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Table of Contents

Filed pursuant to Rule 424(b)(4)
Registration Statement No. 333-174017

PROSPECTUS

GRAPHIC

LRR Energy, L.P.
9,408,000 Common Units
Representing Limited Partner Interests


We are a Delaware limited partnership formed by affiliates of Lime Rock Resources to operate, acquire, exploit and develop producing oil and natural gas properties in North America with long-lived, predictable production profiles. This is the initial public offering of our common units. No public market currently exists for our common units. We have been approved to list our common units on the New York Stock Exchange, subject to official notice of issuance, under the symbol "LRE".


Investing in our common units involves risks. Please read "Risk Factors" beginning on page 23.

These risks include the following:

We may not have sufficient cash to pay the minimum quarterly distribution on our units following the establishment of cash reserves and payment of expenses, including payments to our general partner.

Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

A decline in oil, natural gas or natural gas liquids, or NGLs, prices will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether.

Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with us, and owe limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of our unitholders.

Lime Rock Resources, Lime Rock Partners and other affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets.

Neither we nor our general partner have any employees and we rely solely on Lime Rock Management and Lime Rock Resources Operating Company to manage our business. Most of our management team and the employees of Lime Rock Resources Operating Company will also provide substantially similar services to Lime Rock Resources, and thus will not be solely focused on our business.

Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Affiliates of Lime Rock Management control our general partner and thus will have the power to control our operations.

Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.

Units held by persons who our general partner determines are not eligible holders will be subject to redemption.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation, then our cash available for distribution to our unitholders would be substantially reduced.

Our unitholders will be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 
  Per Common Unit   Total  

Public offering price

  $ 19.0000   $ 178,752,000  

Underwriting discount(1)

  $ 1.1875   $ 11,172,000  

Proceeds, before expenses, to LRR Energy, L.P.

  $ 17.8125   $ 167,580,000  

(1)
Excludes an aggregate structuring fee equal to 0.25% of the gross proceeds of this offering, of which 80% is payable to Wells Fargo Securities, LLC and 20% is payable to Raymond James & Associates, Inc.

We have granted the underwriters a 30-day option to purchase up to an additional 1,411,200 common units on the same terms and conditions as set forth above if the underwriters sell more than 9,408,000 common units in this offering.

The underwriters expect to deliver the common units on or about November 16, 2011.


Wells Fargo Securities        
            Raymond James
        Citigroup    
        RBC Capital Markets


Baird

 

Oppenheimer & Co.

 

Stifel Nicolaus Weisel

Prospectus dated November 10, 2011


Table of Contents

GRAPHIC


TABLE OF CONTENTS

PROSPECTUS SUMMARY

  1
 

LRR Energy, L.P. 

 
1
 

Our Properties

  2
 

Our Hedging Strategy

  2
 

Our Business Strategies

  3
 

Our Competitive Strengths

  3
 

Our Principal Business Relationships

  3
 

Risk Factors

  5
 

Formation Transactions and Partnership Structure

  6
 

Ownership and Organizational Structure of LRR Energy, L.P. 

  7
 

Principal Executive Offices and Internet Address

  8
 

Management of LRR Energy, L.P. 

  8
 

Summary of Conflicts of Interest and Fiduciary Duties

  8
 

The Offering

  10
 

Summary Historical and Pro Forma Financial Data

  17
 

Non-GAAP Financial Measures

  19
 

Summary Reserve and Pro Forma Operating Data

  21

RISK FACTORS

 
23
 

Risks Related to Our Business

 
23
 

Risks Inherent in an Investment in Us

  33
 

Tax Risks to Unitholders

  46

USE OF PROCEEDS

 
51

CAPITALIZATION

 
52

DILUTION

 
53

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

 
55
 

General

 
55
 

Our Minimum Quarterly Distribution

  58
 

Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended June 30, 2011

  60
 

LRR Energy, L.P. Unaudited Pro Forma Cash Available for Distribution

  61
 

Estimated Unaudited Adjusted EBITDA for the Twelve Months Ending September 30, 2012

  62
 

Assumptions and Considerations

  66
 

Sensitivity Analysis

  74

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

 
77
 

Distributions of Available Cash

 
77
 

Operating Surplus and Capital Surplus

  78
 

Capital Expenditures

  81
 

Subordination Period

  83
 

Distributions of Available Cash from Operating Surplus During the Subordination Period

  85
 

Distributions of Available Cash from Operating Surplus After the Subordination Period

  86
 

General Partner Interest and Incentive Distribution Rights

  86
 

Percentage Allocations of Available Cash From Operating Surplus

  87
 

General Partner's Right to Reset Incentive Distribution Levels

  87
 

Distributions from Capital Surplus

  90
 

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

  90

i


 

Distributions of Cash Upon Liquidation

  91
 

Adjustments to Capital Accounts

  93

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

 
94

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

 
98
 

Overview

 
98
 

Historical and Pro Forma Financial and Operating Data

  105
 

Pro Forma Results of Operations

  106
 

Pro Forma Liquidity and Capital Resources

  108
 

Pro Forma Quantitative and Qualitative Disclosure About Market Risk

  111
 

Predecessor Results of Operations

  113
 

Predecessor Liquidity and Capital Resources

  118
 

Predecessor Quantitative and Qualitative Disclosure About Market Risk

  121
 

Critical Accounting Policies and Estimates

  122
 

Recently Issued Accounting Pronouncements

  125
 

Internal Controls and Procedures

  125
 

Inflation

  126
 

Off-Balance Sheet Arrangements

  126

BUSINESS AND PROPERTIES

 
127
 

LRR Energy, L.P. 

 
127
 

Our Business Strategies

  128
 

Our Competitive Strengths

  129
 

Our Principal Business Relationships

  130
 

Partnership Properties

  132
 

Oil and Natural Gas Data and Operations — Partnership Properties

  139
 

Oil and Natural Gas Data and Operations — Our Predecessor

  145
 

Exploitation Activities

  145
 

Operations

  145
 

Environmental Matters and Regulation

  150
 

Other Regulation of the Oil and Natural Gas Industry

  155
 

Employees

  156
 

Offices

  156
 

Legal Proceedings

  157

MANAGEMENT

 
158
 

Management of LRR Energy

 
158
 

Directors and Executive Officers

  159
 

Reimbursement of Expenses of Our General Partner

  163
 

Director Independence

  163
 

Committees of the Board of Directors

  163
 

Executive Compensation

  164
 

Compensation Discussion and Analysis

  165
 

Compensation of Directors

  167
 

Long-Term Incentive Plan

  167

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

 
170

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

 
172
 

Distributions and Payments to Our General Partner and Its Affiliates

 
172
 

Limited Liability Company Agreement of Our General Partner

  174

ii


 

Agreements Governing the Transactions

  175
 

Contracts with Affiliates

  176
 

Review, Approval or Ratification of Transactions with Related Persons

  178

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

 
180
 

Conflicts of Interest

 
180
 

Fiduciary Duties

  188

DESCRIPTION OF THE COMMON UNITS

 
191
 

The Units

 
191
 

Transfer Agent and Registrar

  191
 

Transfer of Common Units

  191

THE PARTNERSHIP AGREEMENT

 
193
 

Organization and Duration

 
193
 

Purpose

  193
 

Cash Distributions

  193
 

Capital Contributions

  193
 

Limited Voting Rights

  194
 

Applicable Law; Forum, Venue and Jurisdiction

  195
 

Limited Liability

  195
 

Issuance of Additional Interests

  196
 

Amendment of the Partnership Agreement

  197
 

Merger, Consolidation, Sale or Other Disposition of Assets

  199
 

Dissolution

  200
 

Liquidation and Distribution of Proceeds

  200
 

Withdrawal or Removal of Our General Partner

  201
 

Transfer of General Partner Units

  202
 

Transfer of Incentive Distribution Rights

  202
 

Transfer of Ownership Interests in Our General Partner

  202
 

Change of Management Provisions

  202
 

Limited Call Right

  203
 

Meetings; Voting

  203
 

Status as Limited Partner

  204
 

Non-Eligible Holders; Redemption

  204
 

Indemnification

  205
 

Reimbursement of Expenses

  205
 

Books and Reports

  205
 

Right to Inspect Our Books and Records

  206
 

Registration Rights

  206

UNITS ELIGIBLE FOR FUTURE SALE

 
207

MATERIAL TAX CONSEQUENCES

 
208
 

Taxation of LRR Energy, L.P. 

 
209
 

Tax Consequences of Unit Ownership

  210
 

Tax Treatment of Operations

  216
 

Disposition of Common Units

  220
 

Uniformity of Common Units

  223
 

Tax-Exempt Organizations and Other Investors

  223
 

Administrative Matters

  224
 

Recent Legislative Developments

  227

iii


 

State, Local and Other Tax Considerations

  227

INVESTMENT IN LRR ENERGY, L.P. BY EMPLOYEE BENEFIT PLANS

 
228

UNDERWRITING

 
230
 

Option to Purchase Additional Common Units

 
230
 

Discounts

  231
 

Indemnification of Underwriters

  231
 

Lock-Up Agreements

  231
 

Electronic Distribution

  232
 

New York Stock Exchange

  233
 

Stabilization

  233
 

Discretionary Accounts

  233
 

Pricing of This Offering

  234
 

Directed Unit Program

  234
 

Relationships

  234
 

Sales Outside the United States

  235

VALIDITY OF THE COMMON UNITS

 
236

EXPERTS

 
236

WHERE YOU CAN FIND MORE INFORMATION

 
236

FORWARD-LOOKING STATEMENTS

 
236

INDEX TO FINANCIAL STATEMENTS

 
F-1

APPENDIX A — FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF LRR ENERGY, L.P.

 
A-1

APPENDIX B — GLOSSARY OF TERMS

 
B-1

APPENDIX C — MILLER AND LENTS, LTD. SUMMARY OF MARCH 31, 2011 RESERVES

 
C-1

APPENDIX D — NETHERLAND, SEWELL & ASSOCIATES, INC. SUMMARY OF MARCH 31, 2011 RESERVES

 
D-1

          You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.

          Until December 5, 2011 (25 days after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This delivery is in addition to a dealer's obligation to deliver a prospectus when acting as an underwriter and with respect to their unsold allotments or subscriptions.


          This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read "Risk Factors" and "Forward-Looking Statements."

iv



Industry and Market Data

          The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates based on our knowledge and experience in the industry in which we operate. Although we believe the third-party sources are reliable and that the third-party information used in this prospectus or in our estimates is accurate and complete, we have not independently verified the information, nor have we ascertained the economic assumptions underlying such information.

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PROSPECTUS SUMMARY

          This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including "Risk Factors," the audited historical and unaudited pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes, unless otherwise indicated, that the underwriters do not exercise their option to purchase additional common units and that, instead, the additional 1,411,200 common units will be issued to Fund I upon expiration of such option.

          References in this prospectus to "LRR Energy," "we," "our," "us" or like terms refer collectively to LRR Energy, L.P. and its operating subsidiary. References to "Fund I" or "our predecessor" refer collectively to Lime Rock Resources A, L.P. ("LRR A"), Lime Rock Resources B, L.P. ("LRR B") and Lime Rock Resources C, L.P. ("LRR C"), which will sell and contribute oil and natural gas properties and related net profits interests and operations to us in connection with this offering. References to "Fund II" refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. References to "Lime Rock Resources" refer collectively to Fund I and Fund II. Our pro forma estimated proved reserve information as of December 31, 2010 and March 31, 2011 is based on reports prepared by Miller and Lents, Ltd. and Netherland, Sewell & Associates, Inc., our independent reserve engineers. A summary of our pro forma estimated proved reserve information as of March 31, 2011 prepared by (i) Miller and Lents, Ltd. is included in this prospectus in Appendix C and (ii) Netherland, Sewell & Associates, Inc. is included in this prospectus in Appendix D. We have included a glossary of some of the oil and natural gas terms used in this prospectus in Appendix B.


LRR Energy, L.P.

          We are a Delaware limited partnership formed in April 2011 by affiliates of Lime Rock Resources to operate, acquire, exploit and develop producing oil and natural gas properties in North America with long-lived, predictable production profiles. Our properties are located in the Permian Basin region in West Texas and southeast New Mexico, the Mid-Continent region in Oklahoma and East Texas and the Gulf Coast region in Texas. As of March 31, 2011, our total estimated proved reserves were approximately 30.3 MMBoe, of which approximately 84% were proved developed reserves (approximately 69% proved developed producing and approximately 15% proved developed non-producing). Approximately 57% of our pro forma revenues for the six months ended June 30, 2011 were from oil and natural gas liquids, or NGLs, and approximately 37% of our total estimated proved reserves were oil and NGLs as measured by volume. As of March 31, 2011, we operated 93% of our proved reserves. Based on our pro forma average net production of 6,133 Boe/d for the six months ended June 30, 2011, our total estimated proved reserves as of March 31, 2011 had a reserve-to-production ratio of approximately 13.5 years.

          Our general partner, LRE GP, LLC, is controlled by Lime Rock Management LP, or Lime Rock Management, which was founded in 1998 and manages approximately $3.9 billion of private capital for investment in the energy industry through its investment funds, Lime Rock Resources and Lime Rock Partners. Following its sale and contribution of oil and natural gas properties and related net profits interests and operations to us in connection with this offering, which we refer to as the Partnership Properties, Lime Rock Resources will own total estimated proved reserves of approximately 15.3 MMBoe as of March 31, 2011, of which approximately 79% are proved developed reserves, with pro forma average net production of approximately 3,983 Boe/d for the six months ended June 30, 2011. In addition, Lime Rock Resources has approximately $520 million of additional acquisition capacity that it expects to deploy over the next two years to purchase additional oil and natural gas properties that may be suitable for acquisition by us in the future.

          Lime Rock Resources has informed us that it intends, from time to time, to offer us the opportunity to purchase some of its mature, producing oil and natural gas assets and to participate in potential joint acquisition opportunities. However, neither Lime Rock Resources nor any of its affiliates

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is obligated to offer or sell any of their properties to us or share future joint acquisition opportunities with us following the consummation of this offering.


Our Properties

          Our properties consist of mature, low-risk onshore oil and natural gas reservoirs with long-lived, predictable production profiles located across three diverse producing regions: (i) the Permian Basin region in West Texas and southeast New Mexico, (ii) the Mid-Continent region in Oklahoma and East Texas and (iii) the Gulf Coast region in Texas.

          The following table summarizes pro forma information by producing region regarding our estimated net proved reserves and producing wells as of March 31, 2011 and our average net production for the six months ended June 30, 2011.

 
  Estimated Pro Forma Net Proved
Reserves as of March 31, 2011(1)
  Pro Forma
Average
Net Production
for the Six
Months Ended
June 30, 2011
   
  Producing
Wells as of
March 31,
2011
 
 
  Average
Reserve-to-
Production
Ratio(2)
 
 
   
  % of Total
Reserves
  % Proved
Developed
  % Oil
and
NGLs
  %
Operated
 
 
  MBoe   Gross   Net  
 
   
   
   
   
   
  (Boe/d)
  (years)
   
   
 

Permian Basin Region

    16,574     55 %   78 %   60 %   92 %   2,608     17.4     665     552  

Mid-Continent Region

    10,130     33 %   94 %   0 %   92 %   2,281     12.2     150     104  

Gulf Coast Region

    3,579     12 %   89 %   31 %   100 %   1,244     7.9     42     35  
                                       

All Regions

    30,283     100 %   84 %(3)   37 %   93 %   6,133     13.5     857     691  
                                               

(1)
Our estimated pro forma net proved reserves were computed by applying average trailing twelve-month index prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the applicable twelve-month period), held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The average trailing twelve-month index prices were $83.41/Bbl for NYMEX-WTI oil and $4.10/MMBtu for NYMEX-Henry Hub natural gas for the twelve months ended March 31, 2011. For NGL pricing, a differential is applied to the $83.41/Bbl average trailing twelve-month index price of oil.

(2)
The average reserve-to-production ratio is calculated by dividing estimated pro forma net proved reserves as of March 31, 2011 by pro forma net production for the six months ended June 30, 2011.

(3)
Approximately 69% of our total estimated proved reserves were proved developed producing and approximately 15% were proved developed non-producing.

          Based on our reserve reports as of March 31, 2011, the estimated decline rate for our existing proved developed producing reserves is approximately 12% per year for 2011 through 2015 and approximately 9% per year thereafter. As of March 31, 2011, our estimated proved developed non-producing reserves included 192 gross (158 net) recompletion, refracture stimulation and workover projects. In addition, as of March 31, 2011, our proved undeveloped reserves included 213 gross (140 net) identified drilling locations.


Our Hedging Strategy

          We plan to enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Our strategy includes entering into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved developed producing reserves over a three-to-five year period at a given point of time, although we may from time to time hedge more or less than this approximate range. Lime Rock Resources will contribute to us at the closing of this offering commodity derivative contracts covering approximately 85% of our estimated production for each of the years ending December 31, 2011 through 2015 from total proved developed producing reserves as of March 31, 2011 based on our reserve reports. These commodity derivative contracts will consist of natural gas, oil and NGL financial swaps and collar contracts and natural gas basis financial

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swaps. By removing a significant portion of price volatility associated with production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations for those periods. For a description of our commodity derivative contracts, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — Partnership Commodity Derivative Contracts."


Our Business Strategies

          Our primary business objective is to generate stable cash flows to allow us to make quarterly cash distributions to our unitholders and, over time, to increase our quarterly cash distributions. To achieve our objective, we intend to execute the following business strategies:

    Exploit opportunities on our current properties and manage our operating costs and capital expenditures.

    Pursue acquisitions of long-lived, low-risk producing oil and natural gas properties with reserve exploitation potential.

    Leverage our relationship with Lime Rock Resources to provide additional acquisition opportunities through drop-down transactions and joint acquisitions.

    Reduce the impact of commodity price volatility on our cash flows through an active hedging program.

    Maintain a balanced capital structure to allow for borrowing capacity to execute our business strategies.

          For a more detailed description of our business strategies, please read "Business and Properties — Our Business Strategies."


Our Competitive Strengths

          We believe the following competitive strengths will enable us to achieve our business strategies:

    Our diverse, predictable, long-lived reserve base with significant operational history under our control.

    Our significant inventory of low-risk projects on existing properties that we operate.

    Our relationship with Lime Rock Resources, which we expect will provide us with access to an inventory of additional mature oil and natural gas properties to acquire in drop-down transactions.

    Our experienced acquisition and operations team with a proven ability to identify, acquire and exploit long-lived oil and natural gas assets.

    Our balanced capital structure and financial flexibility.

          For a more detailed discussion of our competitive strengths, please read "Business and Properties — Our Competitive Strengths."


Our Principal Business Relationships

          Our general partner is controlled by Lime Rock Management. Lime Rock Management was founded in 1998 and manages approximately $3.9 billion of private capital for investment in the energy industry through its investment funds, Lime Rock Resources and Lime Rock Partners. Lime Rock Resources was formed by Lime Rock Management for the purpose of acquiring mature, low-risk producing oil and natural gas properties with long-lived production profiles, and currently consists of two investment funds, Fund I, formed in 2005, and Fund II, formed in 2008. Lime Rock Partners was formed by Lime Rock Management for the purpose of investing in energy companies worldwide in the exploration and production, energy service and oil service technology sectors of the oil and gas industry. Lime Rock Partners manages approximately $3.0 billion through five investment funds. Lime

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Rock Resources will be our largest unitholder following the consummation of this offering, owning an approximate 57.9% limited partner interest in us.

          As a result of their significant ownership interests in us and our general partner, we believe Lime Rock Management and Lime Rock Resources will be motivated to support the successful execution of our business strategy and will provide us with opportunities to pursue acquisitions that will be accretive to our unitholders. Additionally, the management and operations team that manages and operates Lime Rock Resources will manage and operate our properties. Please read "Management" for more information about our officers and directors and their relationship with Lime Rock Management, Lime Rock Resources and Lime Rock Partners.

Recent Developments

          Although we are in the early stages of compiling our financial results for the third quarter of 2011, our preliminary estimated results indicate our pro forma production to approximate 5,600 Boe/d for the three months ended September 30, 2011. Our pro forma production for the three months ended September 30, 2011 was negatively impacted by production curtailments at our predecessor's Pecos Slope and Red Lake fields which approximated 400 Boe/d during the third quarter of 2011. The curtailment in our Pecos Slope field production is due to the gas containing a nitrogen percentage greater than our predecessor's gas purchaser's specification. Our predecessor is actively working with its gas gatherer to reduce the nitrogen percentage to a level within specification. Production at our Red Lake field was curtailed due to a third party gas plant mechanical failure that has since been repaired. At this time approximately 220 Boe/d of production remains curtailed primarily at Pecos Slope and our predecessor currently expects the full restoration of that production during the second quarter of 2012.

          We anticipate our estimated pro forma revenues to approximate $47 million for the three months ended September 30, 2011. Pro forma revenues were $29.9 million for the three months ended June 30, 2011. The increase in our estimated pro forma revenues was primarily due to a hedging loss of approximately $8 million related to the termination of certain oil derivative contracts in the second quarter of 2011 and an approximate $21 million unrealized gain on our commodity derivative contracts during the three months ended September 30, 2011 primarily due to lower oil prices during the quarter. Due to the decline in commodity prices in the third quarter of 2011, our pro forma results will include a non-cash charge of approximately $17 million to impair the value of our proved oil and natural gas properties in the Mid-Continent Region. This charge does not impact our pro forma Adjusted EBITDA for the third quarter of 2011. We expect our Adjusted EBITDA for the third quarter of 2011 will be higher than our Adjusted EBITDA for the three months ended June 30, 2011. Based on our preliminary estimated results, we expect that we would have generated aggregate available cash sufficient to pay in full the aggregate minimum quarterly distribution on our common units, subordinated units and general partner units during the three months ended September 30, 2011.

          These results are preliminary and may differ from those ultimately reported in our future SEC filings. The preliminary financial data included in this prospectus has been prepared by, and is the responsibility of, LRR Energy, L.P. management. PricewaterhouseCoopers LLP has not audited, reviewed, compiled or performed any procedures with respect to the accompanying preliminary financial data. Accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto.

Fund II Acquisition

          In October 2011, Fund II completed the purchase of oil and natural gas properties located in Oklahoma from an undisclosed party for approximately $105 million.

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Risk Factors

          An investment in our common units involves risks. Below is a summary of certain key risk factors that you should consider in evaluating an investment in our common units. This list is not exhaustive. Please read the full discussion of these risks and other risks described under "Risk Factors."

Risks Related to Our Business

    We may not have sufficient cash to pay the minimum quarterly distribution on our units following the establishment of cash reserves and payment of expenses, including payments to our general partner.

    Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

    A decline in oil, natural gas or NGL prices will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether.

Risks Inherent in an Investment in Us

    Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with us, and owe limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of our unitholders.

    Lime Rock Resources, Lime Rock Partners and other affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets.

    Neither we nor our general partner have any employees and we rely solely on Lime Rock Management and Lime Rock Resources Operating Company, Inc., an affiliate of Lime Rock Resources that provides services to operate the oil and natural gas interests of Lime Rock Resources and that we refer to as Lime Rock Resources Operating Company, to manage our business. Most of our management team and the employees of Lime Rock Resources Operating Company will also provide substantially similar services to Lime Rock Resources, and thus will not be solely focused on our business.

    We have material weaknesses in our internal control over financial reporting. If one or more material weaknesses persist or if we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

    Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Affiliates of Lime Rock Management that control our general partner will have the power to control our operations.

    Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without approval of the conflicts committee of our general partner or unitholders. This may result in lower distributions to holders of our common units in certain situations.

    Control of our general partner may be transferred to a third party without unitholder consent.

    We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders' ownership interests.

    Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.

    Units held by persons who our general partner determines are not eligible holders will be subject to redemption.

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Tax Risks to Unitholders

    Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation, then our cash available for distribution to our unitholders would be substantially reduced.

    Our unitholders will be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.


Formation Transactions and Partnership Structure

          At the closing of this offering, the following transactions, which we refer to as the formation transactions, will occur:

    We will enter into a purchase, sale, contribution, conveyance and assumption agreement with Fund I pursuant to which Fund I will sell and contribute to us (i) the Partnership Properties and (ii) certain commodity derivative contracts covering approximately 85% of our estimated production for each of the years ending December 31, 2011 through 2015 from total proved developed producing reserves as of March 31, 2011 based on our reserve reports;

    We will assume approximately $27.3 million of LRR A's debt that currently burdens the Partnership Properties;

    We will enter into a new $500 million credit facility under which we expect to borrow $155.8 million at the closing of this offering;

    We will issue 9,408,000 common units to the public, representing a 42.0% limited partner interest in us;

    We will issue to Fund I an aggregate of 6,249,600 common units and 6,720,000 subordinated units, representing an aggregate 57.9% limited partner interest in us;

    We will issue to our general partner 22,400 general partner units, representing a 0.1% general partner interest in us, and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.54625 per unit per quarter;

    We will make a cash distribution to Fund I of approximately $18.1 million and we will repay in full the debt discussed in the second bullet above with funds from borrowings under our new credit facility, and we will pay to Fund I, in exchange for the Partnership Properties purchased from Fund I, approximately $271.8 million consisting first of proceeds from this offering and second from funds from borrowings under our new credit facility;

    We will enter into a services agreement with Lime Rock Management and Lime Rock Resources Operating Company pursuant to which management, administrative and operational services will be provided to our general partner and us to manage and operate our business; and

    We will enter into an omnibus agreement with Lime Rock Resources that will address certain indemnification matters.

          To the extent the underwriters exercise their option to purchase up to an additional 1,411,200 common units, the number of common units issued to Fund I (as reflected in the fifth bullet above) will decrease by, and the number of common units issued to the public (as reflected in the fourth bullet above) will increase by, the aggregate number of common units purchased by the underwriters pursuant to such exercise. The net proceeds from any exercise of the underwriters' option to purchase additional common units will be used to pay additional cash consideration to Fund I for the Partnership Properties and to make an additional cash distribution to Fund I.

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Ownership and Organizational Structure of LRR Energy, L.P.

          The diagram below illustrates our ownership and organizational structure based on total units outstanding after giving effect to this offering and the related formation transactions and assumes that the underwriters do not exercise their option to purchase additional common units.

 
  Ownership
Interest
 

Common units held by the public

    42.0 %

Common units held by Fund I

    27.9 %

Subordinated units held by Fund I

    30.0 %

General partner units

    0.1 %
       
 

Total

    100.0 %
       

GRAPHIC


(1)
Lime Rock Management LP is ultimately controlled by its co-founders, Jonathan C. Farber and John T. Reynolds, who are Managing Directors of Lime Rock Partners. Mr. Farber is also a director of LRE GP, LLC. Our general partner's non-independent directors and certain of our general partner's executive officers have financial interests in Lime Rock Management LP and its general partner.

(2)
Entities controlled by Messrs. Farber and Reynolds control each of the limited partnerships comprising Fund I and Fund II. Our non-independent directors and certain of our executive officers have financial interests in Fund I through ownership interests in its general partner entities.

(3)
Each of Fund I and Fund II owns a separate class of non-voting member interests (Class B and C, respectively) in our general partner that entitles it to receive, for a period of up to six years following the closing of this offering, 80% and 20%, respectively, of the distributions we make to our general partner on our incentive distribution rights. Our non-independent directors and certain of our executive officers also have financial interests in Fund II through ownership interests in its general partner entities.

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Principal Executive Offices and Internet Address

          Our principal executive offices are located at Heritage Plaza, 1111 Bagby Street, Suite 4600, Houston, Texas 77002, and our phone number is (713) 292-9510. Our website address is www.lrrenergy.com and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.


Management of LRR Energy, L.P.

          Our general partner has sole responsibility for conducting our business and for managing our operations. Lime Rock Management is the controlling member of our general partner and will have the right to elect all of the members of the board of directors of our general partner, with at least three of these directors meeting the independence standards established by the New York Stock Exchange, or NYSE. Three independent directors will be appointed prior to the date our common units are listed for trading on the NYSE. Our unitholders will not be entitled to elect our general partner or its officers and directors or otherwise directly participate in our management or operations. For more information about the executive officers and directors of our general partner, please read "Management — Directors and Executive Officers."

          Neither we, our general partner nor our operating subsidiary have any employees. Upon the closing of this offering, we will enter into a services agreement with Lime Rock Management and Lime Rock Resources Operating Company pursuant to which management, administrative and operational services will be provided to our general partner and us to manage and operate our business. For more information about the services agreement, please read "Management — Management of LRR Energy — Services Agreement."

          As is common with publicly traded partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries. We will initially have one subsidiary, LRE Operating, LLC, a Delaware limited liability company, that will conduct our operations.


Summary of Conflicts of Interest and Fiduciary Duties

General

          Our general partner has a legal duty to manage us in a manner beneficial to the holders of our common and subordinated units. This legal duty originates under state law in statutes and judicial decisions and is commonly referred to as a "fiduciary duty." However, the officers and directors of our general partner also have a fiduciary duty to manage the business of our general partner in a manner beneficial to its owners. Lime Rock Resources owns, holds and manages assets that are similar to ours and could compete with us. Lime Rock Partners' exploration and production portfolio companies also may own and manage assets that are similar to ours and could compete with us. In addition, certain of our general partner's executive officers and non-independent directors will continue to have economic interests, investments and other economic incentives in, as well as management and fiduciary duties to, Lime Rock Management and funds affiliated with Lime Rock Resources and Lime Rock Partners. As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its owners and affiliates, on the other hand. For example, our general partner is entitled to make determinations that affect our ability to generate the cash flows necessary to make cash distributions to our unitholders, including determinations related to:

    purchases and sales of oil and natural gas properties and other acquisitions and dispositions, including whether to pursue acquisitions that are also suitable for Lime Rock Resources;

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    the manner in which our business is operated;

    the level of our borrowings;

    the amount, nature and timing of our capital expenditures; and

    the amount of cash reserves necessary or appropriate to satisfy our general, administrative and other expenses and debt service requirements and to otherwise provide for the proper conduct of our business.

          These determinations will have an effect on the amount of cash distributions we make to the holders of our units, which in turn has an effect on whether our general partner receives incentive cash distributions.

          For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read "Risk Factors — Risks Inherent in an Investment in Us" and "Conflicts of Interest and Fiduciary Duties."

          Our partnership agreement may not be amended during the subordination period without the approval of our public common unitholders, other than in certain limited circumstances where no unitholder approval is required. However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by Lime Rock Resources and its affiliates). Upon consummation of this offering, Lime Rock Resources will own an approximate 57.9% limited partner interest in us (51.6% if the underwriters exercise their over-allotment option in full). Assuming that we do not issue any additional common units and Fund I does not transfer the common and subordinated units that it owns, Lime Rock Resources will have the ability to amend our partnership agreement, including our policy to distribute all of our available cash to our unitholders, without the approval of any other unitholder once the subordination period ends. Please see "Risk Factors — Risks Inherent in an Investment in Us" and "The Partnership Agreement — Amendment of the Partnership Agreement."

Partnership Agreement Modification of Fiduciary Duties

          Delaware law provides that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by the general partner to the limited partners and the partnership. Our partnership agreement limits the liability of our general partner and reduces the fiduciary duties it owes to holders of our common and subordinated units. Our partnership agreement also restricts the remedies available to holders of our common and subordinated units for actions that might otherwise constitute a breach of the fiduciary duties that our general partner owes to our unitholders. By purchasing a common unit, unitholders agree to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, are treated as having consented to various actions contemplated in our partnership agreement and to conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read "Conflicts of Interest and Fiduciary Duties — Fiduciary Duties" for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to our unitholders.

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The Offering

Common units offered by us   9,408,000 common units.
    10,819,200 common units if the underwriters exercise in full their option to purchase additional common units.
Units outstanding after this offering   15,657,600 common units* and 6,720,000 subordinated units, representing a 69.9% and 30.0%, respectively, limited partner interest in us.
    If the underwriters do not exercise their option to purchase up to an additional 1,411,200 common units, we will issue that number of common units to Fund I at the expiration of the option period as additional consideration for the Partnership Properties. To the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remainder of the common units that are subject to the option, if any, will be issued to Fund I at the expiration of the option period. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.
    In addition, our general partner will own 22,400 general partner units, representing a 0.1% general partner interest in us.
Use of proceeds   We intend to use the estimated net proceeds of approximately $167.2 million from this offering, after deducting underwriting discounts and a structuring fee, together with borrowings of approximately $155.8 million under our new revolving credit facility, to:
   

•       make cash distributions and payments to Fund I of approximately $289.9 million;

   

•       repay in full $27.3 million of LRR A's debt that we will assume at the closing of this offering;

   

•       pay fees and expenses of approximately $1.9 million relating to our new credit facility; and

   

•       pay estimated offering expenses of approximately $3.9 million.

    If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds would be approximately $25.1 million. The net proceeds from any exercise of such option will be used to pay additional cash consideration to Fund I for the Partnership Properties and to make an additional cash distribution to Fund I. Please read "Use of Proceeds."
*
Excludes equity grants subject to issuance under our long-term incentive plan. For information regarding anticipated equity grants to certain officers and directors, please read "Security Ownership of Certain Beneficial Owners and Management."

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Cash distributions   We intend to pay a minimum quarterly distribution of $0.4750 per unit ($1.90 per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and the payment of expenses, including payments to our general partner and its affiliates. We refer to this cash as "available cash," and it is defined in our partnership agreement included in this prospectus as Appendix A.

 

 

Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail in "Our Cash Distribution Policy and Restrictions on Distributions." For the first quarter that we are publicly traded, we will pay our unitholders a prorated distribution covering the period from the completion of this offering through December 31, 2011, based on the actual length of that period.

 

 

Assuming our general partner maintains its 0.1% general partner interest in us, our partnership agreement requires us to distribute all of our available cash each quarter in the following manner during the subordination period:

 

•       first, 99.9% to the holders of common units, pro rata, and 0.1% to our general partner, until each common unit has received the minimum quarterly distribution of $0.4750 plus any arrearages from prior quarters;

 

•       second, 99.9% to the holders of subordinated units, pro rata, and 0.1% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $0.4750; and

 

•       third, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unit has received a distribution of $0.54625.


 

 

If cash distributions to our unitholders exceed $0.54625 per common unit and subordinated unit in any quarter, our unitholders and our general partner will receive distributions according to the following percentage allocations:

 

 
   
  Marginal Percentage
Interest in Distributions
 
 
 
Total Quarterly Distribution Target Amount
  Unitholders   General Partner  

  above $0.54625 up to $0.59375     86.9 %   13.1 %

  above $0.59375     76.9 %   23.1 %

 

    The percentage interests shown for our general partner include its 0.1% general partner interest. We refer to the additional increasing distributions to our general partner in excess of its 0.1% general partner interest as "incentive distributions." Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

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    Upon the closing of this offering, Fund I and Fund II will hold non-voting member interests in our general partner that will entitle them to receive 80% and 20%, respectively, of the distributions with respect to the incentive distribution rights owned by our general partner for a period of six years following the closing of this offering. After the expiration of the six-year period, Fund I's and Fund II's non-voting member interests in our general partner will be cancelled and Lime Rock Management will be entitled to receive all of the distributions made to our general partner, including any incentive distributions. For a more detailed description of Fund I's and Fund II's interests in our general partner, please read "Certain Relationships and Related Party Transactions — Limited Liability Company Agreement of Our General Partner."

 

 

If we had completed the formation transactions contemplated in this prospectus and the acquisition of the Partnership Properties on January 1, 2010, our unaudited pro forma available cash generated during the year ended December 31, 2010 would have been approximately $62.7 million. If we had completed the formation transactions contemplated in this prospectus and the acquisition of the Partnership Properties on July 1, 2010, our pro forma cash generated during the twelve months ended June 30, 2011 would have been approximately $51.0 million. The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units, subordinated units and general partner units to be outstanding upon the closing of this offering is approximately $42.6 million (or an average of approximately $10.6 million per quarter). As a result, for the year ended December 31, 2010 and the twelve months ended June 30, 2011, we would have generated aggregate available cash sufficient to pay the aggregate minimum quarterly distribution on our common units, subordinated units and general partner units during such periods. We have not calculated available cash on a pro forma quarter-by-quarter basis for the year ended December 31, 2010 or the twelve months ended June 30, 2011 to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each quarter during those periods. For a calculation of our ability to have made distributions to our unitholders based on our pro forma results of operations for the year ended December 31, 2010 and the twelve months ended June 30, 2011, please read "Our Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended June 30, 2011."

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    We believe, based on our financial forecast and related assumptions included in "Our Cash Distribution Policy and Restrictions On Distributions," that we will have sufficient available cash to pay the minimum quarterly distribution of $0.4750 per unit ($1.90 per unit on an annualized basis) on all common, subordinated and general partner units for the twelve months ending September 30, 2012. Please read "Our Cash Distribution Policy and Restrictions on Distributions — Estimated Unaudited Adjusted EBITDA for the Twelve Months Ending September 30, 2012."

Subordinated units

 

Fund I will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, the subordinated units are entitled to receive the minimum quarterly distribution only after the common units have received their minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages.

Subordination Period

 

The subordination period will begin on the closing date of this offering and will extend until the first business day of any quarter after December 31, 2014 that we have earned and paid from operating surplus, in the aggregate, distributions on each outstanding common unit, subordinated unit and general partner unit and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaling or exceeding the minimum quarterly distribution payable with respect to a period of twelve consecutive quarters immediately preceding such date, provided there are no arrearages in the minimum quarterly distribution on our common units at that time. However, three separate one third tranches of subordinated units may convert on the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2012, December 31, 2013 and December 31, 2014, respectively, provided that an aggregate amount equal to the minimum quarterly distribution payable with respect to all units that would be payable on four, eight or twelve consecutive quarters, as applicable, has been earned and paid prior to the applicable date, in each case provided there are no arrearages in the minimum quarterly distribution on our common units at that time.

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    In addition, the subordination period will end on the first business day after we have earned and paid from operating surplus at least (i) $0.54625 per quarter (115% of the minimum quarterly distribution, which is $2.185 on an annualized basis) on each outstanding common and subordinated unit and the corresponding distributions on our general partner's 0.1% interest and the incentive distribution rights for any four quarter period ending on or after December 31, 2013, or (ii) $0.59375 per quarter (125% of the minimum quarterly distribution, which is $2.375 on an annualized basis) on each outstanding common and subordinated unit and the corresponding distributions on our general partner's 0.1% interest and the incentive distribution rights for any four quarter period, in each case provided there are no arrearages in the minimum quarterly distribution on our common units at that time.

 

 

The subordination period will also end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.

 

 

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period."

Issuance of additional units

 

We can issue an unlimited number of additional units, including units that are senior to the common units in right of distributions, liquidation and voting, on terms and conditions determined by our general partner, without the approval of our unitholders. Please read "Units Eligible for Future Sale" and "The Partnership Agreement — Issuance of Additional Interests."

Limited voting rights

 

Our general partner will manage us and operate us. Unlike stockholders of a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will not have the right to elect our general partner or its board of directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, Lime Rock Resources will own an aggregate of approximately 58.0% of our outstanding common and subordinated units (or 51.7% of our outstanding common and subordinated units if the underwriters exercise their option to purchase additional units in full) and therefore, will be able to prevent the removal of our general partner. Please read "The Partnership Agreement — Limited Voting Rights."

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Limited call right   If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price equal to the greater of (1) the highest cash price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed and (2) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed. Upon the consummation of this offering, Lime Rock Resources will own an aggregate of 39.9% of our common units. Please read "The Partnership Agreement — Limited Call Right."

Eligible Holders and redemption

 

Units held by persons who our general partner determines are not Eligible Holders will be subject to redemption. As used herein, an Eligible Holder means any person or entity qualified to hold an interest in oil and natural gas leases on federal lands. If, following a request by our general partner, a unitholder does not properly complete a certification for any reason, we will have the right to redeem the units held by such person at the then-current market price of the units held by such person. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read "Description of the Common Units — Transfer of Common Units" and "The Partnership Agreement — Non-Eligible Holders; Redemption."

Estimated ratio of taxable income to distributions

 

We estimate that if our unitholders own the common units purchased in this offering through the record date for distributions for the period ending December 31, 2014, such unitholders will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 30% of the cash distributed to such unitholders with respect to that period. For example, if you receive an average annual distribution of $1.90 per unit, we estimate that your average allocable federal taxable income per year through December 31, 2014 will be no more than approximately $0.57 per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read "Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions" for the basis of this estimate.

Material tax consequences

 

For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read "Material Tax Consequences."

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Directed unit program   At our request, the underwriters have reserved up to 5% of the common units being offered by this prospectus for sale at the initial public offering price to the officers, directors and employees of our general partner and its affiliates and certain other persons associated with us, as designated by us. For further information regarding our directed unit program, please read "Underwriting — Directed Unit Program."

Agreement to be bound by the partnership agreement

 

By purchasing a common unit, you will be admitted as a unitholder of our partnership and will be deemed to have agreed to be bound by all the terms of our partnership agreement.

Exchange listing

 

We have been approved to list our common units on the NYSE, subject to official notice of issuance, under the symbol "LRE".

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Summary Historical and Pro Forma Financial Data

          We were formed in April 2011 and do not have historical financial operating results. Therefore, in this prospectus, we present the historical financial statements of our predecessor, which consists of the combined financial statements of LRR A, LRR B and LRR C. The following table presents summary historical combined financial data of our predecessor and summary pro forma financial data of LRR Energy as of the dates and for the periods indicated. The summary historical financial data as of December 31, 2009 and 2010 and for the years ended December 31, 2008, 2009 and 2010 are derived from the audited historical combined financial statements of our predecessor included elsewhere in this prospectus. The balance sheet data as of December 31, 2008 is derived from the audited combined historical financial statements of our predecessor not included in this prospectus. The summary historical financial data as of June 30, 2011 and for the six months ended June 30, 2010 and 2011 are derived from the unaudited historical combined financial statements of our predecessor included elsewhere in this prospectus.

          The summary unaudited pro forma financial data as of June 30, 2011 and for the six months ended June 30, 2011 and the year ended December 31, 2010 are derived from the unaudited pro forma condensed financial statements of LRR Energy included elsewhere in this prospectus. Our unaudited pro forma condensed financial statements give pro forma effect to the following:

    the contribution and sale by Fund I to us of the Partnership Properties in exchange for an aggregate of 6,249,600 common units, 6,720,000 subordinated units and $289.9 million in cash;

    the issuance to our general partner of 22,400 general partner units, representing a 0.1% general partner interest in us, and the incentive distribution rights;

    our assumption of approximately $27.3 million of LRR A's debt that currently burdens the Partnership Properties;

    the issuance and sale by us to the public of 9,408,000 common units in this offering and the application of the net proceeds as described in "Use of Proceeds"; and

    our borrowing of approximately $155.8 million under our new revolving credit facility and the application of the proceeds as described in "Use of Proceeds," including the repayment in full of the assumed debt discussed in the third bullet above.

          The unaudited pro forma balance sheet data assume the events listed above occurred as of June 30, 2011. The unaudited pro forma statement of operations data for the six months ended June 30, 2011 and the year ended December 31, 2010 assume the items listed above occurred as of January 1, 2010. We have not given pro forma effect to incremental selling, general and administrative expenses of approximately $2.5 million that we expect to incur annually as a result of being a publicly traded partnership.

          You should read the following table in conjunction with "— Formation Transactions and Partnership Structure," "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations," the historical combined financial statements of our predecessor and the unaudited pro forma condensed financial statements of LRR Energy and the notes thereto included elsewhere in this prospectus. Among other things, those historical combined financial statements and unaudited pro forma condensed financial statements include more detailed information regarding the basis of presentation for the following information.

          The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in evaluating the financial performance and liquidity of our business. This measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to the most directly comparable financial measures calculated and presented in accordance with GAAP.

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  Predecessor   LRR Energy, L.P.
Pro Forma
 
 
  Year Ended December 31,   Six Months
Ended
June 30,
  Year Ended
December 31,
  Six Months
Ended
June 30,
 
 
  2008   2009   2010   2010   2011   2010   2011  
 
   
   
   
  (unaudited)
  (unaudited)
 
 
  (in thousands)
 

Statement of Operations Data:

                                           

Revenues:

                                           
 

Oil sales

  $ 58,852   $ 34,604   $ 52,670   $ 25,969   $ 34,661   $ 31,850   $ 20,171  
 

Natural gas sales

    100,378     33,798     48,088     25,186     21,754     42,722     19,452  
 

Natural gas liquids sales

    20,393     10,617     14,748     7,431     7,758     10,935     5,728  
 

Realized gain (loss) on commodity derivative instruments

    (2,676 )   70,902     48,029     23,264     41     35,541     29  
 

Unrealized gain (loss) on commodity derivative instruments

    117,757     (62,375 )   (23,964 )   2,040     (3,109 )   (17,733 )   (2,207 )
 

Other income

    18     24     116     46     80     116     80  
                               
   

Total revenues

    294,722     87,570     139,687     83,936     61,185     103,431     43,253  

Operating expenses:

                                           
 

Lease operating expenses

    18,781     19,066     23,804     10,443     11,935     19,080     9,301  
 

Production and ad valorem taxes

    13,899     6,731     9,320     5,067     3,020     7,755     1,632  
 

Depletion and depreciation

    79,477     56,349     55,828     29,584     20,871     40,673     15,397  
 

Impairment of oil and gas properties

    121,561         11,712     10,944         11,712      
 

Accretion expense

    691     1,255     1,366     669     744     1,178     666  
 

(Gain) loss on settlement of asset retirement obligations

    250     (1,570 )   (209 )           (242 )    
 

Management fees

    8,500     8,500     6,104     3,803     2,967          
 

General and administrative expenses

    2,493     2,408     5,293     3,672     3,206     8,901     4,773  
                               
   

Total operating expenses

    245,652     92,739     113,218     64,182     42,743     89,057     31,769  

Operating income (loss)

   
49,070
   
(5,169

)
 
26,469
   
19,754
   
18,442
   
14,374
   
11,484
 

Other income (expense), net:

                                           
 

Interest income

    623     87     17     5     1          
 

Interest expense

    (2,131 )   (1,274 )   (3,223 )   (728 )   (559 )   (4,824 )   (2,412 )
 

Realized gain (loss) on interest rate derivative instruments

    (71 )   (457 )   (649 )   (324 )   (298 )        
 

Unrealized gain (loss) on interest rate derivative instruments

    (709 )   95     (248 )   (332 )   163          
                               
 

Other income (expense), net

    (2,288 )   (1,549 )   (4,103 )   (1,379 )   (693 )   (4,824 )   (2,412 )
                               

Income (loss) before taxes

    46,782     (6,718 )   22,366     18,375     17,749     9,550     9,072  

Income tax benefit (expense)

   
(971

)
 
622
   
(32

)
 
59
   
(146

)
 
   
 
                               

Net income (loss)

  $ 45,811   $ (6,096 ) $ 22,334   $ 18,434   $ 17,603   $ 9,550   $ 9,072  
                               

Other Financial Data:

                                           

Adjusted EBITDA

  $ 133,292   $ 113,240   $ 119,130   $ 58,911   $ 43,166   $ 85,428   $ 29,754  

Cash Flow Data:

                                           

Net cash provided by operating activities

  $ 139,236   $ 108,148   $ 121,269   $ 58,187   $ 37,994              

Net cash used in investing activities

    (217,986 )   (25,129 )   (125,846 )   (111,888 )   (23,585 )            

Net cash provided by (used in) financing activities

    117,758     (118,151 )   1,505     62,978     (20,831 )            

 

 
  Predecessor   LRR Energy, L.P.
Pro Forma
 
 
  As of December 31,   As of
June 30,
  As of
June 30,
 
 
  2008   2009   2010   2011   2011  
 
   
   
   
  (unaudited)
  (unaudited)
 
 
  (in thousands)
 

Balance Sheet Data:

                               

Working capital

  $ 113,846   $ 57,466   $ 33,209   $ 25,665   $ 9,043  

Total assets

    593,866     465,691     504,622     492,953     399,119  

Total debt

    32,250     24,150     27,251     27,251     155,800  

Partners' capital

    521,784     405,646     426,733     423,505     218,967  

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Non-GAAP Financial Measures

          We include in this prospectus the non-GAAP financial measure Adjusted EBITDA and provide reconciliations of Adjusted EBITDA to net income and net cash provided by operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):

    Plus:

    Income tax expense (benefit);

    Interest expense-net, including realized and unrealized losses on interest rate derivative contracts;

    Depletion and depreciation;

    Accretion of asset retirement obligations;

    Gain (loss) on settlement of asset retirement obligations;

    Unrealized losses on commodity derivative contracts;

    Impairment of oil and natural gas properties; and

    Other non-recurring items that we deem appropriate.

    Less:

    Interest income;

    Unrealized gains on commodity derivative contracts; and

    Other non-recurring items that we deem appropriate.

          Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:

    our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis;

    the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and

    our ability to incur and service debt and fund capital expenditures.

          Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.

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Reconciliation of Adjusted EBITDA to Net Income

 
  Our Predecessor   LRR Energy, L.P.
Pro Forma
 
 
   
   
   
  Six Months Ended
June 30,
   
   
 
 
  Year Ended December 31,    
   
 
 
  Year Ended
December 31,
2010
  Six Months Ended
June 30,
2011
 
 
  2008   2009   2010   2010   2011  
 
   
   
   
  (unaudited)
  (unaudited)
 
 
  (in thousands)
 

Net income (loss)

  $ 45,811   $ (6,096 ) $ 22,334   $ 18,434   $ 17,603   $ 9,550   $ 9,072  

Income tax expense (benefit)

    971     (622 )   32     (59 )   146          

Interest expense — net, including realized and unrealized losses on interest rate derivative instruments

    2,911     1,636     4,120     1,384     694     4,824     2,412  

Depletion and depreciation

    79,477     56,349     55,828     29,584     20,871     40,673     15,397  

Accretion of asset retirement obligations

    691     1,255     1,366     669     744     1,178     666  

Gain (loss) on settlement of asset retirement obligations

    250     (1,570 )   (209 )           (242 )    

Unrealized losses on commodity derivative instruments

        62,375     23,964         3,109     17,733     2,207  

Impairment of oil and natural gas properties

    121,561         11,712     10,944         11,712      

Interest income

    (623 )   (87 )   (17 )   (5 )   (1 )        

Unrealized gain on commodity derivative instruments

    (117,757 )           (2,040 )            
                               

Adjusted EBITDA

  $ 133,292   $ 113,240   $ 119,130   $ 58,911   $ 43,166   $ 85,428   $ 29,754  
                               

Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities

 
  Our Predecessor    
   
 
 
  Year Ended December 31,   Six Months Ended
June 30,
   
   
 
 
  2008   2009   2010   2010   2011    
   
 
 
   
   
   
  (unaudited)
   
   
 
 
  (in thousands)
   
   
 

Net cash provided by operating activities

  $ 139,236   $ 108,148   $ 121,269   $ 58,187   $ 37,994              

Change in working capital

    (8,443 )   4,187     (5,888 )   (206 )   4,210              

Interest expense, net

    1,528     1,527     3,717     989     816              

Income tax expense (benefit)

    971     (622 )   32     (59 )   146              
                                   

Adjusted EBITDA

  $ 133,292   $ 113,240   $ 119,130   $ 58,911   $ 43,166              
                                   

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Summary Reserve and Pro Forma Operating Data

          The following tables present summary data with respect to the estimated net proved oil and natural gas reserves of the Partnership Properties as of December 31, 2010 and March 31, 2011 and pro forma operating data for the Partnership Properties for the year ended December 31, 2010 and the six months ended June 30, 2011. The reserve estimates attributable to the Partnership Properties as of December 31, 2010 and March 31, 2011 presented in the table below are based on reports prepared by (i) Miller and Lents, Ltd., or Miller and Lents, independent reserve engineers, and (ii) Netherland, Sewell & Associates, Inc., or Netherland Sewell, independent reserve engineers. These reserve estimates were prepared in accordance with the SEC's rules regarding oil and natural gas reserve reporting that are currently in effect. The following table also contains certain summary unaudited information regarding production and sales of oil and natural gas with respect to such properties.

          Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business and Properties — Oil and Natural Gas Data and Operations — Partnership Properties — Estimated Proved Reserves," and the summaries of our reserve reports for March 31, 2011 included in this prospectus in evaluating the material presented below. The summaries of our reserve reports for December 31, 2010 are included as exhibits to the registration statement of which this prospectus is a part.

Reserve Data

 
  Partnership Properties  
 
  As of
December 31,
2010
  As of
March 31,
2011
 

Estimated Proved Reserves:

             
 

Oil (MBbls)

    4,312     7,362  
 

NGLs (MBbls)

    2,498     3,764  
 

Natural gas (MMcf)

    102,774     114,939  
           
 

Total (MBoe)(1)

    23,939     30,283  
 

Proved developed (MBoe)

    22,500     25,549  
 

Proved undeveloped (MBoe)

    1,439     4,734  
 

Proved developed reserves as a percentage of total proved reserves(2)

    94 %   84 %
 

Standardized measure (in millions)(3)

  $ 285.5   $ 342.3  

Oil and Natural Gas Prices(4):

             
 

Oil — NYMEX — WTI per Bbl

  $ 79.43   $ 83.41  
 

Natural gas — NYMEX — Henry Hub per MMBtu

  $ 4.38   $ 4.10  

(1)
One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.

(2)
Approximately 69% of our total estimated proved reserves were proved developed producing and approximately 15% were proved developed non-producing as of March 31, 2011.

(3)
Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions. We expect to hedge a substantial portion of our future estimated production from total proved producing reserves. For a description of our expected commodity derivative contracts, please read "Management's Discussion

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    and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — Partnership Commodity Derivative Contracts."

(4)
Our estimated net proved reserves and standardized measure were computed by applying average trailing twelve-month index prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the applicable twelve-month period), held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2010, the relevant average realized prices for oil, natural gas and NGLs were $75.17 per Bbl, $4.23 per Mcf and $41.36 per Bbl, respectively. As of March 31, 2011, the relevant average realized prices for oil, natural gas and NGLs were $78.84 per Bbl, $3.94 per Mcf and $42.72 per Bbl, respectively.

Pro Forma Operating Data

 
  LRR Energy, L.P.
Pro Forma
 
 
   
  Six Months Ended June 30,  
 
  Year Ended
December 31,
2010
 
 
  2010   2011  
 
  (unaudited)
 

Net Production:

                   
 

Total production (MBoe)

    2,389     1,144     1,110  
 

Average net production (Boe/d)

    6,546     6,320     6,133 (1)

Average Realized Sales Price (excluding derivatives):

                   
 

Oil (per Bbl)

  $ 75.12   $ 74.72   $ 91.69  
 

Natural gas (per Mcf)

  $ 4.22   $ 4.54   $ 4.17  
 

NGLs (per Bbl)

  $ 39.19   $ 40.59   $ 51.14  

Average Realized Sales Price per Boe (excluding derivatives):

  $ 35.79   $ 37.12   $ 40.86  

Average Realized Sales Price (including derivatives)

                   
 

Oil (per Bbl)

  $ 103.32   $ 105.52   $ 60.05 (2)
 

Natural gas (per Mcf)

  $ 6.55   $ 6.74   $ 5.67  
 

NGLs (per Bbl)

  $ 39.19   $ 40.59   $ 51.14  

Average Realized Sales Price per Boe (including derivatives)

  $ 50.66   $ 51.96   $ 40.89  

Average Unit Costs per Boe:

                   
 

Lease operating expenses

  $ 7.99   $ 7.52   $ 8.38  
 

Production and ad valorem taxes

  $ 3.25   $ 3.45   $ 1.47  
 

General and administrative expenses(3)

  $ 3.73   $ 4.81   $ 4.30  
 

Depletion and depreciation

  $ 17.03   $ 17.78   $ 13.87  

(1)
For further information regarding our production in the second quarter of 2011, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Results of Operations — Pro Forma Six Months Ended June 30, 2011 Compared to Pro Forma Six Months Ended June 30, 2010 — Sales Revenues."

(2)
Includes an allocated hedging loss of approximately $8.1 million, or $36.99 per Bbl, related to the termination of certain oil derivative contracts in the second quarter of 2011.

(3)
Pro forma general and administrative expenses do not include the additional expenses we would have incurred as a publicly traded partnership. We estimate these additional expenses would have been $2.5 million, or $1.05 per Boe, for the year ended December 31, 2010 and $1.3 million, or $1.13 per Boe, for the six months ended June 30, 2011 on a pro forma basis.

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RISK FACTORS

          Limited partner interests are inherently different from the capital stock of a corporation. Prospective unitholders should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

          If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and our unitholders could lose all or part of their investment.


Risks Related to Our Business

We may not have sufficient cash to pay the minimum quarterly distribution on our units following the establishment of cash reserves and payment of expenses, including payments to our general partner.

          We may not have sufficient available cash each quarter to pay the minimum quarterly distribution of $0.4750 per unit (or $10.6 million per quarter in the aggregate), or any distribution at all, on our units. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including development of our oil and gas properties, future debt service requirements and future cash distributions to our unitholders. The amount of cash we distribute on our units principally depends on the cash we generate from operations, which depends on, among other things:

    the amount of oil, NGLs and natural gas we produce;

    the prices at which we sell our oil, NGL and natural gas production;

    the amount and timing of settlements on our commodity and interest rate derivatives;

    the level of our capital expenditures;

    the level of our operating costs, including development costs and payments to our general partner; and

    the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon.

The assumptions underlying the forecast of cash available for distribution we include in "Our Cash Distribution Policy and Restrictions on Distributions" may prove inaccurate and are subject to significant risks and uncertainties which could cause actual results to differ materially from our forecasted results.

          Our management's forecast of cash available for distribution set forth in "Our Cash Distribution Policy and Restrictions on Distributions" includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending September 30, 2012. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results. If our actual results are significantly below forecasted results, we may not generate enough cash available for distribution to pay the minimum quarterly distribution or any amount on our common units or subordinated units, which may cause the market price of our common units to decline materially.

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Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

          We may be unable to sustain our minimum quarterly distribution without substantial capital expenditures that maintain our asset base. Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production and therefore our cash flow and ability to make distributions are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production at economically acceptable terms, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution to our unitholders.

Our development operations require substantial capital expenditures, which will reduce our cash available for distribution and could materially affect our ability to make distributions to our unitholders.

          The development and production of our oil and natural gas reserves requires substantial capital expenditures, which will reduce the amount of cash available for distribution to our unitholders. Further, if the borrowing base under our new credit facility or our revenues decrease as a result of lower oil or natural gas prices, we may not be able to obtain the capital necessary to sustain our operations at the expected levels necessary to generate an amount of cash sufficient to make distributions to our unitholders.

A decline in oil, natural gas or NGL prices will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether.

          Lower oil and natural gas prices may decrease our revenues and thus cash available for distribution to our unitholders. Historically, oil and natural gas prices have been extremely volatile. For example, for the five years ended December 31, 2010, the NYMEX-WTI oil price ranged from a high of $145.29 per Bbl to a low of $31.41 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $13.31 per MMBtu to a low of $1.83 per MMBtu. A significant decrease in commodity prices may cause us to reduce the distributions we pay to our unitholders or we may cease paying distributions.

If commodity prices decline and remain depressed for a prolonged period, a significant portion of our development projects may become uneconomic and cause write downs of the value of our oil and natural gas properties, which may adversely affect our financial condition and our ability to make distributions to our unitholders.

          Significantly lower oil and natural gas prices may render many of our development and production projects uneconomical and result in a downward adjustment of our reserve estimates, which would negatively impact our borrowing base and ability to fund our operations. As a result, we may reduce the amount of distributions paid to our unitholders or cease paying distributions.

          Further, deteriorating commodity prices may cause us to recognize impairments in the value of our oil and natural gas properties. In addition, if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our new credit facility to pay distributions to our unitholders.

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An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could significantly reduce our cash available for distribution and adversely affect our financial condition.

          The hedged prices that we receive for our oil and natural gas production often reflect a regional discount based on the location of production to the relevant benchmark prices used for calculating hedge positions, such as NYMEX. These discounts, if significant, could reduce our cash available for distribution to our unitholders and adversely affect our financial condition.

Our hedging strategy may be ineffective in removing the impact of commodity price volatility from our cash flows, which could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders.

          We expect to enter into commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved developed producing reserves over any subsequent three-to-five year period. The prices at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production.

Our hedging activities could result in cash losses, could reduce our cash available for distributions and may limit potential gains.

          Many of the derivative contracts that we will be a party to will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.

Our hedging transactions expose us to counterparty credit risk.

          Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty's liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.

          It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering is complex, requiring subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. For example, if the prices used in our March 31, 2011 reserve reports had been $10.00 less per barrel for oil and $1.00 less per MMBtu for natural gas, then the standardized measure of our estimated proved reserves as of that date on a pro forma basis would have decreased by $91.7 million, from $342.3 million to $250.6 million.

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          Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.

          The present value of future net cash flows from our proved reserves, or standardized measure, may not be the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the FASB in Accounting Standards Codification ("ASC") 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

          Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. Furthermore, our development and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

    high costs, shortages or delivery delays of rigs, equipment, labor or other services;

    unexpected operational events and conditions;

    adverse weather conditions and natural disasters;

    facility or equipment malfunctions, including pipe or cement failures, casing collapses or other downhole failures;

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

    loss of drilling fluid circulation;

    fires, blowouts, surface craterings and explosions;

    title problems; and

    uncontrollable flows of oil, natural gas or well fluids.

          If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and cash available for distribution to our unitholders.

Our expectations for future drilling activities are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.

          We have identified and scheduled drilling locations as an estimation of our multi-year drilling activities on our acreage. These identified drilling locations represent a significant part of our growth

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strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs and drilling results. Because of these uncertainties, there may be significant delays in timing or we may realize lower than anticipated amounts of estimated proved reserves. Our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our financial condition and results of operations and as a result, ability to make cash distributions to our unitholders.

Shortages of rigs, equipment and crews could delay our operations and reduce our cash available for distribution to our unitholders.

          Higher oil and natural gas prices generally increase the demand for rigs, equipment and crews and can lead to shortages of, and increasing costs for, development equipment, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and reduce our cash available for distribution to our unitholders.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.

          Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in available cash per unit. We may be unable to make such acquisitions because we are:

    unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners;

    unable to obtain financing for these acquisitions on economically acceptable terms; or

    outbid by competitors.

          If we are unable to acquire properties containing estimated proved reserves, our total level of estimated proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions to our unitholders.

Any acquisitions we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders.

          One of our growth strategies is to capitalize on opportunistic acquisitions of oil and gas reserves. Even if we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:

    the validity of our assumptions about estimated proved reserves, future production, commodity prices, revenues, capital expenditures, operating expenses and costs;

    an inability to successfully integrate the assets we acquire;

    an inability to obtain satisfactory title to the assets we acquire;

    a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

    a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

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    the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our 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 our growing assets; and

    the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

          Our 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 data and other information, the results of which are often inconclusive and subject to various interpretations.

          Also, our 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, given time constraints imposed by sellers. 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. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.

None of the proceeds of this offering will be used to maintain the current production levels of our oil and natural gas properties or the current operating capacity of our other capital assets or be reserved for future distributions.

          None of the proceeds of this offering will be used to maintain the current production levels of our oil and natural gas properties or the current operating capacity of our other capital assets, which may be necessary to cover future distributions to our unitholders, and none of the proceeds will be reserved for future distributions to our unitholders. The proceeds of this offering, together with borrowings under our new credit facility, will be used as consideration for the properties sold and contributed to us by Fund I in connection with this offering and the repayment of assumed debt related to such properties.

Adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

          We only own oil and natural gas properties and related assets, all of which are located in New Mexico, Oklahoma and Texas. An adverse development in the oil and natural gas business of these geographic areas could have an impact on our results of operations and cash available for distribution to our unitholders.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.

          The oil and natural gas industry is intensely competitive and we compete with companies that possess and employ financial, technical and personnel resources substantially greater than ours. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural 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 natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and

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future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations and our ability to make distributions to our unitholders.

We may incur additional debt to enable us to pay our quarterly distributions, which may negatively affect our ability to pay future distributions or execute our business plan.

          We may be unable to pay the minimum quarterly distribution without borrowing under our new credit facility. If we use borrowings under our new credit facility to pay distributions to our unitholders for an extended period of time rather than to fund capital expenditures and other activities relating to our operations, we may be unable to maintain or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition and results of operations. If we borrow to pay distributions to our unitholders during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution to our unitholders to avoid excessive leverage.

We expect that our new credit facility will have restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

          We expect that our new credit facility will restrict, among other things, our ability to incur debt and pay distributions, and will require us to comply with customary financial covenants and specified financial ratios. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our new credit facility that are not cured or waived within the specified time periods, a significant portion of our indebtedness may become immediately due and payable and we will be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our new credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our new credit facility, the lenders could seek to foreclose on our assets.

          Our new credit facility will allow us to borrow up to the borrowing base, which is primarily based on the estimated future value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. The borrowing base will be redetermined by our lenders twice each year based on an engineering report with respect to our estimated reserves, based on commodity prices as of such date, as adjusted for the impact of our commodity derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. If we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders.

Our business depends in part on pipelines, transportation and gathering systems and processing facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production and could harm our business.

          The marketability of our oil, NGL and natural gas production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, such as trucks, gathering systems and processing facilities owned by third parties. The amount of oil, NGLs and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. Also, the transfer of our oil and natural gas on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. Our access to

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transportation options, including trucks owned by third parties, can also be affected by U.S. federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil and natural gas production and harm our business.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

          Our oil and natural gas production operations are subject to complex and stringent laws and regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

          Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of oil and natural gas production. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

          On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. On January 2, 2011 regulations that require a reduction in emissions of greenhouse gases from motor vehicles became effective. The EPA has determined that such regulations trigger permit review for greenhouse gas emissions from certain stationary sources. EPA adopted a tiered approach to implementing the permitting of green house gas emissions from stationary in May 2010. The so-called "tailoring rule" only requires the stationary sources with the largest emissions to undergo an assessment of green house gas emissions under the best available control technology under the federal permitting programs. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published mandatory reporting rules for oil and gas systems requiring reporting starting in 2012 for emissions in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil, natural gas and NGL that we produce.

          Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil, natural gas and NGLs that we produce.

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Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.

          We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas exploration and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may 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 may result from environmental and other impacts of our operations.

          Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our 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 we were not able to recover the resulting costs through insurance or increased revenues, our ability to make cash distributions to our unitholders could be adversely affected.

The third parties on whom we rely 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 our business.

          The operations of the third parties on whom we rely 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 may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative contracts to reduce the effect of commodity price, interest rate and other risks associated with our business.

          The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in July 2010, or the Dodd-Frank Act, establishes a new regulatory framework for derivative transactions, including oil and gas hedging transactions. Certain transactions will be required to be cleared on a derivatives clearing organization and traded on an exchange or a swap execution facility, and cash collateral will have to be posted. The Dodd-Frank Act requires the Commodity Futures and Trading Commission, or CFTC, federal regulators of banks and other financial institutions, or the prudential regulators, and the SEC to promulgate the rules implementing the new law, which must be finally adopted by December 31, 2011. Until these regulations are adopted, effective and implemented in practice, we cannot determine what impact the new regulatory framework will have on our business.

          Depending on the rules and definitions ultimately adopted by the CFTC, the SEC and the prudential regulators, we might in the future be required to post cash collateral for our commodities derivative transactions. Posting of cash collateral could cause liquidity issues for us by reducing our ability to use our cash for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus protect cash flows. Although the CFTC, the SEC and the prudential regulators have issued proposed rules under the Dodd-Frank Act, we are at risk until the regulators adopt rules and

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definitions that confirm that companies such as us are not required to post cash collateral for our derivative hedging contracts. Even if we are not required to post cash collateral for our derivative contracts, the banks and other derivatives dealers who are our contractual counterparties will be required to comply with the Dodd-Frank Act's new requirements, and the costs of their compliance will likely be passed on to customers, including us, thus decreasing the benefits to us of hedging transactions and reducing the profitability of our cash flows. In addition, the Dodd-Frank Act may also require our contractual counterparties to our derivative contracts to spin off their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty. These changes might not only increase costs, but could also reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or reduce our ability to monetize or restructure our existing derivative contracts and potentially increase our exposure to less creditworthy counterparties.

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

          The U.S. Congress is considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is a commonly used process in the completion of unconventional natural gas wells in shale formations, as well as tight conventional formations including many of those that we complete and produce. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. If adopted, this legislation could establish an additional level of regulation and permitting at the federal level, and could make it easier for third parties to initiate legal proceedings based on allegations that chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil and surface water. In addition, on October 21, 2011, the EPA announced its intention to propose regulations by 2014 under the Federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production. Some states have adopted and others are also considering legislation to restrict and regulate hydraulic fracturing, including Texas, where the Texas Railroad Commission recently proposed regulations requiring online disclosure of the chemicals used in hydraulic fracturing. Any additional level of regulation could lead to operational delays or increased operating costs which could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and would increase our costs of compliance and doing business, resulting in a decrease of cash available for distribution to our unitholders.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.

          Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and implied distribution yield. The distribution yield of limited partner units is often used by investors to compare and rank similar yield oriented securities for investment decision making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt.

Many of our leases are in areas that have been partially depleted or drained by offset wells.

          Many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests lying contiguous or adjacent to or adjoining our interests could take actions, such as drilling additional wells, that could adversely affect our operations. 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

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wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further exploit and develop our reserves.

We may experience a temporary decline in revenues and production if we lose one of our significant customers.

          For the six months ended June 30, 2011, ConocoPhillips, Seminole Energy Services, and Sunoco accounted for 19%, 12%, and 15%, respectively, of our predecessor's total sales revenues. To the extent any one of our significant customers reduces the volume of its oil or gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and gas production and our revenues and cash available for distribution could decline which could adversely affect our ability to make cash distributions to our unitholders.

Expenses not covered by our insurance could have a material adverse effect on our financial position, results of operations and cash flows.

          We maintain insurance coverage against potential losses that we believe is customary in the industry. However, these policies may not cover all liabilities, claims, fines, penalties or costs and expenses that we may incur in connection with our business and operations, including those related to environmental claims. In addition, we cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.


Risks Inherent in an Investment in Us

Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with us, and owe limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of our unitholders.

          Our general partner is ultimately controlled by the co-founders of Lime Rock Management, who also ultimately control Lime Rock Resources and Lime Rock Partners. In turn, our general partner will have control over all decisions related to our operations. Upon consummation of this offering, Lime Rock Resources will own an approximate 57.9% limited partner interest in us and, through its interest in our general partner, will be entitled to receive 100% of the distributions we make on our incentive distribution rights for a period of six years following the closing of this offering. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. However, our non-independent directors and certain of our executive officers hold similar positions with certain affiliates of our general partner, including Lime Rock Resources, Lime Rock Partners and Lime Rock Management, and will continue to have economic interests, investments and other economic incentives in, as well as management and fiduciary duties to, these affiliates. As a result of these relationships, conflicts of interest may arise in the future between Lime Rock Resources, Lime Rock Partners and Lime Rock Management and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders and us. Please read "Conflicts of Interest and Fiduciary Duties — Conflicts of Interest — Our Partnership Agreement Limits Our General Partner's Fiduciary Duties to Our Unitholders and Restricts the Remedies Available to Unitholders for Actions Taken by Our General Partner That Might Otherwise Constitute Breaches of Fiduciary Duty." These potential conflicts include, among others, the following situations:

    our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

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    neither our partnership agreement nor any other agreement requires Lime Rock Resources, Lime Rock Partners or Lime Rock Management or their respective affiliates (other than our general partner) to pursue a business strategy that favors us. The directors and officers of Lime Rock Resources, Lime Rock Partners and Lime Rock Management and their respective affiliates (other than our general partner) have a fiduciary duty to make these decisions in the best interests of their respective equity holders, which may be contrary to our interests;

    our general partner is allowed to take into account the interests of parties other than us, such as the owners of our general partner, in resolving conflicts of interest, which has the effect of limiting our general partner's fiduciary duty to our unitholders;

    Lime Rock Resources, Lime Rock Partners and Lime Rock Management and their affiliates are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer or sell assets to us. Please read 'Conflicts of Interest and Fiduciary Duties — Conflicts of Interest";

    all of the executive officers of our general partner who will provide services to us, other than our Chief Financial Officer, will also devote a significant amount of time to affiliates of our general partner, including Lime Rock Resources, and may be compensated for services rendered to such affiliates;

    our general partner determines the amount and timing of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;

    we will enter into a services agreement with Lime Rock Management and Lime Rock Resources Operating Company pursuant to which management, administrative and operational services will be provided to our general partner and us to manage and operate our business. Lime Rock Management and Lime Rock Resources Operating Company have similar arrangements with Lime Rock Resources and its affiliates;

    our general partner will determine which costs, including allocated overhead, incurred by it and its affiliates, including Lime Rock Management and Lime Rock Resources Operating Company, are reimbursable by us. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us;

    our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

    our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

    our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

    our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

    our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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Lime Rock Resources, Lime Rock Partners and other affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets.

          Neither our partnership agreement nor the omnibus agreement will prohibit Lime Rock Resources, Lime Rock Partners and their affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For instance, Lime Rock Resources and any future affiliated funds, such as a prospective Fund III, which may commence raising capital to make acquisitions once 75% of the capital of Fund II has been allocated to acquisition opportunities and expenses of Fund II, and the portfolio companies of Lime Rock Partners may acquire, develop or dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. In addition, Lime Rock Resources has approximately $520 million of additional acquisition capacity that it expects to deploy over the next two years. Because of Lime Rock Resources' economic interests to invest those funds, it is likely that they will pursue acquisition opportunities that they may otherwise present to us. Lime Rock Resources and Lime Rock Partners are established participants in the energy business, and have greater resources than ours, which factors may make it more difficult for us to compete with these entities with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders. Please read "Conflicts of Interest and Fiduciary Duties."

Neither we nor our general partner have any employees and we rely solely on Lime Rock Management and Lime Rock Resources Operating Company to manage our business. Most of our management team and the employees of Lime Rock Resources Operating Company will also provide substantially similar services to Lime Rock Resources, and thus will not be solely focused on our business.

          Neither we nor our general partner have any employees and we rely solely on Lime Rock Management and Lime Rock Resources Operating Company to manage us and operate our assets. Upon consummation of this offering, we will enter into a services agreement with Lime Rock Management and Lime Rock Resources Operating Company pursuant to which management, administrative and operational services will be provided to our general partner and us to manage and operate our business.

          Lime Rock Management and Lime Rock Resources Operating Company will also continue to provide substantially similar services and personnel to Lime Rock Resources. Should Lime Rock Resources form other funds, Lime Rock Management and Lime Rock Resources Operating Company may also enter into similar arrangements with those new funds. Because Lime Rock Management and Lime Rock Resources Operating Company will be providing services to us that are substantially similar to those provided to Lime Rock Resources and, potentially, other funds, Lime Rock Management and Lime Rock Resources Operating Company may not have sufficient human, technical and other resources to provide those services at a level that Lime Rock Management and Lime Rock Resources Operating Company would be able to provide to us if it did not provide those similar services to Lime Rock Resources and any other funds. Additionally, Lime Rock Management and Lime Rock Resources Operating Company may make internal decisions on how to allocate their available resources and expertise that may not always be in our best interest compared to those of Lime Rock Resources or other affiliated funds. There is no requirement that Lime Rock Management and Lime Rock Resources Operating Company favor us over Lime Rock Resources or other affiliated funds in providing its services. If the employees of Lime Rock Management and Lime Rock Resources Operating Company do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

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We have material weaknesses in our internal control over financial reporting. If one or more material weaknesses persist or if we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

          Prior to the completion of this offering, our predecessor has been a private entity with limited accounting personnel and other supervisory resources to adequately execute its accounting processes and address its internal control over financial reporting. In connection with our predecessor's audit for the year ended December 31, 2010, our predecessor's independent registered accounting firm identified and communicated material weaknesses related to maintaining an effective control environment in that our predecessor did not maintain an effective control environment in the design and execution of controls that have not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles given the lack of adequate staffing levels. A "material weakness" is a deficiency, or combination of deficiencies, in internal controls such that there is a reasonable possibility that a material misstatement of our predecessor's financial statements will not be prevented, or detected in a timely basis. Additionally, our predecessor did not maintain effective controls over the completeness and accuracy of key spreadsheets used in its computations of various estimates, including depletion and asset retirement obligations. Effective controls were not adequately designed or consistently operated to ensure that key computations were capturing the appropriate information completely and accurately before closing adjustments were made to our predecessor's accounting records. The lack of adequate staffing levels and lack of effective controls over the completeness and accuracy of key spreadsheets resulted in insufficient time spent on review and approval of certain information used to prepare our predecessor's financial statements, resulting in several audit adjustments to the financial statements for the year ended December 31, 2010.

          After the closing of this offering, our management team and financial reporting oversight personnel will be those of our predecessor, and thus, we will face the same material weaknesses described above.

          Prior to the completion of our predecessor's audit for the year ended December 31, 2010, our predecessor's management began to implement new accounting processes and control procedures and also hired additional personnel.

          While we have begun the process of evaluating the design and operation of our internal control over financial reporting, we are in the early phases of our review and will not complete our review until after this offering is completed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses, in addition to the material weaknesses described above. Each of the material weaknesses described above could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our annual or interim combined financial statements that would not be prevented or detected. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the material weaknesses described above or avoid potential future material weaknesses.

          We are not currently required to comply with the SEC's rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC's rules implementing Sections 302 and 404 of the Sarbanes Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the

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requirements of being a publicly traded partnership, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

          Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. If it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed or operating. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

          Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

Most of the directors and officers who have responsibility for our management have significant duties with, and will spend significant time serving, entities that compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

          To maintain and increase our levels of production, we will need to acquire oil and gas properties. Most of the directors and all of the officers of our general partner who are responsible for managing our operations and acquisition activities hold similar positions with Lime Rock Resources and other entities that are in the business, directly or indirectly, of identifying and acquiring oil and gas properties. For example, Mr. Farber, one of our directors, is a co-founder of Lime Rock Management and a managing director of Lime Rock Partners, which is in the business of investing in exploration and production companies. Mr. Pressler, one of our directors, is also a managing director of Lime Rock Partners, and Messrs. Mullins and Adcock, our Co-Chief Executive Officers, are also Co-Chief Executive Officers of Lime Rock Resources, which is in the business of acquiring oil and gas properties. After the closing of this offering, all of the executive officers of our general partner, other than our Chief Financial Officer, will continue to devote significant time to Lime Rock Resources' businesses. Further, our general partner's non-independent directors and certain of our executive officers will continue to have economic interests, investments and other economic incentives in affiliates of our general partner. Messrs. Farber and Pressler are also directors of several oil and gas producing entities that are in the business of acquiring oil and gas properties. The existing positions held by these directors and officers may give rise to fiduciary obligations that are in conflict with fiduciary duties they owe to us. The officers and directors of Lime Rock Resources, Lime Rock Partners and Lime Rock Management may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations with and economic interests in these and other entities, they may have fiduciary obligations to present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for

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other entities with which they are affiliated and elect not to present them to us. These conflicts may not be resolved in our favor.

Cost reimbursements due to our general partner and its affiliates for services provided may be substantial and could reduce our cash available for distribution to you.

          Under our services agreement with Lime Rock Management and Lime Rock Resources Operating Company, each of Lime Rock Management and Lime Rock Resources Operating Company will receive reimbursement for the provision of various services and personnel for our benefit. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders.

          In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Units held by persons who our general partner determines are not eligible holders will be subject to redemption.

          To comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our common units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means:

    a citizen of the United States;

    a corporation organized under the laws of the United States or of any state thereof;

    a public body, including a municipality; or

    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.

          Onshore mineral leases 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. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder run the risk of having their common units redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Affiliates of Lime Rock Management who control our general partner will have the power to control our operations.

          Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will not elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner will be appointed by Lime Rock Management. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these

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limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

          Our general partner will have control over all decisions related to our operations. Our general partner is ultimately controlled by the co-founders of Lime Rock Management, who also ultimately control Lime Rock Resources and Lime Rock Partners. Upon the consummation of this offering, Lime Rock Resources will own an approximate 57.9% limited partner interest in us. As a result, the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Our partnership agreement may not be amended during the subordination period without the approval of our public common unitholders, other than in certain limited circumstances where no unitholder approval is required. However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by Lime Rock Resources and its affiliates). Assuming we do not issue any additional common units and Lime Rock Resources does not transfer its common units, Lime Rock Resources will have the ability to amend our partnership agreement, including our policy to distribute all of our available cash to our unitholders, without the approval of any other unitholder once the subordination period ends. Furthermore, the goals and objectives of Lime Rock Resources and our general partner relating to us may not be consistent with those of a majority of the other unitholders.

Our general partner will be required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.

          Maintenance capital expenditures are those capital expenditures required to maintain the current production levels over the long term of our oil and natural gas properties or maintain the current operating capacity of our other capital assets, including expenditures to replace our oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation.

Our partnership agreement limits our general partner's fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

          Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

    permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, which allows our general partner to consider only the interests and factors that it desires, without a duty or obligation to give any consideration to any

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      interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection with this reset, common units, the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to the partnership agreement;

    provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith;

    generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must either be (i) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (ii) must be "fair and reasonable" to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

    provides that our general partner and its officers and directors will not be liable for monetary damages to us, our 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 our general partner or its officers and directors 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; and

    provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner's board of directors or the conflicts committee of our general partner's board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

          By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders. This may result in lower distributions to holders of our common units in certain situations.

          Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (23%, in addition to distributions paid on its 0.1% general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the 'reset minimum quarterly distribution') and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.

          In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of common units equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this

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reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights.

Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.

          The public unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove our general partner. Following consummation of this offering, Lime Rock Resources will own approximately 58.0% of our outstanding voting units.

          Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor business management, so the removal of the general partner because of the unitholder's dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Control of our general partner may be transferred to a third party without unitholder consent.

          Our 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, our partnership agreement does not restrict the ability of the owners of our general partner, who are affiliates of Lime Rock Management, from transferring all or a portion of their ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby influence the decisions made by the board of directors and officers in a manner that may not be aligned with the interests of our unitholders.

We may not make cash distributions during periods when we record net income.

          The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including cash from reserves established by our general partner, working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions to our unitholders during periods when we record net losses and may not make cash distributions to our unitholders during periods when we record net income.

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We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders' ownership interests.

          Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

    our unitholders' proportionate ownership interest in us will decrease;

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

    because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

    the ratio of taxable income to distributions may increase;

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

    the market price of our common units may decline.

Our partnership agreement restricts the limited voting rights of unitholders, other than our general partner and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.

          Our partnership agreement restricts unitholders' limited voting rights by providing that any common units held by a person, entity or group owning 20% or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders' ability to influence the manner or direction of management.

Once our common units are publicly traded, Lime Rock Resources may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

          After the sale of the common units offered hereby, Lime Rock Resources will own an aggregate of of our outstanding common units and all of our subordinated units, which convert into common units at the end of the subordination period. Once our common units are publicly traded, the sale of these units, including common units issued upon the conversion of the subordinated units, in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a call right that may require common unitholders to sell their common units at an undesirable time or price.

          If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is the greater of (i) the highest cash price paid by either of our general partner or any of its affiliates for any common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those common units; and (ii) the average daily closing prices of our common units over the 20 days preceding the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their common units at an

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undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. Upon consummation of this offering, Lime Rock Resources will own an aggregate of approximately 39.9% of our outstanding common units (30.9% if the underwriters exercise their over-allotment option in full) and all of our subordinated units. At the end of the subordination period, assuming no additional issuances of common units and that all of the subordinated units are converted into common units, Lime Rock Resources will own approximately 58.0% of our aggregate outstanding common units.

If we distribute cash from capital surplus, which is analogous to a return of capital, our minimum quarterly distribution will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.

          Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated average capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus generally would result from cash received from non-operating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 99.9% to our unitholders and 0.1% to our general partner, and will result in a decrease in our minimum quarterly distribution and a lower threshold for distributions on the incentive distribution rights held by our general partner. For a more detailed description of operating surplus, capital surplus and the effect of distributions from capital surplus, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

          Our partnership agreement allows us to add to operating surplus up to two times the amount of our most recent minimum quarterly distribution. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.

Our unitholders' liability may not be limited if a court finds that unitholder action constitutes control of our 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. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:

    a court or government agency determined that we were conducting business in a state but had not complied with that particular state's partnership statute; or

    a unitholder's right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute 'control' of our business.

Our 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, we

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may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us 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 us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

Our unitholders may have limited liquidity for their common units, a trading market may not develop for the common units and our unitholders may not be able to resell their common units at the initial public offering price.

          Prior to this offering, there has been no public market for the common units. After this offering, there will be publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Our unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, a lack of liquidity would likely result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units. All of the 6,249,600 common units (4,838,400 common units if the underwriters exercise in full their option to purchase additional common units) that are issued to affiliates of our general partner, or 39.9% of our outstanding common units, will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by affiliates of our general partner of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to our general partner and its affiliates. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.

If our common unit price declines after the initial public offering, our unitholders could lose a significant part of their investment.

          The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

    changes in commodity prices;

    changes in securities analysts' recommendations and their estimates of our financial performance;

    public reaction to our press releases, announcements and filings with the SEC;

    fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;

    changes in market valuations of similar companies;

    departures of key personnel;

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    commencement of or involvement in litigation;

    variations in our quarterly results of operations or those of other oil and natural gas companies;

    variations in the amount of our quarterly cash distributions to our unitholders;

    future issuances and sales of our common units; and

    changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry.

          In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

Our unitholders will experience immediate and substantial dilution of $9.22 per unit.

          The initial offering price of $19.00 per common unit exceeds our pro forma net tangible book value after this offering of $9.78 per common unit. Based on the initial offering price of $19.00 per common unit, our unitholders will incur immediate and substantial dilution of $9.22 per common unit. This dilution will occur primarily because the assets contributed by affiliates of our general partner are recorded, in accordance with GAAP at their historical cost, and not their fair value. The impact of such dilution would be magnified upon any conversion of the incentive distribution rights into common units.

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our credit facility may restrict our ability to make distributions.

          Our partnership agreement allows us to borrow to make distributions. We may make short-term borrowings under our new credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short-term fluctuation in our working capital that would otherwise cause volatility in our quarter-to-quarter distributions.

          The terms of our new credit facility may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production.

          Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we may be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:

    general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

    conditions in the oil and gas industry;

    the market price of, and demand for, our common units;

    our results of operations and financial condition; and

    prices for oil, NGLs and natural gas.

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Tax Risks to Unitholders

          In addition to reading the following risk factors, prospective unitholders should read "Material Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation, then our cash available for distribution to our unitholders would be substantially reduced.

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

          If we were treated as a corporation for federal income tax purposes (including, but not limited to, due to a change in our business or a change in current law), we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

          Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our units. Our partnership agreement provides that if a law is enacted or an existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the Target Distribution may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

          The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. For example, the Obama Administration and members of Congress have considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted, any such changes could negatively impact the value of an investment in our units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution and the Target Distribution may be adjusted to reflect the impact of that law on us.

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

          Both the Obama Administration's budget proposal for fiscal year 2012 and the proposed American Jobs Act of 2011 include potential legislation that would, if enacted, 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 natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural 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 these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

If the IRS contests any of the federal income tax positions we take, the market for our units may be adversely affected, and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.

          We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with some or all of our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Our unitholders will be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.

          Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

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

          If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units. Because distributions in excess of their allocable share of our total net taxable income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion and IDC recapture. In addition, because the amount realized may include a unitholder's share of our nonrecourse liabilities, if they sell their units, they may incur a tax liability in

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excess of the amount of cash they receive from the sale. Please read "Material Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss."

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.

          Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our 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 at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our units.

We will treat each purchaser of units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.

          Because we cannot match transferors and transferees of units and because of other reasons, we will adopt depletion, depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder's tax returns. Please read "Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election" for a further discussion of the effect of the depletion, depreciation and amortization positions we will adopt.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

          We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our 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, however, 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 among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read "Material Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees."

A unitholder whose units are loaned to a "short seller" to effect a short sale of units may be considered as having disposed of those units. If so, such 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.

          Because a unitholder whose units are loaned to a "short seller" to effect a short sale of units may be considered as having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and

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the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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

          We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For this purpose, multiple sales of the same unit will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if special relief from the IRS is not available) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder's taxable income for the year of termination. A technical termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. Please read "Material Tax Consequences — Disposition of Common Units — Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the units.

          When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders. A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

As a result of investing in our units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

          In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes

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that are imposed by the various jurisdictions in which we conduct business or own property now or in the future even if such unitholders do not live in those jurisdictions. Our unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We initially will own property and conduct business in a number of states, most of which currently impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. We may own property or conduct business in other states or foreign countries in the future. It is a unitholder's responsibility to file all U.S. federal, state and local tax returns.

Compliance with and changes in tax laws could adversely affect our performance.

          We are subject to extensive tax laws and regulations, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

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USE OF PROCEEDS

          We intend to use the estimated net proceeds from this offering of approximately $167.2 million, after deducting underwriting discounts and a structuring fee, together with borrowings of approximately $155.8 million that we will incur upon the closing of this offering under our new revolving credit facility, to:

    make cash distributions and payments to Fund I of approximately $289.9 million;

    repay in full approximately $27.3 million of LRR A's debt that we will assume at closing;

    pay fees and expenses of approximately $1.9 million relating to our new credit facility; and

    pay estimated offering expenses of approximately $3.9 million.

          Other than the $155.8 million that we expect to borrow under our new revolving credit facility upon the closing of this offering, we have no plans to immediately draw down additional borrowings under our new revolving credit facility.

          All of LRR A's debt that we will assume and repay in full at closing was incurred under LRR A' s credit facility in connection with acquisitions. Such debt is secured by mortgages on substantially all of LRR A's oil and natural gas properties, including the Partnership Properties. The interest rate on this credit facility is 2.81% through November 23, 2011, and the credit facility matures in November 2014.

          The following table illustrates our use of the proceeds from this offering and our borrowings under our new credit facility.

Sources of Cash (in millions)   Uses of Cash (in millions)  

Gross proceeds from this offering(1)

  $ 178.8  

Distribution and payment to Fund I(1)

  $ 289.9  

Borrowings under our new credit facility

  $ 155.8  

Repayment of debt assumed from LRR A

  $ 27.3  
                 

       

Underwriting discounts, a structuring fee, fees and expenses associated with our new credit facility and other offering expenses payable by us

  $ 17.4  
                 

Total

  $ 334.6  

Total

  $ 334.6  
               

(1)
If the underwriters exercise their option to purchase additional common units in full, the gross proceeds would be $205.6 million and the total distribution and payment to Fund I would be approximately $315.0 million.

          If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Fund I. Any such common units issued to Fund I will be issued for no consideration other than Fund I's contribution of the Partnership Properties to us in connection with the closing of this offering. If the underwriters exercise their option to purchase 1,411,200 additional common units in full, the additional net proceeds would be approximately $25.1 million. The net proceeds from any exercise of such option will be used to pay additional cash consideration for the Partnership Properties purchased from Fund I and to make an additional cash distribution to Fund I. If the underwriters do not exercise their option to purchase 1,411,200 additional common units, we will issue 1,411,200 common units to Fund I upon the expiration of the option. We will not receive any additional consideration from Fund I in connection with such issuance. Accordingly, the exercise of the underwriters' option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Underwriting."

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CAPITALIZATION

          The following table shows:

    the historical capitalization of our predecessor as of June 30, 2011; and

    our pro forma capitalization as of June 30, 2011, adjusted to reflect the issuance and sale of 9,408,000 common units to the public at an initial offering price of $19.00 per common unit, the other formation transactions described under "Prospectus Summary — Formation Transactions and Partnership Structure" and the application of the net proceeds from this offering as described under "Use of Proceeds."

          We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the unaudited historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Prospectus Summary — Formation Transactions and Partnership Structure," "Use of Proceeds" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." For a description of the pro forma adjustments, please read our Unaudited Pro Forma Condensed Financial Statements.

 
  As of June 30, 2011  
 
  Our
Predecessor
Historical
  Pro Forma
LRR Energy,
L.P.
 
 
  (in thousands)
 

Long-term debt(1)

  $ 27,251   $ 155,800  

Partners' capital/net equity:

             
 

Predecessor partners' capital

    423,505      
 

Common units held by purchasers in this offering

        91,966  
 

Common units held by Fund I

        61,092  
 

Subordinated units held by Fund I

        65,690  
 

General partner interest

        219  
           
   

Total partners' capital/net equity

  $ 423,505   $ 218,967  
           

Total capitalization

  $ 450,756   $ 374,767  
           

(1)
We intend to enter into a $500 million credit facility prior to this offering. After giving effect to the transactions described under "Prospectus Summary — Formation Transactions and Partnership Structure," including our borrowing of $155.8 million under our new credit facility, we will have approximately $94.2 million of borrowing capacity. We do not anticipate having any outstanding letters of credit against our borrowing capacity at the closing of this offering. For additional information on our new credit facility, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — New Credit Facility."

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DILUTION

          Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per unit after this offering. Net tangible book value is our total tangible assets less total liabilities. Based on the initial offering price of $19.00 per common unit, on a pro forma basis as of June 30, 2011, after giving effect to the transactions described under "Prospectus Summary — Formation Transactions and Partnership Structure," including this offering of common units and the application of the related net proceeds, our net tangible book value was $219.0 million, or $9.78 per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for accounting purposes, as illustrated in the following table:

Initial offering price per common unit

        $ 19.00  
 

Pro forma net tangible book value per common unit before this offering(1)

  $ 26.60        
 

Decrease in net tangible book value per common unit attributable to purchasers in this offering

    (16.82 )      
             
 

Less: Pro forma net tangible book value per common unit after this offering(2)

          9.78  
             

Immediate dilution in net tangible book value per common unit to purchasers in this offering(3)

        $ 9.22  
             

(1)
Determined by dividing the pro forma net tangible book value of the contributed assets and liabilities immediately prior to the offering by the number of units (6,249,600 common units, 6,720,000 subordinated units to be issued to Fund I as partial consideration for its contribution of the Partnership Properties and liabilities to us and the issuance of 22,400 general partner units) to be issued to our general partner and its affiliates.

(2)
Determined by dividing our pro forma as adjusted net tangible book value, after giving effect to the application of the net proceeds of this offering, by the total number of units to be outstanding after this offering (15,657,600 common units, 6,720,000 subordinated units and 22,400 general partner units).

(3)
Because the total number of units outstanding following the consummation of this offering will not be impacted by any exercise of the underwriters' option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the underwriters' option to purchase additional common units.

          The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates, including Fund I, in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:

 
  Units Acquired   Total Consideration  
 
  Number   Percent   $   Percent  
 
   
   
  (in millions)
   
 

General partner and its affiliates(1)(2)

    12,992,000     58 % $ 345.6     67 %

Purchasers in this offering(3)

    9,408,000     42 %   167.2     33 %
                   

Total

    22,400,000     100 % $ 512.8     100 %
                   

(1)
Upon the consummation of the transactions contemplated by this prospectus, and assuming the underwriters do not exercise their option to purchase additional common units, our general

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    partner, its owners and their affiliates will own 6,249,600 common units, 6,720,000 subordinated units and 22,400 general partner units.

(2)
The assets contributed by affiliates of our general partner were recorded at historical cost in accordance with GAAP. Total consideration provided by affiliates of our general partner is equal to the net tangible book value of such assets as of June 30, 2011.

(3)
Total consideration represents the consideration received after deducting underwriting discounts and a structuring fee.

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

          You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read "— Estimated Unaudited Adjusted EBITDA for the Twelve Months Ending September 30, 2012." In addition, you should read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

          For additional information regarding our historical and pro forma operating results, you should refer to the unaudited historical combined financial statements for our predecessor as of June 30, 2011 and for the six months ended June 30, 2010 and 2011 and the audited historical combined financial statements of our predecessor as of December 31, 2009 and 2010 and for the years ended December 31, 2008, 2009 and 2010, and our unaudited pro forma condensed financial statements as of June 30, 2011 and for the six months ended June 30, 2010 and 2011 and for the year ended December 31, 2010 included elsewhere in this prospectus.


General

Rationale for Our Cash Distribution Policy

          Our partnership agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. We intend to fund a portion of our capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our cash distribution policy reflects a basic judgment that our unitholders generally will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Also, because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to our unitholders than would be the case if we were subject to such federal income tax.

Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

          There is no guarantee that unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or distributions at any other rate except as provided in our partnership agreement. Our cash distribution policy may be changed at any time and is or may become subject to certain restrictions, including the following:

    Our cash distribution policy will be subject to restrictions on distributions under our new credit facility or other debt agreements that we may enter into in the future. Specifically, our new credit facility will contain financial tests and covenants that we must satisfy. These financial tests and covenants are described in "Management's Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — New Credit Facility." Should we be unable to satisfy these restrictions, or if a default occurs under our new credit facility, we will be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy. Any future indebtedness may contain similar or more stringent restrictions.

    Our general partner will have the authority to establish reserves for the conduct of our business and for future cash distributions to our unitholders, and the establishment of, or an increase in, those reserves could result in a reduction in cash distributions to our unitholders from levels we currently anticipate under our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish, other than

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      with respect to reserves for future cash distributions. Any determination to establish or increase reserves made by our general partner in good faith will be binding on the unitholders. We intend to reserve a sufficient portion of our cash generated from operations to fund our exploitation and development capital expenditures. If our general partner does not set aside sufficient cash reserves or make sufficient cash expenditures to maintain the current production levels of our oil and natural gas properties, we will be unable to pay the minimum quarterly distribution from cash generated from operations and would therefore expect to reduce our distributions. We are unlikely to be able to sustain our current level of distributions without making capital expenditures that maintain the current production levels of our oil and natural gas properties. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may have the effect of, and may effectively represent, a return of part of our unitholders' investment in us as opposed to a return on our unitholders' investment.

    Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay cash distributions to our unitholders.

    Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement may not be amended during the subordination period without the approval of our public common unitholders, other than in certain limited circumstances where no unitholder approval is required. However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by Lime Rock Resources and its affiliates). Upon consummation of this offering, affiliates of Lime Rock Management will control our general partner and Lime Rock Resources will control the voting of an aggregate of approximately 39.9% of our outstanding common units and all of our subordinated units. Assuming we do not issue any additional common units and the affiliates of Lime Rock Management and Lime Rock Resources do not transfer a controlling portion of their equity interests in our general partner or transfer their common units such that they control less than a majority of our outstanding common units, Lime Rock Management and Lime Rock Resources will have the ability to amend our partnership agreement without the approval of any other unitholder once the subordination period ends.

    Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement, our new credit facility and any other debt agreements we may enter into in the future.

    Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

    We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including decreases in commodity prices, decreases in our oil and natural gas production or increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements or anticipated cash needs. For a

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      discussion of additional factors that may affect our ability to pay distributions, please read "Risk Factors."

    If and to the extent our cash available for distribution materially declines, we may reduce our quarterly distribution in order to service or repay our debt or fund capital expenditures.

    All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the cumulative operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components that represent non-operating sources of cash, including a $30.0 million cash basket and working capital borrowings. Consequently, it is possible that distributions from operating surplus may represent a return of capital. For example, the $30.0 million cash basket would allow us to distribute as operating surplus cash proceeds we receive from non-operating sources, such as asset sales, issuances of securities and long-term borrowings, which would represent a return of capital. Distributions representing a return of capital could result in a corresponding decrease in our asset base. Additionally, any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is similar to a return of capital. Distributions from capital surplus could result in a corresponding decrease in our asset base. We do not anticipate that we will make any distributions from capital surplus. Please read "Risk Factors — Risks Inherent in an Investment in Us — If we distribute cash from capital surplus, which is analogous to a return of capital, our minimum quarterly distribution will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased," and "Provisions of Our Partnership Agreement Relating to Cash Distributions — Operating Surplus and Capital Surplus" and "Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions from Capital Surplus — Effect of a Distribution from Capital Surplus."

    Our ability to make distributions to our unitholders depends on the performance of our operating subsidiary and its ability to distribute cash to us. The ability of our operating subsidiary to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

Our Ability to Grow Depends on Our Ability to Access External Capital

          Our partnership agreement requires us to distribute all of our available cash to unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund our growth capital expenditures and make acquisitions. To the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand their ongoing operations. To the extent we issue additional units in connection with any capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our quarterly per unit distribution level. There are no limitations in our partnership agreement, nor do we expect any limitations in our new credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

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Our Minimum Quarterly Distribution

          Upon completion of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $0.4750 per unit per whole quarter, or $1.90 per unit per year on an annualized basis, with such quarterly per unit distribution amount to be paid no later than 45 days after the end of each fiscal quarter, beginning with the quarter ending December 31, 2011. This equates to an aggregate cash distribution of approximately $10.6 million per quarter, or $42.6 million per year, in each case based on the number of common units, subordinated units and general partner units outstanding immediately after completion of this offering. The number of outstanding common units, subordinated units and general partner units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering. To the extent the underwriters exercise their option to purchase additional common units in connection with this offering, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remaining common units subject to the option, if any, will be issued to Fund I at the expiration of the option period. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Our ability to make cash distributions at the minimum quarterly distribution will be subject to the factors described above under the caption "— General — Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy."

          As of the date of this offering, our general partner will be entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. Our general partner's initial 0.1% interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units to Fund I upon expiration of the underwriters' option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units in connection with a reset of the incentive distribution target levels relating to our general partner's incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its initial 0.1% general partner interest. Our general partner has the right, but is not obligated, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its current general partner interest. Our general partner will also hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 23% of the cash we distribute in excess of $0.54625 per common unit per quarter.

          The table below sets forth the number of outstanding common units, subordinated units and general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution of $0.4750 per unit per quarter, or $1.90 per unit on an annualized basis.

 
   
  Minimum Quarterly
Distribution
 
 
  Number of
Units
 
 
  One Quarter   Four Quarters  

Common units held by purchasers in this offering(1)(2)

    9,408,000   $ 4,468,800   $ 17,875,200  

Common units held by Fund I(1)(2)

    6,249,600     2,968,560     11,874,240  

Subordinated units

    6,720,000     3,192,000     12,768,000  

General partner units

    22,400     10,640     42,560  
               
 

Total

    22,400,000   $ 10,640,000   $ 42,560,000  
               

(1)
Assumes the underwriters do not exercise their option to purchase additional common units. If the underwriters do not exercise their option to purchase an additional 1,411,200 common units, we will issue the additional 1,411,200 common units to Fund I upon the expiration of the option. To the extent the underwriters exercise their option to purchase additional common units, the number of

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    units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remainder, if any, will be issued to Fund I upon the expiration of the option. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.

(2)
Does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.

          If the minimum quarterly distribution on our common units is not paid with respect to any quarter, the common unitholders will not be entitled to receive such payments in the future except that, during the subordination period, to the extent we distribute cash in any future quarter in excess of the amount necessary to make cash distributions at the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any of these arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period."

          We do not have a legal obligation to pay the minimum quarterly distribution or distributions at any other rate except as provided in our partnership agreement. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of cash reserves our general partner determines is necessary or appropriate to provide for the conduct of our business (including amounts reserved for capital expenditures, working capital and operating expenses and payments to our general partner and its affiliates for reimbursement of expenses they incur on our behalf and pursuant to our general partner's incentive distribution rights to the extent such rights become payable in connection with the payment of the distribution to comply with applicable law, any of our debt instruments or other agreements or to provide for distributions to our unitholders for any one or more of the next four quarters). Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Available Cash — Definition of Available Cash."

          Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or imposed at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above. However, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirement to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in "good faith," our general partner must believe that the determination is in the best interests of the Partnership. Please read "Conflicts of Interest and Fiduciary Duties."

          Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuation based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. Our partnership agreement, including provisions contained therein requiring us to make cash distributions, may be amended by a vote of the holders of a majority of our common units. At the closing of this offering, affiliates of Lime Rock Management will control our general partner and Lime Rock Resources will own an aggregate of approximately 39.9% of our outstanding common units and all of our subordinated units. Assuming we do not issue any additional common units and the affiliates of Lime Rock Management and Lime Rock Resources do not transfer a controlling portion of their equity interests in our general partner or transfer their common units such that they control less than a majority of our outstanding common units, Lime Rock Management and Lime Rock Resources will have the ability to amend our partnership agreement without the approval of any other unitholder once the subordination period ends.

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          We will pay our quarterly distributions on or about the 15th of February, May, August and November to holders of record on or about the 1st day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. For our initial quarterly distribution, we will adjust the quarterly distribution for the period from the closing of this offering through December 31, 2011 based on the actual length of the period. We expect to pay this initial quarterly cash distribution on or before February 15, 2012.

          In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $0.4750 per unit for the twelve months ending September 30, 2012. In those sections, we present two tables, consisting of:

    "Unaudited Pro Forma Available Cash," in which we present the amount of cash we would have had available for distribution to our unitholders and our general partner for the year ended December 31, 2010 and the twelve months ended June 30, 2011, based on our unaudited pro forma financial statements. Our calculation of unaudited pro forma available cash in these tables should only be viewed as a general indication of the amount of available cash that we might have generated had the formation transactions contemplated in this prospectus occurred in an earlier period; and

    "Estimated Cash Available for Distribution," in which we demonstrate our ability to generate the minimum Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the full minimum quarterly distribution on all the outstanding units, including our general partner units, for the twelve months ending September 30, 2012.


Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010
and the Twelve Months Ended June 30, 2011

          If we had completed the formation transactions contemplated in this prospectus and the acquisition of the Partnership Properties on January 1, 2010, our unaudited pro forma available cash generated during the year ended December 31, 2010 would have been approximately $62.7 million. If we had completed the formation transactions contemplated in this prospectus and the acquisition of the Partnership Properties on July 1, 2010, our pro forma cash generated during the twelve months ended June 30, 2011 would have been approximately $51.0 million. The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units, subordinated units and general partner units to be outstanding upon the closing of this offering is approximately $42.6 million (or an average of $10.6 million per quarter). As a result, for the year ended December 31, 2010 and the twelve months ended June 30, 2011, we would have generated aggregate available cash sufficient to pay the aggregate minimum quarterly distribution on all our common units, subordinated units and general partner units during such periods. The number of outstanding common and subordinated units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering. We have not calculated available cash on a pro forma quarter-by-quarter basis for the year ended December 31, 2010 or the twelve months ended June 30, 2011 to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each quarter during those periods.

          Unaudited pro forma cash available for distribution does not include incremental external selling, general and administrative expenses that we expect we will incur as a result of being a publicly traded partnership, consisting of costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, Sarbanes-Oxley Act compliance, NYSE listing, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. We estimate that these incremental external selling, general and administrative expenses initially will be approximately $2.5 million per year. Such incremental selling, general and administrative expenses are not reflected in our historical and pro forma financial statements.

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          We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the formation transactions contemplated in this prospectus and the acquisition of the Partnership Properties actually been completed as of the dates presented. In addition, cash available to pay distributions is primarily a cash accounting concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution stated above in the manner described in the table below. As a result, you should view the amount of unaudited pro forma available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in an earlier period.

          The following table illustrates, on an unaudited pro forma basis, for the year ended December 31, 2010 and the twelve months ended June 30, 2011, the amount of available cash that would have been available for distribution to our unitholders, assuming that the formation transactions had been consummated on January 1, 2010 and July 1, 2010, respectively. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.


LRR Energy, L.P.
Unaudited Pro Forma Cash Available for Distribution

 
  Pro Forma  
 
  Year Ended
December 31, 2010
  Twelve Months Ended
June 30, 2011
 
 
  (in thousands, except per unit data)
 

Net income

  $ 9,550   $ 9,952  
 

Plus:

             
 

Income tax expense (benefit)

         
 

Interest expense — net, including realized and unrealized losses on interest rate derivative instruments

    4,824     4,824  
 

Depletion and depreciation

    40,673     35,737  
 

Accretion of asset retirement obligations

    1,178     1,255  
 

Unrealized gain (loss) on settlement of asset retirement obligations

    (242 )   (242 )
 

Unrealized loss on commodity derivative instruments

    17,733     21,429  
 

Impairment of oil and natural gas properties

    11,712     768  
           
 

Interest income

         
 

Unrealized gain on commodity derivative instruments

         

Adjusted EBITDA(1)

  $ 85,428   $ 73,723  
 

Less:

             
 

Cash interest expense(2)

    4,752     4,752  
 

Estimated average maintenance capital expenditures(3)

    18,000     18,000  
           

Pro Forma Available cash(4)

  $ 62,676   $ 50,971  
           

Pro Forma Annualized distributions per unit

  $ 1.90   $ 1.90  

Pro Forma Estimated annual cash distributions:

             
 

Distributions on common units held by purchasers in this offering

  $ 17,875   $ 17,875  
 

Distributions on common units held by Fund I

    11,874     11,874  
 

Distributions on subordinated units

    12,768     12,768  
 

Distributions on general partner units

    43     43  
           
   

Total estimated annual cash distributions

  $ 42,560   $ 42,560  
           

Excess

  $ 20,116   $ 8,411  
           

Percent of minimum quarterly distributions payable to common unitholders

    69.9 %   69.9 %

Percent of minimum quarterly distributions payable to subordinated unitholders

    30.0 %   30.0 %

(1)
Adjusted EBITDA is defined in "Prospectus Summary — Non-GAAP Financial Measures."

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(2)
In connection with this offering, we intend to enter into a new $500 million credit facility under which we expect to incur approximately $155.8 million of borrowings upon the closing of this offering. The pro forma cash interest expense is based on $155.8 million of borrowings at an assumed weighted-average rate of 3.05%.

(3)
Historically, our predecessor did not make a distinction between maintenance and growth capital expenditures. For purposes of the presentation of Unaudited Pro Forma Cash Available for Distribution, we have estimated that approximately $18.0 million of our predecessor's capital expenditures were maintenance capital expenditures for the Partnership Properties for the respective periods, which reflects our estimate of the average annual maintenance capital expenditures necessary to maintain our production through December 31, 2015 based on the forecasted production level of 6.1 MBoe/d for the twelve months ending September 30, 2012.

(4)
Does not reflect impact of $2.5 million of estimated incremental annual general and administrative expenses associated with being a publicly traded partnership that we expect to incur.


Estimated Unaudited Adjusted EBITDA for the Twelve Months Ending September 30, 2012

          Based upon the assumptions and considerations set forth in the table below, to fund cash distributions to our unitholders at our annualized minimum quarterly distribution of $1.90 per unit for the twelve months ending September 30, 2012, or $42.6 million in the aggregate, our Adjusted EBITDA for the twelve months ending September 30, 2012 must be at least $65.3 million. The number of outstanding common and subordinated units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.

          We believe that we will be able to generate this estimated Adjusted EBITDA based on the assumptions set forth in "— Assumptions and Considerations." We can give you no assurance, however, that we will generate this amount of estimated Adjusted EBITDA. This estimated Adjusted EBITDA should not be viewed as management's projection of the actual amount of Adjusted EBITDA that we will generate during the twelve-month period ending September 30, 2012. There will likely be differences between our estimated Adjusted EBITDA and our actual results, and those differences could be material. If we fail to generate the estimated Adjusted EBITDA contained in our forecast, we may not be able to pay the minimum quarterly distribution on our common units.

          While we do not as a matter of course make public projections as to future sales, earnings or other results, our management has prepared the prospective financial information that is the basis of our estimated Adjusted EBITDA below to substantiate our belief that we will have sufficient cash to pay the minimum quarterly distribution on all our common units, subordinated units and general partner units for the twelve months ending September 30, 2012. This prospective financial information is a forward-looking statement and should be read together with the historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Risk Factors." This prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the assumptions and considerations on which we base our belief that we can generate sufficient Adjusted EBITDA to pay the minimum quarterly distribution on all of our common units and subordinated units, as well as with respect to our general partner units, for the twelve months ending September 30, 2012. Readers of this prospectus are cautioned not to place undue reliance on this prospective financial information. Please read "— Assumptions and Considerations."

          The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has not compiled, examined or performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance

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with respect thereto. The PricewaterhouseCoopers LLP reports included in the registration statement relate to: (i) our predecessor's historical financial information and (ii) our initial balance sheet as of June 30, 2011. Those reports do not extend to the prospective financial information and should not be read to do so.

          When considering this prospective financial information, you should keep in mind the risk factors and other cautionary statements under "Risk Factors." Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the estimated Adjusted EBITDA sufficient to pay the minimum quarterly distributions to holders of our common units, subordinated units and general partner units for the twelve months ending September 30, 2012.

          We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective financial information or to update this prospective financial information to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

          After accounting for the factors described in "— Our Estimated Unaudited Adjusted EBITDA" and in the footnotes to the table in that section, we believe we will be able to pay cash distributions at the minimum quarterly distribution of $0.4750 per unit on all outstanding common units, subordinated units and general partner units for the twelve months ending September 30, 2012. The number of outstanding common units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.

Our Estimated Unaudited Adjusted EBITDA

          To pay the minimum quarterly distribution to our unitholders of $0.4750 per unit per quarter over the four consecutive calendar quarters ending September 30, 2012, our cumulative cash available to pay distributions must be at least approximately $42.6 million over that period. We have calculated that the amount of estimated Adjusted EBITDA for the twelve months ending September 30, 2012 that will be necessary to generate cash available to pay aggregate distributions of approximately $42.6 million over that period is approximately $65.3 million. Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities or any other measure calculated in accordance with GAAP.

          Adjusted EBITDA is a significant financial metric that will be used by our management to indicate (prior to the establishment of any reserves by the board of directors of our general partner) the cash distributions we expect to pay to our unitholders. Specifically, we intend to use this financial measure to assist us in determining whether we are generating operating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. As used in this prospectus, the term "Adjusted EBITDA" means the sum of net income (loss) adjusted by the following to the extent included in calculating such net income (loss):

    Plus:

    Income tax expense (benefit);

    Interest expense-net, including realized and unrealized losses on interest rate derivative contracts;

    Depletion and depreciation;

    Accretion of asset retirement obligations;

    Gain (loss) on settlement of asset retirement obligations;

    Unrealized losses on commodity derivative contracts;

    Impairment of oil and natural gas properties; and

    Other non-recurring items that we deem appropriate.

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    Less:

    Interest income;

    Unrealized gains on commodity derivative contracts; and

    Other non-recurring items that we deem appropriate.

          The following table presents our estimated unaudited Adjusted EBITDA for the twelve months ending September 30, 2012 on a quarter-by-quarter basis.


LRR Energy, L.P.
Estimated Unaudited Adjusted EBITDA

 
  Forecasted  
 
  Three Months Ending    
 
 
  Twelve Months
Ending
September 30,
2012
 
 
  December 31,
2011
  March 31,
2012
  June 30,
2012
  September 30,
2012
 
 
  (in millions, except per unit amounts)
 

Operating revenue and realized commodity derivative gains (losses)(1)

  $ 30.0   $ 26.2   $ 25.3   $ 24.8   $ 106.3  

Less:

                               
 

Lease operating expenses

    4.2     4.3     4.1     3.9     16.5  
 

Production and ad valorem taxes

    1.8     1.9     1.9     1.8     7.4  
 

General and administrative expenses

    2.2     2.2     2.2     2.2     8.9  
 

Depletion and depreciation

    7.6     7.4     7.4     7.4     29.7  
 

Interest expense

    1.3     1.3     1.3     1.3     5.1  
                       
   

Net income excluding unrealized commodity derivative gains (losses)

  $ 12.9   $ 9.1   $ 8.4   $ 8.2   $ 38.7  

Adjustments to reconcile net income excluding unrealized commodity derivative gains (losses) to estimated Adjusted EBITDA:

                               

Add:

                               
 

Depletion and depreciation

  $ 7.6   $ 7.4   $ 7.4   $ 7.4   $ 29.7  
 

Interest expense

    1.3     1.3     1.3     1.3     5.1  
                       
   

Estimated Adjusted EBITDA

  $ 21.8   $ 17.8   $ 17.1   $ 16.9   $ 73.5  

Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:

                               

Less:

                               
 

Cash interest expense

  $ 1.2   $ 1.2   $ 1.2   $ 1.2   $ 4.7  
 

Estimated average maintenance capital expenditures(3)

    4.5     4.5     4.5     4.5     18.0  
                       
     

Estimated cash available for distribution

  $ 16.1   $ 12.1   $ 11.4   $ 11.2   $ 50.8  

Annualized minimum quarterly distribution per unit for the period

  $ 1.90   $ 1.90   $ 1.90   $ 1.90   $ 1.90  

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  Forecasted  
 
  Three Months Ending    
 
 
  Twelve Months
Ending
September 30,
2012
 
 
  December 31,
2011
  March 31,
2012
  June 30,
2012
  September 30,
2012
 
 
  (in millions, except per unit amounts)
 

Estimated cash distributions for the period(4):

                               
 

Distributions on common units held by purchasers in this offering

  $ 4.4   $ 4.4   $ 4.4   $ 4.4   $ 17.9  
 

Distributions on common units held by Fund I

    3.0     3.0     3.0     3.0     11.9  
 

Distributions on subordinated units

    3.2     3.2     3.2     3.2     12.8  
 

Distributions on general partner units

    0     0     0     0     0  
                       
 

Total estimated cash distributions for the period

  $ 10.6   $ 10.6   $ 10.6   $ 10.6   $ 42.6  
                       
   

Excess cash available for distribution(5)

  $ 5.5   $ 1.5   $ 0.8   $ 0.6   $ 8.2  
                       

Minimum estimated Adjusted EBITDA:

                               
 

Estimated Adjusted EBITDA(2)

  $ 21.8   $ 17.8   $ 17.1   $ 16.9   $ 73.5  

Less:

                               
 

Excess cash available for distribution(5)

    5.5     1.5     0.8     0.6     8.2  
                       
   

Minimum estimated Adjusted EBITDA

  $ 16.3   $ 16.3   $ 16.3   $ 16.3   $ 65.3  
                       

(1)
Includes the forecasted effect of cash settlements of commodity derivative instruments. This amount does not include unrealized commodity derivative gains (losses), as such amounts represent non-cash items and cannot be reasonably estimated in the forecast period.

(2)
Adjusted EBITDA is defined in "Prospectus Summary — Non-GAAP Financial Measures."

(3)
In calculating the estimated cash available for distribution, we have included our estimated maintenance capital expenditures for the twelve months ending September 30, 2012. We expect to incur approximately $13.7 million of capital expenditures for the twelve months ending September 30, 2012 based on our reserve reports as of March 31, 2011, but will reserve an additional $4.3 million to maintain the current level of production from our assets. We estimate that an average annual capital expenditure of $18.0 million will enable us to maintain the current level of production from our assets through December 31, 2015. We have not included any reserves beyond estimated maintenance capital expenditures and cash interest expense in calculating the estimated cash available for distribution.

(4)
The number of outstanding common units assumed herein does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.

(5)
We plan to retain any excess cash for general partnership purposes.

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Assumptions and Considerations

          Based upon the specific assumptions outlined below with respect to the twelve months ending September 30, 2012, we expect to generate estimated Adjusted EBITDA sufficient to establish reserves for capital expenditures and to pay the minimum quarterly distribution on all common, subordinated and general partner units for the twelve months ending September 30, 2012.

          While we believe that these assumptions are reasonable in light of management's current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay quarterly cash distributions equal to our minimum quarterly distribution (absent additional borrowings under our new revolving credit facility), or any amount, on all common, subordinated and general partner units, in which event the market price of our common units may decline substantially. We are unlikely to be able to sustain our minimum quarterly distribution without making capital expenditures that maintain the current production levels of our oil and natural gas properties. We expect to primarily rely upon external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves, to fund our growth capital expenditures and make acquisitions. If we do not set aside sufficient cash reserves or make sufficient cash expenditures to maintain the current production levels of our oil and natural gas properties, we will be unable to pay distributions at the then-current level from cash generated from operations and would therefore expect to reduce our distributions. In addition, decreases in commodity prices from current levels will adversely affect our ability to pay distributions. When reading this section, you should keep in mind the risk factors and other cautionary statements described under "Risk Factors" and "Forward-Looking Statements." Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Operations and Revenue

          Production.    The following table sets forth information regarding net production of oil, NGLs and natural gas on a pro forma basis for the year ended December 31, 2010 and the twelve months ended June 30, 2011 and on a forecasted basis for the twelve months ending September 30, 2012:

 
  Pro Forma
Year Ended
December 31,
2010
  Pro Forma
Twelve Months
Ended
June 30, 2011
  Forecasted
Twelve Months
Ending
September 30, 2012
 
 
  (unaudited)
 

Annual production:

                   
 

Oil (MBbl)

    424     442     470  
 

Natural gas (MMcf)

    10,118     9,905     8,935  
 

NGLs (MBbl)

    279     262     283  
               
   

Total (MBoe)

    2,389     2,355     2,242  

Average net production:

                   
 

Oil (Bbl/d)

    1,162     1,211     1,284  
 

Natural Gas (Mcf/d)

    27,721     27,137     24,413  
 

NGLs (Bbl/d)

    764     718     773  
               
   

Total (Boe/d)

    6,546     6,452     6,126  

          We estimate that our oil, natural gas and NGL production for the twelve months ending September 30, 2012 will be 2.2 MMBoe as compared to approximately 2.4 MMBoe, on a pro forma basis

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for each of the year ended December 31, 2010 and the twelve months ended June 30, 2011. The forecast reflects $13.7 million of capital expenditures to be spent during the twelve months ending September 30, 2012.

          Prices.    The table below illustrates the relationship between average oil, NGL and natural gas realized sales prices and the average NYMEX prices on a pro forma basis for the year ended December 31, 2010 and the twelve months ended June 30, 2011 and our forecast for the twelve months ending September 30, 2012:

 
  Pro Forma
Year Ended
December 31,
2010
  Pro Forma
Twelve Months
Ended
June 30, 2011
  Forecasted
Twelve Months
Ending
September 30, 2012
 
 
  (unaudited)
 

Average oil sales prices:

                   
 

NYMEX-WTI oil price per Bbl

  $ 79.51   $ 89.41   $ 91.06  
 

Differential to NYMEX-WTI oil per Bbl

  $ (4.39 ) $ (5.86 ) $ (4.28 )
               
 

Realized oil sales price per Bbl (excluding cash settlements of derivatives)

  $ 75.12   $ 83.55   $ 86.78  
 

Realized oil sales price per Bbl (including cash settlements of derivatives)(1)

  $ 103.32   $ 80.77   $ 95.55  

Average natural gas sales prices:

                   
 

NYMEX-Henry Hub natural gas price per MMBtu

  $ 4.37   $ 4.16   $ 3.95  
 

Differential to NYMEX-Henry Hub natural gas per MMBtu

  $ (0.15 ) $ (0.12 ) $ (0.16 )
               
 

Realized natural gas sales price per Mcf (excluding cash settlements of derivatives)

  $ 4.22   $ 4.04   $ 3.79  
 

Realized natural gas sales price per Mcf (including cash settlements of derivatives)(1)

  $ 6.55   $ 6.04   $ 5.29  

Average natural gas liquids sales prices:

                   
 

NYMEX-WTI oil price per Bbl

  $ 79.51   $ 89.41   $ 91.06  
 

Differential to NYMEX-WTI oil per Bbl

  $ (40.32 ) $ (45.80 ) $ (43.33 )
               
 

Realized natural gas liquids sales price per Bbl (excluding cash settlements of derivatives)

  $ 39.19   $ 43.61   $ 47.73  
 

Realized natural gas liquids sales price per Bbl (including cash settlements of derivatives)(1)(2)

  $ 39.19   $ 43.61   $ 49.98  
 

Total combined price (per Boe, excluding cash settlements of derivatives)

  $ 35.79   $ 37.53   $ 39.30  
 

Total combined price (per Boe, including cash settlements of derivatives)(1)(2)

  $ 50.66   $ 45.42   $ 47.41  

(1)
Average NYMEX futures prices for the twelve months ending September 30, 2012 as reported on October 25, 2011. For a description of the effect of lower spot prices on cash available for distribution, please read "— Sensitivity Analysis — Commodity Price Changes."

(2)
Historically, our predecessor has not hedged its natural gas liquids sales prices. Our natural gas liquids pro forma realized prices do not include gains or losses on commodity derivative instruments.

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          Price Differentials.    Our natural gas production has historically sold at a negative basis differential from the NYMEX-Henry Hub price primarily due to the distance of the production attributable to our operating areas from the Henry Hub, which is located in Louisiana, and other location and transportation cost factors. In addition, our oil production, which consists of a combination of sweet and sour oil, typically sells at a discount to the NYMEX-WTI price due to quality and location differentials.

          The adjustments we have made to reflect the basis differentials for our forecasted production during the twelve months ending September 30, 2012 are presented in the following table and shown per Bbl for oil and per Mcf for natural gas, as reflected in our reserve reports as of March 31, 2011:

 
  Oil   Natural Gas  
Operating Area
  Per Bbl   Per Mcf  

Permian Basin

  $ (4.57 ) $ (0.13 )

Mid-Continent

  $ (3.34 ) $ (0.24 )

Gulf Coast

  $ 0.10   $ 0.02  

Weighted Average

  $ (4.29 ) $ (0.16 )

          In addition, some of our pro forma production has transportation, gathering and marketing charges deducted from the prices we realize. In the Permian Basin and Mid-Continent areas, most of these charges are inclusive in the net pricing received from the gathering and processing companies. In areas where firm transportation capacity is contracted separately from the counterparties purchasing the natural gas, an additional adjustment is made as a deduction. The Gulf Coast area currently incurs no such additional charges. The transportation costs are necessary to minimize risk of flow interruption to the markets. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Overview — Realized Prices on the Sale of Oil, NGLs and Natural Gas."

          Use of Commodity Derivative Contracts.    At the closing of this offering, we expect that Lime Rock Resources will assign specific commodity derivative contracts to us. For purposes of the forecast in this prospectus, we have assumed that such commodity derivative contracts will cover 1.6 MMBoe, or approximately 70%, of our forecasted total oil, NGL and natural gas production of 2.2 MMBoe for the twelve months ending September 30, 2012. We have assumed that the assigned commodity derivative contracts will consist of swap and collar agreements against the NYMEX-WTI, OPIS-Refined Products and NYMEX-Henry Hub prices for oil, NGLs and natural gas, respectively. The table below shows the volumes and prices we have assumed for our commodity derivative contracts for the twelve months ending September 30, 2012:

 
  Swaps   Collars  
 
  Bbl   Weighted
Average
Price
  Bbl   Weighted
Average
Floor Price
  Weighted
Average
Ceiling Price
 

Oil:

                               

October 2011 — September 2012

    245,735   $ 105.37     20,400   $ 120.00   $ 171.50  

% of forecasted oil production

    52 %         4 %            

 

 
  MMBtu   Weighted
Average
Price
  MMBtu   Weighted
Average
Floor Price
  Weighted
Average
Ceiling Price
 

Natural gas:

                               

October 2011 — September 2012

    4,631,178   $ 6.46     2,205,372   $ 4.74   $ 7.51  

% of forecasted natural gas production

    52 %         25%              

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  Bbl   Weighted
Average
Price
   
   
   
 

NGLs:

                               

October 2011 — September 2012

    173,910   $ 51.38                    

% of forecasted NGL production

    61 %                        

          Natural Gas Liquids.    The following table presents the benefit of NGL revenue on natural gas pricing by operating area during the twelve months ending September 30, 2012, as reflected in our reserve reports as of March 31, 2011 using SEC pricing:

 
  NGL yield
Bbl/MMcf
  NGL Price
$/Bbl
  NGL %
Total Revenue
  Residue Gas +
NGL Price
Differential
$/Mcf
 

Region:

                         
 

Permian Basin

    54   $ 42.14     15 % $ 3.00  
 

Mid-Continent

    0   $     0 % $ (0.24 )
 

Gulf Coast

    47   $ 46.28     33 % $ 2.72  
 

Weighted Average

    24   $ 43.54     15 % $ 1.22  

          As stated in the previous section, natural gas production is typically sold at a negative basis differential from the NYMEX-Henry Hub price. An example of this pricing is shown in the table above regarding the Mid-Continent price differential having a negative adjustment to NYMEX price. This adjustment is partially due to low Btu natural gas with no associated NGLs. However, when factoring in the revenue benefit of NGLs associated with the high Btu gas in the Permian and Gulf Coast Regions, the net price differentials to NYMEX pricing for these two areas is materially positive which shows the revenue benefit of the associated NGL value.

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          Operating Revenues and Realized Commodity Derivative Gains.    The following table illustrates the primary components of operating revenues and realized commodity derivative gains on a pro forma basis for the year ended December 31, 2010 and the twelve months ended June 30, 2011 and on a forecasted basis for the twelve months ending September 30, 2012:

 
  Pro Forma
Year Ended
December 31,
2010
  Pro Forma
Twelve Months
Ended
June 30, 2011
  Forecasted
Twelve Months
Ending
September 30, 2012
 
 
  (unaudited)

   
 
 
  (in millions)
 

Oil:

                   
 

Oil revenues

  $ 31.9   $ 36.9   $ 40.8  
 

Oil derivative instruments gain (loss)

    11.9     (1.2 )   4.1  
               
   

Total

  $ 43.8   $ 35.7   $ 44.9  

Natural gas:

                   
 

Natural gas revenues

  $ 42.7   $ 40.1   $ 33.8  
 

Natural gas derivative instruments gain (loss)

    23.6     19.8     13.5  
               
   

Total

  $ 66.3   $ 59.9   $ 47.3  

NGLs:

                   
 

NGLs revenues

  $ 10.9   $ 11.4   $ 13.5  
 

NGLs derivative instruments gain (loss)(1)

    0.0     0.0     0.6  
               
   

Total

  $ 10.9   $ 11.4   $ 14.1  

Total:

                   
 

Operating revenues

  $ 85.5   $ 88.4   $ 88.1  
 

Commodity derivative instruments gain (loss)

    35.5     18.6     18.2  
               
   

Operating revenue and realized commodity derivative instruments gains

  $ 121.0   $ 107.0   $ 106.3  
               

(1)
Historically, our predecessor has not hedged its NGL sales prices. Our NGL pro forma realized prices do not include gains or losses on commodity derivative instruments.

Capital Expenditures and Expenses

          Capital Expenditures.    Our estimated cash reserves for maintenance capital expenditures for the year ending September 30, 2012 of $18.0 million represent our estimate of the average annual maintenance capital expenditures necessary to maintain our production through 2015 based on the forecasted production level of 6.1 MBoe/d for the twelve months ending September 30, 2012.

          We anticipate replacing declining production and reserves through the drilling and completing of wells on our undeveloped properties and through the acquisition of producing and non-producing oil and natural gas properties from Lime Rock Resources and from third parties. We estimate that we will drill 24 gross (12 net) wells during the forecast period at an aggregate net cost of approximately $9.1 million. We also expect to spend approximately $4.6 million during the twelve-month period ending September 30, 2012 on workovers, recompletions and other field-related costs. In addition, for the same period we will reserve an additional $4.3 million for capital expenditures to maintain the current level of production of our assets through 2015. Although we may make acquisitions during the twelve months

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ending September 30, 2012, our forecast period does not reflect any potential opportunistic acquisitions because we cannot assure you that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase agreements.

          Lease Operating Expenses.    The following table summarizes lease operating expenses on an aggregate basis and on a per Boe basis for the year ended December 31, 2010 and twelve months ended June 30, 2011, pro forma, and on a forecasted basis for the twelve months ending September 30, 2012:

 
  Pro Forma
Year Ended
December 31,
2010
  Pro Forma
Twelve Months
Ended
June 30, 2011
  Forecasted
Twelve Months
Ending
September 30, 2012
 

Lease operating expenses (in millions)

  $ 19.1   $ 19.8   $ 16.5  

Lease operating expenses (per Boe)

  $ 7.99   $ 8.40   $ 7.36  

          We estimate our lease operating expenses for the twelve months ending September 30, 2012 will be approximately $16.5 million. On a pro forma basis, for the year ended December 31, 2010 and twelve months ended June 30, 2011, lease operating expenses were $19.1 million and $19.8 million, respectively, with respect to the Partnership Properties, which includes items such as marketing, gathering, transportation and workover expenses. These same lease operating expenses, for the year ended December 31, 2010 and the twelve months ended June 30, 2011, on a pro forma basis not including those items, would have been $12.0 million and $13.3 million, respectively, or $5.02 and $5.65 per Boe, respectively.

          The $19.1 million and $19.8 million, respectively, of lease operating expenses for the year ended December 31, 2010 and twelve months ended June 30, 2011, on a pro forma basis, do not compare to the estimated lease operating expenses for the twelve months ending September 30, 2012 due to several differences. For example, the $19.1 million and $19.8 million, respectively, include approximately $4.9 million and $5.0 million, respectively, of marketing, gathering and transportation expenses. For the twelve months ending September 30, 2012, the marketing, gathering and transportation expenses related to the Potato Hills and New Years Ridge properties is included in the $16.5 million of lease operating expenses; however, the majority of the remaining marketing, gathering and transportation expenses related to the rest of the Partnership Properties are handled as a deduct to realized commodity prices, as per the March 31, 2011 third-party reserve reports. In addition, on a pro forma basis for the year ended December 31, 2010 and the twelve months ended June 30, 2011, lease operating expenses included approximately $2.2 million and $1.4 million, respectively, of workover expenses; however, for the twelve months ending September 30, 2012, these workover expenses are not included in the lease operating expenses due to the fact that they are non-recurring.

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          Production and Ad Valorem Taxes.    The following table summarizes production and ad valorem taxes before the effects of our commodity derivative contracts on a pro forma basis for the year ended December 31, 2010 and the twelve months ended June 30, 2011 and on a forecasted basis for the twelve months ending September 30, 2012:

 
  Pro Forma
Year Ended
December 31,
2010
  Pro Forma
Twelve Months
Ended
June 30, 2011
  Forecasted
Twelve Months
Ending
September 30, 2012
 
 
  (in millions)
 

Oil, natural gas and NGL revenues, excluding the effect of our commodity derivative contracts

  $ 85.5   $ 88.4   $ 88.1  

Production and ad valorem taxes

  $ 7.8   $ 5.4   $ 7.4  

Production and ad valorem taxes as a percentage of revenue

    9 %   6 %   8 %

          Our production and ad valorem taxes are calculated as a percentage of our oil, natural gas and NGL revenues, excluding the effects of our commodity derivative contracts. In general, as prices and volumes increase, our production taxes increase. As prices and volumes decrease, our production taxes decrease. Additionally, production tax rates vary by state, and as revenues by state vary, our production taxes will increase or decrease. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties. However, these valuations are reasonably correlated to revenues, excluding the effects of our commodity derivative contracts. As a result, we are forecasting our ad valorem taxes as a percent of revenues, excluding the effects of our commodity derivative contracts.

          General and Administrative Expenses.    At the closing of this offering, we will enter into a services agreement with Lime Rock Management and Lime Rock Resources Operating Company with respect to all general and administrative expenses and costs they incur on our general partner's and our behalf, including $2.5 million of incremental annual expenses we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs and director compensation. Under the services agreement, Lime Rock Management and Lime Rock Resources Operating Company will each be reimbursed by our general partner for all general and administrative expenses allocated to us under the services agreement. If our general partner grants awards of bonuses and unit-based compensation to officers and employees in the future, those awards may adversely impact our cash available for distribution. However, we have made no assumptions with respect to these items in the forecast because the board of directors of our general partner has not yet made any determination as to the number of awards, the type of awards or whether or when any awards would be granted. Awards of bonuses and unit-based compensation granted during the twelve months ending September 30, 2012 are not subject to a maximum amount, except that unit-based awards are limited under our long-term incentive plan.

          Depletion and Depreciation Expense.    We estimate that our depletion and depreciation expense for the twelve months ending September 30, 2012 will be approximately $29.7 million, as compared to $40.7 million and $35.7 million, respectively, on a pro forma basis for the year ended December 31, 2010 and the twelve months ended June 30, 2011. The forecasted depletion of our oil and natural gas properties is based on the production estimates in our reserve reports as of March 31, 2011. Our capitalized costs are calculated using the successful efforts method of accounting. For a detailed description of the successful

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efforts method of accounting, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates."

          Cash Interest Expense.    We estimate that at the closing of this offering we will borrow approximately $155.8 million in revolving debt under our new $500 million credit facility. We estimate that the borrowings will bear interest at a weighted average rate of approximately 3.10%. Based on these assumptions, we estimate that our cash interest expense for the twelve months ending September 30, 2012 will be $4.7 million as compared to $4.8 million on a pro forma basis for both the year ended December 31, 2010 and the twelve months ended June 30, 2011.

          We expect that our new credit facility will contain financial covenants that require us to maintain a leverage ratio of not more than 4.0 to 1.0x and a current ratio of not less than 1.0 to 1.0x. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — New Credit Facility" for additional detail regarding the covenants and restrictive provisions to be included in our new credit facility. We expect that the new credit facility will not require any cash expenditures on our part other than cash interest expense that would affect our cash available for distribution. As a result, based on the assumptions used in preparing the estimates set forth above, the new credit facility will not have any effect upon our ability to pay the estimated distributions to our unitholders during the forecast period.

Regulatory, Industry and Economic Factors

          Our forecast for the twelve months ending September 30, 2012 is based on the following significant assumptions related to regulatory, industry and economic factors:

    There will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or any interpretation of existing regulations, that will be materially adverse to our business;

    There will not be any material nonperformance or credit-related defaults by suppliers, customers or vendors, or shortage of skilled labor;

    All supplies and commodities necessary for production and sufficient transportation will be readily available;

    There will not be any major adverse change in commodity prices or the energy industry in general;

    There will not be any material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated events, including any events that could lead to force majeure under any of our marketing agreements;

    There will not be any major adverse change in the markets in which we operate resulting from supply or production disruptions, reduced demand for our product or significant changes in the market prices for our product; and

    Market, insurance, regulatory and overall economic conditions will not change substantially.

Forecasted Distributions

          We expect that aggregate quarterly distributions of available cash on our common units, subordinated units and general partner units for the twelve months ending September 30, 2012 will be approximately $42.6 million. Quarterly distributions of available cash will be paid within 45 days after the close of each calendar quarter.

          While we believe that the assumptions we have used in preparing the estimates set forth above are reasonable based upon management's current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic regulatory and competitive risks and

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uncertainties, including those described in "Risk Factors" that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash that we generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full minimum quarterly distribution or any amount on all our outstanding common, subordinated and general partner units in respect of the twelve months ending September 30, 2012 or thereafter, in which event the market price of the common units may decline materially.


Sensitivity Analysis

          Our ability to generate sufficient cash from operations to pay cash distributions to our unitholders is a function of two primary variables: (i) production volumes; and (ii) commodity prices. In the tables below, we illustrate the effect that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the minimum quarterly distributions on our outstanding common units and subordinated units for the twelve months ending September 30, 2012.

Production Volume Changes

          The following table shows estimated Adjusted EBITDA under production levels of 90%, 100% and 110% of the production level we have forecasted for the twelve months ending September 30, 2012. The estimated Adjusted EBITDA amounts shown below are based on the assumptions used in our forecast.

 
  Percentage of Forecasted Net Production  
 
  90%   100%   110%  
 
  (in millions, except per unit amounts)
 

Forecasted net production:

                   
 

Oil (MBbl)

    423     470     517  
 

Natural gas (MMcf)

    8,041     8,935     9,828  
 

NGLs (MBbl)

    255     283     312  
               
   

Total (MBoe)

    2,018     2,242     2,467  
 

Oil (Bbl/d)

    1,156     1,284     1,413  
 

Natural gas (Mcf/d)

    21,970     24,413     26,852  
 

NGLs (Bbl/d)

    697     773     852  
               
   

Total (Boe/d)

    5,514     6,126     6,740  

Forecasted prices:

                   
 

NYMEX-WTI oil price (per Bbl)

  $ 91.06   $ 91.06   $ 91.06  
 

Realized oil price (per Bbl) (excluding derivatives)

  $ 86.78   $ 86.78   $ 86.78  
 

Realized oil price (per Bbl) (including derivatives)

  $ 96.52   $ 95.55   $ 94.75  
 

NYMEX-Henry Hub natural gas price (per MMBtu)

  $ 3.95   $ 3.95   $ 3.95  
 

Realized natural gas price (per Mcf) (excluding derivatives)

  $ 3.79   $ 3.79   $ 3.79  
 

Realized natural gas price (per Mcf) (including derivatives)

  $ 5.45   $ 5.29   $ 5.15  
 

NYMEX-WTI oil price (per Bbl)

  $ 91.06   $ 91.06   $ 91.06  
 

Realized natural gas liquids price (per Bbl) (excluding derivatives)

  $ 47.73   $ 47.73   $ 47.73  
 

Realized natural gas liquids price (per Bbl) (including derivatives)

  $ 50.23   $ 49.98   $ 49.77  

Forecasted Adjusted EBITDA projection:

                   
 

Operating revenue

  $ 79.3   $ 88.1   $ 97.0  
 

Realized derivative gains (losses)

    18.2     18.2     18.2  
               
   

Total revenue and realized derivative gains (losses)

  $ 97.5   $ 106.3   $ 115.2  
 

Lease operating expenses

  $ 14.8   $ 16.5   $ 18.1  
 

Production and ad valorem taxes

    6.6     7.4     8.1  
 

General and administrative expenses

    8.9     8.9     8.9  
               
   

Estimated Adjusted EBITDA

  $ 67.2   $ 73.5   $ 80.1  
 

Minimum estimated Adjusted EBITDA

 
$

65.3
 
$

65.3
 
$

65.3
 
 

Excess cash available for distribution

    1.9     8.2     14.8  

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Commodity Price Changes

          The following table shows estimated Adjusted EBITDA under various assumed NYMEX-WTI oil and NYMEX-Henry Hub natural gas prices for the twelve months ending September 30, 2012. For the twelve months ending September 30, 2012, we have assumed that, at the closing of this offering, Lime Rock Resources will contribute to us commodity derivative contracts covering 1.6 MMBoe, or approximately 70% of our estimated total oil, NGL and natural gas production for the twelve months ending September 30, 2012, at a weighted average price of $106.50 per Bbl of oil, $51.38 per Bbl of NGLs and $5.91 per MMBtu of natural gas. In addition, the estimated Adjusted EBITDA amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity price differential assumptions. We have assumed no changes in our production based on changes in prices.

 
   
   
   
 
       
 
  (in millions, except per unit amounts)
 

NYMEX-WTI oil price (per Bbl):

  $ 80.00   $ 90.00   $ 100.00  

NYMEX-Henry Hub natural gas price (per MMBtu):

  $ 3.50   $ 4.00   $ 4.50  
               

Forecasted net production:

                   
 

Oil (MBbl)

    470     470     470  
 

Natural gas (MMcf)

    8,935     8,935     8,935  
 

NGLs (MBbl)

    283     283     283  
               
   

Total (MBoe)

    2,242     2,242     2,242  
 

Oil (Bbl/d)

    1,284     1,284     1,284  
 

Natural gas (Mcf/d)

    24,413     24,413     24,413  
 

NGLs (Bbl/d)

    773     773     773  
               
   

Total (Boe/d)

    6,126     6,126     6,126  

Forecasted prices:

                   
 

NYMEX-WTI oil price (per Bbl)

  $ 80.00   $ 90.00   $ 100.00  
 

Realized oil price (per Bbl) (excluding derivatives)

  $ 75.71   $ 85.71   $ 95.71  
 

Realized oil price (per Bbl) (including derivatives)

  $ 90.71   $ 95.05   $ 99.39  
 

NYMEX-Henry Hub natural gas price (per MMBtu)

  $ 3.50   $ 4.00   $ 4.50  
 

Realized natural gas price (per Mcf) (excluding derivatives)

  $ 3.34   $ 3.84   $ 4.34  
 

Realized natural gas price (per Mcf) (including derivatives)

  $ 5.18   $ 5.30   $ 5.42  
 

NYMEX-WTI oil price (per Bbl)

  $ 80.00   $ 90.00   $ 100.00  
 

Realized natural gas liquids price (per Bbl) (excluding derivatives)

  $ 41.66   $ 47.17   $ 52.67  
 

Realized natural gas liquids price (per Bbl) (including derivatives)

  $ 47.63   $ 49.75   $ 51.88  

Forecasted Adjusted EBITDA projection:

                   
 

Operating revenue

  $ 77.2   $ 88.0   $ 98.7  
 

Realized derivative gains (losses)

    25.2     18.2     11.1  
               
   

Total revenue and realized derivative gains (losses)

  $ 102.4   $ 106.2   $ 109.8  
 

Lease operating expenses

  $ 16.5   $ 16.5   $ 16.5  
 

Production and ad valorem taxes

    6.5     7.3     8.2  
 

General and administrative expenses

    8.9     8.9     8.9  
               
   

Estimated Adjusted EBITDA

  $ 70.5   $ 73.5   $ 76.2  

Minimum estimated Adjusted EBITDA

   
65.3
   
65.3
   
65.3
 

Excess cash available for distribution

  $ 5.2   $ 8.2   $ 10.9  

          The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units, subordinated units and general partner units that will be outstanding after this offering is approximately $42.6 million. The minimum estimated Adjusted EBITDA for the twelve months ending September 30, 2012 necessary to pay the aggregate annualized minimum quarterly distributions for such period is approximately $65.3 million, resulting in an excess of cash available for distribution over the minimum quarterly cash distributions of $8.2 million, based on an estimated

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Adjusted EBITDA of $73.5 million for such period. Please see "— LRR Energy, L.P. Estimated Unaudited Adjusted EBITDA."

          Our estimated Adjusted EBITDA for the twelve months ending September 30, 2012 is based on average NYMEX futures prices of $91.06 per barrel of oil and $3.95 per MMBtu of natural gas for the twelve months ending September 30, 2012 as reported on October 25, 2011. Based on such prices, and assuming the effect of the commodity derivative contracts Lime Rock Resources will contribute to us, a decline in oil and natural gas prices by 33.0% to $61.01 per Bbl and $2.64 per MMBtu, respectively, for the twelve-month period ending September 30, 2012, would result in the elimination of any excess of cash available for distribution. If oil and natural gas prices were to decline further, we would be unable to generate sufficient Adjusted EBITDA to pay the minimum quarterly distribution to all of our unitholders. Please see "— Assumptions and Considerations — Prices."

          We plan to enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Our strategy includes entering into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved developed producing reserves over a three-to-five year period at a given point of time, although we may from time to time hedge more or less than this approximate range. For the years ending December 31, 2011 through 2015, Lime Rock Resources will contribute to us at the closing of this offering commodity derivative contracts covering approximately 85% of our estimated production for each year from total proved developed producing reserves as of March 31, 2011 based on our reserve reports. These commodity derivative contracts will consist of natural gas, oil and NGL financial swaps and collar contracts and natural gas basis financial swaps. By removing a significant portion of price volatility associated with production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations for those periods.

          If NYMEX oil and natural gas prices decline, our estimated Adjusted EBITDA would not decline proportionately for two reasons: (1) the effects of our commodity derivative contracts; and (2) production taxes, which are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts, and which decrease as commodity prices decline. Furthermore, we have assumed no changes in estimated production or oil and natural gas operating costs during the twelve months ending September 30, 2012. However, over the long term, a sustained decline in oil and natural gas prices would likely lead to a decline in production and oil and natural gas operating costs, as well as a reduction in our realized oil and natural gas prices. Therefore, the foregoing table is not illustrative of all of the potential effects of changes in commodity prices for periods subsequent to September 30, 2012.

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

          Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.


Distributions of Available Cash

General

          Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2011, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution payable in respect of the quarter ending December 31, 2011 for the period from the closing of the offering through December 31, 2011.

Definition of Available Cash

          Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

    less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:

    provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;

    comply with applicable law, any of our debt instruments or other agreements; or

    provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for future distributions on our subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for such quarter);

    plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

          The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

          We intend to distribute to the holders of our common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.4750 per unit, or $1.90 per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and payment of expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution or any amount on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital

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Resources — New Credit Facility" for a discussion of the restrictions to be included in our credit facility that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

          As of the date of this offering, our general partner will be entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. Our general partner's 0.1% interest in us is represented by general partner units for allocation and distribution purposes. At the consummation of this offering, our general partner's 0.1% interest in us will be represented by 22,400 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its current general partner interest. Our general partner's initial 0.1% interest in our distributions will be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units to Fund I upon expiration of the underwriters' option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units in connection with a reset of the incentive distribution target levels relating to our general partner's incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its 0.1% general partner interest.

          Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 23.1%, of the cash we distribute from operating surplus (as defined below) in excess of $0.54625 per unit per quarter. The maximum distribution of 23.1% includes distributions paid to our general partner on its 0.1% general partner interest and assumes that our general partner maintains its general partner interest at 0.1%. Upon the closing of this offering, Fund I and Fund II will hold non-voting member interests in our general partner that will entitle them to receive 80% and 20%, respectively, of the distributions with respect to the incentive distribution rights and any common units issued to our general partner in connection with a reset of the incentive distribution rights, in each case, for a period of six years following the closing of this offering.


Operating Surplus and Capital Surplus

General

          All cash distributed to unitholders will be characterized as either "operating surplus" or "capital surplus." Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus

          Operating surplus for any period consists of:

    $30.0 million (as described below); plus

    all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions, which include the following:

    borrowings (including sales of debt securities) that are not working capital borrowings;

    sales of equity interests;

    sales or other dispositions of assets outside the ordinary course of business;

    capital contributions received; and

    corporate reorganizations or restructurings;

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provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus

    working capital borrowings made after the end of the period but on or before the date of determination of operating surplus for the period; plus

    cash distributions paid on equity issued (including incremental distributions on incentive distribution rights), other than equity issued on the closing date of this offering, to finance all or a portion of the construction, acquisition or improvement of a capital improvement or replacement of a capital asset (such as reserves or equipment) in respect of the period from the date we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset until the earlier to occur of the date the capital improvement or capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of; plus

    cash distributions paid on equity issued (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the capital improvements or capital assets referred to above, in each case in respect of the period from the date we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset until the earlier to occur of the date the capital improvement or capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of; less

    all of our operating expenditures (as described below) after the closing of this offering and the completion of the transactions described in "Prospectus Summary — Formation Transactions and Partnership Structure"; less

    the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

    all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such twelve-month period with the proceeds of additional working capital borrowings; less

    any loss realized on disposition of an investment capital expenditure.

          As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $30.0 million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including (as described above) certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

          The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

          We define operating expenditures in our partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner

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(including expenses incurred under the services agreement with Lime Rock Management and Lime Rock Resources Operating Company), payments made in the ordinary course of business under interest rate and commodity hedge contracts (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, debt service payments (except as otherwise provided in our partnership agreement) and estimated maintenance capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:

    repayment of working capital borrowings previously deducted from operating surplus pursuant to the provision described in the penultimate bullet point of the description of operating surplus above when such repayment actually occurs;

    payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

    growth capital expenditures;

    actual maintenance capital expenditures (as discussed in further detail below);

    investment capital expenditures;

    payment of transaction expenses relating to interim capital transactions;

    distributions to our partners (including distributions in respect of our incentive distribution rights);

    repurchases of equity interests except to fund obligations under employee benefit plans; or

    any other payments made in connection with this offering that are described under "Use of Proceeds."

Capital Surplus

          Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, capital surplus would generally be generated only by the following (which we refer to as "interim capital transactions"):

    borrowings (including sales of debt securities) other than working capital borrowings;

    sales of our equity interests;

    sales or other dispositions of assets outside the ordinary course of business;

    capital contributions received; and

    corporate reorganizations and restructurings.

Characterization of Cash Distributions

          Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As described above, operating surplus includes up to $30.0 million, which does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as

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operating surplus up to this amount of cash we receive in the future from interim capital transactions that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.


Capital Expenditures

          Estimated maintenance capital expenditures reduce operating surplus, but growth capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are those capital expenditures required to maintain the current production levels over the long term of our oil and natural gas properties or maintain the current operating capacity of our other capital assets. We expect that a primary component of maintenance capital expenditures will be capital expenditures associated with the replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of any replacement asset that is paid in respect of the period from the date that we enter into a binding agreement to commence construction or development of a capital asset until the earlier to occur of the date that any such construction, replacement, acquisition or improvement of a capital improvement or construction replacement, acquisition or improvement of a capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of. Plugging and abandonment cost will also constitute maintenance capital expenditures. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

          Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus. To address this issue, our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures (including estimated plugging and abandonment costs) necessary to maintain our asset base over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our general partner's board of directors at least once a year, provided that any change is approved by the conflicts committee of our general partner's board of directors. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read "Our Cash Distribution Policy and Restrictions on Distributions."

          The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

    it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for the quarter and subsequent quarters;

    it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;

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    in quarters where estimated maintenance capital expenditures exceed actual maintenance capital expenditures, it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights to our general partner because the amount of estimated maintenance capital expenditures will reduce the amount of cash available for distribution to our unitholders, even in quarters where there are no corresponding actual capital expenditures; conversely, the use of estimated maintenance capital expenditures in calculating operating surplus will have the opposite effect for quarters in which actual maintenance capital expenditures exceed our estimated maintenance capital expenditures; and

    it will reduce the likelihood that a large maintenance capital expenditure during a particular quarter will prevent our general partner's affiliates from being able to convert some or all of their subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

          Growth capital expenditures are those capital expenditures that we expect will increase the production over the long term of our oil and natural gas properties or increase the current operating capacity of our other capital assets. Examples of growth capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development, exploitation and production of an existing leasehold interest, to the extent such expenditures are incurred to increase our asset base over the long term. Growth capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of such capital improvement during the period from the date we enter into a binding obligation to commence construction of a capital improvement until the earlier to occur of the date any such capital improvement begins producing in paying quantities or is placed into service, as applicable, or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered growth capital expenditures.

          Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor growth capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of our undeveloped properties in excess of the maintenance of our current production levels of our oil and natural gas properties or the current operating capacity of our other capital assets, but which are not expected to increase the production of our oil and natural gas properties or the current operating capacity of our other capital assets for more than the short term.

          As described above, neither investment capital expenditures nor growth capital expenditures will be included in operating expenditures, and thus will not reduce operating surplus. Because growth capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period from the date we enter into a binding obligation to commence construction of a capital improvement until the earlier to occur of the date any such capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

          Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or growth capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or growth capital expenditure by our general partner's board of directors.

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Subordination Period

General

          Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4750 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

Definition of Subordination Period

          Following this offering, Fund I will own all of our subordinated units. The subordination period will extend until the first business day of any quarter beginning after December 31, 2014 that each of the following tests are met:

    Distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions payable with respect to a period of twelve consecutive quarters immediately preceding such date;

    The "adjusted operating surplus" generated during the period of twelve consecutive quarters immediately preceding that date equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units that were outstanding during these periods payable with respect to such period on a fully diluted basis; and

    There are no arrearages in the payment of the minimum quarterly distribution on the common units.

          When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.

          Notwithstanding the foregoing, before the end of the subordination period, one-third each of the subordinated units will convert in subsequent one-third tranches into common units on a one-for-one basis on the first business day after the distribution to unitholders in respect of any quarter ending on or after:

    December 31, 2012 for the first one-third tranche (2,240,000 subordinated units);

    December 31, 2013 for the second one-third tranche (2,240,000 subordinated units); and

    December 31, 2014 for the third one-third tranche (2,240,000 subordinated units).

    provided that

    distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions that would have been payable with respect to four consecutive quarters (with respect to the first tranche), eight consecutive quarters (with

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      respect to the second tranche) and twelve consecutive quarters (with respect to the third tranche), as applicable;

    The "adjusted operating surplus" (as defined below) generated during the period of four, eight and twelve consecutive quarters, as applicable, immediately preceding that date equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units that were outstanding during these periods payable with respect to such periods on a fully diluted basis; and

    There are no arrearages in the payment of the minimum quarterly distribution on the common units.

          If more than one person owns our subordinated units, a portion of the subordinated units owned by each person will be converted pro rata based on the number of subordinated units owned.

Early Termination of Subordination Period

          Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending on or after December 31, 2013, if each of the following has occurred:

    distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded $2.185 (115% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding that date;

    the "adjusted operating surplus" generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.185 (115% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units that were outstanding during these periods on a fully diluted basis and the corresponding distributions on the incentive distribution rights; and

    there are no arrearages in payment of the minimum quarterly distribution on the common units.

          In addition to the early termination of the subordinated period discussed above, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, if each of the following has occurred:

    distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded $2.375 (125% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding that date;

    the "adjusted operating surplus" generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.375 (125% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units that were outstanding during these periods on a fully diluted basis and the corresponding distributions on the incentive distribution rights; and

    there are no arrearages in payment of the minimum quarterly distribution on the common units.

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Expiration of the Subordination Period Upon Removal of Our General Partner

          In addition, if the unitholders remove our general partner other than for cause:

    the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (1) neither such person nor any of its affiliates voted any of its units in favor of the removal and (2) such person is not an affiliate of the successor general partner; and

    if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

Expiration of the Subordination Period

          When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in the distributions of available cash.

Adjusted Operating Surplus

          Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus is calculated using estimated maintenance capital expenditures rather than actual maintenance capital expenditures and, to the extent the estimated amount is less than the actual amount, the cash generated from operations during that period would be less than the adjusted operating surplus for that period. Adjusted operating surplus for any period consists of:

    operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under "— Operating Surplus and Capital Surplus — Operating Surplus"); less

    any net increase in working capital borrowings with respect to that period; less

    any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

    any net decrease in working capital borrowings with respect to that period; plus

    any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium; plus

    any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.


Distributions of Available Cash from Operating Surplus During the Subordination Period

          We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

    first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter;

    second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

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    third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

    thereafter, in the manner described in "— General Partner Interest and Incentive Distribution Rights."

          The preceding discussion is based on the assumption that we do not issue any additional classes of equity securities and that our general partner maintains its 0.1% general partner interest in us.


Distributions of Available Cash from Operating Surplus After the Subordination Period

          We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

    first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; and

    thereafter, in the manner described in "— General Partner Interest and Incentive Distribution Rights."

          The preceding discussion is based on the assumptions that we do not issue any additional classes of equity securities and that our general partner maintains its 0.1% general partner interest in us.


General Partner Interest and Incentive Distribution Rights

          Our partnership agreement provides that our general partner initially will be entitled to 0.1% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for general partner units to maintain its 0.1% general partner interest if we issue additional units. Our general partner's 0.1% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units to Fund I upon expiration of the underwriters' option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units in connection with a reset of the incentive distribution target levels relating to our general partner's incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash, and our general partner may fund its capital contribution by the contribution to us of common units or other property.

          Incentive distribution rights represent the right to receive an increasing percentage (13% and 23%, in each case, not including distributions paid to the general partner on its 0.1% general partner interest) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Upon the closing of this offering, our general partner will hold all of our incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. In addition, Fund I and Fund II will hold non-voting member interests in our general partner that will entitle them to receive 80% and 20%, respectively, of the distributions with respect to the incentive distribution rights and any common units issued to our general partner in connection with a reset of the incentive distribution rights, in each case, owned by our general partner for a period of six years following the closing of this offering.

          The following discussion assumes that our general partner maintains its 0.1% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

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          If for any quarter:

    we have distributed available cash from operating surplus to the unitholders in an amount equal to the minimum quarterly distribution; and

    we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution to the common unitholders;

    then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

    first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unitholder receives a total of $0.54625 per unit for that quarter (the "first target distribution");

    second, 86.9% to all unitholders, pro rata, and 13.1% to our general partner, until each unitholder receives a total of $0.59375 per unit for that quarter (the "second target distribution"); and

    thereafter, 76.9% to all unitholders, pro rata, and 23.1% to our general partner.


Percentage Allocations of Ava