three years, a sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Partnership could enter into derivative contracts on additional volumes in the future. As a result, the Partnership's internal cash flows would be reduced for affected periods. The duration and magnitude of the commodity price declines cannot be predicted. A sustained decline in commodity prices could result in a shortfall in expected cash flows and require the Partnership to reduce its distributions.

 

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 500 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 incremental working interests in certain of the oil and gas properties owned by Pioneer Southwest USA.

 

The acquisition of the incremental interest in certain of the oil and gas properties owned by Pioneer Southwest USA resulted in a change in reporting entity for periods prior to May 6, 2008. Accordingly, the historic financial position, results of operations and cash flows of the Partnership Predecessor have been recast in this Report to effect the change in reporting entity. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the change in reporting entity.

 

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. 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 commodity sales being hedged. See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding these derivative instruments.

 

Midkiff-Benedum Gas Processing System. During the second half of 2008, Pioneer entered into negotiations with the Partnership relating to the assignment of a portion of Pioneer's option to acquire an interest in the Spraberry Midkiff-Benedum gas processing system (the "System") in West Texas from Atlas Pipeline Partners. The Partnership and Pioneer decided not to pursue the assignment or the acquisition of an interest in the System due to the uncertainty underlying market conditions.

 

Pioneer currently owns a 27 percent interest in the System and the option is exercisable for an additional 22 percent interest in the System for $230 million, subject to normal closing adjustments. All or a portion of the option must be exercised by November 2, 2009. Any portion of the option not exercised by that date will lapse. Based on current commodity prices, the Partnership does not expect Pioneer to exercise the option or assign the option to the Partnership.

 

 

2009 Outlook

 

Commodity prices. The oil, NGL and gas markets are highly volatile, and the Partnership cannot predict future oil, NGL and gas prices. Prices for oil, NGL and gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, NGL and gas, market uncertainty and a variety of additional factors that are beyond the Partnership's control, such as worldwide economic conditions, developments in the issues currently impacting Iraq and Iran and the Middle East in general; the extent to which members of OPEC and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of weather conditions and increasing LNG deliveries to the United States. Although the Partnership cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that the Partnership produces will generally approximate current market prices in the geographic region of the production. From time to time, the Partnership expects that it may use derivative contracts to reduce a portion of its commodity price risk in order to mitigate the impact of price volatility on its oil, NGL and gas revenues. See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Partnership's commodity derivative positions at December 31, 2008. Also see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for disclosures about the Partnership's commodity related derivative financial instruments.

 

First Quarter 2009 outlook. Based on current estimates, the Partnership expects that first quarter 2009 production will average 4,600 to 4,800 BOEPD.

 

First quarter production costs (including production and ad valorem taxes) are expected to average $23.50 to $26.50 per BOE based on NYMEX strip prices for oil, NGLs and gas at the time of the estimate. Depletion, depreciation and amortization ("DD&A") expense is expected to average $5.75 to $6.75 per BOE, reflecting the loss of end-of-well-life reserves due to negative price revisions.

 

General and administrative expense is expected to be $1 million to $2 million. Interest expense and accretion of discount on asset retirement obligations are both expected to be nominal.

 

The Partnership's first quarter cash taxes and effective income tax rate are expected to be approximately one percent as a result of the Partnership being subject to the Texas Margin tax.

 

Derivative designations. Effective February 1, 2009, the Partnership discontinued hedge accounting on all existing commodity derivative instruments, and 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.

 

Acquisition and drilling opportunities. Pioneer has indicated to the Partnership that it is evaluating a sale of up to $200 million of producing assets to the Partnership. Additionally, the Railroad Commission of Texas recently approved fieldwide optional 20-acre downspacing for the Spraberry field, and the Partnership is evaluating the potential benefit of drilling on 20-acre downspacing if margins improve. The Partnership's proved reserves do not currently include reserves that could be recovered from these locations. Pioneer has reported that in 2008, it drilled 18 wells on 20-acre spacing with encouraging results, including the booking of additional proved reserves attributable to certain of Pioneer's 20-acre drilling locations.

 

Results of Operations

 

Oil and gas revenues. Oil and gas revenues totaled $152.8 million, $110.4 million and $106.5 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 54 percent and the average reported NGL price increased by 31 percent. Average reported gas prices increased 47 percent. The revenue increase during 2007, as compared to 2006, was primarily reflective of an increase in reported oil, NGL and gas prices, partially offset by a decrease in oil, NGL and gas volumes.

 

 

            

The following table provides average daily sales volumes for 2008, 2007 and 2006:

 

 

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. See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for additional information about these derivatives.

 

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 $43.2 million, $31.2 million and $28.8 million during 2008, 2007 and 2006, respectively. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Partnership has management control, while production taxes and ad valorem taxes are directly related to commodity price changes. Total production costs per BOE increased during 2008 by 54 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, (iii) increases in production taxes due to commodity price increases and (iv) 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 Properties for periods prior to the Offering. In May 2008, Pioneer, as operator, began charging the Partnership overhead charges associated with operating the Partnership Properties (commonly referred to as the Council of Petroleum Accountants Societies (or "COPAS") fee), instead of the direct internal costs incurred by Pioneer. Assuming the COPAS fee had been charged in the Partnership Predecessor's historical results, the lease operating expense would have been higher on a BOE basis by $1.02, $2.96 and $2.67 for 2008, 2007 and 2006, respectively.

 

 

Total production costs per BOE increased during 2007 by 16 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 tables provide the components of the Partnership's total production costs per BOE and total production costs per BOE for 2008, 2007 and 2006:

 

 

Depletion, depreciation and amortization expense. The Partnership's depletion expense was $4.26, $4.12 and $3.78 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 $4.8 million, $4.4 million and $4.5 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. For periods prior to the Offering, general and administrative expense consisted of an allocation of a portion of Pioneer's general and administrative expense based on the Partnership Predecessor's production as compared to Pioneer's total production from its United States properties (other than Alaska), as measured on a per-barrel-of-oil-equivalent basis. The Partnership and Pioneer entered into an Administrative Services Agreement as of May 6, 2008, pursuant to which Pioneer agreed to perform, either itself or through its affiliates or other third parties, administrative services for the Partnership, and the Partnership agreed to reimburse Pioneer for its expenses incurred in providing such services. Pioneer has informed the Partnership that expenses will be reimbursed based on a methodology of determining the Partnership's share, on a per BOE basis, of certain of the general and administrative costs incurred by Pioneer. Subsequent to the Offering, the Partnership is also responsible for paying for direct third-party services. See Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" 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. See Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" 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 $23 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 $1.1 million, $700 thousand and $95 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 "Item 8. Financial Statements and Supplementary Data" 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 acquisitions, production enhancements and/or drilling initiatives and for unitholder distributions. The Partnership may use any combination of internally- and externally-financed sources to fund acquisitions and unitholder distributions, including borrowings under its credit facility and funds from future private and public equity and debt offerings. As a result of the current circumstances in worldwide financial markets, the availability of external sources of short- and long-term capital funding is uncertain. Consequently, the Partnership expects that for the foreseeable future (i) capital expenditures and unitholder distributions will be funded by internal operating cash flows and (ii) acquisitions will be funded by cash reserves and availability under its credit facility. Although the Partnership expects that internal cash flows during 2009 will be adequate to fund capital expenditures and planned unitholder distributions, and that available borrowing capacity under its credit facility will provide adequate liquidity to fund future acquisitions or capital expenditures, no assurances can be given that such funding sources will be adequate to meet the Partnership's future needs.

 

The Partnership Agreement requires that the Partnership distribute all of its available cash to its partners. In general, available cash is defined to mean cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves for future capital expenditures (including acquisitions), operational needs and distributions for any one or more of the next four quarters. Because the Partnership's proved reserves and production decline continually over time, the Partnership will need to acquire income producing assets that provide cash margins that allow the Partnership to sustain its level of distributions to unitholders over time, or otherwise mitigate the declines through production enhancement or drilling initiatives. Currently, the Partnership is reserving approximately 25 percent of its cash flow to acquire income producing assets or drill downspaced locations in order to maintain its production and proved reserves. The Partnership has adopted a cash distribution policy pursuant to which it intends to declare distributions of $0.50 per unit per quarter, or $2.00 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter. The distribution for the fourth quarter of 2008 of $0.50 per unit was declared by the Board of Directors of the General Partner on January 27, 2009 and was paid on February 12, 2009 to unitholders of record on February 6, 2009.

 

Oil and gas properties. Excluding the 2008 acquisition of the Partnership properties 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 $1.9 million, $8.1 million and $15.9 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. The Partnership currently expects that cash flows from operations will be sufficient to fund its 2009 capital expenditures.

 

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. The Partnership's contingent VPP obligations have not materially changed since December 31, 2007. As of December 31, 2008, the Partnership’s derivative instruments represented assets of approximately $117.1 million; however, they continue to have market risk and represent contractual obligations of the Partnership. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Partnership’s derivative instruments. As of December 31, 2008, the Partnership's asset retirement obligations had increased approximately $4.0 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.

 

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

 

 

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

 

__________

 

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 future acquisitions.

 

Operating activities. Net cash provided by operating activities during 2008, 2007 and 2006 was $101.2 million, $71.6 million and $74.5 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.

 

As described in "Significant Events – Commodity prices," the commodity price declines that have occurred during the second half of 2008, although mitigated by the Partnership's derivative activities, will reduce the Partnership's internal cash flows. The duration and magnitude of the commodity price declines cannot be predicted, but a sustained decline in commodity prices could negatively impact the Partnership's ability to replace declining production and result in a decrease to unitholder distributions in the future.

 

Investing activities. Net cash used in investing activities during 2008 was $144.2 million, as compared to net cash used in investing activities of $8.1 million during 2007 and net cash used in investing activities of $15.9 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 properties in connection with the Offering in 2008. Future investing activities may include expenditures to drill a limited number of 20-acre locations surrounding the Partnership's wells if margins improve. The decrease in net cash used by investing activities during 2007, as compared to 2006, was primarily due to the completion of development drilling operations during 2007.

 

Financing activities. Net cash provided by financing activities for 2008 was $73.0 million, as compared to net cash used in financing activities of $63.5 million for 2007 and $58.6 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 acquisition of Partnership Properties for a purchase price in excess of carrying value and an increase in distributions to the Partnership's owner and partners. The Partnership's financing activities for periods prior to the Offering were limited to distributions of cash to Pioneer.

 

During 2008, the Partnership paid cash distributions to partners 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.

 

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 a $300 million revolving credit facility. As of December 31, 2008, the Partnership had approximately $200 million of available borrowing capacity under its credit facility. The Partnership's borrowing capacity under the credit facility is subject to a covenant requiring that the Partnership maintain a specified ratio of the net present value of the Partnership's projected future cash flows from its oil and gas assets to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. As a result,

 

 

further declines in commodity prices could reduce the Partnership's borrowing capacity under the facility. See Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" 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 its credit facility and, to the extent available, funds from future private and public equity and debt offerings. As discussed above under "Capital commitments," the Partnership Agreement requires that the Partnership distribute all of its available cash to its unitholders and the General Partner. In addition, because the Partnership's proved reserves and production decline continually over time, the Partnership will need to replace production to sustain its level of distributions to unitholders over time. Accordingly, the Partnership's primary needs for cash will be for production growth through acquisitions, production enhancements and/or drilling initiatives (such as 20-acre infill wells) and for distributions to partners. In making cash distributions, the General Partner will attempt to avoid large variations in the amount the Partnership distributes from quarter to quarter. The Partnership Agreement permits the General Partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters, and for the conduct of the Partnership's business, which includes possible acquisitions. A sustained decline in commodity prices could result in a shortfall in expected cash flows. If cash flow from operations does not meet the Partnership's expectations, the Partnership may reduce its level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of its capital expenditures using borrowings under its credit facility, issuances of debt or equity securities or from other sources, such as asset sales or reduced distributions. The Partnership cannot provide any assurance that needed capital will be available on acceptable terms or at all.

 

The Partnership Agreement allows the Partnership to borrow funds to make distributions. The Partnership may borrow to make distributions to unitholders, for example, in circumstances where the Partnership believes that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain its level of distributions. In addition, the Partnership plans to 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 Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" 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 "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Notes C and H of Notes to Consolidated Financial Statements included in "Item 8. Consolidated Financial Statements and Supplementary Data" for additional information about the Partnership’s derivative assets.

 

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. 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 Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" 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 producing activities 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 the Partnership's reservoir engineers and 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 included in this Report as of December 31, 2008 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" 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

 

The following discussions provide information about new accounting pronouncements that were issued by the Financial Accounting Standards Board ("FASB") during 2008:

 

SFAS 157. In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurement" ("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. 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 Partnership adopted the provisions of SFAS 157 for financial assets and liabilities. See Note C of Notes to Consolidated Financial Statements included in "Item 8 Financial Statements and Supplementary Data" for additional information regarding the Partnership's adoption of SFAS 157. The adoption of the provisions of SFAS 157 that were delayed by FSP FAS 157-2 is not expected to have a material effect on the financial condition or results of operations of the Partnership.

 

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

 

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) became effective for the Partnership on January 1, 2009. The implementation of SFAS 141(R) did not impact the financial condition or results of operations of the Partnership 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 Partnership on January 1, 2009 and will only impact future disclosures about the Partnership'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 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.

 

EITF 03-6-1. In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1 "Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities" ("FSP EITF 03-6-1"), which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the net income allocation in computing basic net income per share under the two class method prescribed under SFAS 128 "Earnings per Share." FSP 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and, to the extent applicable, must be applied retrospectively by adjusting all prior-period net income per share data to conform to the provisions of the standard. The adoption of FSP EITF 03-6-1 is not expected to have a material effect on the Partnership's net income per common unit calculations.

 

 

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 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. 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.

 

 

 

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 Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" 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):

 

 

_________

 

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.

 

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 Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" 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.

 

 

ITEM 8.       FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

Index to Consolidated Financial Statements

 

 

 

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC

ACCOUNTING FIRM

 

The Board of Directors of Pioneer Natural Resources GP LLC

and Unitholders of Pioneer Southwest Energy Partners L.P.:

 

We have audited the accompanying consolidated balance sheets of Pioneer Southwest Energy Partners L.P. (the "Partnership") as of December 31, 2008 and 2007, and the related consolidated statements of operations, partners' equity, cash flows and comprehensive income for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Partnership Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership's internal control over financial reporting. Our audits 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 Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit 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 financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Pioneer Southwest Energy Partners L.P. at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

 

 

 

 

Dallas, Texas

March 5, 2009

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit amounts)

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per data amounts)

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY

(in thousands)

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

 

 

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

 

 

 

 

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2008, 2007 and 2006

 

 

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

 

 

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

 

The proceeds from the exercise of the underwriters' over-allotment option in connection with the Offering were used by the Partnership to purchase incremental working interests in certain Partnership Properties, thereby effecting a change in the reporting entity as defined by generally accepted accounting principles in the United States ("GAAP"). The change in reporting entity has been retrospectively applied to all prior periods presented. As a result of the change, net income increased to $66.0 million and $65.1 million for 2007 and 2006, respectively, as compared to $61.7 million and $61.8 million, respectively, previously reported for the same periods.

 

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

 

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

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2008, 2007 and 2006

 

Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion 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.

 

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

 

Inventories. The Partnership's inventories consist of oil held in storage tanks and natural gas liquids ("NGLs") held in storage by the purchaser of the NGLs as of 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 Partnership has deferred revenue recognition of the NGL sales as of December 31, 2008. The Partnership's oil and NGL inventories are carried at the lower of average cost or market, on a first-in, first-out basis. Any impairments of inventory are reflected in other expense in the consolidated statements of operations. As of December 31, 2008, the Partnership's inventories were net of $159 thousand of valuation reserve allowances. See "Revenue recognition" for information regarding the Partnership's accounting policy for revenue recognition.

 

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

 

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

 

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

 

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

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2008, 2007 and 2006

 

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

 

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

 

Derivatives and hedging. The Partnership follows the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income. Under the provisions of SFAS 133, the Partnership may designate a derivative instrument as hedging the exposure to changes in the fair value of an asset or a liability or an identified portion thereof that is attributable to a particular risk (a "fair value hedge") or as hedging the exposure to variability in expected future cash flows that are attributable to a particular risk (a "cash flow hedge"). Both at the inception of a hedge and on an ongoing basis, a fair value hedge must be expected to be highly effective in achieving offsetting changes in fair value attributable to the hedged risk during the periods that a hedge is designated. Similarly, a cash flow hedge must be expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. The expectation of hedge effectiveness must be supported by matching the essential terms of the hedged asset, liability or forecasted transaction to the derivative hedge contract or by effectiveness assessments using statistical measurements. The Partnership's policy is to assess hedge effectiveness at the end of each calendar quarter.

 

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

 

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

 

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

 

Effective February 1, 2009, the Partnership discontinued hedge accounting on all existing commodity derivative instruments, and 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.

 

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

 

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

 

 

 

PIONEER SOUTHWEST ENERGY PARTNERS L.P.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2008, 2007 and 2006

 

Employee benefit plans. The Partnership does not have its own employees. However, for the periods presented prior to the Offering, a portion of the general and administrative expenses and lease operating expenses allocated to the Partnership Predecessor was noncash stock-based compensation recorded on the books of Pioneer. Subsequent to the Offering, the Partnership pays its allocated share of general and administrative expenses pursuant to an Administrative Services Agreement, as described in Note E below, and pays an industry standard COPAS fee with respect to lease operating expenses.

 

Segment reporting. The Partnership's only operating segment is oil and gas producing activities. Additionally, all of the Partnership Properties are located in the United States and all of the related oil, NGL and gas revenues are derived from purchasers located in the United States.

 

Income taxes. Prior to the Offering, the operations of the Partnership Predecessor were included in the federal income tax return of Pioneer. Following the Offering, the Partnership's operations are treated as a partnership with each partner being separately taxed on its share of the Partnership's federal taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying consolidated financial statements. However, the Texas Margin tax was signed into law on May 18, 2006 for tax years beginning on January 1, 2007, which caused the Texas franchise tax to be applicable to numerous types of entities that previously were not subject to the tax, including the Partnership. Accordingly, the Partnership reflects its deferred tax position associated with the future tax effect of the Texas Margin tax in the accompanying consolidated balance sheets.

 

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

 

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

 

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

 

Allocation of owner's net equity and partners' equity. The financial position, results of operations, cash flows and owner's equity of the Partnership for all periods presented prior to the Offering represent those of the Partnership Predecessor. In accordance with GAAP, the contribution and purchase of the Partnership Properties and other net assets from Pioneer were accounted for as transactions between entities under common control. Therefore, the net assets were recorded on the Partnership's balance sheet at $142.3 million, representing Pioneer's carrying value of the net assets and the owner's equity of the Partnership as of the Offering date. Accordingly, the $142.3 million carrying value of the net assets is presented as an allocation of owner's equity to the limited partners' and general partner's equity of Pioneer in the accompanying consolidated statement of partners' equity.

 

Pioneer's carrying value in the net assets acquired by the Partnership includes $2.0 million of noncash working capital contributed by Pioneer, representing net working capital earned from the Partnership Properties during the period from May 1, 2008 through May 5, 2008.

 

 

 

The following table provides Pioneer's carrying values in the assets and (liabilities) contributed to and acquired by the Partnership (in thousands):

 

 

The Partnership acquired a portion of the Partnership Properties from Pioneer for $163.1 million on the date of the Offering, which amount exceeded the carrying value of the net assets by $20.8 million. The $142.3 million portion of the Partnership's payment to Pioneer that is attributable to the carrying value of the Partnership Properties is reflected as an investing activity in the accompanying consolidated statement of cash flows and was recorded as a reduction of Pioneer's general partner's and limited partners' equity, as presented in the accompanying consolidated statement of partners’ equity. The Partnership's payment to Pioneer of $20.8 million in excess of the carrying value of the Partnership Properties is reflected in the accompanying consolidated statement of cash flows as a financing activity and as a reduction of Pioneer's limited partners' equity, as presented in the accompanying statement of partners' equity.

 

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. The novation of the derivative obligations was recorded as a reduction of Pioneer's limited partners' equity, as presented in the accompanying consolidated statement of partners’ equity. See Note H for additional information regarding the novated derivative instruments.

 

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

 

Net income per common unit. The Partnership calculates net income per common unit in accordance with SFAS No. 128, "Earnings Per Share" ("SFAS 128"). For 2008, net income per common unit is calculated by dividing the limited partners' interest in net income derived from operations subsequent to the Offering by the weighted average number of common units outstanding (representing 30,008,700 common units, comprising 20,521,200 common units held by Pioneer and the 9,487,500 common units issued in the Offering). Prior to the

 

 

 

Offering, the Partnership was wholly owned by Pioneer. Accordingly, net income per common unit is not presented for periods prior to the Offering.

 

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

 

For purposes of calculating net income per common unit, the Partnership allocates net income to its limited partners and its general partner each quarter under the provisions of Emerging Issues Task Force Issue No. 03-6, "Participating Securities and the Two-Class Method Under FASB Statement No. 128" ("EITF 03-6").

 

Stock-based compensation. The Partnership accounts for stock-based compensation under SFAS No. 123 (revised 2004), "Share-Based Payment" ("SFAS 123(R)"). The Partnership utilizes the unit price on the date of grant for the fair value of common unit awards.

 

For the years ended December 31, 2008, 2007 and 2006, the Partnership recorded $107 thousand, $0 and $0 of compensation costs associated with stock-based awards, respectively; however, a portion of the general and administrative expenses and lease operating expenses allocated to the Partnership Predecessor was noncash stock based compensation recorded by Pioneer.

 

New accounting pronouncements. The following discussions provide information about new accounting pronouncements that have been issued by FASB:

 

SFAS 157. In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" ("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 Partnership adopted the provisions of SFAS 157 for financial assets and liabilities. See Note C for additional information regarding the Partnership's adoption of SFAS 157. The adoption of the provisions of SFAS 157 that were delayed by FSP FAS 157-2 is not expected to have a material effect on the financial condition or results of operations of the Partnership.

 

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

 

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) became effective for the Partnership on January 1, 2009. The implementation of SFAS 141(R) did not impact the financial condition or results of operations of the Partnership 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 Partnership on January 1, 2009 and will only impact future disclosures about the Partnership'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 accepted accounting principles in the United States ("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.

 

EITF 03-6-1. In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1 ("Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities" ("FSP EITF 03-6-1"), which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the net income allocation in computing basic net income per share under the two class method prescribed under SFAS 128, "Earnings per Share." FSP 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and, to the extent applicable, must be applied retrospectively by adjusting all prior-period net income per share data to conform to the provisions of the standard. The adoption of FSP EITF 03-6-1 is not expected to have a material effect on the Partnership's net income per common unit calculations.

 

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 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. 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.

 

 

Effective January 1, 2008, the Partnership 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:

 

 

 

 

 

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Partnership's financial assets that are measured at fair value on a recurring basis as of December 31, 2008, for each of the fair value input hierarchy levels:

 

 

The Partnership was not a party to any financial liabilities as of December 31, 2008.

 

The Partnership's commodity price derivative assets that are 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 Partnership's commodity price derivative assets classified as Level 3 in the fair value hierarchy:

 

_____________

 

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

 

Oil derivatives. The Partnership's oil derivatives are swap and collar contracts for notional barrels ("Bbls") of oil at fixed (in the case of swaps contracts) or interval (in the case of collar contracts) NYMEX West Texas Intermediate ("WTI") oil prices. Commodity 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 Partnership'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 Partnership's collar contracts were determined based on implied volatility factors provided by the derivative counterparties, adjusted for estimated volatility skews. The volatility factors are not considered significant to the fair values of the collar contracts since intrinsic and time values are the principal components of the collar values.

 

NGL derivatives. The Partnership's NGL derivatives are swap contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs. The asset values attributable to the Partnership's NGL derivative instruments are based on (i) the contracted notional volumes, (ii) average independent broker-supplied forward Mont Belvieu-posted-price quotes and (iii) the applicable credit-adjusted risk-free rate yield curve. NGL swap contracts are not as actively traded as oil and gas 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 Partnership's gas derivatives are swap contracts for notional MMBtus of gas contracted at various posted price indexes, including NYMEX Henry Hub ("HH") swap contracts coupled with basis swaps contracts that convert the HH price index point to Permian Basin index prices. The asset values attributable to the Partnership's gas derivative instruments are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) averages of forward posted price quotes supplied by independent brokers who are active in buying and selling gas derivatives at the indexes other than HH and (iv) the applicable credit-adjusted risk-free rate yield curve.

 

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

 

 

            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 disposition 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.

 

Interest expense. The Partnership incurred $621 thousand of interest expense during 2008, comprised of $466 thousand of Credit Facility commitment fees and $155 thousand of amortization of Credit Facility financing fees. The Partnership did not incur interest expense during 2007 or 2006.

 

 

Partnership agreements. 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 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 G 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 Partnership's income taxes payable to affiliate 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 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.

 

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.

 

Gas processing. Substantially all of the Partnership’s gas is processed at the Midkiff/Benedum and Sale Ranch gas processing plants. Pioneer owns an approximate 27 percent interest in the Midkiff/Benedum gas processing plant, which processes a portion of the wet gas from the Partnership’s wells and retains as compensation approximately 20 percent of the Partnership’s dry gas residue and NGL value processed by the Midkiff/Benedum gas processing plant. Pioneer also owns an approximate 30 percent ownership in the Sale Ranch gas processing plant, which processes a portion of the wet gas from the Partnership wells and retains as compensation approximately 20 percent of the Partnership’s dry gas residue and NGL value processed by the Sale Ranch gas processing plant.

 

Related party charges. 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:

 

As of December 31, 2008, the Partnership'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.

 

Retirement Plans

 

Deferred compensation retirement plan. Pioneer makes contributions to its deferred compensation retirement plan for the officers and key employees of Pioneer. Each officer and key employee of Pioneer is allowed to contribute up to 25 percent of their base salary and 100 percent of their annual bonus. Pioneer provides a matching contribution of 100 percent of the officer’s and key employee’s contribution limited to the first 10 percent of the officer’s base salary and eight percent of the key employee’s base salary. Pioneer’s matching contribution vests immediately. The amounts allocated to the Partnership as a result of Pioneer's contributions made pursuant to the plan totaled $21 thousand, $20 thousand and $21 thousand during 2008, 2007 and 2006, respectively, which are included in general and administrative expenses in the accompanying consolidated financial statements.

 

401(k) plan.  Pioneer makes contributions to the Pioneer USA 401(k) Plan and Matching Plan (the "Plan"), which is a voluntary and contributory plan for eligible employees based on a percentage of employee contributions. The amounts allocated to the Partnership as a result of Pioneer's contributions made pursuant to the Plan totaled $56 thousand, $60 thousand and $63 thousand during 2008, 2007, and 2006, respectively. The Plan is a self-directed

 

 

plan that allows employees to invest their plan accounts in various fund alternatives, including a fund that invests in Pioneer common stock.

 

Long-Term Incentive Plan

 

In May 2008, the Board of Directors of the General Partner adopted a new Long-Term Incentive Plan, which provides for the granting of incentive awards in the form of options, unit appreciation rights, phantom units, restricted units, unit awards and other unit-based awards to directors, employees and consultants of the General Partner and its affiliates who perform services for the Partnership. The Long-Term Incentive Plan limits the number of units that may be delivered pursuant to awards granted under the plan to 3,000,000 common units.

 

             The following table shows the number of awards available under the Partnership's Long-Term Incentive Plan at December 31, 2008:

 

 

During May 2008, the General Partner awarded 12,630 restricted units to directors of the General Partner under the LTIP, of which 6,315 represented the initial restricted unit grant and will vest ratably over three years and 6,315 represented the initial annual restricted unit grant and will vest in May 2009. Associated therewith, the Partnership recognized $107 thousand of general and administrative expense during 2008.

 

As of December 31, 2008, there was approximately $133 thousand of unrecognized compensation expense related to unvested restricted unit awards. As of December 31, 2008, unrecognized compensation expense related to unvested restricted units awards is being amortized on a straight-line basis over the remaining vesting periods of the awards, which is a remaining period of less than three years.

 

The following table reflects the outstanding restricted unit awards as of December 31, 2008, and the activity related thereto for the year then ended:

 

__________

            

 

 

 

NOTE G.         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 required the delivery by Pioneer of specified quantities of gas through December 2007 and requires the delivery of specified quantities of oil through December 2010. Pioneer's VPP agreement represents limited-term overriding royalty interests in oil and gas reserves that: (i) entitle the purchaser to receive production volumes over a period of time from specific lease interests; (ii) do not bear any future production costs and capital expenditures associated with reserves; (iii) are nonrecourse to Pioneer (i.e., the purchaser's only recourse is to the assets acquired); (iv) transfer title of the assets to the purchaser; and (v) allow Pioneer or the Partnership, as the case may be, to retain the assets after the VPP's volumetric quantities have been delivered.

 

Virtually all of the properties that the Partnership owns 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.

 

Gas production from Pioneer's retained interest in the properties subject to the VPP obligation during the years ended December 31, 2007 and 2006 was not adequate to meet the VPP obligation and a portion of the Partnership's gas production was utilized to fund the VPP obligation. Accordingly, the accompanying consolidated financial statements, for the years ended December 31, 2007 and 2006, do not include gas revenues of $216 thousand and $436 thousand, respectively, that would have been recognized absent the VPP obligation. The production associated with the excluded gas revenue was approximately 41,726 Mcf and 87,992 Mcf for the years ended December 31, 2007 and 2006, respectively. The gas VPP obligation expired at December 31, 2007.

 

 

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

 

On May 6, 2008, novation agreements were entered into 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:

 

 

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 Partnership primarily utilizes commodity swap and collar contracts to (i) reduce the impact on the Partnership's net cash provided by operating activities from the price volatility of the commodities the Partnership produces and sells and (ii) help sustain unitholder distributions.

 

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 derivative contracts and the weighted average NYMEX prices per Bbl for those contracts as of December 31, 2008:

 

            

The Partnership reports average oil prices per Bbl including the effects of oil quality adjustments and the net effect of oil hedges (for periods subsequent to the Offering). The following table sets forth (i) the Partnership's oil prices, both reported (including hedge results) and realized (excluding hedge results), and (ii) the net effect of settlements of oil price hedges on oil revenue for the years ended December 31, 2008, 2007 and 2006:

 

 

 

 

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:

 

 

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 years ended December 31, 2008, 2007 and 2006:

 

 

Gas prices. The Partnership employs a policy of hedging a portion of its gas production based on the index price upon which the gas is actually sold in order to mitigate the basis risk between NYMEX prices and actual index prices, or based on NYMEX prices, if NYMEX prices are highly correlated with the index price. The following table sets forth the volumes hedged in 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:

 

 

 

 

 

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 years ended December 31, 2008, 2007 and 2006:

 

 

 

Hedge ineffectiveness. The Partnership recognizes ineffectiveness amounts when (i) hedge volumes exceed 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 for 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 Partnership 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 Partnership did not enter into any hedging transactions prior to the Offering.

 

AOCI - Hedging. As of December 31, 2008 and 2007, AOCI - Hedging represented net deferred gains of $143.0 million and $0, respectively, and an associated deferred tax provision of $1.4 million as of December 31, 2008. The increase in AOCI – Hedging during the year ended December 31, 2008 was primarily attributable 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 Partnership 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 provision associated with commodity hedges during the year ending December 31, 2009 from AOCI - Hedging to income tax provision.

 

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. 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 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.

 

 

Sales to major customers. The Partnership's share of oil and gas production is sold to various purchasers who must be prequalified under Pioneer's credit risk policies and procedures. The Partnership records allowances for doubtful accounts based on the aging of accounts receivable and the general economic condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts. The Partnership is of the opinion that the loss of any one purchaser would not have an adverse effect on the ability of the Partnership to sell its oil and gas production.

 

 

 

The following purchasers individually accounted for ten percent or more of the consolidated oil, NGL and gas revenues in at least one of the years ended December 31, 2008, 2007 and 2006:

 

 

As of December 31, 2008, the Partnership's accounts receivable balance included receivables of $3.1 million, $543 thousand and $435 thousand from Plains Marketing LP, TEPPCO Crude Oil and ONEOK Inc., respectively.

 

Derivative counterparties. The Partnership uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Partnership does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Partnership's credit risk policies and procedures. As of December 31, 2008, the Partnership was a party to derivative instruments with four counterparties.

 

 

The Partnership's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Partnership does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The Partnership has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes the Partnership's asset retirement obligation transactions during the years ended December 31, 2008, 2007 and 2006:

 

 

_________

 

 

The Partnership's other expense for 2008 consisted primarily of expenses related to 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. The Partnership and Pioneer decided during October 2008 not to pursue the assignment or the acquisition of an interest in the Midkiff-Benedum gas processing plant due to the uncertainty underlying market conditions.

 

 

 

NOTE L.       Income Taxes

 

The Partnership's income tax provisions, which amounts were entirely attributable to the Texas Margin tax (which currently approximates one percent of the Partnership's taxable income apportioned to Texas), consisted of the following for years ended December 31, 2008, 2007 and 2006:

 

 

The Partnership's deferred tax attributes represented a $235 thousand noncurrent asset and a $521 thousand current liability as of December 31, 2008. Deferred tax attributes represented a $456 thousand noncurrent liability as of December 31, 2007. The change in the Partnership's deferred tax position primarily resulted from the Offering, which occurred on May 6, 2008, and reflects differences in basis for tax purposes related to oil and gas properties. In connection with the Offering, the Partnership entered into a Tax Sharing Agreement with Pioneer. Under this agreement, the Partnership will pay Pioneer for its share of state and local income and other taxes (currently only the Texas Margin tax) for which the Partnership's results are included in a combined or consolidated tax return filed by Pioneer. The Partnership’s share of Texas Margin tax is determined based on a pro forma tax return prepared by including only the income, deductions, gains, losses, and credits of the Partnership and computing the tax liability as if the Partnership filed a separate return. As of December 31, 2008, the Partnership had not made any payments to Pioneer under the terms of the Tax Sharing Agreement.

 

The Partnership applies the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes" ("FIN 48"). FIN 48 clarifies the accounting for uncertainty in income taxes recognized and prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2008, the Partnership had no material unrecognized tax benefits (as defined in FIN 48). The Partnership does not expect to incur interest charges or penalties related to its tax positions, but if such charges or penalties are incurred, the Partnership's policy is to account for interest charges as interest expense and penalties as other expense in the consolidated statements of operations.

 

 

Derivative designations. Effective February 1, 2009, the Partnership 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. See Note H for more information regarding the Partnership's decision to discontinue hedge accounting.

 

Distribution declaration. In January 2009, the Partnership 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.

 

 

 

Capitalized Costs

 

 

Costs Incurred for Oil and Gas Producing Activities

 

__________

 

Reserve Quantity Information

 

The estimates of the Partnership's proved reserves as of December 31, 2008 were based on evaluations prepared by Pioneer's engineers and audited by independent petroleum engineers. The information included in this Report about the Partnership’s proved reserves as of December 31, 2007 and 2006 represents evaluations by Pioneer’s engineers of the Partnership Predecessor’s proved reserves before the Partnership purchased incremental working interests in certain of the Partnership Properties with the proceeds from the exercise of the underwriters’ over-allotment option associated with the Offering (the "Original Evaluations"). The independent petroleum engineers audited the Original Evaluations of the Partnership Predecessor’s proved reserves as of December 31, 2007 and 2006. The proved reserves that the independent petroleum engineers audited have been increased by approximately six percent and five percent as of December 31, 2007 and 2006, respectively, to recognize the proved reserves attributable to the incremental working interests in certain of the Partnership Properties that were purchased with the proceeds from the exercise of the underwriters’ over-allotment option and, together with the audited proved reserves, form the basis for the information included in this Report about the Partnership’s proved reserves as of December 31, 2007 and 2006.

 

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, 2007 and 2006 utilized respective oil prices of $44.14, $95.75 and $60.90 per Bbl (reflecting adjustments for oil quality), respective NGL prices of $17.91, $52.52 and $27.43 per Bbl, and respective gas prices of $4.41, $5.45 and $4.48 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 Partnership 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.

 

The following table provides a rollforward of total proved reserves for the years ended December 31, 2008, 2007 and 2006, as well as proved developed reserves in total as of the beginning and end of each respective year. 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").

 

 

 

 

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 Partnership's commodity derivative contracts. Utilizing December 31, 2008, commodity prices held constant over each derivative contract's term, the net present value of the Partnership'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.

 

 

 

The following tables provide the standardized measure of discounted future cash flows as of December 31, 2008, 2007 and 2006, as well as a roll forward in total for each respective year:

 

__________

 

Changes in Standardized Measure of Discounted Future Net Cash Flows

 

 

 

 

 

 

Selected Quarterly Financial Results

 

The following table provides selected quarterly financial results for the years ended December 31, 2008 and 2007:

 

 

__________

 

 

 

 

 

 

__________

 

 

 

 

 

 

 

 

Evaluation of disclosure controls and procedures. The Partnership's management, with the participation of the General Partner's principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Exchange Act, the Partnership's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer of the General Partner concluded that the design and operation of the Partnership's disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Partnership in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, including that such information is accumulated and communicated to the Partnership’s management, including the principal executive officer and principal financial officer of its general partner, as appropriate, to allow timely decisions regarding required disclosure.

 

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

 

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

 

This annual report does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of the Partnership's registered public accounting firm due to a transition period exemption established by rules of the SEC for new public companies.

 

 

 

 

 

 

PART III

 

 

The information required in response to this item will be filed by amendment to this Annual Report on Form 10-K.

 

 

The information required in response to this item will be filed by amendment to this Annual Report on Form 10-K.

 

 

The information required in response to this item will be filed by amendment to this Annual Report on Form 10-K.

 

 

The information required in response to this item will be filed by amendment to this Annual Report on Form 10-K.

 

 

The information required in response to this item will be filed by amendment to this Annual Report on Form 10-K.

 

 

 

PART IV

 

 

 

Financial Statements

 

The following consolidated financial statements of the Partnership are included in "Item 8. Financial Statements and Supplementary Data":

 

Report of Independent Registered Pubic Accounting Firm

 

Consolidated Balance Sheets as of December 31, 2008 and 2007

 

Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006

 

Consolidated Statements of Partners' Equity for the Years Ended December 31, 2008, 2007 and 2006

 

Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006

 

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2008, 2007 and 2006

 

Notes to Consolidated Financial Statements

 

Unaudited Supplementary Information

 

 

The exhibits to this Report required to be filed pursuant to Item 15(b) are listed below and in the "Exhibit Index" attached hereto.

 

 

 

 

 

 

89

 

 

 

90

 

 

 

_____________

(a) Filed herewith.

(b) Furnished herewith.

H   Executive Compensation Plan or Arrangement previously filed pursuant to Item 15(b).

 

*Pursuant to the rules of the Commission, the schedules and similar attachments to the Agreement have not been filed. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.

 

 

 

 

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

Date: March 5, 2009

 

 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

 

 

 

Exhibit Index

 

 

93

 

 

 

 

94

 

 

 

 

_____________

(a) Filed herewith.

(b) Furnished herewith.

H   Executive Compensation Plan or Arrangement previously filed pursuant to Item 15(b).

 

*Pursuant to the rules of the Commission, the schedules and similar attachments to the Agreement have not been filed. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.