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10-K
PIONEER SOUTHWEST ENERGY PARTNERS L.P. filed this Form 10-K on 02/29/2012
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Form 10-K
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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, 2011

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   ¨    No   x

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  ¨    No  x

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  x    No  ¨

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  x    No  ¨

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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   ¨    Accelerated filer   x
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes   ¨    No  x

 

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    $ 350,504,520   

Number of common units outstanding as of February 28, 2012

     35,713,700   

 

(1) Portions of the definitive proxy statement for the 2012 Annual Meeting of Shareholders of Pioneer Natural Resources Company to be held during May 2012 as referenced in Part III, Item 11 of this report.

 

 

 


Table of Contents

DOCUMENTS INCORPORATED BY REFERENCE:

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

   6
  

Business Strategy

   7
  

Relationship with Pioneer

   8
  

Competitive Strengths

   8
  

Business Activities

   8
  

Marketing of Production

   10
  

Competition, Markets and Regulations

   10
Item 1A.    Risk Factors    17
  

Risks Related to the Partnership’s Business

   17
  

Risks Related to an Investment in the Partnership

   32
  

Tax Risks to Common Unitholders

   37
Item 1B.    Unresolved Staff Comments    40
Item 2.    Properties    41
  

Reserve Rule Changes

   41
  

Reserve Estimation Procedures and Audits

   41
  

Description of Properties

   45
  

Selected Oil and Gas Information

   45
Item 3.    Legal Proceedings    48
Item 4.    Mine Safety Disclosures    48
PART II   
Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities    49
  

Cash Distributions to Unitholders

   49
Item 6.    Selected Financial Data    50
Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations    51
  

Financial and Operating Performance

   51
  

First Quarter 2012 Outlook

   51
  

Results of Operations

   52
  

Capital Commitments, Capital Resources and Liquidity

   55
  

Critical Accounting Estimates

   57
  

New Accounting Pronouncements

   59
Item 7A.    Quantitative and Qualitative Disclosures About Market Risk    59
  

Quantitative Disclosures

   60
  

Qualitative Disclosures

   62
Item 8.    Financial Statements and Supplementary Data    63
  

Index to Consolidated Financial Statements

   63
  

Report of Independent Registered Public Accounting Firm

   64
  

Consolidated Financial Statements

   65
  

Notes to Consolidated Financial Statements

   70
  

Unaudited Supplementary Information

   90
Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure    95
Item 9A.    Controls and Procedures    95
  

Management’s Report on Internal Control Over Financial Reporting

   95
  

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

   96
Item 9B.    Other Information    97

 

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PART III

Item 10.

   Directors, Executive Officers and Corporate Governance    98
  

Directors and Executive Officers of the General Partner

   98
  

Governance

   101
  

Meetings and Committees of Directors

   101
  

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

   102
  

Code of Ethics

   102
  

Availability of Governance Guidelines, Charters and Code

   102
  

Section 16(a) Beneficial Ownership Reporting Compliance

   102

Item 11.

   Executive Compensation    103
  

Compensation of Directors

   103
  

Compensation of Executive Officers

   104
  

Narrative Disclosure for the 2011 Grants of Plan-Based Awards Table

   110
  

Pension Benefits; Nonqualified Deferred Compensation

   112
  

Potential Payments Upon Termination or Change in Control

   112
  

Compensation Committee Interlocks and Insider Participation

   112

Item 12.

   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters    113
  

Securities Authorized for Issuance under Equity Compensation Plans

   114

Item 13.    

   Certain Relationships and Related Transactions, and Director Independence    115
  

Distributions and Payments to the General Partner and Its Affiliates

   115
  

Administrative Services Agreement

   116
  

Omnibus Agreement, Omnibus Operating Agreements and Operating Agreements

   116
  

Gas Processing Arrangements

   117
  

Tax Sharing Agreement

   117
  

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

   117
  

Director Independence

   117

Item 14.

   Principal Accounting Fees and Services    117
  

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

   118
  

Audit Committee’s Pre-Approval Policy and Procedures

   118
PART IV   

Item 15.

   Exhibits, Financial Statement Schedules    119

Signatures

   123

Exhibit Index

   124

****

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (the “Report”) contains forward-looking statements that involve risks and uncertainties. When used in this document, the words “believes,” “plans,” “expects,” “anticipates,” “forecasts,” “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.

 

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Definitions of Certain Terms and Conventions Used Herein

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

 

 

“ASC” means Accounting Standards Codification as promulgated by the Financial Accounting Standards Board.

 

“ASU” means Accounting Standards Update as promulgated by the Financial Accounting Standards Board.

 

“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 6,000 cubic feet 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, (i) with one or more notional amounts and whose values are derived from the value of one or more underlying assets, reference rates or indexes; (ii) which require no initial net investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors; and, (iii) whose terms require or permit net settlement.

 

“FASB” means Financial Accounting Standards Board.

 

“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 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.

 

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(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 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, drilling locations and acreage, “net” wells, drilling locations and acres are determined by multiplying “gross” wells, drilling locations and acres by the Partnership’s working interest in such wells, drilling locations and acres. Unless otherwise specified, wells, drilling locations and acres statistics quoted herein represent gross wells, drilling locations and acres.

 

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

 

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PART I

 

ITEM 1.

BUSINESS

General

The Partnership is a Delaware limited partnership that was formed in June 2007 by Pioneer to own and acquire oil and gas assets in the Partnership’s area of operations. The Partnership’s area of operations consists of onshore Texas and eight counties in the southeast region of New Mexico.

In December 2011, the Partnership completed a public offering of 2.6 million common units (the “2011 Offering”) for net proceeds of $72.6 million, including $76 thousand contributed by Pioneer Natural Resources GP LLC (the “General Partner”), a subsidiary of Pioneer, to maintain its 0.1 percent general partner interest. Concurrent with the 2011 Offering, Pioneer also sold 1.8 million of its common units for $50.5 million of net proceeds. Pioneer owns a 52.5 percent interest in the Partnership, including the 0.1 percent general partner interest.

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 operations and activities of the Partnership are managed by the General Partner. None of the Partnership, its operating subsidiary or 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, 2011, Pioneer had approximately 3,304 full time employees, 825 of whom are dedicated to drilling and production activities in the Spraberry field in the Permian Basin of West Texas (the “Spraberry field”).

Presentation

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”).

The 2009 Acquisition represented a transaction between entities under common control and is 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) are referred to herein as the “Partnership Predecessor.” 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 Partnership’s accounting presentations and the 2009 Acquisition.

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.

 

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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 44 wells in 2011, 28 wells in 2010 and one well in 2009. The Partnership’s plans for 2012 include increasing to a three-rig drilling program, which the Partnership expects to allow it to drill between 55 wells and 60 wells in 2012. The Partnership plans to drill substantially all of these wells to the Strawn formation, and approximately 35 percent of these wells to the deeper Atoka formation.

 

   

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.

 

   

Benefit from production and reserve enhancements as a result of infill and horizontal drilling and secondary recovery initiatives being advanced by Pioneer. The Partnership 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, (ii) initiated a 7,000 acre waterflood project during 2010 and (iii) drilled two horizontal wells during the second half of 2011, with all three initiatives having encouraging results. 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. To fund development drilling initiatives and future property acquisitions, the Partnership is reserving approximately 25 percent of its net cash provided by operating activities. The Partnership may also use, to the extent available, external financing sources to fund acquisitions, including borrowings under its credit facility and funds from future private and public equity and debt offerings. The Partnership intends to maintain a balanced capital structure, which will afford the Partnership the financial flexibility to fund development drilling initiatives and future acquisitions. See “Liquidity” included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – 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.

 

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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 52.4 percent limited partner interest in the Partnership. Pioneer is a large independent oil and gas exploration and production company with substantially all of its operations located in the United States. Pioneer has reported proved reserves at December 31, 2011, including the Partnership’s properties, of 1,063 MMBOE, of which 608 MMBOE, or 57 percent, were in the Spraberry field. Of the 608 MMBOE of proved reserves in the Spraberry field, 282 MMBOE, or 46 percent, were proved developed reserves and 326 MMBOE, or 54 percent, were proved undeveloped reserves. Pioneer has informed the Partnership that these proved undeveloped reserves represent approximately 4,122 future drilling locations held by Pioneer in the Spraberry field.

Pioneer has stated that it views the Partnership as an integral part of its asset portfolio and expects to offer the Partnership over time the opportunity to purchase portions of Pioneer’s 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 believes its relationship with Pioneer is advantageous because it allows the Partnership to participate jointly with Pioneer in acquisitions in the Partnership’s area of operations.

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

Competitive Strengths

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

 

   

Its relationship with Pioneer:

 

  o

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

  o

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

  o

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

 

   

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

 

   

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

Business Activities

Petroleum industry. Oil and NGL prices have steadily improved since the beginning of 2009, while gas prices have remained volatile and have generally trended lower since 2009. The decline in gas prices is primarily a result of growing gas production associated with discoveries of significant gas reserves in United States shale plays, combined with the warmer than normal 2011/2012 winter, which has resulted in gas storage levels being at historically high levels, and minimal economic demand growth in the United States.

During 2009, 2010 and 2011, economic stimulus initiatives implemented in the United States and worldwide served to stabilize the United States and certain other economies in the world with resulting improvements in industrial demand and consumer confidence. However, other economies, such as those of certain European Union (or “Eurozone”) nations, continue to face economic struggles. The outlook for a continued worldwide economic

 

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recovery 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 2012.

Significant factors that will impact 2012 commodity prices include: the ongoing impact of economic stimulus initiatives in the United States and worldwide and continuing economic struggles in Eurozone nations’ economies; political and economic developments in North Africa and the Middle East; demand from 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 NGL and 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 commodity derivative contracts for a large portion of its forecasted production through 2014, 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 2011, 2010 and 2009 from the Partnership’s derivative price risk management activities and the Partnership’s open derivative positions at December 31, 2011.

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 2,432 producing wells. The Partnership’s interest in 996 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. The Partnership’s plans for 2012 include increasing to a three-rig drilling program, which the Partnership expects to allow it to drill between 55 wells and 60 wells in 2012. 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 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, 2011, the Partnership’s average daily production, on a BOE basis, was 6,943. Production, price and cost information with respect to the Partnership’s properties for 2011, 2010 and 2009 is set forth under “Item 2. Properties — Selected Oil and Gas Information — Production, production prices and production costs data.” During the three years ended December 31, 2011, the Partnership drilled 74 gross (71 net) wells, of which 73 gross wells 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. 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.

 

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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 2011, the Partnership’s significant purchasers were Plains Marketing L.P. (53 percent) and Occidental Energy Marketing (20 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 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 2011, 2010 and 2009 and the Partnership’s open commodity derivative positions at December 31, 2011.

Competition, Markets and Regulations

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

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

Securities regulations. Enterprises that sell securities in public markets are subject to regulatory oversight by agencies such as the SEC and the NYSE. This regulatory oversight imposes on the Partnership the responsibility for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting, and ensuring that the financial statements and other information included in submissions to the SEC do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made in such submissions not misleading. Failure to comply with the rules and regulations of the SEC could subject the Partnership to litigation from public or private plaintiffs. Failure to comply with the rules of the NYSE could result in the delisting of the Partnership’s common units, which 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.

 

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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 laws, rules and regulations to which the Partnership’s business operations are or may be subject.

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

Wastes containing naturally occurring radioactive materials (“NORM”) may also be generated in connection with the Partnership’s operations. Certain processes used to produce oil and gas may enhance the radioactivity of NORM, which may be present in oilfield wastes. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration (“OSHA”). These state and OSHA regulations impose certain requirements concerning worker protection; the treatment, storage and disposal of NORM waste; the management of waste piles, containers and tanks containing NORM; as well as restrictions on the uses of land with NORM contamination.

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

The Partnership currently owns or leases numerous properties that have been producing oil and gas for many years. Although the Partnership believes Pioneer has used operating and waste disposal practices that were standard

 

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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, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. The U.S. Geological Survey is advising the EPA regarding potential seismic hazards associated with these types of underground injection wells. It is possible that federal or state agencies will seek to regulate more stringently the underground injection of oil and gas wastewaters as a result of these events. Nevertheless, the Partnership is not aware of any imminent actions by federal or state agencies that would affect its use or operation of underground injection wells.

The Partnership also routinely uses 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 fuels under the SDWA Underground Injection Control Program. In addition, legislation has been introduced before the United States Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. The Partnership believes that it follows applicable standard industry practices and legal requirements for groundwater protection in its hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Partnership operates, the Partnership could incur significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

 

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In addition, certain governmental reviews are either underway or proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

To the Partnership’s knowledge, there have been no citations, suits or contamination of potable drinking water arising from its fracturing operations. The Partnership does not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, the Partnership believes its existing insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses subject to the terms of such policies.

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 July 2011, the EPA issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs. The EPA’s proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with the flaring of gas. If finalized, these rules could require a number of modifications to the Partnership’s operations, including the installation of new equipment. Such rules could result in significant new cost and compliance burdens to the Partnership and make it more costly and time-consuming to complete oil and gas wells. Any delay or reduction in the drilling and completion of new oil and gas wells could have a material adverse effect on the Partnership’s liquidity, consolidated results of operations and consolidated financial condition.

In response to reported concerns about high concentrations of benzene in the air near certain drilling sites and gas processing facilities in the Barnett Shale area, the Texas Commission on Environmental Quality (the “TCEQ”) adopted new air emissions limitations and permitting requirements for oil and gas facilities in the state, which are applicable to facilities located in the Barnett Shale area. The TCEQ may expand the application of the requirements to facilities in other areas of the state in 2012, which could increase the cost and time associated with drilling wells. The agency’s investigations could lead to additional, more stringent air permitting requirements, increased regulation, and possible enforcement actions against producers, including the Partnership. Any adoption of laws,

 

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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.

Endangered species. The federal Endangered Species Act (the “ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of the Partnership’s operations are conducted in areas where protected species and/or their habitats are known to exist. In these areas, the Partnership may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and the Partnership may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when the Partnership’s operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where the Partnership performs activities could result in increased costs of or limitations on the Partnership’s ability to perform operations and thus have an adverse effect on its business.

The United States Fish and Wildlife Service has proposed listing the Dunes Sagebrush Lizard as endangered under the ESA and expects to make a final determination on the listing by June 2012. Some of the Partnership’s operations in the Permian Basin are located in or near areas that may potentially be designated as Dunes Sagebrush Lizard habitat. If the lizard is classified as an endangered species, the Partnership’s operations in any area that is designated as the lizard’s habitat may be limited, delayed or, in some circumstances, prohibited, and the Partnership may be required to comply with expensive mitigation measures intended to protect the lizard and its habitat. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA and issue decisions with respect to the 250 candidate species over the next several years. The designation of previously unprotected species in areas where the Partnership operates as threatened or endangered could cause the Partnership to incur increased costs arising from species protection measures or could result in limitations on the Partnership’s drilling and production activities that could have an adverse effect on the Partnership’s ability to develop and produce its reserves.

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 public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. 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 adopted two sets of rules 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 of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries as well as certain oil and gas production facilities. The Partnership is monitoring GHG emissions from its operations in accordance with the GHG emissions reporting rule and believes that its monitoring activities are in substantial compliance with applicable reporting obligations.

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.

 

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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, 2011. Additionally, the Partnership is not aware of any environmental issues or claims that will require material capital expenditures during 2012. 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 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.

 

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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. Intrastate gas pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies, including the Railroad Commission of Texas (the “TRRC”). 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 (the “FERC”). Since 1985, FERC has endeavored to make gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis.

Pursuant to the Energy Policy Act of 2005 (“EPAct 2005”), it is unlawful for “any entity,” including producers such as the Partnership that are otherwise not subject to FERC’s jurisdiction under the Natural Gas Act (the “NGA”), 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 applies 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.

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.

Regulation of transportation and sale of oil and NGLs. The availability, terms and cost of transportation significantly affect sales of oil and NGLs. Federal and state regulations govern the price and terms for access to pipeline transportation of oil and gas liquids. Intrastate pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies, including the TRRC. Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act (the “ICA”). The ICA requires that tariff rates for petroleum pipelines, which include both oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory.

Energy commodity prices. Sales prices of gas, oil, condensate and gas liquids are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. The Partnership cannot predict whether new legislation to regulate oil and gas, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on the Partnership’s operations.

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 $0.51 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.

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.

 

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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;

   

gas inventory levels in the United States;

   

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, 2011, the NYMEX oil price ranged from a high of $113.93 per Bbl to a low of $75.67 per Bbl, while the NYMEX Henry Hub gas price ranged from a high of $4.85 per MMBtu to a low of $2.99 per MMBtu.

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

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

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

A significant portion of the Partnership’s assets consist 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.

 

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Because oil and gas properties are a depleting asset, the Partnership will have to drill undeveloped locations and/or acquire additional oil and gas assets that provide cash margins that allow the Partnership to maintain its production and reserves and sustain its level of distributions to unitholders over time.

Producing oil and gas reservoirs are characterized by declining production rates. Because the Partnership’s proved reserves and production decline continually over time, the Partnership will need to drill undeveloped locations and/or acquire additional oil and gas assets that provide cash margins that allow the Partnership to maintain its production and reserves and sustain its level of distributions to unitholders over time. The Partnership may be unable to make such acquisitions if:

 

   

Pioneer decides not to sell any assets to the Partnership;

   

Pioneer decides to acquire assets in the Partnership’s area of operations instead of allowing the Partnership to acquire them;

   

the Partnership is unable to identify attractive acquisition opportunities in its area of operations;

   

the Partnership is unable to agree on a purchase price for assets that are attractive to it; or

   

the Partnership is unable to obtain financing for acquisitions on economically acceptable terms.

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

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

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

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

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

 

   

the validity of the Partnership’s assumptions about reserves, future production, revenues and costs, including synergies;

   

a decrease in the Partnership’s liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;

 

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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 proved reserves and to make cash distributions to its unitholders.

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

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

Future price declines could result in a reduction in the carrying value of the Partnership’s proved oil and gas properties, which could adversely affect the Partnership’s results of operations.

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.

 

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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 of February 24, 2012, approximately 25 percent, 35 percent and 45 percent of the Partnership’s estimated total production for 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, 2011. The use of derivative contracts involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default in its obligations under the Partnership’s derivative contracts, such a default could have a material adverse effect on the Partnership’s results of operations, and could result in a larger percentage of the Partnership’s future production being subject to commodity price changes.

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

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

 

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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.

As of February 24, 2012, approximately 75 percent, 65 percent and 55 percent of the Partnership’s estimated total production for 2012, 2013 and 2014, respectively, have been matched with fixed price commodity swaps or collar contracts with short put options. 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.

The Partnership’s sales of oil, gas and NGLs, and any derivative activities related to such energy commodities, expose the Partnership to potential regulatory risks.

The FERC, the Federal Trade Commission and the Commodity Futures Trading Commission (the “CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to the Partnership’s business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to the Partnership’s physical sales of oil, gas and NGLs, and any derivative activities related to these energy commodities, the Partnership is required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect the Partnership’s financial condition or results of operations.

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, including well stimulation and completion activities, such as hydraulic fracturing, 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, brine, well stimulation and completion fluids, or other pollutants into the surface and subsurface environment;

   

lost or damaged oilfield workover and service tools;

   

unusual or unexpected geological formations or pressure or irregularities in formations;

   

blowouts, cratering, explosions and fires;

   

natural disasters; and

   

uncontrollable flows of oil, gas or well fluids.

 

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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.

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 area of operations is in an area of high industry activity, which may impact the ability of Pioneer, as operator of the Partnership’s properties, to obtain the personnel, equipment, services, resources and facilities access needed to complete development activities as planned or result in increased costs.

The Partnership’s drilling program is being conducted in the Spraberry field, an area in which industry activity has increased rapidly. As a result, demand for personnel, equipment, hydraulic fracturing, proppant for fracture stimulation operations, water and other services and resources, as well as access to transportation, processing and refining facilities for these areas has increased, as has the costs for those items. A delay or inability to secure the personnel, equipment, hydraulic fracturing services, proppant for fracture stimulation operations, other services, resources and facilities access necessary for Pioneer, the operator of the Partnership’s properties, to complete its development activities as planned could result in a rate of oil and gas production below the rate forecasted, and significant increases in costs would impact the Partnership’s profitability.

Pioneer has managed the availability and costs of certain well services through the use of internally provided drilling, fracture stimulation and completion services. During 2011, the Partnership’s capital expenditures benefited from savings realized from Pioneer’s use of such internally provided services in connection with development drilling on the Partnership’s properties. The Partnership expects that its capital expenditures will benefit in 2012 as well; however, Pioneer has no obligation to provide its internal services in connection with the drilling of the Partnership’s undeveloped properties. See Note E of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information about Pioneer services and related party charges.

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.

 

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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.

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

For the year ended December 31, 2011, purchases by Plains Marketing, L.P. and Occidental Energy Marketing represented approximately 53 percent and 20 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. and Occidental Energy Marketing purchase the majority of the Partnership’s oil production pursuant to existing marketing agreements with Pioneer. The Partnership is not a party to the marketing agreements with Plains Marketing, L.P. or Occidental Energy Marketing. Pursuant to the provisions of standard industry operating agreements to which the Partnership’s properties are subject and to which the Partnership is a party, Pioneer, as operator, markets the production on behalf of all working interest owners, including the Partnership, and determines in its sole discretion the terms on which the Partnership’s production is sold.

As is standard in the industry, the oil sold under Pioneer’s marketing agreements with Plains Marketing, L.P. and Occidental Energy Marketing 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.

 

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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 current credit facility, which could hinder or prevent the Partnership from meeting its future capital needs.

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 is higher than historical levels, with many lenders and institutional investors increasing interest rates, enacting tighter lending standards and limiting the amount of funding available to borrowers. If these trends continue, 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 current credit facility is reduced as a result of lower oil, NGL or gas prices, declines in proved reserves, stricter lending requirements or regulations, or for other reasons. Due to these factors, the Partnership cannot be certain that funding will be available if needed and, to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, the Partnership may be unable to implement its business plans, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on the Partnership’s production, revenues and results of operations.

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

Concerns over the worldwide economic outlook, geopolitical issues, the availability and cost of credit, and the United States mortgage and real estate markets continue to increase volatility and affect 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 seems to be improving, concerns about global economic growth or government debt in the Eurozone or the United States 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 also 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

 

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and interest on its future indebtedness to pay these distributions, will reduce the Partnership’s cash available for distribution on its units and will materially affect its business, financial condition and results of operations. If the Partnership borrows to pay distributions during periods of low commodity prices and commodity prices remain low, the Partnership would likely have to reduce its future distributions in order to avoid excessive leverage.

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

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

 

   

the Partnership’s ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

 

   

covenants contained in its existing and future credit and debt arrangements will require it to meet financial tests that may affect its flexibility in planning for and reacting to changes in its business, including possible acquisition opportunities;

 

   

it could need a substantial portion of its cash flow to make principal and interest payments on its indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

 

   

its debt level could make it more vulnerable than its competitors with less debt to the effects of competitive pressures or a downturn in its business or the economy generally.

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

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

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

 

   

grant liens;

   

incur additional indebtedness;

   

engage in a merger, consolidation or dissolution;

   

enter into transactions with affiliates;

   

pay distributions or repurchase equity;

   

make investments;

   

sell or otherwise dispose of its assets, businesses and operations; and

   

materially alter the character of its business.

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

 

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

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

The Partnership is not fully insured against all risks. In addition, pollution and environmental risks generally are not fully insurable. Additionally, the Partnership may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. 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 wells and conduct operations. Any delay in the drilling of new wells or significant increase in drilling costs could reduce its future revenues and cash available for distribution. 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 and completion 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.

 

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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. 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.

 

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

During December 2009, the EPA officially published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted two sets of rules 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 of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries as well as certain oil and gas production facilities.

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 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 CFTC and the SEC to promulgate rules and regulations to implement the new legislation. In December 2011, the CFTC extended temporary exemptive relief from certain regulations applicable to swaps until no later than July 16, 2012. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final 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 derivative transactions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. 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 derivatives 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 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

 

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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.

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 diesels under the SDWA’s Underground Injection Control Program. Moreover, the EPA issued proposed rules in July 2011 that would subject oil and gas production activities to regulation under the NSPS air emissions program including, among other things, the implementation of standards for reduced emission completion techniques to be used during hydraulic fracturing activities. In addition, legislation has been introduced before the United States Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Partnership operates, it could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

Laws and regulations pertaining to threatened and endangered species could delay or restrict the Partnership’s operations and cause it to incur substantial costs.

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the ESA, the Migratory Bird Treaty Act, the CWA and the CERCLA. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities, or at times private parties, may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and may seek damages and, in some cases, criminal penalties. The United States Fish and Wildlife Service has proposed listing the Dunes Sagebrush Lizard as endangered under the ESA and expects to make a final determination on the listing by June 2012. Some of the Partnership’s operations in the Permian Basin are located in or near areas that may potentially be designated as Dunes Sagebrush Lizard habitat. If the lizard is classified as an endangered species, the Partnership’s operations in any area that is designated as the lizard’s habitat may be limited, delayed or, in some circumstances, prohibited, and the Partnerships may be required to comply with expensive mitigation measures intended to protect the lizard and its habitat.

 

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The Partnership’s business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

As an oil and gas producer, the Partnership faces various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of the Partnership’s facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected the Partnership’s operations to increased risks that could have a material adverse effect on the Partnership’s business. In particular, the Partnership’s implementation of various procedures and controls to monitor and mitigate security threats and to increase security for the Partnership’s information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to the Partnership’s operations and could have a material adverse effect on the Partnership’s reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage the Partnership’s reputation and lead to financial losses from remedial actions, loss of business or potential liability.

These risks are not the only risks related to the Partnership’s business. 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.

Risks Related to an Investment in the Partnership

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

Pioneer owns a 52.4 percent limited partner interest in the Partnership and Pioneer owns and controls the General Partner, which controls the Partnership. The directors and officers of the General Partner have a fiduciary duty to manage the General Partner in a manner beneficial to Pioneer. Furthermore, certain directors and officers of the General Partner are directors or officers of affiliates of the General Partner, including Pioneer. Conflicts of interest may arise between Pioneer and its affiliates, including the General Partner, on the one hand, and the Partnership on the other hand. As a result of these conflicts, the directors and officers of the General Partner may favor the interests of the General Partner and the interests of its affiliates over the Partnership’s interests. These potential conflicts include, among others, the following situations:

 

   

Neither the Partnership Agreement nor any other agreement requires Pioneer to pursue a business strategy that favors the Partnership. Directors and officers of Pioneer have a fiduciary duty to make decisions in the best interest of its stockholders, which may be contrary to the Partnership’s interests.

   

The General Partner is allowed to take into account the interests of parties other than the Partnership, such as Pioneer, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to the Partnership.

   

Pioneer will compete with the Partnership and is under no obligation to offer properties to the Partnership. In addition, Pioneer may compete with the Partnership with respect to any future acquisition opportunities.

   

The General Partner determines the amount and timing of expenses, asset purchases and sales, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities and cash reserves, each of which can affect the amount of cash that is available for distribution to unitholders.

   

The Partnership Agreement permits the General Partner to cause the Partnership to pay it or its affiliates for any services rendered to the Partnership and permits the General Partner to enter into additional contractual arrangements with any of these entities on the Partnership’s behalf, and provides for reimbursement to the General Partner for such amounts as it determines pursuant to the provisions of the Partnership Agreement.

 

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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 existing ownership interests.

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

 

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each unitholder’s proportionate ownership interest in the Partnership would decrease;

   

the amount of cash available for distribution on each unit could decrease;

   

the ratio of taxable income to distributions could increase;

   

the relative voting strength of each previously outstanding unit could be diminished; and

   

the market price of the common units could decline.

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

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

 

   

permits the General Partner to make a number of decisions in its sole discretion. This entitles the General Partner to consider only the interests and factors that it desires, and it has no fiduciary duty or obligation to give any consideration to any interest of, or factors affecting, the Partnership, its subsidiaries or any limited partner. Examples include the exercise of its limited call rights, its rights to vote and transfer the units it owns and its registration rights and the determination of whether to consent to any merger or consolidation of the Partnership or any amendment to the Partnership Agreement;

   

with respect to transactions not involving a conflict of interest, provides that the General Partner, when acting in its capacity as general partner and not in its sole discretion, shall not owe any fiduciary duty to the Partnership’s unitholders and shall not owe any fiduciary duty to the Partnership except for the duty to act in good faith, which for purposes of the Partnership Agreement means that a person making any determination or taking or declining to take any action subjectively believes that the decision or action made or taken (or not made or not taken) is in the Partnership’s best interests;

   

generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the Conflicts Committee of the Board of Directors of the General Partner and not involving a vote of unitholders must be determined in good faith. Under the Partnership Agreement, “good faith” for this purpose means that a person making any determination or taking or declining to take any action subjectively believes that the decision or action made or taken (or not made or taken) is fair and reasonable to the Partnership taking into account the totality of the relationships between the parties involved or is on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties;

   

provides that in resolving a conflict of interest, the General Partner and its Conflicts Committee may consider:

 

  ¡  

the relative interests of the parties involved and the benefits and burdens relating to such interest;

  ¡  

the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership);

  ¡  

any customary or accepted industry practices and any customary or historical dealings with a particular person;

  ¡  

any applicable engineering practices or generally accepted accounting practices or principles;

  ¡  

the relative cost of capital of the parties and the consequent rates of return to the equity holders of the parties; and

  ¡  

in the case of the Conflicts Committee only, such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances;

 

   

provides that any decision or action made or taken by the General Partner or its Conflicts Committee in good faith, including those involving a conflict of interest, will be conclusive and binding on all partners and will not be a breach of the Partnership Agreement or of any duty owed to the Partnership;

   

provides that in resolving conflicts of interest, it will be presumed that in making its decision the General Partner or its Conflicts Committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

   

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

 

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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 common units. The vote of the holders of at least 66-2/3 percent of all outstanding common units voting together as a single class is required to remove the General Partner. Pioneer currently owns 52.4 percent of the outstanding common units.

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

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

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

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

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

In order to comply with U.S. laws with respect to the ownership of interests in oil and gas leases on United States federal lands, the Partnership Agreement allows the Partnership to adopt certain requirements regarding those investors who may own common units. As used in this Report, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; (3) a public body, including a municipality; or (4) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases on United States federal lands or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. In the future, if the Partnership owns interests in oil and gas leases on United States federal lands, the General Partner may require unitholders to certify that they are an Eligible Holder. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder may run the risk of (1) if they have not delivered a required Eligible Holder Certification, having quarterly distributions on such units withheld or (2) having their units acquired by the Partnership at the lower of the purchase price of their units or the then current

 

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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 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 18,721,200 common units, 52.4 percent of the outstanding common units. The sale of these units in the public markets could have an adverse effect 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.

These risks are not the only risks related to an investment in 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.

 

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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’s being treated as a partnership for federal income tax purposes. A publicly traded partnership such as the Partnership may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Although the Partnership believes it is treated as a partnership rather than a corporation for such purposes, a change in the Partnership’s business could cause the Partnership to be treated as a corporation 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.

In addition, a change in current law may cause the Partnership to be treated as a corporation for federal income tax purposes. For example, members of Congress have from time to time considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. If the Partnership were subject to federal income tax as a corporation, its cash available to pay distributions would be 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 its unitholders, likely causing a substantial reduction in the value of its 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 affect 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 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 the Partnership is 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. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method the Partnership has adopted. If the IRS were to challenge this method or if new Treasury regulations addressing these matters were issued, the Partnership could be required to change the allocation of items of income, gain, loss and deduction among the Partnership’s unitholders.

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

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

 

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

If a unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and its tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of the Partnership’s net taxable income 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 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 non-U.S. 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 tax rate, and non-U.S. persons will be required to file U.S. 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.

To maintain the uniformity of the economic and tax characteristics of its common units, the Partnership has adopted depreciation, depletion and amortization positions that may not conform to all aspects of existing Treasury Regulations. These positions may result in an understatement of deductions and an overstatement of income to the Partnership’s unitholders. For example, the Partnership does not amortize certain goodwill assets, the value of which has been attributed to certain of its outstanding common units. A subsequent holder of those units may be entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b) (“Section 743(b)”); however, because the Partnership cannot identify these units once they are traded by the initial holder, it does not allocate any subsequent holder of a unit any such amortization deduction. This approach may understate deductions available to those unitholders who own those units and may result in those unitholders reporting that they have a higher tax basis in their units than would be the case if the IRS strictly applied Treasury Regulations relating to these depreciation or amortization adjustments. This, in turn, may result in those unitholders reporting less gain or more loss on a sale of their units than would be the case if the IRS strictly applied those Treasury Regulations.

The IRS may challenge the manner in which the Partnership calculates its unitholder’s basis adjustment under Section 743(b). If so, because the specific unitholders to which this issue relates cannot be identified, the IRS may assert adjustments to all unitholders selling units within the period under audit. A successful IRS challenge to this position or other positions the Partnership may take could adversely affect the amount of taxable income or loss allocated to its unitholders. It also could affect the gain from a unitholder’s sale of common units or result in audit adjustments to the Partnership’s unitholders’ tax returns without the benefit of additional deductions. Consequently, a successful IRS challenge could have a negative effect on the value of the Partnership’s common units.

 

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A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

If a unitholder loans its units to a “short seller” to cover a short sale of units, the unitholder may be considered as having disposed of the loaned units, and the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. During the period of the loan, any of the Partnership’s income, gain, loss or deduction with respect to those units may not be reportable by a unitholder and any cash distributions it receives as to those units may be fully taxable as ordinary income. To avoid the risks associated with a loan to a short seller, unitholders should consider modifying any applicable brokerage account agreements to prohibit their broker from borrowing their units.

The Partnership has adopted certain valuation methodologies for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When the Partnership issues additional units or engages in certain other transactions, it will determine the fair market value of its assets and allocate any unrealized gain or loss attributable to its assets to the capital accounts of the unitholders and the general partner. This methodology may be viewed as understating the value of the Partnership’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under the Partnership’s valuation methods, subsequent purchasers of common units may have a greater portion of their Section 743(b) adjustment allocated to the Partnership’s tangible assets and a lesser portion allocated to its intangible assets. The IRS may challenge these valuation methods, or the Partnership’s allocation of the Section 743(b) adjustment attributable to its tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between the general partner and certain of the unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to the Partnership’s unitholders. It also could affect the amount of taxable gain from the Partnership’s unitholders’ sale of common units and could have a negative effect on the value of the common units or result in audit adjustments to the unitholders’ tax returns without the benefit of additional deductions.

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. For purposes of determining whether the 50 percent threshold has been met, multiple sales of the same interest will be counted only once. 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 calendar year, the closing of the Partnership’s taxable year may also result in more than twelve months of the Partnership’s taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Under current law, the Partnership’s termination would not affect its classification as a partnership for federal income tax purposes, but instead, the Partnership would be treated as a new partnership for tax purposes. If treated as a new partnership, the Partnership must make new tax elections and could be subject to penalties if the Partnership is unable to determine that a termination occurred. Under an IRS relief procedure, if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, the partnership may be permitted to provide only a single Schedule K-1 for the tax years in which the technical termination occurs.

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

 

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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, legislation has been proposed 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 affect the value of an investment in the common units.

These risks are not the only tax 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.

 

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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, during 2010, the FASB issued ASU 2010-03 “Extractive Industries – Oil and Gas,” which aligned the estimation and disclosure requirements of ASC 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, 2011, 2010 and 2009 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, 2011, 2010 and 2009. 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 (the “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 WWR for further review. The reserve estimates are summarized in reserve reconciliations that quantify reserve changes since the previous year end, if any, by revisions of previous estimates, purchases of minerals-in-place, extensions and discoveries, improved recovery, 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.

 

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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 (the “SPE”). A reserve audit as defined by the SPE is not the same as a financial audit. The SPE’s definition of a reserve audit includes the following concepts:

 

   

A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable and has been presented in conformity with the 2007 SPE publication entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information.”

   

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 proved reserve differences. Such data was incorporated, as appropriate, by both parties into the proved 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 the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the SPE.

See “Item 1A. Risk Factors,” “Critical Accounting Estimates” in “Item 7. Management’s Discussion and Analysis of Financial Condition 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 and geoscientists with extensive industry experience and is managed by Pioneer’s Director of the WWR, the technical person that is primarily responsible for overseeing proved reserve estimates for Pioneer. 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,” promulgated by the SPE in 2001

 

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and revised in 2007. The WWR Director’s qualifications include 34 years of experience as a petroleum engineer, with 27 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.

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-2699. 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 33 years of practical experience in petroleum engineering, including 32 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 SPE.

Technologies used in reserves estimates. Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped proved reserves only if an ability and intent has been established to drill the reserves within five years, unless specific circumstances justify a longer time period.

In the context of reserves estimations, reasonable certainty means a high degree of confidence that the quantities will be recovered and reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonable certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating proved reserves, the Partnership uses several different traditional methods such as performance-based methods, volumetric-based methods and analogy with similar properties. In addition, the Partnership utilizes additional technical analysis such as seismic interpretation, wireline formation tests, geophysical logs and core data to provide incremental support for more complex reservoirs. Information from this incremental support is combined with the traditional technologies outlined above to enhance the certainty of the Partnership’s proved reserve estimates.

Proved reserves. The Partnership’s proved reserves totaled 50,732 MBOE, 51,975 MBOE and 44,365 MBOE at December 31, 2011, 2010 and 2009, respectively, representing $796.6 million, $563.8 million and $262.3 million, respectively, of Standardized Measure. Changes in the Partnership’s proved reserve volumes during the year ended December 31, 2011 included production of 2,534 MBOE, extensions and discoveries of 1,337 MBOE, acquisitions of 253 MBOE and negative revisions of previous estimates of 299 MBOE. Revisions of previous estimates are comprised of 2,106 MBOE of positive price revisions and 2,405 MBOE of negative revisions due to updated performance profiles and cost estimates. The Partnership’s proved reserves at December 31, 2011 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 2011. On this basis, the NYMEX price of oil and gas for proved reserve reporting purposes at December 31, 2011 was $96.13 per barrel of oil and $4.12 per Mcf of gas, compared to comparable average NYMEX prices of $79.28 per barrel of oil and $4.37 per Mcf of gas at December 31, 2010.

Tabular proved reserves disclosures. On a BOE basis, 82 percent of the Partnership’s total proved reserves at December 31, 2011 were proved developed reserves. The following table provides information regarding the Partnership’s proved reserves and Standardized Measure as of December 31, 2011:

 

     Summary of Oil and Gas Reserves as of December 31, 2011  
     Based on Average Fiscal Year Prices  
     Oil
(MBbls)
     NGLs
(MBbls)
     Gas
(MMcf)
     MBOE      Standardized
Measure

(in  thousands)
 

Proved

              

Developed

     24,933        10,081        38,939        41,503      $ 704,337  

Undeveloped

     6,092        1,908        7,370        9,229        92,243  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total proved

     31,025        11,989        46,309        50,732      $ 796,580  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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Proved undeveloped reserves. As of December 31, 2011, the Partnership had 609 proved undeveloped well locations (all of which are expected to be developed within the five year period ending December 31, 2016), representing an increase of 482 proved undeveloped well locations (380 percent) since December 31, 2010. The increase in proved undeveloped well locations in 2011 is due to acquisitions during the year of minimal working interests in 506 gross locations (two net locations) in certain units in the Spraberry field. The Partnership’s proved undeveloped reserves totaled 9,229 MBOE and 11,822 MBOE at December 31, 2011 and 2010, respectively. During 2011, 44 proved undeveloped well locations were drilled and completed as developed wells and an additional 8 proved undeveloped well locations were in various stages of drilling and completion at December 31, 2011. As a result, the Partnership converted 3,073 MBOE of proved undeveloped reserves to proved developed reserves during 2011. The following table summarizes, on a MBOE basis, the Partnership’s proved undeveloped reserves activity during the year ended December 31, 2011:

 

Beginning proved undeveloped reserves

     11,822  

Extensions and discoveries

     1,190  

Purchases of minerals in place

     162  

Transfers to proved developed

     (3,073

Revisions of previous estimates

     (872
  

 

 

 

Ending proved undeveloped reserves

     9,229  
  

 

 

 

The Partnership’s development costs incurred during the year ended December 31, 2011 totaled $70.1 million and were comprised of $72.6 million of development drilling expenditures associated with new wells and a $2.5 million net decrease in asset retirement obligations. The Partnership’s proved undeveloped well locations as of December 31, 2011 included 67 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 and in 2012 plans to increase to a three-rig drilling program to accelerate development of 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 2012 drilling program.

The following table represents the estimated timing and cash flows of developing the Partnership’s proved undeveloped reserves as of December 31, 2011 (dollars in thousands):

 

Year Ended December 31, (a)    Estimated
Future
Production
(MBOE)
     Future
Cash
Inflows
     Future
Production
Costs
     Future
Development
Costs
     Future Net
Cash Flows
 

2012

     245      $ 19,116      $ 2,351      $ 58,516      $ (41,751

2013

     640        48,724        6,542        62,624        (20,442

2014

     863        65,258        9,502        38,284        17,472  

2015

     651        48,938        8,215        537        40,186  

2016

     523        38,970        7,199        1,516        30,255  

Thereafter

     6,307        467,315        154,709        4,117        308,489  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     9,229      $ 688,321      $ 188,518      $ 165,594      $ 334,209  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

 

(a)

Beginning in 2012 and thereafter, the production and cash flows represent the drilling results from the respective year plus the incremental effects of proved undeveloped drilling.

 

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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 2,432 producing wells, of which 996 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, 2011 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. During 2011, all Partnership wells were completed in the Lower Wolfcamp and deeper Strawn intervals, with one well completed in the deeper Atoka interval with encouraging results. Approximately 60 percent and 40 percent of the Partnership’s acreage position has Strawn and Atoka potential, respectively.

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, 2011, 2010 and 2009. Because of normal production declines and drilling activities, the historical information presented below should not be interpreted as being indicative of future results.

Production, production prices and production costs data. The price that the Partnership receives for the oil and gas produced is largely a function of market supply and demand. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or gas can result in substantial price volatility. Historically, commodity prices have been volatile and the Partnership expects that volatility to continue in the future. A substantial or extended decline in oil or gas prices or poor drilling results could have a material adverse effect on the Partnership’s financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and the Partnership’s ability to access capital markets.

 

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The following tables set forth production, price and cost data with respect to the Partnership’s properties for the years ended December 31, 2011, 2010 and 2009. These amounts represent the Partnership’s historical results without making pro forma adjustments for any drilling activity that occurred during the respective years.

 

000,000.00 000,000.00 000,000.00
     Year Ended December 31,  
     2011      2010      2009  

Production information:

        

Annual sales volumes:

        

Oil (MBbls)

     1,571        1,425        1,344  

NGLs (MBbls)

     567        587        518  

Gas (MMcf)

     2,376        2,181        2,281  

Total (MBOE)

     2,534        2,375        2,243  

Average daily sales volumes:

        

Oil (Bbls)

     4,305        3,903        3,683  

NGLs (Bbls)

     1,553        1,608        1,420  

Gas (Mcf)

     6,509        5,975        6,248  

Total (BOE)

     6,943        6,507        6,145  

Average prices, including hedge results (a):

        

Oil (per Bbl)

   $ 115.41      $ 103.60      $ 100.35  

NGL (per Bbl)

   $ 42.74      $ 44.31      $ 41.61  

Gas (per Mcf)

   $ 3.28      $ 4.66      $ 5.37  

Revenue (per BOE)

   $ 84.20      $ 77.37      $ 75.23  

Average prices, excluding hedge results (a):

        

Oil (per Bbl)

   $ 92.19      $ 77.56      $ 58.05  

NGL (per Bbl)

   $ 42.74      $ 32.91      $ 25.56  

Gas (per Mcf)

   $ 3.28      $ 3.33      $ 2.81  

Revenue (per BOE)

   $ 69.80      $ 57.72      $ 43.56  

Average costs (per BOE):

        

Production costs:

        

Lease operating (b)

   $ 13.75      $ 14.24      $ 14.04  

Workover

     1.42        1.90        1.46  
  

 

 

    

 

 

    

 

 

 

Total production costs

   $ 15.17      $ 16.14      $ 15.50  
  

 

 

    

 

 

    

 

 

 

Production taxes:

        

Ad valorem

   $ 1.93      $ 2.15      $ 2.09  

Production

     3.51        2.96        2.17  
  

 

 

    

 

 

    

 

 

 

Total production taxes

   $ 5.44      $ 5.11      $ 4.26  
  

 

 

    

 

 

    

 

 

 

Depletion expense

   $ 6.13      $ 5.30      $ 5.80  
  

 

 

    

 

 

    

 

 

 

 

 

(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 includes the direct internal costs of Pioneer to operate the properties. The lease operating expense of these 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 for 2009.

 

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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, 2011, 2010 and 2009:

PRODUCTIVE WELLS (a)

 

$000.00 $000.00 $000.00 $000.00 $000.00 $000.00
     Gross Productive Wells      Net Productive Wells  
     Oil      Gas      Total      Oil      Gas      Total  

As of December 31, 2011 (b)

             2,432                -                 2,432                1,012                -                 1,012  

As of December 31, 2010

     1,116                -         1,116        985                -         985  

As of December 31, 2009

     1,135                -         1,135        981                -         981  

 

 

(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, 2011.

(b)

During 2011, the Partnership purchased minimal working interests in 1,270 gross producing wells (two net) in certain units in the Spraberry field, which decreased the net wells to gross wells ratio when compared to prior periods.

Leasehold acreage. The following table sets forth information about the Partnership’s developed and undeveloped leasehold acreage as of December 31, 2011:

 

     Developed Acreage      Undeveloped Acreage (a)  
     Gross Acres      Net Acres      Gross Acres      Net Acres  

Spraberry field (b)

     23,723        11,003        3,450        3,251  

 

 

(a)

The Partnership’s undeveloped acreage represents proved undeveloped acreage held by productive wells.

(b)

During 2011, the Partnership purchased minimal working interests in 12,302 gross acres (185 net acres) in certain units in the Spraberry field, which decreased the net acreage to gross acreage ratio when compared to prior periods.

The following table sets forth the expiration dates of depths from the base of the Wolfcamp to the base of the Atoka on the Partnership’s gross and net undeveloped acres as of December 31, 2011:

 

     Acres Expiring (a)  
     Gross      Net  

2012

     4,251        3,924  

 

 

(a)

The Partnership is subject to a continuous drilling commitment (“CD”) related to certain depths within current Partnership acreage. The CD relates to 221 gross acres (209 net acres) for Wolfcamp interval only rights and 4,251 gross acres (3,924 net acres) related to rights from the base of the Wolfcamp interval to the base of the Atoka interval. The CD obligates the Partnership to spud a well by April 1, 2012, followed by another well spud within 120 days thereafter until all the depth rights are earned. If the Partnership does not drill these commitment wells, no acreage will expire, but the Partnership will lose the depth rights mentioned above.

 

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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 2011, 2010 and 2009. This information should not be considered indicative of future performance.

DRILLING ACTIVITIES

 

     Gross Wells      Net Wells  
     Year Ended December 31,      Year Ended December 31,  
     2011      2010      2009      2011      2010      2009  

Productive wells: (a)

                 

Development

     44        28        1        42        27        1  

Exploratory

     -         -         -         -         -         -   

Dry holes:

                 

Development

     1        -         -         1        -         -   

Exploratory

     -         -         -         -         -         -   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     45        28        1        43        27        1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

 

(a)

As of December 31, 2011, drilling on 8 gross wells (8 net wells) was in progress. The Partnership had 18 gross wells (18 net wells) upon which drilling was in progress as of December 31, 2010 and seven gross wells (seven net wells) upon which drilling was in progress as of December 31, 2009.

 

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.

 

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

 

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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 $2.03 per unit during 2011. On January 24, 2012, the Board of Directors of the General Partner declared a $0.51 per unit distribution payable on February 10, 2012 to unitholders of record on February 3, 2012.

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, 2011 and 2010:

 

          High              Low          Distributions
Declared Per
Unit
 

Year ended December 31, 2011

        

Fourth quarter

   $ 31.73      $ 21.34      $ 0.51  

Third quarter

   $ 32.72      $ 24.17      $ 0.51  

Second quarter

   $ 35.87      $ 26.21      $ 0.51  

First quarter

   $ 34.79      $ 28.22      $ 0.50  

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  

On February 24, 2012, the last reported sales price of the Partnership’s common units, as reported in the NYSE composite transactions, was $27.57 per unit.

As of February 24, 2012, the Partnership’s common units were held by 14 holders of record. This number does not include owners for whom common units may be held in “street” name.

During the fourth quarter of 2011, 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.

 

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Table of Contents
ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data as of and for the five years ended December 31, 2011 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,  
      2011     2010     2009 (a)     2008 (a)     2007 (a)  
     (in thousands, except per unit data)  

Statements of Operations Data:

          

Revenues:

          

Oil and gas

   $     213,362     $     183,758     $     168,717     $     193,394     $     144,038  

Interest and other

     2       -        210       192       -   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
     213,364       183,758       168,927       193,586       144,038  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

          

Oil and gas production (b)

     38,427       38,334       34,749       38,807       27,879  

Production and ad valorem taxes

     13,784       12,119       9,547       14,213       11,550  

Depletion, depreciation and amortization

     15,534       12,577       13,016       11,582       11,382  

General and administrative

     7,222       6,330       4,790       6,227       5,643  

Accretion of discount on asset retirement obligations

     913       546       484       144       143  

Interest

     1,605       1,543       1,160       621       -   

Derivative losses, net (c)

     11,725       5,431       78,265       -        -   

Other, net

     -        -        549       890       5  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
     89,210       76,880       142,560       72,484       56,602  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before taxes

     124,154       106,878       26,367       121,102       87,436  

Income tax provision

     (1,338     (1,045     (46     (1,326     (920
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 122,816     $ 105,833     $ 26,321     $ 119,776     $ 86,516  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Allocation of net income:

          

Net income (loss) applicable to the Partnership Predecessor

   $ -      $ -      $ (1,598   $ 59,038     $ 86,516  

Net income applicable to the Partnership

     122,816       105,833       27,919       60,738       -   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 122,816     $ 105,833     $ 26,321     $ 119,776     $ 86,516  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Allocation of net income applicable to the Partnership:

          

General partner’s interest in net income

   $ 123     $ 106     $ 28     $ 61    

Limited partners’ interest in net income

     122,466       105,649       27,891       60,677    

Unvested participating securities’ interest in net income

     227       78       -        -     
  

 

 

   

 

 

   

 

 

   

 

 

   

Net income applicable to the Partnership

   $ 122,816     $ 105,833     $ 27,919     $ 60,738    
  

 

 

   

 

 

   

 

 

   

 

 

   

Net income per common unit – basic and diluted

   $ 3.68     $ 3.19     $ 0.92     $ 2.02    
  

 

 

   

 

 

   

 

 

   

 

 

   

Weighted average common units outstanding – basic and diluted

     33,249       33,114       30,399       30,009    
  

 

 

   

 

 

   

 

 

   

 

 

   

Distributions declared per common unit

   $ 2.03     $ 2.00     $ 2.00     $ 0.81    
  

 

 

   

 

 

   

 

 

   

 

 

   

Balance Sheet Data (as of December 31):

          

Total assets

   $ 326,727     $ 280,060     $ 256,638     $ 367,164     $ 217,702  

Long-term debt

   $ 32,000     $ 81,200     $ 67,000     $ -      $ -   

Partners’ equity

   $ 227,206     $ 134,745     $ 141,273     $ 347,831     $ 207,569  

 

(a)

In May 2008, the Partnership completed its initial public offering of 9,487,500 common units representing limited partnership interests (the “2008 Offering”). To effect the 2008 Offering, Pioneer contributed a portion of its ownership of a subsidiary which owned interests in oil and gas properties located in the Spraberry field and sold to the Partnership its remaining ownership interest in the subsidiary. During August 2009, the Partnership acquired certain additional oil and gas property interests in the Spraberry field from Pioneer that, together with the property

 

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interests conveyed to the Partnership in 2008 (the “Conveyed Interests”), represented transactions between entities under common control and are reported in the Partnership’s financial statements similar to poolings of interests. The Partnership’s statements of operations for the years ended December 31, 2009, 2008 and 2007, include the results of operations of the Conveyed Interests (being the results of operations of the “Partnership Predecessor”) prior to their ownership by the Partnership.

(b)

Historical oil and gas production costs associated with the Conveyed Interests includes the direct internal costs of Pioneer to operate the properties for periods presented prior to their ownership by the Partnership. The oil and gas production costs of the properties after they were acquired by the Partnership includes COPAS Fees.

(c)

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.

 

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 2011 include:

 

   

Net income increased to $122.8 million in 2011 from $105.8 million in 2010. The $17.0 million increase in 2011 earnings as compared to 2010 is primarily attributable to (i) a $29.6 million increase in oil and gas sales, primarily due to an 11 percent increase in average reported oil price and a seven percent increase in sales volumes on a BOE basis, partially offset by (ii) a $6.3 million increase in net derivative losses.

   

Daily sales volumes increased seven percent to 6,943 BOEPD in 2011, as compared to 6,507 BOEPD for 2010, primarily due to the successful results of the Partnership’s two-rig drilling program.

   

Average reported oil sales price per Bbl increased to $115.41 during 2011, as compared to $103.60 for 2010. Average reported NGL sales price per Bbl and gas sales price per Mcf decreased to $42.74 and $3.28, respectively, during 2011, as compared to $44.31 and $4.66, respectively, during 2010.

   

Net cash provided by operating activities increased by $20.8 million to $117.7 million, or 21 percent, as compared to $96.9 million reported for 2010, primarily due to higher oil and gas sales volumes and higher realized oil prices.

   

During December 2011, the Partnership completed a public offering of 2.6 million common units at a price to the public of $29.20 per unit. The Partnership received net proceeds of $72.6 million from the offering, including $76 thousand contributed to maintain the General Partner’s 0.1 percent general partner interest, which were used to reduce outstanding borrowings under its credit facility.

First Quarter 2012 Outlook

Based on current estimates, the Partnership expects that production will average 7,100 BOEPD to 7,600 BOEPD.

Production costs (including production and ad valorem taxes) are expected to average $20.00 to $23.00 per BOE based on current NYMEX strip prices for oil, NGLs and gas. Depletion, depreciation and amortization expense is expected to average $6.00 to $7.00 per BOE.

General and administrative expense is expected to be $1.5 million to $2.5 million. Interest expense is expected to be $100 thousand to $300 thousand and accretion of discount on asset retirement obligations is expected to be nominal.

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

 

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Results of Operations

Oil and gas revenues. Oil and gas revenues totaled $213.4 million, $183.8 million and $168.7 million during 2011, 2010 and 2009, respectively. The increase in revenue during 2011, as compared to 2010, was primarily due to increases in average daily sales volumes of oil and gas and an increase in oil commodity prices, offset by a decrease in average daily sales volumes of NGLs. Average daily sales volumes for oil and gas for 2011 increased 10 percent and nine percent, respectively, as compared to 2010. The increase in average daily sales volumes of oil and gas was primarily due to the successful results from the Partnership’s two-rig drilling program with 44 new wells placed on production during 2011 as compared to 28 wells placed on production during 2010. The decrease in average daily sales volumes for NGLs was primarily due to ethane being rejected (left in the gas stream) for a portion of 2011 due to NGL pipeline takeaway capacity limitations. Average reported oil prices for 2011 increased by 11 percent, as compared to the average 2010 reported prices. The increase in revenue during 2010, as compared to 2009, was primarily due to increases in average daily sales volumes of oil and NGLs and increases in oil and NGL commodity prices. Average daily sales volumes for oil and NGLs for 2010 increased six percent and 13 percent, respectively, as compared to 2009. Average reported oil and NGL prices for 2010 increased by three percent and six percent, respectively, as compared to the respective 2009 reported prices.

The following table provides average daily sales volumes for 2011, 2010 and 2009:

 

     Year Ended
December 31,
 
     2011      2010      2009  

Oil (Bbls)

     4,305        3,903        3,683  

NGLs (Bbls)

     1,553        1,608        1,420  

Gas (Mcf)

     6,509        5,975        6,248  

Total (BOE)

     6,943        6,507        6,145  

The following table provides average reported prices, including the results of hedging activities, and average realized prices, excluding the results of hedging activities, for 2011, 2010 and 2009:

 

000000000 000000000 000000000
      Year Ended December 31,  
     2011      2010      2009  

Average reported prices:

        

Oil (per Bbl)

   $ 115.41      $ 103.60      $ 100.35  

NGL (per Bbl)

   $ 42.74      $ 44.31      $ 41.61  

Gas (per Mcf)

   $ 3.28      $ 4.66      $ 5.37  

Total (per BOE)

   $ 84.20      $ 77.37      $ 75.23  

Average realized prices:

        

Oil (per Bbl)

   $ 92.19      $ 77.56      $ 58.05  

NGL (per Bbl)

   $ 42.74      $ 32.91      $ 25.56  

Gas (per Mcf)

   $ 3.28      $ 3.33      $ 2.81  

Total (per BOE)

   $ 69.80      $ 57.72      $ 43.56  

Effective January 1, 2012, the Partnership has no remaining deferred commodity hedge gains or losses to transfer to oil, NGL or gas sales. Accordingly, the Partnership’s future average reported prices will not include any effects from hedging activities. Since February 1, 2009, the Partnership has recognized all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they actually occur. See Notes B, C and H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” for more information about the Partnership’s derivative contracts.

Oil and gas production costs. The Partnership’s oil and gas production costs totaled $38.4 million, $38.3 million and $34.7 million during 2011, 2010 and 2009, respectively. Total production costs per BOE decreased during 2011 by six percent as compared to 2010. The decreases in production costs per BOE reflect the benefits of spreading production costs that are fixed over increasing sales volumes and the variable timing of workover activities. Total production costs per BOE increased during 2010 by four percent as compared to 2009 primarily due to increased workover activities being performed in 2010 to restore production.

 

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The following table provides the components of the Partnership’s production costs per BOE for 2011, 2010 and 2009:

 

     Year Ended December 31,  
         2011              2010              2009      

Lease operating expenses (a)

   $ 13.75      $ 14.24      $ 14.04  

Workover costs

     1.42        1.90        1.46  
  

 

 

    

 

 

    

 

 

 

Total production costs

   $ 15.17      $ 16.14      $ 15.50  
  

 

 

    

 

 

    

 

 

 

 

(a)

Historical lease operating expense associated with those properties acquired in August 2009 includes the direct internal costs of Pioneer to operate the properties. The lease operating expense of these 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 for 2009.

Production and ad valorem taxes. The Partnership recorded production and ad valorem taxes of $13.8 million, $12.1 million and $9.5 million during 2011, 2010 and 2009, respectively. In general, production and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. Consequently, during 2011, the Partnership’s production and ad valorem taxes per BOE have, in the aggregate, increased by six percent, as compared to 2010. The increase is primarily due to increasing realized oil commodity prices. The 20 percent increase in 2010, as compared to 2009, was primarily due to increasing oil and NGL commodity prices.

The following table provides the components of the Partnership’s total production and ad valorem taxes per BOE for 2011, 2010 and 2009:

 

     Year Ended December 31,  
         2011              2010              2009      

Ad valorem taxes

   $ 1.93      $ 2.15      $ 2.09  

Production taxes

     3.51        2.96        2.17  
  

 

 

    

 

 

    

 

 

 

Total production and ad valorem taxes

   $ 5.44      $ 5.11      $ 4.26  
  

 

 

    

 

 

    

 

 

 

Depletion, depreciation and amortization expense. The Partnership recorded depletion expense of $6.13, $5.30 and $5.80 per BOE for 2011, 2010 and 2009, respectively. During 2011, the increase in the per BOE depletion expense is primarily due to an increase in the Partnership’s oil and gas property basis as a result of the two-rig drilling program, partially offset by positive price revisions to proved reserves since December 31, 2010 as a result of higher average first-day-of-the-month oil and NGL prices during the 12-month period ending on December 31, 2011, which had the effect of extending the economic lives of proved properties. During 2010, the decrease in the per BOE depletion expense was primarily due to increases in end-of-well-life reserve volumes from 44,365 MBOE at December 31, 2009 to 51,975 MBOE at December 31, 2010 as a result of commodity price increases and positive performance-related revisions during 2010.

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

 

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General and administrative expense. General and administrative expense totaled $7.2 million, $6.3 million and $4.8 million during 2011, 2010 and 2009, respectively. The Partnership and Pioneer entered into an administrative services agreement in May 2008, pursuant to which Pioneer agreed to perform administrative services for the Partnership, and the Partnership agreed to reimburse Pioneer for its expenses incurred in providing such services. Pursuant to this agreement a portion of Pioneer’s general and administrative expense is allocated to the Partnership based on a methodology of determining the Partnership’s share, on a per-BOE basis, of certain of the general and administrative costs incurred by Pioneer. The Partnership is also responsible for paying for its direct third-party services. The increase in general and administrative expense for 2011, as compared to 2010, is primarily due to an increase in the general and administrative allocation as a result of a six percent increase in the allocation rate and the increase in the Partnership’s sales volumes. The increase in general and administrative expense for 2010, as compared to 2009, was primarily attributable to an increase of 46 percent in the per-BOE rate and to the increases in production volumes for 2010, as compared to 2009. Based on the methodology in the administrative services agreement, the per-BOE rates increased primarily due to increases in Pioneer’s drilling activity in the United States (including the Partnership’s two-rig drilling program) and increases in general and administrative expense attributable to Pioneer’s United States operations (excluding Alaska). 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 additional information regarding the general and administrative expense allocations to the Partnership.

Interest expense. Interest expense totaled $1.6 million for 2011, as compared to $1.5 million for 2010 and $1.2 million for 2009. Interest expense increased during 2011, as compared to 2010, due to increased borrowings under the Partnership’s credit facility to fund a portion of the Partnership’s two-rig drilling program. The Partnership used proceeds from the 2011 Offering to pay down a portion of the credit facility balance, resulting in outstanding borrowings of $32.0 million as of December 31, 2011. For 2011, the Partnership’s weighted average debt outstanding was $89.4 million. For 2010, the Partnership’s weighted average debt outstanding was $72.3 million, with outstanding borrowings under the credit facility as of December 31, 2010 totaling $81.2 million. Interest expense increased during 2010, as compared to 2009, because of borrowings under the credit facility in August 2009 to fund a portion of the cash consideration associated with the 2009 Acquisition and borrowings to fund a portion of the Partnership’s two-rig drilling program. Prior to the 2009 Acquisition in August 2009, the Partnership’s interest expense related primarily to fees associated with maintaining its credit facility. See Note D of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information about the Partnership’s long-term debt and interest expense.

Derivative losses, net. Effective February 1, 2009, the Partnership discontinued hedge accounting on all existing commodity derivative instruments and from that date forward began accounting for all derivative instruments under the mark-to-market accounting rules. In accordance with the mark-to-market accounting rules, the Partnership has recognized changes in the fair value of its derivative contracts since February 1, 2009 as derivative gains or losses in the earnings of the period in which they occurred. Fluctuations in commodity prices during 2011, 2010 and 2009 have impacted the fair value of the Partnership’s derivative instruments and resulted in net derivative losses of $11.7 million, $5.4 million and $78.3 million, respectively. Prior to February 1, 2009, the Partnership accounted for its derivative instruments as cash flow hedges and effective changes in the fair values of the derivative instruments were recognized in Accumulated Other Comprehensive Income. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information about market risk and the types of derivative transactions in which the Partnership participates.

Income tax provision. The Partnership recognized income tax provisions of $1.3 million, $1.0 million and $46 thousand during 2011, 2010 and 2009, respectively. The Partnership’s tax is reflective of the Texas Margin tax. See Note K of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Partnership’s income taxes.

 

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Capital Commitments, Capital Resources and Liquidity

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

In conjunction with the undeveloped properties acquired in the 2009 Acquisition, the Partnership commenced a two-rig drilling program in November 2009. The Partnership added 44 new wells to production during 2011 and had 8 wells awaiting completion at December 31, 2011. During 2012, the Partnership plans to drill 55 wells to 60 wells with a three-rig drilling program at a net cost, including facility connections, of $110 million to $120 million. The Partnership’s 2012 capital expenditure forecast reflects the savings expected by Pioneer’s use of internally provided drilling and completion services in connection with drilling the Partnership’s undeveloped properties. However, Pioneer has no obligation to provide its internal services in connection with any drilling activities related to the Partnership’s undeveloped properties after 2012. The Partnership expects to fund the 2012 drilling program primarily from internal operating cash flows and, to a lesser extent, from borrowings under its credit facility. Although the Partnership expects that internal cash flows and available borrowing capacity under its credit facility will be adequate to fund capital expenditures and planned unitholder distributions, no assurances can be given that such funding sources will be adequate to meet the Partnership’s future needs.

The Partnership Agreement requires that the Partnership distribute all of its available cash to its partners. In general, available cash is defined to mean cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves for future capital expenditures (including acquisitions), operational needs and distributions for any one or more of the next four quarters. Because the Partnership’s proved reserves and production decline continually over time, the Partnership will need to mitigate these declines through drilling initiatives, production enhancement, and/or acquisitions of income producing assets that provide cash margins that allow the Partnership to sustain its level of distributions to unitholders over time. Currently, the Partnership is reserving approximately 25 percent of its cash flow to drill its undeveloped locations in order to maintain its production and cash flow. In the future, the Partnership may use its reserved cash flow for acquisitions of producing properties or undeveloped properties that can be developed to maintain the Partnership’s production and cash flow. The Partnership has adopted a cash distribution policy pursuant to which it intends to declare distributions of $0.51 per unit per quarter, or $2.04 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter. The distribution for the fourth quarter of 2011 of $0.51 per unit was declared by the Board of Directors of the General Partner on January 24, 2012 and was paid on February 10, 2012 to unitholders of record on February 3, 2012.

Oil and gas properties. The Partnership’s cash expenditures for additions to oil and gas properties during 2011, 2010 and 2009 totaled $72.7 million, $45.3 million and $3.8 million, respectively. Additions to oil and gas properties during 2011 reflect expenditures associated with the Partnership’s two-rig drilling program. The Partnership’s expenditures for additions to oil and gas properties for 2011, 2010 and 2009 were funded primarily by net cash provided by operating activities.

Contractual obligations, including off-balance sheet obligations. As of December 31, 2011, the Partnership’s contractual obligations included credit facility indebtedness, asset retirement obligations and derivative instruments. Borrowings outstanding under its credit facility were $32.0 million at December 31, 2011. As of December 31, 2011, the Partnership’s derivative instruments represented assets of $9.3 million and liabilities of $45.1 million; however, these derivative instruments continue to have market risk and represent contractual obligations of the Partnership. The ultimate liquidation value of the Partnership’s commodity derivatives will be dependent upon actual future commodity prices at the time of settlement, which may differ materially from the inputs used to determine the derivatives’ fair values at any point in time. The Partnership entered into these derivatives for the primary purpose of reducing commodity price risk on forecasted physical commodity sales and has an expectation of a high degree of correlation between changes in the derivative values and commodity prices received on physical sales. See Notes C, D and H of Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding the Partnership’s derivative positions and credit facility. As of December 31, 2011, the Partnership’s asset retirement obligations were $10.3 million, a decrease of $2.2 million from December 31, 2010. The change in the 2011 estimate is primarily due to decreases in abandonment cost estimates based on recent actual costs incurred. As of December 31, 2011, the Partnership was not a party to any material off-balance sheet arrangements.

 

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The following table summarizes by period the payments due by the Partnership for contractual obligations estimated as of December 31, 2011:

 

$000000000 $000000000 $000000000 $000000000 $000000000
             Payments Due by Year  
      Total      2012      2013 and
2014
     2015 and
2016
     Thereafter  
            (in thousands)  

Long-term debt

   $ 32,000      $ -       $ 32,000      $ -       $ -   

Derivative obligations

   $ 45,054      $ 28,101      $ 16,953      $ -       $ -   

Asset retirement obligations

   $ 10,315      $ 500      $ 1,000      $ 1,000      $ 7,815  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 87,369      $ 28,601      $ 49,953      $ 1,000      $ 7,815  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Capital resources. The Partnership’s primary capital resources are expected to be net cash provided by operating activities, amounts available under its credit facility and, to the extent available, funds from future private and public equity and debt offerings. For 2012, the Partnership expects to use cash flow from operations and the available borrowing capacity under its credit facility to fund its three-rig drilling program and planned unitholder distributions, and to provide adequate liquidity for future growth opportunities such as additional development drilling or acquisitions.

Operating activities. Net cash provided by operating activities during 2011, 2010 and 2009 was $117.7 million, $96.9 million and $82.5 million, respectively. The increase in net cash provided by operating activities in 2011, as compared to that of 2010, was primarily due to increases in oil and gas sales volumes and higher realized oil prices, partially offset by cash used for changes in working capital. The increase in net cash provided by operating activities in 2010, as compared to that of 2009, was primarily due to increased oil and NGL sales volumes and prices.

Investing activities. Net cash used in investing activities during 2011 was $72.7 million, as compared to $45.3 million during 2010 and $58.5 million during 2009. The increase in net cash used in investing activities during 2011 as compared to 2010 was primarily due to increased well costs, a portion of which is due to drilling deeper to the Strawn interval with positive results, drilling activity associated with the Partnership’s two-rig drilling program (44 new wells placed on production in 2011 as compared to 28 wells in 2010) and oil and gas property acquisitions of $2.8 million. The decrease in net cash used in investing activities during 2010 as compared to 2009 was primarily due to the 2009 Acquisition, partially offset by the two-rig drilling program during 2010.

Financing activities. Net cash used in financing activities for 2011 was $43.9 million, as compared to $52.1 million for 2010 and $53.4 million during 2009. The net cash used in financing activities during 2011 was comprised of unitholder distributions, offset by borrowings under the credit facility to fund a portion of the Partnership’s two-rig drilling program. In addition, the Partnership received $72.6 million of net proceeds, including $76 thousand contributed to maintain the General Partner’s 0.1 percent general partner interest associated with the 2011 Offering, which was used to reduce outstanding borrowings under the credit facility. The net cash used in financing activities during 2010 was comprised of unitholder distributions offset by borrowings under the credit facility to fund a portion of the Partnership’s two-rig drilling program. During 2009, net cash used in financing activities was comprised of unitholder distributions and the payment for the 2009 Acquisition in excess of the carrying value of the net assets acquired, offset by net proceeds from the public equity offering of 3,105,000 of the Partnership’s common units and borrowings under the credit facility to fund a portion of the 2009 Acquisition.

During 2011, 2010 and 2009, the Partnership paid cash distributions to unitholders of $67.3 million, $66.3 million and $60.1 million, respectively. Future distributions and the timing and amount thereof are at the discretion of the Board of Directors of the General Partner.

Liquidity. The Partnership’s principal source of short-term liquidity is cash generated from its operations and availability under its credit facility. As of December 31, 2011, the Partnership had $32.0 million outstanding on its credit facility and $268.0 million of remaining borrowing capacity under the credit facility. The Partnership’s borrowing capacity under the credit facility is subject to a covenant requiring that the Partnership maintain a specified ratio of the net present value of the Partnership’s projected future cash flows from its oil and gas assets to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. As a result, declines in commodity prices

 

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could reduce the Partnership’s borrowing capacity under the credit facility and could require the Partnership to reduce its distributions to unitholders. At December 31, 2011, the Partnership was in compliance with all of its debt covenants. See Note D of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the credit facility.

The Partnership 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. In furtherance of the Partnership’s effort to meet these objectives, as of February 24, 2012, approximately 75 percent, 65 percent and 55 percent of the Partnership’s estimated total production for 2012, 2013 and 2014, respectively, have been matched with fixed price commodity swap contracts or collar contracts with short puts.

The Partnership expects that its primary sources of liquidity will be cash generated from operations, amounts available under the credit facility and, to the extent available, funds from future private and public equity and debt offerings. As discussed above under “– Capital commitments,” the Partnership Agreement requires that the Partnership distribute all of its available cash to its unitholders and the General Partner. In addition, because the Partnership’s proved reserves and production decline continually over time, the Partnership will need to replace production to sustain its level of distributions to unitholders over time. Accordingly, the Partnership’s primary needs for cash will be for production growth through drilling initiatives (such as the planned three-rig drilling program for 2012), acquisitions, production enhancements and for distributions to partners. In making cash distributions, the General Partner will attempt to avoid large variations in the amount the Partnership distributes from quarter to quarter. The Partnership Agreement permits the General Partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters, and for the conduct of the Partnership’s business, which includes possible acquisitions. A sustained decline in commodity prices could result in a shortfall in expected cash flows. If cash flow from operations does not meet the Partnership’s expectations, the Partnership may reduce its level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of its capital expenditures using borrowings under the credit facility, issuances of debt or equity securities or from other sources, such as asset sales. The Partnership cannot provide any assurance that needed capital will be available on acceptable terms or at all.

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

Critical Accounting Estimates

The Partnership prepares its consolidated financial statements for inclusion in this Report in accordance with GAAP. See Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a comprehensive discussion of the Partnership’s significant accounting policies. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of the Partnership’s most critical accounting estimates, judgments and uncertainties that are inherent in the Partnership’s application of GAAP.

Derivative assets and liabilities. The Partnership is a party to derivative contracts that represent material assets and liabilities as of December 31, 2011. In accordance with GAAP, the Partnership records its derivative assets and liabilities at their estimated fair values, the determination of which requires management to make judgments and estimates about observable and unobservable inputs such as forward commodity prices, credit-adjusted interest rates and volatility factors. See Notes C and H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding the Partnership’s derivative instruments.

 

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

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is generally made to the oil and gas property balance. See Notes B and J of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Partnership’s asset retirement obligations.

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

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

 

   

the quality and quantity of available data;

   

the interpretation of that data;

   

the accuracy of various mandated economic assumptions; and

   

the judgment of the persons preparing the estimate.

The Partnership’s proved reserve information included in this Report as of December 31, 2011, 2010 and 2009 were prepared by Pioneer’s reservoir engineers and were audited by independent petroleum engineers. Estimates prepared by third parties may be higher or lower than those included herein.

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

It should not be assumed that the Standardized Measure as of December 31, 2011 included in the Unaudited Supplementary Information included in “Item 8. Financial Statements and Supplementary Data” is the current market value of the Partnership’s estimated proved reserves. In accordance with SEC requirements, the Partnership calculated the Standardized Measure using the average of the NYMEX spot prices for sales of oil and gas on the first calendar day of each month during 2011 and prevailing operating and development costs at the end of the year. Actual future prices and costs may be materially higher or lower than the prices and costs used in the calculation of the Standardized Measure. See “Item 1A. Risk Factors” and “Item. 2 Properties” for additional information regarding estimates of proved reserves.

 

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

Impairment of proved oil and gas properties. The Partnership reviews its proved properties to be held and used whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon estimated future recoverable proved and risk-adjusted probable and possible reserves, its outlook of future commodity prices, production and capital costs expected to be incurred to recover the reserves, discount rates commensurate with the nature of the properties and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated.

New Accounting Pronouncements

The information regarding new accounting pronouncements is included in Note B of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

 

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following quantitative and qualitative information is provided about financial instruments to which the Partnership was a party as of December 31, 2011 and 2010, and from which the Partnership may incur future gains or losses from changes in commodity prices or market interest rates.

The fair values of the Partnership’s derivative contracts are based on the Partnership’s valuation models and applications. During 2010, the Partnership changed its valuation inputs for NGL derivative contracts and used component price inputs presently available from independent active market quoted sources. As of December 31, 2009, the Partnership’s NGL component price inputs were obtained from independent brokers active in buying and selling NGL derivative contracts. During 2011, the Partnership was a party to derivative swap contracts, collar contracts and commodity collar contracts with short put options. See Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Partnership’s derivative contracts. The following table reconciles the changes that occurred in the fair values of the Partnership’s open derivative contracts during 2011 (in thousands):

 

$00000000000
     Derivative
Contract Net
Liabilities
 

Fair value of contracts outstanding as of December 31, 2010

   $ 18,850   

Changes in contract fair values

     11,725   

Contract maturities

     5,195   
  

 

 

 

Fair value of contracts outstanding as of December 31, 2011 (a)

   $ 35,770   
  

 

 

 

 

 

(a)

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

The Partnership accounts for derivative instruments using the mark-to-market accounting method. Therefore, the Partnership recognizes changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

 

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Quantitative Disclosures

Interest rate sensitivity. The following table provides information about the Partnership’s credit facility’s sensitivity to changes in interest rates. The table presents maturities by expected maturity date of the credit facility, the weighted average interest rates expected to be paid on the credit facility given current contractual terms and market conditions and the estimated fair value of outstanding borrowings under the credit facility. The average interest rate represents the average rates being paid on the debt projected forward relative to the forward yield curve for LIBOR on February 24, 2012.

 

000,00.00 000,00.00 000,00.00
     Year Ending December 31,    

Liability

Fair Value at
December 31,

 
     2012     2013     2011  
     (amounts in thousands)  

Total Debt:

      

Variable rate principal maturities

   $ -      $ 32,000     $ 32,393  

Weighted average interest rate

     1.40     1.54  

Commodity price sensitivity. The following tables provide information about the Partnership’s oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of December 31, 2011. Although mitigated by the Partnership’s derivative activities, declines in commodity prices will reduce the Partnership’s revenues and internally-generated cash flows.

Commodity derivative instruments. The Partnership manages commodity price risk with derivative swap contracts, collar contracts and collar contracts with short put options. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum (“floor”) and maximum (“ceiling”) prices for the Partnership on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other collar contracts by virtue of the short put option price, below which the Partnership’s realized price will exceed the variable market prices by the floor price-to-short put price differential. With collar contracts, if the relevant market price is above the ceiling price, the Partnership pays the derivative counterparty the difference between the market price and the ceiling price; if the relevant market price is between the ceiling price and the floor price, the derivative has no cash settlement value; and, if the relevant market price is below the floor price, the Partnership receives the difference between the floor price and the market price from the counterparty. Collar contracts with short puts are similar to collar contracts, except that if the relevant market price is below the short put price, the Partnership receives the difference between the floor price and short put price from the counterparty.

See Notes B, C and H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a description of the accounting procedures followed by the Partnership relative to its derivative financial instruments and for specific information regarding the terms of the Partnership’s derivative financial instruments that are sensitive to changes in oil, NGL or gas prices.

 

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Oil Price Sensitivity

Derivative Financial Instruments as of December 31, 2011

 

$000,00.00 $000,00.00 $000,00.00 $000,00.00
                         

Liability Fair
Value at

December 31,

 
     Year Ending December 31,     
     2012      2013      2014      2011  

Oil Derivatives (a):

              (in thousands

Average daily notional Bbl volumes (b):

           

Swap contracts

     3,000        3,000        -       $ (36,517

Weighted average fixed price per Bbl

   $ 79.32      $ 81.02      $ -      

Collar contracts with short puts

     1,000        1,000        2,000      $ (2,319

Weighted average ceiling price per Bbl

   $ 103.50      $ 111.50      $ 133.00     

Weighted average floor price per Bbl

   $ 80.00      $ 83.00      $ 90.00     

Weighted average short put price per Bbl

   $ 65.00      $ 68.00      $ 75.00     

Average forward NYMEX oil prices (c)

   $ 110.31      $ 106.86      $ 100.34     

 

(a)

See Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Partnership’s derivative contracts.

(b)

Subsequent to December 31, 2011, the Partnership entered into additional (i) collar contracts with short puts for 500 Bbls per day of the Partnership’s July through December 2012 production with a ceiling price of $120.00 per Bbl, a floor price of $95.00 per Bbl and a short put price of $80.00 per Bbl, (ii) collar contracts with short puts for 750 Bbls per day of the Partnership’s 2013 production with a ceiling price of $122.00 per Bbl, a floor price of $95.00 per Bbl and a short put price of $80.00 per Bbl and (iii) collar contracts with short puts for 3,000 Bbls per day of the Partnership’s 2014 production with a ceiling price of $118.00 per Bbl, a floor price of $90.00 per Bbl and a short put price of $70.00 per Bbl.

(c)

The average forward NYMEX oil prices are based on February 24, 2012 market quotes.

NGL Price Sensitivity

Derivative Financial Instruments as of December 31, 2011

 

$000,00.00 $000,00.00
            Liability  
     Year Ending      Fair Value at  
     December 31,      December 31,  
     2012      2011  
            (in
thousands)
 

NGL Derivatives (a):

     

Average daily notional Bbl volumes:

     

Swap contracts

     750      $ (4,995

Weighted average fixed price per Bbl

   $ 35.03     

Average forward Mont Belvieu NGL prices (b)

   $ 51.10     

 

  (a)

See Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Partnership’s derivative contracts.

  (b)

Forward Mont Belvieu-posted-prices are not available as formal market quotes. These forward prices represent estimates as of February 24, 2012 provided by third parties who actively trade in the derivatives. Accordingly, these prices are subject to estimates and assumptions.

 

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Gas Price Sensitivity

Derivative Financial Instruments as of December 31, 2011

 

$000,00.00 $000,00.00 $000,00.00
                

Asset (Liability)

Fair Value at

December 31,

 
                
     Year Ending December 31,    
     2012     2013     2011  
                 (in thousands)  

Gas Derivatives (a):

      

Average daily notional MMBtu volumes:

      

Swap contracts

     5,000       2,500     $ 8,331  

Weighted average fixed price per MMBtu

   $ 6.43     $ 6.89    

Average forward NYMEX gas prices (b)

   $ 2.98     $ 3.79    

Average daily notional MMBtu volumes:

      

Basis swap contracts (c)

     2,500       2,500     $ (270

Weighted average fixed price per MMBtu

   $ (0.30   $ (0.31  

Average forward basis differential prices (b)

   $ (0.19   $ (0.19  

 

(a)

See Note H of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Partnership’s derivative contracts.

(b)

The average forward index gas prices and forward basis differential prices are based on February 24, 2012 NYMEX market quotes and February 24, 2012 estimated El Paso Natural Gas (Permian Basin) differentials to NYMEX prices, respectively.

(c)

To minimize basis risk, the Partnership enters into basis swaps to convert the index prices of those swap contracts from a NYMEX index to an El Paso Natural Gas (Permian Basin) posting index.

Qualitative Disclosures

The Partnership’s primary market risk exposures are from changes in commodity prices and interest rates.

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

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

 

     Page  

Consolidated Financial Statements of Pioneer Southwest Energy Partners L.P.:

  

Report of Independent Registered Public Accounting Firm

     64   

Consolidated Balance Sheets as of December 31, 2011 and 2010

     65   

Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009

     66   

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December  31, 2011, 2010 and 2009

     67   

Consolidated Statements of Partners’ Equity for the Years Ended December  31, 2011, 2010 and 2009

     68   

Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009

     69   

Notes to Consolidated Financial Statements

     70   

Unaudited Supplementary Information

     90   

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Unitholders of Pioneer Southwest Energy Partners L.P.

We have audited the accompanying consolidated balance sheets of Pioneer Southwest Energy Partners L.P. (the “Partnership”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), partners’ equity and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Pioneer Southwest Energy Partners L.P. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

As discussed in Note B to the consolidated financial statements, the Partnership has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements resulting from Accounting Standards Update No. 2010-03, “Oil and Gas Reserve Estimation and Disclosures,” effective December 31, 2009.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pioneer Southwest Energy Partners L.P.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas

February 28, 2012

 

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PIONEER SOUTHWEST ENERGY PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit amounts)

 

000,000.00 000,000.00
     December 31,  
     2011     2010  

ASSETS

  

Current assets:

    

Cash

   $ 1,176     $ 107  

Accounts receivable

     18,063       15,824  

Inventories

     920       883  

Prepaid expenses

     240       260  

Deferred income taxes

     207       -   

Derivatives

     5,619       18,753  
  

 

 

   

 

 

 

Total current assets

     26,225       35,827  
  

 

 

   

 

 

 

Property, plant and equipment, at cost:

    

Oil and gas properties, using the successful efforts method of accounting:

    

Proved properties

     437,085       364,237  

Accumulated depletion, depreciation and amortization

     (141,498     (125,963
  

 

 

   

 

 

 

Total property, plant and equipment

     295,587       238,274  
  

 

 

   

 

 

 

Deferred income taxes

     1,008       1,751  

Derivatives

     3,665       3,783  

Other, net

     242       425  
  

 

 

   

 

 

 
   $ 326,727     $ 280,060  
  

 

 

   

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

  

Current liabilities:

    

Accounts payable:

    

Trade

   $ 10,756     $ 8,422  

Due to affiliates

     830       1,164  

Interest payable

     16       30  

Income taxes payable to affiliate

     550       492  

Deferred income taxes

     -        63  

Derivatives

     28,101       9,673  

Asset retirement obligations

     500       1,000  
  

 

 

   

 

 

 

Total current liabilities

     40,753       20,844  
  

 

 

   

 

 

 

Long-term debt

     32,000       81,200  

Derivatives

     16,953       31,713  

Asset retirement obligations

     9,815       11,558  

Partners’ equity:

    

General partner’s interest–35,750 and 33,147 general partner units issued and outstanding at December 31, 2011 and 2010, respectively

     382       251  

Limited partners’ interest–35,713,700 and 33,113,700 common units issued and outstanding at December 31, 2011 and 2010, respectively

     226,824       98,333  

Accumulated other comprehensive income–deferred hedge gains, net of tax

     -        36,161  
  

 

 

   

 

 

 

Total partners’ equity

     227,206       134,745  

Commitments and contingencies

    
  

 

 

   

 

 

 
   $ 326,727     $ 280,060  
  

 

 

   

 

 

 

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

 

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PIONEER SOUTHWEST ENERGY PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

 

     Year Ended December 31,  
     2011     2010     2009  

Revenues:

      

Oil and gas

   $         213,362     $         183,758     $         168,717  

Interest and other

     2       -        210  
  

 

 

   

 

 

   

 

 

 
     213,364       183,758       168,927  
  

 

 

   

 

 

   

 

 

 

Costs and expenses:

      

Oil and gas production

     38,427       38,334       34,749  

Production and ad valorem taxes

     13,784       12,119       9,547  

Depletion, depreciation and amortization

     15,534       12,577       13,016  

General and administrative

     7,222       6,330       4,790  

Accretion of discount on asset retirement obligations

     913       546       484  

Interest

     1,605       1,543       1,160  

Derivative losses, net

     11,725       5,431       78,265  

Other, net

     -        -        549  
  

 

 

   

 

 

   

 

 

 
     89,210       76,880       142,560  
  

 

 

   

 

 

   

 

 

 

Income before taxes

     124,154       106,878       26,367  

Income tax provision

     (1,338     (1,045     (46
  

 

 

   

 

 

   

 

 

 

Net income

   $ 122,816     $ 105,833     $ 26,321  
  

 

 

   

 

 

   

 

 

 

Allocation of net income:

      

Net loss applicable to the Partnership Predecessor

   $ -      $ -      $ (1,598

Net income applicable to the Partnership

     122,816       105,833       27,919  
  

 

 

   

 

 

   

 

 

 

Net income

   $ 122,816     $ 105,833     $ 26,321  
  

 

 

   

 

 

   

 

 

 

Allocation of net income applicable to the Partnership:

      

General partner’s interest in net income

   $ 123     $ 106     $ 28  

Limited partners’ interest in net income

     122,466       105,649       27,891  

Unvested participating securities’ interest in net income

     227       78       -   
  

 

 

   

 

 

   

 

 

 

Net income applicable to the Partnership

   $ 122,816     $ 105,833     $ 27,919  
  

 

 

   

 

 

   

 

 

 

Net income per common unit - basic and diluted

   $ 3.68     $ 3.19     $ 0.92  
  

 

 

   

 

 

   

 

 

 

Weighted average common units outstanding - basic and diluted

     33,249       33,114       30,399  
  

 

 

   

 

 

   

 

 

 

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

 

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PIONEER SOUTHWEST ENERGY PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

 

     Year Ended December 31,  
     2011     2010     2009  

Net income

   $         122,816     $         105,833     $         26,321  

Other comprehensive activity:

      

Hedge activity, net of tax:

      

Hedge fair value changes, net

     -        -        11,509  

Hedge gains included in net income

     (36,161     (46,277     (70,714
  

 

 

   

 

 

   

 

 

 

Other comprehensive loss

     (36,161     (46,277     (59,205
  

 

 

   

 

 

   

 

 

 

Comprehensive income (loss)

   $ 86,655     $ 59,556     $ (32,884
  

 

 

   

 

 

   

 

 

 

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

 

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PIONEER SOUTHWEST ENERGY PARTNERS L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(in thousands)

 

     General      Limited                        Accumulated        
     Partner      Partner      Owner’s     General     Limited     Other     Total  
     Units      Units      Net     Partner’s     Partners’     Comprehensive     Partners’  
     Outstanding      Outstanding      Equity     Equity     Equity     Income     Equity  

Balance as of December 31, 2008

     30        30,009      $ 62,729     $ 179     $ 143,280     $ 141,643     $ 347,831  

Net loss applicable to Partnership Predecessor

     -         -         (1,598     -        -        -        (1,598

Net income applicable to Partnership

     -         -         -        28       27,891       -        27,919  

Net distributions to owner

     -         -         (7,814     -        -        -        (7,814

Cash distributions to partners

     -         -         -        (60     (60,018     -        (60,078

Deferred income tax assets on acquisition step-up

     -         -         1,399       -        -        -        1,399  

Allocation of owner’s net equity

     -         -         (54,716     -        54,716       -        -   

Proceeds from offering, net

     -         3,105        -        -        60,983       -        60,983  

Partner contributions

     3        -         -        64       -        -        64  

Acquisition of carrying value

     -         -         -        -        (54,716     -        (54,716

Acquisition in excess of carrying value

     -         -         -        -        (113,512     -        (113,512

Other comprehensive income, net of tax:

                

Hedge fair values changes, net

     -         -         -        -        -        11,509       11,509  

Net hedge gains included in net income

     -         -         -        -        -        (70,714     (70,714
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2009

     33        33,114      $ -      $ 211     $ 58,624     $ 82,438     $ 141,273  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash distributions to partners

     -         -         -        (66     (66,228     -        (66,294

Net income applicable to Partnership

     -         -         -        106       105,727       -        105,833  

Contribution of unit-based services

     -         -         -        -        210       -        210  

Other comprehensive income, net of tax:

                

Net hedge gains included in net income

     -         -         -        -        -        (46,277     (46,277
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2010

     33        33,114      $ -      $ 251     $ 98,333     $ 36,161     $ 134,745  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash distributions to partners

     -         -         -        (68     (67,220     -        (67,288

Net income applicable to Partnership

     -         -         -        123       122,693       -        122,816  

Contributions of unit-based services

     -         -         -        -        514       -        514  

Proceeds from offering, net

     -         2,600        -        -        72,504       -        72,504  

Partner contributions

     3        -         -        76       -        -        76  

Other comprehensive income, net of tax:

                

Hedge gains included in net income

     -         -         -        -        -        (36,161     (36,161
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of December 31, 2011

     36        35,714      $ -      $ 382     $ 226,824     $ -      $ 227,206  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

 

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PIONEER SOUTHWEST ENERGY PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

     Year Ended December 31,  
     2011     2010     2009  

Cash flows from operating activities:

      

Net income

   $ 122,816     $ 105,833     $ 26,321  

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depletion, depreciation and amortization

     15,534       12,577       13,016  

Deferred income taxes

     801       552       (470

Accretion of discount on asset retirement obligations

     913       546       484  

Amortization of debt related costs

     182       182       200  

Amortization of unit-based compensation

     514       210       -   

Commodity derivative related activity

     (19,567     (21,816     51,254  

Changes in operating assets and liabilities, net of effects from acquisitions:

      

Accounts receivable

     (2,239     (1,662     (1,556

Inventories

     (37     (32     1,090  

Prepaid expenses

     20       -        (155

Accounts payable

     (695     1,329       (6,853

Interest payable

     (14     4       26  

Income taxes payable to affiliate

     58       32       (32

Asset retirement obligations

     (635     (898     (803
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     117,651       96,857       82,522  
  

 

 

   

 

 

   

 

 

 

Cash flows from investing activities:

      

Payments of acquisition carrying value

     -        -        (54,716

Additions to oil and gas properties

     (72,674     (45,281     (3,760
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (72,674     (45,281     (58,476
  

 

 

   

 

 

   

 

 

 

Cash flows from financing activities:

      

Borrowings under credit facility

     65,404       63,574       150,000  

Principal payments on credit facility

     (114,604     (49,374     (83,000

Proceeds from issuance of partnership units, net of issuance costs

     72,504       -        60,983  

Partner contributions

     76       -        64  

Payments for acquisition in excess of carrying value

     -        -        (113,512

Distributions to unitholders

     (67,288     (66,294     (60,078

Net distributions to owner

     -        -        (7,814
  

 

 

   

 

 

   

 

 

 

Net cash used in financing activities

     (43,908     (52,094     (53,357
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     1,069       (518     (29,311

Cash and cash equivalents, beginning of period

     107       625       29,936  
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 1,176