UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


Washington,
D.C. 20549





FORM
10-K





/x/
            ANNUAL REPORT PURSUANT TO
      SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
      OF 1934For
      the fiscal year ended December 31, 2009
              or/  /
            TRANSITION REPORT PURSUANT
      TO SECTION 13 OR
      15(d) OF THE
      SECURITIES EXCHANGE ACT OF 1934For
      the transition period from ___to___


Commission
file number: 001-34032


Pioneer
Southwest Energy Partners L.P.


(Exact
name of registrant as specified in its charter)





Delaware
            26-0388421(State
      or other jurisdiction of incorporation)
            (I.R.S.
      Employer Identification No.)5205 N. O'Connor Blvd., Suite 200, Irving,
      Texas
            75039(Address
      of principal executive offices)
            (Zip
      Code)





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


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





Title of each class
            Name of each exchange on which
      registeredCommon
      Units Representing Limited Partner Units
            New
      York Stock Exchange





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





Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.YesoNoý





Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.YesoNoý





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.YesýNoo





Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
chapter) during the preceding 12 months (or for such shorter period than the
registrant was required to submit and post such files).YesoNoo





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.  ý





Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company. See
definitions of "large accelerated filer," "accelerated filer" and "smaller
reporting company" in Rule 12b-2 of the Exchange Act.





Large
      accelerated filer    o
            
            Accelerated
      filer                  
      ýNon
      accelerated filer     o
            (Do
      not check if a smaller reporting company)
            Smaller
      reporting company o





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





Aggregate
      market value of common units held by non-affiliates computed by reference
      to the price at which the common equity was last sold, or the average bid
      and asked price of such common equity, as of the last business day of the
      registrant's most recently completed second fiscal quarter
            $175,244,856Number
      of common units outstanding as of February 23, 2010
            33,113,700





DOCUMENTS
INCORPORATED BY REFERENCE:





(1)
            Portions of the definitive proxy
      statement for the Annual Meeting of Shareholders of Pioneer Natural
      Resources Company to be held during May 2010 as referenced in Part III,
      Item 11 of this report.














TABLE
      OF CONTENTSPageCautionary
      Statement Concerning Forward-Looking
      Statements
            3Definitions
      of Certain Terms and Conventions Used
      Herein
            4PART  IItem
      1.
            Business
            6General
            6Presentation
            6Available
      Information
            7Business
      Strategy
            7Relationship
      with
      Pioneer
            8Competitive
      Strengths
            8Business
      Activities
            9Marketing
      of
      Production
            10Competition,
      Markets and
      Regulations
            10Item
      1A.
            Risk
      Factors
            16Risks
      Related to the Partnership's
      Business
            16Risks
      Related to an Investment in the
      Partnership
            30Tax
      Risks to Common
      Unitholders
            34Item
      1B.
            Unresolved
      Staff
      Comments
            37Item
      2.
            Properties
            38Proved
      Reserves
            40Description
      of
      Properties
            41Selected
      Oil and Gas
      Information
            41Item
      3.
            Legal
      Proceedings
            44Item
      4.
            Submission
      of Matters to a Vote of Security
      Holders
            44PART  IIItem
      5.
            Market
      for Registrant's Common Equity, Related Stockholder Matters and Issuer
      Purchases of Equity Securities
            45Cash
      Distributions to
      Unitholders
            45Item
      6.
            Selected
      Financial
      Data
            46Item
      7.
            Management's
      Discussion and Analysis of Financial Condition and Results of
      Operations
            47Financial
      and Operating
      Performance
            47Significant
      Events
            48First
      Quarter 2010
      Outlook
            49Results
      of
      Operations
            49Capital
      Commitments, Capital Resources and
      Liquidity
            52Critical
      Accounting
      Estimates
            55New
      Accounting
      Pronouncements
            57Item
      7A.
            Quantitative
      and Qualitative Disclosures About Market
      Risk
            58Quantitative
      Disclosures
            58Qualitative
      Disclosures
            60Item
      8.
            Financial
      Statements and Supplementary
      Data
            61Index
      to Consolidated Financial
      Statements
            61Report
      of Independent Registered Public Accounting
      Firm
            62Consolidated
      Financial
      Statements
            63Notes
      to Consolidated Financial
      Statements
            69Unaudited
      Supplementary
      Information
            95Item
      9.
            Changes
      in and Disagreements With Accountants on Accounting and Financial
      Disclosure
            103Item
      9A.
            Controls
      and
      Procedures
            103Management
      Report on Internal Control Over Financial Reporting
            103Report
      of Independent Registered Public Accounting Firm on Internal Control Over
      Financial Reporting
            104Item
      9B.
            Other
      Information
            105
















PART  IIIItem
      10.
            Directors,
      Executive Officers and Corporate
      Governance
            106Item
      11.
            Executive
      Compensation
            111Item
      12.
            Security
      Ownership of Certain Beneficial Owners and Management and Related
      Stockholder Matters
            116Item
      13.
            Certain
      Relationships and Related Transactions, and Director
      Independence
            118Item
      14.
            Principal
      Accounting Fees and
      Services
            122PART  IVItem
      15.
            Exhibits,
      Financial Statement
      Schedules
            123Signatures
            127Exhibit
      Index
            128





****





CAUTIONARY
STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS





This Annual Report on Form 10-K ("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 material adverse effect on it. Accordingly, no
assurances can be given that the actual events and results will not be
materially different from the anticipated results described in the
forward-looking statements. See "Item 1. Business — Competition, Markets and
Regulations," "Item 1A. Risk Factors", "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations" 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.
Readers are cautioned not to place undue reliance on forward-looking statements,
which speak only as of the date hereof.  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:





·
            "Bbl"
      means a standard barrel containing 42 United States
    gallons.


·
            "BOE"
      means a barrel of oil equivalent and is a standard convention used to
      express oil and gas volumes on a comparable oil equivalent basis. Gas
      equivalents are determined under the relative energy content method by
      using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas
      liquid.


·
            "BOEPD"means BOE per
      day.


·
            "Btu"means British
      thermal unit, which is a measure of the amount of energy required to raise
      the temperature of one pound of water one degree
    Fahrenheit.


·
            "Common
      unit"means outstanding
      Pioneer Southwest Energy Partners L.P. limited partner
    units.


·
            "COPAS
      fee"means a fee based
      on an overhead rate established by the Council of Petroleum Accountants
      Societies to reimburse the operator of a well for overhead costs, such as
      accounting and engineering costs.


·
            "Derivatives"means financial
      contracts, or financial instruments, whose values are derived from the
      value of an underlying asset, reference rate, or
  index.


·
            "GAAP"
      means accounting principles that are generally accepted in the United
      States of America.


·
            "LIBOR"means London
      Interbank Offered Rate, which is a market rate of
  interest.


·
            "LNG"means liquefied
      natural gas.


·
            "MBbl"means one thousand
      Bbls.


·
            "MBOE"means one thousand
      BOEs.


·
            "Mcf"
      means one thousand cubic feet and is a measure of natural gas
      volume.


·
            "MMBOE"means one million
      BOEs.


·
            "MMBtu"
      means one million Btus.


·
            "MMcf"means one million
      cubic feet.


·
            "Mont
      Belvieu-posted-price" means the daily average of natural gas
      liquids components as priced in Oil Price Information
      Service ("OPIS") in the table "U.S. and Canada LP – Gas Weekly
      Averages" at Mont Belvieu, Texas.


·
            "NGL"means natural gas
      liquid.


·
            "Novation"
      represents the act of replacing one party to a contractual obligation with
      another party.


·
            "NYMEX"
      means the New York Mercantile
Exchange.


·
            "NYSE"
      means the New York Stock Exchange.


·
            "Partnership
      Predecessor"means Pioneer Southwest Energy Partners L.P.
      Predecessor.


·
            "Partnership"
      or "Pioneer
      Southwest" means Pioneer Southwest Energy Partners L.P. and its
      subsidiaries.


·
            "Pioneer"
      means Pioneer Natural Resources Company and its wholly owned
      subsidiaries.


·
            "Proved
      reserves"means the
      quantities of oil and gas, which, by analysis of geoscience and
      engineering data, can be estimated with reasonable certainty to be
      economically producible – from a given date forward, from known reservoirs
      and under existing economic conditions, operating methods, and government
      regulations – prior to the time at which contracts providing the right to
      operate expire, unless evidence indicates that renewal is reasonably
      certain, regardless of whether deterministic or probabilistic methods are
      used for the estimation.  The project to extract the
      hydrocarbons must have commenced or the operator must be reasonably
      certain that it will commence the project within a reasonable
      time.


(i) The
area of the reservoir considered as proved includes (A) The area identified by
drilling and limited by fluid contacts, if any and (B) Adjacent undrilled
portions of the reservoir that can, with reasonable certainty, be judged to be
continuous with it and to contain economically producible oil or gas on the
basis of available geoscience and engineering data.


(ii) In
the absence of data on fluid contacts, proved quantities in a reservoir are
limited by the lowest known hydrocarbons as seen in a well penetration unless
geoscience, engineering, or performance data and reliable technology establishes
a lower contact with reasonable certainty.


(iii)
Where direct observation from well penetrations has defined a highest known oil
elevation and the potential exists for an associated gas cap, proved oil
reserves may be assigned in the structurally higher portions of the reservoir
only if geoscience, engineering, or performance data and reliable technology
establish the higher contact with reasonable certainty.


(iv)
Reserves which can be produced economically through application of improved
recovery techniques (including, but not limited to, fluid injection) are
included in the proved classification when: (A) Successful testing by a pilot
project in an area of the reservoir with properties no more favorable than in
the reservoir









as a
whole, the operation of an installed program in the reservoir or an analogous
reservoir, or other evidence using reliable technology establishes the
reasonable certainty of the engineering analysis on which the project or program
is based: and (B) The project has been approved for development by all necessary
parties and entities, including governmental entities.


(v)
Existing economic conditions include prices and costs at which economic
producibility from a reservoir is to be determined.  The price shall
be the average price during the 12-month period prior to the ending date of the
period covered by the report, determined as an unweighted arithmetic average of
the first-day-of-the-month price for each month within such period, unless
prices are defined by contractual arrangements, excluding escalations based upon
future conditions.


·
            "Recompletion"
      means the completion for production of an existing wellbore in another
      formation from that in which the well has been previously
      completed.


·
            "SEC"means the United
      States Securities and Exchange
Commission.


·
            "Standardized
      Measure"means the
      after-tax present value of estimated future net cash flows of proved
      reserves, determined in accordance with the rules and regulations of the
      SEC, using prices and costs employed in the determination of proved
      reserves and a ten percent discount
rate.


·
            "U.S."
      means United States.


·           "VPP"
means volumetric production payment.


·
            "Workover"
      means operations on a producing well to restore or increase
      production.


·
            With
      respect to information on the working interest in wells, "net" wells are
      determined by multiplying "gross"wells by the
      Partnership's working interest in such wells. Unless otherwise specified,
      well statistics quoted herein represent gross
  wells.


·           All
currency amounts are expressed in U.S. dollars.









PART
I





ITEM
1.                 BUSINESS





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. Pioneer formed Pioneer Southwest Energy Partners USA LLC ("Pioneer
Southwest LLC") to hold certain of the Partnership's oil and gas properties
located in the Spraberry field in the Permian Basin of West Texas (the
"Spraberry field").  To effect the Offering, Pioneer (i) contributed
to the Partnership a portion of its interest in Pioneer Southwest LLC for
additional general and limited partner interests in the Partnership, (ii) sold
to the Partnership its remaining interest in Pioneer Southwest LLC for $141.1
million, (iii) sold incremental working interests in certain of the oil and gas
properties owned by Pioneer Southwest LLC to the Partnership for $22.0 million,
which amount represented the net proceeds from the exercise by the underwriters
of the over-allotment option (the transactions described in (i), (ii) and (iii)
above are referred to in the aggregate as the "2008 IPO Acquisitions"), 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 LLC became a wholly-owned subsidiary of the
Partnership.





On August
31, 2009, the Partnership completed the acquisition of certain oil and gas
properties in the Spraberry field and assumed net obligations associated with
certain commodity price derivative positions and certain other liabilities from
Pioneer pursuant to a Purchase and Sale Agreement having an effective date of
July1, 2009 (the acquisition, including liabilities assumed, is referred to
herein as the "2009 Acquisition").  See Note B of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information about the 2009
Acquisition.





On
November 16, 2009, the Partnership completed a public offering of 3,105,000 of
its common units representing limited partner interests (the "2009 Equity
Offering").  Following the 2009 Equity Offering, Pioneer owns a 61.9
percent limited partner interest in the Partnership.




The
Partnership's only operating segment is oil and gas producing activities.
Additionally, all of the Partnership's 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.  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, 2009, Pioneer had approximately 1,900 full
time employees, 383 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.





Presentation





Because
the 2009 Acquisition represents a transaction between entities under common
control, the Partnership's accompanying consolidated financial statements
included in "Item 8. Financial Statements and Supplementary Data" have been
recast for all periods prior to the 2009 Acquisition, similar to a pooling of
interests, to include the financial position, results of operations and cash
flows of the assets acquired and liabilities assumed in the 2009
Acquisition.  The recast historical financial information presents the
acquired assets as if they were owned by the Partnership for all periods
presented.  See Note B of Notes to Consolidated Financial Statements
included in









"Item 8.
Financial Statements and Supplementary Data" for more information about the
Partnership's accounting presentations.





For all periods prior to their
acquisition and assumption by the Partnership, the financial position, results
of operations, cash flows and changes in owner's equity of the property
interests acquired and the liabilities assumed in the 2009 Acquisition
(representing periods prior to August 31, 2009) and the 2008 IPO Acquisitions
(representing periods prior to May 6, 2008) are referred to herein as the
"Partnership Predecessor."





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 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 current distribution rate and, over
time, to increase its quarterly cash distributions. The Partnership expects to
reserve approximately 25 percent of its cash flow to drill undeveloped locations
and acquire producing and/or undeveloped properties in order to maintain its
production, proved reserves and cash flows.





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





·
            Develop the Partnership's
      proved undeveloped reserves.At current margins, the
      Partnership expects that drilling its undeveloped properties will allow it
      to increase cash flow from operations in order to maintain or increase
      cash distributions to unitholders in the future.  As part of a
      two-rig drilling program initiated in the fourth quarter of 2009, the
      Partnership drilled six wells in 2009 and expects to drill approximately
      50 wells in 2010.  The ultimate outcome and impact to the
      Partnership of the development drilling program cannot be predicted at
      this time.





·
            Purchase oil and gas
      properties in its area of operations directly from Pioneer. The
      Partnership expects to have the opportunity to make acquisitions of
      producing and undeveloped oil and gas properties, particularly in the
      Spraberry field, directly from Pioneer from time to time in the future.
      The Partnership believes that Pioneer intends to offer the Partnership
      over time the opportunity to purchase Pioneer's producing and undeveloped
      oil and gas assets in its area of operations, provided that such
      transactions can be done in an economic manner and depending upon market
      conditions at the time.  See Note B of Notes to Consolidated
      Financial Statements included in "Item 8. Financial Statements and
      Supplementary Data" for additional information about the 2009
      Acquisition.





·
            Purchase oil and gas
      properties in its area of operations from third parties either
      independently or jointly with Pioneer. The Partnership believes
      that over the long-term it will have a cost of capital advantage relative
      to its corporate competitors and a technical advantage due to the scale of
      Pioneer's operations, which will enhance the Partnership's ability to
      acquire producing and undeveloped oil and gas properties.  In
      addition, the Partnership believes that its relationship with Pioneer is
      advantageous because it allows the Partnership to jointly pursue
      acquisitions of oil and gas properties with Pioneer, which increases the
      number and type of transactions it can pursue and increases its
      competitiveness.














·
              Benefit from production and
      reserve enhancements as a result of infill drilling and secondary recovery
      initiatives being advanced by Pioneer. At Pioneer's request, the
      Railroad Commission of Texas amended its rules in October 2008 to allow
      Pioneer and other operators, at their option, to downspace well locations
      in the Spraberry field to 20-acre spacing.  The Partnership has
      the right to drill the 20-acre locations surrounding its wells and is
      considering drilling a limited number of wells in 2010 if margins
      improve.  Pioneer has reported that it is initiating a 7,000
      acre waterflood project in the Spraberry field during 2010, the results of
      which could encourage further waterflooding projects that could benefit
      the Partnership's wells in the future.  The ultimate outcome and
      impact to the Partnership of these initiatives cannot be predicted at this
      time.


·
            Maintain a balanced capital
      structure to ensure financial flexibility for acquisitions. To fund
      development drilling initiatives and future property acquisitions, the
      Partnership is reserving approximately 25 percent of its net cash provided
      by operating activities. The Partnership may also use, to the extent
      available, external financing sources to fund acquisitions, including
      borrowings under its credit facility and funds from future private and
      public equity and debt offerings. The Partnership intends to maintain a
      balanced capital structure which will afford the Partnership the financial
      flexibility to fund development drilling initiatives and future
      acquisitions.  See "Liquidity" included in "Item 7. Management's
      Discussion and Analysis of Financial Condition and Results of Operations"
      for additional information about the Partnership's capital
      structure.





·
            Mitigate commodity price risk
      through derivatives. 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, the Partnership has
      adopted a policy that contemplates using derivative contracts to protect
      the prices for approximately 65 to 85 percent of expected production for a
      period of up to five years, as
appropriate.





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
61.9 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, 2009, including the Partnership's properties, were 899 MMBOE,
of which 498 MMBOE, or 55 percent, were in the Spraberry field. Of the
498 MMBOE of proved reserves in the Spraberry field, 221 MMBOE were
proved developed reserves and 277 MMBOE were proved undeveloped reserves.
These proved undeveloped reserves represent approximately 3,900 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 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 in the Partnership's
area of operations.





The
Partnership's omnibus agreement with Pioneer 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:








·
            Its
      relationship with Pioneer:





o
            Pioneer
      has a significant retained interest in the Spraberry field as well as an
      active development plan, each of which should generate acquisition
      opportunities for the Partnership over
time;


o
            Pioneer's
      significant ownership in the Partnership provides it an economic incentive
      to sell developed and proved undeveloped oil and gas properties to it over
      time; and


o
            The
      Partnership's ability to pursue acquisitions jointly with Pioneer
      increases the number and type of transactions it can pursue and increases
      its competitiveness;












·
            Its
      assets are characterized by long-lived and stable
      production; and





·
            Its
      cost of capital and financial flexibility should over time provide it with
      a competitive advantage in pursuing acquisitions. Unlike the Partnership's
      corporate competitors, the Partnership is not subject to federal income
      taxation at the entity level. In addition, unlike a traditional master
      limited partnership structure, neither the Partnership's management nor
      Pioneer hold any incentive distribution rights that entitle them to
      increasing percentages of cash distributions as the Partnership's
      distributions grow. The Partnership believes that, collectively, these two
      factors provide the Partnership with a lower long-term cost of capital,
      thereby enhancing the Partnership's ability to compete for future
      acquisitions both individually and jointly with
  Pioneer.





Business
Activities





Petroleum
industry.Beginning in the second half of 2008 and continuing
throughout 2009, the United States and other industrialized countries
experienced a significant economic slowdown, which led to a substantial decline
in worldwide energy demand. During this same time period, North American gas
supply was increasing as a result of the rise in domestic unconventional gas
production. The combination of lower energy demand due to the economic slowdown
and higher North American gas supply resulted in significant declines in oil,
NGL and gas prices. While oil and NGL prices started to steadily increase
beginning in the second quarter of 2009, gas prices remained volatile throughout
2009 due to high storage levels and increasing gas supply.  The
outlook for a worldwide economic recovery in 2010 remains uncertain and the
timing of a recovery in worldwide demand for energy is difficult to
predict.  As a result, it is likely that commodity prices during 2010
will continue to be volatile.





For the
several years preceding the 2008 worldwide economic slowdown, 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
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 slowdown 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 the Partnership believes will impact 2010 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.





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 2009 and 2008 from the Partnership's
derivative price risk management activities and the Partnership's open
derivative positions at December 31, 2009.





The
Partnership.Currently, the Partnership's oil and gas
properties consist only of non-operated working interests in oil and gas
properties in the Spraberry field, all of which are operated by Pioneer,
including 1,155 producing wells. The Partnership's interest in 1,037 of these
wells is 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.   The Partnership acquired certain proved
undeveloped oil and gas









properties
in connection with the 2009 Acquisition and commenced a two-rig drilling program
in the fourth quarter to begin developing the undeveloped
properties.  See "Item 2. Properties – Description of Properties."
According to the Energy Information Administration, the Spraberry field is the
second 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.





Production and
drilling activities.During the year ended December 31,
2009,  the Partnership's average daily production, on a BOE basis was
6,145. Production, price and cost information with respect to the Partnership's
properties for 2009, 2008 and 2007 is set forth under "Item 2. Properties —
Selected Oil and Gas Information — Production, Price and Cost
Data."  During the three years ended December 31, 2009, the
Partnership drilled 26 gross (25 net) wells, all of which were successfully
completed as productive wells.





Acquisition
activities.   Part of the Partnership's  business strategy
is to acquire oil and gas properties in its area of operations that complement
its assets, provide development opportunities and potentially increase the
Partnership's net cash provided by operating activities to sustain or increase
unitholder distributions.  During 2009, the Partnership invested
$168.2 million of acquisition capital to purchase proved oil and gas properties
from Pioneer, including additional interests in its existing properties and
undeveloped properties in the Spraberry field for future drilling
initiatives.  See Note B of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a
description of the Partnership's acquisition of proved oil and gas properties in
2009.





Marketing
of Production





General.As
operator of the Partnership's properties, Pioneer markets the Partnership's
production and pays 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 2009, the Partnership's significant
purchasers were Plains Marketing LP (56 percent), Occidental Energy Marketing
(15 percent) and TEPPCO Crude Oil (10 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 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 to earnings during 2009 and 2008 from commodity derivative
activities and the Partnership's open commodity derivative positions at December
31, 2009.





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 are expected to
be an important element of the Partnership's future 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's 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.





Securities
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 and internal
controls over financial reporting, and ensuring 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.  Failure to comply with the rules and regulations of the
SEC could subject the Partnership to litigation from public or private
plaintiffs. Failure to comply with the rules of the NYSE could result in the
delisting of the Partnership's common units, which would have an adverse effect
on the liquidity and market value of the common units.  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:





·
            require
      the acquisition of various permits before drilling
    commences;


·
            enjoin
      some or all of the operations of facilities deemed in non-compliance with
      permits;


·
            restrict
      the types, quantities and concentration of various substances that can be
      released into the environment in connection with oil and gas drilling,
      production and transportation
activities;


·
            limit
      or prohibit drilling activities on certain lands lying within wilderness,
      wetlands and other protected areas;
and


·
            require
      remedial measures to mitigate pollution from former and ongoing
      operations, such as requirements to close pits and plug abandoned
      wells.





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, the United States Congress and
state legislatures, and federal and state regulatory 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 (the "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. 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 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 used 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 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 by 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 injection wells are regulated
by the Safe Drinking Water Act (the "SDWA") and analogous state and local laws.
The underground injection well program under the SDWA requires permits from the
EPA or analogous state agency for the Partnership's disposal wells, establishes
minimum standards for injection well operations, and restricts the types and
quantities of fluids that may be injected. 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. In addition, the United States Congress is considering amending the
SDWA to require additional regulation of chemicals used by the oil and gas
industry in the hydraulic fracturing process, and some states are considering
similar regulations.





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, the 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 the 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 related 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 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.On December 15, 2009, the EPA officially published its findings that
emissions of carbon dioxide, methane and other "greenhouse gases," or "GHGs,"
present an endangerment to human health and the environment because emissions of
such gases are, according to the EPA, contributing to warming of the Earth's
atmosphere and other climatic changes. These findings by the EPA allow the
agency to proceed with the adoption and implementation of regulations that would
restrict emissions of GHGs under existing provisions of the CAA. In late
September 2009, the EPA had proposed two sets of regulations in anticipation of
finalizing its findings that would require a reduction in emissions of GHGs from
motor vehicles and that could also lead to the imposition of GHG emission
limitations in CAA permits for certain stationary sources. In addition, on
September 22, 2009, the EPA issued a final rule requiring the reporting of GHG
emissions from specified large GHG emission sources in the United States
beginning in 2011 for emissions occurring in 2010. The adoption and
implementation of any regulations imposing reporting obligations on, or limiting
emissions of GHGs from, the Partnership's equipment and operations could require
the Partnership to incur costs to reduce emissions of GHGs associated with the
Partnership's operations or could adversely affect demand for the oil, NGL and
gas that the Partnership produces.





Also, on
June 26, 2009, the U.S. House of Representatives approved adoption of the
"American Clean Energy and Security Act of 2009" ("ACESA"), which is also known
as the "Waxman-Markey cap-and-trade legislation." The purpose of ACESA is to
control and reduce emissions of greenhouse gases in the United States. ACESA
would establish an economy-wide cap on emissions of GHGs in the United States
and would require an overall reduction in GHG emissions of 17 percent (from 2005
levels) by 2020, and by over 80 percent by 2050. Under ACESA, most sources of
GHG emissions would be required to obtain GHG emission "allowances"
corresponding to their annual emissions of GHGs. The number of emission
allowances issued each year would decline as necessary to meet ACESA's overall
emission reduction goals. As the number of GHG emission allowances permitted by
ACESA declines each year, the cost or value of allowances would be expected to
escalate significantly. The net effect of ACESA would be to impose increasing
costs on the combustion of carbon-based









fuels
such as oil, refined petroleum products and gas. The U.S. Senate has begun work
on its own legislation for controlling and reducing emissions of GHGs in the
United States. If the Senate adopts GHG legislation that is different from
ACESA, the Senate legislation would need to be reconciled with ACESA and both
chambers would be required to approve identical legislation before it could
become law.





In
addition, more than one-third of the states, either individually or through
multi-state regional initiatives, already have begun implementing legal measures
to reduce emissions of GHGs, primarily through the planned development of
emission inventories or regional greenhouse gas cap and trade
programs.  Finally, other nations have been seeking to reduce
emissions of GHGs 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 GHGs to below 1990 levels by
2012.  Depending on the particular jurisdiction in which the
Partnership's operations are located, it could be required to purchase and
surrender allowances for GHG emissions resulting from the Partnership's
operations.





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 effect 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 ended December 31, 2009. Additionally, the Partnership is not aware
of any environmental issues or claims that will require material capital
expenditures during 2010. 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 effect on the Partnership's business, financial condition and results
of operations.  See "Item 1A. Risk Factors" for additional
information.





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.





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:




·
            the
      location of wells;


·
            the
      method of drilling and casing
wells;


·
            the
      surface use and restoration of properties upon which wells are
      drilled;


·
            the
      plugging and abandoning of wells;
and


·
            notice
      to surface owners and other third
parties.




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 affect the economics of
production from these wells, 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 for resale 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. As a result of initiatives like FERC Order No. 636 ("Order 636"), issued
in April 1992, the interstate natural gas transportation and marketing system
has been substantially restructured to remove various barriers and practices
that historically limited non-pipeline gas sellers, including producers, from
effectively competing with interstate pipelines for sales to local distribution
companies and large industrial and commercial customers.  The most
significant provisions of Order 636 require that interstate pipelines provide
firm and interruptible transportation service on an open access basis that is
equal for all gas supplies.  In many instances, the results of Order
636 and related initiatives have been to substantially reduce or eliminate the
interstate pipelines' traditional role as wholesalers of gas in favor of
providing only storage and transportation services.




In August
2005, Congress enacted the Energy Policy Act of 2005 ("EPAct
2005").  Among other matters, EPAct 2005 amends the Natural Gas Act
("NGA") to make it unlawful for "any entity," including otherwise
non-jurisdictional producers such as the Partnership, to use any deceptive or
manipulative device or contrivance in connection with the purchase or sale of
gas or the purchase or sale of transportation services subject to regulation by
the FERC, in contravention of rules prescribed by the FERC.  The
FERC's rules implementing this provision make it unlawful, in connection with
the purchase or sale of gas subject to the jurisdiction of the FERC, or the
purchase or sale of transportation services subject to the jurisdiction of the
FERC, for any entity, directly or indirectly, to use or employ any device,
scheme or artifice to defraud; to make any untrue statement of material fact or
omit to make any such statement necessary to make the statements made not
misleading; or to engage in any act or practice that operates as a fraud or
deceit upon any person.  EPAct 2005 also gives the FERC authority to
impose civil penalties for violations of the NGA up to $1.0 million per day per
violation.  The anti-manipulation rule does not apply to activities
that relate only to intrastate or other non-jurisdictional sales or gathering,
but does apply to activities of otherwise non-jurisdictional entities to the
extent the activities are conducted "in connection with" gas sales, purchases or
transportation subject to FERC jurisdiction, which includes the annual reporting
requirements under Order 704 (defined below).





In
December 2007, the FERC issued rules ("Order 704") requiring that any market
participant, including a producer such as the Partnership, that engages in
wholesale sales or purchases of gas that equal or exceed 2.2 million MMBtus
during a calendar year must annually report such sales and purchases to the
FERC.  Order 704 is intended to increase the transparency of the
wholesale gas markets and to assist the FERC in monitoring those markets and in
detecting market manipulation.





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 or gas prices 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 affected 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 occurs, it could materially harm the Partnership's business, financial
condition or results of operations. In that case, the Partnership might not be
able to pay 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 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:





•
            the
      amount of oil, NGL and gas the Partnership produces;•
            the
      prices at which the Partnership sells its oil, NGL and gas
      production;•
            the
      effectiveness of its commodity price derivatives;•
            the
      level of its operating costs, including fees and reimbursement of expenses
      to the General Partner and its affiliates;•
            the
      Partnership's ability to replace declining reserves;•
            the
      success of the Partnership's development drilling
  program;•
            the
      Partnership's ability to acquire oil and gas properties from third parties
      in a competitive market and at an attractive price to the
      Partnership;•
            Pioneer's
      willingness to sell assets to the Partnership at a price that is
      attractive to the Partnership and to Pioneer;•
            prevailing
      economic conditions;•
            the
      level of competition the Partnership faces;•
            fuel
      conservation measures and alternate fuel
      requirements; and•
            government
      regulation and taxation.





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





•
            the
      level of the Partnership's capital expenditures for acquisitions of
      additional oil and gas assets, developing proved undeveloped properties,
      and recompletion opportunities in existing oil and gas
    wells;•
            the
      Partnership's ability to make borrowings under its credit facility to pay
      distributions;•
            sources
      of cash used to fund acquisitions;•
            debt
      service requirements and restrictions on distributions contained in the
      Partnership's credit facility or future financing
    agreements;•
            fluctuations
      in the Partnership's working capital needs;•
            general
      and administrative expenses;



















•
              timing
      and collectability of receivables; and•
              the
      amount of cash reserves, which the Partnership expects to be substantial,
      established by the General Partner for the proper conduct of the
      Partnership's business.




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
prices 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, NGL and gas, market
uncertainty and a variety of additional factors that are beyond the
Partnership's control, such as:





•
            domestic
      and foreign supply of and demand for oil, NGL and gas;•
            weather
      conditions;•
            overall
      domestic and global political and economic conditions;•
            actions
      of OPEC and other state-controlled oil companies relating to oil price and
      production controls;•
            the
      effect of increasing liquefied natural gas, or LNG, deliveries to the
      United States;•
            technological
      advances affecting energy consumption and energy
supply;•
            domestic
      and foreign governmental regulations and taxation;•
            the
      effect of energy conservation efforts;•
            the
      capacity, cost and availability of oil and gas pipelines and other
      transportation facilities, and the proximity of these facilities to the
      Partnership's wells; and•
            the
      price and availability of alternative
fuels.





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, 2009, the NYMEX oil
price ranged from a high of $81.37 per Bbl to a low of $33.98 per Bbl, while the
NYMEX Henry Hub gas price ranged from a high of $6.07 per MMBtu to a low of
$2.51 per MMBtu.





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





The
Partnership's revenue, profitability and cash flow depend upon the prices and
demand for oil, NGL and gas, and a drop in prices could 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.





A
significant portion of the Partnership's assets consists of working interests in
identified producing wells, or "wellbore interests," and the Partnership does
not have the right to develop other portions of the leaseholds related to such
wellbore interests.





A significant portion of the
Partnership's assets consist of mineral interests and leasehold interests in
identified producing wells (often referred to as wellbore interests). The
Partnership's rights as to these wellbores 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 these wellbore interests 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  Partnership is also prohibited from extending the horizontal
reach of the wellbore interest. These restrictions on the Partnership's ability
to extend the vertical and horizontal limits of its existing wellbore interests
could have an









adverse
effect on 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, the Partnership will have to drill
undeveloped locations and/or acquire additional oil and gas assets that provide
cash margins that allow the Partnership to maintain its production and reserves
and sustain its level of distributions to unitholders 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 drill undeveloped locations and/or acquire additional oil and gas assets that
provide cash margins that allow the Partnership to maintain its production and
reserves and sustain its level of distributions to unitholders over time. The
Partnership may be unable to make such acquisitions if:





•
            Pioneer
      decides not to sell any assets to the Partnership;•
            Pioneer
      decides to acquire assets in the Partnership's area of operations instead
      of allowing the Partnership to acquire them;•
            the
      Partnership is unable to identify attractive acquisition opportunities in
      its area of operations;•
            the
      Partnership is unable to agree on a purchase price for assets that are
      attractive to it; or•
            the
      Partnership is unable to obtain financing for acquisitions on economically
      acceptable terms.





The Partnership expects to reserve
approximately 25 percent of its cash flow to drill undeveloped locations and/or
acquire additional oil and gas assets in order to maintain its production,
proved reserves and cash flows, which will reduce its cash available for
distribution.





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 facility 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 drill undeveloped
locations and/or acquire additional oil and gas assets in order to maintain its
production, proved reserves and cash flow. To the extent its production declines
faster than the Partnership anticipates or the cost to drill for or acquire
additional reserves is greater than the Partnership anticipates, the Partnership
will require a greater amount of capital to maintain its production, proved
reserves and cash flow. The use of cash generated from operations to fund
drilling or acquisitions 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
drilling initiatives or 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 to raise capital 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
      validity of the Partnership's assumptions about reserves, future
      production, revenues and costs, including synergies;•
            a
      decrease in the Partnership's liquidity by using a significant portion of
      its available cash or borrowing capacity to finance
      acquisitions;

















•
              a
      significant increase in the Partnership's interest expense or financial
      leverage if the Partnership incurs additional debt to finance
      acquisitions;•
              dilution
      to its unitholders and a decrease in available cash per unit if the
      Partnership issues additional partnership securities to finance
      acquisitions;•
              the
      assumption of unknown liabilities, losses or costs for which the
      Partnership is not indemnified or for which its indemnity is
      inadequate;•
              the
      diversion of management's attention from other business
      concerns;•
              an
      inability to hire, train or retain qualified personnel to manage and
      operate the Partnership's growing business and
      assets; and•
              customer
      or key employee losses at the acquired
  businesses.


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, which 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 manage 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. Subsequent to the Partnership's decision to
discontinue hedge accounting effective February 1, 2009, 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 result in significant noncash
losses.  The Partnership has direct commodity price exposure on the
portion of its production volumes not covered by derivative contracts. 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
continued into the first half of 2009.  Approximately 15 percent, 25
percent, 25 percent and 40 percent of the Partnership's estimated total
production for 2010, 2011, 2012 and 2013, 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, 2009. 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
its 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.





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 reduction 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 85 percent, 75
percent, 75 percent and 60 percent of the Partnership's estimated total
production for 2010, 2011, 2012 and 2013, 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, 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, 2012.
The Partnership's commodity price derivative strategy and future derivative
transactions are 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. 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 earnings 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:





·
            historical
      production from the area compared with production from other producing
      areas;


·
            the
      quality and quantity of available
data;


·
            the
      interpretation of that data;


·
            the
      assumed effects of regulations by governmental
  agencies;


·
            assumptions
      concerning future commodity prices;
and


·
            assumptions
      concerning future operating costs, severance, ad valorem and excise taxes,
      development costs, transportation costs and workover and remedial
      costs.





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





·
            the
      quantities of oil and gas that are ultimately
  recovered;


·
            the
      production and operating costs
incurred;


·
            the
      amount and timing of future development expenditures;
  and


·
            future
      commodity prices.





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 the average of the first-day-of-the-month commodity prices
during the twelve-month period preceding the date of the









estimate
and prevailing operating and development 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:





·
            the
      amount and timing of actual
production;


·
            levels
      of future capital spending;


·
            increases
      or decreases in the supply of or demand for oil and gas;
    and


·
            changes
      in governmental regulations or
taxation.





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. In general,
it requires the use of the average of the first-day-of-the-month commodity
prices during the twelve-month period preceding the date of the estimate, 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 operations are subject to
all the risks normally incident to the oil and gas development and production
business, and could be curtailed or delayed or become uneconomical as a result
of other factors, including:





•
            high
      costs, shortages or delivery delays of equipment, labor or other
      services;•
            unexpected
      operational events and/or conditions;•
            reductions
      in oil, NGL and gas prices;•
            limitations
      in the market for oil, NGL and gas;•
            adverse
      weather conditions;•
            facility
      or equipment malfunctions;•
            equipment
      failures or accidents;•
            title
      problems;•
            pipe
      or cement failures or casing collapses;•
            compliance
      with environmental and other governmental requirements;•
            environmental
      hazards, such as gas leaks, oil spills, pipeline ruptures and discharges
      of toxic gases;•
            lost
      or damaged oilfield workover and service tools;•
            unusual
      or unexpected geological formations or pressure or irregularities in
      formations;•
            blowouts,
      cratering, explosions and fires;•
            natural
      disasters; and•
            uncontrollable
      flows of oil, gas or well fluids.





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.  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's oil and gas
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 Partnership's properties. The Partnership's dependence on Pioneer 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.





ThePartnership'sexpectations for
future drilling activities will be realized over several years, making them
susceptible to uncertainties that could materially alter the occurrence or
timing of such activities.





The Partnership has identified
drilling locations and prospects for future drilling opportunities and enhanced
recovery activities.  These drilling locations represent a significant part
of the Partnership's future drilling plans. The Partnership's ability to drill
and develop these locations depends on a number of factors, including the
availability of capital, seasonal conditions, regulatory approvals, negotiation
of agreements with third parties, commodity prices, costs and drilling results.
Because of these uncertainties, the Partnership cannot give any assurance as to
the timing of these activities or that they will ultimately result in the
realization of proved reserves or meet the Partnership's expectations for
success. As such, the Partnership's actual drilling and enhanced recovery
activities may materially differ from the Partnership's current expectations,
which could have a significant adverse effect on the Partnership's reserves,
financial condition and results of operations.





A
substantial portion of the Partnership's oil and gas properties is 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.





The Partnership's title to a
substantial portion of its oil and gas properties is burdened by a volumetric
production payment, 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 either (i) 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 by the Partnership in connection with the delivery of such volumes)
required to meet the VPP obligation or (ii) deliver to the Partnership
volumes equal to the volumes delivered pursuant to the VPP obligation. For
example, since the 2009 Acquisition, 5 MBbls of the Partnership's production has
been utilized by Pioneer to meet VPP obligations. Accordingly, Pioneer delivered
5 MBbls of alternative volumes of oil production to the Partnership through the
end of December 2009. To the extent Pioneer fails to comply with its obligation,
the decrease in the Partnership's production would result in a decrease in its
cash available for distribution. Please read Note G of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for more information about the VPP.





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 from existing
wells.  In addition, the Partnership's forecasts assume that none of
the risks associated with the Partnership's oil and gas









operations
summarized in this Item 1A occur, such as facility or equipment malfunctions,
adverse weather effects, or downturns in commodity prices or significant
increases in costs, which could make certain production
uneconomical.





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. In addition, the Partnership's
operations are restricted to onshore Texas and the southeast region of New
Mexico. Due to its lack of diversification, 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 three 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,
2009, purchases by Plains Marketing, L.P., Occidental Energy Marketing and
TEPPCO Crude Oil represented approximately 56 percent, 15 percent and 10 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. 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., Occidental
Energy Marketing 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., Occidental Energy Marketing or 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.,
Occidental Energy Marketing 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 primary term of the marketing agreement between Pioneer and
Occidental Energy Marketing expires on December 31, 2012, after which time the
contract will automatically be extended on a month-to-month basis until either
party gives 30 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.













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





Recently,
global financial markets and economic conditions were disrupted and volatile,
and the debt and equity capital markets were exceedingly distressed, making 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
increased as many lenders and institutional investors increased interest rates,
enacted tighter lending standards and limited the amount of funding available to
borrowers.  If these events were to recur, the Partnership could 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.





Concerns over the worldwide economic
outlook, geopolitical issues, the availability and cost of credit, the United
States 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, precipitated a
worldwide recession. Concerns about global economic growth have had a
significant adverse effect on global financial markets and commodity
prices.  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 highly
competitive, including 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 effect 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
drilling and 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 obtain additional financing, if necessary, for
      working capital, capital expenditures, acquisitions or other purposes may
      be impaired or such financing may not be available on favorable
      terms;•
            covenants
      contained in its existing and future credit and debt arrangements will
      require it to meet financial tests that may affect its flexibility in
      planning for and reacting to changes in its business, including possible
      acquisition opportunities;•
            it
      could need a substantial portion of its cash flow to make principal and
      interest payments on its indebtedness, reducing the funds that would
      otherwise be available for operations, future business opportunities and
      distributions to unitholders; and•
            its
      debt level could make it more vulnerable than its competitors with less
      debt to the effects of competitive pressures or a downturn in its business
      or the economy generally.





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:





•
            grant
      liens;•
            incur
      additional indebtedness;•
            engage
      in a merger, consolidation or dissolution;•
            enter
      into transactions with affiliates;•
            pay
      distributions or repurchase equity;•
            make
      investments;•
            sell
      or otherwise dispose of its assets, businesses and
      operations; and•
            materially
      alter the character of its
business.





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 oil and gas properties, 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 oil
and gas properties, 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.





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





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. For example, during the three years prior to the recent
economic decline, oil and gas companies generally experienced increasing
drilling and operating costs. Although the Partnership has experienced decreases
in these costs over the past year, 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:





•
            unexpected
      drilling conditions;•
            pressure
      or irregularities in formations;•
            equipment
      failures or accidents;•
            adverse
      weather conditions;•
            restricted
      access to land for drilling or laying pipelines; and•
            costs
      of, or shortages or delays in the delivery of, drilling rigs and
      equipment.













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
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 large 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, 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.





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
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.





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.





The
adoption of derivatives legislation by Congress could have an adverse effect on
the Partnership's ability to use derivative instruments to reduce the effect of
commodity price risk associated with its business.





Congress
currently is considering comprehensive financial reform legislation that
includes restrictions on certain transactions involving derivatives. This
legislation also would provide the Commodity Futures Trading Commission,
("CFTC") with express authority to impose position limits related to energy
commodities, such as oil and gas.  Separately, the CFTC is proposing
regulations to set position limits for certain futures and option contracts in
the major energy markets.  Although it is not possible at this time to
predict whether or when the CFTC may adopt rules or Congress may act on
derivatives legislation, any laws or regulations that may be adopted could have
an adverse effect on the Partnership's ability to utilize derivative instruments
to reduce the effect of commodity price risk associated with its
business.





The
adoption of climate change legislation by Congress and/or regulation by the EPA
could result in increased operating costs and reduced demand for the oil, NGLs
and gas the Partnership produces.





In
December 2009, the EPA officially published its findings that emissions of
"greenhouse gases," or "GHGs," present an endangerment to human health and the
environment because emissions of such gases are, according to the EPA,
contributing to warming of the Earth's atmosphere and other climatic changes.
These findings by the EPA allow the agency to proceed with the regulations that
would restrict emissions of GHGs under existing provisions of the federal Clean
Air Act. Any regulations imposing reporting obligations on, or limiting
emissions of GHGs from, the Partnership's equipment and operations could require
the Partnership to incur costs to reduce emissions of GHGs associated with the
Partnership's operations or could adversely affect demand for the oil, NGLs and
gas that the Partnership produces.





Also, in
June 2009, the U.S. House of Representatives approved adoption of the "American
Clean Energy and Security Act of 2009," ("ACESA"), which is also known as the
"Waxman-Markey cap-and-trade legislation." The purpose of ACESA is to control
and reduce emissions of GHGs in the United States. Under ACESA, most sources of
GHG emissions would be required to obtain GHG emission "allowances"
corresponding to their annual emissions of GHGs, with the number of emission
allowances issued each year declining as necessary to meet ACESA's overall
emission reduction goals. The net effect of ACESA would be to impose increasing
costs on the combustion of carbon-based fuels such as oil, refined petroleum
products and gas. The U.S. Senate has begun work on its own legislation for
controlling and reducing emissions of GHGs in the United States.





It is not
possible at this time to predict whether climate change legislation will be
enacted, but any laws or regulations that may be adopted to restrict or reduce
emissions of GHGs would likely require the Partnership to incur increased
operating costs and could have an adverse effect on demand for the oil, NGLs and
gas it produces. See "Item 1. Business — Competition, Markets and
Regulations" above for additional discussion regarding recent legislative and
regulatory action regarding climate change.





Finally,
it should be noted that some scientists have concluded that increasing
concentrations of GHGs in the Earth's atmosphere may produce climate changes
that have significant physical effects, such as increased frequency and severity
of storms, droughts, and floods and other climatic events; if any such effects
were to occur, they could have an adverse effect on the Partnership's assets and
operations.












Federal
and state legislation and regulatory initiatives relating to hydraulic
fracturing could result in increased costs and additional operating restrictions
or delays.





Congress
is currently considering legislation to amend the federal Safe Drinking Water
Act to regulate chemicals used by the oil and gas industry in the hydraulic
fracturing process, and some other states are considering similar regulations.
Hydraulic fracturing involves the injection of water, sand and chemicals under
pressure into rock formations to stimulate oil and gas production. Sponsors of
bills currently pending before the U.S. Senate and House of Representatives have
asserted that chemicals used in the fracturing process could adversely affect
drinking water supplies. The proposed legislation also would require the
disclosure of chemical constituents used in the fracturing process to state or
federal regulatory agencies, which could make such information publicly
available.  The availability of this information could make it easier
for third parties opposing the hydraulic fracturing process to initiate legal
proceedings based on allegations that specific chemicals used in the fracturing
process could adversely affect groundwater.  In addition, these bills,
if adopted, could establish an additional level of regulation at the federal
level that could lead to operational delays or increased operating costs and
could result in additional regulatory burdens that could make it more difficult
to perform hydraulic fracturing and increase the Partnership's costs of
compliance and doing business.





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 61.9 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:





•
            Neither
      the Partnership Agreement nor any other agreement requires Pioneer to
      pursue a business strategy that favors the Partnership. Directors and
      officers of Pioneer have a fiduciary duty to make decisions in the best
      interest of its stockholders, which may be contrary to the Partnership's
      interests.•
            The
      General Partner is allowed to take into account the interests of parties
      other than the Partnership, such as Pioneer, in resolving conflicts of
      interest, which has the effect of limiting its fiduciary duty to the
      Partnership.•
            Pioneer
      will compete with the Partnership and is under no obligation to offer
      properties to the Partnership. In addition, Pioneer may compete with the
      Partnership with respect to any future acquisition
      opportunities.•
            The
      General Partner determines the amount and timing of expenses, asset
      purchases and sales, capital expenditures, borrowings, repayments of
      indebtedness, issuances of additional partnership securities and cash
      reserves, each of which can affect the amount of cash that is available
      for distribution to unitholders.•
            The
      Partnership Agreement permits the General Partner to cause the Partnership
      to pay it or its affiliates for any services rendered to the Partnership
      and permits the General Partner to enter into additional contractual
      arrangements with any of these entities on the Partnership's behalf, and
      provides for reimbursement to the General Partner for such amounts as it
      determines pursuant to the provisions of the Partnership
      Agreement.





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
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 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 to
unitholders.





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 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:





•
            each
      unitholder's proportionate ownership interest in the Partnership would
      decrease;•
            the
      amount of cash available for distribution on each unit could
      decrease;



















•
              the
      ratio of taxable income to distributions could
increase;•
              the
      relative voting strength of each previously outstanding unit could be
      diminished; and•
              the
      market price of the common units could
decline.


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:





•
            permits
      the General Partner to make a number of decisions in its sole discretion.
      This entitles the General Partner to consider only the interests and
      factors that it desires, and it has no fiduciary duty or obligation to
      give any consideration to any interest of, or factors affecting, the
      Partnership, its subsidiaries or any limited partner. Examples include the
      exercise of its limited call rights, its rights to vote and transfer the
      units it owns and its registration rights and the determination of whether
      to consent to any merger or consolidation of the Partnership or any
      amendment to the Partnership Agreement;•
            with
      respect to transactions not involving a conflict of interest, provides
      that the General Partner, when acting in its capacity as general partner
      and not in its sole discretion, shall not owe any fiduciary duty to the
      Partnership's unitholders and shall not owe any fiduciary duty to the
      Partnership except for the duty to act in good faith, which for purposes
      of the Partnership Agreement means that a person making any determination
      or taking or declining to take any action subjectively believes that the
      decision or action made or taken (or not made or not taken) is in the
      Partnership's best interests;•
            generally
      provides that affiliate transactions and resolutions of conflicts of
      interest not approved by the Conflicts Committee of the Board of Directors
      of the General Partner and not involving a vote of unitholders must be
      determined in good faith. Under the Partnership Agreement, "good faith"
      for this purpose means that a person making any determination or taking or
      declining to take any action subjectively believes that the decision or
      action made or taken (or not made or taken) is fair and reasonable to the
      Partnership taking into account the totality of the relationships between
      the parties involved or is on terms no less favorable to the Partnership
      than those generally being provided to or available from unrelated third
      parties;•
            provides
      that in resolving a conflict of interest, the General Partner and its
      Conflicts Committee may consider:





•
            the
      relative interests of the parties involved and the benefits and burdens
      relating to such interest;•
            the
      totality of the relationships between the parties involved (including
      other transactions that may be particularly favorable or advantageous to
      the Partnership);•
            any
      customary or accepted industry practices and any customary or historical
      dealings with a particular person;•
            any
      applicable engineering practices or generally accepted accounting
      practices or principles;•
            the
      relative cost of capital of the parties and the consequent rates of return
      to the equity holders of the parties; and•
            in
      the case of the Conflicts Committee only, such additional factors it
      determines in its sole discretion to be relevant, reasonable or
      appropriate under the
circumstances;





•
            provides
      that any decision or action made or taken by the General Partner or its
      Conflicts Committee in good faith, including those involving a conflict of
      interest, will be conclusive and binding on all partners and will not be a
      breach of the Partnership Agreement or of any duty owed to the
      Partnership;•
            provides
      that in resolving conflicts of interest, it will be presumed that in
      making its decision the General Partner or its Conflicts Committee acted
      in good faith, and in any proceeding brought by or on behalf of any
      limited partner or the Partnership, the person bringing or prosecuting
      such proceeding will have the burden of overcoming such
      presumption; and












•
              provides
      that the General Partner and its officers and directors will not be liable
      for monetary damages to the Partnership, the Partnership's limited
      partners or assignees for any acts or omissions unless there has been a
      final and non-appealable judgment entered by a court of competent
      jurisdiction determining that the General Partner or those other persons
      acted in bad faith or engaged in fraud or willful misconduct, or, in the
      case of a criminal matter, acted with knowledge that the conduct was
      criminal.


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, currently it would be
difficult for them to remove the General Partner because Pioneer owns a
substantial number of units. 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 62 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 currently conducts 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 its
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 additional entity-level taxation by individual states would
further 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 has
been required to pay an annual Texas Margin tax at a maximum effective rate of
0.7 percent of its federal gross income apportioned to Texas in the prior year.
Imposition of such a tax on the Partnership by any other state in which the
Partnership may conduct activities in the future would further 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
common units each month based upon the ownership of the common 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 if new Treasury
regulations addressing these matters 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 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
are 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
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 decrease a unitholder's basis in its common units, the
amount, if any, of such prior excess distributions with respect to the common
units the unitholder 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 depletion, depreciation and intangible drilling and development
costs 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 in the future
operate.





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.





Certain
U.S. federal income tax deductions currently available with respect to oil and
gas exploration and development may be eliminated as a result of future
legislation.





President Obama's proposed Fiscal
Year 2011 Budget includes proposed legislation that would, if enacted into law,
make significant changes to United States tax laws, including the elimination of
certain key U.S. federal income tax incentives currently available to oil and
gas companies. These changes include, but are not limited to, (i) the repeal of
the percentage depletion allowance for oil and gas properties, (ii) the
elimination of current deductions for intangible drilling and development costs,
(iii) the elimination of the deduction for certain domestic production
activities, and (iv) an extension of the amortization period for certain
geological and geophysical expenditures.  Each of these changes is
proposed to be effective for taxable years beginning, or in the case of costs
described in (ii) and (iv), costs paid or incurred, after December 31,
2010.  It is unclear whether these or similar changes will be enacted
and, if enacted, how soon any such changes could become effective. The passage
of any legislation as a result of these proposals or any other similar changes
in U.S. federal income tax laws could eliminate certain tax deductions that are
currently available with respect to oil and gas exploration and development, and
any such change could increase the taxable income allocable to the unitholders
and negatively impact the value of an investment in the common
units.





ITEM
      1B.
            UNRESOLVED
      STAFF COMMENTS





None.














ITEM
2.                 PROPERTIES





Reserve
Rule Changes





During
2009, the SEC issued its final rule on the modernization of oil and gas
reporting (the "Reserve Ruling") and the Financial Accounting Standards Board
(the "FASB") issued Accounting Standards Update No. 2010-03 ("ASU 2010-03")
"Extractive Industries – Oil and Gas," which aligns the estimation and
disclosure requirements of FASB Accounting Standards Codification Topic 932 with
the Reserve Ruling.  The Reserve Ruling and ASU 2010-03 are effective
for Annual Reports on Form 10-K for fiscal years ending on or after December 31,
2009.  The key provisions of the Reserve Ruling and ASU 2010-03 are as
follows:





·
            Expanding
      the definition of oil- and gas-producing activities to include the
      extraction of saleable hydrocarbons, in the solid, liquid or gaseous
      state, from oil sands, coalbeds or other nonrenewable natural resources
      that are intended to be upgraded into synthetic oil or gas, and activities
      undertaken with a view to such
extraction;


·
            Amending
      the definition of proved oil and gas reserves to require the use of an
      average of the first-day-of-the-month commodity prices during the 12-month
      period ending on the balance sheet date rather than the period-end
      commodity prices;


·
            Adding
      to and amending other definitions used in estimating proved oil and gas
      reserves, such as "reliable technology" and "reasonable
      certainty";


·
            Broadening
      the types of technology that an issuer may use to establish reserves
      estimates and categories; and,


·
            Changing
      disclosure requirements and providing formats for tabular reserve
      disclosures.





Reserve
Estimation Procedures and Audits





The
information included in this Report about the Partnership's proved reserves as
of December 31, 2009, 2008 and 2007 represents evaluations prepared by Pioneer's
reservoir engineers.  Netherland, Sewell & Associates, Inc.
("NSAI") audited all of the Partnership's proved reserves as of December 31,
2009; audited the Partnership's proved reserves as of December 31, 2008 before
the Partnership completed the 2009 Acquisition; and audited the Partnership's
proved reserves as of December 31, 2007 before the Partnership completed the
2009 Acquisition and purchased the Over-allotment Property Interests (the NSAI
evaluations as of December 31, 2008 and 2007 are referred to herein as the
"Original Evaluations").  The proved reserves that NSAI audited in the
Original Evaluations have been increased by 80 percent and 62 percent as of
December 31, 2008 and 2007, respectively, to recognize the proved reserves
attributable to the 2009 Acquisition and the Over-allotment Property Interests
and, together with the proved reserves included in the Original Evaluations,
form the basis for the information included in this Report about the
Partnership's proved reserves as of December 31, 2008 and 2007.  The
Partnership has no oil and gas reserves from non-traditional
sources.





Reserve estimation
procedures.Pioneer has established internal controls over
reserve estimation processes and procedures to support the accurate and timely
preparation and disclosure of reserve estimations in accordance with SEC and
GAAP requirements.  These controls include oversight of the reserves
estimation reporting processes by Pioneer's Worldwide Reserves Group ("WWR"),
and annual external audits of all of the Partnership's proved reserves by
NSAI.





The
management of Pioneer's oil and gas assets is decentralized geographically by
individual asset teams responsible for the oil and gas activities in each of
Pioneer's operating areas.  Pioneer's Permian asset team (the "Asset
Team") is staffed with reservoir engineers and geoscientists who prepare reserve
estimates for the Permian assets at the end of each calendar quarter using
reservoir engineering information technology.  There is shared oversight of
the Asset Team's reservoir engineers by the Asset Team's managers and the
Director of the WWR, each of whom is in turn subject to direct or indirect
oversight by Pioneer's President and Chief Operating Officer ("COO") and
management committee ("MC").  Pioneer's MC is comprised of its Chief
Executive Officer, COO, Chief Financial Officer and other Executive Vice
Presidents.  The Asset Team's reserve estimates are reviewed by the
asset team reservoir engineers before being submitted to the Director of the WWR
and are summarized in reserve reconciliations that quantify reserve changes
represented by revisions of previous estimates, purchases of minerals-in-place,
extensions and discoveries, production and sales of minerals-in-place.  All
reserve estimates, material assumptions and inputs used in reserve estimates and
significant changes in reserve estimates are reviewed for engineering and
financial appropriateness and compliance with SEC and GAAP standards by the
WWR.  The MC









reviews
the consolidated reserves estimates and any differences with NSAI before the
estimates are approved. The engineers and geoscientists who participate in the
reserves estimation and disclosure process attended training on the Reserve
Ruling by external consultants and internal Pioneer programs. 
Additionally, the WWR has prepared and maintains an internal document for the
asset teams to reference on reserve estimation and preparation to promote
objectivity in the preparation of the Partnership's reserve estimates and SEC
and GAAP compliance in the reserve estimation and reporting
process.





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:





·
            A
      reserve audit is an examination of reserve information that is conducted
      for the purpose of expressing an opinion as to whether such reserve
      information, in the aggregate, is reasonable and has been presented in
      conformity with generally accepted petroleum engineering and evaluation
      principles.


·
            The
      estimation of proved reserves is an imprecise science due to the many
      unknown geologic and reservoir factors that cannot be estimated through
      sampling techniques. Since reserves are only estimates, they cannot be
      audited for the purpose of verifying exactness. Instead, reserve
      information is audited for the purpose of reviewing in sufficient detail
      the policies, procedures and methods used by a company in estimating its
      reserves so that the reserve auditors may express an opinion as to
      whether, in the aggregate, the reserve information furnished by a company
      is reasonable.


·
            The
      methods and procedures used by a company, and the reserve information
      furnished by a company, must be reviewed in sufficient detail to permit
      the reserve auditor, in its professional judgment, to express an opinion
      as to the reasonableness of the reserve information. The auditing
      procedures require the reserve auditor to prepare its own estimates of
      reserve information for the audited
properties.





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, which is included as an exhibit to this
Report, that Pioneer's estimates of the Partnership's proved oil and gas
reserves included in the Original Evaluations 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.





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.









Qualificationsofreserves preparers and
auditors.The WWR is staffed by petroleum engineers with
extensive industry experience and is managed by Pioneer's Director of WWR. 
Pioneer's petroleum engineers meet the professional qualifications of reserves
estimators and reserves auditors as defined by the "Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information," approved by the
Board of the Society of Petroleum Engineers in 2001 and revised in 2007. 
The WWR Director's qualifications include 32 years of experience as a petroleum
engineer, with 25 years focused on reserves reporting for independent oil and
gas companies, including Pioneer.  His educational background includes an
undergraduate degree in Chemical Engineering and a Masters in Business
Administration in Finance.  He is also a Chartered Financial Analyst
("CFA") charterholder and a member of the Oil and Gas Reserves Committee of the
Society of Petroleum Engineers.





NSAI
provides worldwide petroleum property analysis services for energy clients,
financial organizations and government agencies.  NSAI was founded in 1961
and performs consulting petroleum engineering services under Texas Board of
Professional Engineers Registration No. F-002699.  The technical person
primarily responsible for auditing the Partnership's reserves estimates has been
a practicing consulting petroleum engineer at NSAI since 1983 and has over 30
years of practical experience in petroleum engineering, including 29 years
experience in the estimation and evaluation of proved reserves.  He
graduated with a Bachelor of Science degree in Chemical Engineering in 1978 and
meets or exceeds the education, training, and experience requirements set forth
in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information" promulgated by the Society of Petroleum
Engineers.





Technologies used in reserves
estimates.Pioneer uses reliable technologies to establish reserve
estimates on behalf of the Partnership. The technology that Pioneer uses
includes a combination of seismic data and interpretation, wireline formation
tests, geophysical logs and core data to determine reserves
estimates.





Proved
reserves. The Partnership's proved reserves totaled 44,365 MBOE, 40,805
MBOE and 55,591 MBOE at December 31, 2009, 2008 and 2007, respectively,
representing $262.3 million, $187.2 million and $987.3 million, respectively, of
Standardized Measure. Changes in the Partnership's proved reserve volumes during
the year ended December 31, 2009 included production of 2,243 MBOE, additions of
147 MBOE and revisions of previous estimates of 5,656 MBOE.  Revisions
of previous estimates are comprised of 4,396 MBOE of positive price revisions
and 1,260 MBOE of favorable technical revisions.  The Partnership's
proved reserves at December 31, 2009 were determined using an average of the
NYMEX spot prices for sales of oil and gas on the first calendar day of each
month during 2009.  On this basis, the price of oil and gas for 2009
proved reserve reporting purposes was $61.14 per barrel of oil and $3.87 per Mcf
of gas, compared to year end NYMEX spot prices of $44.60 per barrel of oil and
$5.71 per Mcf of gas at December 31, 2008.





Tabular proved reserves
disclosures.On a BOE basis, 73 percent of the Partnership's
total proved reserves at December 31, 2009 were proved developed reserves. The
following table provides information regarding the Partnership's proved reserves
and Standardized Measure as of December 31, 2009:





Summary
      of Oil and Gas Reserves as of December 31, 2009 Based onAverage Fiscal
      Year PricesStandardizedOil
            
            NGLs
            
            Gas
            
            
            
            
            Measure(MBbls)
            
            (MBbls)
            
            (MMcf)
            
            MBOE
            
            
            (in
      thousands)ProvedDeveloped
            19,726
            
            7,396
            
            30,548
            
            32,213
            
            $
            258,712Undeveloped
            8,015
            
            2,451
            
            10,116
            
            12,152
            
            
            3,584Total
      proved (a)
            27,741
            
            9,847
            
            40,664
            
            44,365
            
            $
            262,296


_______


(a)
            See
      Unaudited Supplementary Information included in "Item 8. Financial
      Statements and Supplementary Data" for information regarding the impact of
      adopting the Reserve Ruling and ASU 2010-03 on the Partnership's proved
      reserves and Standardized Measure.





Proved undeveloped
reserves.As of December 31, 2009, the Partnership had 170
proved undeveloped well locations (all of which are expected to be developed
within the five year period ending December 31, 2014), representing an increase
of two proved undeveloped well locations (one percent) since December 31,
2008.  During 2009, three proved undeveloped well locations were
drilled and completed as developed wells, at a net cost of $1.9









million.  The
Partnership's proved undeveloped reserves totaled 12,152 MBOE and 11,050 MBOE at
December 31, 2009 and 2008, respectively. Changes in the Partnership's proved
undeveloped reserve volumes during the year ended December 31, 2009 included
additions of 147 MBOE and revisions of previous estimates of 954
MBOE.  Revisions of previous estimates are primarily comprised of
positive price revisions.  The Partnership's proved undeveloped well
locations as of December 31, 2009 included 64 proved undeveloped well locations
that have remained undeveloped for five years or more.  Prior to the
2009 Acquisition, all of the Partnership's proved undeveloped well locations
were part of the Partnership Predecessor and, as such, they were part of
Pioneer's inventory of undeveloped well locations in the Spraberry
field.  In November 2009, the Partnership commenced a two-rig drilling
program to develop its proved undeveloped properties.  The Partnership
drilled six wells in 2009, but production on the new wells did not begin until
early 2010.  See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations – Capital commitments" for more
information about the Partnership's two-rig drilling program.  The
following table represents the estimated timing and cash flows of developing the
Partnership's proved undeveloped reserves as of December 31, 2009 (dollars in
thousands):





EstimatedFuture
            
            Future
            
            Future
            
            FutureProduction
            
            Cash
            
            Production
            
            Development
            
            Future
      NetYear
      Ended December 31, (a)
            
            (MBOE)
            
            Inflows
            
            Costs
            
            Costs
            
            Cash
      Flows2010
            
            166
            
            $
            7,936
            
            $
            1,242
            
            $
            40,290
            
            $
            (33,596)2011
            
            481
            
            
            23,122
            
            
            3,991
            
            
            41,379
            
            
            (22,248)2012
            
            689
            
            
            33,358
            
            
            5,962
            
            
            46,042
            
            
            (18,646)2013
            
            874
            
            
            42,484
            
            
            7,882
            
            
            31,919
            
            
            2,6832014
            
            762
            
            
            36,723
            
            
            7,371
            
            
            -
            
            
            29,352Thereafter
            
            9,180
            
            
            433,279
            
            
            251,287
            
            
            2,880
            
            
            179,11212,152
            
            $
            576,902
            
            $
            277,735
            
            $
            162,510
            
            $
            136,657


______


(a)
            Beginning
      in 2010 and thereafter, the production and cash flows represent the
      drilling results from the respective year plus the incremental effects of
      proved undeveloped drilling.





Description
of Properties





Currently, the Partnership's oil and
gas properties consist only of non-operated working interests in oil and gas
properties in the Spraberry field in the Permian Basin area of West Texas, all
of which are operated by Pioneer, including 1,155 producing wells. The
Partnership's interest in 1,037 of these wells is 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.





All of
the Partnership's proved reserves at December 31, 2009 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 second 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.





Costs
incurred for 2009 totaled $66.7 million and were comprised of $60.0 million,
representing Pioneer's carrying value of the net assets at the completion date
of the 2009 Acquisition, $5.7 million of development drilling expenditures
associated with new wells and a $1.0 million increase in asset 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's properties as of and for each of the years ended December 31,
2009, 2008 and 2007. 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's properties for the years ended
December 31, 2009, 2008 and 2007. These amounts represent the Partnership's
historical results without making pro forma adjustments for any drilling
activity that occurred during the respective years.





Year
      Ended December 31,2009
            
            2008
            
            2007Production
      information:Annual
      sales volumes:Oil
      (MBbls)
            
            
            1,344
            
            
            1,441
            
            
            1,543NGLs
      (MBbls)
            
            
            518
            
            
            476
            
            
            602Gas
      (MMcf)
            
            
            2,281
            
            
            2,133
            
            
            2,318Total
      (MBOE)
            
            
            2,243
            
            
            2,272
            
            
            2,531Average
      daily sales volumes:Oil
      (Bbls)
            
            
            3,683
            
            
            3,937
            
            
            4,226NGLs
      (Bbls)
            
            
            1,420
            
            
            1,298
            
            
            1,649Gas
      (Mcf)
            
            
            6,248
            
            
            5,828
            
            
            6,352Total
      (BOE)
            
            
            6,145
            
            
            6,206
            
            
            6,934Average
      prices, including hedge results (a):Oil
      (per Bbl)
            
            $
            100.35
            
            $
            107.79
            
            $
            71.28NGL
      (per Bbl)
            
            $
            41.61
            
            $
            48.41
            
            $
            37.41Gas
      (per Mcf)
            
            $
            5.37
            
            $
            7.06
            
            $
            4.98Revenue
      (per BOE)
            
            $
            75.23
            
            $
            85.14
            
            $
            56.91Average
      prices, excluding hedge results (a):Oil
      (per Bbl)
            
            $
            58.05
            
            $
            99.71
            
            $
            71.28NGL
      (per Bbl)
            
            $
            25.56
            
            $
            45.84
            
            $
            37.41Gas
      (per Mcf)
            
            $
            2.81
            
            $
            6.24
            
            $
            4.98Revenue
      (per BOE)
            
            $
            43.56
            
            $
            78.69
            
            $
            56.91Average
      costs (per BOE):Production
      costs:Lease
      operating (b)
            
            $
            14.04
            
            $
            14.24
            
            $
            9.21Workover
            
            
            1.46
            
            
            2.85
            
            
            1.80Total
      production costs
            
            $
            15.50
            
            $
            17.09
            
            $
            11.01Production
      and ad valorem taxes:Ad
      valorem
            
            $
            2.09
            
            $
            2.23
            
            $
            1.60Production
            
            
            2.17
            
            
            4.02
            
            
            2.96Total
      production and ad valorem taxes
            
            $
            4.26
            
            $
            6.25
            
            $
            4.56Depletion
      expense
            
            $
            5.80
            
            $
            5.10
            
            $
            4.50


______


(a)
            The
      Partnership discontinued hedge accounting effective February 1,
      2009.  Hedge results beginning February 1, 2009 represent the
      transfer to oil and gas revenues of net deferred hedge gains included in
      accumulated other comprehensive income as of the de-designation
      date.


(b)
            Historical
      lease operating expense associated with those properties acquired in
      August 2009 and the Partnership's properties that were acquired in
      conjunction with the initial public offering in May 2008 include the
      direct internal costs of Pioneer to operate the properties.  The
      lease operating expense of the properties after they were acquired by the
      Partnership includes COPAS Fees.  Assuming the COPAS Fees had
      been charged in the Partnership Predecessor's historical results, the
      Partnership's lease operating expense would have been higher on a BOE
      basis by approximately $0.15, $1.03 and $2.63 for 2009, 2008 and 2007,
      respectively.















Productive
wells.The following table sets forth the number of productive
oil and gas wells attributable to the Partnership's properties as of December
31, 2009, 2008 and 2007:





PRODUCTIVE
WELLS (a)





Gross
      Productive Wells
            
            Net
      Productive WellsOil
            
            Gas
            
            Total
            
            Oil
            
            Gas
            
            TotalAs
      of December 31, 2009
            
            1,155
            
            -
            
            1,155
            
            981
            
            -
            
            981As
      of December 31, 2008
            
            1,158
            
            -
            
            1,158
            
            1,003
            
            -
            
            1,003As
      of December 31, 2007
            
            1,163
            
            -
            
            1,163
            
            1,008
            
            -
            
            1,008


______


(a)
            All
      of the Partnership's wells are operated by Pioneer.  Productive
      wells consist of producing wells and wells capable of production,
      including shut-in wells.  The Partnership had no multiple
      completion wells as of December 31,
2009.





Leasehold acreage.The
following table sets forth information about the Partnership's developed and
undeveloped leasehold acreage as of December 31, 2009:





Developed
      Acreage
            
            Undeveloped
      AcreageGross
      Acres
            
            Net
      Acres
            
            Gross
      Acres
            
            Net
      AcresSpraberry
      field
            
            8,028
            
            7,575
            
            6,844
            
            6,494





The following table sets forth the
expiration dates of the leases on the Partnership's gross and net undeveloped
acres as of December 31, 2009:




Acres
      Expiring (a)Gross
            
            Net2010
            
            2,081
            
            2,052


______


(a)
            The
      Partnership's undeveloped acreage represents proved undeveloped acreage
      held by productive wells except for 2,081 acres (2,052 net acres) that are
      subject to a continuous drilling commitment.  The continuous
      drilling commitment obligates Pioneer and the Partnership to spud a well
      by February 1, 2010, which was done, and then spud another well thereafter
      within 120 days of completing the previous well.  These acres
      will not expire if the continuous drilling commitment is
      fulfilled.





Drilling
activities.The following table sets forth the number of gross
and net productive and dry hole wells that were drilled during 2009, 2008 and
2007, 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





Gross
      Wells
            
            Net
      WellsYear
      Ended December 31,
            
            Year
      Ended December 31,2009
            
            2008
            
            2007
            
            2009
            
            2008
            
            2007Productive
      wells: (a)Development
            
            6
            
            9
            
            11
            
            6
            
            9
            
            10Exploratory
            
            -
            
            -
            
            -
            
            -
            
            -
            
            -Dry
      holes:Development
            
            -
            
            -
            
            -
            
            -
            
            -
            
            -Exploratory
            
            -
            
            -
            
            -
            
            -
            
            -
            
            -Total
            
            6
            
            9
            
            11
            
            6
            
            9
            
            10


______


(a)
            As
      of December 31, 2009, drilling on two gross wells (two net wells) was in
      progress.  The Partnership had no wells upon which drilling was
      in progress as of December 31, 2008 and
2007.












ITEM
3.                      LEGAL
PROCEEDINGS





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.





ITEM
4.                 SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS





The Partnership did not submit any
matters to a vote of security holders during the fourth quarter of
2009.












PART
II





ITEM
5.                 MARKET
FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES
OF EQUITY SECURITIES





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 totaling $2.00 per unit during 2009.  On January 25, 2010,
the Board of Directors of the General Partner declared a $0.50 per unit
distribution payable on February 11, 2010 to unitholders of record on February
4, 2010.





The
following table sets forth quarterly high and low prices of the Partnership's
common units and distributions declared per unit for the years ended December
31, 2009 and 2008:





DividendsDeclaredHigh
            
            Low
            
            Per
      UnitYear
      ended December 31, 2009Fourth
      quarter
            $
            22.67
            
            $
            18.51
            
            $
            0.50Third
      quarter
            $
            21.25
            
            $
            17.03
            
            $
            0.50Second
      quarter
            $
            20.03
            
            $
            15.50
            
            $
            0.50First
      quarter
            $
            17.60
            
            $
            13.01
            
            $
            0.50Year
      ended December 31, 2008Fourth
      quarter
            $
            17.20
            
            $
            9.98
            
            $
            0.50Third
      quarter
            $
            22.68
            
            $
            14.35
            
            $
            0.31Second
      quarter
            $
            22.58
            
            $
            18.92
            
            $
            -





On
February 23, 2010, the last reported sales price of the Partnership's common
units, as reported in the NYSE composite transactions, was $22.50 per
unit.





As of
February 23, 2010, the Partnership's common units were held by 14 holders of
record. This number does not include owners for whom common units may be held in
"street" name.





During the fourth quarter of 2009, the
Partnership did not repurchase any common units.





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. 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.









ITEM
6.                 SELECTED
FINANCIAL DATA







The
following selected financial data as of and for the five years ended December
31, 2009 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."




Year
      Ended December 31,2009
            
            2008
            
            2007
            
            2006
            
            2005Statements
      of Operations Data:
            (in
      thousands, except per unit data)Revenues:Oil
      and gas
            $
            168,717
            
            $
            193,394
            
            $
            144,038
            
            $
            126,918
            
            $
            106,265Interest
      and other
            
            210
            
            
            192
            
            
            -
            
            
            -
            
            
            -168,927
            
            
            193,586
            
            
            144,038
            
            
            126,918
            
            
            106,265Costs
      and expenses:Oil
      and gas production  (a)
            
            34,749
            
            
            38,807
            
            
            27,879
            
            
            24,133
            
            
            19,589Production
      and ad valorem taxes
            
            9,547
            
            
            14,213
            
            
            11,550
            
            
            11,124
            
            
            8,902Depletion,
      depreciation and amortization
            
            13,016
            
            
            11,582
            
            
            11,382
            
            
            9,678
            
            
            7,943General
      and administrative
            
            4,790
            
            
            6,227
            
            
            5,643
            
            
            5,345
            
            
            5,537Accretion
      of discount on asset retirement obligations
            
            484
            
            
            144
            
            
            143
            
            
            136
            
            
            127Interest
            
            1,160
            
            
            621
            
            
            -
            
            
            -
            
            
            -Derivative
      losses, net (b)
            
            78,265
            
            
            -
            
            
            -
            
            
            -
            
            
            -Other,
      net
            
            549
            
            
            890
            
            
            5
            
            
            25
            
            
            70142,560
            
            
            72,484
            
            
            56,602
            
            
            50,441
            
            
            42,168Income
      before taxes
            
            26,367
            
            
            121,102
            
            
            87,436
            
            
            76,477
            
            
            64,097Income
      tax provision
            
            (46)
            
            
            (1,326)
            
            
            (920)
            
            
            (323)
            
            
            -Net
      income
            $
            26,321
            
            $
            119,776
            
            $
            86,516
            
            $
            76,154
            
            $
            64,097Allocation
      of net income:Net
      income (loss) applicable to the Partnership Predecessor
            $
            (1,598)
            
            $
            59,038
            
            $
            86,516
            
            $
            76,154
            
            $
            64,097Net
      income applicable to the Partnership
            
            27,919
            
            
            60,738
            
            
            -
            
            
            -
            
            
            -Net
      income
            $
            26,321
            
            $
            119,776
            
            $
            86,516
            
            $
            76,154
            
            $
            64,097Allocation
      of net income applicable to the Partnership:General
      partner's interest in net income
            $
            28
            
            $
            61Limited
      partners' interest in net income
            
            27,891
            
            
            60,677Net
      income applicable to the Partnership
            $
            27,919
            
            $
            60,738Net
      income per common unit – basic and diluted
            $
            0.92
            
            $
            2.02Weighted
      average common units outstanding – basic and diluted
            
            30,399
            
            
            30,009Distributions
      declared per common unit
            $
            2.00
            
            $
            0.81Balance
      Sheet Data (as of December 31):Total
      assets
            $
            256,638
            
            $
            367,164
            
            $
            217,702
            
            $
            209,687
            
            $
            174,399Long-term
      debt
            $
            67,000
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -Partners'
      equity
            $
            141,273
            
            $
            347,831
            
            $
            207,569
            
            $
            196,498
            
            $
            164,576


________


(a)
            Historical
      oil and gas production costs associated with those properties acquired in
      August 2009 and the Partnership's properties that were acquired in
      conjunction with the initial public offering in May 2008 include the
      direct internal costs of Pioneer to operate the properties.  The
      oil and gas production costs of the properties after they were acquired by
      the Partnership include COPAS Fees.(b)
            On
      January 31, 2009, the Partnership discontinued hedge accounting for its
      derivative contracts and began using the mark-to-market method of
      accounting for derivatives.  See "Item 7A. Quantitative and
      Qualitative Disclosures About Market Risk" and Notes B and H of Notes to
      Consolidated Financial Statements included in "Item 8. Financial
      Statements and Supplementary Data" for information about the Partnership's
      derivative contracts and associated accounting
  methods.












ITEM 7.
            MANAGEMENT'S DISCUSSION AND
      ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
      OPERATIONS





Presentation





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. Pioneer formed Pioneer Southwest Energy Partners USA LLC ("Pioneer
Southwest LLC") to hold certain of the Partnership's oil and gas properties
located in the Spraberry field in the Permian Basin of West Texas (the
"Spraberry field").  To effect the Offering, Pioneer (i) contributed
to the Partnership a portion of its interest in Pioneer Southwest LLC for
additional general and limited partner interests in the Partnership, (ii) sold
to the Partnership its remaining interest in Pioneer Southwest LLC for $141.1
million, (iii) sold incremental working interests in certain of the oil and gas
properties owned by Pioneer Southwest LLC to the Partnership for $22.0 million,
which amount represented the net proceeds from the exercise by the underwriters
of the over-allotment option (the transactions described in (i), (ii) and (iii)
above are referred to in the aggregate as the "2008 IPO Acquisitions") 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 LLC became a wholly-owned subsidiary of the
Partnership.





On August
31, 2009, the Partnership completed an acquisition of certain oil and gas
properties in the Spraberry field and assumed net obligations associated with
certain commodity price derivative positions and certain other liabilities from
Pioneer pursuant to a Purchase and Sale Agreement having an effective date of
July 1, 2009 (the acquisition, including liabilities assumed, is referred herein
as the "2009 Acquisition").





Because the 2009 Acquisition represents
a transaction between entities under common control, the Partnership's operating
and financial results, including the accompanying consolidated financial
statements included in "Item 8. Financial Statements and Supplementary Data,"
have been recast for all periods prior to the 2009 Acquisition, similar to a
pooling of interests, to include the financial position, results of operations
and cash flows of the assets acquired and liabilities assumed in the 2009
Acquisition.  The recast historical financial information presents the
acquired assets as if they were owned by the Partnership for all periods
presented.  See Note B of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for more
information about the Partnership's accounting presentations.





The balances and activity included
in the Partnership's financial position, results of operations, cash flows and
changes in owner's equity of the property interests acquired and the liabilities
assumed in the 2009 Acquisition (representing periods prior to August 31, 2009)
and the 2008 IPO Acquisitions (representing periods prior to May 6, 2008) are
referred to herein as the "Partnership Predecessor". Therefore, the financial
statements and financial information for the years ended December 31, 2009, 2008
and 2007 reflect the operations of the Partnership combined with the Partnership
Predecessor for all periods presented.





Financial
and Operating Performance





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





·
            Net
      income decreased 78 percent to $26.3 million in 2009 from $119.8 million
      in 2008.  The decrease in earnings is primarily attributable to
      (i) $67.0 million of unrealized net derivative losses recorded in 2009
      under the mark-to-market accounting method and (ii) declines in realized
      commodity prices during 2009, partially offset by (iii) the financial
      impact of operating cost reduction
initiatives.


·
            Daily
      sales volumes declined one percent to 6,145 BOEPD in 2009, as compared to
      6,206 BOEPD for 2008.


·
            Average
      reported oil, NGL and gas sales prices decreased to $100.35, $41.61 and
      $5.37, respectively, during 2009 as compared to $107.79, $48.41 and $7.06,
      respectively, for 2008.


·
            Net
      cash provided by operating activities decreased by $49.9 million, or 38
      percent, as compared to 2008, primarily due to lower realized commodity
      prices and changes in working
capital.













Significant
Events





Acquisition from
Pioneer.On August 31, 2009, the Partnership completed an
acquisition of oil and gas properties in the Spraberry field (the "2009
Acquisition") pursuant to a Purchase and Sale Agreement having an effective date
of July 1, 2009.  Associated therewith, the Partnership paid Pioneer
$168.2 million of cash, including customary closing adjustments, and assumed net
obligations associated with certain commodity price derivative positions and
certain other liabilities that were assigned by Pioneer to the
Partnership.  The 2009 Acquisition was funded with cash on hand and
borrowings under the Partnership's credit facility.





Drilling
opportunities.The 2009 Acquisition included proved
undeveloped leasehold acreage representing approximately 170 40-acre drilling
locations.  As part of the acquisition, the Partnership announced its
plans to initiate a two-rig drilling program in the fourth quarter of 2009 to
develop its acreage.  Under its announced drilling plan, the
Partnership drilled six wells in 2009 and, based on current plans, expects to
drill approximately 50 wells in 2010.





During 2008, Pioneer initiated a
program to test 20-acre infill drilling performance in the Spraberry
field.  Pioneer drilled and completed eleven 20-acre wells in 2008 and
completed nine additional 20-acre wells in 2009 with encouraging
results.  The Partnership's future investing activities may include
expenditures to drill a limited number of 20-acre locations surrounding the
Partnership's wells if forecasted drilling costs and operating margins justify
the expenditures.





2009 equity
offering.On November 16, 2009, the Partnership completed the
2009 Equity Offering of 3,105,000 of its common units representing limited
partner interests.  Net proceeds from the 2009 Equity Offering of
$61.0 million were used to reduce credit facility
borrowings.  Following the 2009 Equity Offering, Pioneer owns a 61.9
percent limited partner interest in the Partnership.





Modernization of
oil and gas reporting.During 2009, the SEC issued the Reserve
Ruling and the FASB issued ASU 2010-03.  The Reserve Ruling and ASU
2010-03 are effective for Annual Reports on Forms 10-K for fiscal years ending
on or after December 31, 2009.  The key provisions of the Reserve
Ruling and ASU 2010-03 which impact the Partnership's disclosures and
consolidated financial statements are as follows:





·
            Amending
      the definition of proved oil and gas reserves to require the use of an
      average of the first-day-of-the-month commodity prices during the 12-month
      period ending on the balance sheet date rather than the period-end
      commodity prices,


·
            Adding
      to and amending other definitions used in estimating proved oil and gas
      reserves, such as "reliable technology" and "reasonable
      certainty,"


·
            Broadening
      the types of technology that an issuer may use to establish reserves
      estimates and categories, and


·
            Changing
      disclosure requirements and providing formats for tabular reserve
      disclosures, including the following new disclosure
      provisions:


o
            Disclosure
      of an issuer's internal controls over reserves estimation and the
      qualifications of the business entity or individual preparing or auditing
      the reserves estimates,


o
            Disclosure
      based on a new definition of the term "geographic area,"
    and


o
            Disclosure
      of the development of proved undeveloped
  reserves.





See "Item
2. Properties," "Results of Operations – Depletion, depreciation and
amortization expense" below and supplementary disclosures in "Item 8. Financial
Statements and Supplementary Data" for associated disclosures and information
about how the adoption of the Reserve Ruling and ASU 2010-03 impacted the
Partnership.





Commodity
prices.  Beginning in the second half of 2008 and continuing
throughout 2009, the United States and other industrialized countries
experienced a significant economic slowdown, which led to a substantial decline
in worldwide energy demand. During this same time period, North American gas
supply was increasing as a result of the rise in domestic unconventional gas
production. The combination of lower energy demand due to the economic slowdown
and higher North American gas supply resulted in significant declines in oil,
NGL and gas prices. While oil and NGL prices started to steadily increase
beginning in the second quarter of 2009, gas prices remained volatile throughout
2009 due to high storage levels and increasing gas supply.  The
outlook for a worldwide economic recovery in 2010 remains uncertain, and the
timing of a recovery in worldwide demand for energy is difficult to
predict.  As a result, it is likely that commodity prices during 2010
will continue to be volatile.












To
mitigate the risk associated with commodity price volatility, the Partnership
has entered into commodity price derivatives.  As of December 31,
2009, the Partnership had oil swap and collar contracts equivalent to
approximately 90 percent of its forecasted production for the years 2010 through
2012 and 85 percent of its forecasted production for 2013; NGL swap contracts
for approximately 55 percent of its forecasted production for the years 2010 and
2011 and for approximately 50 percent of its forecasted production for 2012; and
gas swap contracts for approximately 90 percent of its forecasted production for
the year 2010, approximately 45 percent of its forecasted production for 2011
and approximately 40 percent of its forecasted production for the years 2012 and
2013.





Although
the Partnership has entered into derivative contracts on a large portion of its
production volumes through 2013, a sustained lower commodity price environment
would result in lower realized prices for unprotected volumes and reduce the
prices at which the Partnership could enter into derivative contracts on
additional volumes in the future. As a result, the Partnership's internal cash
flows would be reduced for affected periods. The timing, duration and magnitude
of any period of lower commodity prices cannot be predicted. A sustained decline
in commodity prices could result in a shortfall in expected cash flows and
require the Partnership to reduce its distributions.  Additionally, a
sustained decline in commodity prices could reduce the Partnership's borrowing
capacity under its credit facility. 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.





First
Quarter 2010 Outlook





Based on current estimates, the
Partnership expects that production will average 5,800 to 6,200
BOEPD.





Production
costs (including production and ad valorem taxes) are expected to average $20.00
to $23.00 per BOE based on current NYMEX strip prices for oil, NGLs and
gas.  Depletion, depreciation and amortization ("DD&A") expense is
expected to average $5.00 to $6.00 per BOE.





General
and administrative expense is expected to be $1 million to $2
million.  Interest expense is expected to be $400 thousand to $600
thousand and accretion of discount on asset retirement obligations is expected
to be nominal.





The
Partnership's cash taxes and effective income tax rate are expected to be
approximately one percent of earnings before income taxes, as a result of the
Partnership being subject to the Texas margin tax.





Results
of Operations





Oil and gas
revenues.Oil and gas revenues totaled $168.7 million, $193.4
million and $144.0 million during 2009, 2008 and 2007,
respectively.  The decrease in revenue during 2009, as compared to
2008, was primarily due to decreases in commodity prices and a slight decrease
in average daily sales volumes.  Average reported oil, NGL and gas
prices for 2009 decreased by seven percent, 14 percent and 24 percent,
respectively, as compared to the respective 2008 reported prices.  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, NGL and gas prices for 2008, as
compared to 2007, increased by 51 percent, 29 percent and 42 percent,
respectively.





The following table provides average
daily sales volumes for 2009, 2008 and 2007:





Year
      Ended December 31,2009
            
            2008
            
            2007Oil
      (Bbls)
            
            3,683
            
            3,937
            
            4,226NGLs
      (Bbls)
            
            1,420
            
            1,298
            
            1,649Gas
      (Mcf)
            
            6,248
            
            5,828
            
            6,352Total
      (BOE)
            
            6,145
            
            6,206
            
            6,934













The
following table provides average reported prices, including the results of
hedging activities, and average realized prices, excluding the results of
hedging activities, for 2009, 2008 and 2007:





Year
      Ended December 31,2009
            
            2008
            
            2007Average
      reported prices:Oil
      (per Bbl)
            
            $
            100.35
            
            $
            107.79
            
            $
            71.28NGL
      (per Bbl)
            
            $
            41.61
            
            $
            48.41
            
            $
            37.41Gas
      (per Mcf)
            
            $
            5.37
            
            $
            7.06
            
            $
            4.98Total
      (per BOE)
            
            $
            75.23
            
            $
            85.14
            
            $
            56.91Average
      realized prices:Oil
      (per Bbl)
            
            $
            58.05
            
            $
            99.71
            
            $
            71.28NGL
      (per Bbl)
            
            $
            25.56
            
            $
            45.84
            
            $
            37.41Gas
      (per Mcf)
            
            $
            2.81
            
            $
            6.24
            
            $
            4.98Total
      (per BOE)
            
            $
            43.56
            
            $
            78.69
            
            $
            56.91








Derivative
activities.The
Partnership utilizes commodity swap and collar contracts to reduce the impact of
commodity price volatility on the Partnership's net cash provided by operating
activities. Effective
February 1, 2009, the Partnership discontinued hedge accounting on all existing
commodity derivative instruments and from that date forward began accounting for
all derivative instruments using the mark-to-market accounting
method.  Consequently, since February 1, 2009, the Partnership has
recognized changes in the fair values of its derivative contracts as gains or
losses in the earnings of the period in which they occurred.





Interest.The
Partnership's interest income totaled $210 thousand and $192 thousand during
2009 and 2008, respectively.  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 $34.7 million, $38.8 million and $27.9 million during 2009, 2008
and 2007, respectively. Total production costs per BOE decreased during 2009 by
nine percent as compared to 2008 primarily due to the financial impact of cost
reduction initiatives implemented by Pioneer, including reductions in
electricity costs, saltwater disposal fees and oilfield services
costs.  Workover costs were significantly lower in 2009, as compared
to 2008, primarily as a result of lower commodity prices reducing the return on
investment associated with certain workovers such that they were not economical
to perform.





The
Partnership Predecessor's lease operating expense includes an allocation of
Pioneer's direct internal costs associated with the operation of the properties
prior to their acquisition by the Partnership. Upon completion of the 2008 IPO
Acquisitions and the 2009 Acquisition, Pioneer, as operator, began charging the
Partnership COPAS Fees, 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 $0.15, $1.03 and $2.63 for 2009, 2008 and 2007,
respectively.





Total
production costs per BOE increased during 2008 by 55 percent as compared to 2007
primarily due to (i) normal production declines over which the fixed portion of
production costs per BOE are attributed, (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 overhead charges as a result of COPAS Fees and (iv) increases
in workover costs incurred to maximize production volumes as wells
mature.










The following table provides the
components of the Partnership's production costs per BOE for 2009, 2008 and
2007:





Year
      Ended December 31,2009
            
            2008
            
            2007Lease
      operating expenses
            
            $
            14.04
            
            $
            14.24
            
            $
            9.21Workover
      costs
            
            
            1.46
            
            
            2.85
            
            
            1.80Total
      production costs
            
            $
            15.50
            
            $
            17.09
            
            $
            11.01





Production and ad
valorem taxes.The Partnership recorded production and ad
valorem taxes of $9.5 million, $14.2 million and $11.5 million during 2009, 2008
and 2007, respectively.  The decrease in 2009 was primarily the result
of overall declines in commodity prices.  The increase during 2008, as
compared to 2007, was primarily the result of overall increases in commodity
prices.





The following table provides the
components of the Partnership's total production and ad valorem taxes per BOE
for 2009, 2008 and 2007:





Year
      Ended December 31,2009
            
            2008
            
            2007Ad
      valorem taxes
            
            $
            2.09
            
            $
            2.23
            
            $
            1.60Production
      taxes
            
            
            2.17
            
            
            4.02
            
            
            2.96Total
      production and ad valorem taxes
            
            $
            4.26
            
            $
            6.25
            
            $
            4.56





Depletion,
depreciation and amortization expense.The Partnership's
depletion expense was $5.80, $5.10 and $4.50 per BOE for 2009, 2008 and 2007,
respectively. During 2009, the increase in per BOE depletion expense was
primarily due to the declines in end-of-well-life reserve volumes as a result of
lower commodity prices during 2009, as compared to 2008.





During
2009, the Partnership adopted the provisions of the Reserve Ruling and ASU
2010-03.  The Reserve Ruling and ASU 2010-03, which became effective
for Annual Reports on Forms 10-K for fiscal years ending on or after December
31, 2009, changed the definition of proved oil and gas reserves to require the
use of an average of the first-day-of-the-month commodity prices during the
12-month period ending on the balance sheet date rather than the period-end
commodity prices, added to and amended certain definitions used in estimating
proved oil and gas reserves, such as "reliable technology" and "reasonable
certainty," and broadened the types of technology that an issuer may use to
establish reserves estimates and categories.  The new pricing
provisions of the Reserve Ruling reduced the Partnership's fourth quarter 2009
end-of-well-life reserves from what they would have been under the previous
definition of proved reserves that used end of period pricing, thereby
increasing the Partnership's DD&A expense in the fourth quarter of 2009 by
approximately $337 thousand, or $0.15 per BOE for the year ended December 31,
2009.  The other provisions of the Reserve Ruling and ASU 2010-03 did
not have a material effect on the Partnership as of and for the periods ended
December 31, 2009.





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.





General and
administrative expense.General and administrative expense
totaled $4.8 million, $6.2 million and $5.6 million during 2009, 2008 and 2007,
respectively. The decrease in general and administrative expense during 2009, as
compared to 2008, was primarily due to a reduction in the per BOE rate used to
allocate a portion of Pioneer's general and administrative expense to the
Partnership.  The increase in general and administrative expense
during 2008, as compared to 2007, was primarily due to legal, accounting and
other costs associated with being a public company that were not necessary prior
to the Offering.  The Partnership Predecessor's general and
administrative expense consisted of an allocation of a portion of Pioneer's
general and administrative expense based on the Partnership Predecessor's
production as compared to Pioneer's total production from its United States
properties (other than Alaska), as measured on a per-barrel-of-oil-equivalent
basis. The Partnership and Pioneer entered into an Administrative Services
Agreement as of May 6, 2008, pursuant to which Pioneer agreed to perform, either
itself or through its affiliates or other third parties, administrative services
for the Partnership, and the









Partnership
agreed to reimburse Pioneer for its expenses incurred in providing such
services.  Pioneer has informed the Partnership that expenses will be
reimbursed based on a methodology of determining the Partnership's share, on a
per BOE basis, of certain of the general and administrative costs incurred by
Pioneer.  Subsequent to the Offering, the Partnership is also
responsible for paying for direct third-party services.  See Note E of
Notes to 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 $1.2 million for 2009, as
compared to $621 thousand for 2008.  Prior to the 2009 Acquisition in
August 2009, the Partnership's interest expense related primarily to fees
associated with maintaining its credit facility.  Interest expense
increased during 2009, as compared to 2008, because the Partnership had no
outstanding debt prior to the 2009 Acquisition.  The Partnership
borrowed $138.0 million under its credit facility to fund a portion of the cash
consideration associated with the 2009 Acquisition.  The Partnership
used the proceeds from the 2009 Equity Offering in November 2009 to pay down a
portion of its credit facility borrowings, resulting in outstanding borrowings
of $67.0 million at December 31, 2009.  For the four-month period
subsequent to the 2009 Acquisition, the Partnership's weighted average debt
outstanding under its credit facility was $115.1 million.  The
Partnership's 2009 interest expense increased primarily as a result of this
increase in indebtedness.  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 $549 thousand during 2009 as
compared to $890 thousand during 2008 and $5 thousand during
2007.  Other expenses in 2009 related primarily to the professional
costs associated with the 2009 Acquisition.  Other expenses in 2008
related primarily to the Partnership's evaluation of a potential assignment by
Pioneer to the Partnership of Pioneer's option to acquire an incremental
interest in a gas processing plant partially owned by Pioneer.





Derivative loss,
net.Effective February 1, 2009, the Partnership discontinued
hedge accounting on all existing commodity derivative instruments, and since
that date has accounted for derivative instruments using the mark-to-market
accounting method.  Fluctuations in commodity prices since February 1,
2009 have impacted the fair value of the Partnership's derivative instruments
and resulted in net mark-to-market derivative losses of $78.3 million for
2009.  For 2008, the Partnership accounted for its derivative
instruments as cash flow hedges and effective changes in the fair values of the
derivative instruments were recognized in AOCI - Hedging.  See Note H
of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding the
types of derivative transactions in which the Partnership
participates.





Income tax
provision.The Partnership recognized income tax provisions of $46
thousand, $1.3 million and $920 thousand during 2009, 2008 and 2007,
respectively.  The Partnership's tax provision is reflective of the
Texas margin tax.  See Note L of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
additional information regarding the Partnership's income taxes.





Capital
Commitments, Capital Resources and Liquidity





Capital
commitments.The Partnership's primary cash funding needs will
be for production growth through drilling initiatives and acquisitions and for
unitholder distributions. The Partnership may use any combination of internally-
and externally-financed sources to fund drilling activities, acquisitions and
unitholder distributions, including borrowings under its credit facility and
funds from future private and public equity and debt offerings.





In
conjunction with the undeveloped properties acquired in the 2009 Acquisition,
the Partnership commenced a two-rig drilling program in November
2009.  The Partnership drilled six wells in 2009 and plans to drill
approximately 50 wells during 2010 at a net cost of approximately $45
million.  The Partnership expects to fund the 2010 drilling program
primarily from internal operating cash flows and, to a lesser extent, from
borrowings under its credit facility.  Although the Partnership
expects that internal cash flows and available borrowing capacity under its
credit facility will be adequate to fund capital expenditures and planned
unitholder distributions, no assurances can be given that such funding sources
will be adequate to meet the Partnership's future needs.





The Partnership Agreement requires
that the Partnership distribute all of its available cash to its partners. In
general, available cash is defined to mean cash on hand at the end of a quarter
after the payment of expenses and the establishment of cash reserves for future
capital expenditures (including acquisitions), operational needs and
distributions for any one or more of the next four quarters. Because the
Partnership's proved reserves and production









decline
continually over time, the Partnership will need to mitigate these declines
through drilling initiatives, production enhancement and/or acquisitions of
income producing assets that provide cash margins that allow the Partnership to
sustain its level of distributions to unitholders over time. Currently, the
Partnership is reserving approximately 25 percent of its cash flow to drill its
undeveloped locations in order to maintain its production and cash flow. In the
future, the Partnership may use its reserved cash flow for acquisitions of
producing properties or undeveloped properties that can be developed to maintain
the Partnership's production and cash flow.  The Partnership has
adopted a cash distribution policy pursuant to which it intends to declare
distributions of $0.50 per unit per quarter, or $2.00 per unit per year, to be
paid no later than 45 days after the end of each fiscal quarter. The
distribution for the fourth quarter of 2009 of $0.50 per unit was declared by
the Board of Directors of the General Partner on January 25, 2010 and was paid
on February 11, 2010 to unitholders of record on February 4, 2010.





Oil and gas
properties.Excluding the payments related to the carrying
value of the 2009 Acquisition and the 2008 IPO Acquisitions, the Partnership's
cash expenditures for additions to oil and gas properties during 2009, 2008 and
2007 totaled $3.8 million, $15.6 million and $18.6 million,
respectively.  Additions to oil and gas properties during 2009 reflect
expenditures associated with the six wells drilled in 2009 as part of the
two-rig drilling program started in November 2009.  The Partnership's
expenditures for additions to oil and gas properties for 2009, 2008 and 2007
were funded by net cash provided by operating activities.





Contractual
obligations, including off-balance sheet obligations.As of December 31, 2009,
the Partnership's contractual obligations included credit facility indebtedness,
asset retirement obligations, derivative instruments and contingent VPP
obligations.  Borrowings outstanding under its credit facility were
$67.0 million at December 31, 2009.  As of December 31, 2009, the
Partnership's derivative instruments represented assets of $39.8 million and
liabilities of $33.8 million; however, they continue to have market risk and
represent contractual obligations of the Partnership.  The ultimate
liquidation value of the Partnership's commodity derivatives will be dependent
upon actual future commodity prices, which may differ materially from the inputs
used to determine the derivatives' fair values at any point in
time.  The Partnership entered into these derivatives for the primary
purpose of reducing commodity price risk on forecasted physical commodity sales
and has an expectation of a high degree of correlation between changes in the
derivative values and the forecasted commodity risks.  See Notes C, F
and H of Notes to the 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
the Partnership's derivative positions and credit facility.  As of
December 31, 2009, the Partnership's asset retirement obligations had increased
approximately $678 thousand from December 31, 2008.  As of December
31, 2009, the Partnership was not a party to any material off-balance sheet
arrangements.




A
substantial portion of the properties that the Partnership owns is subject to
Pioneer's 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'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 either
(i) make a cash payment to the Partnership for the value of the production
(computed by taking the volumes delivered to meet the VPP obligation times the
price the Partnership would have received for the related volumes, plus any
out-of-pocket expenses or other expenses or losses incurred in connection with
the delivery of such volumes) required to meet the VPP obligation or (ii)
deliver to the Partnership volumes equal to the volumes delivered pursuant to
the VPP obligation. Accordingly, the VPP obligation is not expected to affect
the liquidity of the Partnership. If Pioneer were to default in its obligation
with respect to the Partnership's volumes delivered pursuant to the VPP
obligation, the decrease in the Partnership's production would result in a
decrease in the Partnership's cash available for distribution.  The
VPP obligation expires at the end of 2010.










The following table summarizes by
period the payments due by the Partnership for contractual obligations estimated
as of December 31, 2009:





Payments
      Due by Year2010
            
            2011
      and
            
            2013
      and
            
            ThereafterTotal
            
            2012
            2014(in
      thousands)Long-term
      debt (a)
            
            $
            67,000
            
            $
            -
            
            $
            -
            
            $
            67,000
            
            $
            -Derivative
      obligations
            
            $
            33,811
            
            $
            3,606
            
            $
            20,958
            
            $
            9,247
            
            $
            -Other
      liabilities (b)
            
            $
            7,105
            
            $
            500
            
            $
            1,000
            
            $
            1,000
            
            $
            4,605Total
            
            $
            107,916
            
            $
            4,106
            
            $
            21,958
            
            $
            77,247
            
            $
            4,605


­­­ _______


(a)
                See
      "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for
      information regarding estimated future interest payment obligations under
      long-term debt obligations and Note D of Notes to Consolidated Financial
      Statements included in "Item 8. Financial Statements and Supplementary
      Data."  The amount included in the table above represents principal
      maturities only.
 (b)
                The
      Partnership's other liabilities represent the current and noncurrent
      portions of the Partnership's asset retirement obligations for which
      neither the ultimate settlement amounts nor their timing can be precisely
      determined in advance.


Capital
resources.The Partnership's primary capital resources are
expected to be net cash provided by operating activities, amounts available
under its credit facility and, to the extent available, funds from future
private and public equity and debt offerings.  For 2010, the
Partnership expects to use cash flow from operations and the available borrowing
capacity under its credit facility to fund its drilling program and planned
unitholder distributions, and to provide adequate liquidity for future growth
opportunities such as additional development drilling or
acquisitions.





Operating activities.Net
cash provided by operating activities during 2009, 2008 and 2007 was $82.5
million, $132.5 million and $94.0 million, respectively. The decrease in net
cash provided by operating activities in 2009, as compared to that of 2008, was
primarily due to decreased oil, NGL and gas sales prices and changes in working
capital. 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.





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





Investing activities.Net
cash used in investing activities during 2009 was $58.5 million, as compared to
$157.9 million during 2008 and $18.6 million during 2007. The decrease in net
cash used in investing activities during 2009 as compared to 2008 was primarily
due to limited additions to oil and gas properties during 2009 and the
difference in the relative transaction sizes between the 2008 IPO Acquisition
and the 2009 Acquisition.  Future investing activities will include
expenditures associated with the two-rig program to drill proved undeveloped
well locations that commenced in the fourth quarter of 2009.  The
increase in net cash used by investing activities during 2008, as compared to
2007, was primarily due to the acquisition of Pioneer's carrying value in the
properties included in the 2008 IPO Acquisitions.





Financing activities.Net
cash used in financing activities for 2009 was $53.4 million, as compared to net
cash provided by financing activities of $55.4 million for 2008 and net cash
used in financing activities of $75.4 million during 2007.  The
decrease in net cash provided by financing activities during 2009, as compared
to 2008, was primarily due to a decline in proceeds from the 2009 Equity
Offering as compared to the Offering in 2008, the relative increase in the
payment for the 2009 Acquisition in excess of the carrying value of the net
assets acquired as compared to the 2008 IPO Acquisitions and an increase in
distributions to unitholders, partially offset by credit facility net borrowings
in 2009 and a decrease in net distributions to the owner of the Partnership
Predecessor.  The increase in net cash provided by financing
activities during 2008, as compared to 2007, was primarily due to proceeds
received from the Offering, partially offset by the 2008 IPO Acquisitions
purchase price in excess of Pioneer's carrying value and an increase in
aggregate distributions to the Partnership's owner and partners.  The
Partnership's financing activities for periods prior to the Offering were
limited to distributions of cash to Pioneer.










During
2009, the Partnership paid cash distributions to unitholders of $60.1 million
($2.00 per unit).  Future distributions and the timing and amount
thereof are at the discretion of the Board of Directors of the General
Partner.  See "Capital commitments" for information about the
Partnership's cash distributions paid in February 2010.





Liquidity.The
Partnership's principal source of short-term liquidity is cash generated from
its operations and availability under its credit facility.  As of
December 31, 2009, the Partnership had $67.0 million outstanding on its credit
facility and approximately $225 million of remaining borrowing capacity under
the 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, declines in commodity prices could reduce the
Partnership's borrowing capacity under the credit facility and could require the
Partnership to reduce its distributions to unitholders.  See Note D of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding the
credit facility.





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





The
Partnership Agreement allows the Partnership to borrow funds to make
distributions. The Partnership may borrow to make distributions to unitholders,
for example, in circumstances where the Partnership believes that the
distribution level is sustainable over the long-term, but short-term factors
have caused available cash from operations to be insufficient to sustain its
level of distributions. In addition, the Partnership plans to continue 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
and liabilities.The Partnership is a party to derivative
contracts that represent material assets and liabilities as of December 31,
2009.  In accordance with GAAP, the Partnership records its derivative assets
and liabilities at their estimated fair values, the determination of which
requires management to make judgments and estimates about observable and
unobservable inputs such as forward commodity prices, credit-adjusted interest
rates and volatility factors.  See Notes C and H of Notes to
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 the Partnership's derivative
instruments.





Asset retirement
obligations.The Partnership has obligations to remove
tangible equipment and facilities and to restore the land at the end of oil and
gas production operations. The Partnership's removal and restoration obligations
are primarily associated with plugging and abandoning wells operated by Pioneer.
Estimating the future restoration and removal costs is difficult and requires
management to make estimates and judgments because most of the removal
obligations are many years in the future. 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 properties as opposed to
the alternatively acceptable full cost method. The critical difference between
the successful efforts method of accounting and the full cost method is as
follows: under the successful efforts method, exploratory dry holes and
geological and geophysical exploration costs are charged against earnings during
the periods in which they occur; whereas, under the full cost method of
accounting, such costs and expenses are capitalized as assets, pooled with the
costs of successful wells and charged against the earnings of future periods as
a component of depletion expense.  Historically, the Partnership has
not had any exploratory drilling activities or incurred geological and
geophysical costs, and therefore the financial results utilizing the successful
efforts method did not significantly differ from that of the full cost method.
However, in the future, if the Partnership drills unsuccessful exploratory wells
or incurs geological and geophysical costs, these activities will negatively
impact its future financial results of the period in which such costs
occur.




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
      quality and quantity of available
data;


·
            the
      interpretation of that data;


·
            the
      accuracy of various mandated economic assumptions;
  and


·
            the
      judgment of the persons preparing the
estimate.




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




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




It should not be assumed that the
Standardized Measure as of December 31, 2009 included in the Unaudited
Supplementary Information included in "Item 8. Financial Statements and
Supplementary Data" is the current market value of the Partnership's estimated
proved reserves. In accordance with SEC requirements, the Partnership calculated
the Standardized Measure using the average of the NYMEX spot prices for sales of
oil and gas on the









first
calendar day of each month during 2009 and prevailing operating and development
costs at the end of the year. Actual future prices and costs may be materially
higher or lower than the prices and costs used in the calculation of the
Standardized Measure. See "Item 1A. Risk Factors" and "Item. 2 Properties" 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 wells. 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 information regarding new
accounting pronouncements is included in Note B of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data."









ITEM
7A.                      QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK




The following quantitative and
qualitative information is provided about financial instruments to which the
Partnership was a party as of December 31, 2009 and 2008, and from which the
Partnership may incur future gains or losses from changes in commodity prices or
market interest rates.





The fair
value of the Partnership's derivative contracts is based on the Partnership's
valuation models and applications, which are validated against counterparties'
estimates. The Partnership did not change its valuation method during
2009.  During 2009, the Partnership was a party to commodity swap,
collar contracts and commodity collar contracts with short put options. 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 2009 (in thousands):





DerivativeContract
      NetAssets
      (a)Fair
      value of contracts outstanding as of December 31, 2008
            
            $
            117,065Novation
      of derivative contracts from Pioneer
            
            
            (5,225)Changes
      in contract fair values
            
            
            (61,805)Contract
      terminations
            
            
            (44,020)Fair
      value of contracts outstanding as of December 31, 2009
            
            $
            6,015


­­­_______


(a)         Represents
the fair values of open derivative contracts subject to market
risk.





Effective February 1, 2009, the
Partnership discontinued hedge accounting on all existing commodity derivative
instruments, and since that date has accounted for derivative instruments using
the mark-to-market accounting method.  Therefore, since February 1,
2009, the Partnership recognizes changes in the fair values of its derivative
contracts as gains or losses in the earnings of the period in which they
occurred.





Quantitative
Disclosures




Interest rate
sensitivity.  The following table provides information about
financial instruments to which the Partnership was a party as of December 31,
2009 that were sensitive to changes in interest rates.  The table
presents maturities by expected maturity date, the weighted average interest
rates expected to be paid on the credit facility given current contractual terms
and market conditions and the debt's estimated fair value.  The
average interest rate represents the average rates being paid on the debt
projected forward relative to the forward yield curve for LIBOR on February 23,
2010.





LiabilityFair
      Value atYear
      Ending December 31,
            
            
            December
      31,2010
            
            2011
            
            2012
            
            2013
            
            
            2009(in
      thousands, except percentages)Total
      Debt:Variable
      rate principalmaturities
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            67,000
            
            $
            68,495Weighted
      averageinterest
      rate
            
            
            1.41%
            
            
            2.70%
            
            
            3.99%
            
            
            4.76%













Commodity price
sensitivity.The following tables provide information about
the Partnership's oil, NGL and gas derivative financial instruments that were
sensitive to changes in oil, NGL and gas prices as of December 31,
2009.  Although mitigated by the Partnership's derivative activities,
declines in commodity prices will reduce the Partnership's revenues and internal
cash flows.





Commodity
derivative instruments.The Partnership manages commodity
price risk with derivative contracts, such as swap contracts, collar contracts
and collar contracts with short put options. 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. Collar contracts with short
put options differ from other collar contracts by virtue of the short put option
price, below which the Partnership's realized price will exceed the variable
market prices by the floor price-to-short put price differential. With collar
contracts, if the relevant market price is above the ceiling price, the
Partnership pays the derivative counterparty the difference between the market
price and the ceiling price; if the relevant market price is between the ceiling
price and the floor price, the derivative has no cash settlement value; and, if
the relevant market price is below the floor price, the Partnership receives the
difference between the floor price and the market price from the counterparty.
Collar contracts with short puts are similar to collar contracts, except that if
the relevant market price is below the short put price, the Partnership receives
the difference between the floor price and short put price from the
counterparty.


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, 2009





Asset
      (Liability)Fair
      Value atYear
      Ending December 31,
            
            December
      31,2010
            
            2011
            
            2012
            
            2013
            
            2009Oil
      Derivatives:
            
            
            
            
            
            
            
            
            
            
            
            
            
            (in
      thousands)Average
      daily notional Bbl volumes (a):Swap
      contracts
            
            
            2,500
            
            
            750
            
            
            3,000
            
            
            3,000
            
            $
            (9,343)Weighted
      average fixed price per Bbl
            
            $
            93.34
            
            $
            77.25
            
            $
            79.32
            
            $
            81.02Collar
      contracts
            
            
            -
            
            
            2,000
            
            
            -
            
            
            -
            
            $
            23,107Weighted
      average ceiling price per Bbl
            
            $
            -
            
            $
            170.00
            
            $
            -
            
            $
            -Weighted
      average floor price per Bbl
            
            $
            -
            
            $
            115.00
            
            $
            -
            
            $
            -Collar
      contracts with Short Puts
            
            
            1,000
            
            
            1,000
            
            
            1,000
            
            
            1,000
            
            
            (5,932)Weighted
      average ceiling price per Bbl
            
            $
            87.75
            
            $
            99.60
            
            $
            103.50
            
            $
            111.50Weighted
      average floor price per Bbl
            
            $
            70.00
            
            $
            70.00
            
            $
            80.00
            
            $
            83.00Weighted
      average short put price per Bbl
            
            $
            55.00
            
            $
            55.00
            
            $
            65.00
            
            $
            68.00Average
      forward NYMEX oil prices (b)
            
            $
            80.68
            
            $
            83.18
            
            $
            84.59
            
            $
            85.53


______


(a)
            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.


(b)      The
average forward NYMEX oil prices are based on February 23, 2010 market
quotes.











NGL
Price Sensitivity


Derivative
Financial Instruments as of December 31, 2009





Year
      Ending December 31,
            
            Asset
      (Liability)Fair
      Value at December 31,2010
            
            2011
            
            2012
            
            2009NGL
      Derivatives:
            
            
            
            
            
            
            
            
            
            
            (in
      thousands)Average
      daily notional Bbl volumes (a):Swap
      contracts
            
            
            750
            
            
            750
            
            
            750
            
            $
            (4,905)Weighted
      average fixed price per Bbl
            
            $
            52.52
            
            $
            34.65
            
            $
            35.03Average
      forward Mont Belvieu NGL prices (b)
            
            $
            44.79
            
            $
            42.96
            
            $
            42.75


_______


(a)
            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.


(b)
            Forward
      Mont Belvieu NGL prices are not available as formal market
      quotes.  These forward prices represent estimates as of February
      23, 2010 provided by third parties who actively trade in the
      derivatives.  Accordingly, these prices are subject to estimates
      and assumptions.





Gas
Price Sensitivity


Derivative
Financial Instruments as of December 31, 2009





Fair
      Value atYear
      Ending December 31,
            December
      31,2010
            
            2011
            
            2012
            
            2013
            
            2009Gas
      Derivatives:
            
            
            
            
            
            
            
            
            
            
            
            
            
            (in
      thousands)Average
      daily notional MMBtu volumes (a):Swap
      contracts
            
            
            5,000
            
            
            2,500
            
            
            2,500
            
            
            2,500
            
            $
            3,671Weighted
      average fixed price per MMBtu (b)
            
            $
            7.44
            
            $
            6.65
            
            $
            6.77
            
            $
            6.89Average
      forward NYMEX gas prices (c)
            
            $
            5.12
            
            $
            5.81
            
            $
            6.09
            
            $
            6.29Average
      daily notional MMBtu volumes (a):Basis
      swap contracts
            
            
            2,500
            
            
            -
            
            
            -
            
            
            -
            
            $
            (583)Weighted
      average fixed price per MMBtu (b)
            
            $
            (0.87)
            
            $
            -
            
            $
            -
            
            $
            -


______


(a)
            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.


(b)
            To
      minimize basis risk, the Partnership enters into basis swaps to convert
      the index prices of the swap contracts from a NYMEX index to an El Paso
      Natural Gas (Permian Basin) posting index, which is highly correlated with
      the indices where the Partnership's forecasted gas sales are expected to
      be priced.


(c)       The
average forward NYMEX gas prices are based on February 23, 2010 market
quotes.





Qualitative
Disclosures


The Partnership's primary market risk exposures are from changes in commodity
prices and interest rates.  As of December 31, 2008, the Partnership
had no long-term borrowings or significant market risk exposure associated with
changes in interest rates.




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








PageConsolidated
      Financial Statements of Pioneer Southwest Energy Partners
      L.P.:Report
      of Independent Registered Public Accounting
      Firm
            62Consolidated
      Balance Sheets as of December 31, 2009 and 2008
            63Consolidated
      Statements of Operations for the Years Ended December 31, 2009, 2008 and
      2007
            64Consolidated
      Statements of Partners' Equity for the Years Ended December 31,2009, 2008 and
    2007
            65Consolidated
      Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and
      2007
            67Consolidated
      Statements of Comprehensive Income (Loss) for the Years Ended December
      31,
              2009,
      2008 and 2007
            68Notes
      to Consolidated Financial
      Statements
            69Unaudited
      Supplementary
      Information
            95














REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





To the
Board of Directors of Pioneer Natural Resources GP LLC and the


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, 2009 and 2008, and the
related consolidated statements of operations, partners' equity, cash flows, and
comprehensive income (loss) for each of the three years in the period ended
December 31, 2009.  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 Company
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. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
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, 2009 and 2008, and the consolidated results
of its operations and its cash flows for each of the three years in the period
ended December 31, 2009, in conformity with U.S. generally accepted accounting
principles.





As
discussed in Note B to the consolidated financial statements, effective January
1, 2009, the Partnership retroactively changed its method of calculating basic
and diluted net income per common unit with the adoption of the guidance
originally issued in FSP No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities(codified in FASB ASC Topic 260, Earnings Per
Share).  Additionally, as discussed in Note B to the
consolidated financial statements, the Partnership has changed its reserve
estimates and related disclosures as a result of adopting new oil and gas
reserve estimation and disclosure requirements resulting from Accounting
Standards Update No. 2010-03,
Oil and Gas Reserve Estimation and Disclosures,effective for annual
reporting periods ended on or after December 31, 2009.




We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Pioneer Southwest Energy Partners L.P.'s
internal control over financial reporting as of December 31, 2009, based on
criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 26, 2010 expressed an
unqualified opinion thereon.








/s/ Ernst & Young LLP





Dallas,
Texas


February
26, 2010












PIONEER
SOUTHWEST ENERGY PARTNERS L.P.





CONSOLIDATED
BALANCE SHEETS


(in
thousands, except unit amounts)





December
      31,2009
            
            2008
      (a)ASSETSCurrent
      assets:Cash
      and cash equivalents
            
            $
            625
            
            $
            29,936Accounts
      receivable
            
            
            14,162
            
            
            12,606Inventories
            
            
            851
            
            
            1,941Prepaid
      expenses
            
            
            260
            
            
            105Derivatives
            
            
            16,042
            
            
            51,261Total
      current assets
            
            
            31,940
            
            
            95,849Property,
      plant and equipment, at cost:Oil
      and gas properties, using the successful efforts method of
      accounting:Proved
      properties
            
            
            311,730
            
            
            305,075Accumulated
      depletion, depreciation and amortization
            
            
            (113,386)
            
            
            (100,370)Total
      property, plant and equipment
            
            
            198,344
            
            
            204,705Deferred
      income taxes
            
            
            1,964
            
            
            -Other
      assets:Derivatives
            
            
            23,784
            
            
            65,804Other,
      net
            
            
            606
            
            
            806$
            256,638
            
            $
            367,164LIABILITIES
      AND PARTNERS' EQUITYCurrent
      liabilities:Accounts
      payable:Trade
            
            $
            6,139
            
            $
            5,824Due
      to affiliates
            
            
            697
            
            
            5,968Interest
      payable
            
            
            26
            
            
            -Income
      taxes payable to affiliate
            
            
            460
            
            
            492Deferred
      income taxes
            
            
            127
            
            
            521Derivatives
            
            
            3,606
            
            
            -Asset
      retirement obligations
            
            
            500
            
            
            99Total
      current liabilities
            
            
            11,555
            
            
            12,904Long-term
      debt
            
            
            67,000
            
            
            -Derivatives
            
            
            30,205
            
            
            -Deferred
      income taxes
            
            
            -
            
            
            101Asset
      retirement obligations
            
            
            6,605
            
            
            6,328Partners'
      equity:Owner's
      net equity
            
            
            -
            
            
            62,729General
      partner's interest – 33,147 and 30,039 general partner units issued and
      outstanding, respectively
            
            
            211
            
            
            179Limited
      partners' interest – 33,113,700 and 30,008,700 common units issued and
      outstanding, respectively
            
            
            58,624
            
            
            143,280Accumulated
      other comprehensive income – deferred hedge gains, net of
    tax
            
            
            82,438
            
            
            141,643Total
      partners' equity
            
            
            141,273
            
            
            347,831Commitments
      and contingencies$
            256,638
            
            $
            367,164


______


(a)
            Recast
      as described in Note B




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 unit amounts)





Year
      Ended December 31,2009
            
            
            2008
      (a)
            
            
            2007
      (a)Revenues:Oil
      and gas
            
            $
            168,717
            
            $
            193,394
            
            $
            144,038Interest
      and other
            
            
            210
            
            
            192
            
            
            -168,927
            
            
            193,586
            
            
            144,038Costs
      and expenses:Oil
      and gas production
            
            
            34,749
            
            
            38,807
            
            
            27,879Production
      and ad valorem taxes
            
            
            9,547
            
            
            14,213
            
            
            11,550Depletion,
      depreciation and amortization
            
            
            13,016
            
            
            11,582
            
            
            11,382General
      and administrative
            
            
            4,790
            
            
            6,227
            
            
            5,643Accretion
      of discount on asset retirement obligations
            
            
            484
            
            
            144
            
            
            143Interest
            
            
            1,160
            
            
            621
            
            
            -Derivative
      loss, net
            
            
            78,265
            
            
            -
            
            
            -Other,
      net
            
            
            549
            
            
            890
            
            
            5142,560
            
            
            72,484
            
            
            56,602Income
      before taxes
            
            
            26,367
            
            
            121,102
            
            
            87,436Income
      tax provision
            
            
            (46)
            
            
            (1,326)
            
            
            (920)Net
      income
            
            $
            26,321
            
            $
            119,776
            
            $
            86,516Allocation
      of net income:Net
      income (loss) applicable to the Partnership Predecessor
            
            $
            (1,598)
            
            $
            59,038
            
            $
            86,516Net
      income applicable to the Partnership
            
            
            27,919
            
            
            60,738
            
            
            -Net
      income
            
            $
            26,321
            
            $
            119,776
            
            $
            86,516Allocation
      of net income applicable to the Partnership:General
      partner's interest in net income
            
            $
            28
            
            $
            61Limited
      partners' interest in net income
            
            
            27,891
            
            
            60,677Net
      income applicable to the Partnership
            
            $
            27,919
            
            $
            60,738Net
      income per common unit - basic and diluted
            
            $
            0.92
            
            $
            2.02Weighted
      average common units outstanding - basic and diluted
            
            
            30,399
            
            
            30,009


______


(a)
              Recast
      as described in Note B


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


PIONEER
SOUTHWEST ENERGY PARTNERS L.P.





CONSOLIDATED
STATEMENT OF PARTNERS' EQUITY


(in
thousands)





General
            
            Limited
            
            
            
            
            
            
            
            
            
            
            AccumulatedPartner
            
            Partner
            
            
            Owner's
            
            General
            
            Limited
            
            Other
            
            TotalUnits
            
            Units
            
            
            Net
            
            Partner's
            
            Partners'
            
            Comprehensive
            
            Partners'Outstanding
            
            Outstanding
            
            
            Equity
            
            Equity
            
            Equity
            
            Loss
            
            EquityBalance
      as of December 31, 2006 (a)
            
            -
            
            -
            
            $
            196,498
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            196,498Net
      income
            
            -
            
            -
            
            
            86,516
            
            
            -
            
            
            -
            
            
            -
            
            
            86,516Partner
      contributions
            
            -
            
            -
            
            
            1
            
            
            -
            
            
            -
            
            
            -
            
            
            1Net
      distributions to owner
            
            -
            
            -
            
            
            (75,446)
            
            
            -
            
            
            -
            
            
            -
            
            
            (75,446)Balance
      as of December 31, 2007 (a)
            
            -
            
            -
            
            
            207,569
            
            
            -
            
            
            -
            
            
            -
            
            
            207,569Net
      income applicable to the Partnership Predecessor
            
            -
            
            -
            
            
            59,038
            
            
            -
            
            
            -
            
            
            -
            
            
            59,038Net
      income applicable to the Partnership
            
            -
            
            -
            
            
            -
            
            
            61
            
            
            60,677
            
            
            -
            
            
            60,738Net
      distributions to owner
            
            -
            
            -
            
            
            (61,604)
            
            
            -
            
            
            -
            
            
            -
            
            
            (61,604)Cash
      distributions to partners
            
            -
            
            -
            
            
            -
            
            
            (24)
            
            
            (24,307)
            
            
            -
            
            
            (24,331)Allocation
      of owner's net equity
            
            -
            
            20,521
            
            
            (142,274)
            
            
            142
            
            
            142,132
            
            
            -
            
            
            -Proceeds
      from initial public offering, net
            
            -
            
            9,488
            
            
            -
            
            
            -
            
            
            163,045
            
            
            -
            
            
            163,045Partner
      contributions
            
            30
            
            -
            
            
            -
            
            
            24
            
            
            -
            
            
            -
            
            
            24Acquisition
      of carrying value
            
            -
            
            -
            
            
            -
            
            
            (24)
            
            
            (142,250)
            
            
            -
            
            
            (142,274)Acquisition
      in excess of carrying value
            
            -
            
            -
            
            
            -
            
            
            -
            
            
            (20,795)
            
            
            -
            
            
            (20,795)Novation
      of derivative obligations
            
            -
            
            -
            
            
            -
            
            
            -
            
            
            (37,249)
            
            
            -
            
            
            (37,249)Working
      capital contribution
            
            -
            
            -
            
            
            -
            
            
            -
            
            
            2,027
            
            
            -
            
            
            2,027Other
      comprehensive income, net of tax:Hedge
      fair values changes, net
            
            -
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            156,284
            
            
            156,284Net
      hedge gains included in net income
            
            -
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (14,641)
            
            
            (14,641)Balance
      as of December 31, 2008 (a)
            
            30
            
            30,009
            
            $
            62,729
            
            $
            179
            
            $
            143,280
            
            $
            141,643
            
            $
            347,831


______


(a)
              Recast
      as described in Note B


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





PIONEER
SOUTHWEST ENERGY PARTNERS L.P.





CONSOLIDATED
STATEMENT OF PARTNERS' EQUITY


(in
thousands)





General
            
            Limited
            
            
            
            
            
            
            
            
            
            
            AccumulatedPartner
            
            Partner
            
            
            Owner's
            
            General
            
            Limited
            
            Other
            
            TotalUnits
            
            Units
            
            
            Net
            
            Partner's
            
            Partners'
            
            Comprehensive
            
            Partners'Outstanding
            
            Outstanding
            
            
            Equity
            
            Equity
            
            Equity
            
            Loss
            
            EquityBalance
      as of December 31, 2008 (a)
            
            30
            
            30,009
            
            $
            62,729
            
            $
            179
            
            $
            143,280
            
            $
            141,643
            
            $
            347,831Net
      income applicable to the Partnership Predecessor
            
            -
            
            -
            
            
            (1,598)
            
            
            -
            
            
            -
            
            
            -
            
            
            (1,598)Net
      income applicable to the Partnership
            
            -
            
            -
            
            
            -
            
            
            28
            
            
            27,891
            
            
            -
            
            
            27,919Net
      distributions to owner
            
            -
            
            -
            
            
            (7,814)
            
            
            -
            
            
            -
            
            
            -
            
            
            (7,814)Cash
      distributions to partners
            
            -
            
            -
            
            
            -
            
            
            (60)
            
            
            (60,018)
            
            
            -
            
            
            (60,078)Deferred
      income tax assets on acquisition step-up
            
            -
            
            -
            
            
            1,399
            
            
            -
            
            
            -
            
            
            -
            
            
            1,399Allocation
      of owner's net equity
            
            -
            
            
            
            
            (54,716)
            
            
            -
            
            
            54,716
            
            
            -
            
            
            -Proceeds
      from offering, net
            
            3
            
            3,105
            
            
            -
            
            
            -
            
            
            60,983
            
            
            -
            
            
            60,983Partner
      contributions
            
            -
            
            -
            
            
            -
            
            
            64
            
            
            -
            
            
            -
            
            
            64Acquisition
      of carrying value
            
            -
            
            -
            
            
            -
            
            
            -
            
            
            (54,716)
            
            
            -
            
            
            (54,716)Acquisition
      in excess of carrying value
            
            -
            
            -
            
            
            -
            
            
            -
            
            
            (113,512)
            
            
            -
            
            
            (113,512)Other
      comprehensive income, net of tax:Hedge
      fair values changes, net
            
            -
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            11,509
            
            
            11,509Net
      hedge gains included in net income
            
            -
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (70,714)
            
            
            (70,714)Balance
      as of December 31, 2009
            
            33
            
            33,114
            
            $
            -
            
            $
            211
            
            $
            58,624
            
            $
            82,438
            
            $
            141,273


______


(a)
            Recast
      as described in Note B




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)





Year
      Ended December 31,2009
            
            2008
      (a)
            
            2007
      (a)Cash
      flows from operating activities:Net
      income
            
            $
            26,321
            
            $
            119,776
            
            $
            86,516Adjustments
      to reconcile net income to net cash provided by operating
      activities:Depletion,
      depreciation and amortization
            
            
            13,016
            
            
            11,582
            
            
            11,382Deferred
      income taxes
            
            
            (470)
            
            
            278
            
            
            52Accretion
      of discount on asset retirement obligations
            
            
            484
            
            
            144
            
            
            143Inventory
      valuation adjustment
            
            
            -
            
            
            159
            
            
            -Amortization
      of debt issuance costs
            
            
            200
            
            
            155
            
            
            -Derivative
      related activity
            
            
            51,254
            
            
            (11,349)
            
            
            -Changes
      in operating assets and liabilities:Accounts
      receivable
            
            
            (1,556)
            
            
            5,786
            
            
            (4,829)Inventories
            
            
            1,090
            
            
            (1,152)
            
            
            (948)Prepaid
      expenses
            
            
            (155)
            
            
            (105)
            
            
            -Accounts
      payable
            
            
            (6,853)
            
            
            7,550
            
            
            1,200Interest
      payable
            
            
            26
            
            
            -
            
            
            -Income
      taxes payable to affiliate
            
            
            (32)
            
            
            (196)
            
            
            688Asset
      retirement obligations
            
            
            (803)
            
            
            (173)
            
            
            (195)Net
      cash provided by operating activities
            
            
            82,522
            
            
            132,455
            
            
            94,009Cash
      flows from investing activities:Payments
      of acquisition carrying value
            
            
            (54,716)
            
            
            (142,274)
            
            
            -Additions
      to oil and gas properties
            
            
            (3,760)
            
            
            (15,625)
            
            
            (18,563)Net
      cash used in investing activities
            
            
            (58,476)
            
            
            (157,899)
            
            
            (18,563)Cash
      flows from financing activities:Borrowings
      under credit facility
            
            
            150,000
            
            
            -
            
            
            -Principal
      payments on credit facility
            
            
            (83,000)
            
            
            -
            
            
            -Proceeds
      from issuance of partnership common units, net of issuance
      costs
            
            
            60,983
            
            
            163,045
            
            
            -Partner
      contributions
            
            
            64
            
            
            24
            
            
            1Payments
      for acquisition in excess of carrying value
            
            
            (113,512)
            
            
            (20,795)
            
            
            -Payments
      of financing fees
            
            
            -
            
            
            (960)
            
            
            -Distributions
      to unitholders
            
            
            (60,078)
            
            
            (24,331)
            
            
            -Net
      distributions to owner
            
            
            (7,814)
            
            
            (61,604)
            
            
            (75,446)Net
      cash provided by (used in) financing activities
            
            
            (53,357)
            
            
            55,379
            
            
            (75,445)Net
      increase (decrease) in cash and cash equivalents
            
            
            (29,311)
            
            
            29,935
            
            
            1Cash
      and cash equivalents, beginning of period
            
            
            29,936
            
            
            1
            
            
            -Cash
      and cash equivalents, end of period
            
            $
            625
            
            $
            29,936
            
            $
            1


______


(a)
              Recast
      as described in Note B


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


PIONEER
SOUTHWEST ENERGY PARTNERS L.P.





CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


(in
thousands)





Year
      Ended December 31,2009
            
            2008
      (a)
            
            2007
      (a)Net
      income
            
            $
            26,321
            
            $
            119,776
            
            $
            86,516Other
      comprehensive income, net of tax:Hedge
      fair value changes, net
            
            
            11,509
            
            
            156,284
            
            
            -Net
      hedge gains included in net income
            
            
            (70,714)
            
            
            (14,641)
            
            
            -Other
      comprehensive income (loss)
            
            
            (59,205)
            
            
            141,643
            
            
            -Comprehensive
      income (loss)
            
            $
            (32,884)
            
            $
            261,419
            
            $
            86,516


______


(a)
              Recast
      as described in Note B


The
accompanying notes are an integral part of these consolidated financial
statements.
 
 PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


NOTE
A.                      Formation
of the Partnership and Description of Business





Pioneer
Southwest Energy Partners L.P., a Delaware limited partnership (the
"Partnership"), was formed in June 2007 by Pioneer Natural Resources Company
(together with its subsidiaries, "Pioneer") to own and acquire oil and gas
assets in the Partnership's area of operations. The Partnership's area of
operations consists of onshore Texas and eight counties in the southeast region
of New Mexico. Prior to the completion on May 6, 2008 of the Partnership's
initial public offering of 9,487,500 common units representing limited partner
interests (the "Offering"), Pioneer owned all of the general and limited partner
interests in the Partnership. Pioneer formed Pioneer Southwest Energy Partners
USA LLC, a Texas limited liability company ("Pioneer Southwest LLC"), 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 LLC for additional general and limited partner
interests in the Partnership, (ii) sold to the Partnership its remaining
interest in Pioneer Southwest LLC for $141.1 million, (iii) sold incremental
working interests in certain of the oil and gas properties owned by Pioneer
Southwest LLC to the Partnership for $22.0 million, which amount represented the
net proceeds from the exercise by the underwriters of the over-allotment option
(the transactions referred described in (i), (ii) and (iii) above are referred
to in the aggregate as the "2008 IPO Acquisitions" and the transaction referred
to in (iii) above is referred to individually as the "Over-allotment
Acquisition"), 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 LLC became a wholly-owned
subsidiary of the Partnership.





On August
31, 2009, the Partnership completed an acquisition of oil and gas properties in
the Spraberry field from Pioneer pursuant to a Purchase and Sale Agreement
having an effective date of July 1, 2009.  Associated therewith,
Pioneer Southwest LLC paid Pioneer $168.2 million of cash, including customary
closing adjustments, and assumed net obligations associated with certain
commodity price derivative positions and certain other liabilities that were
assigned by Pioneer to Pioneer Southwest LLC (the acquisition, including assumed
liabilities, is referred to herein as the "2009 Acquisition").





NOTE
B.                 Summary
of Significant Accounting Policies




Presentation.The 2008 IPO Acquisitions and the 2009 Acquisition represented
transactions between entities under common control, similar to a pooling of
interests, whereby the assets acquired and the liabilities assumed are combined
with those of the Partnership at Pioneer's historical amounts for all periods
presented. Consequently, for all periods prior to their acquisition and
assumption by the Partnership, the historical financial position, results of
operations, cash flows and changes in owner's equity of the property interests
acquired and the liabilities assumed in the 2009 Acquisition (representing
periods prior to August 31, 2009) and the 2008 IPO Acquisitions (representing
periods prior to May 6, 2008) are referred to herein as the "Partnership
Predecessor."  As a result of the 2009 Acquisition, the Partnership's
accompanying consolidated balance sheet as of December 31, 2008 and the
Partnership's accompanying consolidated statements of operations, consolidated
statement of partners' equity, consolidated statements of cash flows and
consolidated statements of comprehensive income (loss) for the years ended
December 31, 2008 and 2007 have been recast to include the historical accounting
attributes of the Partnership Predecessor.









PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


The following table provides the
composition of the historical accounting attributes of the Partnership, as
combined with the Partnership Predecessor:





Pioneer
      Southwest Energy Partners L.P.Composition
      of Historical Accounting AttributesMay
      6, 2008 through
            
            Subsequent
      toPrior
      to May 6, 2008
            
            August
      31, 2009
            
            August
      31, 20092008
      IPO Acquisitions
            
            Partnership
      Predecessor
            
            Partnership
            
            Partnership2009
      Acquisition
            
            Partnership
      Predecessor
            
            Partnership
      Predecessor
            
            Partnership




The Partnership's consolidated
financial statements have been prepared in accordance with Regulation S-X,
Article 3 "General instructions as to financial statements" and ASC Topic 225-10
"Income Statement."  Certain expenses of the Partnership Predecessor
that were incurred by Pioneer and combined in the accompanying consolidated
financial statements are only indirectly attributable to Pioneer's ownership of
the Partnership's 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"
below.




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.




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




Inventories.The
Partnership's inventories consist of oil held in storage tanks as of December
31, 2009 and oil held in storage tanks and NGLs held in storage by the purchaser
of the NGLs as of December 31, 2008.  The Partnership's oil and NGL
inventories are carried at the lower of lifting 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.  As of December 31, 2009, there were no valuation
reserve allowances recorded by the Partnership.  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.






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


Capitalized costs relating to proved
properties are depleted using the unit-of-production method based on proved
reserves.  Costs of significant nonproducing properties, wells in the
process of being drilled and development projects are excluded from depletion
until such time as the related project is completed and proved reserves are
established or, if unsuccessful, impairment is determined.




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.




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.  Estimates of the sum of expected future
cash flows requires management to estimate future recoverable proved and
risk-adjusted probable and possible reserves, forecasts of future commodity
prices, production and capital costs and discount rates. Uncertainties about
these future cash flow variables cause impairment estimates to be inherently
imprecise  Any impairment charge incurred is expensed and reduces the
Partnership's recorded basis in the asset.




Asset retirement
obligations.The Partnership records the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred if a reasonable estimate of fair value can be made. Asset retirement
obligations are generally capitalized as part of the carrying value of the
long-lived asset. Conditional asset retirement obligations meet the definition
of liabilities and are recognized when incurred.




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 recognizes all derivative instruments
as either assets or liabilities at fair value. Derivative instruments that are
not designated as hedges must be adjusted to fair value through earnings. Under
the provisions of GAAP, 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 during which it is a party to
derivatives that are designated as hedges.




Under the provisions of GAAP, 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 GAAP, 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
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007




Pioneer does not designate hedge
derivatives to forecasted sales at the well level. Consequently, the
Partnership's consolidated financial statements do not include recognition of
hedge gains or losses associated with Partnership's properties for periods
during which they were owned by the Partnership Predecessor.  See Note
H for information about the Partnership Predecessor's derivative
instruments.




Effective February 1, 2009, the
Partnership discontinued hedge accounting on all existing commodity derivative
instruments and from that date forward began accounting for all derivative
instruments using the mark-to-market accounting method.  Consequently,
since February 1, 2009, the Partnership has recognized changes in the fair
values of its derivative contracts as gains or losses in the earnings of the
period in which they occurred.




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




Owner's net
equity – Partnership Predecessor.  Since the Partnership
Predecessor was not a separate legal entity, none of Pioneer's debt was directly
attributable to its ownership of the Partnership's properties, and no formal
intercompany financial arrangement existed related to the Partnership
Predecessor. Therefore, the changes in net assets of the Partnership Predecessor
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 Predecessor, the accompanying
consolidated statements of operations do not include any allocation of interest
expense incurred by Pioneer to the Partnership Predecessor.




Employee benefit
plans.  The Partnership does not have its own employees.
However, 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 began paying 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 fee (commonly referred
to as a Council of Petroleum Accountants Societies, or "COPAS Fee") with respect
to lease operating expenses of the Partnership's properties during periods
subsequent to their purchase in the 2008 IPO Acquisitions and the 2009
Acquisition.




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




Income taxes.While owned by Pioneer, the operations of the Partnership Predecessor
were included in Pioneer's federal income tax return. The Partnership's
operations (exclusive of the Partnership Predecessor 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 Partnership became subject to
the Texas Margin tax for tax years beginning on January 1, 2007. 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) collectability is
reasonably assured.




The Partnership uses the entitlements
method of accounting for oil, NGL and gas revenues. Sales proceeds in excess of
the Partnership's entitlement are included in other liabilities and the
Partnership's share of sales taken by others is included in other assets in the
accompanying consolidated balance sheets. The Partnership had no material oil,
NGL or gas entitlement assets or liabilities as of December 31, 2009 or
2008.






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 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, 2009 and 2008, the Partnership had no
material environmental liabilities.




Allocation of
owner's net equity and partners' equity.In accordance with
GAAP, the contribution and purchase of the Partnership's properties and other
net assets from Pioneer at the time of the 2008 IPO Acquisitions and the 2009
Acquisition were recorded on the Partnership's balance sheet at Pioneer's
historic carrying values.  Owner's net equity of $62.7 million
included in the Partnership's accompanying consolidated balance sheet as of
December 31, 2008 represents the carrying values of the Partnership
Predecessor's net assets on that date.




On May 6, 2008, the  carrying
value of the net assets contributed and purchased in the 2008 IPO Acquisitions
amounted to $142.3 million and 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
net assets contributed and purchased in connection with the 2008 IPO
Acquisitions during the period from May 1, 2008 through May 5,
2008.




The following table provides Pioneer's
carrying values in the assets acquired and liabilities assumed in the 2008 IPO
Acquisitions (in thousands):





Accounts
      receivable
            $
            2,943Accounts
      receivable - affiliate
            
            1,501Inventories
            
            850Proved
      oil and gas properties
            
            220,323Accumulated
      depletion, depreciation and amortization
            
            (78,553)Deferred
      income tax assets
            
            1,247Accounts
      payable - trade
            
            (2,417)Asset
      retirement obligations
            
            (1,593)Total
      net asset carrying values as of May 5, 2008
            
            144,301Less:
      working capital contributed
            
            2,027Net
      assets acquired
            
            142,274Cash
      paid for net assets
            
            163,069Value
      in excess of carrying value
            $
            20,795




The Partnership acquired a portion of
the Partnership's properties from Pioneer for $163.1 million on the date of the
2008 IPO Acquisitions, 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's 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 associated Partnership's 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 consolidated statement of partners'
equity.






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007





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 $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.




The total consideration attributable to
the 2009 Acquisition was $168.2 million in cash, including customary closing
adjustments, the novation by Pioneer USA to Pioneer Southwest LLC of certain
associated commodity price derivative positions, and the assumption by Pioneer
Southwest LLC of certain other liabilities. The Partnership funded the
acquisition with cash on hand and $138.0 million of borrowings under its credit
facility.





The
carrying value of the assets acquired and liabilities assumed in the 2009
Acquisition was $54.7 million, including the fair value of novated commodity
derivative obligations and incremental deferred income tax assets attributable
to the transaction, and is presented as a net reduction to the limited partner's
interest of Pioneer in the Partnership's consolidated statement of partners'
equity.





The
following table provides Pioneer's carrying values in the assets acquired and
liabilities assumed in the 2009 Acquisition (in thousands):





Accounts
      receivable
            $
            2,122Inventories
            
            73Proved
      oil and gas properties
            
            80,186Accumulated
      depletion, depreciation and amortization
            
            (20,145)Accounts
      payable - trade
            
            (1,396)Accounts
      payable - affiliate
            
            (1,285)Asset
      retirement obligations
            
            (741)Deferred
      income tax liability
            
            (272)Deferred
      income tax asset on acquisition step-up
            
            1,399Derivative
      obligations, net
            
            (5,225)Total
      net asset carrying values as of August 31, 2009
            
            54,716Cash
      paid for net assets
            
            168,228Value
      in excess of carrying value
            $
            113,512




Allocation of
costs.  The accompanying consolidated financial statements have
been prepared in accordance with ASC Topic 225-10. 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 have also been included in the
accompanying consolidated financial statements.  Pioneer has allocated
general and administrative expenses to the Partnership Predecessor based on the
Partnership's 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.  For 2009 and 2008, net income per common unit is
calculated by dividing the limited partners' interest in net income derived from
operations (which excludes net income from Partnership






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


Predecessor
operations) by the weighted average number of common units
outstanding.  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 two-class method.  Under the two-class method, the Partnership's
net income is allocated among the general partner's interest in net income and
the limited partners' interest in net income.  Net income per common
unit is based upon the limited partners' interest in net income and the weighted
average common units outstanding during the periods of calculation.





Stock-based
compensation.For stock-based compensation awards granted or modified,
compensation expense is being recognized in the Partnership's financial
statements on a straight line basis over the vesting period based on their fair
values on the dates of grant.  The Partnership utilizes the unit price
on the date of grant as the fair value of the common unit awards.





For the
years ended December 31, 2009, 2008 and 2007, the Partnership recorded $217
thousand, $107 thousand and $0 of compensation costs associated with unit-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:





On June
30, 2009, the Financial Accounting Standards Board ("FASB") issued Statement of
Financial Accounting Standards ("SFAS") No. 168, "The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting Principles – a
replacement of FASB Statement No. 162" ("SFAS 168"). SFAS 168 creates a new
source of authoritative U.S. accounting and reporting standards for
nongovernmental entities, known as the FASB Accounting Standards Codification
("ASC"). This statement is effective for interim and annual periods ending after
September 15, 2009. On September 30, 2009, the Partnership adopted the
provisions of SFAS 168. Hereafter, all new accounting pronouncements will be
referred to by their section in the ASC.





In September 2006, the FASB issued SFAS
No. 157, "Fair Value Measures" ("ASC 820"). ASC 820 defines fair value,
establishes a framework for measuring fair value and enhances disclosures about
fair value measures required under other accounting pronouncements, but it does
not change existing guidance as to whether or not an instrument is carried at
fair value. In February 2008, the FASB issued FASB Staff Position No. 157-2
("ASC 820-10"), which delayed the effective date of ASC 820 for nonfinancial
assets and liabilities until fiscal years beginning after November 15, 2008,
except for items that were recognized or disclosed at fair value in the
financial statements on a recurring basis at least annually. On January 1, 2008,
the Partnership adopted the provisions of ASC 820 as they pertain to financial
assets and liabilities. See Note C for additional information regarding the
Partnership's adoption of ASC 820. On January 1, 2009, the Partnership adopted
the provisions of ASC 820 that were delayed by ASC 820-10.





In December 2007, the FASB issued SFAS
No. 141(R), "Business Combinations" ("ASC 805"). ASC 805 replaced SFAS 141 and
provides greater consistency in the accounting and financial reporting of
business combinations. ASC 805 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's units or shares issued in consideration for a business
combination, the






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


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
ASC 805 also require that restructuring costs resulting from the business
combination that the acquirer expects, but is not required to incur, and costs
incurred to effect the acquisition be recognized separate from the business
combination. The Partnership became subject to the provisions of ASC 805 on
January 1, 2009.





In March
2008, the FASB issued SFAS No. 161, "Disclosures about Derivative Instruments
and Hedging Activities – an amendment of FASB Statement No. 133" ("ASC 815-10").
ASC 815-10 changed the disclosure requirements for derivative instruments and
hedging activities by requiring entities to provide enhanced disclosures about
(a) how and why an entity uses derivative instruments, (b) how derivative
instruments and related hedged items are accounted for under ASC 815, and (c)
how derivative instruments and related hedged items affect an entity's financial
position, financial performance and cash flows. The Partnership adopted the
provisions of ASC 815-10 on January 1, 2009.  See Note H for
derivative disclosures provided in accordance with ASC 815 and ASC
815-10.




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" ("ASC 260-10"),
which addresses whether instruments granted in share-based payment transactions
are participating securities prior to vesting and, therefore, need to be
included in the net income allocation in computing basic net income per unit
under the two-class method prescribed under ASC 260.  The Partnership
retrospectively adopted the provisions of ASC 260-10 on January 1,
2009.  All share-based payments of the Partnership's common units
represent grants of outstanding common units by the General
Partner.  Consequently, the Partnership had no participating
share-based payments under the provisions of ASC 260-10 during 2009 and
2008.




In
December 2008, the SEC released the final rule on "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 became
effective for annual reports on Forms 10-K for fiscal years ending on or after
December 31, 2009. During December 2009, the FASB issued Accounting
Standards Update No. 2010-03, "Extractive Activities – Oil and Gas (Topic 932),"
("ASU 2010-03") to conform ASC Topic 932 to the Reserve Ruling. The Partnership
adopted the provisions of the Reserve Ruling and the provisions of ASU 2010-03
on December 31, 2009. See Unaudited Supplementary Information for more
information regarding the adoption of the Reserve Ruling and the related effect
on the Partnership's earnings.





In April
2009, the FASB issued FASB Staff Position No. FAS 157-4, "Determining Fair Value
When the Volume and Level of Activity for the Asset or Liability Have
Significantly Decreased and Identifying Transactions That Are Not Orderly" ("ASC
820-10-65"), which provides additional guidelines for estimating fair value in
accordance with ASC 820 when the volume and level of activity for the asset or
liability have decreased and guidance on identifying circumstances that indicate
a transaction is not orderly.  ASC 820-10-65 was adopted by the
Partnership during the second quarter of 2009 and did not have a material impact
on the Partnership's fair value measurements.





In May
2009, the FASB issued SFAS No. 165, "Subsequent Events" ("ASC
855").  ASC 855 provides additional guidelines for disclosing
subsequent events in an issuer's financial statements and further requires an
issuer to disclose a finite time period for which the company has evaluated
subsequent events.  ASC 855 was adopted by the Partnership during the
second quarter of 2009 and did not have a significant impact on the







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


Partnership's
recognition or disclosure of subsequent events.  See Note N for the
Partnership's subsequent events disclosures.





NOTE
C.                      Disclosures
About Fair Value of Financial Instruments





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





·
            Level
      1 – quoted prices for identical assets or liabilities in active
      markets.


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


·
            Level
      3 – unobservable inputs for the asset or
  liability.





The fair
value input hierarchy level to which an asset or liability measurement in its
entirety falls is determined based on the lowest level input that is significant
to the measurement in its entirety.  The following table presents the
Partnership's financial assets and liabilities that are measured at fair value
on a recurring basis as of December 31, 2009, for each of the fair value input
hierarchy levels:





Fair
      Value Measurements at Reporting Date UsingQuoted
      Prices In
            
            
            SignificantActive
      Markets
            
            
            Other
            
            
            Significantfor
      Identical
            
            
            Observable
            
            
            Unobservable
            
            
            Fair
      Value atAssets
            
            
            Inputs
            
            
            Inputs
            
            
            December
      31,(Level
      1)
            
            
            (Level
      2)
            
            
            (Level
      3)
            
            
            2009(in
      thousands)Assets:Commodity
      derivative contracts
            
            $
            -
            
            $
            38,424
            
            $
            1,402
            
            $
            39,826Liabilities:Commodity
      derivative contracts
            
            $
            -
            
            $
            27,503
            
            $
            6,308
            
            $
            33,811










PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


The Partnership's commodity price
derivatives that are classified as Level 3 in the fair value hierarchy at
December 31, 2009 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:





Year
      EndedFair
      Value Measurements Using Significant
            
            December
      31,Unobservable
      Inputs (Level 3)
            2009(in
      thousands)Assets
      (liabilities):Beginning
      balance
            
            $
            13,828Settlements
            
            
            (5,503)Fair
      value changes:Included
      in earnings - realized (a)
            
            
            (2,061)Included
      in earnings – unrealized (a)
            
            
            (10,652)Included
      in other comprehensive income
            
            
            (518)Ending
      balance
            
            $
            (4,906)


______


(a)
            For
      periods prior to February 1, 2009, the hedge-effective portion of realized
      gains and losses on commodity hedge derivatives are included in oil, NGL
      and gas revenues in the accompanying consolidated statements of
      operations.  For periods beginning February 1, 2009, changes in
      fair value are included in derivative loss, net in the accompanying
      consolidated statements of operations.  See Note B for a
      description of the Partnership's derivative accounting
      methods.





The following table presents the
carrying amounts and fair values of the Partnership's financial instruments as
of December 31, 2009:





December
      31, 2009
            
            December
      31, 2008Carrying
            
            
            
            
            CarryingValue
            
            Fair
      Value
            
            Value
            
            Fair
      Value(in
      thousands)Assets:Commodity
      derivatives
            $
            39,826
            
            $
            39,826
            
            $
            117,065
            
            $
            117,065Liabilities:Commodity
      derivatives
            $
            33,811
            
            $
            33,811
            
            $
            -
            
            $
            -Credit
      facility
            $
            67,000
            
            $
            68,495
            
            $
            -
            
            $
            -




Commodity
derivative instruments.  The Partnership's commodity price
derivative assets and liabilities represent oil, NGL and gas swap and collar
contracts.  All of the Partnership's oil and gas asset and liability
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 of oil at fixed (in the case of swaps
contracts) or interval (in the case of collar contracts) NYMEX West Texas
Intermediate ("WTI") oil prices.  Commodity derivative asset values
are determined, in part, by utilization of the derivative counterparties'
credit-adjusted risk-free rates, and commodity derivative liability values are
determined, in part, by utilization of the Partnership's credit-adjusted
risk-free rate.  The counterparties' credit-adjusted risk-free rates
are based on independent market-quoted credit default swap rate curves for the
counterparties' debt plus the United States Treasury Bill yield curve as of
December 31, 2009.  The Partnership's credit-adjusted risk-free rate
curve is based on independent market-quoted forward LIBOR curves plus 250 basis
points, representing the Partnership's






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


estimated
borrowing rate if it were to finance future settlements.  The asset
and liability transfer values attributable to the Partnership's oil derivative
instruments as of December 31, 2009 are based on (i) the contracted notional
volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii)
the applicable credit-adjusted risk-free rate yield curve and (iv) the implied
rate of volatility inherent in the collar contracts.  The implied
rates of volatility inherent in the Partnership's collar contracts were
determined based on average volatility factors provided by certain independent
brokers who are active in buying and selling oil options and were corroborated
by market-quoted volatility factors.




NGL
derivatives.The Partnership's NGL derivatives are swap
contracts for notional blended barrels of Mont Belvieu-posted-price
NGLs.  The asset and liability 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 and liability values attributable to the
Partnership's gas derivative instruments are based on (i) the contracted
notional volumes, (ii) independent active NYMEX futures price quotes for HH gas,
(iii) averages of forward posted price quotes supplied by independent brokers
who are active in buying and selling gas 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.




Credit
Facility.  The fair value of the Partnership's credit facility
is based on (i) contractual interest and fees, (ii) forward active market-quoted
LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate
yield curve.





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.





NOTE
D.   Long-term Debt




In May 2008, the Partnership entered
into a $300 million revolving credit facility (the "Credit Facility"). The
Credit Facility matures in May 2013 and 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, 2009, the Partnership had outstanding borrowings of $67.0 million 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 derivative 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






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


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.  As of December 31, 2009, the
Partnership was in compliance with all of its debt covenants.




Because of the net present value
covenant, borrowing capacity under the Credit Facility was limited to
approximately $225 million as of December 31, 2009. 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, a sustained decline 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.




The Partnership pays a commitment fee
on the unused portion of the Credit Facility.  The commitment fee is
variable based on the Partnership's consolidated leverage ratio.  For
2009, the commitment fee was 0.175 percent.




Interest
expense.The Partnership incurred $1.2 million and $621
thousand of interest expense during 2009 and 2008, respectively.  In
2009, interest expense was comprised of $469 thousand of Credit Facility
commitment fees, $235 thousand of amortization of Credit Facility financing fees
and $456 thousand of interest related to borrowings under the Credit
Facility.  During 2008, interest expense was 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.  During 2009, the Partnership paid
interest of $899 thousand.





NOTE
E.  Related Party Transactions




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 LLC
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 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






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


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 LLC 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 Partnership Predecessor's use, ownership and operation of
the properties the Partnership acquired pursuant to the 2008 IPO Acquisitions,
(ii) losses attributable to defects in title to the Partnership's interest in
then-producing intervals in the wellbores the Partnership acquired pursuant to
2008 IPO Acquisitions, and (iii) taxes attributable to the Partnership
Predecessor's operations of those properties. 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
acquired 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 LLC 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's 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, 2009 and 2008, the Partnership's income
taxes payable to affiliate in the accompanying consolidated balance sheets
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 PartnershipAgreement 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






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


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.





2009 Acquisition.Pursuant to the Purchase and Sale Agreement associated with the 2009
Acquisition, Pioneer Southwest LLC and Pioneer USA entered into an Omnibus
Operating Agreement (the "2009 Omnibus Operating Agreement") and an operating
agreement (the "2009 Operating Agreement") relating to Pioneer USA's operations
on behalf of Pioneer Southwest LLC. Additionally, Pioneer Southwest LLC and
Pioneer USA amended their existing Omnibus Operating Agreement (the "IPO Omnibus
Operating Agreement") and operating agreement (the "IPO Operating Agreement")
that were entered into at the time of the 2008 IPO Acquisition to provide that
certain Partnership properties formerly governed by those agreements (those that
are no longer limited to wellbore interests) will now be governed by the 2009
Omnibus Operating Agreement and the 2009 Operating Agreement, and to provide
that certain of the property interests acquired in the 2009 Acquisition (those
that are limited to wellbore interests) will be governed by the IPO Omnibus
Operating Agreement and the IPO Operating Agreement. Similar to the IPO Omnibus
Operating Agreement, the 2009 Omnibus Operating Agreement places restrictions
and limitations on Pioneer Southwest LLC's ability to exercise certain rights
that would otherwise be available to it under the 2009 Operating Agreement. For
example, Pioneer Southwest LLC is restricted in its ability to remove Pioneer
USA as the operator of Pioneer Southwest LLC's properties, Pioneer USA's
proposed operations will take precedence over any conflicting operations that
Pioneer Southwest LLC proposes and Pioneer Southwest LLC will allow Pioneer USA
to use certain of Pioneer Southwest LLC's production facilities in connection
with other properties operated by Pioneer USA, subject to capacity limitations.
Pursuant to the 2009 Operating Agreement, Pioneer Southwest LLC pays Pioneer USA
COPAS Fees. Pioneer Southwest LLC also pays Pioneer USA for its direct and
indirect expenses that are chargeable to the assets covered by the 2009
Operating Agreement.




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 retained as compensation 19 percent of the
Partnership's dry gas residue and NGL value processed by the Midkiff/Benedum gas
processing plant during 2009.  The retention percentage for the
Midkiff/Benedum plant declines by one percent per year to 16 percent in 2012,
when it is held constant thereafter.  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.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


Related party
charges.  In accordance with standard industry operating
agreements and the agreements described above, the Partnership incurred the
following charges from Pioneer during 2009 and 2008:





Year
      Ended December 31,2009
            
            2008(in
      thousands)Producing
      well overhead (COPAS) fees
            $
            8,926
            
            $
            5,476Payment
      of lease operating and supervision charges
            
            7,649
            
            
            3,977Drilling
      related charges
            
            1,213
            
            
            167General
      and administrative expenses
            
            1,933
            
            
            1,567Total
            $
            19,721
            
            $
            11,187




As of December 31, 2009, the
Partnership's accounts payable-affiliate balance in the accompanying
consolidated balance sheet is comprised of approximately $697 thousand of
general and administrative expenses.  The balance of $6.0 million as
of December 31, 2008 is comprised primarily of lease operating expenses,
including COPAS Fees, and general and administrative expenses.




The Partnership Predecessor did not
incur any related party charges associated with its operations for the periods
presented, since the Partnership Predecessor represents Pioneer's results of
operations attributable to the Partnership's properties prior to their purchase
by the Partnership.





NOTE
F.            
Incentive Plans





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 $26 thousand, $32 thousand and $26 thousand during 2009, 2008 and
2007, 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 $108 thousand, $97 thousand
and $79 thousand during 2009, 2008 and 2007, 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 LTIP, 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 LTIP limits the number of units
that may be delivered pursuant to awards granted under the plan to 3,000,000
common units.









PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


The following table shows the number of
awards available under the Partnership's LTIP at December 31, 2009:





Approved
      and authorized awards
            
            3,000,000Awards
      issued after May 6, 2008
            
            (25,539)Awards
      available for future grant
            
            2,974,461





During 2009, the General Partner
awarded 12,909 restricted common units to directors of the General Partner under
the LTIP, of which 2,038 units vest ratably over three years and 10,871 units
vest in May 2010.  During May 2008, the General Partner awarded 12,630
restricted units to directors under the LTIP.  The Partnership
recognized $217 thousand and $107 thousand of general and administrative expense
during 2009 and 2008, respectively, associated with the LTIP
awards.




As of December 31, 2009, there was
approximately $152 thousand of unrecognized compensation expense related to
unvested restricted unit awards.  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, 2009 and December 31 2008,
and the activity related thereto for the year then ended:





Year
      Ended December 31,
            
            Year
      Ended December 31,2009
            
            2008Weighted
            
            
            
            WeightedNumber
            Average
            
            Number
            AverageOf
      Units
            Price
            
            Of
      Units
            PriceRestricted
      unit awards:Outstanding
      at beginning of year
            
            12,630
            
            $
            19.00
            
            -
            
            $
            -Units
      granted
            
            12,909
            
            $
            18.26
            
            12,630
            
            $
            19.00Lapse
      of restrictions
            
            (8,418)
            
            $
            19.00
            
            -
            
            $
            -Outstanding
      at end of year
            
            17,121
            
            $
            18.45
            
            12,630
            
            $
            19.00





NOTE
G.  Commitments and Contingencies




Volumetric
Production Payments. The Partnership's title to a substantial portion of
the Partnership's 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.




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 either (i) make a cash payment to the Partnership for the value of
the production






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


(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 or (ii)
deliver to the Partnership volumes equal to the volumes delivered pursuant to
the VPP obligation. Accordingly, the VPP obligation is not expected to affect
the liquidity of the Partnership. If Pioneer were to default in its obligation
with respect to the Partnership's volumes to be 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.  Since
the 2009 Acquisition, 5 MBbls of the Partnership's production has been utilized
by Pioneer to meet VPP obligations.  Accordingly, Pioneer delivered 5
MBbls of alternative volumes of oil production to the Partnership through the
end of December 2009.




A portion of the Partnership
Predecessor's production was utilized to fund the VPP obligation since oil and
gas production from Pioneer's properties subject to the VPP obligation was
not adequate to meet the VPP obligation during the years ended December 31,
2009, 2008 and 2007. Accordingly, the accompanying consolidated financial
statements, for the years ended December 31, 2009, 2008 and 2007, do not include
oil and gas revenues or the related production volumes utilized to fund the VPP
obligation since they are related to the Partnership Predecessor.





NOTE
H.   Derivative Financial Instruments




The Partnership uses financial
derivative contracts to manage exposures to commodity price
fluctuations.  The Partnership 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 were effective as hedges of the designated commodity price
risk through January 31, 2009, are being deferred and recognized in the
Partnership's earnings in the same periods as the forecasted sales being
hedged.  During 2009 and 2008, the Partnership settled derivatives
which represented liabilities of $15.7 million and $11.3 million, respectively,
on the date of novation.  See Note B for information regarding
novation agreements entered into during August 2009 in connection with the 2009
Acquisition.




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:





2010(in
      thousands)Oil
            
            $
            8,528NGL
            
            
            948Gas
            
            
            684Total
      novated hedges
            
            $
            10,160




Associated with the 2009 Acquisition,
novation agreements were entered into among Pioneer, the Partnership and certain
derivative instrument counterparties that transferred Pioneer's rights and
responsibilities under certain derivative instruments to the Partnership on
August 31, 2009.  The aggregate fair value of these
derivative






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


instruments
represented a liability of $5.2 million.  These derivative instruments
are being accounted for in accordance with the Partnership's mark-to-market
accounting policy.  Consequently, the Partnership recognized $5.2
million of derivative losses attributable to the Partnership Predecessor during
2009 in the accompanying consolidated statements of operations.




All derivative contracts are recorded
in the Partnership's consolidated balance sheets at estimated fair
value.  Fair value is generally determined based on the
credit-adjusted present value difference between the fixed contract price and
the underlying market price at the determination date.  Effective
February 1, 2009, the Partnership discontinued hedge accounting on all
existing derivative instruments and since that date has accounted for derivative
instruments using the mark-to-market accounting method. Consequently, since
February 1, 2009, the Partnership has recognized changes in the fair values of
its derivative contracts as gains or losses in the earnings of the period in
which they occurred.





Changes
in the fair value of effective cash flow hedges prior to the Partnership's
discontinuance of hedge accounting on February 1, 2009 were recorded as a
component of AOCI – Hedging, which has been or will be transferred to earnings
when the hedged transaction is recognized in earnings. Any ineffective portion
of changes in the fair value of hedge derivatives prior to February 1, 2009
was recorded in the earnings of the period of change. The ineffective portion
was calculated as the difference between the change in fair value of the hedge
derivative and the estimated change in cash flows from the item
hedged.  Cash inflows and outflows attributable to the Partnership's
commodity derivatives are included in net cash provided by operating activities
in the Partnership's accompanying consolidated statements of cash flows for
during 2009 and 2008.




Cash flow hedges
and derivative price risk management.  The Partnership utilizes
commodity swap and collar contracts to (i) reduce the impact on the
Partnership's net cash provided by operating activities from the price
volatility of the commodities the Partnership produces and sells and (ii) help
sustain unitholder distributions.   Pioneer did not designate
derivative hedges to forecasted sales at the well
level.  Consequently, the Partnership's consolidated financial
statements do not include recognition of hedge gains or losses associated with
the Partnership's oil and gas properties for periods during which they were
owned by the Partnership Predecessor nor recognition of derivative assets or
liabilities associated with such derivative contracts prior to the contracts
being novated to the Partnership.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


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 Bbls underlying the Partnership's outstanding oil derivative contracts and
the weighted average NYMEX prices per Bbl for those contracts as of December 31,
2009:




Year
      Ending December 31,2010
            
            2011
            
            
            2012
            
            
            2013Oil
      Derivatives:Swap
      contracts:Volume
      (Bbls per day)
            
            2,500
            
            
            750
            
            
            3,000
            
            
            3,000Price
      per Bbl
            $
            93.34
            
            $
            77.25
            
            $
            79.32
            
            $
            81.02Collar
      contracts:Volume
      (Bbls per day)
            
            -
            
            
            2,000
            
            
            -
            
            
            -Price
      per BblCeiling
            $
            -
            
            $
            170.00
            
            $
            -
            
            $
            -Floor
            $
            -
            
            $
            115.00
            
            $
            -
            
            $
            -Collar
      contracts with short puts:Volume
      (Bbls per day)
            
            1,000
            
            
            1,000
            
            
            1,000
            
            
            1,000Price
      per BblCeiling
            $
            87.75
            
            $
            99.60
            
            $
            103.50
            
            $
            111.50Floor
            $
            70.00
            
            $
            70.00
            
            $
            80.00
            
            $
            83.00Short
      put
            $
            55.00
            
            $
            55.00
            
            $
            65.00
            
            $
            68.00




The Partnership reports average oil
prices per Bbl including the effects of oil quality adjustments and the net
effect of oil hedges (for periods subsequent to the aforementioned hedge
novations).  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, 2009, 2008 and 2007:





Year
      Ended December 31,2009
      (a)
            
            2008
            
            2007Average
      price reported per Bbl
            
            $
            100.35
            
            $
            107.79
            
            $
            71.28Average
      price realized per Bbl
            
            $
            58.05
            
            $
            99.71
            
            $
            71.28Increase
      to oil revenue from hedging activity   (in thousands)
    (a)
            
            $
            56,863
            
            $
            11,654
            
            $
            -


_______


(a)
            The
      Partnership discontinued hedge accounting effective February 1,
      2009.  Hedge results beginning February 1, 2009 represent the
      transfer of net deferred hedge gains included in AOCI – Hedging to oil and
      gas revenues.  See "AOCI – Hedging" below for additional
      information.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


NGL 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,
2009:





Year
      Ending December 31,2010
            
            2011
            
            2012NGL
      Derivatives:Swap
      contracts:Volume
      (Bbls per day)
            
            
            750
            
            
            750
            
            
            750Price
      per Bbl
            
            $
            52.52
            
            $
            34.65
            
            $
            35.03




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 aforementioned hedge
novations).  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, 2009, 2008 and 2007:





Year
      Ended December 31,2009
      (a)
            
            2008
            
            2007Average
      price reported per Bbl
            
            $
            41.61
            
            $
            48.41
            
            $
            37.41Average
      price realized per Bbl
            
            $
            25.56
            
            $
            45.84
            
            $
            37.41Increase
      to NGL revenue from hedging activity (in    thousands)
      (a)
            
            $
            8,320
            
            $
            1,220
            
            $
            -


_______


(a)
            The
      Partnership discontinued hedge accounting effective February 1,
      2009.  Hedge results beginning February 1, 2009 represent the
      transfer of net deferred hedge gains included in AOCI – Hedging to oil and
      gas revenues.  See "AOCI – Hedging" below for additional
      information.





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, 2009:





Year
      Ending December 31,2010
            
            2011
            
            2012
            
            2013Gas
      Derivatives:Swap
      contracts:Volume
      (MMBtus per day)
            
            
            5,000
            
            
            2,500
            
            
            2,500
            
            
            2,500Price
      per MMBtu
            
            $
            7.44
            
            $
            6.65
            
            $
            6.77
            
            $
            6.89Basis
      Swap contracts:Permian
      Basin index swaps - (MMBtus per day)
            
            
            2,500
            
            
            -
            
            
            -
            
            
            -Price
      differential ($/MMBtu)
            
            $
            (0.87)
            
            $
            -
            
            $
            -
            
            $
            -







­­­


PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


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
aforementioned hedge novations).  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, 2009, 2008 and
2007:





Year
      Ended December 31,2009
      (a)
            
            2008
            
            2007Average
      price reported per Mcf
            
            $
            5.37
            
            $
            7.06
            
            $
            4.98Average
      price realized per Mcf
            
            $
            2.81
            
            $
            6.24
            
            $
            4.98Increase
      to gas revenue from hedging activity (in   thousands)
    (a)
            
            $
            5,848
            
            $
            1,767
            
            $
            -


_______


(a)
            The
      Partnership discontinued hedge accounting effective February 1,
      2009.  Hedge results beginning February 1, 2009 represent the
      transfer of net deferred hedge gains included in AOCI – Hedging to oil and
      gas revenues.  See "AOCI – Hedging" below for additional
      information.




Tabular
disclosures about derivative instruments.Effective February
1, 2009, the Partnership discontinued hedge accounting on all existing commodity
derivative instruments and since that date has accounted for derivative
instruments using the mark-to-market accounting method. Consequently, all of the
Partnership's commodity derivatives were non-hedge derivatives as of December
31, 2009, but were hedge derivatives as of December 31, 2008.  The
following tables provide tabular disclosures of the Partnership's commodity
derivative instruments:





Fair
      Value of Derivative Instrumentsas
      of December 31, 2009Asset
      Derivatives
            
            Liability
      DerivativesBalance
      Sheet
            
            Fair
            
            Balance
      Sheet
            
            FairLocation
            Value
            Location
            Value(in
      thousands)
            
            
            
            (in
      thousands)Derivatives
      - current
            
            $
            16,042
            
            Derivatives
      - current
            
            $
            3,606Derivatives
      - noncurrent
            
            
            23,784
            
            Derivatives
      - noncurrent
            
            
            30,205Total
      derivatives not designated as    hedging
      instruments
            
            $
            39,826
            
            
            
            $
            33,811










PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007





Fair
      Value of Derivative Instrumentsas
      of December 31, 2008Asset
      Derivatives
            
            Liability
      DerivativesBalance
      Sheet
            
            Fair
            
            Balance
      Sheet
            
            FairLocation
            Value
            Location
            Value(in
      thousands)
            
            
            
            (in
      thousands)Derivatives
      - current
            
            $
            51,261
            
            Derivatives
      - current
            
            $
            -Derivatives
      - noncurrent
            
            
            65,804
            
            Derivatives
      - noncurrent
            
            
            -Total
      derivatives designated ashedging
      instruments
            
            $
            117,065
            
            
            
            $
            -







Effect
      of Derivative Instruments on the Consolidated Statement of
      OperationsAmount
      of Gain (Loss) Recognized in OCI on Derivatives(Effective
      Portion)Derivatives
      in Cash Flow
            
            Year
      Ended December 31,Hedging  Relationships
            
            2009
            
            2008(in
      thousands)Commodity
      contracts
            
            $
            11,235
            
            $
            157,606Amount
      of Gain (Loss) Reclassified from AOCI into IncomeLocation
      of Gain (Loss)
            
            (Effective
      Portion)Reclassified
      from AccumulatedOCI
      into Income
            
            Year
      Ended December 31,(Effective
      Portion)
            
            2009
            
            2008(in
      thousands)Oil
      and gas revenues
            
            $
            71,030
            
            $
            14,641







Amount
      of (Gain) Loss Recognized in Income on DerivativesDerivatives
      Not
            
            Location
      of LossDesignated
      as Hedging
            
            Recognized
      in Income on
            
            Year
      Ended December 31,Instruments
            
            Derivatives
            
            2009
            
            
            2008(in
      thousands)Commodity
      contracts
            
            Derivative
      loss, net
            $
            78,265
            
            $
            -







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


AOCI -
Hedging.The fair value of the effective portion of the
derivative contracts on January 31, 2009 was reflected in AOCI-Hedging and has
been or is being transferred to oil and gas revenue over the term of the
derivative contract.  In accordance with the mark-to-market method of
accounting, the Partnership will recognize all future changes in the fair values
of its derivative contracts as gains or losses in the earnings of the period in
which they occur.




As of December 31, 2009 and 2008, AOCI
- Hedging represented net deferred gains of $83.2 million and $143.0 million,
respectively, and associated deferred tax provisions of $731 thousand and $1.4
million as of December 31, 2009 and 2008, respectively.




During the twelve month periods ending
December 31, 2010 and 2011, respectively, the Partnership expects to reclassify
$46.7 million and $36.5 million of net deferred hedge gains and $411 thousand
and $320 thousand, respectively, of deferred Texas margin tax provisions
associated with derivative contracts from AOCI - Hedging to oil and gas revenues
and income tax provisions, respectively.





NOTE
I.            Major
Customers and Derivative Counterparties




Sales to major
customers.The Partnership's share of oil, NGL 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, 2009, 2008 and
2007:





Year
      Ended December 31,2009
            
            2008
            
            2007Plains
      Marketing L.P.
            
            56%
            
            56%
            
            51%Occidental
      Energy Marketing
            
            15%
            
            16%
            
            16%TEPPCO
      Crude Oil
            
            10%
            
            9%
            
            9%ONEOK
      Inc.
            
            9%
            
            8%
            
            10%





As of December 31, 2009, the
Partnership's accounts receivable balance included receivables of $6.0 million,
$1.8 million, $975 thousand and $1.9 million from Plains Marketing L.P.,
Occidental Energy Marketing, TEPPCO Crude Oil and ONEOK Inc.,
respectively.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


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.  The following table provides the
Partnership's derivative assets and liabilities by counterparty as of December
31, 2009:




Assets
            
            Liabilities(in
      thousands)JP
      Morgan Chase
            $
            23,107
            
            $
            583Societe
      Generale
            
            11,646
            
            
            4,179Barclays
      Capital
            
            3,371
            
            
            1,610Citibank
            
            1,232
            
            
            4,711Toronto
      Dominion
            
            400
            
            
            1,072Wells
      Fargo
            
            70
            
            
            21,656Total
            $
            39,826
            
            $
            33,811





NOTE
J.            Asset
Retirement Obligations




The Partnership's asset retirement
obligations primarily relate to the Partnership's portion of future plugging and
abandonment of wells and related facilities. Market risk premiums associated
with asset retirement obligations are estimated to represent a component of the
Partnership's credit-adjusted risk-free rate that is employed in the
calculations of asset retirement obligations.  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, 2009, 2008 and
2007:





Year
      Ended December 31,2009
            
            2008
            
            2007(in
      thousands)Beginning
      asset retirement obligations
            
            $
            6,427
            
            $
            1,957
            
            $
            1,917Net
      wells placed on production and changes in estimates
            
            
            997
            
            
            4,499
            
            
            92Liabilities
      settled
            
            
            (803)
            
            
            (173)
            
            
            (195)Accretion
      of discount
            
            
            484
            
            
            144
            
            
            143Ending
      asset retirement obligation
            
            $
            7,105
            
            $
            6,427
            
            $
            1,957





NOTE
K.            Other
Expense




The Partnership's other expense for
2009 consisted primarily of expenses related to the 2009
Acquisition.  In 2008, other expense 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 not to pursue the assignment or the acquisition of an interest in the
Midkiff-Benedum gas processing plant due to the uncertainty of underlying market
conditions.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


NOTE
L.            Income
Taxes




The following table summarizes the
Partnership's income tax provisions, which were entirely attributable to the
Texas Margin tax (which rate currently approximates one percent of the
Partnership's taxable income apportioned to Texas), for the years ended December
31, 2009, 2008 and 2007:





Year
      Ended December 31,2009
            
            2008
            
            2007(in
      thousands)Current
      provisions:U.S.
      state
            
            $
            516
            
            $
            1,048
            
            $
            868Deferred
      provisions (benefit):U.S.
      state
            
            
            (470)
            
            
            278
            
            
            52$
            46
            
            $
            1,326
            
            $
            920




The Partnership's deferred tax
attributes represented a $2.0 million noncurrent asset and a $127 thousand
current liability as of December 31, 2009.  Deferred tax attributes
represented a $521 thousand current liability and a $101 thousand noncurrent
liability as of December 31, 2008.  The change in the Partnership's
deferred tax position primarily resulted from a step-up in tax basis of the oil
and gas properties acquired in the 2009 Acquisition.  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.   During 2009, the Partnership paid $499 thousand to
Pioneer under the terms of the Tax Sharing Agreement.





The Partnership applies the provisions
of ASC Topic 740-10 "Income Taxes," which 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, 2009, the Partnership had no material unrecognized tax benefits
(as defined in ASC 740-10). 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.





NOTE
M.            Public
Offering of Common Units




On November 16, 2009, the Partnership
completed a public offering of 3,105,000 of its common units representing
limited partner interests. Net proceeds from the public offering of $61.0
million were used to reduce Credit Facility borrowings.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 December
31, 2009, 2008 and 2007


NOTE
N.           Subsequent
Events




In accordance with ASC 855, the
Partnership has evaluated subsequent events through February 25, 2010, the date
of issuance of the consolidated financial statements.  The Partnership
is not aware of any reportable subsequent events through February 25, 2010,
except as disclosed below.





Distribution
declaration.In January 2010, the Partnership declared a cash
distribution of $0.50 per common unit for the period from October 1, 2009 to
December 31, 2009.  The distribution was paid on February 11, 2010 to
unitholders of record at the close of business on February 4,
2010.  Associated therewith, the Partnership paid $16.6 million of
aggregate distributions.











PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 UNAUDITED
SUPPLEMENTARY INFORMATION
 December
31, 2009, 2008 and 2007


Capitalized
Costs





December
      31,2009
            
            2008(in
      thousands)Oil
      and gas properties:Proved
      properties
            
            $
            311,730
            
            $
            305,075Less
      accumulated depletion, depreciation and amortization
            
            
            (113,386)
            
            
            (100,370)Net
      capitalized cost for oil and gas properties
            
            $
            198,344
            
            $
            204,705





Costs
Incurred for Oil and Gas Producing Activities





Year
      Ended December 31,2009
            
            2008
            
            2007(in
      thousands)Acquisition
      of carrying value (a)
            
            $
            60,041
            
            $
            141,770
            
            $
            -Development
      costs (b)
            
            
            6,655
            
            
            16,410
            
            
            13,580Total
      costs incurred
            
            $
            66,696
            
            $
            158,180
            
            $
            13,580


______


(a)
            See
      Notes A and B for information about the 2009 Acquisition and the 2008 IPO
      Acquisitions.


(b)
            Includes
      increases to asset retirement obligations for 2009, 2008 and 2007 of $1.0
      million, $4.5 million and $92 thousand, respectively.  Excludes
      $1.0 million of development costs incurred prior to the Offering in 2008
      that are included in the acquisition of carrying value on May 6,
      2008.





Reserve
Quantity Information




The information included in this Report
about the Partnership's proved reserves as of December 31, 2009 represents
evaluations by Pioneer's reservoir engineers.  The information
included in this Report about the Partnership's proved reserves as of December
31, 2008 and 2007 represents evaluations by Pioneer's reservoir engineers of the
Partnership's and the Partnership Predecessor's proved
reserves.  Netherland, Sewell & Associates, Inc. ("NSAI") audited
the Partnership's proved reserves as of December 31, 2009.  NSAI
audited the Partnership's proved reserves as of December 31, 2008 before the
2009 Acquisition and audited the Partnership's proved reserves as of December
31, 2007 before the 2009 Acquisition and the Over-allotment Acquisition (the
"Original Evaluations").  The proved reserves that NSAI audited in the
Original Evaluations have been increased by 80 percent and 62 percent as of
December 31, 2008 and 2007, respectively, to recognize the proved reserves
attributable to the 2009 Acquisition and the Over-allotment Acquisition and,
together with the proved reserves included in the Original Evaluations, form the
basis for the information included in this Report about the Partnership's proved
reserves as of December 31, 2009, 2008 and 2007.




During 2009, the SEC issued the Reserve
Ruling and the FASB issued ASU 2010-03.  The Reserve Ruling and ASU
2010-03 are effective for Annual Reports on Forms 10-K for fiscal years ending
on or after December 31, 2009.  The key provisions of the Reserve
Ruling and ASU 2010-03 are as follows:





·
            Expanding
      the definition of oil- and gas-producing activities to include the
      extraction of saleable hydrocarbons, in the solid, liquid or gaseous
      state, from oil sands, coalbeds or other nonrenewable natural resources
      that are intended to be upgraded into synthetic oil or gas, and activities
      undertaken with a view to such
extraction;











PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 UNAUDITED
SUPPLEMENTARY INFORMATION
 December
31, 2009, 2008 and 2007


·
            Amending
      the definition of proved oil and gas reserves to require the use of an
      average of the first-day-of-the-month commodity prices during the 12-month
      period ending on the balance sheet date rather than the period-end
      commodity prices;


·
            Adding
      to and amending other definitions used in estimating proved oil and gas
      reserves, such as "reliable technology" and "reasonable
      certainty;"


·
            Broadening
      the types of technology that a registrant may use to establish reserves
      estimates and categories; and


·
            Changing
      disclosure requirements and providing formats for tabular reserve
      disclosures.




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, 2009, 2008 and 2007 utilized respective oil
prices of $60.42, $44.14 and $95.75 per Bbl (reflecting adjustments for oil
quality), respective NGL prices of $26.12, $17.91 and $52.52 per Bbl, and
respective gas prices of $2.84, $4.41 and $5.45 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.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 UNAUDITED
SUPPLEMENTARY INFORMATION
 December
31, 2009, 2008 and 2007


The following table provides a
rollforward of total proved reserves for the years ended December 31, 2009, 2008
and 2007, as well as proved developed reserves and proved undeveloped reserves
in total as of the beginning and end of each respective year. Oil and NGL
volumes are expressed in thousands of barrels ("MBbls"), gas volumes are
expressed in millions of cubic feet ("MMcf") and total volumes are expressed in
thousands of barrels of oil equivalent ("MBOE").




Oil
            
            NGL
            
            Gas
            
            Total(MBbls)
            
            (MBbls)
            
            (MMcf)
            
            (MBOE)Total
      Proved Reserves:Balance,
      December 31, 2006
            
            33,331
            
            11,665
            
            49,785
            
            53,292Revisions
      of previous estimates
            
            2,271
            
            1,601
            
            5,745
            
            4,830Production
            
            (1,543)
            
            (602)
            
            (2,318)
            
            (2,531)Balance,
      December 31, 2007
            
            34,059
            
            12,664
            
            53,212
            
            55,591Revisions
      of previous estimates
            
            (7,359)
            
            (2,993)
            
            (12,970)
            
            (12,514)Production
            
            (1,441)
            
            (476)
            
            (2,133)
            
            (2,272)Balance,
      December 31, 2008
            
            25,259
            
            9,195
            
            38,109
            
            40,805Revisions
      of previous estimates
            
            3,724
            
            1,144
            
            4,724
            
            5,656Extensions
      and discoveries
            
            102
            
            26
            
            112
            
            147Production
            
            (1,344)
            
            (518)
            
            (2,281)
            
            (2,243)Balance,
      December 31, 2009 (a)
            
            27,741
            
            9,847
            
            40,664
            
            44,365Proved
      Developed Reserves:December
      31:2006
            
            25,572
            
            9,087
            
            38,680
            
            41,1052007
            
            26,736
            
            10,382
            
            43,414
            
            44,3542008
            
            18,015
            
            6,936
            
            28,822
            
            29,7552009
      (a)
            
            19,726
            
            7,396
            
            30,548
            
            32,213Proved
      Undeveloped Reserves (b):December
      31:2006
            
            7,759
            
            2,578
            
            11,105
            
            12,1872007
            
            7,323
            
            2,282
            
            9,798
            
            11,2372008
            
            7,244
            
            2,259
            
            9,287
            
            11,0502009
      (a) (b)
            
            8,015
            
            2,451
            
            10,116
            
            12,152


______


(a)
            See
      "Transition to New Reserve Ruling Provisions" below for information about
      the effect of adopting the Reserve Ruling and ASU 2010-03 on the
      Partnership's proved, proved developed and proved undeveloped oil and gas
      reserves.


(b)
            As
      of December 31, 2009, the Partnership had 170 proved undeveloped well
      locations (all of which are expected to be developed within the five year
      period ending December 31, 2014), representing an increase of two proved
      undeveloped well locations (one percent) since December 31,
      2008.  During 2009, three proved undeveloped well locations were
      drilled and completed as developed wells, at a net cost of $1.9
      million.  The Partnership's proved undeveloped reserves totaled
      12,152 MBOE and 11,050 MBOE at December 31, 2009 and 2008, respectively.
      Changes in the Partnership's proved undeveloped reserve volumes during the
      year ended December 31, 2009 included additions of 147 MBOE and revisions
      of previous estimates of 954 MBOE.  Revisions of previous
      estimates are primarily comprised of positive price
      revisions.  The Partnership's proved undeveloped well locations
      as of December 31, 2009 included 64 proved undeveloped well locations that
      have remained undeveloped for five years or more.  Prior to the
      2009 Acquisition, all of the Partnership's proved undeveloped well
      locations were part of the Partnership Predecessor and, as such, they were
      part of Pioneer's inventory of undeveloped well locations in the Spraberry
      field.










PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 UNAUDITED
SUPPLEMENTARY INFORMATION
 December
31, 2009, 2008 and 2007


Standardized
Measure of Discounted Future Net Cash Flows




The standardized measure of discounted
future net cash flows ("Standardized Measure") is computed by applying commodity
prices based on average prices for sales of oil, NGLs and gas on the first
calendar day of the prior twelve-month period for 2009 and year end prices for
2008 and 2007 (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 the first-day-of-the-month commodity
prices during the 12-month period ending on December 31, 2009, 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 $115 million at December 31, 2009.




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 as of December 31, 2009, 2008 and 2007, as well as a
rollforward in total for each respective year:





Year
      Ended December 31,2009
            
            2008
            
            2007(in
      thousands)Oil
      and gas producing activitiesFuture
      cash inflows
            
            $
            2,048,674
            
            $
            1,448,040
            
            $
            4,217,890Future
      production costs
            
            
            (1,223,278)
            
            
            (807,178)
            
            
            (1,417,126)Future
      development costs (a)
            
            
            (184,156)
            
            
            (144,236)
            
            
            (157,603)Future
      income tax expense
            
            
            (2,742)
            
            
            (2,809)
            
            
            (16,235)638,498
            
            
            493,817
            
            
            2,626,92610%
      annual discount for estimated timing of cash flows
            
            
            (376,202)
            
            
            (306,598)
            
            
            (1,639,577)Standardized
      measure of discounted future net cash flows
            
            $
            262,296
            
            $
            187,219
            
            $
            987,349


­­­­­­­­­­______


(a)
            Includes
      $29.3 million ($21.0 million net of salvage value), $20.8 million ($10.3
      million net of salvage value) and $21.7 million ($10.7 million net of
      salvage value) of undiscounted future asset retirement expenditures
      estimated as of December 31, 2009, 2008 and 2007, respectively,

                using
      current estimates of future abandonment costs. See Note J for
      corresponding information regarding the Partnership's discounted asset
      retirement obligations.








PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 UNAUDITED
SUPPLEMENTARY INFORMATION
 December
31, 2009, 2008 and 2007


Changes
in Standardized Measure of Discounted Future Net Cash Flows





Year
      Ended December 31,2009
            
            2008
            
            2007(in
      thousands)Oil
      and gas sales, net of production costs
            
            $
            (53,391)
            
            $
            (125,733)
            
            $
            (103,760)Net
      changes in prices and production costs
            
            
            47,526
            
            
            (707,519)
            
            
            396,602Extensions
      and discoveries
            
            
            530
            
            
            -
            
            
            -Development
      costs incurred during the period
            
            
            2,857
            
            
            11,299
            
            
            13,527Revisions
      of estimated future development costs
            
            
            (20,831)
            
            
            (11,879)
            
            
            (14,671)Revisions
      of previous quantity estimates
            
            
            39,663
            
            
            (52,141)
            
            
            93,155Accretion
      of discount
            
            
            18,800
            
            
            99,684
            
            
            55,864Changes
      in production rates, timing and other
            
            
            40,257
            
            
            (22,557)
            
            
            (2,516)Change
      in present value of future net revenues
            
            
            75,411
            
            
            (808,846)
            
            
            438,201Net
      change in present value of future income taxes
            
            
            (334)
            
            
            8,716
            
            
            (4,519)75,077
            
            
            (800,130)
            
            
            433,682Balance,
      beginning of year
            
            
            187,219
            
            
            987,349
            
            
            553,667Balance,
      end of year
            
            $
            262,296
            
            $
            187,219
            
            $
            987,349










PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 UNAUDITED
SUPPLEMENTARY INFORMATION
 December
31, 2009, 2008 and 2007


Transition
to New Reserve Ruling Provisions




The
Partnership adopted the provisions of the Reserve Ruling and ASU 2010-03 on
December 31, 2009.  The new pricing provisions of the Reserve Ruling
reduced the Partnership's fourth quarter 2009 end-of-life reserves from what
they would have been under the previous definition of proved reserves that used
end of period pricing, thereby increasing the Partnership's DD&A expense for
the fourth quarter of  2009 by $337 thousand and reducing earnings by
$0.01 per common unit for the year ended December 31, 2009.  The other
provisions of the Reserve Ruling and ASU 2010-03 did not have a material effect
on the Partnership as of and for the periods ended December 31,
2009.  See "Item 2. Properties" and Note B for more information about
the provisions of the Reserve Ruling.





The
tables below present the decreases to the Partnership's proved reserves, proved
developed reserves, proved undeveloped reserves and Standardized Measure as of
December 31, 2009 due to the adoption of the Reserve Ruling:





Decrease
to Proved Reserves, Proved Developed Reserves and Proved Undeveloped
Reserves





Oil
            
            NGL
            
            Gas
            
            Total(MBbls)
            
            (MBbls)
            
            (MMcf)
            
            (MBOE)Total
      Proved Reserves:Balance,
      December 31, 2008
            
            -
            
            -
            
            -
            
            -Revisions
      of previous estimates
            
            (2,904)
            
            (1,224)
            
            (5,223)
            
            (4,998)Extensions
      and discoveries
            
            -
            
            -
            
            -
            
            -Production
            
            -
            
            -
            
            -
            
            -Balance,
      December 31, 2009
            
            (2,904)
            
            (1,224)
            
            (5,223)
            
            (4,998)Proved
      Developed Reserves:December
      31, 2009:
            
            (2,588)
            
            (1,115)
            
            (4,770)
            
            (4,498)Proved
      Undeveloped Reserves:December
      31, 2009:
            
            (316)
            
            (109)
            
            (453)
            
            (500)





Decrease
to Standardized Measure of Discounted Future Net Cash Flows


Year
      EndedDecember
      31,2009(in
      thousands)Oil
      and gas producing activitiesFuture
      cash inflows
            
            $
            (1,049,321)Future
      production costs
            
            
            330,212Future
      development costs
            
            
            880Future
      income tax expense
            
            
            6,972(711,257)10%
      annual discount for estimated timing of cash flows
            
            
            422,657Standardized
      measure of discounted future net cash flows - net decrease
            
            $
            (288,600)










PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 UNAUDITED
SUPPLEMENTARY INFORMATION
 December
31, 2009, 2008 and 2007


Selected
Quarterly Financial Results





The following table provides selected
quarterly financial results for the years ended December 31, 2009 and
2008:





QuarterFirst
            
            Second
            
            Third
            
            Fourth(in
      thousands, except per unit data)Year
      ended December 31, 2009:Oil
      and gas revenues:As
      reported
            
            $
            32,564
            
            $
            34,953
            
            $
            43,574
            
            $
            48,540Adjustment
      for 2009 Acquisition (a)
            
            
            4,205
            
            
            4,881Adjusted
            
            $
            36,769
            
            $
            39,834
            
            $
            43,574
            
            $
            48,540Total
      revenues:As
      reported
            
            $
            32,682
            
            $
            35,009
            
            $
            43,609
            
            $
            48,541Adjustment
      for 2009 Acquisition (a)
            
            
            4,205
            
            
            4,881Adjusted
            
            $
            36,887
            
            $
            39,890
            
            $
            43,609
            
            $
            48,541Total
      costs and expenses:As
      reported
            
            $
            20,437
            
            $
            36,911
            
            $
            18,562
            
            $
            59,855Adjustment
      for 2009 Acquisition (a)
            
            
            3,394
            
            
            3,401Adjusted
            
            $
            23,831
            
            $
            40,312
            
            $
            18,562
            
            $
            59,855Net
      income (loss):As
      reported
            
            $
            12,161
            
            $
            (1,907)
            
            $
            24,936
            
            $
            (11,131)Adjustment
      for 2009 Acquisition (a)
            
            
            800
            
            
            1,462Adjusted
            
            $
            12,961
            
            $
            (445)
            
            $
            24,936
            
            $
            (11,131)Basic
      and diluted net income (loss) per common unit
            
            $
            0.40
            
            $
            (0.06)
            
            $
            0.96
            
            $
            (0.35)


______


(a)
            In
      August 2009, the Partnership completed the 2009 Acquisition from Pioneer.
      Because the 2009 Acquisition was acquired from Pioneer, the acquisition
      was accounted for as a transaction between entities under common control,
      whereby the assets and liabilities were recorded at Pioneer's historical
      cost and the Partnership's historical financial information was recast to
      include the results of operations of the properties acquired in the 2009
      Acquisition for all periods presented.   See Note B for
      additional information regarding the 2009
  Acquisition.









PIONEER
SOUTHWEST ENERGY PARTNERS L.P.
 
 UNAUDITED
SUPPLEMENTARY INFORMATION
 December
31, 2009, 2008 and 2007





QuarterFirst
            
            Second
            
            Third
            
            Fourth(in
      thousands, except per unit data)Year
      ended December 31, 2008:Oil
      and gas revenues:As
      reported
            
            $
            36,191
            
            $
            40,990
            
            $
            40,195
            
            $
            35,456Adjustment
      for 2009 Acquisition (a)
            
            
            10,048
            
            
            12,246
            
            
            12,556
            
            
            5,712Oil
      and gas revenues
            
            $
            46,239
            
            $
            53,236
            
            $
            52,751
            
            $
            41,168Total
      revenues:As
      reported
            
            $
            36,191
            
            $
            40,999
            
            $
            40,219
            
            $
            36,615Adjustment
      for 2009 Acquisition (a)
            
            
            10,048
            
            
            12,246
            
            
            12,556
            
            
            5,712Total
      revenues
            
            $
            46,239
            
            $
            53,245
            
            $
            52,775
            
            $
            42,327Total
      costs and expenses:As
      reported
            
            $
            12,383
            
            $
            14,420
            
            $
            15,452
            
            $
            14,929Adjustment
      for 2009 Acquisition (a)
            
            
            3,781
            
            
            4,302
            
            
            3,879
            
            
            3,338Total
      costs and expenses
            
            $
            16,164
            
            $
            18,722
            
            $
            19,331
            
            $
            18,267Net
      income:As
      reported
            
            $
            23,559
            
            $
            26,300
            
            $
            24,456
            
            $
            20,465Adjustment
      for 2009 Acquisition (a)
            
            
            6,201
            
            
            7,862
            
            
            8,585
            
            
            2,348Net
      income
            
            $
            29,760
            
            $
            34,162
            
            $
            33,041
            
            $
            22,813Basic
      and diluted net income per common unit
            
            $
            -
            
            $
            0.53
            
            $
            0.81
            
            $
            0.68


______


(a)
            In
      August 2009, the Partnership completed the 2009 Acquisition from Pioneer.
      Because the 2009 Acquisition was acquired from Pioneer, the acquisition
      was accounted for as a transaction between entities under common control,
      whereby the assets and liabilities were recorded at Pioneer's historical
      cost and the Partnership's historical financial information was recast to
      include the results of operations of the properties acquired in the 2009
      Acquisition for all periods presented.   See Note B for
      additional information regarding the 2009
  Acquisition











PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


ITEM
      9.
            CHANGES
      IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
      DISCLOSURE





None.





ITEM
      9A.
            CONTROLS
      AND PROCEDURES




Evaluation of
disclosure controls and procedures.The Partnership's
management, under the supervision and 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
effectiveness of the design and operation of 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 Partnership's disclosure controls and procedures were
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 the 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 three
months ended December 31, 2009 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





The
management of the Partnership is responsible for establishing and maintaining
adequate internal control over financial reporting. The Partnership's internal
control over financial reporting is a process designed by management, under the
supervision of the General Partner's Chief Executive Officer and Chief Financial
Officer, to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of the Partnership's financial statements for
external purposes in accordance with generally accepted accounting
principles.





As of
December 31, 2009, management, under the supervision of the General Partner's
Chief Executive Officer and Chief Financial Officer, assessed the effectiveness
of the Partnership's internal control over financial reporting based on the
criteria for effective internal control over financial reporting established in
"Internal Control — Integrated Framework," issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on the evaluation under the
framework in "Internal Control – Integrated Framework", management concluded
that the Partnership's internal control over financial reporting was effective
as of December 31, 2009, based on those criteria.





Ernst
& Young LLP, the independent registered public accounting firm that audited
the consolidated financial statements of the Partnership included in this
Report, has issued an attestation report on the Partnership's internal control
over financial reporting as of December 31, 2009. The report, which expresses an
unqualified opinion on the effectiveness of the Partnership's internal control
over financial reporting as of December 31, 2009, is included in this Item under
the heading "Report of Independent Registered Public Accounting
Firm."







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





To The
Board of Directors of Pioneer Natural Resources GP LLC and the


Unitholders
of Pioneer Southwest Energy Partners L.P.





We have
audited Pioneer Southwest Energy Partners L.P.'s (the "Company") internal
control over financial reporting as of December 31, 2009, based on criteria
established in Internal
Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). Pioneer Southwest
Energy Partners L.P.'s management is responsible for maintaining effective
internal control over financial reporting, and for its assessment of the
effectiveness of internal control over financial reporting included in the
accompanying Management's Report on Internal Control Over Financial Reporting.
Our responsibility is to express an opinion on the Company's internal control
over financial reporting based on our audit.





We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States).  Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects.  Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness
of internal control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances.  We
believe that our audit provides a reasonable basis for our opinion.





A
company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles.  A company's internal
control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the assets of the company;
(2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial
statements.





Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements.  Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.





In our
opinion, Pioneer Southwest Energy Partners L.P. maintained, in all material
respects, effective internal control over financial reporting as of December 31,
2009, based on the COSO criteria.





We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of Pioneer
Southwest Energy Partners L.P. as of December 31, 2009 and 2008, and the related
consolidated statements of operations, partners' equity, cash flows, and
comprehensive income (loss) for each of the three years in the period ended
December 31, 2009 and our report dated February 26, 2010 expressed an
unqualified opinion thereon.





/s/ Ernst
& Young LLP





Dallas,
Texas


February
26, 2010







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


ITEM
      9B.
            OTHER
      INFORMATION





None.














PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


PART
      III





ITEM
      10.
            DIRECTORS,
      EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE





The
Partnership's operations and activities are managed by the General Partner,
which is a wholly-owned subsidiary of Pioneer. All of the Partnership's
executive management personnel are employees of Pioneer and devote their time as
needed to conduct the Partnership's business and affairs. The Board of Directors
of the General Partner oversees the General Partner's management, operations and
activities. Except as otherwise noted, references in this Report to "the Board
of Directors" refer to the Board of Directors of the General
Partner.




The Partnership and Pioneer have
entered into an Administrative Services Agreement pursuant to which Pioneer
performs administrative services for the Partnership such as accounting,
business development, finance, land, legal, engineering, investor relations,
management, marketing, information technology, insurance, government
regulations, communications, regulatory, environmental and human resources. The
agreement provides that Pioneer employees (including executive officers of the
General Partner) will devote such portion of their time as may be reasonable and
necessary for the operation of the Partnership's business. The executive
officers of the General Partner devote significantly less than a majority of
their time to the Partnership's business and the Partnership expects that to be
the case for the foreseeable future. See "Item 13. Certain Relationships and
Related Party Transactions, and Director Independence — Administrative Services
Agreement" for additional information about the Administrative Services
Agreement.





Directors and Executive Officers of
the General Partner





Unitholders
are not entitled to elect the General Partner or the directors of the General
Partner, or to directly or indirectly participate in the management or operation
of the Partnership. As owner of the General Partner, Pioneer elects all the
members of the Board of Directors. The General Partner owes a fiduciary duty to
the Partnership, although the Partnership's First Amended and Restated Agreement
of Limited Partnership (the "Partnership Agreement") limits such duties and
restricts the remedies available to unitholders for actions taken by the General
Partner that might otherwise constitute breaches of fiduciary
duties.




The following table sets forth
certain information regarding the members of the Board of Directors and the
executive officers of the General Partner.





Name
            
            Age
            
            PositionPhillip
      A. Gobe
            
            57
            
            DirectorAlan
      L. Gosule
            
            69
            
            DirectorRoyce
      W. Mitchell
            
            55
            
            DirectorArthur
      L. Smith
            
            57
            
            DirectorScott
      D. Sheffield
            
            57
            
            Chairman
      of the Board of Directors and Chief Executive OfficerRichard
      P. Dealy
            
            43
            
            Executive
      Vice President, Chief Financial Officer, Treasurer and
      DirectorDanny
      L. Kellum
            
            55
            
            Executive
      Vice President, Domestic Operations and DirectorTimothy
      L. Dove
            
            53
            
            President
      and Chief Operating OfficerMark
      S. Berg
            
            51
            
            Executive
      Vice President, General CounselChris
      J. Cheatwood
            
            49
            
            Executive
      Vice President, GeoscienceFrank
      W. Hall
            
            59
            
            Vice
      President and Chief Accounting
Officer





Executive officers and directors
serve until their successors are duly appointed or elected.




Set forth below is biographical
information about each of the directors named above, including the specific
experience, qualifications, attributes or skills that led to Pioneer's
conclusion that the person should serve as a director of the General
Partner.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


Scott D. Sheffield was
elected Chief Executive Officer and director of the General Partner in June 2007
and Chairman of the Board in May 2008. Mr. Sheffield, a distinguished
graduate of The University of Texas with a Bachelor of Science degree in
Petroleum Engineering, has held the position of Chief Executive Officer of
Pioneer since August 1997. He was President of Pioneer from August 1997 to
November 2004, and assumed the position of Chairman of the Board of Directors in
August 1999. He was the Chairman of the Board of Directors and Chief Executive
Officer of Parker & Parsley Petroleum Company ("Parker & Parsley") from
October 1990 until Pioneer was formed in August 1997. Mr. Sheffield joined
Parker & Parsley Development Company ("PPDC"), a predecessor of Parker &
Parsley, as a petroleum engineer in 1979. Mr. Sheffield served as Vice
President — Engineering of PPDC from September 1981 until April 1985, when he
was elected President and a Director. In March 1989, Mr. Sheffield was
elected Chairman of the Board of Directors and Chief Executive Officer of PPDC.
Before joining PPDC, Mr. Sheffield was employed as a production and
reservoir engineer for Amoco Production Company. Pioneer believes that Mr.
Sheffield's experience and education, as summarized above, render him qualified
to serve on the General Partner's Board of Directors, and particularly, his role
as Chief Executive Officer, his educational background and work experience in
petroleum engineering, his deep knowledge of the General Partner's business
resulting from his long tenure with Pioneer and its predecessor, and his
extensive knowledge of the energy industry.





Richard P. Dealy was elected
Executive Vice President, Chief Financial Officer, Treasurer and director of the
General Partner in June 2007. Mr. Dealy was elected Executive Vice
President and Chief Financial Officer of Pioneer in November 2004. Prior to that
time, Mr. Dealy held positions of Vice President and Chief Accounting
Officer from February 1998 and Vice President and Controller from August 1997 to
January 1998. Mr. Dealy joined Parker & Parsley in July 1992 and was
promoted to Vice President and Controller in 1995, in which position he served
until August 1997. He is a Certified Public Accountant, and prior to joining
Parker & Parsley, he was employed by KPMG LLP. Mr. Dealy graduated with
honors from Eastern New Mexico University with a Bachelor of Business
Administration degree in Accounting and Finance. Pioneer believes that Mr. Dealy
is qualified to serve on the General Partner's Board of Directors based on his
experience and education, as summarized above, and particularly, his role as
Chief Financial Officer, his extensive experience in public accounting and
finance, and his deep knowledge of the General Partner's business resulting from
his long tenure with Pioneer and its predecessor.





Phillip A. Gobewas elected
as a director of the General Partner in June 2009. Mr. Gobe joined Energy
Partners, Ltd. as chief operating officer in December 2004 and became president
in May 2005, and served in those capacities until his retirement in September
2007. Mr. Gobe also served as a director of Energy Partners, Ltd. from November
2005 until May 2008.  Prior to that, Mr. Gobe served as Chief
Operating Officer of Nuevo Energy Company from February 2001 until its
acquisition by Plains Exploration & Production Company in May 2004. Prior to
that time, he held numerous operations and human resources positions with Vastar
Resources, Inc. and Atlantic Richfield Company and its subsidiaries. Subsequent
to his retirement in September 2007, Energy Partners, Ltd. filed a voluntary
petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in May
2009. Mr. Gobe is a graduate of the University of Texas with a degree in history
and earned his MBA at the University of Louisiana in Lafayette. Pioneer believes
that Mr. Gobe is qualified to serve on the General Partner's Board of Directors
based on his experience and education, as summarized above, and particularly,
his extensive senior management experience in the oil and gas
industry.





Alan L. Gosule was elected as
a director of the General Partner in April 2008. Mr. Gosule has been a
partner in the New York office of the law firm of Clifford Chance LLP (successor
to Roger & Wells) since August 1991 and prior to that time was a partner in
the law firm of Gaston & Snow. Mr. Gosule is a graduate of Boston
University and its Law School and received an LLM in Taxation from Georgetown
University. Mr. Gosule also serves on the Board of Directors of MFA
Financial, Inc., Home Properties, Inc. and F.L. Putnam Investment Management
Company. He also serves on the Board of Trustees of Ursuline Academy. Pioneer
believes that Mr. Gosule is qualified to serve on the General Partner's Board of
Directors based on his experience and education, as summarized above, and
particularly, his education in the law and his extensive experience of over 40
years as an attorney advising private and public companies.





Danny L. Kellum was elected a
director of the General Partner in June 2009. Mr. Kellum was elected Executive
Vice President, Permian Operations of the General Partner in February 2010, and
prior to that served as Executive Vice President, Operations of the General
Partner since June 2007. Mr. Kellum, who received a Bachelor






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


of
Science degree in Petroleum Engineering from Texas Tech University in 1979, was
elected Executive Vice President - Permian Operations of Pioneer in February
2010. Mr. Kellum had previously served as Executive Vice President - Domestic
Operations of Pioneer from May 2000 until January 2010, and as Vice President -
Domestic Operations from January 2000 until May 2000, and Vice President -
Permian Division from August 1997 until December 1999. Mr. Kellum joined Parker
& Parsley as an operations engineer in 1981 after a brief career with Mobil
Oil Corporation, and his service with Parker & Parsley included serving as
Spraberry District Manager from 1989 until 1994 and as Vice President of the
Spraberry and Permian Division until August 1997. Pioneer believes that Mr.
Kellum is qualified to serve on the General Partner's Board of Directors based
on his experience and education, as summarized above, and particularly, his role
as Executive Vice President, Domestic Operations, his educational background and
work experience in petroleum engineering and operations, and his deep knowledge
of the General Partner's business resulting from his long tenure with Pioneer
and its predecessor.





Royce W. Mitchell was elected
as a director of the General Partner in April 2008. Mr. Mitchell has been
self-employed as an executive consultant, focusing on advising audit committees
of exploration and production companies, since January 2005, except for the
period from April 2008 through December 2008 when he served as Chief Financial
Officer of Frac Tech Services, Ltd. Mr. Mitchell served as Executive Vice
President, Chief Financial Officer and Chief Accounting Officer of Key Energy
Services, Inc. from January 2002 to January 2005. Before joining Key Energy
Services, Inc., he was a partner with KPMG LLP from April 1986 through December
2001 specializing in the oil and gas industry. He received a BBA from Texas Tech
University and is a certified public accountant. Pioneer believes that Mr.
Mitchell is qualified to serve on the General Partner's Board of Directors based
on his experience and education, as summarized above, and particularly, his
extensive experience in accounting matters focused on the oil and gas industry,
developed through experience with both an outside accounting firm and companies
in the industry.




Arthur L. Smithwas elected
as a director of the General Partner in April 2008. Mr. Smith is President
and Managing Member of Triple Double Advisors, LLC (an investment advisory firm
focusing on the energy industry), a position he has held since August 2007. From
1984 to 2007, Mr. Smith was Chairman and CEO of John S. Herold, Inc. (a
petroleum research and consulting firm). From 1976 to 1984, Mr. Smith was a
securities analyst with Argus Research Corp., The First Boston Corporation and
Oppenheimer & Co., Inc. Mr. Smith holds the CFA designation.
Mr. Smith serves on the board of directors of Plains All American GP LLC,
the general partner of Plains All American Pipeline, L.P. He also serves on the
board of non-profit Dress for Success Houston and the Board of Visitors for the
Nicholas School of the Environment at Duke University. Mr. Smith received a
BA from Duke University and an MBA from NYU's Stern School of Business. Pioneer
believes that Mr. Smith is qualified to serve on the General Partner's Board of
Directors based on his experience and education, as summarized above, and
particularly, his extensive experience of over 30 years in the fields of
financial analysis and investment banking, and his experience in the oil and gas
industry.





Set forth
below is biographical information about each of the General Partner's executive
officers, other than Messrs. Sheffield, Dealy and Kellum.





Timothy L. Dove was elected
President and Chief Operating Officer of the General Partner in June 2007.
Mr. Dove was elected President and Chief Operating Officer of Pioneer in
November 2004. Prior to that time, Mr. Dove held the positions of Executive
Vice President and Chief Financial Officer from February 2000 to November 2004
and Executive Vice President — Business Development from August 1997 to January
2000. Mr. Dove joined Parker & Parsley in May 1994 as Vice President —
International and was promoted to Senior Vice President — Business Development
in October 1996, in which position he served until August 1997. Before joining
Parker & Parsley, Mr. Dove was employed with Diamond Shamrock Corp.,
and its successor, Maxus Energy Corp., in various capacities in international
exploration and production, marketing, refining, and planning and development.
Mr. Dove earned a Bachelor of Science degree in Mechanical Engineering from
Massachusetts Institute of Technology in 1979 and received his Master of
Business Administration in 1981 from the University of Chicago.










PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


Mark S. Berg was elected
Executive Vice President, General Counsel and Assistant Secretary of the General
Partner in June 2007. Mr. Berg was elected Executive Vice President and
General Counsel of Pioneer in April 2005. Prior to that time, Mr. Berg
served as Executive Vice President, General Counsel and Secretary of American
General Corporation, a Fortune 200 diversified financial services company, from
1997 through 2002. Subsequent to the sale of American General to American
International Group, Inc., Mr. Berg joined Hanover Compressor Company as
Senior Vice President, General Counsel and Secretary. He served in that capacity
from May of 2002 through April of 2004. Mr. Berg began his career in 1983
with the Houston-based law firm of Vinson & Elkins L.L.P. He was a partner
with the firm from 1990 through 1997. Mr. Berg graduated Magna Cum Laude
and Phi Beta Kappa with a Bachelor of Arts degree from Tulane University in
1980. He earned his Juris Doctorate with honors from the University of Texas Law
School in 1983.




Chris J. Cheatwood was
elected Executive Vice President, Geoscience of the General Partner in June
2007. Mr. Cheatwood was elected Executive Vice President, Business Development
and Technology of Pioneer in February of 2010. Mr. Cheatwood had previously
served as Executive Vice President, Geoscience of Pioneer since November 2007,
and as Executive Vice President - Worldwide Exploration from January 2002 until
November 2007, Senior Vice President - Exploration from December 2000 to January
2002, and Vice President - Domestic Exploration from July 1998 to December
2000.  Before joining Pioneer, Mr. Cheatwood spent ten years with
Exxon Corporation.  Mr. Cheatwood is a graduate of the University of
Oklahoma with a Bachelor of Science degree in Geology and earned his Master of
Science degree in Geology from the University of Tulsa.




Frank W. Hall was elected
Vice President and Chief Accounting Officer of the General Partner in May 2008.
Mr. Hall was elected Vice President and Chief Accounting Officer of Pioneer
in May 2008. Prior to that time, Mr. Hall held the positions for Pioneer of
Corporate Controller from March 2007, Assistant Controller from January 2005 to
March 2007 and Manager of Financial Reporting from September 1998 to January
2005. From 1989 to 1998, Mr. Hall was an employee of Oryx Energy Company,
where he held Senior Financial Analyst positions in Financial Planning and
Financial Reporting. He was a partner in the certified public accounting firm of
Hall, Brock & Co. from 1983 to 1989; the Controller of Riddle Oil Company
from 1980 to 1983; and a member of the audit staff of Touche Ross & Co. from
1977 to 1980. Mr. Hall graduated with highest honors from the University of
Dallas with a Master of Business Administration in Corporate Finance and
graduated from the University of Texas at San Antonio with a Bachelor of
Business Administration, where he majored in accounting and business
management.





Governance





The NYSE
does not require a listed limited partnership like the Partnership to have a
majority of independent directors or to establish a compensation committee or a
nominating and corporate governance committee. It is the Partnership's present
intent, however, for the Board of Directors to have a majority of independent
directors.





The Board
of Directors has assessed the independence of each non-employee director under
the independence standards of the NYSE and the SEC, and has determined that
Messrs. Gobe, Gosule, Mitchell and Smith meet the requirements for
independence under these standards and are independent.





Meetings
and Committees of Directors





The Board
of Directors held 15 meetings during 2009. During 2009, each of the directors
attended at least 75 percent of the aggregate of the total number of meetings of
the Board of Directors and the total number of meetings of all committees of the
Board of Directors on which that director served.





The Board
of Directors has two standing committees: the Audit Committee and the Conflicts
Committee.





Audit Committee. The Audit
Committee assists the Board of Directors in its oversight of the Partnership's
internal controls, financial statements and the audit process. The Audit
Committee has the sole authority to retain and terminate the Partnership's
independent auditors, approve all auditing services and related fees and the
terms thereof, and pre-approve any permitted non-audit services to be rendered
by the Partnership's independent auditors.






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


The Audit
Committee also is responsible for confirming the independence and objectivity of
the Partnership's independent auditors. The members of the Audit Committee are
Messrs. Mitchell (Chairman), Gobe, Gosule and Smith.  The Board
of Directors has determined that each member of the Audit Committee meets the
independence standards of the NYSE and SEC applicable to members of the Audit
Committee. Those standards require that the director not be an affiliate of the
Partnership and that the director not receive from the Partnership, directly or
indirectly, any consulting, advisory or other compensatory fees except for fees
for services as a director. The Board of Directors also has determined that each
of the Audit Committee members is financially literate and that
Mr. Mitchell is an Audit Committee financial expert as defined by the SEC.
The Audit Committee held 12 meetings during 2009. Information regarding the
functions performed by the Audit Committee and its membership also can be found
in the Audit Committee's Charter, which is posted on the Partnership's website
at www.pioneersouthwest.com.





Conflicts Committee. The
Conflicts Committee reviews specific matters that the Board of Directors
believes may involve conflicts of interest. At the request of the Board of
Directors, the Conflicts Committee determines whether to approve the conflict of
interest matter. The members of the Conflicts Committee must meet the
independence and experience standards established by NYSE and SEC rules to serve
on an audit committee of a board of directors, and certain other requirements.
Any matters approved by the Conflicts Committee in good faith will be
conclusively deemed to be fair and reasonable to the Partnership, approved by
all of the Partnership's partners and not a breach by the General Partner of any
duties it may owe to the Partnership. The members of the Conflicts Committee are
Messrs. Smith (Chairman), Gobe, Gosule and Mitchell. The Conflicts
Committee held three meetings during 2009. Information regarding the functions
performed by the Conflicts Committee and its membership also can be found in the
Conflicts Committee's Charter, which is posted on the Partnership's website at
www.pioneersouthwest.com.





Executive Sessions of Non-Management
Directors, Procedure for
Directly Contacting the Board of Directors and Whistleblower
Policy





The Board
of Directors holds regular executive sessions in which the four independent
directors meet without any members of management present. The purpose of these
executive sessions is to promote open and candid discussion among the
independent directors. As there are only four independent directors, the
directors believe it is not necessary to appoint a presiding director for these
executive sessions.





A means
for interested parties to contact the Board of Directors (including the
independent directors as a group) directly has been established and is published
on the Partnership's website at www.pioneersouthwest.com.
All complaints and concerns will be received and processed by the Corporate
Secretary's Office of the General Partner. Information may be submitted
confidentially and anonymously, although the Partnership may be obligated by law
to disclose the information or identity of the person providing the information
in connection with government or private legal actions and in certain other
circumstances. The Partnership's policy is not to take any adverse action, and
to not tolerate any retaliation against any person for asking questions or
making good faith reports of possible violations of law, Partnership policy or
the Code of Business Conduct and Ethics.





Code of Ethics




Neither the Partnership nor the
General Partner has any employees. The Partnership and Pioneer have entered into
an Administrative Services Agreement pursuant to which Pioneer performs
administrative services for the Partnership, and all of Pioneer's employees are
subject to the Pioneer Natural Resources Code of Business Conduct and Ethics.
Accordingly, the Board of Directors of the General Partner has adopted the
Pioneer Natural Resources Code of Business Conduct and Ethics to govern its
members as well as the Partnership and the General Partner.





Availability
of Governance Guidelines, Charters and Code




Copies of the General Partner's
Governance Guidelines, Audit Committee Charter, Conflicts Committee Charter and
the Pioneer Natural Resources Code of Business Conduct and Ethics are available
on the Partnership's website at www.pioneersouthwest.com.






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.





Section
16(a) Beneficial Ownership Reporting Compliance




The executive officers and directors
of the General Partner and persons who beneficially own more than ten percent of
the Partnership's common units are required to file reports with the SEC,
disclosing the amount and nature of their beneficial ownership in common units
of the Partnership, as well as changes in that ownership. Based solely on its
review of reports and written representations that the Partnership has received,
the Partnership believes that all required reports were timely filed during
2009.





ITEM
      11.
            EXECUTIVE
      COMPENSATION





Compensation Discussion and
Analysis





The
Partnership is a master limited partnership and does not directly employ any of
the individuals responsible for managing or operating the Partnership's
business. All of the executive officers of the General Partner are executive
officers of Pioneer and devote their time as needed to conduct the Partnership's
business and affairs. Pursuant to the agreements with Pioneer, the Partnership
has agreed to reimburse the General Partner and its affiliates, including
Pioneer, for the cost of the services they provide to the Partnership, including
the compensation of their officers and other employees providing services to the
Partnership.





Neither
the Partnership nor the General Partner has a compensation committee. The
compensation policies and philosophy of Pioneer govern the types and amount of
compensation granted to each of Pioneer's executive officers, which include the
executive officers of the General Partner, with respect to their services to
Pioneer and its subsidiaries as a group. Accordingly, Pioneer has the ultimate
decision-making authority with respect to the total compensation of the
executive officers of the General Partner (except with respect to awards under
the Partnership's 2008 Long-Term Incentive Plan, which are granted by the Board
of Directors if any are granted). The compensation paid by Pioneer to the
executive officers of the General Partner is included within the total general
and administrative costs incurred by Pioneer, which are allocated to the
Partnership pursuant to a formula under the Administrative Services Agreement.
As a result, neither the General Partner nor the Partnership establishes the
amount of compensation that is awarded to the executive officers of the General
Partner, except with respect to awards under the Partnership's 2008 Long-Term
Incentive Plan. See "Item 13. Certain Relationships and Related Party
Transactions, and Director Independence — Administrative Services Agreement" for
additional information about the allocation of expenses to the Partnership under
the Administrative Services Agreement.




A full discussion of the
compensation programs for Pioneer's executive officers and the policies and
philosophy of the Compensation Committee of the Board of Directors of Pioneer
will be set forth in the proxy statement for Pioneer's 2010 Annual Meeting of
Stockholders under the heading "Compensation of Executive Officers," and the
Partnership incorporates by reference that section of Pioneer's proxy statement
into this Item 11. Pioneer's proxy statement will be available upon its filing
on the SEC's website at www.sec.govand on Pioneer's
website at www.pxd.comunder the heading
"Investors — SEC Filings."





Long-Term Incentive
Plan





As indicated above, although neither
the Partnership nor the General Partner has a compensation committee, the
General Partner has adopted the Pioneer Southwest Energy Partners L.P. 2008
Long-Term Incentive Plan for directors of the General Partner and for employees
and consultants of the General Partner and its affiliates who perform services
for the Partnership. The purpose of the long-term incentive plan is to provide a
means to enhance profitable growth by attracting and retaining individuals to
serve as directors of the General Partner as well as the employees and
consultants of Pioneer and its subsidiaries who provide services to the
Partnership by providing such individuals a means to acquire and maintain
ownership or awards, the value of which is tied to the performance of common
units. The long-term incentive plan seeks to achieve this purpose by providing
for grants of options, restricted units, phantom units, unit appreciation
rights, unit awards and other unit-based awards. The discussion below provides a
general overview and discussion regarding how the plan operates.






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.





Securities
to Be Offered




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. Units
withheld to satisfy exercise prices or tax withholding obligations will again be
available for delivery pursuant to other awards. In addition, if an award is
forfeited, cancelled or otherwise terminates, expires or is settled without the
delivery of units, the units subject to such award will again be available for
new awards under the plan. The units delivered pursuant to awards may be units
acquired in the open market or acquired from any person including the
Partnership, or any combination of the foregoing, as determined in the
discretion of the plan administrator (as defined below).




Administration
of the Plan




The plan
is administered by the Board of Directors or a committee thereof, referred to as
the plan administrator in this Report. The plan administrator may terminate or
amend the long-term incentive plan or any part of the plan at any time with
respect to any units for which a grant has not yet been made, including
increasing the number of units that may be granted, subject to any tax and legal
restrictions and the requirements of the exchange upon which the common units
are listed at that time. However, no change in any outstanding grant may be made
that would materially reduce the rights or benefits of the participant without
the consent of the participant. The plan will expire upon the earlier of (i) the
date units are no longer available under the plan for grants, (ii) its
termination by the Board of Directors or (iii) the tenth anniversary of the date
approved by the General Partner.




Awards




In General. The plan
administrator may make grants of awards with such terms as the plan
administrator shall determine, including terms governing the service period
and/or other performance conditions pursuant to which any such awards will vest
and/or be settled, as applicable. Grant levels in any given year may vary on a
discretionary basis based on measuring the Partnership's financial, operational,
strategic or other appropriate performance, as well as the individual
performance of plan participants.




Restricted Units. A
restricted unit is a common unit that vests over a period of time and during
that time is subject to forfeiture. Restricted units generally will be entitled
to receive quarterly distributions during the vesting period, but such
distributions may be subjected to the same or different vesting provisions as
the restricted unit. In addition, the plan administrator may provide that such
distributions be used to acquire additional restricted units.




Phantom Units. A phantom unit
entitles the grantee to receive a common unit upon or as soon as reasonably
practicable following the phantom unit's settlement date or, in the discretion
of the plan administrator, a cash payment equivalent to the fair market value of
a common unit. The plan administrator may, in its discretion, grant distribution
equivalent rights ("DERs") with respect to phantom unit awards. DERs entitle the
participant to receive cash or additional awards equal to the amount of any cash
distributions made by the Partnership during the period the phantom unit is
outstanding. Payment of a DER may be subject to the same vesting terms and/or
settlement terms as the award to which it relates or different vesting terms
and/or settlement terms, in the discretion of the plan
administrator.




Unit Options. Unit options
must have an exercise price that is not less than the fair market value of the
units on the date of grant. In general, unit options granted will become
exercisable over a period determined by the plan administrator.




Unit Appreciation Rights. A
unit appreciation right is an award that, upon exercise, entitles the
participant to receive the excess of the fair market value of a unit on the
exercise date over the exercise price established for the unit appreciation
right. Such excess will be paid in cash or common units. Unit appreciation
rights must have an exercise price that is not less than the fair market value
of the common units on the date of grant. In general, unit appreciation rights
granted will become exercisable over a period determined by the plan
administrator.






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


Other Unit-Based Awards. The long-term incentive plan permits the grant
of other unit-based awards, which are awards that are based, in whole or in
part, on the value or performance of a common unit or are denominated or payable
in common units. Upon settlement, the award may be paid in common units, cash or
a combination thereof, as provided in the award agreement.




Unit Awards. The long-term
incentive plan permits the grant of units that are not subject to vesting
restrictions. Unit awards may be in lieu of or in addition to other compensation
payable to the individual. The availability of unit awards is intended to
furnish additional compensation to plan participants and to align their economic
interests with those of common unitholders.




Other
Provisions





Change in Control; Termination of
Service. The plan administrator may, in its discretion, provide that
awards under the long-term incentive plan become exercisable or vest, as
applicable, upon a "change of control," as defined in the plan or an applicable
award agreement. In addition, the plan administrator may, in its discretion,
provide that if a grantee's employment, consulting arrangement or membership on
the Board of Directors terminates for any reason, the grantee's unvested award
will be automatically forfeited unless, and to the extent, the plan
administrator or the terms of the award agreement provide
otherwise.





Tax Withholding. Unless other
arrangements are made, the plan administrator is authorized to withhold for any
award, from any payment due under any award or from any compensation or other
amount owing to a participant the amount (in cash, units, units that would
otherwise be issued pursuant to such award, or other property) of any applicable
taxes payable with respect to the grant of an award, its settlement, its
exercise, the lapse of restrictions applicable to an award or in connection with
any payment relating to an award or the transfer of an award and to take such
other actions as may be necessary to satisfy the withholding obligations with
respect to an award.





Anti-Dilution Adjustments. If
any "equity restructuring" event occurs that could result in an additional
compensation expense under GAAP if adjustments to awards with respect to such
event were discretionary, the plan administrator will equitably adjust the
number and type of units covered by each outstanding award and the terms and
conditions of such award to equitably reflect the restructuring event, and the
plan administrator will adjust the number and type of units with respect to
which future awards may be granted. With respect to a similar event that would
not result in an accounting charge if adjustment to awards were discretionary,
the plan administrator shall have complete discretion to adjust awards in the
manner it deems appropriate. In the event the plan administrator makes any
adjustment in accordance with the foregoing provisions, a corresponding and
proportionate adjustment shall be made with respect to the maximum number of
units available under the plan and the kind of units or other securities
available for grant under the plan.





Compensation
Committee Report





Neither
the Partnership nor the General Partner has a compensation committee. The Board
of Directors of the General Partner has reviewed and discussed the compensation
discussion and analysis required by Item 402(b) of the SEC's Regulation S-K set
forth above with management and based on this review and discussion, has
approved it for inclusion in this Form 10-K.





The Board
of Directors of Pioneer Natural Resources GP LLC:





Richard
P. Dealy


Phillip
A. Gobe


Alan L.
Gosule


Danny L.
Kellum


Royce W.
Mitchell


Scott D.
Sheffield


Arthur L.
Smith







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.





Compensation
of Directors





2009
DIRECTOR COMPENSATION TABLE





The table below summarizes the
compensation paid to the non-employee directors of the General Partner during
2009:





Name
            
            Fees
      Earned or
              Paid
      in Cash (1)
              ($)
            Unit
      Awards (2),(3)
              ($)
            Total
              ($)Phillip
      A. Gobe
            
            $
            19,113
            
            $
            85,818
            
            $
            104,931Alan
      L. Gosule
            
            $
            62,513
            
            $
            49,987
            
            $
            112,500Royce
      W. Mitchell
            
            $
            70,013
            
            $
            49,987
            
            $
            120,000Arthur
      L. Smith
            
            $
            70,013
            
            $
            49,987
            
            $
            120,000


___________


(1)
            Amounts
      represent fees earned or paid in cash for services as a director during
      2009, including the cash portion of the annual base retainer fee and
      committee chairmanship or membership fees incurred in connection with
      service on the Board of Directors or any committee of the Board. Mr. Gobe
      joined the Board of Directors in June
2009.


(2)
            The
      amounts in this column represent the aggregate grant-date fair value of
      restricted unit awards made to the directors during 2009, calculated in
      accordance with ASC 718. The grant-date fair value is based on the closing
      price of the Partnership's common units as of the most recent trading day
      prior to the date the grants are awarded.  The amounts for
      Messrs. Gosule, Mitchell and Smith represent amounts attributable to
      annual grants made in May 2009, at which time the grant-date fair value of
      each unit award granted computed in accordance with ASC 718 was
      $17.57.  Upon his election to the Board in June 2009, Mr. Gobe
      was awarded an initial grant of restricted units having a value of $40,000
      and a pro rata portion of the annual grant amount, at which time the
      grant-date fair value of each unit award granted computed in accordance
      with ASC 718 was $19.62. Additional detail regarding the Partnership's
      unit-based awards is included in Note F of Notes to Consolidated Financial
      Statements included in "Item 8. Financial Statements and Supplementary
      Data."


(3)
            Aggregate
      director unit awards for which restrictions had not lapsed as of December
      31, 2009, totaled 17,121 units.





The Board
of Directors believes providing competitive compensation is necessary to attract
and retain qualified independent directors. The Board of Directors believes that
the compensation package should require a significant portion of the total
compensation package to be equity-based to align the interests of the directors
and the Partnership's unitholders.





The
elements of compensation for the non-employee directors for the 2009-2010
director year, which runs from May 2009 to May 2010, were as
follows:





•
            Each
      non-employee director receives an annual base retainer fee of $45,000, and
      an annual fee of $10,000 for service on one or more
      committees.


•
            Audit
      Committee members receive an additional $7,500 annual
  fee.


•
            Each
      non-employee director receives an annual equity award of $50,000 in
      restricted units, which vests one year following the date of the
      award.


•
            The
      chairmen of the Audit and Conflicts Committees receive an additional
      $7,500 annual fee.


•
            A
      newly-elected non-employee director receives an initial equity award of
      $40,000 in restricted units at the time of his or her election to the
      board, which vests ratably over a three-year period on each anniversary of
      the grant date.









PIONEER
SOUTHWEST ENERGY PARTNERS L.P.





Additionally,
each non-employee director is provided information technology support by the
Partnership and is also reimbursed for travel expenses to attend meetings of the
Board of Directors or its committees, travel and entertainment expenses for each
director's spouse who is invited to accompany directors to meetings of the Board
of Directors and Partnership-related business trips, director education,
seminars and trade publications. No additional fees are paid for attendance at
Board of Directors or committee meetings. The executive officers who are also
directors do not receive additional compensation for serving on the Board of
Directors.





The
vesting of ownership and the lapse of transfer restrictions on restricted units
to non-employee directors is accelerated in the event of the death or disability
of the director or a change in control of the Partnership.





Compensation
Committee Interlocks and Insider Participation




As previously discussed, the Board
of Directors is not required to maintain, and does not maintain, a compensation
committee. Scott D. Sheffield, the General Partner's Chairman of the Board and
Chief Executive Officer, serves as the Chairman of the Board and Chief Executive
Officer of Pioneer, and Richard P. Dealy, a director of the General Partner and
the General Partner's Executive Vice President and Chief Financial Officer, and
Danny L. Kellum, a director of the General Partner and the General Partner's
Executive Vice President, Operations, serve as executive officers of Pioneer.
All compensation decisions with respect to each of these persons are made by the
Compensation Committee of the board of directors of Pioneer. With the exception
of the foregoing, none of the executive officers of the General Partner serves,
or in the past year has served, as a member of the board of directors or
compensation committee of any entity that has one or more of its executive
officers serving as a member of the Board of Directors. See "Item 13. Certain
Relationships and Related Transactions, and Director Independence."










PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


ITEM
      12.
            SECURITY
      OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
      STOCKHOLDERS MATTERS




The following table sets forth the
beneficial ownership of the Partnership's common units as of February 23, 2010
by (i) each person known by the Partnership to beneficially own five percent or
more of the outstanding units; (ii) each member of the Board of Directors; (iii)
each of Pioneer's Chief Executive Officer, Chief Financial Officer and the three
other most highly compensation executive officers of Pioneer for 2009 (the
"NEOs"); and (iv) all directors and executive officers of the General Partner as
a group.





Unless
otherwise noted, the persons named below have sole voting power and investment
power with respect to such units.





Name of Person or Identity of
      Group
            
            Number
      of
              Units
            
            Percentage
              of
      Class (a)Pioneer
      Natural Resources USA, Inc. (b)
            
            20,521,200
            
            62.05205
      N. O'Connor Blvd.Suite
      200Irving,
      Texas 75039Scott
      D. Sheffield
            
            12,000
            
            (c)Richard
      P. Dealy
            
            20,000
            
            (c)Mark
      S. Berg
            
            11,426
            
            (c)Timothy
      L. Dove
            
            8,068
            
            (c)Jay
      P. Still
            
            400
            
            (c)Phillip
      A. Gobe (d)
            
            14,374
            
            (c)Alan
      L. Gosule (d)
            
            8,555
            
            (c)Royce
      W. Mitchell (d)
            
            7,055
            
            (c)Arthur
      L. Smith (d)
            
            7,055
            
            (c)All
      directors and executive officers as a group (11 persons)
    (d)
            
            94,033
            
            (c)





___________


(a)
            Based
      on 33,113,700 common units
outstanding.


(b)
            Pioneer
      Natural Resources USA, Inc. is a wholly-owned subsidiary of Pioneer, and
      therefore Pioneer also beneficially owns these common
    units.


(c)
            Does
      not exceed one percent of class.


(d)
            Includes
      restricted units awarded under the Pioneer Southwest Energy Partners L.P.
      2008 Long-Term Incentive Plan.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


The
following table sets forth, as of February 23, 2010, the number of shares of
common stock of Pioneer owned by (i) each member of the Board of Directors; (ii)
each NEO; and (iii) all directors and executive officers of the General Partner
as a group:





Name of Person or Identity of
      Group
            
            Number
      of
              Shares
            
            Percentage
              of
      Class (a)Scott
      D. Sheffield (c) (d) (e) (f) (g)
            
            754,052
            
            (b)Richard
      P. Dealy (c) (d) (e) (g)
            
            142,461
            
            (b)Mark
      S. Berg (d) (e) (g)
            
            84,527
            
            (b)Timothy
      L. Dove (c) (d) (e) (g)
            
            259,305
            
            (b)Jay
      P. Still (c) (d) (e) (g)
            
            61,444
            
            (b)Danny
      L. Kellum (d) (e) (g)
            
            114,497
            
            (b)Phillip
      A. Gobe
            
            -
            
            -Alan
      L. Gosule
            
            -
            
            -Royce
      W. Mitchell
            
            -
            
            -Arthur
      L. Smith
            
            -
            
            -All
      directors and executive officers as a group (11 persons) (c) (d) (e) (f)
      (g)
            
            1,479,166
            
            1.3





___________


(a)
            Based
      on 115,550,322 shares of common stock
  outstanding.


(b)
            Does
      not exceed one percent of class.


(c)
            Includes
      the following number of shares subject to exercisable stock options:
      Mr. Sheffield, 60,000; Mr. Dealy, 10,500; Mr. Dove, 19,998;
      and all directors and executive officers as a group,
    110,496.


(d)
            Includes
      the following number of unvested restricted shares or restricted stock
      units: Mr. Sheffield, 239,551; Mr. Dealy, 78,362; Mr. Berg,
      51,516; Mr. Dove, 132,617; Mr. Still, 45,098; Mr. Kellum,
      49,015; and all directors and executive officers as a group,
      613,784.


(e)
            Includes
      the following number of shares held in each respective officer's 401(k)
      account:  Mr. Sheffield, 22,133; Mr. Dealy, 312;
      Mr. Berg, 8,468; Mr. Dove, 352; Mr. Still, 165; Mr. Kellum,
      533; and all directors and executive officers as a group,
      33,700.


(f)
            Mr. Sheffield's
      beneficial ownership includes 37,827 shares held in his investment
      retirement account.


(g)
            Excludes
      the performance units that will vest if and to the extent predetermined
      performance targets are achieved.










PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


Securities
Authorized for Issuance under Equity Compensation Plans





The following table summarizes
information about the Partnership's equity compensation plans as of December 31,
2009:




Number
      of Securities
              to
      be Issued Upon
              Exercise
      of
              Outstanding
      Options
              (a)
            
            
            Weighted
      Average
              Exercise
      Price of
              Outstanding
      Options
            
            Number
      of Securities
              Remaining
      Available for
              Future
      Issuance Under Equity
              Compensation
      Plans
              (Excluding
      Securities Reflected
              in
      First Column) (b)Pioneer
      Southwest Energy Partners L.P.:2008
      Long-Term Incentive Plan
            
            —
            
            $
            —
            
            2,974,461





__________


(a)
            There
      were no outstanding options, warrants or equity rights awarded under the
      Partnership's equity compensation plans as of December 31, 2009. The
      securities do not include restricted units awarded under the 2008
      Long-Term Incentive Plan.(b)
            All
      equity compensation plans have been approved by security
      holders.





See "Item 11. Executive Compensation"
and Note F of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for discussion of the Pioneer
Southwest Energy Partners L.P. 2008 Long-Term Incentive Plan.





ITEM
      13.
            CERTAIN
      RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
      INDEPENDENCE




As of February 23, 2010, affiliates of
the General Partner, including its directors and executive officers, owned
20,615,233 common units representing approximately 62 percent of the common
units outstanding. In addition, the General Partner owned a 0.1 percent general
partner interest in the Partnership.





Distributions and Payments to the
General Partner and Its Affiliates




The following table summarizes the
distributions and payments to be made by the Partnership to the General Partner
and its affiliates in connection with the ongoing operation and liquidation of
the Partnership. These distributions and payments were determined by and among
affiliated entities and, consequently, are not the result of arm's-length
negotiations.





Ongoing
      OperationsDistributions
      of available cash to theGeneral Partner and its
    affiliates
            The
      Partnership makes cash distributions to its partners, including the
      General Partner and its affiliates, as the holders of common units and
      general partner units. During 2009, Pioneer received a total of $41.1
      million in distributions from the Partnership in respect of its common
      units and general partner units.Payments
      to the General Partner and its affiliates
            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 and its affiliates in connection with operating the
      Partnership's business. These expenses include salary, bonus, incentive
      compensation (including equity compensation) and other amounts paid to
      persons who perform services for the Partnership or on its behalf. Pioneer





118
   
 
 is
      entitled to determine in good faith the expenses that are allocable to the
      Partnership. To implement part of this Partnership Agreement requirement,
      the Partnership and Pioneer have entered into the Administrative Services
      Agreement, which establishes a formula by which a portion of Pioneer's
      overhead expenses is allocated to the Partnership. See "— Administrative
      Services Agreement" below. The Partnership is charged an operating
      overhead fee pursuant to operating agreements with Pioneer. See " —
      Operating Agreements" below. Additionally, Pioneer is a minority owner of
      certain gas processing plants that process a portion of the Partnership's
      wet gas and retain as compensation a portion of the Partnership's dry gas
      residue and NGL value. See "— Gas Processing Arrangements" below. The
      Partnership has agreed to pay Pioneer for the Partnership's share of state
      and local income and other taxes. See "— Tax Sharing Arrangement"
      below.Withdrawal
      or removal of the General Partner
                If
      the General Partner withdraws or is removed, its general partner interest
      will either be sold to the new general partner for cash or converted into
      common units, in each case for an amount equal to the fair market value of
      those interests.Liquidation
      StageLiquidation
                If
      the Partnership were to be liquidated, the partners, including the General
      Partner, would be entitled to receive liquidating distributions according
      to their particular capital account balances.
 August 2009 Purchase and Sale
Transaction




On August 31, 2009, Pioneer
Southwest Energy Partners USA LLC ("Pioneer Southwest LLC"), a wholly-owned
subsidiary of the Partnership, completed the acquisition from Pioneer of oil and
gas properties in the Spraberry field and assumed net obligations associated
with certain commodity price derivative positions and certain other liabilities
pursuant to a Purchase and Sale Agreement with Pioneer having an effective date
of July 1, 2009 (the acquisition, including liabilities assumed, is referred to
in this Report as the "2009 Acquisition").  Associated therewith,
Pioneer Southwest LLC paid Pioneer $168.2 million of cash, including customary
closing adjustments. In connection with the assumption of the net obligations
associated with commodity price derivative positions, Pioneer and the
Partnership entered into novation agreements with the relevant counterparties.
The novation agreements transferred Pioneer's rights and responsibilities under
the net derivative obligations to the Partnership. See Note B of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data." Pursuant to the Purchase and Sale Agreement, Pioneer agreed
to indemnify the Partnership for one year against liabilities with respect to
the use, ownership and operation of the transferred properties or with the
violation of environmental laws, and for four years against claims that Pioneer
failed to pay any required royalties associated with the transferred properties.
Pioneer will also indemnify the Partnership for breaches of representations as
to tax matters until the expiration of the applicable statutes of limitations
for taxes. In general, Pioneer's indemnification obligation is capped at 25
percent of the total consideration, and Pioneer will not have any
indemnification obligation until the Partnership's losses exceed two percent of
the total consideration, in the aggregate, and then only to the extent such
aggregate losses exceed two percent.





Administrative
Services Agreement




Pursuant to the Administrative
Services Agreement, 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. Currently, expenses are reimbursed based on
a






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


methodology
of determining the Partnership's share, on a per BOE basis, of certain of the
general and administrative costs incurred by Pioneer. Under this initial
methodology, the per BOE cost for services during any period is 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 VPP 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 is
determined by multiplying the per BOE costs by the Partnership's total
production (including volumes delivered by the Partnership under VPP
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 at any time upon 90 days notice. The Partnership
paid a total of $1.9 million to Pioneer under this agreement during
2009.





Omnibus
Agreement, Omnibus Operating Agreements and Operating Agreements





Pioneer
is the operator of all of the Partnership's properties. Upon the closing of the
Partnership's initial public offering in May 2008, the Partnership and
Pioneer  entered into an Omnibus Agreement (the "IPO Omnibus
Agreement") and an Omnibus Operating Agreement (the "IPO Omnibus Operating
Agreement") to govern their relationship with respect to the properties the
Partnership acquired in connection with the initial public offering. In
addition, in connection with the 2009 Acquisition, the Partnership and Pioneer
entered into an Omnibus Operating Agreement (the "2009 Omnibus Operating
Agreement") to govern their relationship with respect to the properties the
Partnership acquired in connection with that acquisition, and amended IPO
Omnibus Operating Agreement with respect to certain matters.





Area of Operations. The IPO
Omnibus Agreement limits the Partnership's area of operations to onshore Texas
and the southeast region of New Mexico, comprising Chaves, Curry, De Baca, Eddy,
Lincoln, Lea, Otero and Roosevelt counties. Pioneer has the right to expand the
Partnership's area of operations, but has no obligation to do so.





VPP. A substantial portion of
the properties that the Partnership owns is subject to Pioneer's
VPP.  Pursuant to the IPO Omnibus Agreement and the Purchase and Sale
Agreement relating to the 2009 Acquisition, 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 either (i) make a cash payment to the Partnership for the value of
the production (computed by taking the volumes delivered to meet the VPP
obligation times the price the Partnership would have received for the related
volumes, plus any out-of-pocket expenses or other expenses or losses incurred by
the Partnership in connection with the delivery of such volumes) required to
meet the VPP obligation or (ii) deliver to the Partnership volumes equal to the
volumes delivered pursuant to the VPP obligation.





Operations. Pursuant to the
IPO Omnibus Operating Agreement and the 2009 Omnibus Operating
Agreement,  the Partnership has agreed to certain restrictions and
limitations on its ability to exercise certain rights that would otherwise be
available to it under the operating agreements that govern the Partnership's
properties where Pioneer is the operator. For example, the Partnership will not
object to attempts by Pioneer to develop the leasehold acreage surrounding the
Partnership's wells; the Partnership is restricted in its ability to remove
Pioneer as the operator; Pioneer-proposed operations will take precedence over
any conflicting operations that the Partnership proposes; and the Partnership
must allow Pioneer to use certain of the Partnership's production facilities in
connection with other properties operated by Pioneer, subject to capacity
limitations.





In
addition, Pioneer and the Partnership have entered into operating agreements
with respect to the Partnership's properties. Pursuant these agreements, the
Partnership pays Pioneer overhead charges associated with






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


operating
the Partnership's oil and gas properties (commonly referred to as the Council of
Petroleum Accountants Societies, or COPAS, fee). Overhead charges are usually
paid by third parties to the operator of a well pursuant to operating
agreements. The Partnership also pays Pioneer for its direct and indirect
expenses that are chargeable to the wells under their respective operating
agreements.





Indemnities Relating to the IPO
Properties. Pursuant to the IPO Omnibus Agreement, Pioneer will indemnify
the Partnership until May 6, 2011 against liabilities with respect to claims
associated with the use, ownership and operation of the IPO Properties prior to
May 6, 2008, the closing of the initial public offering up to an amount not to
exceed $10.0 million in the aggregate. In addition, Pioneer will not have any
indemnification obligation until the Partnership's losses exceed $500 thousand
in the aggregate, and then only to the extent such aggregate losses exceed $500
thousand.  With respect to title to the wellbore interests conveyed to
the Partnership as part of the IPO Properties, Pioneer will indemnify the
Partnership until May 6, 2011 for losses attributable to defects in title to the
Partnership's interest in the presently producing intervals in the wellbores,
other than certain permitted encumbrances that the Partnership has agreed do not
constitute title defects. Examples of such permitted encumbrances include
regulatory and existing contractual obligations, certain restrictions on
assignment that have been waived either in writing or by the passage of time,
certain liens that do not materially interfere with the use of the Partnership's
properties as they have been used in the past or are proposed to be used in the
future, and the VPP obligation. Pioneer will also indemnify the Partnership
until the expiration of the applicable statutes of limitations for taxes
attributable to the operations of the IPO Properties prior to May 6,
2008.





Gas
Processing Arrangements





Pioneer owns an approximate 27
percent interest in the Midkiff/Benedum gas processing plant and an approximate
30 percent interest in the Sale Ranch gas processing plant. These plants process
wet gas from producing wells, and retain as compensation approximately 19
percent and 20 percent, respectively, of the dry gas residue and NGL value.
Substantially all of the Partnership's total NGL and gas sales revenues in 2009
were from the sale of NGL and gas processed through the Midkiff/Benedum and Sale
Ranch gas processing plants.





Tax
Sharing Agreement





The Partnership and Pioneer have
entered into a Tax Sharing Agreement, pursuant to which the Partnership agreed
to 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. During 2009,
the Partnership recorded a payable to Pioneer of $460 thousand under this
agreement.





Policies and Procedures for Review,
Approval and Ratification of Related Person
Transactions





The Partnership's Governance Guidelines
provide that independent directors are to periodically review all transactions
that would require disclosure under Item 404(a) of SEC Regulation S-K, and make
a recommendation to the Board of Directors regarding the initial authorization
or ratification of any such transaction. All of the transactions disclosed in
this Item 13 entered into since January 1, 2009, were either pursuant
to agreements in place at the time of the Offering and accordingly were not
required to be reviewed, ratified or approved pursuant to the Governance
Guidelines, or were so reviewed, ratified or approved.




The Partnership Agreement provides
that the General Partner is responsible to identify conflicts of interest, and
may choose to resolve a conflict of interest by any one of the methods described
in the Partnership Agreement. The General Partner intends to submit to the
Conflicts Committee for review, approval or ratification any material
transactions in which any related person (principally directors, officers,
significant unitholders and their immediate family members) has a material
interest and that involves at least $120,000. However, the General Partner is
not required under the Partnership Agreement to do so.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


Director
Independence




See "Item 10. Directors,
Executive Officers and Corporate Governance" for
information  regarding the directors of the General Partner and the
independence requirements applicable to the Board of Directors and its
committees.





ITEM
      14.
            PRINCIPAL
      ACCOUNTING FEES AND SERVICES




The Audit Committee of the Board of
Directors of the General Partner selected Ernst & Young LLP as the
independent registered public accounting firm to audit the Partnership's
consolidated financial statements for the year ended December 31,
2009.





Fees
Incurred by the Partnership for Services Provided by Ernst & Young
LLP




The following table shows the fees paid
or accrued by the Partnership for audit services provided by Ernst & Young
LLP for the years ended December 31, 2009 and 2008:





2009
            
            2008Audit
      fees (a)
            $
            959,142
            
            $
            881,000Audit-related
      fees (b)
            
            -
            
            
            -Tax
      fees (b)
            
            -
            
            
            -All
      other fees (b)
            
            -
            
            
            -$
            959,142
            
            $
            881,000


______


(a)
            Audit
      fees represent fees for professional services provided in connection with
      the (i) the audit of the Partnership's annual consolidated financial
      statements included in this Annual Report on Form 10-K, (ii) reviews of
      the Partnership's quarterly financial statements included in its Quarterly
      Reports on Form 10-Q, and (iii) services in connection with the
      Partnership's other filings with the SEC, including review and preparation
      of registration statements, comfort letters, consents and research
      necessary to comply with generally accepted auditing
      standards.


(b)
            There
      were no audit-related fees, tax fees or other fees paid to Ernst &
      Young LLP for services in 2009 or
2008.





Audit
Committee's Pre-Approval Policy and Procedures





The Audit
Committee's policy is to pre-approve all audit and permissible non-audit
services provided by the independent registered public accounting firm. These
services may include audit services, audit-related services, and other services.
Pre-approval is detailed as to the specific service or category of service and
is subject to a specific approval. The Audit Committee requires the independent
registered public accounting firm and management to report on the actual fees
charged for each category of service at Audit Committee meetings throughout the
year.





During
the year, circumstances may arise when it may become necessary to engage the
independent registered public accounting firm for additional services not
contemplated in the original pre-approval. In those circumstances, the Audit
Committee requires specific pre-approval before engaging the independent
registered public accounting firm. The Audit Committee has delegated
pre-approval authority to the chairman of the Audit Committee for those
instances when pre-approval is needed prior to a scheduled Audit Committee
meeting. The chairman of the Audit Committee must report on such approval at the
next scheduled Audit Committee meeting.





All 2009
audit and non-audit services provided by the independent registered public
accounting firm were pre-approved.






PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


PART
IV




ITEM
15.                      EXHIBITS,
FINANCIAL STATEMENT SCHEDULES




(a)         Listing
of Financial Statements




Financial
Statements




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




·
            Report
      of Independent Registered Public Accounting
Firm




·
            Consolidated
      Balance Sheets as of December 31, 2009 and
2008




·
            Consolidated
      Statements of Operations for the Years Ended December 31, 2009, 2008 and
      2007




·
            Consolidated
      Statements of Partners' Equity for the Years Ended December 31, 2009, 2008
      and 2007




·
            Consolidated
      Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and
      2007




·
            Consolidated
      Statements of Comprehensive Income (Loss) for the Years Ended December 31,
      2009, 2008 and 2007




·
            Notes
      to Consolidated Financial
Statements




·
            Unaudited
      Supplementary Information




(b)         Exhibits




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




(c)         Financial
Statement Schedules




No financial statement schedules are
required to be filed as part of the Report or they are inapplicable.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


Exhibits





Exhibit
              Number
            
            
            
            Description2.1
            
            
            —
            Contribution
      Agreement, dated May 6, 2008, by and among the Partnership, Pioneer
      Natural Resources USA, Inc. and Pioneer Natural Resources GP LLC
      (incorporated by reference to Exhibit 2.1 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on May 9,
      2008).2.2
            
            
            —
            Membership
      Interest Sale Agreement, dated May 6, 2008, between the Partnership
      and Pioneer Natural Resources USA, Inc. (incorporated by reference to
      Exhibit 2.2 to the Partnership's Current Report on Form 8-K, File No.
      001-34032, filed with the SEC on May 9, 2008).2.3
            *
            
            —
            Purchase
      and Sale Agreement, dated May 6, 2008, by and among Pioneer Southwest
      Energy Partners USA LLC, Pioneer Natural Resources USA, Inc. and Pioneer
      Retained Properties Company LLC (incorporated by reference to Exhibit 2.3
      to the Partnership's Current Report on Form 8-K, File No. 001-34032, filed
      with the SEC on May 9, 2008).2.4
            *
            
            —
            Omnibus
      Agreement, dated May 6, 2008, by and among the Partnership, Pioneer
      Natural Resources GP LLC, Pioneer Southwest Energy Partners USA LLC,
      Pioneer Natural Resources Company and Pioneer Natural Resources USA, Inc.
      (incorporated by reference to Exhibit 2.4 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on May 9,
      2008).2.5
            *
            
            —
            Agreement
      and Plan of Merger, dated May 1, 2008, by and among Pioneer Southwest
      Energy Partners USA LLC, Pioneer Natural Resources USA, Inc., Pioneer
      Retained Properties Company LLC and Pioneer Limited Natural Resources
      Properties LLC (incorporated by reference to Exhibit 2.1 to the
      Partnership's Current Report on Form 8-K, File No. 001-34032, filed with
      the SEC on May 2, 2008).2.6
            *
            
            —
            First
      Amendment to Omnibus Agreement entered into as of December 31, 2008, to be
      effective as of May 6, 2008 among the Partnership, Pioneer Natural
      Resources GP LLC, Pioneer Southwest Energy Partners USA LLC, Pioneer
      Natural Resources Company and Pioneer Natural Resources USA, Inc.
      (incorporated by reference to Exhibit 2.6 to the Partnership's Annual
      Report on Form 10-K for the year ended December 31, 2008, File No.
      001-34032).2.7
            *
            
            —
            Purchase
      And Sale Agreement By And Among Pioneer Natural Resources USA, Inc.,
      Pioneer Southwest Energy Partners USA LLC and the Partnership
      (incorporated by reference to Exhibit 2.1 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on September 3,
      2009).3.1
            
            
            —
            Certificate
      of Limited Partnership of Pioneer Resource Partners L.P. (incorporated by
      reference to Exhibit 3.1 to the Partnership's Registration Statement on
      Form S-1 (File No. 333-144868)).3.2
            
            
            —
            Certificate
      of Amendment to Certificate of Limited Partnership of Pioneer Resource
      Partners L.P. (incorporated by reference to Exhibit 3.2 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).3.3
            
            
            —
            First
      Amended and Restated Agreement of Limited Partnership of Pioneer Southwest
      Energy Partners L.P. dated May 6, 2008, between Pioneer Natural Resources
      GP LLC, as the General Partner, and Pioneer Natural Resources USA, Inc.,
      as the Organizational Limited Partner, together with any other persons who
      become Partners (as defined in such agreement) in the Partnership
      (incorporated by reference to Exhibit 3.1 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on May 9,
      2008).4.1
            
            
            —
            Form
      of Senior Indenture (incorporated by reference to Exhibit 4.1 to the
      Partnership's Registration Statement on Form S-3 (Registration No.
      333-162566)).4.2
            
            
            —
            Form
      of Subordinated Indenture (incorporated by reference to Exhibit 4.2 to the
      Partnership's Registration Statement on Form S-3 (Registration No.
      333-162566)).10.1
            
            H
            —
            Pioneer
      Southwest Energy Partners L.P. 2008 Long Term Incentive Plan (incorporated
      by reference to Exhibit 10.2 to the Partnership's Registration Statement
      on Form S-1 (Registration No.
333-144868)).





124









10.2
              
              
              —
              Administrative
      Services Agreement, dated May 6, 2008, among the Partnership, Pioneer
      Natural Resources GP LLC, Pioneer Southwest Energy Partners USA LLC, and
      Pioneer Natural Resources USA, Inc. (incorporated by reference to Exhibit
      10.2 to the Partnership's Current Report on Form 8-K, File No. 001-34032,
      filed with the SEC on May 9, 2008).10.3
              
              
              —
              Tax
      Sharing Agreement, dated May 6, 2008, by and between the Partnership
      and Pioneer Natural Resources Company (incorporated by reference to
      Exhibit 10.3 to the Partnership's Current Report on Form 8-K, File No.
      001-34032, filed with the SEC on May 9, 2008).10.4
              
              
              —
              Omnibus
      Operating Agreement, dated May 6, 2008, by and between Pioneer
      Southwest Energy Partners USA LLC and Pioneer Natural Resources USA, Inc.
      (incorporated by reference to Exhibit 10.4 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on May 9,
      2008).10.5
              
              
              —
              First
      Amendment dated August 31, 2009 to Omnibus Operating Agreement dated May
      6, 2008, between Pioneer Natural Resources USA, Inc. and Pioneer Southwest
      Energy Partners USA LLC (incorporated by reference to Exhibit 10.2 to the
      Partnership's Current Report on Form 8-K, File No. 001-34032, filed with
      the SEC on September 3, 2009).10.6
              
              H
              —
              Form
      of Restricted Unit Award Agreement for Initial Grants to Non-Employee
      Directors (incorporated by reference to Exhibit 10.1 to the Partnership's
      Current Report on Form 8-K, File No. 001-34032, filed with the SEC on May
      2, 2008).10.7
              
              H
              —
              Form
      of Restricted Unit Award Agreement for Annual Grants to Non-Employee
      Directors (incorporated by reference to Exhibit 10.2 to the Partnership's
      Current Report on Form 8-K, File No. 001-34032, filed with the SEC on May
      2, 2008).10.8
              
              
              —
              Indemnification
      Agreement between the Partnership and Phillip A. Gobe, together with a
      schedule identifying other substantially identical agreements between the
      Partnership and each non-employee director of the Partnership's general
      partner identified on the schedule and identifying the material
      differences between each of those agreements and the filed Indemnification
      Agreement (incorporated by reference to Exhibit 10.1 to the Partnership's
      Current Report on Form 8-K, File No. 001-34032, filed with the SEC on
      August 19, 2009).10.9
              
              
              —
              Credit
      Agreement entered into as of October 29, 2007, among the Partnership, as
      the Borrower, Bank of America, N.A., as Administrative Agent, and certain
      other lenders (incorporated by reference to Exhibit 10.1 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).10.10
              
              
              —
              Amendment
      to Credit Agreement dated as of December 14, 2007, among the Partnership,
      as the Borrower, Bank of America, N.A., as Administrative Agent, and
      certain other lenders (incorporated by reference to Exhibit 10.8 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).10.11
              
              
              —
              Second
      Amendment to Credit Agreement dated as of February 15, 2008, among the
      Partnership, as the Borrower, Bank of America, N.A., as Administrative
      Agent, and certain other lenders (incorporated by reference to Exhibit
      10.13 to the Partnership's Registration Statement on Form S-1
      (Registration No. 333-144868)).10.12
              
              
              —
              Third
      Amendment to Credit Agreement dated as of April 15, 2008, among the
      Partnership, as the Borrower, Bank of America, N.A., as Administrative
      Agent, and certain other lenders (incorporated by reference to Exhibit
      10.15 to the Partnership's Registration Statement on Form S-1
      (Registration No. 333-144868)).10.13
              
              
              —
              Limited
      Waiver Regarding Credit Agreement, entered into as of March 26, 2009,
      among the Partnership, as the Borrower, Bank of America, N.A., as
      Administrative Agent, and the other lenders signatory thereto
      (incorporated by reference to Exhibit 10.1 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on March 31,
      2009).10.14
              
              
              —
              Crude
      Oil Purchase Contract (incorporated by reference to Exhibit 10.9 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).10.15
              
              
              —
              Natural
      Gas Liquids Purchase Contract  (incorporated by reference to
      Exhibit 10.10 to the Partnership's Registration Statement on Form S-1
      (Registration No. 333-144868)).10.16
              
              
              —
              Crude
      Oil Purchase Contract (incorporated by reference to Exhibit 10.11 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).10.17
              
              
              —
              Crude
      Oil Purchase Contract (incorporated by reference to Exhibit 10.12 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).














10.18
                
                
                —
                Omnibus
      Operating Agreement dated August 31, 2009, between Pioneer Natural
      Resources USA, Inc. and Pioneer Southwest Energy Partners USA LLC
      (incorporated by reference to Exhibit 10.1 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on September 3,
      2009).10.19
                
                (a)
                —
                Amendment
      to Crude Oil Purchase Contract filed as Exhibit 10.9 to the Partnership's
      Registration Statement on Form S-1 (Registration No.
      333-144868).10.20
                
                (a)
                —
                Amendment
      to Natural Gas Liquids Purchase Contract filed as Exhibit 10.10 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868).10.21
                
                (a)
                —
                Amendment
      to Crude Oil Purchase Contract filed as Exhibit 10.11 to the Partnership's
      Registration Statement on Form S-1 (Registration No.
      333-144868).10.22
                
                (a)
                —
                Amendment
      to Crude Oil Purchase Contract filed as Exhibit 10.12 to the Partnership's
      Registration Statement on Form S-1 (Registration No.
      333-144868).10.23
                
                (a)
                —
                Crude
      Oil Contracts with Occidental Energy Marketing, Inc.21.1
                
                (a)
                —
                Subsidiaries
      of the registrant.23.1
                
                (a)
                —
                Consent
      of Ernst & Young LLP.23.2
                
                (a)
                —
                Consent
      of Netherland, Sewell & Associates, Inc.31.1
                
                (a)
                —
                Chief
      Executive Officer certification under Section 302 of Sarbanes-Oxley Act of
      2002.31.2
                
                (a)
                —
                Chief
      Financial Officer certification under Section 302 of Sarbanes-Oxley Act of
      2002.32.1
                
                (b)
                —
                Chief
      Executive Officer certification under Section 906 of Sarbanes-Oxley Act of
      2002.32.2
                
                (b)
                —
                Chief
      Financial Officer certification under Section 906 of Sarbanes-Oxley Act of
      2002.99.1
                
                (a)
                —
                Report
      of Netherland, Sewell & Associates, Inc..


_____________


(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.







PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


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.








PIONEER
      SOUTHWEST ENERGY PARTNERS
      L.P.             
      by: Pioneer Natural Resources GP LLC, its general
  partner


Date:
February 26, 2010








By:
            /s/  Scott
      D. SheffieldScott
      D. Sheffield,Chairman
      of the Board of Directors and
              Chief
      Executive Officer




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.





Signature
            
            Title
            Date/s/  Scott
      D. Sheffield
            
            Chairman
      of the Board of Directors and ChiefExecutive Officer
      (principal executiveofficer)
            February
      26, 2010Scott
      D. Sheffield/s/  Richard
      P. Dealy
            
            Executive Vice President,
      Chief Financial
      Officer, Treasurer and Director (principal financial officer)
            February
      26, 2010Richard
      P. Dealy/s/  Frank
      W. Hall
            
            Vice
      President and Chief AccountingOfficer
              (principal
      accounting officer)
            February
      26, 2010Frank
      W. Hall/s/  Phillip
      A. Gobe
            
            Director
            February
      26, 2010Phillip
      A. Gobe/s/  Alan
      L. Gosule
            
            Director
            February
      26, 2010Alan
      L. Gosule/s/  Danny
      L. Kellum
            
            Director
            February
      26, 2010Danny
      L. Kellum/s/  Royce
      W. Mitchell
            
            Director
            February
      26, 2010Royce
      W. Mitchell/s/  Arthur
      L. Smith
            
            Director
            February
      26, 2010Arthur
      L. Smith










PIONEER
SOUTHWEST ENERGY PARTNERS L.P.


Exhibits





Exhibit
              Number
            
            
            
            Description2.1
            
            
            —
            Contribution
      Agreement, dated May 6, 2008, by and among the Partnership, Pioneer
      Natural Resources USA, Inc. and Pioneer Natural Resources GP LLC
      (incorporated by reference to Exhibit 2.1 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on May 9,
      2008).2.2
            
            
            —
            Membership
      Interest Sale Agreement, dated May 6, 2008, between the Partnership
      and Pioneer Natural Resources USA, Inc. (incorporated by reference to
      Exhibit 2.2 to the Partnership's Current Report on Form 8-K, File No.
      001-34032, filed with the SEC on May 9, 2008).2.3
            *
            
            —
            Purchase
      and Sale Agreement, dated May 6, 2008, by and among Pioneer Southwest
      Energy Partners USA LLC, Pioneer Natural Resources USA, Inc. and Pioneer
      Retained Properties Company LLC (incorporated by reference to Exhibit 2.3
      to the Partnership's Current Report on Form 8-K, File No. 001-34032, filed
      with the SEC on May 9, 2008).2.4
            *
            
            —
            Omnibus
      Agreement, dated May 6, 2008, by and among the Partnership, Pioneer
      Natural Resources GP LLC, Pioneer Southwest Energy Partners USA LLC,
      Pioneer Natural Resources Company and Pioneer Natural Resources USA, Inc.
      (incorporated by reference to Exhibit 2.4 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on May 9,
      2008).2.5
            *
            
            —
            Agreement
      and Plan of Merger, dated May 1, 2008, by and among Pioneer Southwest
      Energy Partners USA LLC, Pioneer Natural Resources USA, Inc., Pioneer
      Retained Properties Company LLC and Pioneer Limited Natural Resources
      Properties LLC (incorporated by reference to Exhibit 2.1 to the
      Partnership's Current Report on Form 8-K, File No. 001-34032, filed with
      the SEC on May 2, 2008).2.6
            *
            
            —
            First
      Amendment to Omnibus Agreement entered into as of December 31, 2008, to be
      effective as of May 6, 2008 among the Partnership, Pioneer Natural
      Resources GP LLC, Pioneer Southwest Energy Partners USA LLC, Pioneer
      Natural Resources Company and Pioneer Natural Resources USA, Inc.
      (incorporated by reference to Exhibit 2.6 to the Partnership's Annual
      Report on Form 10-K for the year ended December 31, 2008, File No.
      001-34032).2.7
            *
            
            —
            Purchase
      And Sale Agreement By And Among Pioneer Natural Resources USA, Inc.,
      Pioneer Southwest Energy Partners USA LLC and the Partnership
      (incorporated by reference to Exhibit 2.1 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on September 3,
      2009).3.1
            
            
            —
            Certificate
      of Limited Partnership of Pioneer Resource Partners L.P. (incorporated by
      reference to Exhibit 3.1 to the Partnership's Registration Statement on
      Form S-1 (File No. 333-144868)).3.2
            
            
            —
            Certificate
      of Amendment to Certificate of Limited Partnership of Pioneer Resource
      Partners L.P. (incorporated by reference to Exhibit 3.2 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).3.3
            
            
            —
            First
      Amended and Restated Agreement of Limited Partnership of Pioneer Southwest
      Energy Partners L.P. dated May 6, 2008, between Pioneer Natural Resources
      GP LLC, as the General Partner, and Pioneer Natural Resources USA, Inc.,
      as the Organizational Limited Partner, together with any other persons who
      become Partners (as defined in such agreement) in the Partnership
      (incorporated by reference to Exhibit 3.1 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on May 9,
      2008).4.1
            
            
            —
            Form
      of Senior Indenture (incorporated by reference to Exhibit 4.1 to the
      Partnership's Registration Statement on Form S-3 (Registration No.
      333-162566)).4.2
            
            
            —
            Form
      of Subordinated Indenture (incorporated by reference to Exhibit 4.2 to the
      Partnership's Registration Statement on Form S-3 (Registration No.
      333-162566)).10.1
            
            H
            —
            Pioneer
      Southwest Energy Partners L.P. 2008 Long Term Incentive Plan (incorporated
      by reference to Exhibit 10.2 to the Partnership's Registration Statement
      on Form S-1 (Registration No.
333-144868)).











10.2
              
              
              —
              Administrative
      Services Agreement, dated May 6, 2008, among the Partnership, Pioneer
      Natural Resources GP LLC, Pioneer Southwest Energy Partners USA LLC, and
      Pioneer Natural Resources USA, Inc. (incorporated by reference to Exhibit
      10.2 to the Partnership's Current Report on Form 8-K, File No. 001-34032,
      filed with the SEC on May 9, 2008).10.3
              
              
              —
              Tax
      Sharing Agreement, dated May 6, 2008, by and between the Partnership
      and Pioneer Natural Resources Company (incorporated by reference to
      Exhibit 10.3 to the Partnership's Current Report on Form 8-K, File No.
      001-34032, filed with the SEC on May 9, 2008).10.4
              
              
              —
              Omnibus
      Operating Agreement, dated May 6, 2008, by and between Pioneer
      Southwest Energy Partners USA LLC and Pioneer Natural Resources USA, Inc.
      (incorporated by reference to Exhibit 10.4 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on May 9,
      2008).10.5
              
              
              —
              First
      Amendment dated August 31, 2009 to Omnibus Operating Agreement dated May
      6, 2008, between Pioneer Natural Resources USA, Inc. and Pioneer Southwest
      Energy Partners USA LLC (incorporated by reference to Exhibit 10.2 to the
      Partnership's Current Report on Form 8-K, File No. 001-34032, filed with
      the SEC on September 3, 2009).10.6
              
              H
              —
              Form
      of Restricted Unit Award Agreement for Initial Grants to Non-Employee
      Directors (incorporated by reference to Exhibit 10.1 to the Partnership's
      Current Report on Form 8-K, File No. 001-34032, filed with the SEC on May
      2, 2008).10.7
              
              H
              —
              Form
      of Restricted Unit Award Agreement for Annual Grants to Non-Employee
      Directors (incorporated by reference to Exhibit 10.2 to the Partnership's
      Current Report on Form 8-K, File No. 001-34032, filed with the SEC on May
      2, 2008).10.8
              
              
              —
              Indemnification
      Agreement between the Partnership and Phillip A. Gobe, together with a
      schedule identifying other substantially identical agreements between the
      Partnership and each non-employee director of the Partnership's general
      partner identified on the schedule and identifying the material
      differences between each of those agreements and the filed Indemnification
      Agreement (incorporated by reference to Exhibit 10.1 to the Partnership's
      Current Report on Form 8-K, File No. 001-34032, filed with the SEC on
      August 19, 2009).10.9
              
              
              —
              Credit
      Agreement entered into as of October 29, 2007, among the Partnership, as
      the Borrower, Bank of America, N.A., as Administrative Agent, and certain
      other lenders (incorporated by reference to Exhibit 10.1 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).10.10
              
              
              —
              Amendment
      to Credit Agreement dated as of December 14, 2007, among the Partnership,
      as the Borrower, Bank of America, N.A., as Administrative Agent, and
      certain other lenders (incorporated by reference to Exhibit 10.8 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).10.11
              
              
              —
              Second
      Amendment to Credit Agreement dated as of February 15, 2008, among the
      Partnership, as the Borrower, Bank of America, N.A., as Administrative
      Agent, and certain other lenders (incorporated by reference to Exhibit
      10.13 to the Partnership's Registration Statement on Form S-1
      (Registration No. 333-144868)).10.12
              
              
              —
              Third
      Amendment to Credit Agreement dated as of April 15, 2008, among the
      Partnership, as the Borrower, Bank of America, N.A., as Administrative
      Agent, and certain other lenders (incorporated by reference to Exhibit
      10.15 to the Partnership's Registration Statement on Form S-1
      (Registration No. 333-144868)).10.13
              
              
              —
              Limited
      Waiver Regarding Credit Agreement, entered into as of March 26, 2009,
      among the Partnership, as the Borrower, Bank of America, N.A., as
      Administrative Agent, and the other lenders signatory thereto
      (incorporated by reference to Exhibit 10.1 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on March 31,
      2009).10.14
              
              
              —
              Crude
      Oil Purchase Contract (incorporated by reference to Exhibit 10.9 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).10.15
              
              
              —
              Natural
      Gas Liquids Purchase Contract  (incorporated by reference to
      Exhibit 10.10 to the Partnership's Registration Statement on Form S-1
      (Registration No. 333-144868)).10.16
              
              
              —
              Crude
      Oil Purchase Contract (incorporated by reference to Exhibit 10.11 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).10.17
              
              
              —
              Crude
      Oil Purchase Contract (incorporated by reference to Exhibit 10.12 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868)).
 
     
 
 10.18
              
              
              —
              Omnibus
      Operating Agreement dated August 31, 2009, between Pioneer Natural
      Resources USA, Inc. and Pioneer Southwest Energy Partners USA LLC
      (incorporated by reference to Exhibit 10.1 to the Partnership's Current
      Report on Form 8-K, File No. 001-34032, filed with the SEC on September 3,
      2009).10.19
              
              (a)
              —
              Amendment
      to Crude Oil Purchase Contract filed as Exhibit 10.9 to the Partnership's
      Registration Statement on Form S-1 (Registration No.
      333-144868).10.20
              
              (a)
              —
              Amendment
      to Natural Gas Liquids Purchase Contract filed as Exhibit 10.10 to the
      Partnership's Registration Statement on Form S-1 (Registration No.
      333-144868).10.21
              
              (a)
              —
              Amendment
      to Crude Oil Purchase Contract filed as Exhibit 10.11 to the Partnership's
      Registration Statement on Form S-1 (Registration No.
      333-144868).10.22
              
              (a)
              —
              Amendment
      to Crude Oil Purchase Contract filed as Exhibit 10.12 to the Partnership's
      Registration Statement on Form S-1 (Registration No.
      333-144868).10.23
              
              (a)
              —
              Crude
      Oil Contracts with Occidental Energy Marketing, Inc.21.1
              
              (a)
              —
              Subsidiaries
      of the registrant.23.1
              
              (a)
              —
              Consent
      of Ernst & Young LLP.23.2
              
              (a)
              —
              Consent
      of Netherland, Sewell & Associates, Inc.31.1
              
              (a)
              —
              Chief
      Executive Officer certification under Section 302 of Sarbanes-Oxley Act of
      2002.31.2
              
              (a)
              —
              Chief
      Financial Officer certification under Section 302 of Sarbanes-Oxley Act of
      2002.32.1
              
              (b)
              —
              Chief
      Executive Officer certification under Section 906 of Sarbanes-Oxley Act of
      2002.32.2
              
              (b)
              —
              Chief
      Financial Officer certification under Section 906 of Sarbanes-Oxley Act of
      2002.99.1
              
              (a)
              —
              Report
      of Netherland, Sewell & Associates, Inc..


_______ ______


(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.