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EX-32.2 - PSE DECEMBER 31, 2010 10-K EXH. 32.2 - Pioneer Southwest Energy Partners L.P.pseexh322.htm
EX-31.1 - PSE DECEMBER 31, 2010 10-K EXH. 31.1 - Pioneer Southwest Energy Partners L.P.pseexh311.htm
EX-23.1 - PSE DECEMBER 31, 2010 10-K EXH. 23.1 - Pioneer Southwest Energy Partners L.P.pseexh231.htm
EX-99.1 - PSE DECEMBER 31, 2010 10-K EXH. 99.1 - Pioneer Southwest Energy Partners L.P.pseexh991.htm
EX-21.1 - PSE DECEMBER 31, 2010 10-K EXH. 21.1 - Pioneer Southwest Energy Partners L.P.pseexh211.htm
EX-23.2 - PSE DECEMBER 31, 2010 10-K EXH. 23.2 - Pioneer Southwest Energy Partners L.P.pseexh232.htm
EX-31.2 - PSE DECEMBER 31, 2010 10-K EXH. 31.2 - Pioneer Southwest Energy Partners L.P.pseexh312.htm
EX-32.1 - PSE DECEMBER 31, 2010 10-K EXH. 32.1 - Pioneer Southwest Energy Partners L.P.pseexh321.htm
EX-10.24 - PSE DECEMBER 31, 2010 10-K EXH. 10.24 - Pioneer Southwest Energy Partners L.P.pseexh1024.htm
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 1934
 
For the fiscal year ended December 31, 2010
or
/  /
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from___to___
Commission file number: 001-34032
Pioneer Southwest Energy Partners L.P.
(Exact name of registrant as specified in its charter)

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) 969-3586
Securities registered pursuant to Section 12(b) of the Act:

Title of each class
Name of each exchange on which registered
Common 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.Yes  o No  ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.Yes  o No  ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  ý No  o

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).  Yes  o No  o

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                     ý
Non 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).  Yes   o    No   ý

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
$305,811,272
Number of common units outstanding as of February 23, 2011                                                                                                                              
33,113,700

DOCUMENTS INCORPORATED BY REFERENCE:

(1)
Portions of the definitive proxy statement for the 2011 Annual Meeting of Shareholders of Pioneer Natural Resources Company to be held during May 2011 as referenced in Part III, Item 11 of this report.
 
 

 
 
 

 
TABLE OF CONTENTS
     
 
 
Page
Cautionary Statement Concerning Forward-Looking Statements                                                                                                                                    
3
Definitions of Certain Terms and Conventions Used Herein                                                                                                                                    
4
   
PART  I
     
Item 1.
Business                                                                                                                      
6
 
General                                                                                                                   
6
 
Presentation                                                                                                                   
6
 
Available Information                                                                                                                   
7
 
Business Strategy                                                                                                                   
7
 
Relationship with Pioneer                                                                                                                   
8
 
Competitive Strengths                                                                                                                   
8
 
Business Activities                                                                                                                   
9
 
Marketing of Production                                                                                                                   
10
 
Competition, Markets and Regulations                                                                                                                   
10
Item 1A.
Risk Factors                                                                                                                      
16
 
Risks Related to the Partnership's Business                                                                                                                   
16
 
Risks Related to an Investment in the Partnership                                                                                                                   
30
 
Tax Risks to Common Unitholders                                                                                                                   
35
Item 1B.
Unresolved Staff Comments                                                                                                                      
37
Item 2.
Properties                                                                                                                      
38
 
Reserve Rule Changes                                                                                                                   
38
 
Reserve Estimation Procedures and Audits                                                                                                                   
38
 
Description of Properties                                                                                                                   
41
 
Selected Oil and Gas Information                                                                                                                   
42
Item 3.
Legal Proceedings                                                                                                                      
44
Item 4.
Removed and Reserved                                                                                                                      
44
     
PART  II
     
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity  Securities
45
 
Cash Distributions to Unitholders                                                                                                                   
45
Item 6.
Selected Financial Data                                                                                                                      
46
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
47
 
Financial and Operating Performance                                                                                                                   
47
 
First Quarter 2011 Outlook                                                                                                                   
47
 
Results of Operations                                                                                                                   
47
 
Capital Commitments, Capital Resources and Liquidity                                                                                                                   
50
 
Critical Accounting Estimates                                                                                                                   
53
 
New Accounting Pronouncements                                                                                                                   
54
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk                                                                                                                      
55
 
Quantitative Disclosures                                                                                                                   
55
 
Qualitative Disclosures                                                                                                                   
57
Item 8.
Financial Statements and Supplementary Data                                                                                                                      
58
 
Index to Consolidated Financial Statements                                                                                                                   
58
 
Report of Independent Registered Public Accounting Firm                                                                                                                   
59
 
Consolidated Financial Statements                                                                                                                   
60
 
Notes to Consolidated Financial Statements                                                                                                                   
66
 
Unaudited Supplementary Information                                                                                                                   
87
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
92
Item 9A.
Controls and Procedures                                                                                                                      
92
 
Management Report on Internal Control Over Financial Reporting                                                                                                                   
92
 
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
93
Item 9B.
Other Information                                                                                                                      
94

 
 
2
 
 

 


PART  III
     
Item 10.
Directors, Executive Officers and Corporate Governance                                                                                                                      
95
 
Directors and Executive Officers of the General Partner                                                                                                                   
95
 
Governance                                                                                                                   
98
 
Meetings and Committees of Directors                                                                                                                   
98
 
Executive Sessions of Non-Management Directors, Procedure for Directly Contacting the Board of Directors and Whistleblower Policy
99
 
Code of Ethics                                                                                                                   
99
 
Availability of Governance Guidelines, Charters and Code                                                                                                                   
99
 
Section 16(a) Beneficial Ownership Reporting Compliance                                                                                                                   
99
Item 11.
Executive Compensation                                                                                                                      
100
 
Compensation of Directors                                                                                                                   
100
 
Compensation of Executive Officers                                                                                                                   
101
 
Narrative Disclosure for the 2010 Grants of Plan-Based Awards Table                                                                                                                   
107
 
Pension Benefits; Nonqualified Deferred Compensation                                                                                                                   
109
 
Potential Payments Upon Termination or Change in Control                                                                                                                   
109
 
Compensation Committee Interlocks and Insider Participation                                                                                                                   
109
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
110
 
Securities Authorized for Issuance under Equity Compensation Plans                                                                                                                   
112
Item 13.
Certain Relationships and Related Transactions, and Director Independence
112
 
Distributions and Payments to the General Partner and Its Affiliates                                                                                                                   
112
 
Administrative Services Agreement                                                                                                                   
113
 
Omnibus Agreement, Omnibus Operating Agreements and Operating Agreements
113
 
Gas Processing Agreements                                                                                                                   
114
 
Tax Sharing Agreement                                                                                                                   
115
 
Policies and Procedures for Review, Approval and Ratification of Related Person Transactions
115
 
Director Independence                                                                                                                   
115
Item 14.
Principal Accounting Fees and Services                                                                                                                      
115
 
Fees Incurred by the Partnership for Services Provided by Ernst & Young LLP
116
 
Audit Committee's Pre-Approval Policy and Procedures                                                                                                                   
116
     
PART  IV
     
Item 15.
Exhibits, Financial Statement Schedules                                                                                                                      
117
Signatures                                                                                                                              
121
Exhibit Index                                                                                                                              
122

****

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
 
This Annual Report on Form 10-K (the "Report") contain forward-looking statements that involve risks and uncertainties. When used in this document, the words "believes," "plans," "expects," "anticipates," "intends," "continue," "may," "will," "could," "should," "future," "potential," "estimate," or the negative of such terms and similar expressions as they relate to Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest" or the "Partnership") are intended to identify forward-looking statements. The forward-looking statements are based on the Partnership's current expectations, assumptions, estimates and projections about the Partnership and the industry in which the Partnership operates. Although the Partnership believes that the expectations and assumptions reflected in the forward-looking statements are reasonable, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Partnership's control.  In addition, the Partnership may be subject to currently unforeseen risks that may have a material adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See "Item 1. Business — Competition, Markets and Regulations," "Item 1A. Risk Factors," "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.
 
3

 
 

 

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 liquids.
·  
"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" are those 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 ("LKH") 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 ("HKO") 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
 
4
 
 
 
 

 
 
·  
evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was 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.

5
 

 
 
 

 
PART I

ITEM 1.                 BUSINESS

General

Pioneer Southwest Energy Partners L.P. (the "Partnership") 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 derivative contracts 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 to herein as the "2009 Acquisition").  See Note B and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the 2009 Acquisition.

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, 2010, Pioneer had approximately 2,248 full time employees, 563 of whom are dedicated to drilling and production activities in 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
 
The 2009 Acquisition and the 2008 IPO Acquisitions represented transactions between entities under common control and are reported in the Partnership's accompanying consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" similar to a pooling of interests.  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." 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.

6
 

 
 

 

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 development drilling of undeveloped properties will allow it to increase cash flow from operations in order to maintain and possibly 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 and completed one well in 2009 and 28 wells in 2010.  The Partnership expects to drill and complete 40 wells to 45 wells in 2011.  The Partnership is drilling and completing its wells in the upper and lower Spraberry, Dean and Wolfcamp formations.

·  
 
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.

·  
 
Purchase oil and gas properties in its area of operations directly from Pioneer. The Partnership believes that Pioneer intends to offer the Partnership over time the opportunity to purchase portions of 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 in the Spraberry field.

·  
Benefit from production and reserve enhancements as a result of infill and horizontal drilling and secondary recovery initiatives being advanced by Pioneer. The Partnership also believes that it benefits from its relationship with Pioneer because the Partnership is able to learn from the various production and proved reserve enhancement initiatives being performed by Pioneer.  For instance, Pioneer has (i) drilled 20-acre infill locations during the past three years with encouraging results, (ii) initiated a 7,000 acre waterflood project during 2010 with an initial production response expected during the first half of 2011 and (iii) commenced drilling on two horizontal wells during the fourth quarter of 2010. 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

 
7
 
 
 

 
 
  
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 – Capital Commitments, Capital Resources and Liquidity" 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 percent 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, 2010, including the Partnership's properties, were 1,011 MMBOE, of which 549 MMBOE, or 54 percent, were in the Spraberry field. Of the 549 MMBOE of proved reserves in the Spraberry field, 255 MMBOE were proved developed reserves (46 percent) and 294 MMBOE were proved undeveloped reserves (54 percent). These proved undeveloped reserves represent approximately 3,885 future drilling locations held by Pioneer in the Spraberry field.
 
Pioneer views the Partnership as an integral part of its asset portfolio and expects to offer the Partnership over time the opportunity to purchase from Pioneer portions of its 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.

 
 
 
8
 
 

 

Business Activities

Petroleum industry.  For several years preceding 2008, the petroleum industry was generally characterized by volatile, but upward trending oil, NGL and gas commodity prices. During the first half of 2008, North American gas prices increased as a result of reduced inventory levels, a perceived shortage of North American gas supply and anticipation that the United States would become a larger importer of LNG, which was then selling in the world market at a substantial premium to United States gas prices. However, by mid-year 2008, it became apparent that capital investments in gas drilling and discoveries of significant gas reserves in United States shale plays would cause domestic gas supply to exceed existing United States gas demand.  Beginning in the second half of 2008 and continuing throughout most of 2009, the United States and other industrialized countries experienced a significant economic slowdown, which led to a substantial decline in worldwide energy demand. Declining energy demand due to the economic slowdown, together with the increased supply of United States gas resulted in sharp declines in oil, NGL and North American gas prices during the second half of 2008 and first half of 2009.

During the second half of 2009 and throughout 2010, economic stimulus initiatives implemented in the United States and worldwide served to stabilize economies and increase industry and consumer confidence.  While oil and NGL prices have steadily improved since the beginning of the second quarter of 2009, gas prices have remained volatile throughout 2009 and 2010 as a result of increased gas supply and growing storage levels in the United States, which has offset the growth in demand.  The outlook for continuation of the worldwide economic recovery in 2011 is cautiously optimistic but remains uncertain; therefore, the sustainability of the recovery in worldwide demand for energy is difficult to predict.  As a result, the Partnership believes it is likely that commodity prices, especially North American gas prices, will continue to be volatile during 2011.

Significant factors that will impact 2011 commodity prices include: the ongoing impact of economic stimulus initiatives in the United States and worldwide in response to the worldwide economic decline; political and economic developments in North Africa and the Middle East; 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.

The Partnership uses commodity derivative contracts to mitigate the impact of commodity price volatility on the Partnership's net cash provided by operating activities Although the Partnership has entered into derivative contracts on a large portion of its forecasted production 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.  A sustained decline in commodity prices could result in a shortfall in expected cash flows, which could negatively impact the Partnership's liquidity, financial position, future results of operations and ability to sustain or increase distributions to unitholders.  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 2010 and 2009 from the Partnership's derivative price risk management activities and the Partnership's open derivative positions at December 31, 2010.
 
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 1,116 producing wells. The Partnership's interest in 1,021 of these wells is limited to only those rights that are necessary to produce hydrocarbons from those particular wellbores, 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 of 2009 to begin developing the undeveloped properties.  See "Item 2. Properties – Description of Properties." According to the latest information available from 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, the Partnership believes that Pioneer intends to offer to the Partnership over time the opportunity to purchase portions of Pioneer's producing and undeveloped 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 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
 
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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, 2010, the Partnership's average daily production, on a BOE basis was 6,507. Production, price and cost information with respect to the Partnership's properties for 2010, 2009 and 2008 is set forth under "Item 2. Properties — Selected Oil and Gas Information — Production, price and cost data."  During the three years ended December 31, 2010, the Partnership drilled 38 gross (37 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 operations, 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 two years. Sales prices for oil, NGL and gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, 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 2010, the Partnership's significant purchasers were Plains Marketing LP (53 percent), Occidental Energy Marketing (17 percent) and Enterprise Crude Oil LLC (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 contracts, collar contracts and collar contracts with short puts 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. Effective February 1, 2009, the Partnership discontinued hedge accounting on all of its then-existing hedge contracts and began accounting for its derivative contracts using the mark-to-market ("MTM") method of accounting.  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 about the impact of commodity derivative activities on oil, NGL and gas revenues and net derivative losses during 2010, 2009 and 2008 and the Partnership's open commodity derivative positions at December 31, 2010.

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
 
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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 could 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.
 
 
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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, Congress has considered legislation that would repeal an exemption in the SDWA for the underground injection of hydraulic fracturing fluids near drinking water sources. Sponsors of the legislation have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies.  If enacted, the legislation could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements.  The legislation also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then 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.  The Subcommittee on Energy and Environment of the U.S. House of Representatives is examining the practice of hydraulic fracturing in the United States and is gathering information on its potential effects on human health and the environment.  The EPA also has commenced a study of the potential adverse effects that hydraulic fracturing
 
 
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may have on water quality and public health.  In addition, various state and local governments have implemented or are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, requirements for disclosure of chemical constituents, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds.

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.

In addition, the Texas Commission on Environmental Quality ("TCEQ") recently adopted new air emissions limitations and permitting requirements for oil and gas facilities in the state, which will first become applicable to facilities located in the Barnett Shale area on April 1, 2011.   The TCEQ expects to expand the application of these requirements to facilities in other areas of the state in early 2012.  These new requirements could increase the cost and time associated with drilling wells.  Any adoption of laws, regulations, orders or other legally enforceable mandates governing drilling and operating activities that result in more stringent drilling or operating conditions or limit or prohibit the drilling of new wells for any extended period of time could increase the Partnership's costs and/or reduce its production, which could have a material adverse effect on the Partnership's results of operations and cash flows.

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. In December 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 welfare 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. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA.  The EPA recently adopted two sets of rules, which became effective January 2, 2011, that regulate greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources.  The EPA has also adopted rules requiring the reporting on an annual basis beginning in 2011 of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, for emissions occurring after January 1, 2010, as well as certain oil and gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of
 
 
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GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.  Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Partnership to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and gas, which could reduce the demand for the oil and gas the Partnership produces.  Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Partnership's business, financial condition and results of operations. 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 financial condition and results of 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, 2010. Additionally, the Partnership is not aware of any environmental issues or claims that will require material capital expenditures during 2011. 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 federal and state departments and agencies 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 various drilling and operating costs, 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 method and ability to fracture stimulate 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
 
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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 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 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.
 
Transportation of hazardous materials.  The federal Department of Transportation has adopted regulations requiring that certain entities transporting designated hazardous materials develop plans to address security risks related to the transportation of hazardous materials.  The Partnership does not believe that these requirements will have an adverse effect on the Partnership or its operations.  The Partnership cannot provide any assurance that the security plans required under these regulations would protect against all security risks and prevent an attack or other incident related to the Partnership's transportation of hazardous materials.
 
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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 economically replace proved 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.

 
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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 – Capital Commitments, Capital Resources and Liquidity" 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, NGLs 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 worldwide supply of and demand for oil, NGL and gas;
·  inventory levels at Cushing, Oklahoma, the benchmark for West Texas Intermediate ("WTI") oil prices;
·  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 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, 2010, the NYMEX oil price ranged from a high of $91.51 per Bbl to a low of $68.01 per Bbl, while the NYMEX Henry Hub gas price ranged from a high of $6.01 per MMBtu to a low of $3.29 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.
 
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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 only 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.
 
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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.
 
 
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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, 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. Since the Partnership's decision to discontinue hedge accounting effective February 1, 2009, these derivative arrangements have been subject to mark-to-market accounting treatment, and the changes in fair market value of the arrangements are being 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 30 percent, 20 percent, 40 percent and 75 percent of the Partnership's estimated total production for 2011, 2012, 2013 and 2014, 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 percent to 85 percent of expected production for a period of up to five years. In addition, the Partnership's credit facility requires it to enter into derivative contracts for 50 percent or more of its oil, NGL and gas production attributable to proved developed producing reserves through December 31, 2012. 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, 2010. 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.
 
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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 70 percent, 80 percent, 60 percent and 25 percent of the Partnership's estimated total production for 2011, 2012, 2013 and 2014, 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 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.

 
 
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Because all proved reserve estimates are to some degree subjective, each of the following items could differ materially from those assumed in estimating proved 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 proved reserves and cash flows based on the same available data. The Partnership's actual production, revenues and expenditures with respect to proved 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 of, or shortages or delays in the delivery of, drilling rigs, 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;
 
 
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·  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.

The Partnership's expectations 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, drilling and production costs, access to and availability of equipment, services and personnel, 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.
 
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 and the results of future drilling activity.  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. Risk Factors" occur, such as facility or equipment malfunctions, adverse weather effects, or downturns in commodity prices or significant increases in costs, which could make certain drilling activities or 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.
 
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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, 2010, purchases by Plains Marketing, L.P., Occidental Energy Marketing and Enterprise Crude Oil LLC represented approximately 53 percent, 17 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 Enterprise Crude Oil LLC 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 Enterprise Crude Oil LLC.  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 Enterprise Crude Oil LLC 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. expired on January 1, 2011; however, the contract will continue to automatically extend 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 Enterprise Crude Oil LLC 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.
 
During the second half of 2008 and during most of 2009, 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.
 
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Declining general economic, business or industry conditions could have a material adverse affect on the Partnership's results of operations.
 
During 2008 and the first half of 2009, concerns over worldwide economic outlook, geopolitical issues, the availability and cost of credit, and the United States mortgage and real estate markets contributed to increased volatility and diminished expectations for the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment, resulted in a worldwide recession. While the worldwide economic outlook has improved, concerns about global economic growth could have a significant adverse effect on global financial markets and commodity prices.  If the economic climate in the United States or abroad were to deteriorate, demand for petroleum products could diminish, which could 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;
 
 
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·  
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
 
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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.
 
In an environment of rising commodities prices, demand for drilling rigs, supplies, oilfield services, equipment and crews generally increases, which could delay the Partnership's operations, lead to increased costs and reduce its cash available for distribution, which could be exacerbated if the Partnership's derivatives limit the ability of the Partnership to benefit from higher commodities prices.
 
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 past year, oil and gas companies generally experienced increasing drilling and operating costs due to increasing oil and NGL prices.  Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict the Partnership's ability to drill and complete wells and conduct operations. Any delay in the drilling of new wells or significant increase in costs could reduce its future revenues and cash available for distribution.  In addition, if the Partnership's derivatives limit the Partnership's ability to realize the benefit of higher commodities prices, the Partnership could experience higher costs without a commensurate increase in cash flows.
 
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
   
·  access to, and the cost and availability of, the equipment, services and personnel required to complete the Partnership's drilling, completion
       and operating activities.
 
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
 
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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 recent adoption of climate change legislation by the United States Congress or regulation by the EPA could result in increased operating costs and reduced demand for the oil, NGLs and gas the Partnership produces.

During December 2009, the EPA officially published its findings that emissions of GHGs present an endangerment to human health and welfare 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 federal CAA.  Based on these findings, the EPA has begun adopting and implementing regulations
 
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to restrict emissions of GHGs under existing provisions of the CAA.  The EPA recently adopted two sets of rules, which became effective January 2, 2011, that regulate greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources.  The EPA has also adopted rules requiring the reporting on an annual basis beginning in 2011of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, for emissions occurring after January 1, 2010, as well as certain oil and gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.  Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.
 
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Partnership to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas, which could reduce the demand for the oil and gas the Partnership produces.  Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Partnership's business, financial condition and results of operations. 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 financial condition and results of operations. See "Item 1. Business — Competition, Markets and Regulations" above for additional discussion regarding government regulation.
 
The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Partnership's ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.
 
The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership, that participate in that market.  The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"),  was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the "CFTC") and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment.  In its rulemaking under the Dodd-Frank Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents.  Certain bona fide hedging transactions or positions would be exempt from these position limits.  It is not possible at this time to predict when the CFTC will finalize these regulations.  The financial reform legislation may also require the Partnership to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to the Partnership is uncertain at this time.  The financial reform legislation may also require the counterparties to the Partnership's derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.  The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect the Partnership's available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Partnership encounters, reduce the Partnership's ability to monetize or restructure its existing derivative contracts, and increase the Partnership's exposure to less creditworthy counterparties.  If the Partnership reduces its use of derivatives as a result of the legislation and regulations, the Partnership's results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Partnership's ability to plan for and fund capital expenditures or make distributions to unitholders.  Finally, the legislation was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas.  The Partnership's revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.  Any of these consequences could have a material adverse effect on the Partnership, its financial condition, its results of operations and its ability to make distributions to unitholders.
 
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Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
 
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations.  The Partnership routinely utilizes hydraulic fracturing techniques in many of its drilling and completion programs.  The process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and gas production.  The process is typically regulated by state oil and gas commissions.  The EPA, however, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act's Underground Injection Control Program.  While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA's recent decision.  At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices.  Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.  In addition, various state and local governments have implemented or are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, requirements for disclosure of chemical constituents, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds.  If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for the Partnership to perform fracturing to stimulate production from tight formations.  In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, the Partnership’s fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs.  Restrictions on hydraulic fracturing could also reduce the amount of oil and gas that the Partnership is ultimately able to produce from its reserves.

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 62 percent of the outstanding common units of 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.
 
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·  
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.
 
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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;
 
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·  
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.  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
 
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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, representing 62 percent of the outstanding 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.
 
34
 
 
 

 

 
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.
 
 
35

 
 
 

 

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
 
36
 
 
 

 
 
 
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.

In recent years, there have been tax legislation discussions 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. Such tax legislation 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.  It is unclear whether any of these or similar changes will be proposed in the future and, if enacted, how soon any such changes could become effective. The passage of any future legislation 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.

These risks are not the only risks facing the Partnership.  Additional risks and uncertainties not currently known to the Partnership or that it currently deems to be immaterial also may materially adversely affect the Partnership's business, financial condition or future results.

ITEM 1B.
UNRESOLVED STAFF COMMENTS

None.
 
 
 
37
 

 
 
 

 

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 became 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, 2010, 2009 and 2008 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, 2010 and 2009; and audited the Partnership's proved reserves as of December 31, 2008 before the Partnership completed the 2009 Acquisition.  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.  Annually, 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 periodically attend training on the Reserve Ruling by external consultants and/or through internal Pioneer programs.  Additionally, the WWR has prepared and maintains an internal document for the Asset Team 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.  
 
38
 
 
 

 
 
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 accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the SPE.
·  
 
The estimation of 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 their 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 accepting 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 and associated pre-tax future net revenues discounted at ten percent are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering standards promulgated by the SPE.
 
Also, see "Item 1A. Risk Factors," "Critical Accounting Estimates" in "Item 7. Management's Discussion and Analysis and Results of Operations" and "Item 8. Financial Statements and Supplementary Data" for additional discussions regarding proved reserves and their related cash flows.

Qualifications of reserves 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 directors of the Society of Petroleum Engineers in 2001 and revised in 2007.  The WWR Director's qualifications include 33 years of experience as a petroleum engineer, with 26 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") and a member of the Oil and Gas Reserves Committee of the SPE.   
 
39
 
 
 
 

 
 
      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 31 years of practical experience in petroleum engineering, including 30 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 board of directors of the SPE.
 
Technologies used in reserves estimates. Pioneer uses reliable technologies to establish additions to reserve estimates on behalf of the Partnership, including seismic data and interpretation, wireline formation tests, geophysical logs and core data.  Reserve additions associated with reliable technologies were less than two percent of the Partnership's total proved reserves during the year ended December 31, 2010.
 
Proved reserves. The Partnership's proved reserves totaled 51,975 MBOE, 44,365 MBOE and 40,805 MBOE at December 31, 2010, 2009 and 2008, respectively, representing $563.8 million, $262.3 million and $187.2 million, respectively, of Standardized Measure. Changes in the Partnership's proved reserve volumes during the year ended December 31, 2010 included production of 2,375 MBOE and positive revisions of previous estimates of 9,985 MBOE.  Revisions of previous estimates are comprised of 4,388 MBOE of positive price revisions and 5,597 MBOE of positive performance-related revisions.  The Partnership's proved reserves at December 31, 2010 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 2010.  On this basis, the price of oil and gas for proved reserve reporting purposes at December 31, 2010 was $79.28 per barrel of oil and $4.37 per Mcf of gas, compared to comparable average NYMEX prices of $61.14 per barrel of oil and $3.87 per Mcf of gas at December 31, 2009.
 
Tabular proved reserves disclosures.  On a BOE basis, 77 percent of the Partnership's total proved reserves at December 31, 2010 were proved developed reserves. The following table provides information regarding the Partnership's proved reserves and Standardized Measure as of December 31, 2010:

 
 
Summary of Oil and Gas Reserves as of December 31, 2010
 
 
Based on Average Fiscal Year Prices
 
 
 
 
 
 
 
 
 
 
 
Standardized
 
 
Oil
 
NGLs
 
Gas
 
 
 
 
Measure
 
 
(MBbls)
 
(MBbls)
 
(MMcf)
 
MBOE
 
 
(in thousands)
Proved
 
 
 
 
 
 
 
 
 
 
 
Developed
 23,682 
 
 9,966 
 
 39,032 
 
 40,153 
 
$
 502,133 
 
Undeveloped
 7,515 
 
 2,546 
 
 10,567 
 
 11,822 
 
 
 61,633 
Total proved
 31,197 
 
 12,512 
 
 49,599 
 
 51,975 
 
$
 563,766 
 
Proved undeveloped reserves.  As of December 31, 2010, the Partnership had 127 proved undeveloped well locations (all of which are expected to be developed within the five year period ending December 31, 2015), representing a decrease of 43 proved undeveloped well locations (25 percent) since December 31, 2009.  The Partnership's proved undeveloped reserves totaled 11,822 MBOE and 12,152 MBOE at December 31, 2010 and 2009, respectively.  During 2010, 28 proved undeveloped well locations were drilled and completed as developed wells and an additional 18 proved undeveloped well locations were in various stages of drilling and completion at December 31, 2010.  As a result, the Partnership converted 2,913 MBOE of proved undeveloped reserves to proved developed reserves during 2010.  The Partnership's development costs incurred during the year ended December 31, 2010 totaled $52.5 million and were comprised of $46.7 million of development drilling expenditures associated with new wells and a $5.8 million increase in asset retirement obligations.  The Partnership's proved undeveloped well locations as of December 31, 2010 included 48 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.  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, 2010 (dollars in thousands):
 
40
 
 
 

 

 
 
 
Estimated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Future
 
Future
 
Future
 
Future
 
 
 
 
 
 
Production
 
Cash
 
Production
 
Development
 
Future Net
Year Ended December 31, (a)
 
(MBOE)
 
Inflows
 
Costs
 
Costs
 
Cash Flows
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2011 
 
 250 
 
$
 16,098 
 
$
 2,180 
 
$
 61,351 
 
$
 (47,433)
2012 
 
 702 
 
 
 44,650 
 
 
 6,576 
 
 
 67,530 
 
 
 (29,456)
2013 
 
 942 
 
 
 58,909 
 
 
 9,245 
 
 
 57,689 
 
 
 (8,025)
2014 
 
 873 
 
 
 53,806 
 
 
 9,327 
 
 
 3,219 
 
 
 41,260 
2015 
 
 668 
 
 
 40,322 
 
 
 7,640 
 
 
 - 
 
 
 32,682 
Thereafter
 
 8,387 
 
 
 502,451 
 
 
 188,807 
 
 
 6,573 
 
 
 307,071 
 
 
 11,822 
 
$
 716,236 
 
$
 223,775 
 
$
 196,362 
 
$
 296,099 
______
(a)
Beginning in 2011 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. The Partnership's interests include 1,116 producing wells, of which 1,021 wells are limited to only those rights that are necessary to produce hydrocarbons from that particular wellbore, and do not include the right to drill additional wells (other than replacement wells or downspaced wells, such as 20-acre infill wells) within the area covered by the mineral or leasehold interest to which that wellbore relates.
 
All of the Partnership's proved reserves at December 31, 2010 were located in the Spraberry field. According to latest information available from 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 four formations, the upper and lower Spraberry,  the Dean and the Wolfcamp, at depths ranging from 6,700 feet to 11,300 feet.
 
The Partnership added 28 new wells to production during 2010 and had 18 wells awaiting completion at December 31, 2010.  The Partnership added one new well to production during 2009 and had seven wells awaiting completion at December 31, 2009.  The performance to date of these drilled and completed wells has exceeded the expectations of the Partnership's management, in part due to the completion of these wells in the deeper Wolfcamp formation and organic rich shale/silt intervals.

41
 

 
 
 

 

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, 2010, 2009 and 2008. 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, 2010, 2009 and 2008. 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,
 
 
2010 
 
2009 
 
2008 
Production information:
 
 
 
 
 
 
 
 
 
  Annual sales volumes:
 
 
 
 
 
 
 
 
 
    Oil (MBbls)
 
 
1,425 
 
 
1,344 
 
 
1,441 
    NGLs (MBbls)
 
 
 587 
 
 
 518 
 
 
 476 
    Gas (MMcf)
 
 
2,181 
 
 
2,281 
 
 
2,133 
    Total (MBOE)
 
 
2,375 
 
 
2,243 
 
 
2,272 
  Average daily sales volumes:
 
 
 
 
 
 
 
 
 
    Oil (Bbls)
 
 
3,903 
 
 
3,683 
 
 
3,937 
    NGLs (Bbls)
 
 
1,608 
 
 
1,420 
 
 
1,298 
    Gas (Mcf)
 
 
5,975 
 
 
6,248 
 
 
5,828 
    Total (BOE)
 
 
6,507 
 
 
6,145 
 
 
6,206 
  Average prices, including hedge results (a):
 
 
 
 
 
 
 
 
 
    Oil (per Bbl)
 
$
 103.60 
 
$
 100.35 
 
$
 107.79 
    NGL (per Bbl)
 
$
 44.31 
 
$
 41.61 
 
$
 48.41 
    Gas (per Mcf)
 
$
 4.66 
 
$
 5.37 
 
$
 7.06 
    Revenue (per BOE)
 
$
 77.37 
 
$
 75.23 
 
$
 85.14 
  Average prices, excluding hedge results (a):
 
 
 
 
 
 
 
 
 
    Oil (per Bbl)
 
$
 77.56 
 
$
 58.05 
 
$
 99.71 
    NGL (per Bbl)
 
$
 32.91 
 
$
 25.56 
 
$
 45.84 
    Gas (per Mcf)
 
$
 3.33 
 
$
 2.81 
 
$
 6.24 
    Revenue (per BOE)
 
$
 57.72 
 
$
 43.56 
 
$
 78.69 
Average costs (per BOE):
 
 
 
 
 
 
 
 
 
  Production costs:
 
 
 
 
 
 
 
 
 
    Lease operating (b)
 
$
 14.24 
 
$
 14.04 
 
$
 14.24 
    Workover
 
 
 1.90 
 
 
 1.46 
 
 
2.85 
      Total production costs
 
$
 16.14 
 
$
 15.50 
 
$
 17.09 
  Production taxes:
 
 
 
 
 
 
 
 
 
    Ad valorem
 
$
 2.15 
 
$
 2.09 
 
$
2.23 
    Production
 
 
 2.96 
 
 
 2.17 
 
 
4.02 
      Total production taxes
 
$
 5.11 
 
$
 4.26 
 
$
 6.25 
  Depletion expense
 
$
5.30 
 
$
5.80 
 
$
5.10 
______
(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 and $1.03 for 2009 and 2008, respectively.

 
42

 
 
 

 

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, 2010, 2009 and 2008:

PRODUCTIVE WELLS (a)

 
 
Gross Productive Wells
 
Net Productive Wells
 
 
Oil
 
Gas
 
Total
 
Oil
 
Gas
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2010
 
 1,116 
 
 - 
 
 1,116 
 
 985 
 
 - 
 
 985 
As of December 31, 2009
 
 1,135 
 
 - 
 
 1,135 
 
 981 
 
 - 
 
 981 
As of December 31, 2008
 
 1,158 
 
 - 
 
 1,158 
 
 1,003 
 
 - 
 
 1,003 
______
(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, 2010.

Leasehold acreage. The following table sets forth information about the Partnership's developed and undeveloped leasehold acreage as of December 31, 2010:

 
 
Developed Acreage
 
Undeveloped Acreage
 
 
Gross Acres
 
Net Acres
 
Gross Acres
 
Net Acres
 
 
 
 
 
 
 
 
 
Spraberry field
 
9,243 
 
8,736 
 
5,628 
 
5,333 

The following table sets forth the expiration dates of the leases on the Partnership's gross and net undeveloped acres as of December 31, 2010:

 
 
Acres Expiring (a)
 
 
Gross
 
Net
2011 
 
 1,506 
 
 1,485 
______
(a)
The Partnership's undeveloped acreage represents proved undeveloped acreage held by productive wells except for 1,506 acres (1,485 net acres) that are subject to a continuous drilling commitment.  The continuous drilling commitment obligates Pioneer and the Partnership to spud a well by April 22, 2011, 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 by the Partnership during 2010, 2009 and 2008. This information should not be considered indicative of future performance.

 
DRILLING ACTIVITIES

 
 
 
Gross Wells
 
Net Wells
 
 
 
Year Ended December 31,
 
Year Ended December 31,
 
 
 
2010 
 
2009 
 
2008 
 
2010 
 
2009 
 
2008 
Productive wells: (a)
 
 
 
 
 
 
 
 
 
 
 
 
 
Development
 
 28 
 
 1 
 
 9 
 
 27 
 
 1 
 
 9 
 
Exploratory
 
 - 
 
 - 
 
 - 
 
 - 
 
 - 
 
 - 
Dry holes:
 
 
 
 
 
 
 
 
 
 
 
 
 
Development
 
 - 
 
 - 
 
 - 
 
 - 
 
 - 
 
 - 
 
Exploratory
 
 - 
 
 - 
 
 - 
 
 - 
 
 - 
 
 - 
Total
 
 28 
 
 1 
 
 9 
 
 27 
 
 1 
 
 9 
______
(a)
As of December 31, 2010, drilling on 18 gross wells (18 net wells) was in progress.  The Partnership had seven gross wells (seven net wells) upon which drilling was in progress as of December 31, 2009 and no wells upon which drilling was in progress as of December 31, 2008.
 
 
43

 
 

 

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.                 REMOVED AND RESERVED

 
 
 
44

 
 

 

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 2010.  On January 24, 2011, the Board of Directors of the General Partner declared a $0.50 per unit distribution payable on February 11, 2011 to unitholders of record on February 3, 2011.
 
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, 2010 and 2009:

 
 
 
 
 
 
 
 
Dividends
 
 
 
 
 
 
 
 
Declared
 
 
High
 
Low
 
Per Unit
Year ended December 31, 2010
 
 
 
 
 
 
 
 
 
Fourth quarter
$
 30.42 
 
$
 27.15 
 
$
 0.50 
 
Third quarter
$
 28.33 
 
$
 23.53 
 
$
 0.50 
 
Second quarter
$
 25.65 
 
$
 20.93 
 
$
 0.50 
 
First quarter
$
 23.87 
 
$
 20.72 
 
$
 0.50 
 
 
 
 
 
 
 
 
 
 
Year ended December 31, 2009
 
 
 
 
 
 
 
 
 
Fourth quarter
$
 22.67 
 
$
 18.51 
 
$
 0.50 
 
Third quarter
$
 21.25 
 
$
 17.03 
 
$
 0.50 
 
Second quarter
$
 20.03 
 
$
 15.50 
 
$
 0.50 
 
First quarter
$
 17.60 
 
$
 13.01 
 
$
 0.50 

On February 23, 2011, the last reported sales price of the Partnership's common units, as reported in the NYSE composite transactions, was $32.93 per unit.
 
As of February 23, 2011, the Partnership's common units were held by 16 holders of record. This number does not include owners for whom common units may be held in "street" name.

During the fourth quarter of 2010, the Partnership did not repurchase any common units nor did the Partnership make any unregistered sales of 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.
 
45
 

 
 
 

 

ITEM 6.                 SELECTED FINANCIAL DATA

 
The following selected financial data as of and for the five years ended December 31, 2010 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,
 
 
 
2010 
 
2009 
 
2008 
 
2007 
 
2006 
Statements of Operations Data:
(in thousands, except per unit data)
 
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil and gas
$
 183,758 
 
$
 168,717 
 
$
 193,394 
 
$
 144,038 
 
$
 126,918 
 
 
Interest and other
 
 - 
 
 
 210 
 
 
 192 
 
 
 - 
 
 
 - 
 
 
 
 
 183,758 
 
 
 168,927 
 
 
 193,586 
 
 
 144,038 
 
 
 126,918 
 
Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil and gas production  (a)
 
 38,334 
 
 
 34,749 
 
 
 38,807 
 
 
 27,879 
 
 
 24,133 
 
 
Production and ad valorem taxes
 
 12,119 
 
 
 9,547 
 
 
 14,213 
 
 
 11,550 
 
 
 11,124 
 
 
Depletion, depreciation and amortization
 
 12,577 
 
 
 13,016 
 
 
 11,582 
 
 
 11,382 
 
 
 9,678 
 
 
General and administrative
 
 6,330 
 
 
 4,790 
 
 
 6,227 
 
 
 5,643 
 
 
 5,345 
 
 
Accretion of discount on asset retirement obligations
 
 546 
 
 
 484 
 
 
 144 
 
 
 143 
 
 
 136 
 
 
Interest
 
 1,543 
 
 
 1,160 
 
 
 621 
 
 
 - 
 
 
 - 
 
 
Derivative losses, net (b)
 
 5,431 
 
 
 78,265 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Other, net
 
 - 
 
 
 549 
 
 
 890 
 
 
 5 
 
 
 25 
 
 
 
 
 76,880 
 
 
 142,560 
 
 
 72,484 
 
 
 56,602 
 
 
 50,441 
 
Income before taxes
 
 106,878 
 
 
 26,367 
 
 
 121,102 
 
 
 87,436 
 
 
 76,477 
 
Income tax provision
 
 (1,045)
 
 
 (46)
 
 
 (1,326)
 
 
 (920)
 
 
 (323)
 
Net income
$
 105,833 
 
$
 26,321 
 
$
 119,776 
 
$
 86,516 
 
$
 76,154 
 
Allocation of net income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss) applicable to the Partnership Predecessor
$
 - 
 
$
 (1,598)
 
$
 59,038 
 
$
 86,516 
 
$
 76,154 
 
 
Net income applicable to the Partnership
 
 105,833 
 
 
 27,919 
 
 
 60,738 
 
 
 - 
 
 
 - 
 
 
Net income
$
 105,833 
 
$
 26,321 
 
$
 119,776 
 
$
 86,516 
 
$
 76,154 
 
Allocation of net income applicable to the Partnership:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
General partner's interest in net income
$
 106 
 
$
 28 
 
$
 61 
 
 
 
 
 
 
 
 
Limited partners' interest in net income
 
 105,649 
 
 
 27,891 
 
 
 60,677 
 
 
 
 
 
 
 
 
Unvested participating securities' interest in net income
 
 78 
 
 
 - 
 
 
 - 
 
 
 
 
 
 
 
 
Net income applicable to the Partnership
$
 105,833 
 
$
 27,919 
 
$
 60,738 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income per common unit – basic and diluted
$
 3.19 
 
$
 0.92 
 
$
 2.02 
 
 
 
 
 
 
 
Weighted average common units outstanding – basic and diluted
 
33,114 
 
 
30,399 
 
 
30,009 
 
 
 
 
 
 
 
Distributions declared per common unit
$
2.00 
 
$
2.00 
 
$
0.81 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (as of December 31):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total assets
$
 280,060 
 
$
 256,638 
 
$
 367,164 
 
$
 217,702 
 
$
 209,687 
 
Long-term debt
$
 81,200 
 
$
 67,000 
 
$
 - 
 
$
 - 
 
$
 - 
 
Partners' equity
$
 134,745 
 
$
 141,273 
 
$
 347,831 
 
$
 207,569 
 
$
 196,498 
________
(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)
Effective February 1, 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.
 
 
 
46
 
 

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

Financial and Operating Performance

Highlights of the Partnership's financial and operating performance for 2010 include:

·